Agricultural Marketing Service
Industry and Security Bureau
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National Oceanic and Atmospheric Administration
Army Department
Federal Energy Regulatory Commission
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Community Living Administration
Food and Drug Administration
National Institutes of Health
Coast Guard
U.S. Citizenship and Immigration Services
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U.S. Immigration and Customs Enforcement
Fish and Wildlife Service
National Park Service
Alcohol, Tobacco, Firearms, and Explosives Bureau
Drug Enforcement Administration
Justice Programs Office
Federal Aviation Administration
Federal Motor Carrier Safety Administration
Federal Transit Administration
Pipeline and Hazardous Materials Safety Administration
Internal Revenue Service
Consult the Reader Aids section at the end of this issue for phone numbers, online resources, finding aids, and notice of recently enacted public laws.
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Agricultural Marketing Service, USDA.
Notice of availability of final guidance.
The National Organic Program (NOP) is announcing the availability of a final guidance document intended for use by accredited certifying agents, and certified and exempt organic operations. The guidance document is entitled: Substances Used in Post-Harvest Handling of Organic Products (NOP 5023). This guidance document is intended to inform the public of NOP's current thinking on this topic.
The final guidance document announced by this document is effective on January 19, 2016.
Paul Lewis, Ph.D., Standards Division, National Organic Program, USDA–AMS–NOP, 1400 Independence Ave. SW., Room 2642–S., Ag Stop 0268, Washington, DC 20250–0268. Telephone: (202) 720–3252, Email:
On April 25, 2014, the National Organic Program (NOP) published in the
NOP received 10 comments on the draft guidance document. Based upon the comments received, the NOP revised and is publishing a final guidance document on Substances Used in Post-Harvest Handling of Organic Products (NOP 5023). The guidance document includes an appendix (NOP 5023–1) where the NOP provides a complete discussion of the comments received and the rationale behind any changes made to the guidance documents.
This final guidance clarifies the USDA organic regulations regarding substances used in post-harvest handling activities such as washing, packing and storage of organic products. There is no discrete section of the National List of Allowed and Prohibited Substances (National List) (7 CFRs 205.600 through 205.607) designated for substances used in these post-harvest handling activities. Instead, the substances allowed for use in post-harvest handling appear in different sections of the National List (
This final guidance provides information to all USDA-accredited certifying agents (certifiers) and certified and exempt organic operations about substances that may be used in post-harvest handling of organic products. More specifically, this final guidance clarifies: (1) What substances may be used for post-harvest handling; (2) the difference between “post-harvest handling of raw agricultural commodities” and “further processing”; and (3) the regulatory requirements for facility pest management. This guidance also defines post-harvest substances and post-harvest handling.
This final guidance is available from the NOP through “The Program Handbook: Guidance and Instructions for Accredited Certifying Agents (ACAs) and Certified Operations”. This Handbook provides those who own, manage, or certify organic operations with guidance and instructions that can assist them in complying with the USDA organic regulations. The current edition of the Program Handbook is available online at
This final guidance document is being issued in accordance with the Office of Management and Budget (OMB) Bulletin on Agency Good Guidance Practices (GGPs) (January 25, 2007, 72 FR 3432–3440).
The purpose of GGPs is to ensure that program guidance documents are developed with adequate public participation, are readily available to the public, and are not applied as binding requirements. This final guidance represents NOP's current thinking on the topic. It does not create or confer any rights for, or on, any person and does not operate to bind the NOP or the public. Guidance documents are intended to provide a uniform method for operations to comply that can reduce the burden of developing their own methods and simplify audits and inspections. Alternative approaches that can demonstrate compliance with the Organic Foods Production Act (OFPA), as amended (7 U.S.C. 6501–6522), and its implementing regulations are also acceptable. As with any alternative compliance approach, NOP strongly encourages industry to discuss alternative approaches with NOP before implementing them to avoid unnecessary or wasteful expenditures of resources and to ensure the proposed alternative approach complies with the Act and its implementing regulations.
Persons with access to Internet may obtain the final guidance at the USDA Agricultural Marketing Service Web site at
7 U.S.C. 6501–6522.
U.S. Citizenship and Immigration Services, Department of Homeland Security.
Final rule.
In this final rule, the Department of Homeland Security (DHS) is revising its regulations affecting: highly skilled workers in the nonimmigrant classifications for specialty occupation from Chile, Singapore (H–1B1), and Australia (E–3); the immigrant classification for employment-based first preference (EB–1) outstanding professors and researchers; and nonimmigrant workers in the Commonwealth of the Northern Mariana Islands (CNMI)-Only Transitional Worker (CW–1) classification. DHS anticipates that these changes to the regulations will benefit these highly skilled workers and CW–1 nonimmigrant workers by removing unnecessary hurdles that place such workers at a disadvantage when compared to similarly situated workers in other visa classifications.
This final rule is effective February 16, 2016.
Paola Rodriguez Hale, Adjudications Officer (Policy), Office of Policy and Strategy, U.S. Citizenship and Immigration Services, Department of Homeland Security, 20 Massachusetts Avenue NW., Washington, DC 20529–2141. Contact telephone number is (202) 272–8377.
DHS is revising its regulations affecting: (1) Highly skilled workers in the nonimmigrant classifications for specialty occupation from Chile, Singapore (H–1B1), and Australia (E–3); (2) the immigrant classification for employment-based first preference (EB–1) outstanding professors and researchers; and (3) nonimmigrant workers in the Commonwealth of the Northern Mariana Islands (CNMI)-Only Transitional Worker (CW–1) classification.
Specifically, in this final rule, DHS is amending its regulations to include H–1B1 and principal E–3 classifications in the list of classes of foreign nationals authorized for employment incident to status with a specific employer, and to clarify that H–1B1 and principal E–3 nonimmigrants are allowed to work without having to separately apply to DHS for employment authorization.
DHS is also amending the regulations to provide H–1B1 and principal E–3 nonimmigrants with authorization for continued employment with the same employer if the employer has timely filed for an extension of the nonimmigrant's stay. DHS is providing this same authorization for continued employment for CW–1 nonimmigrants if a petitioner has timely filed a Petition for a CNMI-Only Nonimmigrant Transitional Worker, Form I–129CW, or successor form requesting an extension of stay.
In addition, DHS is updating the regulations describing the filing procedures for extensions of stay and change of status requests to include the principal E–3 and H–1B1 nonimmigrant classifications. These changes will harmonize and align the regulations for principal E–3, H–1B1, and CW–1 nonimmigrant classifications with the existing regulations for other, similarly situated nonimmigrant classifications.
Finally, DHS is expanding the current list of initial evidence for EB–1 outstanding professors and researchers to allow petitioners to submit evidence comparable to the other forms of evidence already listed in 8 CFR 204.5(i)(3)(i). This will harmonize the regulations for EB–1 outstanding professors and researchers with certain employment-based immigrant categories that already allow for submission of comparable evidence.
DHS is amending its regulations in several ways to improve the programs serving the principal E–3, H–1B1, and CW–1 nonimmigrant classifications and the EB–1 immigrant classification for outstanding professors and researchers. These changes will harmonize the regulations governing these classifications with regulations governing similar visa classifications and remove unnecessary hurdles that have placed principal E–3, H–1B1, CW–1 and certain EB–1 workers at a disadvantage when compared to similarly situated workers in other visa classifications. DHS believes this rule also best achieves our goal of addressing unwarranted disparities involving continued employment authorization among and within particular nonimmigrant classifications.
Sections 103(a) and 214(a)(1) of the Immigration and Nationality Act (INA),
On May 12, 2014, DHS published a proposed rule to amend regulations governing filing procedures and work authorization for principal E–3 and H–1B1 nonimmigrants (8 CFR 214.1(c)(1) and 8 CFR 248.3(a) with respect to filing procedures and 8 CFR 274a.12(b)(9) and 8 CFR 274a.12(b)(25) with respect to work authorization), continued work authorization for principal E–3, H–1B1, and CW nonimmigrants (8 CFR 274a.12(b)(20)), and evidentiary requirements for EB–1 outstanding professors and researchers (8 CFR 204.5(i)(3)(ii)). By proposing this rule, DHS intended to remove current regulatory obstacles that may cause unnecessary disruptions to petitioning employers' productivity. DHS also intended to remove obstacles for these workers to remain in or enter the United States and to treat them in the same way as others under similar classifications are treated.
This final rule will not impose any additional costs on employers, workers, or any governmental entity. Changing the employment authorization regulations for H–1B1 and principal E–3 nonimmigrants will make those regulations consistent with the regulations of other similarly situated nonimmigrant worker classifications, which will provide qualitative benefits. In this final rule, DHS also amends its regulations to authorize continued employment for up to 240 days for H–1B1, principal E–3, and CW–1 nonimmigrant workers whose status has expired, provided that the petitioner timely filed the requests for extensions of stay with U.S. Citizenship and Immigration Services (USCIS). Such amendment will minimize the potential for employment disruptions for U.S. employers of H–1B1, principal E–3, and CW–1 nonimmigrant workers. Finally, this final rule may assist U.S. employers that recruit EB–1 outstanding professors and researchers by expanding the range of evidence that they may provide to support their petitions. A summary of the costs and benefits of the changes made by this rule is presented in Table 1.
The Immigration Act of 1990 (IMMACT90), among other things, reorganized immigrant classifications and also created new employment-based immigrant classifications.
American businesses continue to need highly skilled nonimmigrant and immigrant workers, and the U.S. legal immigration system can be improved by removing regulatory barriers to lawful employment of these workers through a system that reflects our diverse values and needs.
On May 12, 2014, DHS published a proposed rule in the
• Clarify that principal E–3 and H–1B1 nonimmigrants are authorized to work for the specific employer listed in their petition without requiring separate approval for work authorization from USCIS (8 CFR 274a.12(b)(25) and 8 CFR 274a.12(b)(9));
• Authorize continued employment authorization for CW–1, principal E–3, and H–1B1 nonimmigrants with pending, timely filed extension of stay requests (8 CFR 274a.12(b)(20));
• Update the regulations describing the filing procedures for extension of stay and change of status requests to include the principal E–3 and H–1B1 nonimmigrant classifications (8 CFR 214.1(c)(1) and 8 CFR 248.1(a)); and
• Allow a petitioner who wants to employ an EB–1 outstanding professor or researcher to submit evidence comparable to the evidence otherwise described in 8 CFR 204.5(i)(3)(i), which may demonstrate that the beneficiary is recognized internationally as an outstanding professor or researcher.
Consistent with the vision of attracting and retaining foreign workers, this final rule removes unnecessary obstacles for principal E–3 and H–1B1 highly skilled workers and CW–1 nonimmigrant workers to continue working in the United States, and for EB–1 outstanding professors and researchers to seek admission as immigrants. For example, under current regulations, H–1B1, CW–1, and principal E–3 nonimmigrants are not included in the regulations that authorize continued employment while a timely filed extension of stay request is pending. The regulations at 8 CFR 274a.12(b)(20) authorize foreign nationals in specific nonimmigrant classifications to continue employment with the same employer for a 240-day period beyond the authorized period specified on the Arrival-Departure Record, Form I–94, as long as a timely request for an extension of stay is filed. This means that these individuals can continue to work with the specific employer listed in their petition, even after their authorized stay expires, as long as their extension of stay request is still pending. Because Congress created the E–3, H–1B1, and CW–1 nonimmigrant classifications after 8 CFR 274a.12(b)(20) was effective, these nonimmigrant workers are not included in this provision and cannot continue to work with the same employer beyond the existing authorization while waiting for USCIS to adjudicate an extension of stay request. DHS is amending its regulations at 8 CFR 274a.12(b)(20) to give H–1B1, CW–1, and principal E–3 nonimmigrants the same treatment as other, similarly situated nonimmigrants, such as H–1B, E–1, and E–2 nonimmigrants.
Moreover, E–3 and H–1B1 nonimmigrants are not listed in the regulations describing the filing procedures for extension of stay and change of status requests. Although the form instructions for H–1B1 and principal E–3 extension of stay and change of status requests (Instructions for Petition for a Nonimmigrant Worker, Form I–129) were updated to include H–1B1 and principal E–3 nonimmigrants when these categories were first established, the regulations were not. In this final rule, DHS is amending the regulations to add H–1B1 and principal E–3 nonimmigrants to the list of nonimmigrants that may extend their stay or change their status in the United States.
In addition, current regulations do not designate H–1B1 nonimmigrants and principal E–3 as authorized to accept employment with a specific employer incident to status, although such nonimmigrants are so authorized by statute.
Finally, the language of the current EB–1 regulations for outstanding professors and researchers may not fully encompass other types of evidence that may be comparable, such as evidence that the professor or researcher has important patents or prestigious peer-reviewed funding grants. In this final rule, DHS is modifying the regulations describing permissible initial evidence for outstanding professors and researchers to allow a petitioner to submit evidence that is comparable to the currently accepted evidence listed in 8 CFR 204.5(i)(3)(i) to demonstrate that such beneficiaries are recognized internationally as outstanding in their academic areas.
In preparing this final rule, DHS considered all the public comments received and all other materials contained in the docket. This final rule adopts the regulatory amendments set forth in the proposed rule without substantive change. The rationale for the proposed rule and the reasoning provided in its background section remain valid with respect to these regulatory amendments. Section II.B above and this section each describe the changes that are the focus of this rulemaking. This final rule does not address a number of comments that DHS considered beyond the scope of this rulemaking because the comments requested changes to the regulations that DHS had not proposed and that commenters could not have reasonably anticipated that DHS would make. Such comments include suggestions for expanding premium processing services and for providing expedited processing for certain family-based petitions, travel while an application for an adjustment of status is pending, re-entry permits, translations, grace periods, specific comments in reference to another DHS rulemaking
In response to the proposed rule, DHS received 38 comments during the 60-day public comment period. Commenters included individuals, employers, workers, attorneys, nonprofit organizations, and one business organization.
While opinions on the proposed rule varied, a clear majority of the commenters supported the proposed changes in the rule. Specifically, supporters of the proposed rule welcomed the proposed employment authorization changes for principal E–3, H–1B1, and CW–1 nonimmigrants; the proposed update to the regulations clarifying the application requirements for E–3 and H–1B1 nonimmigrants requesting changes of status or extensions of stay; and the comparable evidence provision for EB–1 outstanding professors and researchers. Several commenters supported the comparable evidence provision and suggested additional evidence for DHS to consider when evaluating eligibility for EB–1 outstanding professors and researchers. Overall, the commenters supported DHS's efforts to harmonize the regulations to benefit highly skilled workers and CW–1 nonimmigrant workers and to remove unnecessary hurdles that place such workers at a disadvantage when compared to similarly situated workers.
Some commenters stated general opposition to the proposed rule, but did not offer any specific alternatives or suggestions relating to the proposals outlined in this rulemaking. Another commenter stated that the changes proposed with respect to EB–1 outstanding professors and researchers would be insufficient, and proposed a “point based system” instead.
DHS has reviewed all of the public comments received in response to the proposed rule, and responds to the issues raised by the comments below. The DHS responses are organized by subject area.
Multiple commenters provided general support for all the proposed changes in rule. One supporter stated that the proposed regulatory amendments will benefit many nonimmigrants. Another supporter indicated that the proposed changes will add to the much-needed math, science, and technology pool of workers in the United States. One commenter noted the need for regulatory action in order to attract and retain workers, and supported the ongoing efforts to harmonize the rules that are applicable to similarly situated visa categories and bring them in line with actual agency practice. This same commenter added that the proposed changes will provide uniformity and predictability for U.S. employers and their employees and will enhance compliance at virtually no cost to DHS. Another commenter also underscored the importance of removing unnecessary regulatory barriers to improve the ability of U.S. higher education institutions to attract and retain talented and sought-after professionals. Some commenters supported the changes, but did not discuss perceived benefits. One commenter requested DHS to finalize the rule quickly.
One commenter expressed general opposition to this rulemaking, but did not cite any specific provision or offer any specific alternatives or suggestions relating to the proposals outlined in this rulemaking. Another commenter opposed having temporary worker programs, in general, but did not offer any specific alternatives that would fall within the scope of this rule. DHS has not changed the final rule in response to these comments.
Three commenters supported the proposal to add the H–1B1 and principal E–3 classifications to the list of nonimmigrants authorized to work incident to status with a specific employer. They stated that the proposed change reflects the current practice, which allows work authorization based on approval of the [nonimmigrant] classification, but does not require a separate application for employment authorization. Therefore, the proposed change will produce consistency between current practice and regulatory language.
One commenter recommended that DHS amend the regulations to list B–1 nonimmigrant household employees in 8 CFR 274a.12(b) as authorized for employment with a specific employer incident to status. The commenter also recommended that DHS amend 8 CFR 274a.12(a) to include spouses of L–1, E–1, and E–2 nonimmigrants in the categories of individuals who are authorized for employment incident to status. DHS has determined that
DHS appreciates commenters' support for the proposal to add the H–1B1 and principal E–3 classifications to the list of nonimmigrants authorized to work incident to status with a specific employer. The INA describes the employment of E–3 and H–1B1 nonimmigrants with a specific, petitioning employer as the very basis for their presence in the United States.
DHS received multiple comments regarding the provision authorizing the continued employment of principal E–3 and H–1B1 nonimmigrants. Most of these comments supported the provision to authorize the continued employment for E–3 and H–1B1 nonimmigrants with timely filed, pending extension of stay requests. One commenter explained that while employers file extension requests several months prior to the expiration of the workers' nonimmigrant status, unexpected processing delays can prevent the extension requests from being approved before such status expires. In turn, the nonimmigrant employees must stop working, causing serious disruptions to both the employers and their nonimmigrant workers. The commenters further stated that the current lack of continued work authorization results in lost wages to employees and loss in productivity to employers. The commenters noted that the continued employment authorization period, which may last up to 240 days, will protect against such interruptions by ensuring that U.S. employers who employ individuals in the E–3 and H–1B1 nonimmigrant classifications experience as little disruption as possible in the employment of their workers. These commenters therefore welcomed the proposed continued employment authorization because it will minimize disruption to employers and thereby promote economic growth. These commenters also supported the continued employment authorization proposal because it would harmonize the regulations applicable to E–3 and H–1B1 nonimmigrants with regulations applicable to similarly situated nonimmigrants. For example, one of these commenters noted that this change would allow colleges and universities to treat their similarly situated employees in a fair and consistent manner. One of these commenters also stated that the proposed change would substantially aid in attracting and retaining these workers.
Additionally, one commenter supported the proposed E–3 continued work authorization because comparable eligibility for continued work authorization for H–1B nonimmigrants has been extremely helpful in allowing the commenter's current tenure-track H–1B faculty, researchers, and staff to continue employment while USCIS is processing H–1B extension requests, and would permit similarly situated E–3 employees the same benefit. DHS appreciates the support from the public for this proposed provision. The potential gap in work authorization from unanticipated processing delays can burden both employers and employees alike. DHS also believes it is important to provide employers of H–1B1 and E–3 nonimmigrants the benefits that accrue from the predictability that currently is available to employers of nonimmigrants in similar employment-based nonimmigrant classifications, who file timely requests for extensions of stay with the same employers. Therefore, DHS has determined that it will adopt this provision without change, thereby automatically extending employment authorization to principal E–3 and H–1B1 nonimmigrants with timely filed, pending extension of stay requests.
One commenter recommended expanding the 240-day rule to cover Q–1 nonimmigrants. The commenter stated that, as with other nonimmigrant classifications, government error can delay approval, leading to serious business disruptions to the employer and adverse consequences to the workers through no fault of their own.
DHS has determined that expansion of continued employment authorization beyond the classifications identified in the proposed rule is not appropriate at this time, and it has therefore not included such an expansion in this final rule. This suggestion is outside the scope of this rulemaking, which did not make any proposals or invite public comment with respect to Q–1 nonimmigrants. Therefore, in this final rule, DHS will update its regulations at 8 CFR 274a.12(b)(20) and adopt, without change, the proposed provision to authorize continued employment authorization for principal E–3 and H–1B1 nonimmigrants with pending, timely filed extension of stay requests.
Six commenters supported the provision for automatic employment authorization for CW–1 nonimmigrant workers with timely filed, pending extension of stay requests. One commenter explained that while employers file extension requests several months prior to the expiration of the workers' nonimmigrant status, unexpected processing delays can prevent the extension requests from being timely approved and cause serious disruptions to employers and nonimmigrants. Another commenter remarked that current adjudication delays for CW–1 nonimmigrant workers are burdensome on the beneficiaries and on the local economy, and therefore urged DHS to adopt the proposed continued work authorization provision for CW–1 nonimmigrant workers. Commenters commonly stated that the potential lack of work authorization due to a processing delay results in serious disruption to both an employer's business and to the employee's life. The
DHS appreciates the support from the public for this proposed provision. The disruption of employment can create a burden for both employers and employees. As a matter of equity, it is also important to ensure that CW–1 nonimmigrants who are waiting for USCIS to adjudicate their extension of stay requests with the same employer also benefit from the continued employment authorization available to other CW–1 nonimmigrants who change employers or an employee under the previous CNMI immigration system. Current regulations for the continued employment of CW–1 nonimmigrant workers are also inconsistent. Specifically, the regulations currently only provide continued work authorization for CW–1 nonimmigrant workers seeking to change to a new employer, including a change in employer resulting from early termination, and not to CW–1 nonimmigrants seeking an extension of stay with the same employer. 8 CFR 214.2(w)(7). This disparity may serve as an incentive for CW–1 nonimmigrant workers to change employers just to maintain continued employment authorization, which will inconvenience the CW–1 nonimmigrant worker's current employer who might lose the worker to another employer.
One commenter strongly supported this proposed change and noted that various employers previously sought to have a continuing work authorization provision included in the initial CW regulations without success. The commenter stated that the DHS response to this request then was that such provision was not authorized by the CNRA.
DHS notes that the interim rule amending 8 CFR 214.2(w) to create the CW classification published on October 27, 2009, and provided a 30-day comment period.
One of the commenters also supported the proposed change because it will help both employers and employees in the CNMI by providing employers with more time to file extension requests and by allowing employees to remain in lawful work-authorized status while awaiting the adjudication of the extension requests filed on their behalf. DHS appreciates the support for the continued work authorization provision for CW–1 nonimmigrants. The regulatory changes aim to provide both the employer and employee with continued employment when an employer files a timely request for an extension of stay for the CW–1 nonimmigrant worker. However, this new provision does not change the filing requirements or allot more time for employers to file extension requests. Under 8 CFR 214.2 (w)(12)(ii), an employer may file up to 6 months before it actually needs the employee's services, and this rulemaking does not change this filing requirement. Instead, this rulemaking provides a mechanism that automatically extends employment authorization, for a period of up to 240 days, while the employer's timely filed, extension of stay request remains pending.
One commenter proposed allowing an employee who transfers to another employer to continue to work pending the adjudication of the new petition with the prospective employer. DHS's proposed rule did not suggest continued work authorization for CW–1 nonimmigrant workers seeking a change of employment because DHS regulations already allow continued work authorization for changes of employment so long as certain requirements are met. As described above, under 8 CFR 214.2(w)(7), a CW–1 nonimmigrant worker may work for a prospective new employer after the prospective employer files a non-frivolous Petition for a CNMI-Only Nonimmigrant Transitional Worker, Form I–129CW, for new employment. The employer must file the petition for new employment to classify the alien as a CW–1 nonimmigrant, before the CW–1 nonimmigrant worker's authorized period of stay expires. The CW–1 nonimmigrant worker must not have worked without authorization in the United States since being admitted. If the petitioner and CW–1 nonimmigrant worker meet these conditions, then employment authorization will continue until DHS adjudicates the new petition.
One commenter proposed allowing a terminated employee to continue to work without interruption, subject to certain conditions. DHS's proposed rule did not suggest continued work authorization for terminated CW–1 nonimmigrant workers because USCIS regulations already allow for continued work authorization for terminated CW–1 nonimmigrant workers under certain circumstances. Under 8 CFR 214.2(w)(7)(v), a terminated CW–1 nonimmigrant worker who has not otherwise violated the terms and conditions of his or her status may work
While the commenters supported the continued employment authorization for CW–1 nonimmigrant workers, they also offered specific suggestions regarding various aspects of the CW–1 transitional worker program. One commenter remarked that the continued work authorization provision merely provides a temporary solution to meet the needs of the local investors, and that a permanent immigration status is necessary. The commenter encouraged the immediate passage of U.S. Senate bill S. 744 as a permanent solution to this CNMI foreign worker situation. Another commenter suggested that foreign workers in the CNMI should be provided with a “better” immigration status. The rulemaking focused on continued employment authorization for certain CW–1s with timely filed extension of stay requests. The CW program as a whole was not a subject of this rulemaking. These comments are outside the scope of this rulemaking.
DHS has determined that it will adopt this provision without change, thereby automatically extending employment authorization to CW–1 nonimmigrants who have timely filed, pending extension of stay requests for the same employer. Specifically, DHS will add the CW–1 nonimmigrant classification to the list of employment-authorized nonimmigrant classifications, at 8 CFR 274a.12(b)(20), that receive an automatic extension of employment authorization of up to 240 days while the employer's timely filed extension of stay requests remain pending. This will ensure that the CW nonimmigrants are permitted continued employment authorization based on both pending change of employers requests and pending extension of stay requests.
DHS only received one comment on the proposal to add principal E–3 and H–1B1 nonimmigrants to the list of nonimmigrant classifications that must file a petition with USCIS to request an extension of stay or change of status. The commenter stated that the proposed changes, if adopted, will go far to enable initial and uninterrupted continued employment of H–1B1 and E–3 nonimmigrants. The commenter added that the changes create equity for these nonimmigrant categories as compared to other similar nonimmigrant categories for specialty workers. For reasons previously stated, DHS will adopt this provision without change. Specifically, DHS will amend 8 CFR 214.1(c)(1) and 8 CFR 248.3(a) to add the E–3 and H–1B1 nonimmigrant classifications to the list of nonimmigrant classifications that must file a petition with USCIS to request an extension of stay or change of status. This updates the regulations so they conform to the filing procedures described in the form instructions.
DHS received a number of comments on the proposal to expand the current list of initial evidence for EB–1 outstanding professors and researchers to allow petitioners to submit evidence comparable to the other forms of evidence already listed in 8 CFR 204.5(i)(3)(i).
Most of the commenters on the EB–1 comparable evidence provision supported it, for a variety of reasons. They cited the perceived positive effects on the United States, the need for harmonization of the regulations, and the need to submit evidence to allow beneficiaries to fully document their accomplishments. DHS notes that the same commenters remarked on more than one aspect of the comparable evidence provision.
Specifically, commenters remarked that the change would positively affect the United States in a variety of ways. Two commenters noted that the comparable evidence provision would expand the number of individuals eligible for this classification and would benefit the United States as a whole. Some commenters noted that the comparable evidence provision will improve the ability of U.S. employers, especially higher education employers, to attract, recruit, and retain talented foreign professors, researchers, and scholars. One of these commenters added that this regulatory change will improve the capability to recruit and retain talented individuals which conduct the research that allows U.S. businesses to develop and sell products. This improved capability to recruit these individuals will help the U.S. economy's growth. Another commenter added that refining the EB–1 outstanding professors and researchers evidentiary list would benefit the United States by boosting research, innovation, and development.
DHS appreciates the commenters' support for the comparable evidence provision based on the perceived positive effects on United States' competitiveness and the Nation's economy. DHS agrees with the commenters that the proposed comparable evidence provision may also help U.S. employers recruit EB–1 outstanding professors and researchers.
A number of commenters supported expansion of the current list of evidentiary criteria for EB–1 outstanding professors and researchers to allow the submission of comparable evidence because it would harmonize the EB–1 outstanding professor and researcher regulations with those of other comparable employment-based immigrant classifications, eliminating unwarranted disparities with respect to these policies. Commenters emphasized that the proposed comparable evidence provision in turn would bring the criteria for proving eligibility for the outstanding professors and researchers classification in line with those that have long been permitted for other preference categories such as EB–1 aliens of extraordinary ability and EB–2 aliens of exceptional ability. These commenters stated that the proposed change is a logical extension of the existing regulatory provision listing the evidentiary criteria for EB–1 outstanding professors and researchers, especially since the similarly situated EB–1 extraordinary ability classification, which requires satisfaction of a higher evidentiary threshold, allows for consideration of comparable evidence.
DHS appreciates commenters' support for the comparable evidence provision based on the harmonization of the comparable regulations. DHS agrees that by allowing for the submission of comparable evidence, DHS will bring the evidentiary standards of the EB–1 outstanding professor and researcher category in line with those currently available to individuals qualifying under both the EB–1 extraordinary ability and EB–2 exceptional ability categories. This change in turn will provide equity for EB–1 outstanding professors and researchers with other
A number of commenters supported expanding the criteria for EB–1 outstanding professors and researchers because doing so would remove evidentiary limitations and allow employers to present full documentation of an employee's qualifications. One of these commenters added that the language in the proposed rule was well drafted and broad enough to include all evidence that may prove outstanding achievement. Under current regulation, petitioners need to fit evidence into specific evidentiary categories. For example, petitioners have submitted funding grants as documentation of major awards under 8 CFR 204.5(i)(3)(i)(A). In other instances, petitioners may have omitted relevant evidence that could have helped to demonstrate the beneficiary is recognized internationally as outstanding, such as high salary and affiliation with prestigious institutions, because they did not believe it would fit into any of the regulatory evidentiary category. Commenters noted that the proposed change adds necessary flexibility; for instance, this change will now potentially allow for the submission of important patents, grant funding and other such achievements that may not neatly fall into the previously existing evidentiary categories. Two of these commenters also commended DHS for recognizing that the types of evidence relevant to the determination of eligibility for this classification have changed greatly since these evidentiary criteria were first created, and will continue to evolve over time due to the changing needs of American businesses.
One of the commenters that supported the comparable evidence provision also expressed concern regarding how USCIS considers comparable evidence. The commenter reported that recent decisions in other employment-based categories suggest that adjudicators allow comparable evidence only when none of the listed criteria apply. The commenter added that comparable evidence should be presumed acceptable, regardless of whether any of the otherwise enumerated criteria apply, as long as the evidence is relevant to the merits of the case. This commenter urged DHS to clarify this approach here, as well as with certain employment-based classifications where comparable evidence is currently in use.
DHS appreciates the commenter's concern regarding adjudicative trends in how USCIS considers comparable evidence. DHS regulations provide that petitions in the EB–1 extraordinary ability and EB–2 exceptional ability classifications must establish that one or more permissible standards are not readily applicable to the beneficiary's occupation in order to rely on the comparable evidence provision respective to those standards.
For EB–1 outstanding professors and researchers, DHS confirms that a petitioner will be able to submit comparable evidence instead of, or in addition to, evidence targeted at the standards currently listed in 8 CFR 204.5(i)(3)(i) to demonstrate that the beneficiary is internationally recognized as outstanding if the currently listed standards do not readily apply. The intent of this provision is to allow petitioners, in cases where evidence of the beneficiary's achievements do not fit neatly into the enumerated list, to submit alternate, but qualitatively comparable, evidence. Under this provision, a petitioner may submit evidence falling within the standards listed under 8 CFR 204.5(i)(3)(i), and may also use the comparable evidence provision to submit additional types of comparable evidence that is not listed, or that may not be fully encompassed, in 8 CFR 204.5(i)(3)(i). DHS notes that a petitioner's characterization of existing standards as “not readily applying” to the submitted evidence will be considered in the totality of the circumstances, but USCIS ultimately will determine which standard is satisfied, if any, by any form of submitted evidence.
As noted in the proposed rule, limiting submission of comparable evidence for outstanding professors and researchers only to instances in which the standards do not readily apply “to the alien's occupation” would not adequately serve the goal of this regulatory change because unlike the standards for EB–1 aliens of extraordinary ability and EB–2 aliens of exceptional ability, the standards for EB–1 outstanding professors and researchers are tailored to only these two occupations.
After establishing that the evidentiary standards listed in 8 CFR 204.5(i)(3)(i) does not readily apply to the evidence he or she is submitting, the petitioner may then submit alternative, but qualitatively comparable evidence for those standards. The existing evidentiary standards listed in 8 CFR 204.5(i)(3)(i) serve as a roadmap for determining, among other things, the quantity and types of evidence that should be submitted in order for such evidence to be considered “comparable.”
Given the overwhelming support and strong justification for the comparable evidence provision as proposed, DHS will adopt it and amend 8 CFR 204.5(i)(3) to include a comparable evidence provision.
Two commenters opposed the comparable evidence provision for outstanding professors and researchers. One commenter indicated that they opposed it because it will expand the number of eligible foreign nationals competing for high-tech jobs. The commenter stated that many engineers, computer professionals and scientists are unemployed or under-employed and asserted that the proposed change
While the commenter did not submit data to support the wage and instability concerns, DHS takes these comments seriously. DHS appreciates this viewpoint and has carefully considered the potential for any negative effects on the labor market as a result of this rulemaking. Congress imposed a numerical limitation for the number of EB–1 visas available annually. The annual cap on EB–1 visas generally is set by statute at 40,000, plus any visas left over from the fourth and fifth employment based preference categories (special immigrants and immigrant investors) described in section 203(b)(4) and (5) of the INA, 8 U.S.C. 1153(b)(4) and (5). In FY 14, USCIS received 3,549 petitions for EB–1 outstanding professors and researchers. DHS notes that this provision does not expand the visa numerical limitation beyond that set forth by Congress. Rather, DHS is simply expanding the list of evidentiary standards so that those who may be meritorious of classification under INA 203(b)(1)(B) can more readily demonstrate their eligibility, consistent with similar classifications. This provision provides greater flexibility for petitioners on what evidence they may submit to show that the beneficiary is recognized internationally as outstanding in the academic field specified in the petition. It does not change any of the remaining petitioning requirements (such as the job offer) or expand the types of individuals who can qualify for the EB–1 classification beyond those individuals authorized under the statute. Instead, this change better enables petitioners to hire outstanding professors and researchers by providing a set of standards that are flexible enough to encompass any evidence that may demonstrate that they are recognized internationally as outstanding.
Another commenter expressed concern regarding existing fraud and abuse in the H–1B and EB–1 programs, stating that the government should first focus on ways to prevent such abuse “before passing any law to ease the process” for these individuals. The commenter did not provide any data on the nature or extent of such fraud and abuse, and did not otherwise identify a connection between the proposed rule's provisions and past instances of fraud and abuse. DHS takes concerns regarding fraud and abuse very seriously and has measures in place to detect and combat fraud. Strict consequences are already in place for immigration-related fraud and criminal activities, including inadmissibility to the United States, mandatory detention, ineligibility for naturalization, and removability.
Additionally, the USCIS Fraud Detection and National Security Directorate (FDNS) currently combats fraud and abuse, including in the H–1B and EB–1 programs, by developing and maintaining efficient and effective anti-fraud and screening programs, leading information sharing and collaboration activities, and supporting law enforcement and intelligence communities. FDNS's primary mission is to determine whether individuals or organizations filing for immigration benefits pose a threat to national security, public safety, or the integrity of the nation's legal immigration system. FDNS's objective is to enhance USCIS's effectiveness and efficiency in detecting and removing known and suspected fraud from the application process, thus promoting the efficient processing of legitimate applications and petitions. FDNS officers resolve background check information and other concerns that surface during the processing of immigration benefit applications and petitions. Resolution often requires communication with law enforcement or intelligence agencies to make sure that the information is relevant to the applicant or petitioner at hand and, if so, whether the information would have an impact on eligibility for the benefit. FDNS officers also perform checks of USCIS databases and public information, as well as other administrative inquiries, to verify information provided on, and in support of, applications and petitions. FDNS uses the Fraud Detection and National Security Data System (FDNS–DS) to identify fraud and track potential patterns.
USCIS has formed a partnership with U.S. Immigration and Customs Enforcement (ICE), in which FDNS pursues administrative inquiries into most application and petition fraud, while ICE conducts criminal investigations into major fraud conspiracies. Individuals with information regarding fraud and abuse in the immigration benefits system are encouraged to contact FDNS at
Six commenters suggested additional categories of evidence that DHS should consider accepting as comparable evidence or initial evidence. One commenter suggested that DHS accept the number of years of experience working in a research field and an offer of employment by a research organization or institute of higher education as comparable evidence to the various criteria
One commenter suggested that DHS give priority to U.S. doctoral degree holders applying as outstanding researchers or professors who already have a tenure-track faculty position. The commenter explained that these individuals teach and conduct research in narrowly focused fields and are therefore not heavily cited. As a result, they are not usually eligible for EB–1 positions because they cannot meet the existing criterion involving “published material in professional publications written by others” about the professor or researcher's work.
In general, three commenters suggested that DHS consider a U.S. earned doctoral degree as evidence to qualify for the EB–1 classification. Their comments varied in detail and scope. One commenter stated that DHS should grant the EB–1 classification to individuals who obtained their doctoral degrees from U.S. schools. This commenter did not provide any details or context to clarify this suggestion. Another commenter suggested that DHS should allow individuals with U.S. doctoral degrees in science, technology, engineering and mathematics (STEM) with a related job [offer] to qualify for the EB–1 category. DHS is unable to
One of these commenters suggested that DHS expand the list of initial evidence to include a STEM doctoral degree issued by a U.S. accredited university, and that DHS could publish a list of U.S. accredited universities to make the criteria more transparent. The commenter explained that a petitioner could satisfy the proposed criteria by submitting an “attested copy”
DHS carefully considered the commenters' suggestions for initial and additional evidence for the EB–1 outstanding professors and researchers classification. DHS believes that the evidence suggested in the comments above regarding minimum number of years of experience and minimum education requirements generally would not be beneficial in an analysis of whether an individual is internationally recognized as outstanding in his or her academic field. The purpose of the proposed comparable evidence provision is to allow petitioners to present evidence that, although not on the enumerated list, may still serve to demonstrate that the professor or researcher is internationally recognized as outstanding. DHS appreciates that to achieve this goal, the standards listed in 8 CFR 204.5(i)(3)(i) need to have some measure of flexibility so they may continue to evolve over time in response to U.S. business needs and/or the changing nature of certain work environments or practices. It is not clear, however, whether the commenters' suggestions regarding minimum number of years of experience, minimum education requirements, and salary requirements are intended to limit or expand the current evidentiary criteria for EB–1 outstanding professors or researchers. If they were intended to limit the criteria, then the commenters' suggestions would have the effect of narrowing the eligibility criteria by requiring very specific evidence that is possessed by a specific subset of the potential population of outstanding professors and researchers. In direct contrast, the intended purpose of the comparable evidence provision is to provide flexibility for this population. If the commenter's suggestions, however, were intended to expand the type of evidence that may be considered, that suggestion is consistent with the purpose of the comparable evidence provision as it provides needed flexibility to establish eligibility. Therefore, DHS declines to adopt these suggestions as amendments to the standards listed in 8 CFR 204.5(i)(3)(i) in favor of a broad comparable evidence provision.
One commenter expressed concern that adding the proposed comparable evidence provision will not improve the probability that an outstanding professor and researcher will qualify for the classification. The commenter explained that adjudicators analyze this classification under a two-part analysis, and therefore meeting the criteria is not enough to prove eligibility. Instead, the commenter suggested that DHS impose a point- based system as an alternative, transparent method for evaluating whether these individuals are eligible for the classification. The commenter added that this would eliminate any subjectivity in the process and allow a researcher or petitioner to predict whether he or she meets or does not meet the criteria.
DHS disagrees with the commenter's assertion that the proposed comparable evidence provision will not benefit petitioners and these specific foreign workers. The stated purpose of the proposed comparable evidence provision is to allow petitioners to submit additional types of evidence and to fully document the beneficiary's international recognition as an outstanding professor or researcher in order to demonstrate eligibility for the requested classification. However, this proposal does not change the eligibility standard for this classification. The petitioner must still demonstrate, by a preponderance of the evidence, that the beneficiary is recognized internationally as outstanding in the specific academic area.
The commenter correctly asserted that adjudicators analyze this classification using a two-part approach. The USCIS policy memo,
DHS appreciates the suggestion for an alternative framework for analysis of the EB–1 outstanding professors and researchers classification, but DHS declines to adopt the suggested point-based system as it would require a much broader reshaping of the current immigration system. This suggestion would require a wholesale rulemaking for all the other classifications, which is beyond the scope of this rulemaking.
DHS declines to adopt the suggestions for initial evidence, additional evidence, and an alternative framework. As previously noted, DHS is tailoring this regulation to provide EB–1 outstanding professors and researchers with a comparable evidence provision that mirrors the other employment-based immigrant categories that already allow for submission of comparable evidence.
One commenter requested clarification as to whether the changes proposed in this rule would affect processing times for family immigration. The commenter did not state which aspects of the proposed changes he or she believes could impact family immigration processing times. While there is always a possibility that changes to one USCIS business process may trigger unanticipated downstream effects on other USCIS business processes, DHS does not anticipate that changes made by this rule will have a direct impact on family based immigration processing times.
Another commenter supported DHS's replacement of the more narrow term “employer” with the more general term “petitioner” in reference to who may file a request to change or extend status under 8 CFR 214.1(c)(1) and 248.3(a). The commenter explained that the term “employer” does not adequately describe the array of individuals and entities that may file petitions under 8 CFR 214.2 and the term “petitioner” is a much more accurate descriptor. DHS agrees that the term “petitioner” is a more accurate depiction of the individual who may file in a variety of scenarios. Additionally, this change will generally eliminate inconsistency between the change of status and extension of stay provisions and the classification-specific provisions in 8 CFR 214.2. This change will eliminate any confusion that the current inconsistency between these provisions may have caused. DHS will adopt this provision without change.
Executive Orders 12866 and 13563 direct agencies to assess the costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distributive impacts, and equity). Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, reducing costs, harmonizing rules, and promoting flexibility. This rule has not been designated a “significant regulatory action,” under section 3(f) of Executive Order 12866. Accordingly, the rule has not been reviewed by the Office of Management and Budget (OMB).
This analysis updates the estimated costs and benefits discussed in the proposed rule. This final rule will not impose any additional compliance costs on employers, individuals, or government entities, and will not require additional funding for the Federal Government. However, DHS notes that there could be additional familiarization costs as employers read the final rule in the
Additionally, DHS will allow petitioners of EB–1 outstanding professors and researchers to submit comparable evidence, instead of or in addition to the evidence listed in 8 CFR 204.5(i)(3)(i), to demonstrate that the professor or researcher is recognized internationally as outstanding in his or her academic field. Allowing comparable evidence for EB–1 outstanding professors and researchers will match the evidentiary requirements with those of similarly situated employment-based immigrant classifications.
DHS notes that the above-referenced changes are part of DHS's Retrospective Review Plan for Existing Regulations under Executive Order 13563.
The costs and benefits of the final rule are summarized in Table 2.
A summary of the classification types affected by this final rule is shown in Table 3.
Under
In this rule, DHS amends its regulations to permit principal E–3 and H–1B1 nonimmigrants to continue their employment with the same employer for up to 240 days after their authorized period of stay expires (as specified on their Arrival-Departure Record, Form I–94) while requests for extension of stay on their behalf are pending. To obtain authorization to continue employment for up to 240 days, employers or petitioners must timely file the Petition for Nonimmigrant Worker, Form I–129. Since employers are already required to file the Petition for Nonimmigrant Worker, Form I–129, in order to request an extension of stay on behalf of the nonimmigrant worker, there are no additional filing requirements or costs for employers or petitioners to comply with in this final rule. DHS notes there are minimal familiarization costs to employers associated with reading the rule in the
Table 4 shows that USCIS received a total of 5,294 extension of stay requests for H–1B1 and principal E–3 nonimmigrant workers in the FYs from 2010 through 2014 (an average of 1,059 requests per year). USCIS approved 4,026 extensions of stay requests in the same period (an average of 805 per year). Extension of stay requests received and petition approvals are not meant for direct comparison because USCIS may receive a petition in one year but make a decision on it in another year.
USCIS does not have an estimate of either: (a) the number of cases where principal E–3 and H–1B1 nonimmigrants are unable to continue employment with their employer because their employer's timely petition for an extension of stay was not adjudicated before their authorized period of stay expired, or (b) how long principal E–3 and H–1B1 nonimmigrants were unable to work when their employer's timely petition for an extension of stay was not adjudicated before their authorized period of stay expired.
In addition, DHS is amending the regulations to codify current practices. Specifically, DHS is amending 8 CFR 274a.12(b) to clarify in the regulations that the principal E–3 and H–1B1 nonimmigrant classifications are employment authorized incident to status with a specific employer. DHS is also amending 8 CFR 214.1(c)(1) and 8 CFR 248.3(a) to add the principal E–3 and H–1B1 nonimmigrant classifications to the list of nonimmigrant classifications that must file a petition with USCIS to make an extension of stay or change of status request. Again, both of these regulatory clarifications are consistent with current practice.
This provision of the final rule will apply to the CW–1 classification, which is issued solely to nonimmigrant workers in the CNMI. The CW–1 nonimmigrant visa classification was created to allow certain workers who are otherwise ineligible for any other nonimmigrant visa classification under the INA to work in the CNMI during the transition period to the U.S. Federal immigration system. This transition period was set to end on December 31, 2014. On June 3, 2014, the U.S. Secretary of Labor exercised statutory responsibility and authority by extending the CW transitional worker program for an additional 5 years, through December 31, 2019.
CW–1 nonimmigrant workers may be initially admitted to the CNMI for a
DHS has determined that current regulations contain an inconsistency. While current regulations provide continued work authorization for CW–1 nonimmigrant workers while petitions for a change of employers are pending and for certain beneficiaries of initial CW transitional worker petitions filed on or before November 27, 2011, continued work authorization is not currently provided for CW–1 nonimmigrant workers requesting extensions of stay with the same employer. This inconsistency in the regulations may create an incentive for CW–1 nonimmigrant workers to change employers, as they would have the advantage of uninterrupted work authorization.
DHS is revising the regulations to allow for equitable treatment of CW–1 nonimmigrant workers who remain with the same employer by extending continued employment authorization for up to 240 days while a timely filed, pending request for an extension of stay with the same employer is being adjudicated. As with the similar proposal in this rule regarding H–1B1 and principal E–3 nonimmigrants, current employers of CW–1 nonimmigrant workers may also avoid productivity losses that could occur if a CW–1 nonimmigrant worker cannot continue employment while the timely filed extension request is pending.
The CW–1 nonimmigrant classification is temporary. DHS has established numerical limitations on the number of CW–1 nonimmigrant classifications that may be granted (see Table 5). The numerical limitations apply to both initial petitions and extension of stay requests, including change of employer petitions, in a given FY. DHS has set the numerical limitation for CW–1 nonimmigrant workers at 12,999 for FY 2016.
Source: FYs 2011 and 2012, 8 CFR 214(w)(viii). FY 2013,
DHS set the numerical limit of CW–1 nonimmigrant workers at 14,000 for FY 2014 and petitioning employers filed initial petitions for 1,133 beneficiaries; extension of stay requests from the same employer for 8,952 beneficiaries; and extension of stay requests from new employers for an additional 1,298 beneficiaries.
This provision will not impose any additional costs on any petitioning employer or for CW–1 nonimmigrant workers. The benefits of this final rule will be that DHS will treat CW–1 nonimmigrant workers whose extension of stay request is timely filed by the same employer similar relative to other CW–1 nonimmigrant workers whose request is timely filed by a new employer. Additionally, this provision will mitigate any potential distortion in the labor market for employers of CW–1 nonimmigrant workers created by the differing provisions for retained workers versus provisions for workers changing employers and prevent a potential loss of productivity for current employers. Under current law, these benefits would be limited in duration, as the transition period in which CW–1 nonimmigrant worker classifications are issued is now scheduled to end on December 31, 2019. Unfortunately, USCIS does not have data to permit a quantitative estimation of the benefits
For the EB–1 outstanding professor and researcher immigrant classification, under current regulations, a petitioner must submit initial evidence to demonstrate that the beneficiary is recognized internationally as outstanding in his or her specific academic field. The type of evidence that is required is outlined in 8 CFR 204.5(i)(3).
To demonstrate that the EB–1 professor or researcher is recognized internationally as outstanding in his or her academic field, DHS, through this rulemaking, is allowing petitioners to substitute comparable evidence (examples might include award of important patents and prestigious, peer-reviewed funding or grants) for the evidence listed in 8 CFR 204.5(i)(3)(i)(A)—(F).
By allowing for comparable evidence, DHS will harmonize the evidentiary requirements of the EB–1 outstanding professor and researcher category with those currently available to the EB–1 extraordinary ability category as well as the EB–2 category for a person of exceptional ability.
This provision of the final rule will not create additional costs for any petitioning employer or for the EB–1 outstanding professor and researcher classification. The benefits of this provision are qualitative, as it will treat EB–1 outstanding professors and researchers the same as certain other individuals who seek similar
As shown in Table 6, over the past 10 FY(s), USCIS approved an average of 93.23 percent of EB–1 petitions for outstanding professors and researchers under the current evidentiary standards. USCIS does not have data to indicate which, if any, of the 2,379 petitions that were not approved from FY 2005 through FY 2014 would have been approved under the proposed evidentiary standards. Furthermore, we are not able to estimate whether the proposed evidentiary standards would alter the demand for EB–1 outstanding professors and researchers by U.S. employers. Because of this data limitation, the further quantification of this benefit is not possible.
DHS welcomed public comments from impacted stakeholders, such as employers or prospective employers of an EB–1 outstanding professor or researcher, providing information or data that would enable DHS to calculate the resulting benefits of this provision. DHS did not receive any data on this request that would allow DHS to calculate quantitative benefits of this regulatory change. As indicated earlier in the preamble, DHS did receive comments
The Regulatory Flexibility Act of 1980 (RFA), 5 U.S.C. 601–612, as amended by the Small Business Regulatory Enforcement Fairness Act of 1996, Public Law 104–121 (March 29, 1996), requires Federal agencies to consider the potential impact of regulations on small entities while they are developing the rules. The term “small entities” comprises small businesses, not-for-profit organizations that are independently owned and operated and are not dominant in their fields, and governmental jurisdictions with populations of less than 50,000. This final rule revises regulations to allow for additional flexibilities; harmonizes the conditions of employment of principal E–3, H–1B1, and CW–1 nonimmigrant workers with other, similarly situated nonimmigrant categories; and harmonizes the allowance of comparable evidence for EB–1 outstanding professors and researchers with evidentiary requirements of other similar employment-based immigrant categories. As discussed previously, DHS does not anticipate that the additional provisions will result in additional compliance costs for impacted U.S. employers, including any small entities, other than the minimal costs associated with reading and becoming familiar with benefits offered by the rule.
As discussed extensively in the regulatory assessment for Executive Orders 12866 and 13563 and elsewhere throughout the preamble, this final rule does not impose any additional compliance costs on U.S. employers. U.S. employers must continue filing extension of stay requests with DHS to extend the period of authorized stay of E–3, H–1B1, and CW–1 nonimmigrant employees, as is currently required. This final rule, however, will allow for a continued period of authorized employment for the nonimmigrant worker who is the beneficiary of this petition, provided that the petition is timely filed. This will provide increased flexibilities for the U.S. petitioning employers without imposing any additional costs or compliance procedures.
Based on the foregoing, DHS certifies that this rule will not have a significant economic impact on a substantial number of small entities.
This final rule will not result in the expenditure by State, local and tribal governments, in the aggregate, or by the private sector, of $100 million or more in any 1 year, and it will not significantly or uniquely affect small governments. Therefore, no actions were deemed necessary under the provisions of the Unfunded Mandates Reform Act of 1995.
This final rule is not a major rule as defined by section 804 of the Small Business Regulatory Enforcement Act of 1996. This rule will not result in an annual effect on the economy of $100 million or more; a major increase in costs or prices; or significant adverse effects on competition, employment, investment, productivity, innovation, or on the ability of United States-based companies to compete with foreign-based companies in domestic and export markets.
This rule will not have substantial direct effects on the States, on the relationship between the Federal Government and the States, or on the distribution of power and responsibilities among the various levels of government. Therefore, in accordance with section 6 of Executive Order 13132, it is determined that this rule does not have sufficient federalism implications to warrant the preparation of a federalism summary impact statement.
This rule meets the applicable standards set forth in sections 3(a) and 3(b)(2) of Executive Order 12988.
Under the Paperwork Reduction Act (PRA) of 1995, Public Law 104–13, agencies are required to submit to the Office of Management and Budget (OMB), for review and approval, any reporting requirements inherent in a rule.
The information collection requirement contained in this rule, Immigrant Petition for Alien Worker, Form I–140, has been previously approved for use by OMB under the PRA. The OMB control number for the information collection is 1615–0015.
This final rule requires a revision to the Immigrant Petition for Alien Worker, Form I–140, instructions to expand the current list of evidentiary standards to include comparable evidence so that U.S. employers petitioning for an EB–1 outstanding professor or researcher may be aware that they may submit additional or alternative documentation demonstrating the beneficiary's achievements if the evidence otherwise described in 8 CFR 204.5(i)(3)(i) does not readily apply. Specifically, DHS is adding a new paragraph “b” under the “Initial Evidence” section of the form instructions, to specify that employers filing for an outstanding professor or researcher may submit comparable evidence to establish the foreign national's eligibility if the listed standards under 8 CFR 204.5(i)(3)(i) do not readily apply. DHS is also providing minor clarifying language updates to the form instructions to maintain parity among USCIS forms. DHS has submitted the revised information collection request (ICR) to OMB for review, and OMB has conducted a preliminary review under 5 CFR 1320.11.
DHS has considered the public comments received in response to EB–1 provision in the proposed rule,
DHS did not receive comments related to the Immigrant Petition for Alien Workers, Form I–140, revisions. As a result, DHS will not submit any further changes to the information collection.
USCIS has submitted the supporting statement to OMB as part of its request for approval of this revised information collection instrument. There is no change in the estimated annual burden hours initially reported in the proposed rule. Based on a technical and procedural update required in the ICRs for all USCIS forms, USCIS has newly accounted for estimates for existing out-of-pocket costs that respondents may incur to obtain tax, financial, or business records, and/or other evidentiary documentation depending on the specific employment-based immigrant visa classifications requested on the Immigrant Petition for Alien Worker, Form I–140. This change in the ICR is a technical and procedural update and is not a result of any change related to this final rule.
Administrative practice and procedure, Immigration, Reporting and recordkeeping requirements.
Administrative practice and procedure, Aliens, Cultural exchange programs, Employment, Foreign officials, Health professions, Reporting and recordkeeping, Students.
Aliens, Reporting and recordkeeping requirements.
Administrative practice and procedure, Aliens, Employment, Penalties, Reporting and recordkeeping requirements.
Accordingly, chapter I of title 8 of the Code of Federal Regulations is amended as follows:
8 U.S.C. 1101, 1103, 1151, 1153, 1154, 1182, 1184, 1186a, 1255, 1641; 8 CFR part 2.
(i) * * *
(3) * * *
(ii) If the standards in paragraph (i)(3)(i) of this section do not readily apply, the petitioner may submit comparable evidence to establish the beneficiary's eligibility.
8 U.S.C. 1101, 1102, 1103, 1182, 1184, 1186a, 1187, 1221, 1281, 1282, 1301–1305 and 1372; sec. 643, Public Law 104–208, 110 Stat. 3009–708; Public Law 106–386, 114 Stat. 1477–1480; section 141 of the Compacts of Free Association with the Federated States of Micronesia and the Republic of the Marshall Islands, and with the Government of Palau, 48 U.S.C. 1901 note, and 1931 note, respectively; 8 CFR part 2.
The revision and addition read as follows:
(c) * * *
(1)
8 U.S.C. 1101, 1103, 1184, 1258; 8 CFR part 2.
(a)
8 U.S.C. 1101, 1103, 1324a; 48 U.S.C. 1806; 8 CFR part 2.
The revisions and addition read as follows:
(b) * * *
(9) A temporary worker or trainee (H–1, H–2A, H–2B, or H–3), pursuant to § 214.2(h) of this chapter, or a nonimmigrant specialty occupation worker pursuant to section 101(a)(15)(H)(i)(b1) of the Act. * * *
(20) A nonimmigrant alien within the class of aliens described in paragraphs (b)(2), (b)(5), (b)(8), (b)(9), (b)(10), (b)(11), (b)(12), (b)(13), (b)(14), (b)(16), (b)(19), (b)(23) and (b)(25) of this section whose status has expired but on whose behalf an application for an extension of stay was timely filed pursuant to § 214.2 or § 214.6 of this chapter. * * *
(25) A nonimmigrant treaty alien in a specialty occupation (E–3) pursuant to section 101(a)(15)(E)(iii) of the Act.
Federal Aviation Administration (FAA), DOT.
Final rule.
This action amends the city designation of the Class D airspace at Broomfield, CO, changing the designation to Denver, CO, and the airport name to Rocky Mountain Metropolitan Airport. The name and associated city location of the airport are updated to coincide with the FAA's aeronautical database. This does not affect the charted boundaries or operating requirements of the airspace.
Effective 0901 UTC, March 31, 2016. The Director of the Federal Register approves this incorporation by reference action under Title 1, Code of Federal Regulations, part 51, subject to the annual revision of FAA Order 7400.9 and publication of conforming amendments.
FAA Order 7400.9Z, Airspace Designations and Reporting Points, and subsequent amendments can be viewed online at
FAA Order 7400.9, Airspace Designations and Reporting Points, is published yearly and effective on September 15.
Steve Haga, Federal Aviation Administration, Operations Support Group, Western Service Center, 1601 Lind Avenue SW., Renton, WA 98057; telephone (425) 203–4563.
The FAA's authority to issue rules regarding aviation safety is found in Title 49 of the United States Code. Subtitle I, Section 106 describes the authority of the FAA Administrator. Subtitle VII, Aviation Programs, describes in more detail the scope of the agency's authority. This rulemaking is promulgated under the authority described in Subtitle VII, Part A, Subpart I, Section 40103. Under that section, the FAA is charged with prescribing regulations to assign the use of airspace necessary to ensure the safety of aircraft and the efficient use of airspace. This regulation is within the scope of that authority as it amends Class D airspace at Denver, CO.
This document amends FAA Order 7400.9Z, Airspace Designations and Reporting Points, dated August 6, 2015, and effective September 15, 2015. FAA Order 7400.9Z is publicly available as listed in the
This amendment to Title 14, Code of Federal Regulations (14 CFR) part 71 modifies the legal description of the Class D airspace at Denver, CO, by updating the name and associated city designation of the airport to coincide with the FAA's aeronautical database. Jefferson County Airport is renamed Rocky Mountain Metropolitan Airport and the city designation is corrected from Broomfield, CO, to Denver, CO. This does not affect the boundaries or operating requirements of the airspace.
Class D airspace designations are published in paragraph 5000 of FAA Order 7400.9Z dated August 6, 2015, and effective September 15, 2015, which is incorporated by reference in 14 CFR part 71.1. The Class D airspace designations listed in this document will be published subsequently in the Order.
This is an administrative change amending the airport name and city location to be in concert with the FAAs aeronautical database, and does not affect the boundaries, or operating requirements of the airspace, therefore, notice and public procedure under 5 U.S.C. 553(b) are unnecessary.
The FAA has determined that this regulation only involves an established body of technical regulations for which frequent and routine amendments are necessary to keep them operationally current, is non-controversial and
The FAA has determined that this action qualifies for categorical exclusion under the National Environmental Policy Act in accordance with FAA Order 1050.1F, “Environmental Impacts: Policies and Procedures,” paragraph 5–6.5a. This airspace action is not expected to cause any potentially significant environmental impacts, and no extraordinary circumstances exist that warrant preparation of an environmental assessment.
Airspace, Incorporation by reference, Navigation (air).
In consideration of the foregoing, the Federal Aviation Administration amends 14 CFR part 71 as follows:
49 U.S.C. 106(f), 106(g); 40103, 40113, 40120; E.O. 10854, 24 FR 9565, 3 CFR, 1959–1963 Comp., p. 389.
That airspace extending upward from the surface to, but not including, 8,000 feet MSL, within a 5-mile radius of Rocky Mountain Metropolitan Airport. This Class D airspace area is effective during the specific dates and times established in advance by a Notice to Airmen. The effective date and time will thereafter be continuously published in the Airport/Facility Directory.
U.S. Customs and Border Protection, Department of Homeland Security; Department of the Treasury.
Final rule.
This document adopts as a final rule, with one change, interim amendments to the U.S. Customs and Border Protection (CBP) regulations that were published in the
Effective February 16, 2016.
Textile Operational Aspects: Anita Harris, Textile Operations Branch, Office of International Trade, (202) 863–6241.
Other Operational Aspects: Seth Mazze, Trade Policy and Programs, Office of International Trade, (202) 863–6567.
Legal Aspects: Yuliya Gulis, Regulations and Rulings, Office of International Trade, (202) 325–0042.
On May 18, 2004, the United States and Australia (the “Parties”) signed the United States-Australia Free Trade Agreement (“AFTA” or “Agreement”). On August 3, 2004, the President signed into law the United States-Australian Free Trade Agreement Implementation Act (the “Act”), Public Law 108–286, 118 Stat. 919 (19 U.S.C. 3805 note), which approved and made statutory changes to implement the AFTA. On December 20, 2004, the President signed Proclamation 7857 to implement the AFTA. The Proclamation, which was published in the
On February 10, 2015, CBP published CBP Dec. 15–03 in the
Although the interim regulatory amendments were promulgated without prior public notice and comment procedures and took effect on February 10, 2015, CBP Dec. 15–03 provided for the submission of public comments which would be considered before adoption of the interim regulations as a final rule. The prescribed public comment closed on April 13, 2015. CBP received one comment on CBP Dec. 15–03.
One response was received to the solicitation of comments on the interim rule set forth in CBP Dec. 15–03. The comment is discussed below.
One commenter questioned whether the AFTA requires that Australian exporters be consulted before the interim regulations take effect.
The changes proposed in the interim regulations took effect on the date of publication of the interim regulations.
This document clarifies 19 CFR 10.725(c) by removing the parenthetical cross reference to §§ 10.746 and 10.747 and, instead, stating that the importer's actions must be “pursuant to” those CBP regulations.
After further review of the matter, including consideration of the above-mentioned comment submitted in response to CBP's solicitation of public comment, CBP has determined to adopt as final, with a clarification, the interim rule published in the
This document is not a regulation subject to the provisions of Executive Order 12866 of September 30, 1993 (58 FR 51735, October 1993), because it pertains to a foreign affairs function of the United States and implements an international agreement, as described above, and therefore is specifically exempted by section 3(d)(2) of Executive Order 12866.
CBP Dec. 15–03 was issued as an interim rule rather than a notice of proposed rulemaking because CBP had determined that the interim regulations involve a foreign affairs function of the United States pursuant to section 553(a)(1) of the Administrative Procedure Act (APA). As no notice of proposed rulemaking was required, the provisions of the Regulatory Flexibility Act, as amended (5 U.S.C. 601
The collections of information contained in these regulations have previously been reviewed and approved by the Office of Management and Budget (OMB) in accordance with the requirements of the Paperwork Reduction Act (44 U.S.C. 3507) under control number 1651–0117, which covers many of the free trade agreement requirements that CBP administers, and 1651–0076, which covers general recordkeeping requirements. The collections of information in these regulations are in §§ 10.723, 10.724, and 10.727 of title 19 of the Code of Federal Regulations (19 CFR 10.723, 10.724, and 10.727). This information is required in connection with general recordkeeping requirements (§ 10.727), as well as claims for preferential tariff treatment under the AFTA and the Act and will be used by CBP to determine eligibility for tariff preference under the AFTA and the Act. The likely respondents are business organizations including importers, exporters and manufacturers.
The estimated total annual reporting burden associated with the collection of information in this final rule is 4,000 hours. Under the Paperwork Reduction Act, an agency may not conduct or sponsor and a person is not required to respond to a collection of information, unless it displays a valid OMB control number.
This document is being issued in accordance with § 0.1(a)(1) of the CBP regulations (19 CFR 0.1(a)(1)) pertaining to the authority of the Secretary of the Treasury (or his/her delegate) to approve regulations related to certain CBP revenue functions.
Alterations, Bonds, Customs duties and inspection, Exports, Imports, Preference programs, Repairs, Reporting and recordkeeping requirements, Trade agreements.
Accounting, Customs duties and inspection, Financial and accounting procedures, Reporting and recordkeeping requirements, Trade agreements, User fees.
Administrative practice and procedure, Customs duties and inspection, Penalties, Trade agreements.
Administrative practice and procedure, Customs duties and inspection, Exports, Imports, Reporting and recordkeeping requirements, Trade agreements.
Administrative practice and procedure, Exports, Imports, Reporting and recordkeeping requirements.
For the reasons stated above, the interim rule amending Parts 10, 24, 162, 163, and 178 of the CBP regulations (19 CFR parts 10, 24, 162, 163, and 178), which was published at 80 FR 7303 on February 10, 2015, is adopted as a final rule with the following change:
19 U.S.C. 66, 1202 (General Note 3(i), Harmonized Tariff Schedule of the United States), 1321, 1481, 1484, 1498, 1508, 1623, 1624, 3314.
Sections 10.721 through 10.748 also issued under 19 U.S.C. 1202 (General Note 28, HTSUS) and Pub. L. 108–286, 118 Stat. 919 (19 U.S.C. 3805 note).
Customs and Border Protection, Department of Homeland Security; Department of the Treasury.
Final rule.
This document amends Customs and Border Protection (CBP)
For legal aspects, Lisa L. Burley, Chief, Cargo Security, Carriers and Restricted Merchandise Branch, Regulations and Rulings, Office of International Trade, (202) 325–0215. For operational aspects, William R. Scopa, Branch Chief, Partner Government Agency Branch, Trade Policy and Programs, Office of International Trade, (202) 863–6554,
Pursuant to the provisions of the 1970 United Nations Educational, Scientific and Cultural Organization (UNESCO) Convention, implemented by the Convention on Cultural Property Implementation Act (Pub. L. 97–446, 19 U.S.C. 2601
Import restrictions listed in 19 CFR 12.104g(a) are “effective for no more than five years beginning on the date on which the agreement enters into force with respect to the United States. This period can be extended for additional periods not to exceed five years if it is determined that the factors which justified the initial agreement still pertain and no cause for suspension of the agreement exists” (19 CFR 12.104g(a)).
Since the initial notice was published on January 23, 2001, the import restrictions were extended twice. First, on January 19, 2006, CBP published CBP Dec. 06–01 in the
On December 23, 2014, the Department of State received a request by the Government of the Republic of Italy to extend the Agreement. Subsequently, the Department of State proposed to extend the Agreement. After considering the views and recommendations of the Cultural Property Advisory Committee, the Assistant Secretary for Educational and Cultural Affairs, United States Department of State, determined that the cultural heritage of Italy continues to be in jeopardy from pillage of archaeological material representing the pre-Classical, Classical, and Imperial Roman periods and made the necessary determinations to extend the import restrictions for an additional five years. Diplomatic notes have been exchanged, reflecting the extension of those restrictions for an additional five-year period. Accordingly, CBP is amending 19 CFR 12.104g(a) to reflect this extension of the import restrictions.
The Designated List of Pre-Classical, Classical and Imperial Roman Period Archaeological Material from Italy covered by these import restrictions is set forth in CBP Dec. 11–03. The Designated List and accompanying image database may also be found at the following Internet Web site address:
The restrictions on the importation of these archaeological materials from the Republic of Italy are to continue in effect for an additional five years. Importation of such material continues to be restricted unless the conditions set forth in 19 U.S.C. 2606 and 19 CFR 12.104c are met.
This amendment involves a foreign affairs function of the United States and is, therefore, being made without notice or public procedure (5 U.S.C. 553(a)(1)). In addition, CBP has determined that such notice or public procedure would be impracticable and contrary to the public interest because the action being taken is essential to avoid interruption of the application of the existing import restrictions (5 U.S.C. 553(b)(B)). For the same reasons, a delayed effective date is not required under 5 U.S.C. 553(d)(3).
Because no notice of proposed rulemaking is required, the provisions of the Regulatory Flexibility Act (5 U.S.C. 601
It has been determined that this rule is not a significant regulatory action under Executive Order 12866.
This regulation is being issued in accordance with 19 CFR 0.1(a)(1).
Cultural property, Customs duties and inspection, Imports, Prohibited merchandise.
For the reasons set forth above, part 12 of Title 19 of the Code of Federal Regulations (19 CFR part 12), is amended as set forth below:
5 U.S.C. 301; 19 U.S.C. 66, 1202 (General Note 3(i), Harmonized Tariff Schedule of the United States (HTSUS)), 1624;
Sections 12.104 through 12.104i also issued under 19 U.S.C. 2612;
Internal Revenue Service (IRS), Treasury.
Final regulations; correcting amendment.
This document contains corrections to final regulations (TD 9745) that were published in the
This correction is effective
Shareen Pflanz at (202) 317–4718 (not a toll-free number).
The final regulations (TD 9745) that are the subject of this correction are under section 36B of the Internal Revenue Code.
As published, the final regulations (TD 9745) contains an error that may prove to be misleading and is in need of clarification.
Income taxes, Reporting and recordkeeping requirements.
Accordingly, 26 CFR part 1 is corrected by making the following correcting amendment:
(d) * * *
(2) * * *
(i) * * *
(A) The enrollment premiums for the month (reduced by any amounts that were refunded); or
Pension Benefit Guaranty Corporation.
Final rule.
This final rule amends the Pension Benefit Guaranty Corporation's regulation on Benefits Payable in Terminated Single-Employer Plans to prescribe interest assumptions under the regulation for valuation dates in February 2016. The interest assumptions are used for paying benefits under terminating single-employer plans covered by the pension insurance system administered by PBGC.
Effective February 1, 2016.
Catherine B. Klion (
PBGC's regulation on Benefits Payable in Terminated Single-Employer Plans (29 CFR part 4022) prescribes actuarial assumptions—including interest assumptions—for paying plan benefits under terminating single-employer plans covered by title IV of the Employee Retirement Income Security Act of 1974. The interest assumptions in the regulation are also published on PBGC's Web site (
PBGC uses the interest assumptions in Appendix B to Part 4022 to determine whether a benefit is payable as a lump sum and to determine the amount to pay. Appendix C to Part 4022 contains interest assumptions for private-sector pension practitioners to refer to if they wish to use lump-sum interest rates determined using PBGC's historical methodology. Currently, the rates in Appendices B and C of the benefit payment regulation are the same.
The interest assumptions are intended to reflect current conditions in the financial and annuity markets. Assumptions under the benefit payments regulation are updated monthly. This final rule updates the benefit payments interest assumptions for February 2016.
The February 2016 interest assumptions under the benefit payments regulation will be 1.25 percent for the period during which a benefit is in pay status and 4.00 percent during any years preceding the benefit's placement in pay status. In comparison with the interest assumptions in effect for January 2016, these interest assumptions are unchanged.
PBGC has determined that notice and public comment on this amendment are impracticable and contrary to the public interest. This finding is based on the need to determine and issue new interest assumptions promptly so that
Because of the need to provide immediate guidance for the payment of benefits under plans with valuation dates during February 2016, PBGC finds that good cause exists for making the assumptions set forth in this amendment effective less than 30 days after publication.
PBGC has determined that this action is not a “significant regulatory action” under the criteria set forth in Executive Order 12866.
Because no general notice of proposed rulemaking is required for this amendment, the Regulatory Flexibility Act of 1980 does not apply. See 5 U.S.C. 601(2).
Employee benefit plans, Pension insurance, Pensions, Reporting and recordkeeping requirements.
In consideration of the foregoing, 29 CFR part 4022 is amended as follows:
29 U.S.C. 1302, 1322, 1322b, 1341(c)(3)(D), and 1344.
Coast Guard, DHS.
Notice of deviation from drawbridge regulation.
The Coast Guard has issued a temporary deviation from the operating schedule that governs the Montlake Bridge across the Lake Washington Ship Canal, mile 5.2, at Seattle, WA. The deviation is necessary to allow the bridge to operate in single leaf mode during day light hours, and a full closure (both bascule leafs in the closed-to-navigation position) during night time hours while work crews replace bridge decking. This deviation allows a single leaf opening with a one hour advance notice during the day, and remains in the closed-to-navigation position at night.
This deviation is effective from 6 a.m. on February 27, 2016 to 6 p.m. on February 28, 2016.
The docket for this deviation, [USCG–2016–0021] is available at
If you have questions on this temporary deviation, call or email Mr. Steven Fischer, Bridge Administrator, Thirteenth Coast Guard District; telephone 206–220–7282, email
Washington Department of Transportation has requested a temporary deviation from the operating schedule for the Montlake Bridge across the Lake Washington Ship Canal, at mile 5.2, at Seattle, WA. The deviation is necessary to accommodate work crews conducting timely bridge deck repairs.
The Montlake Bridge in the closed position provides 30 feet of vertical clearance throughout the navigation channel, and 46 feet of vertical clearance throughout the center 60 feet of the bridge; vertical clearance references to the Mean Water Level of Lake Washington. When half the span is open with a single leaf, 46 feet of vertical clearance will be reduced
To facilitate this event, the north half of the bridge span, or single leaf, will open with at least a one hour advance notice provided to the bridge operator from 6 a.m. to 6 p.m. on February 27, 2016. From 6 p.m. on February 27, 2016 to 5 a.m. on February 28, 2016, the Montlake Bridge span will remain in the closed-to-navigation position, or full closure. Then, from 5 a.m. to 6 p.m. on February 28, 2016, the north half of the bridge span will open with at least a one hour advance notice to the bridge operator. The normal operating schedule for the Montlake Bridge operates in accordance with 33 CFR 117.1051(e).
The deviation period is from 6 a.m. on February 27, 2016 to 6 p.m. on February 27, 2016 (north single leaf opening if a one hour notice is given); from 6 p.m. on February 27, 2016 to 5 a.m. on February 28, 2016 (remain in the closed-to-navigation position); from 5 a.m. on February 28, 2016 to 6 p.m. on February 28, 2016 (north single leaf opening if a one hour notice is given).
Waterway usage on the Lake Washington Ship Canal ranges from commercial tug and barge to small pleasure craft. Vessels able to pass through the bridge in the closed-to-navigation position may do so at any time. The bridge will be able to open for emergency vessels in route to a call when an hour notice is given to the bridge operator, and a single leaf opening will be provided. The Lake Washington Ship Canal has no immediate alternate route for vessels to pass. The Coast Guard will also inform the users of the waterways through our Local and Broadcast Notices to Mariners of the change in operating schedule for the bridge so that vessels can arrange their transits to minimize any impact caused by the temporary deviation.
In accordance with 33 CFR 117.35(e), the drawbridge must return to its regular operating schedule immediately at the end of the designated time period. This deviation from the operating regulations is authorized under 33 CFR 117.35.
Environmental Protection Agency (EPA).
Direct final rule.
Environmental Protection Agency (EPA) is taking direct final action to approve revisions to the Operating Permits Program for the State of Missouri submitted on March 16, 2015. These revisions update the emissions fee for permitted sources as set by Missouri Statute from $40 to $48 per ton of air pollution emitted annually, effective January 1, 2016.
This direct final rule will be effective March 15, 2016, without further notice, unless EPA receives adverse comment by February 16, 2016. If EPA receives adverse comment, we will publish a timely withdrawal of the direct final rule in the
Submit your comments, identified by Docket ID No. EPA–R07–OAR–2015–0790, to
Stephen Krabbe, Environmental Protection Agency, Air Planning and Development Branch, 11201 Renner Boulevard, Lenexa, Kansas 66219 at 913–551–7991 or by email at
Throughout this document “we,” “us,” or “our” refer to EPA. This section provides additional information by addressing the following:
EPA is taking direct final action to approve the Operating Permits Program revision submitted by the state of Missouri for 10 CSR 10–6.110, “Reporting Emission Data, Emission Fees, and Process Information,” on March 16, 2015. Section (3)(A) revised the emission fees section, which is approved under the Operating Permits Program only, and updates the emissions fee for permitted sources as set by Missouri Statute from $40 to $48 per ton of air pollution emitted annually, effective January 1, 2016, as set by Missouri statute.
The state submission has met the public notice requirements for SIP submissions in accordance with 40 CFR 51.102. The submission also satisfied the completeness criteria of 40 CFR part 51, appendix V. In addition, the revision meets the substantive SIP requirements of the Clean Air Act (CAA), including section 110 and implementing regulations.
We are publishing this direct final rule without a prior proposed rule because we view this as a noncontroversial action and anticipate no adverse comment. However, in the “Proposed Rules” section of this
In this action, EPA is finalizing regulatory text that includes incorporation by reference. In accordance with requirements of 1 CFR 51.5, the EPA is finalizing the incorporation by reference of the Missouri amendments to 40 CFR part 52 set forth below. EPA has made, and will continue to make, these documents generally available electronically through
Under the CAA, the Administrator is required to approve a SIP submission that complies with the provisions of the Act and applicable Federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in reviewing SIP submissions, EPA's role is to approve state choices, provided that they meet the criteria of the CAA. Accordingly, this action merely approves state law as meeting Federal requirements and does not impose additional requirements beyond those imposed by state law. For that reason, this action:
• Is not a significant regulatory action subject to review by the Office of Management and Budget under Executive Orders 12866 (58 FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21, 2011);
• Does not impose an information collection burden under the provisions of the Paperwork Reduction Act (44 U.S.C. 3501
• Is certified as not having a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601
• Does not contain any unfunded mandate or significantly or uniquely affect small governments, as described in the Unfunded Mandates Reform Act of 1995 (Pub. L. 104–4);
• Does not have Federalism implications as specified in Executive Order 13132 (64 FR 43255, August 10, 1999);
• Is not an economically significant regulatory action based on health or safety risks subject to Executive Order 13045 (62 FR 19885, April 23, 1997);
• Is not a significant regulatory action subject to Executive Order 13211 (66 FR 28355, May 22, 2001);
• Is not subject to requirements of Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) because application of those requirements would be inconsistent with the CAA; and
• Does not provide EPA with the discretionary authority to address, as appropriate, disproportionate human health or environmental effects, using practicable and legally permissible methods, under Executive Order 12898 (59 FR 7629, February 16, 1994).
The action is not approved to apply on any Indian reservation land or in any other area where EPA or an Indian tribe has demonstrated that a tribe has jurisdiction. In those areas of Indian country, the rule does not have tribal implications and will not impose substantial direct costs on tribal governments or preempt tribal law as specified by Executive Order 13175 (65 FR 67249, November 9, 2000).
The Congressional Review Act, 5 U.S.C. 801
Under section 307(b)(1) of the CAA, petitions for judicial review of this action must be filed in the United States Court of Appeals for the appropriate circuit by March 15, 2016. Filing a petition for reconsideration by the Administrator of this final rule does not affect the finality of this action for the purposes of judicial review nor does it extend the time within which a petition for judicial review may be filed, and shall not postpone the effectiveness of such rule or action. This action may not be challenged later in proceedings to enforce its requirements. (See section 307(b)(2).)
Environmental protection, Air pollution control, Carbon monoxide, Incorporation by reference, Intergovernmental relations, Lead, Nitrogen dioxide, Ozone, Particulate matter, Reporting and recordkeeping requirements, Sulfur oxides, Volatile organic compounds.
Environmental protection, Administrative practice and procedure, Air pollution control, Intergovernmental relations, Operating permits, Reporting and recordkeeping requirements.
For the reasons stated in the preamble, the EPA amends 40 CFR parts 52 and 70 as set forth below:
42 U.S.C. 7401
(c) * * *
42 U.S.C. 7401
(ee) The Missouri Department of Natural Resources submitted revisions to Missouri rule 10 CSR 10–6.110, “Reporting Emission Data, Emission Fees, and Process Information” on March 16, 2015. The state effective date is November 20, 2014. This revision is effective March 15, 2016.
Office of Family Assistance (OFA), Administration for Children and Families (ACF), Department of Health and Human Services (HHS).
Final rule.
This final rule makes regulatory changes to the Temporary Assistance for Needy Families (TANF) regulations to require states, subject to penalty, to maintain policies and practices that prevent TANF funded assistance from being used in any electronic benefit transfer transaction in any liquor store; any casino, gambling casino, or gaming establishment; or any retail establishment that provides adult-oriented entertainment in which performers disrobe or perform in an unclothed state for entertainment. This rule implements provisions of Section 4004 of the Middle Class Tax Relief and Job Creation Act of 2012.
Rebecca Shwalb, Office of Family Assistance, 202–260–3305 (not a toll-free call). Deaf and hearing impaired individuals may call the Federal Dual Party Relay Service at 1–800–877–8339 between 8:00 a.m. and 7:00 p.m. Eastern Time.
Authorized by title IV–A of the Social Security Act, TANF is a block grant that provides states, territories, and tribes federal funds to design and operate a program to accomplish the purposes of TANF. The purposes are to: (1) Assist needy families so that children can be cared for in their own homes or in the homes of relatives; (2) reduce the dependency of needy parents by promoting job preparation, work, and marriage; (3) prevent out-of-wedlock pregnancies; and (4) encourage the formation and maintenance of two-parent families. In addition to federal TANF block grant funds, each state must spend a certain minimum amount of non-federal funds to help eligible families in ways that further a TANF purpose. This is referred to as maintenance-of-effort (MOE).
In general, federal TANF and state MOE funds may be expended on benefits and services targeted to needy families, and activities that aim to prevent and reduce out-of-wedlock pregnancies or encourage the formation and maintenance of two-parent families, as well as administrative expenses. In particular, federal TANF and state MOE funds may be expended on “assistance,” defined at 45 CFR 260.31(a)(1) as including cash payments, vouchers, and other forms of benefits designed to meet a family's ongoing basic needs (
Based on the most recent information provided to us by states, there are currently four means that states use to provide assistance payments to eligible low-income families with children: Paper checks, Electronic Funds Transfers (EFT), Electronic Benefit Transfer (EBT) cards, and Electronic Payment Cards (EPC). Most states have replaced paper checks with one or more of the other three delivery methods in order to provide benefits in a timelier manner, reduce theft and fraud, and eliminate the need for recipients to pay check-cashing fees. Some states automatically transfer assistance payments directly into a recipient's own private bank account through EFT. However, this option is not available if a recipient does not have access to or qualify for a checking account. Most states load the amount of assistance on EBT cards or EPCs, both of which allow recipients to use a debit-like card to access their benefits through automated teller machines (ATMs) and point-of-sale (POS) devices. EPCs differ from government EBT cards in that they are network-branded (
Among its provisions, the Middle Class Tax Relief and Job Creation Act of 2012, Public Law (Pub. L.) 112–96, requires states to maintain policies and practices to prevent TANF assistance from being used in any EBT transaction (as defined at 42 U.S.C. 608(a)(12)(B)(iii)) in any liquor store; any casino, gambling casino, or gambling establishment; or any retail establishment which provides adult-oriented entertainment in which performers disrobe or perform in an unclothed state for entertainment.
The legislation at Section 4004(b) also imposes a new reporting requirement as well as a new penalty. Each state is required to report annually to the Department of Health and Human Services (HHS) on its implementation of policies and practices related to restricting recipients from using their TANF assistance in EBT transactions at the prohibited locations. HHS will reduce a state's block grant by not more than five percent of the state family assistance grant in fiscal year (FY) 2014 and annually thereafter if the state fails to comply with this reporting requirement or if, based on the information that the state reports, HHS finds that the state has not implemented and maintained the required policies and practices. The statute provides the Secretary of HHS the authority to reduce the amount of the penalty based on the degree of noncompliance of the state.
Finally, states are required under Section 4004(c) of Public Law 112–96 to include in their state TANF plans a statement outlining how they intend to implement policies and procedures to prevent access to assistance through EFTs at casinos, liquor stores, and establishments providing adult-oriented entertainment. The state plan also must include an explanation of how the state will ensure that (1) recipients of the assistance have adequate access to their cash assistance, and (2) recipients of assistance have access to using or withdrawing assistance with minimal fees or charges, including an opportunity to access assistance with no fee or charges; are provided information on applicable fees and surcharges that apply to electronic fund transactions involving the assistance; and that such information is made publicly available. This rule does not regulate the state plan provisions at Section 4004(c) of Public Law 112–96, but it incorporates the statutory state plan language under the Middle Class Job Creation and Tax Relief Act of 2012. Following publication of the final rule, HHS plans to issue additional guidance regarding the adequate access provision.
HHS published a notice of proposed rulemaking (NPRM) (79 FR 7127) on February 6, 2014, to regulate the TANF provisions in Section 4004(a) and (b) of Public Law 112–96. The proposed rule added new penalties for failure to report or adequately demonstrate implementation of the requirements outlined in Public Law 112–96, defined terms relevant to the new requirements, specified when the penalty takes effect, and identified how HHS will determine whether a state warrants a penalty. It also provided details regarding what types of policies and practices HHS would accept as complying with the statutory requirements. In addition to general comments, the NPRM sought input from commenters regarding two specific issues: TANF assistance deposited directly in recipients' bank accounts and accessed with a personal debit card, and internet transactions.
HHS received a total of 28 comments, including comments from six states, seven membership and research/advocacy organizations, and three EBT industry organizations. The remaining commenters were members of the public. We include a detailed summary of comments as well as HHS's responses to comments in Section V of this final rule. Public comments on the proposed rule are available for review on
The final rule amends the TANF program regulations in the following three ways: (1) It adds a requirement to implement policies and practices to prevent TANF assistance from being used in any electronic benefit transfer transaction in any: liquor store; any casino, gambling casino or gaming establishment; and any retail establishment which provides adult-oriented entertainment in which performers disrobe or perform in an unclothed state for entertainment, (2) it adds a requirement to report on policies and practices in an annual report, and
(1) When incorporating the requirement at 45 CFR 264.60 to implement policies and practices to prevent TANF assistance from being used in any electronic benefit transfer transaction in any liquor store; any casino, gambling casino or gaming establishment; and any retail establishment which provides adult-oriented entertainment in which performers disrobe or perform in an unclothed state for entertainment, we mirror the statutory language at Section 4004(a) of Public Law 112–96. The preambles to the NPRM and the final rule provide details on the types of policies and practices HHS would accept as complying with the statutory requirements, and identify those that do not. In doing so, we identify that different approaches may be acceptable depending on the method of delivery (EBT, EPC, or direct deposit). We also correct an error we made in the NPRM suggesting that bank identification number (BIN) blocking was a potential approach to preventing TANF assistance from being used in POS terminals in the specified locations. Finally, we reiterate that states have a responsibility to develop appropriate policies for preventing TANF cash assistance administered by state programs from being used at any of the three types of businesses, including those located on tribal land. In general, we have provided flexibility in meeting the statutory and regulatory requirements so that states may develop cost-effective implementation strategies that fit within the existing structures of state operations.
We also have added the relevant accompanying definitions to the TANF regulations at 45 CFR 264.0. Regarding the definitions of the three types of establishments, we have made some changes to those we proposed in the NPRM. For example, we are striking from our definition of “retail establishment which provides adult-oriented entertainment in which performers disrobe or perform in an unclothed state for entertainment,” the language, “such an establishment that prohibits the entrance of minors under the age specified by state law.” Commenters noted that local ordinances, rather than state law, apply to such establishments, and can vary considerably from jurisdiction to jurisdiction. Since we are no longer expanding upon the statutory definition, we have deleted the definition of “retail establishment which provides adult-oriented entertainment in which performers disrobe or perform in an unclothed state for entertainment” from § 264.0. Rather, we encourage states to exercise the flexibility provided by the statute to build on the required restrictions with respect to these establishments, consistent with state and local policies. Furthermore, in response to comments suggesting we quantify the term “primarily” in the definitions for “casino, gambling casino, or gaming establishment” and “liquor store,” we will defer to states' reasonable interpretation of the law. Additionally, we interpret Congress's use of “liquor” to refer to alcoholic beverages broadly, rather than a narrow definition that excludes alcoholic beverages such as beer and wine.
We are clarifying that the broad definition of “electronic benefit transfer transaction” includes transactions using or accessing TANF funds in private bank accounts because those funds may be accessed by a TANF recipient in a manner that the statutory definition specifies,
(2) In order to add the requirement to report on relevant policies and practices to the TANF regulations, we are amending 45 CFR parts 262, 264, and 265. The regulations at 45 CFR 262.3 and 264.61 tie the reporting requirement to the penalty specified at 45 CFR 262.1(a)(16). We reiterate that we are requiring an annual EBT report in order to determine whether states have maintained the required policies and practices in each fiscal year following FY 2014. One commenter suggested that the statute does not provide authority for annual reporting, maintaining that the statute obligates HHS to impose a penalty only if a state fails to submit one required report; that state would be subject to a penalty for FY 2014 (for its failure to report by February 22, 2014) and each fiscal year until it submits a report. We disagree with this interpretation and do not believe that it comports with the statute.
In response to suggestions for ways to ease the reporting burden, we have incorporated this reporting requirement in the Annual Report on TANF and MOE Programs under 45 CFR 265.9(b)(10), rather than requiring the submission of a separate EBT report. Accordingly, we are amending the regulation at 45 CFR 265.9(b).
We continue to require that the reports address specific areas that will allow us to determine whether states have implemented policies and practices that comply with the statutory requirements. The NPRM identified these areas as follows: Identifying locations; methods to prevent use of TANF assistance via EBT transactions in restricted locations; monitoring; and enforcement of compliance. With this final rule, we are providing clearer descriptions of the type of information we are requesting. For example, we have amended the request for information on “monitoring,” to “ongoing monitoring to ensure policies are being carried out as intended,” and instead of “enforcement of compliance,” this component should read “responding to findings of non-compliance or program ineffectiveness.” This way, we do not imply that specific practices, such as monitoring of transaction reports, are required. At the same time, we would like reports to describe how states will review and evaluate the policies and practices implemented, and correct for non-compliance and ineffectiveness. In sum, in 45 CFR 265.9(b)(10), the four areas we are requiring states to address in their reports are: (1) Procedures for preventing the use of TANF assistance via electronic benefit transfer transactions in any liquor store; any casino, gambling casino, or gaming establishment
(3) We are amending 45 CFR 262.1 and 264.61 to add the penalty for failure to report or demonstrate implementation and maintenance of these policies and practices. At 45 CFR 262.62, we specify that this penalty will be imposed for FY 2014 and each succeeding fiscal year in which a state fails to submit a report that demonstrates it has implemented and maintained the relevant policies and practices. Even though one commenter suggested that this approach exceeds our statutory authority, we maintain that the statute allows HHS to impose a penalty in “each succeeding fiscal year in which the State does not demonstrate that such State has implemented and maintained such policies and practices.” Furthermore, in response to commenters' recommendations, we have added language to the regulation related to reducing the penalty based on the degree of noncompliance. We also clarify in the regulations that states are not held responsible for individuals' fraudulent activities, as provided by the statute.
This final rule is being issued under the authority granted to the Secretary of Health and Human Services (HHS) by the Middle Class Tax Relief and Job Creation Act of 2012 (Pub. L. 112–96), Section 408 of the Social Security Act (42 U.S.C. 608), Section 409 of the Social Security Act (42 U.S.C. 609), and Section 1102 of the Social Security Act (42 U.S.C. 1302), which authorizes the Secretary to make and publish such rules and regulations, not inconsistent with the Act, as may be necessary to the efficient administration of functions under the Act.
The statute at 42 U.S.C. 617 limits the authority of the federal government to regulate state conduct or enforce the TANF provisions of the Social Security Act, except as expressly provided. We have interpreted this provision to allow us to regulate where Congress has charged HHS with enforcing certain TANF provisions by assessing penalties. Because the legislation includes a TANF penalty, HHS has the authority to regulate in this instance.
The final rule in part 262 adds new penalties for failure to report or adequately implement the new requirements outlined in Public Law 112–96, specifies when a penalty takes effect, and identifies the reporting form that HHS will use to determine whether a state warrants a penalty.
Sec. 4004(b) of Public Law 112–96 at Sec. 409(a)(16) of the Social Security Act (the Act) creates a new TANF penalty. As provided in the statute, the penalty will be imposed if a state fails to report to HHS its implementation of the policies and practices to prevent assistance provided under the state program funded under this part from being used in any electronic benefit transfer transaction in: (i) Any liquor store; (ii) any casino, gambling casino, or gaming establishment; or (iii) any retail establishment which provides adult-oriented entertainment in which performers disrobe or perform in an unclothed state for entertainment. Furthermore, HHS may impose a penalty if it determines, based on the information provided in a state report, that the state has not demonstrated that it has implemented and maintained such policies and practices. This penalty may be imposed for FY 2014 and each succeeding fiscal year in which a state does not demonstrate that it has implemented and maintained such policies and practices. If HHS determines that the state should be subject to a penalty, it will reduce the state family assistance grant in the succeeding fiscal year by five percent, or a lesser amount based on the degree of noncompliance. States should note that the regulations at 45 CFR 262.4 through 262.7, concerning the processes for appealing a penalty, presenting a reasonable cause justification, and submitting a corrective compliance plan, apply to the new penalty added to 45 CFR 262.1.
Accordingly, this final rule adds paragraph (i) to § 262.1(a)(16) to provide that a penalty of not more than five percent of the adjusted State Family Assistance Grant (SFAG) will be applied for failure to report annually as part of the Annual Report on TANF and MOE Programs under 45 CFR 265.9(b)(10), on the state's implementation of policies and practices related to these prohibited EBT transactions. The final rule also adds paragraph (a)(16)(ii) to provide that a penalty likewise will be applied for FY 2014 and each succeeding fiscal year if the state does not demonstrate that it has implemented and maintained such policies and practices. Note that if a state fails to submit a report for a fiscal year and, when it ultimately submits a report, also fails to demonstrate its implementation of policies and practices, the combined penalty will not exceed five percent of its adjusted SFAG. Conforming changes have been made at § 262.1(c)(2) to add reference to the penalties in paragraphs (a)(16)(i) and (ii).
When determining “degree of noncompliance” with respect to reports submitted after the deadline, the Secretary may take into account factors such as the length of time a report was late and any extenuating circumstances that may have caused late reporting. When determining “degree of noncompliance” with respect to inadequate policies and practices, the Secretary may consider the steps taken to develop policies to comply with the requirements (even if not fully implemented), whether there are procedures related to identifying some or all of the types of locations specified in the statute, whether procedures take into account transactions at both ATMs and POS terminals, and whether the
The final rule amends § 262.2 to add new paragraph (e) indicating that the penalty for failure to report on how the state is implementing and maintaining policies and practices to prevent assistance from being used in electronic benefit transfer transactions in specified locations will be imposed for FY 2014 and each succeeding fiscal year in which the state does not demonstrate it has implemented and maintained the policies and practices in accordance with 45 CFR 264.60.
This final rule amends § 262.3 by adding a new paragraph (g) to specify that in order to determine if a state is subject to a penalty under 45 CFR 262(a)(16)(i) and (ii), HHS will use the submission of the initial report that was due by February 22, 2014, and beginning in FY 2015, the Annual Report on TANF and MOE Programs under 45 CFR 265.9(b)(10). We are amending the Annual Report on TANF and MOE Programs under 45 CFR 265.9(b) in order to include reporting for electronic benefit transfer transaction policies and practices. The Annual Report on TANF and MOE Programs at 45 CFR 265.9(b) is due at the same time as the fourth quarter TANF data report, within 45 days following the end of the fourth quarter. Note that this reporting requirement is distinct from the provisions of Public Law 112–96 related to additional state plan requirements (see Sec. 4004(c)).
The final part 264 explains in further detail what HHS expects of states when implementing the new requirements of Public Law 112–96 by specifying the policies and practices required, providing relevant definitions, and addressing consequences if a state fails to meet the requirement.
In order to clarify the types of locations where states are required to prohibit the use of TANF assistance via electronic benefit transfer transactions and to ensure that the policies and practices are applied consistently between states, we are amending § 264.0(b) to define the terms included in Section 4004 of Public Law 112–96. The following is a discussion of the definitions of the terms in alphabetical order.
Although one commenter acknowledged that it may be theoretically possible for a deposit account to consist of a sub-account for TANF funds and a subaccount for all other funds, all agreed that implementing such a requirement would be practically infeasible. If implemented, the banks would face requirements to identify customers who receive cash benefits, determine the dollars in a checking or savings account that are “TANF” dollars versus wages or other income from the state, such as child support. Requiring the entire United States banking system to develop the appropriate capabilities (TANF funds recipients could have deposit accounts at any of the nearly 7,000 banks and thousands more credit unions in the U.S.) would result in an extraordinary burden and high costs. While one commenter stated that the banks would need to develop the ability to monitor where funds are used, as there is no current mechanism for a state to monitor the use of such funds, another stated that current bank infrastructure could not support identification of individual retailers. Commenters emphasized that the capacity and infrastructure to apply the requirements to personal bank accounts/debit cards simply do not exist at this point, and the costs that would need to be devoted to this effort would not outweigh the benefit.
A few commenters maintained that because states could not actually implement procedures in order to comply with this requirement, they would have to discontinue the option of direct deposit. One commenter maintained that even if states provided the option of direct deposit, the difficulties with applying the statutory requirement to TANF assistance in personal bank accounts would provide disincentives for banks to work with TANF customers. Commenters argued these would be unfortunate consequences of this legislation because there are many benefits of being “banked” (
Finally, a number of commenters maintained that Congress did not intend to include transactions with personal debit cards within the definition of “electronic benefit transfer transaction” in Public Law 112–96, and that only accounts established by a government agency were intended to fall within Congress's definition of EBT systems.
Ultimately, all commenters recommended that the restrictions not extend to TANF funds deposited into private bank accounts. One advocacy group recommended that if, in the future, there is sufficient evidence that TANF assistance recipients' use of bank accounts to purchase prohibited goods and services threatens the integrity of the TANF program, any new expansion of the current restrictions should be added only within the context of a full TANF reauthorization.
This final rule adds § 264.60 under subpart A, which requires states to implement policies and practices to prevent assistance (defined at § 260.31(a)) provided with federal TANF or state TANF MOE funds from being used in any electronic benefit transfer transaction in any: (a) Liquor store; (b) casino, gambling casino or gaming establishment; or (c) retail establishment which provides adult-oriented entertainment in which performers disrobe or perform in an unclothed state for entertainment. The NPRM often used the phrase “policies and procedures” in the discussion of this section. The final rule revises the language, instead referring to “policies and practices,” in order to mirror the statutory language. As we proposed in the NPRM, HHS will accept any reasonable approaches that further these goals and comply with the statutory and regulatory requirements. States' policies and practices must prohibit the use of TANF funds at the specified locations, while ensuring reasonable access to cash assistance, as directed by Congress.
In their initial reports, a few states described procedures that involve informing recipients and/or owners of the restricted businesses of the rules (
We do encourage states to periodically evaluate the effectiveness of their policies and practices, and adapt or revise them as necessary. In doing so, they maintain the flexibility afforded by the regulation to implement either systemic or non-systemic approaches. We have suggested a number of options for how states may structure policies. We require states to describe how they plan to correct for non-compliance and ineffectiveness in the annual report.
Finally, we want to reiterate that while one of the new state plan requirements at Sec. 4004(c) of Public Law 112–96 conveys a clear emphasis that states ensure adequate access to cash assistance for recipients, this language does not provide states the option to avoid imposing a restriction at an ATM or POS terminal located in any of the three types of specified businesses in order to ensure adequate access. Rather, it conveys a responsibility for states to take corrective actions to increase locations where TANF recipients may access their cash assistance if they find that there are an insufficient number of access points in a geographic area.
We are adding a § 264.61 to address the penalty associated with the new requirements. Under paragraph (a), HHS will impose a penalty of not more than five percent of a state's adjusted SFAG
In order to meet this requirement, states' reports must fully explain the policies and practices that are being implemented and maintained. Note that if a state submits a late report and once submitted, also fails to demonstrate its implementation of policies and practices, the combined penalty will not exceed five percent of its adjusted SFAG. Any deficiencies that arise with respect to a state's reporting of its EBT policies and practices in the Annual Report (
All penalties will be imposed in accordance with 45 CFR part 262, which provides states with procedures for appealing a penalty, and submitting a reasonable cause justification or corrective compliance plan.
Furthermore, Sec. 409(a)(16)(C) of the Act, as amended by Sec. 4004(b) of Public Law 112–96 provides HHS the discretion to reduce the penalty amount based on the degree of noncompliance of the state. Sec. 409(a)(16)(C) of the Act, as amended by Sec. 4004(b) of Public Law 112–96, also specifies that “Fraudulent activity by any individual in an attempt to circumvent the policies and practices required by Sec. 408(a)(12) shall not trigger a state penalty under subparagraph (A);” as such, HHS will not base any penalty on such information. We have added paragraphs (c) and (d) in this section of the regulation, incorporating these two provisions of the statute.
Please see discussion after 45 CFR 262.1 for comments and responses related to these penalty provisions.
In response to comments expressing concern over the burden of having a separate annual report due on February 22 of each fiscal year, we are amending § 265.9, by adding paragraph (b)(10) to state that in accordance with §§ 264.60 and 264.61, a report of policies and practices to prevent assistance (defined at § 260.31(a)) provided with federal TANF or state TANF MOE funds from being used in any electronic benefit transfer transaction in any liquor store; any casino, gambling casino, or gaming establishment
This rule establishes new information collection requirements in §§ 262.3(g) and 265.9(b)(10) of the TANF regulations. This collection is subject to review by the Office of Management and Budget (OMB) under the Paperwork Reduction Act of 1995 (the PRA) (44 U.S.C. 3501–3520). We did not receive any public comments on the specific burden hour estimate identified in the proposed rule. The information collection requirements, as described below, are identical to those contained in the proposed rule (OMB control number 0970–0437). However, now that the initial reporting due February 22, 2014, has passed, we have reduced the burden hour estimate by half. We also note that we will incorporate this reporting requirement into the Annual Report on TANF and MOE Programs under 45 CFR 265.9(b), and will obtain OMB approval for a standard form before the next information collection is due. The annual report is due at the same time as the fourth quarter TANF data report, or within 45 days following the end of the fourth quarter.
As required by the Paperwork Reduction Act of 1995, codified at 44 U.S.C. 3507, ACF will submit a copy of these sections to the Office of Management and Budget (OMB) for review and they will not be effective until they have been approved and assigned a clearance number.
We estimate the costs of implementing these requirements will be approximately $54,000 annually. We calculated this estimate by multiplying 1,080 hours by $50 (average cost per hour).
The Secretary certifies under 5 U.S.C. 605(b), as enacted by the Regulatory Flexibility Act (Pub. L. 96–354), that this final regulation will not result in a significant impact on a substantial number of small entities. We note that any impact on businesses emanates from statutory mandate and the policies that states adopt in implementing the statutory requirement.
In order to address potential concerns of the types of establishments specified in the statute, as well as state EBT vendors, HHS has drafted the regulation in a manner that minimizes the impact on businesses, including small businesses, by providing states flexibility when implementing policies and practices that comply with the new requirements. In particular, states have the flexibility to implement approaches that do not place significant burden or impose large costs on their EBT vendors, small businesses, or any particular party. Therefore, any costs resulting from policies under which states require action by small entities, including small businesses, are the result of choices states make when implementing the statutory requirements.
The direct primary impact of this final regulation is on state governments. State governments are not considered small entities under the Act.
Executive Orders 12866 and 13563 direct agencies to assess all costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distributive impacts and equity). Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility. This rule meets the criteria for a significant regulatory action under E.O. 12866 and has been reviewed by OMB. For the reasons set forth below, ACF does not believe the impact of this regulatory action would be economically significant and that the annual cost would fall below the $100 million threshold.
Commenters also noted that the regulation's benefits do not outweigh its costs, as implementation costs are so large and the percentage of TANF cash assistance recipients using EBT cards on prohibited transactions is so small. One of these commenters noted that some states have considered ending EBT programs and reinstating paper checks to exempt themselves from the regulatory requirements. They suggested increasing state flexibility in implementing the regulation by removing the four components that states must include in their implementation report listed in the proposed provision at 45 CFR 262.3(g).
We understand that this regulation will impose new costs on states. In response to this issue, we have provided flexibility in meeting the regulatory requirements so that states may develop cost-effective implementation strategies that fit within the existing structure of state operations. In general, the costs associated with implementation, and the parties that bear these costs, largely depend on the policies and practices a state chooses to in enact order to comply with the statutory requirements.
Nevertheless, regardless of the approach a state may take when implementing policies in order to comply with the statute and regulations, there will be, at a minimum, administrative costs for the state agency responsible for administering the TANF benefits. We recognize that states will spend funds on the following types of costs to implement the changes in order to complete the annual progress report to ACF:
Costs to identify the prohibited locations;
Costs to modify existing tracking of recipient use of electronic benefits and/or electronic banking;
Costs to monitor recipient use of electronic benefit transfers;
Costs to investigate and follow up on violations of electronic benefit transfers;
Cost to process and respond to appeals.
With regard to the reporting requirement, based on our estimate described under the Paperwork Reduction Act section of this preamble, the total costs for all states to comply with this requirement would fall well below the $100 million threshold. We will not remove the four components of the report, as commenters recommended. We do agree that the language in the components should be clarified (see discussion of regulation at § 265.9, above). It was not our intention to limit state flexibility or be overly prescriptive. The report components we have identified reflect general elements of all policies and practices that reflect full compliance with the statute, not specific policies and practices. As demonstrated by the initial reports states submitted in response to the statutory requirement, a majority of states have implemented sufficient policies and practices that take into account each of these components. Furthermore, by identifying these components in a standard form, we are ensuring that states take a comprehensive approach to composing their policies and practices, and that ACF receives complete reports describing the procedures states have chosen to implement.
Additionally, the statutory requirements and regulation provide potential benefits that coincide with the goal of financial responsibility. For example, the policies and practices that states implement may result in reductions in inappropriate expenditures of government funds, and emphasize to recipients that they should ensure assistance is spent only on basic needs. There may also be opportunities to educate recipients on financial management and on ways to minimize access fees.
Section 202 of the Unfunded Mandates Reform Act of 1995 requires that a covered agency prepare a budgetary impact statement before promulgating a rule that includes any federal mandate that may result in the expenditure by state, tribal, and local governments, in the aggregate, or by the private sector, of $100 million or more in any one year. HHS has determined that this rule will not result in the expenditure by state, local, and tribal governments, in the aggregate, or by the private sector, of more than $100 million in any one year.
For more detail regarding estimated costs, see the section containing the Regulatory Impact Analysis.
This regulation is not a major rule as defined in the Congressional Review Act or CRA (5 U.S.C. Chapter 8). The CRA defines a major rule as one that has resulted or is likely to result in: (1) An annual effect on the economy of $100 million or more; (2) a major increase in costs or prices for consumers, individual industries, federal, state, or local government agencies, or geographic regions; or (3) significant adverse effects on competition, employment, investment, productivity, or innovation, or on the ability of United States-based enterprises to compete with foreign-based enterprises in domestic and export markets. HHS has determined that this final rule does not meet any of these criteria. For more detail regarding estimated costs, see the section containing the Regulatory Impact Analysis.
Executive Order 13132, Federalism, prohibits an agency from publishing any rule that has federalism implications if the rule either imposes substantial direct compliance costs on state and local governments and is not required by statute, or the rule preempts state law, unless the agency meets the consultation and funding requirements of section 6 of the Executive Order. This final rule does not have federalism implications as defined in the Executive Order. Consistent with Executive Order 13132, HHS specifically requested comments from state and local government officials in the proposed rule regarding federalism implications; we did not receive any comments in response to this specific solicitation.
Section 654 of the Treasury and General Government Appropriations Act of 1999 (Pub. L. 105–277) requires federal agencies to determine whether a regulation may negatively impact family well-being. The Department has concluded that this final rule does not have a negative impact on family well-being, but rather that it will have positive benefits. The statutory requirements and regulations promote the goal of financial responsibility, helping to ensure that families are using their TANF assistance for basic needs. States also may incorporate within their policies and practices opportunities to educate recipients on budgeting, and their state plans must include an explanation of how the state will ensure that recipients have access to using or withdrawing assistance with minimal fees.
Administrative practice and procedures, Day care, Employment, Grant programs-social programs, Loan programs-social programs, Manpower training programs, Penalties, Public assistance programs, Reporting and recordkeeping requirements, Vocational education.
For the reasons set forth in the preamble, parts 262, 264, and 265 of 45 CFR are amended as follows:
31 U.S.C. 7501
(a) * * *
(16)(i) A penalty of not more than five percent of the adjusted SFAG (in accordance with § 264.61(a) of this chapter), for failure to report annually on the state's implementation and maintenance of policies and practices required in § 264.60 of this chapter.
(ii) A penalty of not more than five percent of the adjusted SFAG (in accordance with § 264.61(b) of this chapter), for FY 2014 and each succeeding fiscal year in which the state does not demonstrate that it has implemented and maintained policies
(iii) The penalty under paragraphs (a)(16)(i) and (ii) of this section may be reduced based on the degree of noncompliance of the state.
(iv) Fraudulent activity by any individual receiving TANF assistance in an attempt to circumvent the policies and practices required by § 264.60 of this chapter shall not trigger a state penalty under paragraphs (a)(16)(i) and (ii) of this section.
(c) * * *
(2) We will take the penalties specified in paragraphs (a)(3) through (6) and (8) through (16) of this section by reducing the SFAG payable for the fiscal year that immediately follows our final decision.
(e) In accordance with § 264.61(a) and (b) of this chapter, the penalty specified in § 262.1(a)(16) will be imposed for FY 2014 and each succeeding fiscal year.
(g) To determine if a State is subject to a penalty under § 262.1(a)(16), we will use the information provided in annual state reports at § 265.9(b)(10) of this chapter, in accordance with Section 409(a)(16) of the Social Security Act.
31 U.S.C. 7501
(b) * * *
(i) A grocery store which sells groceries including staple foods and which also offers, or is located within the same building or complex as, casino, gambling, or gaming activities; or
(ii) Any other establishment that offers casino, gambling, or gaming activities incidental to the principal purpose of the business.
Pursuant to Section 408(a)(12) of the Act, states are required to implement policies and practices, as necessary, to prevent assistance (defined at § 260.31(a) of this chapter) provided with federal TANF or state TANF MOE funds from being used in any electronic benefit transfer transaction in any: liquor store; casino, gambling casino or gaming establishment; or retail establishment which provides adult-oriented entertainment in which performers disrobe or perform in an unclothed state for entertainment.
(a) Pursuant to Section 409(a)(16) of the Act and in accordance with 45 CFR part 262, a penalty of not more than five percent of the adjusted SFAG will be imposed for failure to report by February 22, 2014 and each succeeding fiscal year on the state's implementation of policies and practices required in § 264.60. The penalty will be imposed in the succeeding fiscal year, subject to § 262.4(g) of this chapter.
(b) Pursuant to Section 409(a)(16) of the Act and in accordance with 45 CFR part 262, a penalty of not more than five percent of the adjusted SFAG will be imposed for FY 2014 and each succeeding fiscal year in which the state fails to demonstrate the state's implementation of policies and practices required in § 264.60. The penalty will be imposed in the succeeding fiscal year subject to § 262.4(g) of this chapter.
(c) A penalty applied under paragraphs (a) and (b) of this section may be reduced based on the degree of noncompliance of the state.
(d) Fraudulent activity by any individual in an attempt to circumvent the policies and practices required by § 264.60 shall not trigger a state penalty under paragraphs (a) and (b) of this section.
42 U.S.C. 603, 605, 607, 609, 611, and 613; Pub. L. 109–171.
(b) * * *
(10) A comprehensive description of the state's policies and practices to prevent assistance (defined at § 260.31(a) of this chapter) provided with federal TANF or state TANF MOE funds from being used in any electronic benefit transfer transaction in any: liquor store; casino, gambling casino or gaming establishment; or retail establishment which provides adult-oriented entertainment in which performers disrobe or perform in an unclothed state for entertainment. Reports must address:
(i) Procedures for preventing the use of TANF assistance via electronic benefit transfer transactions in any liquor store; any casino, gambling casino, or gaming establishment
(ii) How the state identifies the locations specified in the statute;
(iii) Procedures for ongoing monitoring to ensure policies are being carried out as intended; and
(iv) How the state responds to findings of non-compliance or program ineffectiveness.
(11) The state's TANF Plan must describe how the state will:
(i) Implement policies and procedures as necessary to prevent access to assistance provided under the State
(ii) Ensure that recipients of assistance provided under the State program funded under this part have access to using or withdrawing assistance with minimal fees or charges, including an opportunity to access assistance with no fee or charges, and are provided information on applicable fees and surcharges that apply to electronic fund transactions involving the assistance, and that such information is made publicly available.
Federal Communications Commission.
Final rule.
This document implements certain changes to the rules governing six remote control and telemetry channels in the VHF band. We will allow the licensing and operation of vehicular repeater systems (VRS) and other mobile repeaters on these channels. In addition, we revise and update the technical rules for these channels to allow greater use of VRS systems while providing protection for incumbent telemetry users who rely on these frequencies for control of critical infrastructure systems.
Effective March 15, 2016, except for the addition of § 90.175(b)(4), containing new or modified information collection requirements that require approval by the Office of Management and Budget under the Paperwork Reduction Act of 1995, which will become effective after such approval, on the effective date specified in a notice that the Commission publishes in the
Roberto Mussenden, Policy and Licensing Division, Public Safety and Homeland Security Bureau, (202) 418–1428. For additional information concerning the information collection requirements contained in this document, send an email to
This is a summary of the Commission's
In 2013, the Commission's
In the
The Final Regulatory Flexibility Analysis required by section 604 of the Regulatory Flexibility Act, 5 U.S.C. 604, is included in Appendix B of the Report and Order.
This document contains new information collection requirements subject to the Paperwork Reduction Act of 1995 (PRA), Public Law 104–13. It will be submitted to the Office of Management and Budget (OMB) for review under 3507(d) of the PRA. OMB, the general public, and other Federal agencies will be invited to comment on the new information collection requirements contained in this proceeding. In addition, we note that pursuant to the Small Business Paperwork Relief Act of 2002, Public Law 107–198,
The actions taken in the Report and Order in PS Docket No. 13–229 have been analyzed with respect to the Paperwork Reduction Act of 1995, Pub.
The Commission will send a copy of this
As required by the Regulatory Flexibility Act (RFA), an Initial Regulatory Flexibility Analysis (IRFA) was incorporated into the
In the
• Allow the use of mobile repeaters on the following six telemetry channels: 173.2375, 173.2625, 173.2875, 173.3125, 173.3375, and 173.3625 MHz.
• Allow the use of bandwidths up to 11.25 kHz on these channels.
• Require frequency coordination for applications seeking primary status on these frequencies.
• Limit applicants to a license a maximum of three channels on a primary basis
There were no comments filed that specifically addressed the rules and policies proposed in the IRFA.
The RFA directs agencies to provide a description of and, where feasible, an estimate of the number of small entities that may be affected by the proposed rules, if adopted. The RFA generally defines the term “small entity” as having the same meaning as the terms “small business,” “small organization,” and “small governmental jurisdiction.” In addition, the term “small business” has the same meaning as the term “small business concern” under the Small Business Act. A small business concern is one which: (1) Is independently owned and operated; (2) is not dominant in its field of operation; and (3) satisfies any additional criteria established by the SBA.
This
The RFA requires an agency to describe any significant alternatives that it has considered in reaching its
The
The
None.
The Commission will send a copy of the
Accordingly,
Radio.
For the reasons discussed in the preamble, the Federal Communications Commission amends 47 CFR part 90 as follows:
Sections 4(i), 11, 303(g), 303(r), and 332(c)(7) of the Communications Act of 1934, as amended, 47 U.S.C. 154(i), 161, 303(g), 303(r), and 332(c)(7), and Title VI of the Middle Class Tax Relief and Job Creation Act of 2012, Pub. L. 112–96, 126 Stat. 156.
The revisions and additions read as follows:
(c) * * *
(3) * * *
(d) * * *
(90) The maximum effective radiated power (ERP) may not exceed 2 watts for mobile stations, and 5 watts for mobile repeater stations and hand-carried transmitters that communicate directly with mobile repeater stations.
(91) This frequency is available on a shared basis both for remote control and telemetry operations and for mobile repeater operations. The authorized bandwidth may not exceed 11.25 kHz.
(92) This frequency is available on a shared basis with the Industrial/Business Pool for remote control and telemetry operations. Licensees seeking primary status for the use of this frequency for mobile repeater stations and hand-carried transmitters that communicate directly with mobile repeater stations must describe the area of normal day-to-day operations either in terms of operation in a specific county or in the terms of maximum distance from a geographic center (latitude and longitude) and shall be subject to the frequency coordination requirements of § 90.175.
(93) Mobile repeaters operating on this frequency are subject to a channel loading requirement of 50 transmitter-receivers. Loading standards will be applied in terms of the number of units actually in use or to be placed in use within 8 months following authorization. A licensee will be required to show that an assigned frequency is at full capacity before it may be assigned a second or additional frequency. Channel capacity may be reached either by the requirements of a single licensee or by several users sharing a channel. Until a channel is loaded to capacity it will be available for assignment to other users in the same area.
The revisions and additions read as follows:
(b) * * *
(3) * * *
(c) * * *
(92) This frequency is available on a shared basis both for remote control and telemetry operations and for mobile repeater operations. The authorized bandwidth may not exceed 11.25 kHz.
(93) This frequency is available on a shared basis with the Public Safety Pool for remote control and telemetry operations. In cases where § 90.35(c)(95) applies to this frequency, licensees seeking primary status for the use of this frequency for mobile repeater stations and hand-carried transmitters that communicate directly with mobile repeater stations must describe the area of normal day-to-day operations either in terms of operation in a specific county or in the terms of maximum distance from a geographic center (latitude and longitude) and shall be subject to the frequency coordination requirements of § 90.175.
(94) Mobile repeaters operating on this frequency are subject to a channel loading requirement of 50 transmitter-receivers. Loading standards will be applied in terms of the number of units actually in use or to be placed in use within 8 months following authorization. A licensee will be required to show that an assigned frequency pair is at full capacity before it may be assigned a second or additional frequency. Channel capacity may be reached either by the requirements of a single licensee or by several users sharing a channel. Until a channel is loaded to capacity it will be
(95) The maximum effective radiated power (ERP) may not exceed 2 watts for mobile stations, and 5 watts for mobile repeater stations and hand-carried transmitters that communicate directly with mobile repeater stations.
(b) * * *
(4) For any application for mobile repeater station operations on frequencies denoted by both § 90.20(d)(90) and (92), or by both § 90.35(c)(93) and (95) the frequency coordinator responsible for the application must determine and disclose to the applicant the call signs and the service areas of all active co-channel incumbent remote control and telemetry stations inside the applicant's proposed area of operation by adding a special condition to the application, except when the applicant has obtained written concurrence from an affected incumbent licensee, or when the applicant and the incumbent licensee are the same entity.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Announcement of 2016 Commercial Pacific bluefin tuna catch limit.
NMFS is announcing that the Pacific bluefin tuna catch limit applicable to U.S. commercial fishing vessels in the eastern Pacific Ocean (EPO) in 2016 is 425 metric tons (mt). This notice is necessary to inform fishery participants of the catch limit established in a final rule published on July 8, 2015.
The catch limit is effective February 14, 2016, through 11:59 p.m. local time December 31, 2016.
Celia Barroso, NMFS West Coast Region, 562–432–1850.
The United States is a member of the Inter-American Tropical Tuna Commission (IATTC), which was established under the Convention for the Establishment of an Inter-American Tropical Tuna Commission (Convention) signed in 1949. The Convention is an international agreement that, among other matters, serves as a framework for international conservation and management of highly migratory species of fish in the IATTC Convention Area.
Fishing for tuna in the EPO is managed, in part, under the Tuna Conventions Act of 1950 (Act), as amended. Under the Act, NMFS must publish regulations to carry out recommendations of the IATTC. Regulations governing fishing by U.S. vessels in accordance with the Act appear at 50 CFR part 300, subpart C, and these regulations implement IATTC recommendations for the conservation and management of highly migratory fish resources in the EPO.
In 2014, the IATTC adopted Resolution C–14–06 (
NMFS, through landings data and other available information, has determined that U.S. commercial vessels in the EPO have caught less than 175 mt of PBF in 2015; preliminary estimates indicate total landings to be approximately 96 mt. In accordance with 50 CFR 300.25(h), this
As a reminder, in accordance with 50 CFR 300.25(h), a trip limit of 25 mt per vessel applies. When NMFS anticipates that the total catch for the U.S. fleet has reached 375 mt, NMFS will impose a 2 mt trip limit until 425 mt have been caught and the fishery is closed.
16 U.S.C. 951
Office of Energy Efficiency and Renewable Energy, Department of Energy.
Supplemental notice of proposed rulemaking.
The Energy Policy and Conservation Act of 1975, as amended (EPCA), prescribes energy conservation standards for various consumer products and certain commercial and industrial equipment, including small, large, and very large air-cooled commercial package air conditioning and heating equipment and commercial warm air furnaces. EPCA also requires that the U.S. Department of Energy (DOE) periodically review and consider amending its standards for specified categories of industrial equipment, including commercial heating and air-conditioning equipment, in order to determine whether more-stringent, amended standards would be technologically feasible and economically justified, and save a significant additional amount of energy. In this document, DOE proposes to amend the energy conservation standards for both small, large, and very large air-cooled commercial package air conditioning and heating equipment and commercial warm air furnaces identical to those set forth in a direct final rule published elsewhere in this
DOE will accept comments, data, and information regarding the proposed standards no later than May 4, 2016.
Comments regarding the likely competitive impact of the proposed standard should be sent to the Department of Justice contact listed in the
1.
2.
3.
4.
No telefacsimilies (faxes) will be accepted.
For detailed instructions on submitting comments and additional information on the rulemaking process, see section III of this document (“Public Participation”).
Written comments regarding the burden-hour estimates or other aspects of the collection-of-information requirements contained in this proposed rule may be submitted to Office of Energy Efficiency and Renewable Energy through the methods listed above and by email to
EPCA requires the Attorney General to provide DOE a written determination of whether the proposed standard is likely to lessen competition. The U.S. Department of Justice Antitrust Division invites input from market participants and other interested persons with views on the likely competitive impact of the proposed standard. Interested persons may contact the Division at
A link to the docket Web page for small, large, and very large air-cooled commercial package air conditioning and heating equipment can be found at:
For further information on how to review the dockets, please contact Ms. Brenda Edwards at (202) 586–2945 or by email:
Mr. John Cymbalsky, U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Building Technologies, EE–5B, 1000 Independence Avenue SW., Washington, DC 20585–0121. Telephone: (202) 286–1692. Email:
Title III, Part C
Section 342(a) of EPCA, which was added as part of the Energy Policy Act of 1992, Public Law 102–486 (October 24, 1992) (“EPAct 1992”), introduced new provisions regarding DOE's authority to regulate certain commercial and industrial equipment. Among the equipment EPAct 1992 required DOE to regulate were small and large air-cooled commercial package air conditioning and heating equipment, along with commercial warm air furnaces (“CWAFs”). See EPAct 1992, sec. 122 (codified as amended at 42 U.S.C. 6313(a)). As part of these changes, Congress specified energy conservation standards for this equipment to meet. See id. Later, the Energy Policy Act of 2005, Public Law 109–58 (August 8, 2005) (“EPACT 2005”), further amended DOE's authority to include very large air-cooled commercial package air conditioning and heating equipment and added standards for this equipment to meet as well. See EPACT 2005, sec. 136 (codified as amended at 42 U.S.C. 6313(a)). (Small, large, and very large, air-cooled commercial package air conditioning and heating equipment are also known generally as air-cooled commercial unitary air conditioners and heat pumps (“CUACs” and “CUHPs”). Congress established standards for CUACs/CUHPs that have a rated capacity between 65,000 British thermal units per hour (Btu/h) and 760,000 Btu/h. Similarly, for CWAFs, Congress established standards for equipment that (1) have a rated capacity (rated maximum input
Collectively, CUACs/CUHPs and CWAFs are designed to heat and cool commercial buildings and are often located on a building's rooftop.
Section 342(a) of EPCA concerns energy conservation standards for small, large, and very large, CUACs and CUHPs. (42 U.S.C. 6313(a)) This category of equipment has a rated capacity between 65,000 Btu/h and 760,000 Btu/h. This equipment is designed to heat and cool commercial buildings and is often located on the building's rooftop.
The initial Federal energy conservation standards for CWAFs were added to EPCA by the Energy Policy Act of 1992 (EPACT 1992), Public Law 102–486 (Oct. 24, 1992). See 42 U.S.C. 6313(a)(4). These types of covered equipment have a rated capacity (rated maximum input
Pursuant to section 342(a)(6) of EPCA, DOE is to consider amending the energy efficiency standards for certain types of commercial and industrial equipment whenever ASHRAE amends the standard levels or design requirements prescribed in ASHRAE/IES Standard 90.1, and whenever more than 6 years had elapsed since the issuance of the most recent final rule establishing or amending a standard for the equipment as of the date of AEMTCA's enactment, December 18, 2012. (42 U.S.C. 6313(a)(6)(C)(vi)) Because more than six years had elapsed since DOE issued a final rule with standards for CUACs and CUHPs or CWAFs on October 18, 2005 (see 70 FR 60407), DOE initiated the process to review these standards.
Pursuant to EPCA, DOE's energy conservation program for covered equipment consists essentially of four parts: (1) Testing; (2) labeling; (3) the establishment of Federal energy conservation standards; and (4) certification and enforcement procedures. Subject to certain criteria and conditions, DOE is required to develop test procedures to measure the energy efficiency, energy use, or estimated annual operating cost of covered equipment. (42 U.S.C. 6314) Manufacturers of covered equipment must use the prescribed DOE test procedure as the basis for certifying to DOE that their equipment comply with the applicable energy conservation standards adopted under EPCA and when making representations to the public regarding their energy use or efficiency. (42 U.S.C. 6314(d)) Similarly, DOE must use these test procedures to determine whether a given manufacturer's equipment complies with standards adopted pursuant to EPCA. The DOE test procedures for small, large, and very large CUACs/CUHPs and CWAFs currently appear at title 10 of the Code of Federal Regulations (“CFR”) 431.96 and 431.76, respectively.
When setting standards for the equipment addressed by this document, EPCA prescribes that in deciding whether a proposed standard is economically justified, DOE must determine whether the benefits of the standard exceed its burdens. DOE must make this determination after receiving comments on the proposed standard, and by considering, to the maximum extent practicable, the following seven statutory factors:
1. The economic impact of the standard on manufacturers and consumers of products subject to the standard;
2. The savings in operating costs throughout the estimated average life of the covered products in the type (or class) compared to any increase in the price, initial charges, or maintenance expenses for the covered products
3. The total projected amount of energy savings likely to result directly from the standard;
4. Any lessening of the utility or the performance of the covered products likely to result from the standard;
5. The impact of any lessening of competition, as determined in writing by the Attorney General, that is likely to result from the standard;
6. The need for national energy conservation; and
7. Other factors the Secretary of Energy considers relevant. (42 U.S.C. 6313(a)(6)(B)(ii))
With respect to the types of equipment at issue in this document, EPCA also contains what is known as an “anti-backsliding” provision, which prevents the Secretary from prescribing any amended standard that either increases the maximum allowable energy use or decreases the minimum required energy efficiency of a covered product. (42 U.S.C. 6313(a)(6)(B)(iii)(I)) Also, the Secretary may not prescribe an amended or new standard if interested persons have established by a preponderance of the evidence that the standard is likely to result in the unavailability in the United States of any covered product type (or class) of performance characteristics (including reliability, features, sizes, capacities, and volumes) that are substantially the same as those generally available in the United States. (42 U.S.C. 6313(a)(6)(B)(iii)(II))(aa)
With respect to the equipment addressed by this document, DOE notes that EPCA prescribes limits on the Agency's ability to promulgate a standard if DOE has made a finding that interested persons have established by a preponderance of the evidence that a standard is likely to result in the unavailability of any product type (or class) of performance characteristics that are substantially the same as those generally available in the United States at the time of the finding. See 42 U.S.C. 6313(B)(iii)(II).
Additionally, EPCA generally specifies criteria to follow when promulgating multiple energy conservation standards for covered products based on different subcategories. In these cases, DOE must specify a different standard level for a type or class of product that has the same function or intended use if DOE determines that products within such group: (A) Consume a different kind of energy from that consumed by other covered products within such type (or class); or (B) have a capacity or other performance-related feature which other products within such type (or class) do not have and such feature justifies a higher or lower standard. See 42 U.S.C. 6295(q)(1). In determining whether a performance-related feature justifies a different standard for a group of products, DOE must consider such factors as the utility to the customer of such a feature and other factors DOE deems appropriate. Id. Any rule prescribing such a standard must include an explanation of the basis on which such higher or lower level was established. See 42 U.S.C. 6295(q)(2). With respect to the equipment addressed by this supplemental notice of proposed rulemaking (“SNOPR”), DOE notes that EPCA prescribes limits on the Agency's ability to promulgate a standard if DOE has made a finding that interested persons have established by a preponderance of the evidence that a standard is likely to result in the unavailability of any product type (or class) of performance characteristics that are substantially the same as those generally available in the United States at the time of the finding. See 42 U.S.C. 6313(B)(iii)(II).
With particular regard to this document, the Energy Independence and Security Act of 2007 (“EISA 2007”), Public Law 110–140 (December 19, 2007), amended EPCA, in relevant part, to grant DOE authority to issue a type of final rule (
Responding to comments received from interested parties with respect to DOE's proposals, on April 1, 2015, DOE issued a Notice of Intent to Establish the Commercial Package Air Conditioners and Commercial Warm Air Furnaces Working Group to Negotiate Potential Energy Conservation Standards for Commercial Package Air Conditioners and Commercial Warm Air Furnaces. 80 FR 17363. The CUAC/CUHP–CWAF Working Group (in context, “the Working Group”) was established under the Appliance Standards and Rulemaking Federal Advisory Committee (“ASRAC”) in accordance with the Federal Advisory Committee Act and the Negotiated Rulemaking Act with the purpose of discussing and, if possible, reaching consensus on a set of energy conservation standards to propose or finalize for CUACs, CUHPs and CWAFs. The Working Group was to consist of fairly representative parties having a defined stake in the outcome of the proposed standards, and would consult, as appropriate, with a range of experts on technical issues.
DOE received 17 nominations for membership. Ultimately, the Working Group consisted of 17 members, including one member from ASRAC and one DOE representative.
DOE has determined that the statement containing recommendations with respect to energy conservation standards for CUACs, CUHPs and CWAFs was submitted jointly by interested persons that are fairly representative of relevant points of view, in accordance with 42 U.S.C. 6295(p)(4)(A) and 6313(a)(6)(B).
Pursuant to 42 U.S.C. 6295(p)(4), the Secretary must also determine whether a jointly-submitted recommendation for an energy or water conservation standard satisfies 42 U.S.C. 6295(o) or 42 U.S.C. 6313(a)(6)(B), as applicable. In making this determination, DOE has conducted an analysis to evaluate whether the potential energy conservation standards under consideration would meet these requirements. This evaluation is similar to the comprehensive approach that DOE typically conducts whenever it considers potential energy conservation standards for a given type of product or equipment. DOE applies the same principles to any consensus recommendations it may receive to satisfy its statutory obligation to ensure that any energy conservation standard that it adopts achieves the maximum improvement in energy efficiency that is technologically feasible and economically justified and will result in the significant conservation of energy. Upon review, the Secretary determined that the Term Sheet submitted in the instant rulemaking comports with the standard-setting criteria set forth under 42 U.S.C. 6313(a)(6)(B). As a result, DOE published a direct final rule establishing energy conservation standards for CUACs/CUHPs and CWAFs elsewhere in this
For further background information on these proposed standards and the supporting analyses, please see the direct final rule published elsewhere in this
When considering more stringent standards for the equipment at issue, DOE must determine, supported by clear and convincing evidence that adopting those standards would result in the significant additional conservation of energy and be technologically feasible and economically justified. See 42 U.S.C. 6313(a)(6)(A)(ii). In determining whether a standard is economically justified, the Secretary must determine whether the benefits of the standard exceed its burdens by, to the greatest extent practicable, considering the seven statutory factors discussed previously. (42 U.S.C. 6313(a)(6)(B)(ii)(I)–(VII))
DOE considered the impacts of amended standards for CUACs/CUHPs and CWAFs at each TSL, beginning with the maximum technologically feasible level, to determine whether that level would be economically justified. Where the max-tech level was not justified, DOE then considered the next most efficient level and undertook the same evaluation until it reached the highest efficiency level that is both technologically feasible and economically justified and saves a significant amount of energy.
To aid the reader as DOE discusses the benefits and/or burdens of each TSL, tables in this section present a summary of the results of DOE's quantitative analysis for each TSL. In addition to the quantitative results presented in the tables, DOE also considers other burdens and benefits that affect economic justification.
Table II.1 and Table II.2 summarize the quantitative impacts estimated for each TSL for CUACs and CUHPs. The national impacts are measured over the lifetime of CUACs and CUHPs purchased in the 2018–2048 period. The energy savings, emissions reductions, and value of emissions reductions refer to full-fuel-cycle results. The efficiency levels contained in each TSL are described in section V.A of the direct final rule.
DOE first considered TSL 5, which represents the max-tech efficiency levels. TSL 5 would save 23.4 quads of energy, an amount DOE considers significant. Under TSL 5, the NPV of consumer benefit would be $18.8 billion using a discount rate of 7-percent, and $68.2 billion using a discount rate of 3-percent.
The cumulative emissions reductions at TSL 5 are 1,383 million Mt of CO
At TSL 5, the average LCC impact is a savings of $5,326 for small CUACs, $12,900 for large CUACs, and $18,338 for very large CUACs. The simple payback period is 4.6 years for small CUACs, 4.6 years for large CUACs, and 6.3 years for very large CUACs. The fraction of consumers experiencing a net LCC cost is 16 percent for small CUACs, 11 percent for large CUACs, and 6 percent for very large CUACs. Although DOE did not estimate consumer impacts for CUHPs, the results would be very similar to those for CUACs for the reasons stated in section V.B.1 of the direct final rule.
At TSL 5, the projected change in INPV ranges from a decrease of $881.9 million to an increase of $93.1 million, which corresponds to a change of −53.7 percent and 5.7 percent, respectively. The industry is expected to incur $591.0 million in total conversion costs at this level. DOE projects that 98.7 percent of current equipment listings would require redesign at this level to meet this standard level today. At this level, DOE recognizes that manufacturers could face technical resource constraints. Manufacturers stated they would require additional engineering expertise and additional test laboratory capacity. It is unclear whether manufacturers could complete the hiring of the necessary technical expertise and construction of the necessary test facilities in time to allow for the redesign of all equipment to meet max-tech by 2019. Furthermore, DOE recognizes that a standard set at max-tech could greatly limit equipment differentiation in the CUAC/CUHP market. By commoditizing a key differentiating feature, a standard set at max-tech would likely accelerate consolidaton in the industry.
The Secretary tentatively concludes that at TSL 5 for CUACs and CUHPs, the benefits of energy savings, positive NPV of consumer benefits, emission reductions, and the estimated monetary value of the emissions reductions would be outweighed by the economic burden on some consumers, and the impacts on manufacturers, including the conversion costs and profit margin impacts that could result in a large reduction in INPV. Consequently, the Secretary has tentatively concluded that TSL 5 is not economically justified.
DOE then considered TSL 4. TSL 4 would save 19.7 quads of energy, an amount DOE considers significant. Under TSL 4, the NPV of consumer benefit would be $19.2 billion using a discount rate of 7-percent, and $64.1 billion using a discount rate of 3-percent.
The cumulative emissions reductions at TSL 4 are 1,167 million Mt of CO
At TSL 4, the average LCC impact is a savings of $3,035 for small CUACs, $16,803 for large CUACs, and $18,386 for very large CUACs. The simple payback period is 2.5 years for small CUACs, 2.5 years for large CUACs, and 5.6 years for very large CUACs. The fraction of consumers experiencing a net LCC cost is 25 percent for small CUACs, 1 percent for large CUACs, and 3 percent for very large CUACs. Although DOE did not estimate consumer impacts for CUHPs, the results would be very similar to those for CUACs for the reasons stated in section V.B.1 of the direct final rule.
At TSL 4, the projected change in INPV ranges from a decrease of $619.6 million to an increase of $16.3 million, which corresponds to a change of −37.7 percent and 1.0 percent, respectively. The industry is expected to incur $538.8 million in total conversion costs at this level. DOE projects that 96.0 percent of current equipment listings would require redesign at this level to meet this standard level today.
The Secretary tentatively concludes that at TSL 4 for CUACs and CUHPs, the benefits of energy savings, positive NPV of consumer benefits, emission reductions, and the estimated monetary value of the emissions reductions would be outweighed by the economic burden on some consumers, and the impacts on manufacturers, including the conversion costs and profit margin impacts that could result in a reduction in INPV. Consequently, the Secretary has tentatively concluded that TSL 4 is not economically justified.
DOE then considered TSL 3.5. TSL 3.5 would save 16.4 quads of energy, an amount DOE considers significant. Under TSL 3.5, the NPV of consumer benefit would be $17.1 billion using a discount rate of 7-percent, and $55.3 billion using a discount rate of 3-percent.
The cumulative emissions reductions at TSL 3.5 are 973 million Mt of CO
At TSL 3.5, the average LCC impact is a savings of $3,517 for small CUACs, $12,266 for large CUACs, and $8,881 for very large CUACs. The simple payback period is 2.6 years for small CUACs, 2.6 years for large CUACs, and 7.2 years for very large CUACs. The fraction of consumers experiencing a net LCC cost is 13 percent for small CUACs, 1 percent for large CUAC, and 23 percent for very large CUACs. Although DOE did not estimate consumer impacts for CUHPs, the results would be very similar to those for CUACs for the reasons stated in section V.B.1 of the direct final rule.
At TSL 3.5, the projected change in INPV ranges from a decrease of $506.4 million to an increase of $25.7 million, which corresponds to a change of −30.8 percent and 1.6 percent, respectively. The industry is expected to incur $489.2 million in total conversion costs at this level. DOE projects that 93.5 percent of current equipment listings would
The Secretary tentatively concludes that at TSL 3.5 for CUACs and CUHPs, the benefits of energy savings, positive NPV of consumer benefits, emission reductions, and the estimated monetary value of the emissions reductions would be outweighed by the economic burden on some consumers, and the impacts on manufacturers, including the conversion costs and profit margin impacts that could result in a reduction in INPV. Consequently, the Secretary has tentatively concluded that TSL 3.5 is not economically justified.
DOE then considered TSL 3. TSL 3 would save 15.9 quads of energy, an amount DOE considers significant. Under TSL 3, the NPV of consumer benefit would be $16.8 billion using a discount rate of 7-percent, and $53.7 billion using a discount rate of 3-percent.
The cumulative emissions reductions at TSL 3 are 943 million Mt of CO
At TSL 3, the average LCC impact is a savings of $4,233 for small CUACs, $10,135 for large CUACs, and $8,881 for very large CUACs. The simple payback period is 4.9 years for small CUACs, 2.6 years for large CUACs, and 7.2 years for very large CUACs. The fraction of consumers experiencing a net LCC cost is 5 percent for small CUACs, 2 percent for large CUAC, and 23 percent for very large CUACs. Although DOE did not estimate consumer impacts for CUHPs, the results would be very similar to those for CUACs for the reasons stated in section V.B.1 of the direct final rule.
At TSL 3, the projected change in INPV ranges from a decrease of $447.2 million to an increase of $52.4 million, which corresponds to a change of −27.2 percent and 3.2 percent, respectively. DOE projects that 81.6 percent of current equipment listings would require redesign at this level to meet this standard level today.
The Secretary tentatively concludes that at TSL 3 for CUACs and CUHPs, the benefits of energy savings, positive NPV of consumer benefits, emission reductions, and the estimated monetary value of the emissions reductions would be outweighed by the economic burden on some consumers, and the impacts on manufacturers, including the conversion costs and profit margin impacts that could result in a large reduction in INPV. Consequently, the Secretary has tentatively concluded that TSL 3 is not economically justified.
DOE then considered the Recommended TSL, which reflects the standard levels recommended by the Working Group. The Recommended TSL would save 14.8 quads of energy, an amount DOE considers significant. Under the Recommended TSL, the NPV of consumer benefit would be $15.2 billion using a discount rate of 7-percent, and $50.0 billion using a discount rate of 3-percent.
The cumulative emissions reductions at the Recommended TSL are 873 million Mt of CO
At the Recommended TSL, the average LCC impact is a savings of $4,233 for small CUACs, $10,135 for large CUACs, and $8,610 for very large CUACs. The simple payback period is 4.9 years for small CUACs, 2.6 years for large CUACs, and 6.2 years for very large CUACs. The fraction of consumers experiencing a net LCC cost is 5 percent for small CUACs, 2 percent for large CUACs, and 7 percent for very large CUACs. Although DOE did not estimate consumer impacts for CUHPs, the results would be very similar to those for CUACs for the reasons stated in section V.B.1 of the direct final rule.
The Recommended TSL, as presented by the Working Group and approved by ASRAC, aligns the effective dates of the CUAC/CUHP and CWAF rulemakings. That approach adopts the ASHRAE 90.1–2013 efficiency levels in 2018 and a higher level in in 2023 as recommended by the Working Group. DOE anticipates that aligning the effective dates will reduce total conversion costs and cumulative regulatory burden, while also allowing industry to gain clarity on potential regulations that could affect refrigerant availability before the higher appliance standard takes effect in 2023. DOE projects that 31.5 percent of current equipment listings would require redesign at this level to meet the 2018 standard level, while 79.6 percent of current equipment listings would require redesign at this level to meet the 2023 standard level.
At the Recommended TSL, the projected change in INPV ranges from a decrease of $440.4 million to a decrease of $38.5 million, which corresponds to a change of −26.8 percent and −2.3 percent, respectively. The industry is expected to incur $520.8 million in total conversion costs at this level. However, the industry members of the Working Group noted that aligning the compliance dates for the CUAC/CUHP and CWAF standards in the manner recommended would allow manufacturers to coordinate their redesign and testing expenses for these equipment. (CUAC: AHRI and ACEEE, No. 80 at p. 1). With this coordination, manufacturers explained that there would be a reduction in the total conversion costs associated with the direct final rule. The resulting synergies from aligning the CUAC/CUHP and CWAF compliance dates would produce INPV impacts that are less severe than the forecasted INPV range of −26.8 percent to −2.3 percent.
After considering the analysis and weighing the benefits and burdens, DOE has tentatively determined that the recommended standards are in accordance with 42 U.S.C. 6313(a)(6)(B), which contains provisions for adopting a uniform national standard more stringent than the amended ASHRAE Standard 90.1 for the equipment considered in this document. Specifically, the Secretary has tentatively determined, supported by clear and convincing evidence that such adoption would result in the significant additional conservation of energy and is technologically feasible and economically justified. In determining whether the recommended standards are economically justified, the Secretary has tentatively determined that the benefits of the recommended standards exceed the burdens. Namely, the Secretary has tentatively concluded that under the recommended standards for CUACs and CUHPs, the benefits of energy savings, positive NPV of consumer benefits, emission reductions, the estimated monetary value of the emissions reductions, and positive average LCC savings would outweigh the negative impacts on some consumers and on manufacturers, including the conversion costs that could result in a reduction in INPV for manufacturers.
The proposed amended energy conservation standards for CUACs and CUHPs, which prescribe the minimum allowable IEER and, for commercial unitary heat pumps, COP, are shown in Table II.3.
The benefits and costs of the proposed standards—which mimic those found in the direct final rule—can also be expressed in terms of annualized values. The annualized net benefit is the sum of: (1) The annualized national economic value (expressed in 2014$) of the benefits from operating equipment that meet the adopted standards (consisting primarily of operating cost savings from using less energy, minus increases in product purchase costs, and (2) the annualized monetary value of the benefits of CO
Table II.4 shows the annualized values for CUACs and CUHPs under the Recommended TSL, expressed in 2014$. The results under the primary estimate are as follows. Using a 7-percent discount rate for benefits and costs other than CO
Table II.5 and Table II.6 summarize the quantitative impacts estimated for each TSL for CWAFs. For TSL 2, the national impacts are projected over the lifetime of equipment sold in 2023–2048. For the other TSLs, the impacts are projected over the lifetime of equipment sold in 2019–2048. The energy savings, emissions reductions, and value of emissions reductions refer to full-fuel-cycle results. The efficiency levels contained in each TSL are described in section V.A of the direct final rule.
DOE first considered TSL 5, which represents the max-tech efficiency levels. TSL 5 would save 2.4 quads of energy, an amount DOE considers significant. Under TSL 5, the NPV of consumer cost would be $0.4 billion using a 7-percent discount rate, and the NPV of consumer benefit would be $2.6 billion using a 3-percent discount rate.
The cumulative emissions reductions at TSL 5 are 126 Mt of CO
At TSL 5, the average LCC impact is a savings of $766 for gas-fired CWAFs and $1,817 for oil-fired CWAFs. The simple payback period is 11.3 years for gas-fired CWAFs and 7.5 years for oil-fired CWAFs. The fraction of consumers experiencing a net LCC cost is 58 percent for gas-fired CWAF and 54 percent for oil-fired CWAFs.
At TSL 5, the projected change in INPV ranges from a decrease of $115.7 million to an increase of $47.2 million, which corresponds to a change of −120.1 percent and 49.0 percent, respectively. The industry is expected to incur $157.5 million in total conversion costs at this level. DOE projects that 99 percent of current equipment listings would require redesign at this level.
The Secretary tentatively concludes that at TSL 5 for CWAFs, the benefits of energy savings, positive NPV of consumer benefits using a discount rate of 3 percent, emission reductions, and the estimated monetary value of the emissions reductions would be outweighed by the economic burden on most consumers, the negative NPV of consumer benefits using a 7-percent discount rate, and the impacts on manufacturers, including the conversion costs and profit margin impacts that could result in a large reduction in INPV. Consequently, the Secretary has tentatively concluded that TSL 5 is not economically justified.
DOE then considered TSL 4. TSL 4 would save 0.41 quads of energy, an amount DOE considers significant. Under TSL 4, the NPV of consumer cost would be $0.4 billion using a 7-percent discount rate, and $0.1 billion using a 3-percent discount rate.
The cumulative emissions reductions at TSL 4 are 22 Mt of CO
At TSL 4, the average LCC impact is a savings of $75 for gas-fired CWAFs and $400 for oil-fired CWAFs. The simple payback period is 12.3 years for gas-fired CWAFs and 1.9 years for oil-fired CWAFs. The fraction of consumers experiencing a net LCC cost is 58 percent for gas-fired CWAFs, and 11 percent for oil-fired CWAFs.
At TSL 4, the projected change in INPV ranges from a decrease of $35.9 million to an increase of $28.4 million, which corresponds to a change of −37.3 percent and 29.5 percent, respectively. The industry is expected to incur $47.6 million in total conversion costs at this level. DOE projects that 94 percent of current product listings would require redesign at this level.
The Secretary tentatively concludes that at TSL 4 for CWAFs, the benefits of energy savings, emission reductions, and the estimated monetary value of the emissions reductions would be outweighed by the economic burden on many consumers, negative NPV of consumer benefits, and the impacts on manufacturers, including the conversion costs and profit margin impacts that could result in a large reduction in INPV. Consequently, the Secretary has tentatively concluded that TSL 4 is not economically justified.
DOE then considered TSL 3. TSL 3 would save 0.41 quads of energy, an amount DOE considers significant. Under TSL 3, the NPV of consumer cost would be $0.4 billion using a 7-percent discount rate, and $0.1 billion using a 3-percent discount rate.
The cumulative emissions reductions at TSL 3 are 22 Mt of CO
At TSL 3, the average LCC impact is a savings of $75 for gas-fired CWAFs. The simple payback period is 12.3 years for gas-fired CWAFs. The fraction of consumers experiencing a net LCC cost is 58 percent for gas-fired CWAFs. The EL at TSL 3 for oil-fired CWAFs is the baseline, so there are no LCC impacts for oil-fired CWAFs at TSL 3.
At TSL 3, the projected change in INPV ranges from a decrease of $30.9 million to an increase of $28.8 million, which corresponds to a change of −32.0 percent and 29.9 percent, respectively. The industry is expected to incur $41.0 million in total conversion costs at this level. DOE projects that 91 percent of current equipment listings would require redesign at this level.
The Secretary tentatively concludes that at TSL 3 for CWAFs, the benefits of
DOE then considered TSL 2, which corresponds to the recommendations by the Working Group. TSL 2 would save 0.23 quads of energy, an amount DOE considers significant. Under TSL 2, the NPV of consumer benefit would be $0.3 billion using a 7-percent discount rate, and $1.0 billion using a 3-percent discount rate.
The cumulative emissions reductions at TSL 2 are 12.4 Mt of CO
At TSL 2, the average LCC impact is a savings of $284 for gas-fired CWAFs and $400 for oil-fired CWAFs. The simple payback period is 1.4 years for gas-fired CWAF and 1.9 years for oil-fired CWAFs. The fraction of consumers experiencing a net LCC cost is 6 percent for gas-fired CWAFs and 11 percent for oil-fired CWAFs.
At TSL 2, 57 percent of current equipment listings would require redesign at this level. The projected change in INPV ranges from a decrease of $13.4 million to a decrease of $5.9 million, which corresponds to a decrease of 13.9 percent and 6.1 percent, respectively. The CWAF industry is expected to incur $22.2 million in total conversion costs. However, the industry noted that aligning the compliance dates for the CUAC/CUHP and CWAF standards, as recommended by the Working Group, would allow manufacturers to coordinate their redesign and testing expenses for this equipment. If this occurs, there could be a reduction in the total conversion costs associated with the DFR. The resulting synergies from aligning the compliance dates of the CUAC/CUHP and CWAF standards would produce INPV impacts that are less severe than the forecasted INPV range of −13.9 percent to −6.1 percent.
After considering the analysis and weighing the benefits and burdens, DOE has tentatively determined that the recommended standards are in accordance with 42 U.S.C. 6313(a)(6)(B), which contains provisions for adopting a uniform national standard more stringent than the amended ASHRAE/IES Standard 90.1 for the equipment considered in this document. Specifically, the Secretary has tentatively determined, supported by clear and convincing evidence, that such adoption would result in significant additional conservation of energy and is technologically feasible and economically justified. In determining whether the recommended standards are economically justified, the Secretary has tentatively determined that the benefits of the recommended standards exceed the burdens. Namely, the Secretary has tentatively concluded that under the recommended standards for CWAFs, the benefits of energy savings, positive NPV of consumer benefits, emission reductions, the estimated monetary value of the emissions reductions, and positive average LCC savings would outweigh the negative impacts on some consumers and on manufacturers, including the conversion costs that could result in a reduction in INPV for manufacturers.
Based on the above analyses, DOE is proposing to amend the energy conservation standards for CWAFs—as expressed in terms of thermal efficiency—in the manner shown in Table II.7.
The benefits and costs of the proposed standards can also be expressed in terms of annualized values. The annualized net benefit is the sum of: (1) The annualized national economic value (expressed in 2014$) of the benefits from operating equipment that meet the adopted standards (consisting primarily of operating cost savings from using less energy, minus increases in equipment purchase costs), and (2) the annualized monetary value of the benefits of CO
Table II.8 shows the annualized values for CWAFs under TSL 2, expressed in 2014$. The results under the primary estimate are as follows. Using a 7-percent discount rate for benefits and costs other than CO
Using a 3-percent discount rate for all benefits and costs and the average SCC series corresponding to a value of $40.0/ton in 2015 (in 2014$), the estimated cost of the adopted standards for CWAFs is $4.38 million per year in increased equipment costs, while the estimated benefits are $71 million per year in reduced operating costs, $24.3 million per year in CO
DOE will accept comments, data, and information regarding this proposed rule before or after the public meeting, but no later than the date provided in the
Submitting comments via
However, your contact information will be publicly viewable if you include it in the comment itself or in any documents attached to your comment. Any information that you do not want to be publicly viewable should not be included in your comment, nor in any document attached to your comment. Otherwise, persons viewing comments will see only first and last names, organization names, correspondence containing comments, and any documents submitted with the comments.
Do not submit to
DOE processes submissions made through
Include contact information each time you submit comments, data, documents, and other information to DOE. If you submit via mail or hand delivery/courier, please provide all items on a CD, if feasible, in which case it is not necessary to submit printed copies. No telefacsimiles (faxes) will be accepted.
Comments, data, and other information submitted to DOE electronically should be provided in PDF (preferred), Microsoft Word or Excel, WordPerfect, or text (ASCII) file format. Provide documents that are not secured, that are written in English, and that are free of any defects or viruses. Documents should not contain special characters or any form of encryption and, if possible, they should carry the electronic signature of the author.
Factors of interest to DOE when evaluating requests to treat submitted information as confidential include: (1) A description of the items; (2) whether and why such items are customarily treated as confidential within the industry; (3) whether the information is generally known by or available from other sources; (4) whether the information has previously been made available to others without obligation concerning its confidentiality; (5) an explanation of the competitive injury to the submitting person that would result from public disclosure; (6) when such information might lose its confidential character due to the passage of time; and (7) why disclosure of the information would be contrary to the public interest.
It is DOE's policy that all comments may be included in the public docket, without change and as received, including any personal information provided in the comments (except information deemed to be exempt from public disclosure).
The regulatory reviews conducted for this proposed rule are identical to those conducted for the direct final rule published elsewhere in this
The Secretary of Energy has approved publication of this proposed rule.
Administrative practice and procedure, Confidential business information, Energy conservation, Household appliances, Imports, Intergovernmental relations, Reporting and recordkeeping requirements, Small businesses.
For the reasons set forth in the preamble, DOE proposes to amend part 431 of chapter II, subchapter D, of title 10 of the Code of Federal Regulations, to read as set forth below:
42 U.S.C. 6291–6317.
(a)
(1) For gas-fired commercial warm air furnaces manufactured starting on January 1, 1994, until January 1, 2023, the TE at the maximum rated capacity (rated maximum input) must be not less than 80 percent; and
(2) For gas-fired commercial warm air furnaces manufactured starting on January 1, 2023, the TE at the maximum rated capacity (rated maximum input) must be not less than 81 percent.
(b)
(1) For oil-fired commercial warm air furnaces manufactured starting on January 1, 1994, until January 1, 2023, the TE at the maximum rated capacity (rated maximum input) must be not less than 81 percent; and
(2) For oil-fired commercial warm air furnaces manufactured starting on January 1, 2023, the TE at the maximum rated capacity (rated maximum input) must be not less than 82 percent.
(1) Is either a horizontal single package or split-system unit; or a vertical unit that consists of two components that may be shipped or installed either connected or split;
(2) Is intended for indoor installation with ducting of outdoor air from the building exterior to and from the unit, as evidenced by the unit and/or all of its components being non-weatherized, including the absence of any marking (or listing) indicating compliance with UL 1995, “Heating and Cooling Equipment,” or any other equivalent requirements for outdoor use;
(3)(i) If it is a horizontal unit, a complete unit has a maximum height of 35 inches;
(ii) If it is a vertical unit, a complete unit has a maximum depth of 35 inches; and
(4) Has a rated cooling capacity greater than or equal to 65,000 Btu/h and up to 300,000 Btu/h.
a. Redesignating Tables 5 through 11 as Tables 7 through 13;
b. Revising paragraph (b) and the introductory text of paragraph (c);
c. In paragraph (d)(1) introductory text, removing “Table 7” and adding in its place “Table 9”;
d. In paragraph (d)(2) introductory text, removing “Table 8” and adding in its place “Table 10”; and
e. In paragraph (d)(3) introductory text, removing “Table 9” and adding in its place “Table 11”.
The revisions read as follows:
(b) Each commercial air conditioner or heat pump (not including single package vertical air conditioners and single package vertical heat pumps, packaged terminal air conditioners and packaged terminal heat pumps, computer room air conditioners, and variable refrigerant flow systems) manufactured starting on the compliance date listed in the corresponding table must meet the applicable minimum energy efficiency standard level(s) set forth in Tables 1 through 6 of this section.
(c) Each packaged terminal air conditioner (PTAC) and packaged terminal heat pump (PTHP) manufactured starting on January 1, 1994, but before October 8, 2012 (for standard size PTACs and PTHPs) and before October 7, 2010 (for non-standard size PTACs and PTHPs) must meet the applicable minimum energy efficiency standard level(s) set forth in Table 7 of this section. Each standard size PTAC and PTHP manufactured starting on October 8, 2012, and each non-standard size PTAC and PTHP manufactured starting on October 7, 2010, must meet the applicable minimum energy efficiency standard level(s) set forth in Table 6 of this section.
U.S. Small Business Administration.
Advance notice of proposed rulemaking.
The U.S. Small Business Administration (SBA) is soliciting
Comments must be submitted on or before March 15, 2016.
You may submit comments, identified by RIN 3245–AG76, by any of the following methods: (1) Federal Rulemaking Portal:
Linda Reilly, Acting Director, Office of Financial Assistance, U.S. Small Business Administration, 409 3rd Street SW., 8th Floor, Washington, DC 20416, telephone number (202) 205–9949 or
The Certified Development Company (CDC) program, also referred to as the 504 Loan Program, is authorized pursuant to Title V of the Small Business Investment Act of 1958, 15 U.S.C. 695
Under the 504 Loan Program, loans are made to small business applicants by CDCs, which are SBA's community-based partners for providing 504 Loans. With the exception of several for-profit CDCs grandfathered into the 504 Loan Program, a CDC is a nonprofit corporation that promotes economic development within its community through 504 Loans. CDCs are certified and regulated by the SBA, and work with SBA and participating lenders (typically banks) to provide financing to small businesses with the goal of facilitating the creation and retention of jobs and local economic development. There are over 260 CDCs nationwide each with a defined Area of Operations covering a specific geographic area. The Area of Operations for most CDCs is the state in which they are incorporated.
Under 13 CFR 120.825, CDCs are required to be able to sustain their operations continuously with reliable sources of funds, such as income from services rendered and contributions from government or other sponsors. This regulation also provides that any funds generated from loan activity in the 504 Loan Program that remain after payment of staff and overhead expenses (such funds referred to herein as “remaining funds”) must be retained by the CDC as a reserve for future operations or for investment in other local economic development activity in the CDC's Area of Operations. In addition, on March 21, 2014, SBA issued a Final Rule (79 FR 15641) that requires each CDC's Board of Directors to ensure that the CDC establishes and maintains adequate reserves for operations (13 CFR 120.823(d)(9)) and invests in economic development in each State in its Area of Operations where the CDC has outstanding 504 Loans (13 CFR 120.823(d)(10)). Accordingly, in reading 13 CFR 120.823(d)(9) and (10) and 120.825 together, each CDC's Board of Directors must ensure that any remaining funds are either retained as a reserve or invested in the CDC's community, but the current rules do not require the CDC to retain or invest any specific amounts or percentages.
CDCs have requested that SBA provide guidance on the acceptable types and amounts of investments that should apply to the remaining funds. To address the issue raised by the CDCs, SBA is considering whether to issue a future Proposed Rulemaking that would require CDCs to set aside a certain amount of their revenues for investing in other local economic development activities. SBA is also considering whether the rulemaking should address minimum and/or maximum requirements with respect to the size of the reserve that a CDC retains for its future operations. As stated above, 13 CFR 120.825 requires a CDC “to be able to sustain its operations continuously, with reliable sources of funds,” and a minimum reserve requirement would assist CDCs in complying with this provision. Excessive reserves, however, could limit the amount a CDC would have available for investing in local economic development activities. To develop a proposed rule to address these issues, SBA needs additional information and invites interested parties to provide it by responding to the questions set forth below.
Finally, SBA is considering providing guidance, through an agency directive (
To assist SBA in addressing the above issues, SBA requests comments from interested parties on the following questions:
1. What percentage of the CDC's 504 Loan Program revenues do remaining funds typically represent at the end of the CDC's fiscal year?
2. Should SBA require CDCs to use a certain amount or percentage of their remaining funds to invest in other local economic development activity in the CDC's Area of Operations? Please provide reasons for your response.
3. If the answer to question 2 is yes, how should the amount required to be invested in other local economic development activity in the CDC's Area of Operations be calculated? Some possibilities could include a percentage of the original loan amount of the CDC's 504 portfolio, a percentage of the current outstanding loan amount of the CDC's 504 portfolio, a percentage of the annual fees received by the CDC as a result of its 504 lending, or a percentage of the CDC's remaining funds. Should the percentage vary depending upon the dollar value of the CDC's portfolio or other factors? If so, describe how the percentage should vary and upon what factors.
4. Should SBA require CDCs to retain a minimum amount as a reserve for future operations if there are any remaining funds? If not, why not?
5. If the answer to question 4 is yes, how should the amount of a CDC's
6. Should SBA limit the amount that CDCs may retain as a reserve for future operations? If not, why not? If yes, what would be a reasonable maximum amount to allow as a reserve?
7. Should a CDC be able to decide that the reserve option would be a more prudent use of its remaining funds than economic development investments to ensure that it has the ability to “sustain its operations continuously”? Why or why not?
8. Should SBA require CDCs to first apply any remaining funds to the reserve for future operations before using any remaining funds for investments? Please provide reasons for your response.
9. What requirements, if any, should apply to a CDC's remaining funds if it voluntarily decertifies or is removed from the 504 Loan Program? Should the CDC be required to invest these funds in local economic development activities prior to decertification or removal?
10. What types of economic development activities should be included in the definition of “acceptable investments in economic development”? Are there any activities that should not be included in the definition? Examples of such acceptable investments in economic development could include loans, grants or other forms of direct financial support that are issued by the CDC for: (1) Other federal, state or local lending programs, such as microlending or revolving loan funds; (2) Small Business Development Centers; (3) business incubators; (4) industrial development; and (5) other non-profit economic development entities. Should the definition include business or technical procurement assistance provided by the CDC or paid for by the CDC?
Interested parties are invited to provide any other comments that they may have relating to the issues described in this Advance Notice of Proposed Rulemaking. We ask that you provide a brief justification for any suggested changes.
Federal Aviation Administration (FAA), DOT.
Supplemental notice of proposed rulemaking (NPRM); reopening of comment period.
We are revising an earlier proposed airworthiness directive (AD) for certain B/E Aerospace protective breathing equipment (PBE) that is installed on airplanes. The NPRM proposed inspecting the PBE to determine if the pouch has the proper vacuum seal and replacing if necessary. The NPRM was prompted by reports of a compromise in the vacuum seal of the pouch that contains the PBE. This action revises the NPRM by requiring replacement of the PBE following newly issued service information regardless of inspection results. We are proposing this supplemental NPRM (SNPRM) to correct the unsafe condition on these products. Since these actions impose an additional burden over that proposed in the NPRM, we are reopening the comment period to allow the public the chance to comment on these proposed changes.
We must receive comments on this SNPRM by February 29, 2016.
You may send comments, using the procedures found in 14 CFR 11.43 and 11.45, by any of the following methods:
•
•
•
•
For service information identified in this proposed rule, contact B/E Aerospace, Inc., Commercial Aircraft Products Group, 10800 Pflumm Road, Lenexa, Kansas 66215; telephone: (913) 338–9800; fax: (913) 338–8419; Internet:
You may examine the AD docket on the Internet at
David Enns, Aerospace Engineer, Wichita Aircraft Certification Office, FAA, 1801 S. Airport Road, Room 100, Wichita, Kansas 67209; telephone: (316) 946–4147; fax: (316) 946–4107; email:
We invite you to send any written relevant data, views, or arguments about this proposed AD. Send your comments to an address listed under the
We will post all comments we receive, without change, to
We issued an NPRM to amend 14 CFR part 39 by adding an AD that would apply to certain B/E Aerospace protective breathing equipment (PBE) that is installed on airplanes. The NPRM published in the
Since we issued the NPRM (80 FR 34330, June 16, 2015), further investigation into the fire of the PBE, part number (P/N) 119003–11, found that the ignitor candles from the PBE units that caught fire had a breach of the filter in the candle assembly. The breach of the filter in the candle assembly allowed hot particles from the igniter candle to enter the oxygen rich environment of the PBE hood, which could cause a fire. All ignitor candles that were examined after fire events showed a breach in the filter. Due to the complexities involved with the chemical reaction within the candle, a definitive cause for the breached filters has not been identified. B/E Aerospace PBE, P/N 119003–21, contains a stainless steel mesh in the outlet path of the igniter candle. It has been established that the installation of the stainless steel mesh will prevent hot particles from entering the PBE hood as a result of a breached filter. Also, it was initially believed that the fire events occurred only with PBEs that had compromised vacuum sealed pouches. Two recent events occurred with PBEs that were reported by the operators to be in serviceable conditions, although the FAA and PBE manufacturer could not verify the condition of the pouch or PBE before the event. Therefore, we can no longer conclude that a PBE, P/N 119003–11, with an intact vacuum seal will prevent the possibility of spark and fire.
This condition, if not corrected, could result in the PBE catching fire.
We gave the public the opportunity to comment on the NPRM (80 FR 34330, June 16, 2015). The following presents the comments received on the NPRM (80 FR 34330, June 16, 2015) and the FAA's response to each comment.
B/E Aerospace, Inc. requested that the labor cost stated for doing the inspection be changed from .5 work-hour to .1 work-hour.
The commenter stated that the manpower specified in the related service bulletin for doing the inspection is 1 minute for 1 person. By comparison, the labor cost stated in the NPRM is .5 work-hour. The commenter believes that 0.5 work-hour is unreasonably long based on experience with the PBE. The commenter also stated that as a consequence, this aspect of the NPRM incorrectly suggests a substantial burden on the industry given the number of PBE units requiring the inspection.
The commenter requested that the labor cost for doing the inspection be changed to be consistent with the related service information.
We partially agree with the commenter. Even though we agree that it may take less than .5 work-hour to inspect the PBE, it is FAA practice to present labor cost in .5 work-hour increments. We have not changed this proposed AD based on this comment.
Airbus stated that the Applicability section should also include PBE, P/N 119003–21, all FAA-approved PBEs.
The commenter stated that the candle in PBE, P/N 119003–21, is identical to the one in PBE, P/N 119003–11, and the abnormal behavior of the candle is also possible on the PBE, P/N 119003–21. The remaining effects of a candle malfunction from a PBE, P/N 119003–21, are still not sufficiently known,
The commenter requested that the inspections also apply to PBE, P/N 119003–21, and all other FAA-approved PBEs as well.
We do not agree with the commenter. Our investigation revealed that the cause of the unsafe condition has been limited to PBE, P/N 119003–11. The manufacturer has tested PBE, P/N 119003–21, with candle assemblies that had a breach in the filter. The PBE, P/N 119003–21, has been shown to stop hot particles from entering the hood and causing a fire. Due to additional testing and investigation, this proposed AD now requires replacing the PBE, P/N 119003–11, with a PBE, P/N 119003–21, or other FAA-approved PBE. We are still allowing inspecting the PBE, P/N 119003–11, until the required replacement time.
We have not changed this proposed AD based on this comment.
United Airlines requested incorporating existing MEL procedures into the AD.
The commenter stated that the proposed AD requires replacing a PBE that has a compromised vacuum seal before further flight. The commenter requested a revision to the AD to allow airplane operation with a minimum equipment list (MEL).
We agree with the commenter. An MEL is intended to permit operation with inoperative instruments or equipment for a period of time until repairs can be done. Repairs must be done at the earliest opportunity. To maintain an acceptable level of safety and reliability, the MEL establishes limitations on the duration of and conditions for operation with inoperative equipment.
We have changed this proposed AD based on this comment.
We reviewed B/E Aerospace Service Bulletin No. 119003–35–011, Rev. 000, dated February 4, 2015, and Service Bulletin 119003–35–009, Rev. 009, dated November 9, 2015. The B/E Aerospace Service Bulletin No. 119003–35–011, Rev. 000, dated February 4, 2015, describes procedures for inspecting PBE, P/N 119003–11, to determine if the vacuum seal of the pouch containing the PBE is compromised. B/E Aerospace Service Bulletin 119003–35–009, Rev. 009, dated November 9, 2015, describes procedures for replacing PBE, P/N 119003–11, with P/N 119003–21. This service information is reasonably available because the interested parties have access to it through their normal course of business or by the means identified in the
We are proposing this SNPRM because we evaluated all the relevant information and determined the unsafe condition described previously is likely to exist or develop in other products of the same type design. Certain changes described above expand the scope of the NPRM (80 FR 34330, June 16, 2015). As a result, we have determined that it is necessary to reopen the comment period to provide additional opportunity for the public to comment on this SNPRM.
This SNPRM would require accomplishing the actions specified in the service information described
B/E Aerospace Service Bulletin No. 119003–35–011, Rev. 000, dated February 4, 2015, applies to all PBE with P/N 119003–11 and P/N 119003–21. We have determined that this proposed AD would apply only to a PBE with P/N 119003–11 with regard to the inspection requirement of paragraph (g) of this proposed AD. B/E Aerospace Service Bulletin 119003–35–009, Rev. 009, dated November 9, 2015, includes instructions for disposal. In this proposed AD, we are requiring only the replacement action.
We estimate that this proposed AD affects 9,000 products installed on airplanes of U.S. registry.
We estimate the following costs to comply with this proposed AD:
Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. “Subtitle VII: Aviation Programs” describes in more detail the scope of the Agency's authority.
We are issuing this rulemaking under the authority described in Subtitle VII, Part A, Subpart III, section 44701: “General requirements.” Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.
We determined that this proposed AD would not have federalism implications under Executive Order 13132. This proposed AD would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government.
For the reasons discussed above, I certify this proposed regulation:
(1) Is not a “significant regulatory action” under Executive Order 12866,
(2) Is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979),
(3) Will not affect intrastate aviation in Alaska, and
(4) Will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
Air transportation, Aircraft, Aviation safety, Incorporation by reference, Safety.
Accordingly, under the authority delegated to me by the Administrator, the FAA proposes to amend 14 CFR part 39 as follows:
49 U.S.C. 106(g), 40113, 44701.
We must receive comments by February 29, 2016.
None.
This AD applies to B/E Aerospace Protective Breathing Equipment (PBE), part number (P/N) 119003–11, that is installed on airplanes.
Joint Aircraft System Component (JASC)/Air Transport Association (ATA) of America Code 35; Oxygen.
This AD was prompted by a report of a PBE, P/N 119003–11, catching fire upon activation by a crewmember. We are issuing this AD to correct the unsafe condition on these products.
Comply with this AD within the compliance times specified, unless already done.
Within 3 months after the effective date of this AD, while still in the stowage box, physically inspect the PBE pouch to determine if it has an intact vacuum seal. Do this inspection following paragraph III.A.1. of the Accomplishment Instructions in B/E Aerospace Service Bulletin No. 119003–35–011. Rev. 000, dated February 4, 2015.
(1)
(2)
(1) The Manager, Wichita Aircraft Certification Office (ACO), FAA, has the authority to approve AMOCs for this AD, if requested using the procedures found in 14 CFR 39.19. In accordance with 14 CFR 39.19, send your request to your principal inspector or local Flight Standards District Office, as appropriate. If sending information directly
(2) Before using any approved AMOC, notify your appropriate principal inspector, or lacking a principal inspector, the manager of the local flight standards district office/certificate holding district office.
(1) For more information about this AD, contact David Enns, Aerospace Engineer, Wichita ACO, FAA, 1801 S. Airport Road, Room 100, Wichita, Kansas 67209; phone: (316) 946–4147; fax: (316) 946–4107; email:
(2) For service information identified in this AD, contact B/E Aerospace, Inc., 10800 Pflumm Road, Commercial Aircraft Products Group, Lenexa, Kansas 66215; telephone: (913) 338–9800; fax: (913) 338–8419; Internet:
Federal Aviation Administration (FAA), Department of Transportation (DOT).
Notice of proposed rulemaking (NPRM).
We propose to adopt a new airworthiness directive (AD) for SOCATA Models MS 880B, MS 885, MS 892A–150, MS 892E–150, MS 893A, MS 893E, MS 894A, MS 894E, Rallye 100S, Rallye 150ST, Rallye 150T, Rallye 235E, and Rallye 235C airplanes that would supersede AD 92–06–10. This proposed AD results from mandatory continuing airworthiness information (MCAI) originated by an aviation authority of another country to identify and correct an unsafe condition on an aviation product. The MCAI describes the unsafe condition as fatigue failure of the nose landing gear wheel axle. We are issuing this proposed AD to require actions to address the unsafe condition on these products.
We must receive comments on this proposed AD by February 29, 2016.
You may send comments by any of the following methods:
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For service information identified in this proposed AD, contact SOCATA, Direction des services, 65921 Tarbes Cedex 9, France; phone: +33 (0) 5 62 41 73 00; fax: +33 (0) 5 62 41 76 54; email:
Albert Mercado, Aerospace Engineer, FAA, Small Airplane Directorate, 901 Locust, Room 301, Kansas City, Missouri 64106; telephone: (816) 329–4119; fax: (816) 329–4090; email:
We invite you to send any written relevant data, views, or arguments about this proposed AD. Send your comments to an address listed under the
We will post all comments we receive, without change, to
On February 25, 1992, we issued AD 92–06–10, Amendment 39–8190 (57 FR 8063; March 6, 1992) (“92–06–10”). That AD required actions intended to address an unsafe condition on SOCATA Models MS 880B, MS 885, MS 894A, MS 893A, MS 892A–150, MS 892E–150, MS 893E, MS 894E, Rallye 100S, Rallye 150T, Rallye 150ST, Rallye 235E, and Rallye 235C airplanes and was based on mandatory continuing airworthiness information (MCAI) originated by an aviation authority of another country.
Since we issued AD 92–06–10, new findings led to an adjustment of the inspection intervals.
The European Aviation Safety Agency (EASA), which is the Technical Agent for the Member States of the European Community, has issued EASA AD 2015–0203, dated October 7, 2015 (referred to after this as “the MCAI”), to correct an unsafe condition for the specified products. The MCAI states:
A nose landing gear (NLG) wheel axle rupture occurred in service. The results of the technical investigation revealed that this failure was due to premature wear.
This condition, if not detected and corrected, could lead to cracks in the axle and detachment of axle and wheel, possibly resulting in failure of the NLG with consequent damage to the aeroplane and injury to occupants.
To address this potential unsafe condition, DGAC France issued AD 91–163(A) (later revised twice) to require repetitive detailed inspections (DET) of the NLG wheel axle and replacement of the NLG wheel axle attachment screws in accordance with the instructions of SOCATA Service Bulletin (SB) 150–32.
Since DGAC France AD 91–163(A)R2 was issued, new findings led to an adjustment of the inspection interval. Consequently, SOCATA issued SB 150–32, now at Revision 3.
For the reasons described above, this new AD retains the requirements of the DGAC France AD 91–163(A)R2, which is superseded, but requires these actions to be accomplished within reduced intervals.
SOCATA has issued Daher-Socata Mandatory Service Bulletin SB 150–32, Revision 3, dated September 2015. The service bulletin describes procedures for inspection of the nose gear wheel axle. This service information is reasonably available because the interested parties
This product has been approved by the aviation authority of another country, and is approved for operation in the United States. Pursuant to our bilateral agreement with this State of Design Authority, they have notified us of the unsafe condition described in the MCAI and service information referenced above. We are proposing this AD because we evaluated all information and determined the unsafe condition exists and is likely to exist or develop on other products of the same type design.
We estimate that this proposed AD will affect 77 products of U.S. registry. We also estimate that it would take about 10 work-hours per product to comply with the basic requirements of this proposed AD. The average labor rate is $85 per work-hour. Required parts would cost about $500 per product.
Based on these figures, we estimate the cost of the proposed AD on U.S. operators to be $103,950, or $1,350 per product.
In addition, we estimate that any necessary follow-on actions would take about 3 work-hours and require parts costing $1,450, for a cost of $1,705 per product. We have no way of determining the number of products that may need these actions.
Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. “Subtitle VII: Aviation Programs,” describes in more detail the scope of the Agency's authority.
We are issuing this rulemaking under the authority described in “Subtitle VII, Part A, Subpart III, Section 44701: General requirements.” Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.
We determined that this proposed AD would not have federalism implications under Executive Order 13132. This proposed AD would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government.
For the reasons discussed above, I certify this proposed regulation:
(1) Is not a “significant regulatory action” under Executive Order 12866,
(2) Is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979),
(3) Will not affect intrastate aviation in Alaska, and
(4) Will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
Air transportation, Aircraft, Aviation safety, Incorporation by reference, Safety.
Accordingly, under the authority delegated to me by the Administrator, the FAA proposes to amend 14 CFR part 39 as follows:
49 U.S.C. 106(g), 40113, 44701.
We must receive comments by February 29, 2016.
This AD supersedes AD 92–06–10 Amendment 39–8190 (57 FR 8063; March 6, 1992) (“AD 92–06–10”).
This AD applies to SOCATA Models MS 880B, MS 885, MS 892A–150, MS 892E–150, MS 893A, MS 893E, MS 894A, MS 894E, Rallye 100S, Rallye 150ST, Rallye 150T, Rallye 235E, and Rallye 235C airplanes, all serial numbers, certificated in any category.
Air Transport Association of America (ATA) Code 32: Landing Gear.
This AD was prompted by mandatory continuing airworthiness information (MCAI) originated by an aviation authority of another country to identify and correct an unsafe condition on an aviation product. The MCAI describes the unsafe condition as fatigue failure of the nose landing gear wheel axle. We are issuing this proposed AD to detect and correct chafing and cracking of the nose gear wheel axle, which could lead to failure of the nose landing gear with consequent damage to the airplane and/or occupants.
Unless already done, do the following actions in paragraphs (f)(1) through (f)(5) of this AD, including all subparagraphs.
(1) Do a detailed visual inspection of the intersection between the axle radius and the nose landing gear fork area for chafing at whichever occurs later in paragraph (f)(1)(i) or (f)(1)(ii) of this AD and repetitively thereafter at intervals not to exceed 200 hours time-in-service (TIS) following Daher-Socata Mandatory Service Bulletin SB 150–32, Revision 3, dated September 2015:
(i) Upon accumulating 200 hours TIS since the airplane's first flight or 200 hours TIS since the last inspection required by AD 92–06–10; or
(ii) Within the next 50 hours TIS after the effective date of this AD or within 500 hours TIS since the last inspection required by AD 92–06–10, whichever occurs first.
(2) Do a dye penetrant inspection on the nose wheel axle for cracks, distortion, and nicks or wear at whichever occurs later in paragraph (f)(2)(i) or (f)(2)(ii) of this AD and repetitively thereafter at intervals not to exceed 200 hours time-in-service (TIS) following Daher-Socata Mandatory Service Bulletin SB 150–32, Revision 3, dated September 2015:
(i) Upon accumulating 200 hours TIS since the airplane's first flight or 200 hours TIS since the last inspection required by AD 92–06–10; or
(ii) Within the next 50 hours TIS after the effective date of this AD or within 500 hours TIS since the last inspection required by AD 92–06–10, whichever occurs first.
(3) If any cracks or damage is found in any inspection required by paragraphs (f)(1) or (f)(2) in this AD, contact SOCATA for FAA-approved repair or replacement instructions approved specifically for this AD and, before further flight, implement those instructions. Use the contact information found in paragraph (i) of this AD to contact SOCATA.
(4) Replace the nose landing gear wheel axle attachment screws with new screws at whichever occurs later in paragraph (f)(4)(i) or (f)(4)(ii) of this AD following Daher-Socata Mandatory Service Bulletin SB 150–32, Revision 3, dated September 2015:
(i) Upon accumulating 2,000 hours TIS since airplane's first flight or 2,000 hours TIS since last nose landing gear wheel attachment screw replacement with new screws; or
(ii) Within 50 hours TIS since April 17, 1992 (the effective date retained from AD 92–06–10).
(5) After the effective date of this AD, a used nose landing gear or a used nose landing gear wheel axle may be installed provided it has been inspected and found free of cracks and/or damage and the nose landing gear wheel axle attachment screws have been replaced with new screws as specified in paragraphs (f)(1), (f)(2), and (f)(4) of this AD.
This AD allows credit for the inspections required in paragraph (f)(1) and (f)(2) of this AD, if done before the effective date of this AD, following Daher-Socata Mandatory Service Bulletin SB 150–32, Revision 2, dated January 1994.
The following provisions also apply to this AD:
(1) Alternative Methods of Compliance (AMOCs): The Manager, Standards Office, FAA, has the authority to approve AMOCs for this AD, if requested using the procedures found in 14 CFR 39.19. Send information to ATTN: Albert Mercado, Aerospace Engineer, FAA, Small Airplane Directorate, 901 Locust, Room 301, Kansas City, Missouri 64106; telephone: (816) 329–4119; fax: (816) 329–4090; email:
(2) Airworthy Product: For any requirement in this AD to obtain corrective actions from a manufacturer or other source, use these actions if they are FAA-approved. Corrective actions are considered FAA-approved if they are approved by the State of Design Authority (or their delegated agent). You are required to assure the product is airworthy before it is returned to service.
Refer to MCAI European Aviation Safety Agency (EASA) AD 2015–0203, dated October 7, 2015; and Daher-Socata Mandatory Service Bulletin SB 150–32, Revision 2, dated January 1994, for related information. You may examine the MCAI on the Internet at
Environmental Protection Agency (EPA).
Proposed rule.
The Environmental Protection Agency (EPA) is proposing a partial approval and partial disapproval of revisions to the Sacramento Metropolitan (Metro) Air Quality Management District (SMAQMD or District) portion of the California State Implementation Plan (SIP). These revisions concern the District's demonstration regarding Reasonably Available Control Technology (RACT) requirements for the 1997 8-hour ozone National Ambient Air Quality Standard (NAAQS). We are proposing action on a local SIP revision under the Clean Air Act (CAA or the Act). We are taking comments on this proposal and plan to follow with a final action.
Any comments must arrive by February 16, 2016.
Submit your comments, identified by Docket ID No. EPA–R09–OAR–2012–959 at
Stanley Tong, EPA Region IX, (415) 947–4122,
Throughout this document, “we,” “us” and “our” refer to the EPA.
Table 1 lists the documents addressed by this proposal with the dates that they were adopted by the local air agency and submitted to the EPA by the California Air Resources Board (CARB).
The 2006 RACT SIP and Updated RACT SIP became complete by operation of law under CAA section 110(k)(1)(B) on January 11, 2008 and July 21, 2009, respectively.
There are no previous versions of these documents in the SMAQMD portion of the California SIP.
Volatile organic compounds (VOCs) and nitrogen oxides (NO
Section IV.G. of the preamble to the EPA's final rule to implement the 1997 8-hour ozone NAAQS (70 FR 71612, November 29, 2005) discusses RACT requirements. It states in part that where a RACT SIP is required, States implementing the 8-hour standard generally must assure that RACT is met either through a certification that previously required RACT controls represent RACT for 8-hour implementation purposes or through a new RACT determination. The submitted documents provide SMAQMD's analyses of its compliance with the CAA section 182 RACT requirements for the 1997 8-hour ozone NAAQS. The EPA's technical support documents (TSDs)(“2006 RACT SIP TSD” and “RACT SIP Update TSD”) have more information about the District's submissions and the EPA's evaluations thereof.
SIP rules must be enforceable (see CAA section 110(a)(2)), must not interfere with applicable requirements concerning attainment and reasonable further progress or other CAA requirements (see CAA section 110(l)), and must not modify certain SIP control requirements in nonattainment areas without ensuring equivalent or greater emissions reductions (see CAA section 193). Generally, SIP rules must require RACT for each category of sources covered by a CTG document as well as each major source of NO
Guidance and policy documents that we use to evaluate enforceability and CAA section 182 RACT SIPs include the following:
1. “Final Rule to Implement the 8-Hour Ozone National Ambient Air Quality Standard—Phase 2” (70 FR 71612; November 29, 2005).
2. “State Implementation Plans, General Preamble for the Implementation of Title I of the Clean Air Act Amendments of 1990” (57 FR 13498; April 16, 1992).
3. Issues Relating to VOC Regulation Cutpoints, Deficiencies, and Deviations: Clarification to Appendix D of November 24, 1987
4. Guidance Document for Correcting Common VOC and Other Rule Deficiencies, August 21, 2001, U.S. EPA Region IX (the “Little Bluebook”).
5. “State Implementation Plans; Nitrogen Oxides Supplement to the General Preamble for the Implementation of Title I of the Clean Air Act Amendments of 1990” (57 FR 55620, November 25, 1992) (“the NO
6. RACT SIPs, Letter dated March 9, 2006 from EPA Region IX (Andrew Steckel) to CARB (Kurt Karperos) describing Region IX's understanding of what constitutes a minimally acceptable RACT SIP.
7. Memorandum from William T. Harnett to Regional Air Division Directors, (May 18, 2006), “RACT Qs & As—Reasonably Available Control Technology (RACT) Questions and Answers”.
8. RACT SIPs, Letter dated April 4, 2006 from EPA Region IX (Andrew Steckel) to CARB (Kurt Karperos) listing EPA's current CTGs, ACTs, and other documents which may help to establish RACT.
With respect to major stationary sources, because the Sacramento Metro nonattainment area was classified as “serious” nonattainment for the 1997 8-hour ozone NAAQS at the time that California submitted the 2006 RACT SIP to the EPA, the EPA evaluated this submission in accordance with the 50 ton per year (tpy) threshold for “major stationary sources” of VOC or NO
The 2006 RACT SIP and Updated RACT SIP provide the District's
First, with respect to CTG source categories, Table 1 of the 2006 RACT SIP Staff Report and Table 1 of the Updated RACT SIP Staff Report lists all CTG source categories and match those CTG categories with corresponding District rules which implement RACT. SMAQMD also searched its database of permitted sources and telephone directories for potential sources belonging to those CTG categories for which the District did not have rules. Based on these evaluations, the District concluded that there were no CTG source categories for which the District had sources but no applicable RACT requirement.
Where there are no existing sources covered by a particular CTG document, states may, in lieu of adopting RACT requirements for those sources, adopt negative declarations certifying that there are no such sources in the relevant nonattainment area. Table 2 below lists all of the source categories for which SMAQMD's 2006 RACT SIP and Updated RACT SIP provide negative declarations.
Subsequent to submitting its 2006 RACT SIP and Updated RACT SIP, SMAQMD submitted, and the EPA approved, negative declarations for the following CTG source categories: Coating Operations at Aerospace Manufacturing and Rework Operations (77 FR 23130, April 18, 2012), Fiberglass Boat Manufacturing Materials (77 FR 63743, October 17, 2012), and Automobile and Light-Duty Truck Assembly Coatings (77 FR 63743, October 17, 2012).
With the exception of the Pharmaceuticals Manufacturing CTG and the municipal landfill category, we are proposing to find that SMAQMD's 2006 RACT SIP and Updated RACT SIP, including the above negative declarations, largely demonstrate that the applicable SIP rules for the CTG source categories operating within the Sacramento Metro area satisfy RACT for the 1997 8-hour ozone NAAQS. We will discuss the deficiencies with Rule 455, Pharmaceuticals Manufacturing and the municipal landfill category, in the next section.
Our 2006 RACT SIP TSD provides a more detailed discussion of the EPA's rationale, including an overview of the District's analyses which were made available for public comment during the District's rulemaking process, together with recommendations for rule improvements.
Second, with respect to certain non-CTG source categories located at facilities that are major stationary sources of VOC or NO
Our 2006 RACT SIP TSD provides a more detailed discussion of the EPA's rationale for these proposals, including an overview of the District's analyses which were made available for public comment during the District's rulemaking process.
Finally, with respect to all other major stationary sources of VOC or NO
Rule 455, Pharmaceuticals Manufacturing, (amended 11/29/83 and 9/5/96) lacks test methods, recordkeeping, and monitoring requirements which are necessary to support enforcement of the rule. See CAA section 110(a). These are deficiencies listed in the EPA's “Blue Book” (Issues Relating to VOC Regulation Cutpoints, Deficiencies, and Deviations, May 25, 1988, revised January 11, 1990) and should be corrected.
The Kiefer landfill is a major source of VOCs located within the Sacramento Metro area. SMAQMD Rule 485, Municipal Landfill Gas, exempts landfills covered under the NSPS, 40 CFR part 60 Subpart WWW, including Kiefer Landfill. Although the District has been delegated authority to implement and enforce the NSPS, as well as the relevant NESHAP (40 CFR part 63 Subpart AAAA), those requirements have not been incorporated into the SIP. The District should amend the rule or submit relevant portions of the facility's permit for SIP approval.
Our TSDs for the 2006 RACT SIP and Updated RACT SIP provide additional recommendations for future rule improvements.
For the reasons discussed above and explained more fully in our 2006 RACT SIP TSD and Updated RACT SIP TSD, the EPA proposes to partially approve and partially disapprove SMAQMD's 2006 RACT SIP and Updated RACT SIP. Under CAA section 110(k)(3), we propose to approve the 2006 RACT SIP and Updated RACT SIP, with the exception of Rule 455, Pharmaceutical Manufacturing and the municipal waste landfill category, as satisfying the RACT requirements of CAA section 182(b)(2) and (f).
Also under CAA section 110(k)(3), we propose to disapprove those elements of the 2006 RACT SIP and Updated RACT SIP that pertain to Rule 455 and the municipal waste landfill category, which the EPA has determined do not meet all of the applicable CAA requirements. We will not finalize this partial disapproval, however, if we fully approve revisions to Rule 455 and the municipal waste landfill category as satisfying RACT before finalizing action on the 2006 RACT SIP and Updated RACT SIP.
The EPA is committed to working with CARB and the District to resolve the Rule 455 and municipal waste landfill RACT deficiencies identified in this proposed action.
If finalized, this partial disapproval would trigger the 2-year clock for the federal implementation plan (FIP) requirement under section 110(c).
In addition, final disapproval would trigger sanctions under CAA section 179 and 40 CFR 52.31 unless the EPA approves subsequent SIP revisions that correct the RACT SIP deficiencies within 18 months of the effective date of the final action.
We will accept comments from the public on the proposed partial approval and partial disapproval for the next 30 days.
Additional information about these statutes and Executive Orders can be found at
This action is not a significant regulatory action and was therefore not submitted to the Office of Management and Budget (OMB) for review.
This action does not impose an information collection burden under the PRA because this action does not impose additional requirements beyond those imposed by state law.
I certify that this action will not have a significant economic impact on a substantial number of small entities under the RFA. This action will not impose any requirements on small entities beyond those imposed by state law.
This action does not contain any unfunded mandate as described in UMRA, 2 U.S.C. 1531–1538, and does not significantly or uniquely affect small governments. This action does not impose additional requirements beyond those imposed by state law. Accordingly, no additional costs to State, local, or tribal governments, or to the private sector, will result from this action.
This action does not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government.
This action does not have tribal implications, as specified in Executive Order 13175, because the SIP is not approved to apply on any Indian reservation land or in any other area where the EPA or an Indian tribe has demonstrated that a tribe has jurisdiction, and will not impose substantial direct costs on tribal governments or preempt tribal law. Thus, Executive Order 13175 does not apply to this action.
The EPA interprets Executive Order 13045 as applying only to those regulatory actions that concern environmental health or safety risks that the EPA has reason to believe may disproportionately affect children, per the definition of “covered regulatory action” in section 2–202 of the Executive Order. This action is not subject to Executive Order 13045 because it does not impose additional requirements beyond those imposed by state law.
This action is not subject to Executive Order 13211, because it is not a significant regulatory action under Executive Order 12866.
Section 12(d) of the NTTAA directs the EPA to use voluntary consensus standards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. The EPA believes that this action is not subject to the requirements of section 12(d) of the NTTAA because application of those requirements would be inconsistent with the CAA.
The EPA lacks the discretionary authority to address environmental justice in this rulemaking.
Environmental protection, Air pollution control, Incorporation by reference, Intergovernmental relations, Nitrogen dioxide, Ozone, Reporting and recordkeeping requirements, Volatile organic compounds.
42 U.S.C. 7401
Environmental Protection Agency (EPA).
Proposed rule.
The Environmental Protection Agency (EPA) is proposing to approve a state implementation plan (SIP) revision submitted by the State of California to provide for attainment of the 1-hour ozone national ambient air quality standard in the San Joaquin Valley, California ozone nonattainment area and to meet other Clean Air Act requirements. Specifically, with respect to the 1-hour ozone standard, the EPA is proposing to find the emissions inventories to be acceptable and to approve the reasonably available control measures demonstration, the rate of progress demonstrations, the attainment demonstration, contingency measures for failure to meet rate of progress milestones, the provisions for advanced technology/clean fuels for boilers, and the demonstration that the plan provides sufficient transportation control strategies and measures to offset emissions increases due to increases in motor vehicle activity. For the 1997 8-hour ozone standard, the EPA is proposing to approve the demonstration that the plan provides sufficient transportation control strategies and measures to offset emissions increases due to increases in motor vehicle activity.
Any comments must arrive by February 16, 2016.
Submit your comments, identified by Docket ID Number EPA–R09–OAR–2015–0048, by one of the following methods:
1.
2.
3.
John Ungvarsky, Air Planning Office (AIR–2), U.S. Environmental Protection Agency, Region 9, (415) 972–3963,
Throughout this document, “we,” “us” and “our” refer to the EPA.
Ground-level ozone is formed when oxides of nitrogen (NO
Under section 109 of the Clean Air Act (CAA), the EPA promulgates national ambient air quality standards (NAAQS or standards) for pervasive air pollutants, such as ozone. In 1979, the EPA established the NAAQS for ozone at 0.12 parts per million (ppm) averaged over a 1-hour period (“1-hour ozone standard”). 44 FR 8202 (February 8, 1979). An area is considered to have attained the 1-hour ozone standard if there are no violations of the standard, as determined in accordance with the regulation codified at 40 CFR 50.9, based on three consecutive calendar years of complete, quality assured and certified monitoring data. A violation occurs when the ambient ozone air quality monitoring data show greater than one (1.0) “expected number” of exceedances per year at any site in the area, when averaged over three consecutive calendar years.
In 1997, the EPA revised the NAAQS for ozone to set the acceptable level of ozone in the ambient air at 0.08 ppm, averaged over an 8-hour period (“1997 8-hour ozone standard”). 62 FR 38856 (July 18, 1997). The EPA determined that the 1997 8-hour standard would be more protective of human health, especially children and adults who are active outdoors, and individuals with a pre-existing respiratory disease, such as asthma. In 2008, the EPA revised and further strengthened the NAAQS for ozone by setting the acceptable level of ozone in the ambient air at 0.075 ppm, averaged over an 8-hour period (“2008 8-hour ozone standard”). 73 FR 16436 (March 27, 2008). In 2015, the EPA further tightened the 8-hour ozone standard to 0.070 ppm. 80 FR 65292 (October 26, 2015). While both the 1979 1-hour ozone standard and the 1997 8-hour ozone standard have been revoked, certain requirements that had applied under the revoked standards continue to apply under the anti-backsliding provisions of CAA section 172(e).
Once the EPA has promulgated a NAAQS, states are required to develop and submit plans that provide for the implementation, maintenance, and enforcement of the NAAQS under CAA section 110(a)(1). The content requirements for such plans, which are referred to as state implementation plans (SIPs) are found in CAA section 110(a)(2). Under the Clean Air Act, as amended in 1977, the EPA designated all areas of the country as “attainment,” “nonattainment,” or “unclassifiable” for the various NAAQS depending upon the availability of ambient concentration data and depending upon whether violations of the NAAQS were occurring in a given area. The CAA further requires states with “nonattainment” areas to submit revisions to their SIPs that provide for, among other things, attainment of the relevant standard within certain prescribed periods.
In California, the California Air Resources Board (CARB) is responsible for adoption and submittal to the EPA of California SIPs and California SIP revisions and is the primary State agency responsible for regulation of mobile sources. Local and regional air pollution control districts are responsible for developing regional air quality plans and for regulation of stationary sources. For the San Joaquin Valley, the San Joaquin Valley Unified Air Pollution Control District (SJVUAPCD or “District”) develops and adopts air quality management plans to address CAA SIP planning requirements applicable to that region. Such plans are then submitted to CARB for adoption and submittal to the EPA as revisions to the California SIP.
Under the 1977 CAA Amendments, the EPA designated the San Joaquin Valley Air Basin (“San Joaquin Valley” or “Valley”) as a “nonattainment” area for the photochemical oxidant (later, the 1-hour ozone) NAAQS. 43 FR 8962, at
The CAA, as amended in 1977, required states to submit SIP revisions for nonattainment areas that, among other requirements, provided for attainment no later than 1987; however, like many areas of the country, the San Joaquin Valley failed to attain the ozone NAAQS by 1987. In the 1990 CAA Amendments, Congress established a classification system for ozone nonattainment areas under which areas with more severe ozone problems were given a higher classification and more time to attain the standard but were subject to a greater number of, and more stringent, SIP requirements. The classifications include “Marginal,” “Moderate,” “Serious,” “Severe,” and “Extreme.” See CAA section 181(a)(1).
Under this classification system, the San Joaquin Valley was classified as a “Serious” ozone nonattainment area for the 1-hour ozone standard with an attainment date of no later than November 15, 1999. 56 FR 56694 (November 6, 1991). In response, in 1994, CARB submitted
In 2001, the EPA found that the San Joaquin Valley had failed to attain the 1-hour ozone standard by the “Serious” area deadline and reclassified the area to “Severe.” 66 FR 56476 (November 8, 2001). In 2004, the EPA granted the State's request to voluntarily reclassify the San Joaquin Valley from “Severe” to “Extreme” for the 1-hour ozone standard and required the state to submit a SIP revision providing for the “Extreme” area SIP elements in CAA section 182(e), which include a demonstration of attainment of the standard as expeditiously as practicable, but no later than November 15, 2010. 69 FR 20550 (April 16, 2004).
In response, CARB and the District developed and adopted the
Specifically, we approved the following elements of the 2004 Ozone Plan: (1) Rate-of-progress (ROP) demonstration as meeting the requirements of CAA section 172(c)(2) and 182(c)(2) and 40 CFR 51.905(a)(1)(i) and 51.900(f)(4); (2) ROP contingency measures as meeting the requirements of CAA section 172(c)(9) and 182(c)(9); (3) the attainment demonstration as meeting the requirements of 182(c)(2)(A) and 181(a) and 40 CFR 51.905(a)(1)(ii); (4) the attainment contingency measures as meeting the requirements of CAA section 172(c)(9); and (5), along with certain measures contained in the 2003 State Strategy, the demonstration of implementation of reasonably available control measures (RACM)(exclusive of RACT)
Our approval of the 2004 Ozone Plan was challenged, and the U.S. Court of Appeals for the Ninth Circuit remanded the approval of the plan back to the EPA based on its conclusion that the EPA had not adequately considered and addressed the implications of more recent emissions data in determining that the 2004 Ozone Plan had met all applicable CAA requirements.
Meanwhile, as noted above, in 1997, the EPA established an 8-hour ozone standard to replace the 1-hour ozone standard, and in 2004, the EPA designated the San Joaquin Valley as a “Serious” nonattainment area for the 1997 8-hour ozone standard. 69 FR 23858, at 23888–23899 (April 30, 2004). In 2010, the EPA approved a request by CARB to reclassify the San Joaquin Valley as “Extreme” for the 1997 8-hour ozone standard. 75 FR 24409 (May 5, 2010). In 2004, the EPA also established regulations governing the transition from the 1-hour ozone standard to the 1997 8-hour ozone standard, and under these regulations, the 1-hour ozone standard was revoked in most areas of the country, including the San Joaquin Valley, effective June 15, 2005, but the SIP revision requirements that applied at the time of revocation of the standard continue to apply after revocation
In 2007, in response to SIP revision requirements for the 1997 8-hour ozone standard, CARB and the District developed and adopted the
As part of the approval of the 2007 Ozone Plan, the EPA approved the demonstration that the plan provides for transportation control strategies (TCS) and TCMs sufficient to offset any growth in emissions from growth in VMT or the number of vehicle trips as meeting the requirements of CAA section 182(d)(1)(A).
However, between the time when the EPA's approval of the 2007 Ozone Plan was signed and when it was published in the
In 2013, in response to the EPA's withdrawal of approval of the 2004 Ozone Plan and the VMT emission offset demonstration for the 1997 8-hour ozone standard and the related finding of failure to submit, CARB and the District prepared, adopted, and submitted the
Lastly, as noted above, the EPA tightened the 8-hour ozone standard in 2008 and tightened the standard further in 2015. The EPA has designated the San Joaquin Valley as an “Extreme” area for the 2008 8-hour ozone standard. 77 FR 30088 (May 21, 2012). The “Extreme” area plan for the San Joaquin Valley for the 2008 ozone standard is due in 2016. In establishing final implementation rules for the 2008 8-hour ozone standard, the EPA revoked the 1997 8-hour ozone standards and includes anti-backsliding requirements that apply upon revocation of the 1997 8-hour ozone standards. 80 FR 12264 (March 6, 2015). Consistent with the application of anti-backsliding provisions upon revocation of the 1-hour ozone standards, areas that remain designated as nonattainment for the 1997 8-hour ozone standard at the time of revocation of the 1997 8-hour ozone standard continue to be subject to certain SIP requirements that had
The District adopted the 2013 Ozone Plan on September 19, 2013, and CARB approved the plan as a revision to the California SIP on November 21, 2013.
Appendix D of the 2013 Ozone Plan contains the VMT emissions offset demonstrations for the 1-hour ozone and 1997 8-hour ozone NAAQS. On June 19, 2014, CARB submitted a technical supplement to the VMT emissions offset demonstrations submitted as part of the 2013 Ozone Plan.
CAA sections 110(a)(1) and (2) and 110(l) require a state to provide reasonable public notice and opportunity for public hearing prior to the adoption and submittal of a SIP or SIP revision. To meet this requirement, every SIP submittal should include evidence that adequate public notice was given and an opportunity for a public hearing was provided consistent with the EPA's implementing regulations in 40 CFR 51.102.
Both the District and CARB have satisfied applicable statutory and regulatory requirements for reasonable public notice and hearing prior to adoption and submittal of the 2013 Ozone Plan. The District conducted a public workshop on April 16, 2013. On August 20, 2013, the District posted on its Web site an announcement and supporting documents for a September 19, 2013 public hearing and also sent out an email to
CARB also provided the required public notice and opportunity for public comment prior to its November 21, 2013 public hearing and approval of the 2013 Ozone Plan as a revision to the California SIP. See CARB “Notice of Public Meeting” dated October 21, 2013, and CARB Resolution No. 13–45. As noted previously, on December 20, 2013, CARB submitted the 2013 Ozone Plan and related public process documentation to the EPA. The EPA determined that CARB's December 20, 2013 SIP revision submittal was complete on May 19, 2014.
Based on information in the December 20, 2013 SIP submittal and subsequent email communication with District staff, the EPA has determined that all hearings were properly noticed. We find, therefore, that the submittal of the 2013 Ozone Plan meets the procedural requirements for public notice and hearing in CAA sections 110(a) and 110(l).
We have evaluated the emissions inventories in the 2013 Ozone Plan to determine if they are consistent with EPA guidance (General Preamble at 13502) and adequate to support that plan's RACM, ROP and attainment demonstrations. Appendix B of the 2013 Ozone Plan presents the base year and projected emission inventories relied on for the ROP and attainment demonstrations. Appendix B also discusses the methodology used to determine base year (2007) emissions and identifies the growth and control factors used to project emissions for the 2013 and 2016 (ROP milestone years) and 2017 (ROP increment and attainment) projected year inventories. The plan includes summer (May through October) average daily inventories for the base year of 2007 and projected inventories for years 2013 through 2022 for all major source categories (stationary sources, area sources, and on-road and nonroad mobile sources). Emissions are calculated for the two major ozone precursors—NO
The emissions inventories in the 2013 Ozone Plan were developed using data provided by CARB, the California Department of Transportation, and the San Joaquin Valley's eight metropolitan planning organizations (MPO).
CARB also conducts periodic evaluations and updates of the growth profiles to ensure that emission forecasts are based on data that reflect historical trends, current conditions, and recent forecasts. CARB staff conducted a category-by-category review and update of the growth profile data for source categories that, in aggregate, comprise more than 95 percent of the NO
Motor vehicle emissions were based on estimates of VMT provided by the regional transportation planning agencies and the California Department of Transportation. The plan uses CARB's Emission FACtor (EMFAC) model, version EMFAC2011, to calculate the emission factors for cars, trucks and buses. At the time that the 2013 Ozone Plan was developed, EMFAC2011 was the mobile source model approved for use in California SIPs.
Table 1 provides a summary of the emissions estimates prepared for the 2013 Ozone Plan for the base year (2007) and ROP and attainment years 2013, 2016, and 2017.
We have determined that the 2007 base year emission inventory in the 2013 Ozone Plan is comprehensive, accurate, and current and that this inventory as well as the 2013, 2016, and 2017 projected inventories have been prepared consistent with EPA guidance. Accordingly, we propose to find that these inventories provide an appropriate basis for the various other elements of the 2013 Ozone Plan, including RACM, and the ROP and attainment demonstrations.
CAA section 172(c)(1) requires nonattainment area plans to provide for the implementation of all RACM. The RACM demonstration requirement is a continuing applicable requirement for the San Joaquin Valley “Extreme” 1-hour ozone nonattainment area under EPA's anti-backsliding rules that apply once a standard has been revoked. See 40 CFR 51.1105(a)(1) and 51.1100(o)(17).
The EPA has previously provided guidance interpreting the RACM requirement in the General Preamble at 13560 and a memorandum entitled “Guidance on the Reasonably Available Control Measure Requirement and Attainment Demonstration Submissions for Ozone Nonattainment Areas,” John Seitz, Director, OAQPS to Regional Air Directors, November 30, 1999 (Seitz memo). In summary, EPA guidance provides that states, in addressing the RACM requirement, should consider all potential measures for source categories in the nonattainment area to determine whether they are reasonably available for implementation in that area and whether they would advance the area's attainment date by one or more years.
The District's RACM demonstration and control strategy for the 1-hour ozone standard in the 2013 Ozone Plan relies on control measures that have been adopted by CARB and the District under previous attainment plans. In the more recent years prior to the adoption of the 2013 Ozone Plan, CARB and the District have developed and implemented comprehensive plans for the 1997 8-hour ozone standards, 1997 PM
The District's RACM analysis builds on previously adopted measures. Table 3–1 (p. 3–3) in the 2013 Ozone Plan lists currently adopted District rules that are contributing towards attainment of the 1-hour ozone standard. The 2013 Ozone Plan's RACM evaluation for NO
The following information is provided in appendix C of the 2013 Ozone Plan for each stationary or area source category or District rule:
• A description of the sources within the category or sources subject to the rule;
• Base year (2007) and projected baseline year emissions (for every year from 2013 to 2022) in the source category or affected by the rule;
• A discussion of the current rule requirements and/or listing and discussion of existing rules, regulations, or other control efforts that address the source category; and
• Identification and discussion of potential new controls, including in many cases, a discussion of the technological and economic feasibility of the new controls. Rules adopted by other agencies (including the EPA, South Coast Air Quality Management District (AQMD), and Bay Area AQMD) are discussed and compared to existing SJVUAPCD rules. Measures proposed by the public for the source category/rule are also identified and discussed. In addition, non-regulatory approaches to reducing emissions in each stationary and area source category are discussed, including the use of incentives, opportunities for technology advancement programs, policy initiatives, and education/outreach programs.
Through its RACM evaluation process, the District identified two new control measures for adoption, and through adoption of the 2013 Ozone Plan, the District committed to adopt and submit these measures as a revision to the California SIP (see District Resolution 2013–9–13, page 5), although the District and State do not rely on reductions from these commitments in their attainment demonstration. See 2013 Ozone Plan, section 3.1.3 (p. 3–8).
The District's commitments have been fulfilled in that the anticipated rule amendments have been adopted and the rules have been submitted to the EPA as a revision to the California SIP. The current status of the rules is shown in table 2, and as shown there, the EPA has approved one of the two rules and has proposed approval of the other. We expect to take final action on the second rule prior to final action on the 2013 Ozone Plan.
In light of the comprehensiveness of the District's stationary and area source program, and the stringency of the District's regulations, the 2013 Ozone Plan concludes that RACM is being implemented for sources under the District's jurisdiction. See section 4.2.1 of the 2013 Ozone Plan.
The District also identified a number of source categories for which existing information is inadequate to determine the feasibility of additional controls. These categories and the additional controls to be studied are discussed in section 3.1.4. (p. 3–9). The schedule for these studies is given in table 3–4 (see 2013 Ozone Plan, p. 3–10).
The TSD for today's action includes additional information on each District rule, including its status in terms of federal approval and the net inventory changes between 2007 and 2017.
Given the need for significant emissions reductions in California nonattainment areas, CARB has been a leader in the development and adoption of stringent mobile source control measures nationwide and has unique authority under CAA section 209 (subject to a waiver or authorization by the EPA) to adopt and implement new emissions standards for many categories of on-road vehicles and engines and new and in-use off-road engines. CARB has adopted standards and other requirements related to the control of emissions from numerous types of on-road motor vehicles and new and in-use off-road vehicles, such as passenger cars, trucks, buses, motorcycles, off-road engines (gasoline and diesel-powered), in-use off-road diesel fueled fleets, portable equipment, marine engines, and many others.
Historically, the EPA has allowed California to take into account emissions reductions from CARB regulations for which the EPA has issued waivers or authorizations under
CARB's mobile source program extends beyond regulations that are subject to the waiver or authorization process set forth in CAA section 209 to include standards and other requirements to control emissions from in-use heavy-duty trucks and buses, gasoline and diesel fuel specifications, and many other types of mobile sources. Generally, these regulations have been submitted and approved as revisions to the California SIP. See,
Section 3.1.1.2 of the 2013 Ozone Plan discusses the emissions reductions from CARB's mobile source program and includes a table (table 3–2) that lists all of the regulations adopted or amended by CARB from 2000 through early 2012. While all of the listed measures contribute to some degree to attainment of the 1-hour ozone standard in the San Joaquin Valley, some are called out in particular as providing significant emissions reductions relied upon for attainment of the ozone standard under the 2013 Ozone Plan. These measures include the in-use heavy-duty diesel-powered truck regulation, the in-use off-road equipment regulation, and the advanced clean car program, among others. The 2013 Ozone Plan concludes that, in light of the comprehensiveness and stringency of CARB's mobile source program, all reasonable control measures under CARB's jurisdiction are being implemented.
With respect to TCMs, the 2013 Ozone Plan relies on the documentation found in appendix C of the 2012 PM
The 2013 Ozone Plan concludes that the RACM requirement is met through implementation of the measures described above under the District's jurisdiction, CARB's jurisdiction, and the MPOs' jurisdiction for stationary and area sources, mobile sources, and TCMs, respectively. The plan also concludes that to advance the attainment date by one year (
The process followed by the District in the 2013 Ozone Plan to identify RACM is generally consistent with the EPA's recommendations in the General Preamble. The process included compiling a comprehensive list of potential controls measures for sources of NO
We have reviewed the District's determination in the 2013 Ozone Plan that its stationary and area source control measures represent RACM for NO
With respect to mobile sources, we recognize CARB as a leader in the development and implementation of stringent control measures for on-road and off-road mobile sources. Its current program addresses the full range of mobile sources in the San Joaquin Valley through regulatory programs for both new and in-use vehicles. See 2013 Ozone Plan, table 3–2 and appendix A of the TSD. With respect to transportation controls, we note that the MPOs have a program to fund cost-effective TCMs. See appendix C, p. C–33 of the 2012 PM
Based on our review of the results of these RACM analyses, the District's and CARB's adopted rules, we propose to find that there are, at this time, no additional reasonably available measures that would advance attainment of the 1-hour ozone standard in the San Joaquin Valley. In the 2013 Ozone Plan, the District estimates that it would take a reduction between of 12.1 tpd of NO
For the foregoing reasons, we propose to find that the 2013 Ozone Plan provides for the implementation of all RACM as required by CAA section 172(c)(1) and 40 CFR 51.1105(a)(1) and 51.1100(o)(17).
CAA section 172(c) requires nonattainment area plans to provide for reasonable further progress (RFP) which is defined in section 171(1) as such annual incremental reductions in emissions as are required in part D or may reasonably be required by the Administrator in order to ensure attainment of the relevant ambient standard by the applicable date. CAA sections 182(c)(2) and (e) require that “Serious” and above area SIPs include ROP quantitative milestones that are to be achieved every 3 years after 1996 until attainment. For ozone areas classified as Serious and above, section 182(c)(2) requires that the SIP must provide for reductions in ozone-season, weekday VOC emissions of at least 3 percent per year net of growth averaged over each consecutive 3-year period. This is in addition to the 15 percent reduction over the first 6-year period required by CAA section 182(b)(1) for areas classified as moderate and above. The CAA requires that these milestones be calculated from the 1990 inventory after excluding, among other things, emission reductions from “[a]ny measure related to motor vehicle exhaust or evaporative emissions promulgated by the Administrator by January 1, 1990” and emission reductions from certain federal gasoline volatility requirements. CAA section 182(b)(1)(B)–(D). The EPA has issued guidance on meeting 1-hour ozone ROP requirements. See General Preamble at 13516 and “Guidance on the Post-1996 Rate-of-Progress Plan and the Attainment Demonstration,” EPA–452/R–93–015, EPA Office of Air Quality Planning and Standards, February 18, 1994 (corrected).
CAA section 182(c)(2)(C) allows for NO
The ROP demonstration requirement is a continuing applicable requirement for the San Joaquin Valley “Extreme” 1-hour ozone nonattainment area under the EPA's anti-backsliding rules that apply once a standard has been revoked. See 40 CFR 51.1105(a)(1) and 51.1100(o)(4).
Section 4.3.2 (beginning on page 4–5) of the 2013 Ozone Plan provides a demonstration that the San Joaquin Valley meets the 2010, 2013, and 2016 ROP milestones and 2017 increment.
Based on our review of the ROP calculations in the 2013 Ozone Plan, summarized in table 3 above, we conclude the 2013 Ozone Plan demonstrates that sufficient emission reductions have or will be achieved to meet the 2010, 2013, and 2016 ROP milestones and the 2017 increment. Therefore, we propose to approve the ROP demonstration in the 2013 Ozone Plan as meeting the requirements of CAA section 172(c)(2) and 182(c)(2)(B), and 40 CFR 51.1105(a)(1) and 51.1100(o)(4).
CAA section 182(c)(2)(A) requires states with ozone nonattainment areas classified as “Serious” or above to submit plans that demonstrate attainment of the 1-hour ozone standard by the applicable attainment date. Under the CAA, as amended in 1990, the San Joaquin Valley “Extreme” nonattainment area was to have attained the 1-hour ozone standard by November 15, 2010. In 2011, we determined that the San Joaquin Valley had failed to attain the standard by the 2010 attainment date. 76 FR 82133 (December 30, 2011). Given that the original statutory attainment date had passed and the 1-hour ozone standard had been revoked, in our 2012 final action withdrawing our approval of the 2004 Ozone Plan and issuing findings of failure to submit, we set a new attainment date by reference to CAA section 172(a)(2). 77 FR 70376, at 70377 (November 26, 2012), effective November 26, 2012. Application of the attainment date formulation in section 172(a)(2) means that the state was required to submit a revised San Joaquin Valley plan demonstrating attainment of the 1-hour ozone standard as expeditiously as practicable, but no later than five years from the effective date of the findings of failure to submit, or, in this case, no later than November 26, 2017.
An attainment demonstration should include a control strategy that identifies specific measures to reduce emissions and photochemical modelling results showing that the emissions reductions from implementation of the control strategy is sufficient to attain the standard by the applicable attainment date. The attainment demonstration requirement is a continuing applicable requirement for the San Joaquin Valley “Extreme” 1-hour ozone nonattainment area under the EPA's anti-backsliding rules that apply once a standard has been revoked. See 40 CFR 51.1105(a)(1) and 51.1100(o)(12).
The 2013 Ozone Plan relies entirely on reductions from previously adopted measures. Tables 3–1 and 3–2 in the 2013 Ozone Plan documents District and State measures that contribute to attainment of the 1-hour ozone standard in 2017. Although the 2013 Ozone Plan includes two commitment measures (see table 3–3 in 2013 Ozone Plan), reductions from those measures were not relied on for attainment. Moreover, the two measures have been adopted and submitted to the EPA.
The future year inventories, which include reductions from adopted and creditable measures, were used in the 2013 Ozone Plan's modeling analysis described in appendix E of the 2013 Ozone Plan. Based on the modeling analysis, the District determined that the 1-hour ozone standard could be attained in 2017. A summary of the base year (2007) and 2017 attainment-year emissions inventories is shown in table 1 above. It reflects reductions of 238 tpd of NO
For purposes of evaluating the 2013 Ozone Plan, all of the measures relied on to satisfy the applicable control requirements are baseline measures. As the term is used here, baseline measures are federal, State, and District rules and regulations adopted prior by the end of January 2012 (
The District has adopted more than 50 prohibitory rules that limit emissions of either VOC or NO
The state's baseline measures fall within two categories: Measures for which the State has obtained a waiver or authorization of federal pre-emption under CAA section 209 (“waiver” measures) and those for which the state is not required to obtain a waiver (“non-waiver” measures). Non-waiver measures include: Improvements to California's inspection and maintenance (I/M) program, SmogCheck; cleaner burning gasoline and diesel regulations; and limits on the VOC content and reactivity of consumer products. Table 3–2 of the 2013 Ozone Plan lists many of the state's measures adopted since 2006 that are contributing to attainment of the 1-hour ozone standard.
Over the years, the EPA has approved the non-waiver measures and amendments to those measures as part of the California SIP. Historically, the EPA has allowed California to take credit for waiver measures (to meet CAA SIP requirements including ROP and attainment demonstrations) notwithstanding the fact that the regulations themselves have not been submitted or approved into the California SIP. However, in light of the Ninth Circuit's decision in
The 2013 Ozone Plan also includes reductions from federal measures. These measures include, for example, the EPA's national emission standards for heavy duty diesel trucks,
CAA section 182(c)(2)(A) requires SIPs for ozone nonattainment areas to include a “demonstration that the plan, as revised, will provide for attainment of the ozone [NAAQS] by the applicable attainment date. This attainment demonstration must be based on photochemical grid modeling or any other analytical method determined by the Administrator, in the Administrator's discretion, to be at least as effective.” Air quality modeling is used to establish emissions attainment targets, that is, the combination of emissions of ozone precursors that the area can accommodate without exceeding the relevant standard, and to assess whether the proposed control strategy will result in attainment of that standard. The procedures for modeling ozone as part of an attainment demonstration are contained in the EPA's Guidance on the Use of Models and Other Analyses for Demonstrating Attainment of Air Quality Goals for the 8-Hour Ozone and PM
Older guidance for the 1-hour ozone NAAQS was provided in Guideline for Regulatory Application of the Urban Airshed Model;
CARB performed the air quality modeling for the 2013 Ozone Plan, with assistance from the District. The 2013 Ozone Plan's modeling protocol is contained in appendix E (“Modeling Protocol”). This protocol was reviewed by the EPA, and contains all of the elements recommended in the Guidance, including selection of model, and modeling period, modeling domain, and model boundary conditions and initialization procedures; a thorough discussion of emission inventory development and their spatial and temporal allocation; and other model input preparation procedures, model performance evaluation procedures; selection of days and other details for calculating RRFs; and provisions for the archiving of and access to raw model inputs and outputs. While some additional detail on the input meteorological data could have been useful, overall the protocol adequately addresses all of the expected elements.
The modeling analysis uses the Community Multiscale Air Quality (CMAQ) photochemical model, developed by the EPA. The SAPRC99 (State-wide Air Pollution Research Center, 1999 version) chemical mechanism was used in CMAQ, based on CARB's historical experience with it, its favorable scientific review and good performance over the years. The modeling incorporates routinely available meteorological and air quality data collected during 2007, the base year for the 2013 Ozone Plan. The WRF model (Weather and Research Forecasting model, from the National Center for Atmospheric Research) was used to prepare meteorological input for CMAQ. CMAQ and WRF are both recognized in the Modeling Guidance as technically sound, state-of-the-art models. Air quality modeling was performed for May through September, 2007, a period that spans the ozone season in the San Joaquin Valley. The overall air quality modeling domain includes the entire State of California with 12 km resolution, and a nested domain of finer 4 km resolution that covers the San Joaquin Valley. The overall meteorological modeling covers California's neighboring states, and major portions of the next outer ring of states, with 35 km resolution; it has nested domains at 12 km and 4 km, with the latter, innermost covering the entire State of California. The areal extent, and the horizontal and vertical resolution used in these models were more than adequate for modeling San Joaquin Valley ozone.
Model performance information is provided in appendix F of the 2013 Ozone Plan in the form of time series and scatter plots of modeled ozone compared to monitored ozone, for the May–September, 2007 period. The time series show a good match between predicted and observed concentrations. While there is some underprediction during the second half of the period (mid-July through September), performance is generally good, and the overall peaks were captured by the model. Scatter plots also show good performance, with very few outliers. Modeled values are generally within 20% of observations, and root-mean-square error (RMSE) values are typically near 0.7, showing good correlation between modeled and monitored concentrations. While current Modeling Guidance does not prescribe specific performance goals, the Modeling Protocol adopted goals from the older, 1991 EPA 1-hour ozone modeling guidance, section 5.2: Unpaired highest prediction accuracy: Within 20 percent; Normalized bias within 15 percent; and Gross error of all pairs above 60 parts per billion (ppb) (
The 2013 Ozone Plan used a “band-RRF” approach for the use of modeling results in the modeled attainment test. This a refinement of the approach in the Modeling Guidance, and is described in appendix F (“Modeling Approach and Results,” section 1.4.1) of the 2013 Ozone Plan, as well as in the Modeling Protocol and in a journal paper.
The 2013 Ozone Plan band-RRF approach parallels the Modeling Guidance, but differs in several specifics, especially in the choice of concentration levels to include in calculating the RRF. The 2013 Ozone Plan applied an initial performance screen: Only days that meet the model performance criteria cited above were retained for the calculation. For the choice of grid cell to represent the monitor, the 2013 Ozone Plan used the grid cell containing the monitor itself, rather than the maximum cell within 15 km; this puts a somewhat greater reliance on the spatial accuracy of the model, but is not necessarily less conservative. The 2013 Ozone Plan's choice of concentration days to include is more complex than in the Guidance. Instead of using an average over all high concentration days, in the band-RRF approach there is a different RRF for each 10 ppb-wide (0.010 ppm) band of ozone concentrations; the RRF used for a particular monitored day is computed from future and base year averages only within the concentration band relevant for that day, rather than from all high days.
An additional difference between the 2013 Ozone Plan modeled attainment test and the Modeling Guidance is that it uses only the single 2005–2007 design value as the starting point, whereas for a 2007 base year the Modeling Guidance would recommend the average of the three design values for 2005–2007, 2006–2008, and 2007–2009. It is not clear how to use band-RRF approach in conjunction with this Guidance recommendation, but presumably it would involve using ozone observations from a longer period than 2005 through 2007. Using a longer period might make for more stable design value estimates, less subject to year-to-year meteorological variability; conversely it also introduces some inconsistency given that emissions changes during a longer period would generally be larger. The EPA estimated the effect of using an alternative starting point by applying modeled percent change in design value from the 2013 Ozone Plan to the 2006–2008 design value, and to the three-design value average mentioned above. The results were 120.2 and 119.6 ppb (0.1202 and 0.1196 ppm), respectively, both slightly higher than the 2013 Ozone Plan's 119.3 ppb (0.1193 ppm), but both less than the NAAQS-compliant value of 124 ppb (or 0.124 ppm, which rounds to 0.12 ppm). Documentation on the rationale for the 2013 Ozone Plan choice of the 2005–2007 design value starting point would have strengthened the support for the attainment demonstration, but even in its absence, the EPA finds the procedure followed to be adequate for the San Joaquin Valley 1-hour ozone attainment demonstration.
The final model results appear in chapter 2 of the 2013 Ozone Plan (and are repeated in appendix F, section 1.4.2 “Attainment Demonstration”). These are tables of three-year design values for base year 2007 and for the projected year 2017. The highest monitored 2007 design value was 135 ppb (0.135 ppm) at the Edison monitor. The highest projected 2017 design value, accounting for emission reductions occurring during 2007–2017 was 119.3 ppb (0.1193 ppm) at Edison monitor. This is comfortably below the maximum 124 ppb (0.124 ppm) consistent with NAAQS attainment. The next highest 2017 design value was substantially less, 107.4 ppb (0.1074 ppm) at the Arvin monitor.
The 2013 Ozone Plan contains a “Weight of Evidence” (WOE) section in its appendix G. This section includes analyses of ambient concentration and emission trends, and additional analyses that strengthen the 2013 Ozone Plan's attainment demonstration conclusion that NAAQS attainment will be achieved in 2017. The overall San Joaquin Valley design value trend from 1994 through 2012 is downward, despite some individual multi-year periods of little progress, and corroborates the projection of attainment in 2017 (appendix G, figure 1, page G–2). This pattern is also seen for individual monitoring site design values trends (appendix G, figures 4–6 and 8–10, pages G–6—G–10). An exception to this is the Fresno-Drummond site, for which the 2007–2011 trend is upward, though the number of NAAQS exceedance days remains small (appendix G, figure 6, page G–7). Since VOC and especially NO
The 2013 Ozone Plan includes NO
Finally, the 2013 Ozone Plan provides a supplemental attainment demonstration using a traditional “single RRF” approach, in addition to the “band-RRF” approach (appendix G, sections 6.1 and 6.2, pages G–26—G–33). (As described above, in the former approach, described in the Modeling Guidance for 8-hour ozone, a single RRF is used regardless of the ozone concentration. In the latter approach there is a different RRF for each “band” or range of ozone values.) The single
The various analyses provided in appendix G of the 2013 Ozone Plan provide assurance in the attainment demonstration's conclusion that the 1-hr ozone NAAQS will be attained in 2017.
The modeling showed that existing State and District control measures are sufficient to attain the 1979 1-hour Ozone NAAQS by 2017 at all monitoring sites in the San Joaquin Valley. Given the extensive discussion of modeling procedures, tests, and performance analyses called for in the Modeling Protocol and the good model performance, the EPA finds that the modeling is adequate for purposes of supporting the 1-hour ozone attainment demonstration.
To approve a SIP's attainment demonstration, the EPA must make several findings: First, we must find that the demonstration's technical bases—emissions inventories and air quality modeling—are adequate. As discussed above in section III.A, we propose to find that the inventories in the 2013 Ozone Plan provide an appropriate basis for the various other elements of the 2013 Ozone Plan, including the attainment demonstration, and for the reasons discussed above, we find the air quality modeling adequate to support the attainment demonstration.
Second, we must find that the SIP provides for expeditious attainment through the implementation of all RACM. As discussed above in section III.B, we are proposing to approve the RACM demonstration in the 2013 Ozone Plan.
Third, we must find that the emissions reductions that are relied on for attainment are creditable and are sufficient to provide for attainment. As stated previously in today's action, the EPA is proposing to approve the 2013 Ozone Plan in part based on the permanence and enforceability of the waiver measures flowing from the approval of the measures as part of the SIP. Thus, the EPA will not finalize approval of the 2013 Ozone Plan until the Agency takes final action to approve the waiver measures as part of the California SIP. Once that occurs, the 2013 Ozone Plan will rely entirely on adopted and approved rules to achieve the emissions reductions needed to attain the 1-hour ozone standards in the San Joaquin Valley in 2017.
Section 172(c)(9) and 182(c)(9) of the CAA require that SIPs contain contingency measures that will take effect without further action by the state or the EPA if an area fails to attain the ozone standard by the applicable attainment date (section 172(c)(9)) or fails to meet an ROP milestone (section 182(c)(9)). This requirement is a continuing applicable requirement for the San Joaquin Valley “Extreme” 1-hour ozone nonattainment area under the EPA's anti-backsliding rules that apply once a standard has been revoked. See 40 CFR 51.1105(a)(1) and 51.1100(o)(13).
The Act does not specify how many contingency measures are needed or the magnitude of emission reductions that must be provided by these measures. However, the EPA provided initial guidance interpreting the contingency measure requirements in the General Preamble at 13510. Our interpretation is based upon the language in sections 172(c)(9) and 182(c)(9) in conjunction with the control measure requirements of sections 172(c), 182(b) and 182(c)(2)(B), the reclassification and failure to attain provisions of section 181(b) and other provisions. In the General Preamble, the EPA indicated that states with moderate and above ozone nonattainment areas should include sufficient contingency measures so that, upon implementation of such measures, additional emissions reductions of three percent of the emissions in the adjusted base year inventory (or such lesser percentage what will cure the identified failure) would be achieved in the year following the year in which the failure is identified. These reductions should be beyond what is needed to meet the attainment and/or ROP requirement. States may use reductions of either VOC or NO
In subsequent guidance,
Contingency measure provisions are described in Section 4.4 of the 2013 Ozone Plan. To provide for contingency measures for failure to meet the ROP milestones, the SIP relies on surplus NO
For the failure to attainment contingency measure, the 3 percent reduction from the 2007 baseline can come from either VOC or NO
CAA section 182(e)(3) provides that SIPs must require each new, modified, and existing electric utility and industrial and commercial boiler that emits more than 25 tons per year (tpy) of NO
Further guidance on this requirement is provided in the General Preamble at 13523. According to the General Preamble, a boiler should generally be considered as any combustion equipment used to produce steam and generally does not include a process heater that transfers heat from combustion gases to process streams. General Preamble at 13523. In addition, boilers with rated heat inputs less than 15 million Btu (MMBtu) per hour which are oil or gas fired may generally be considered de minimis and exempt from these requirements since it is unlikely that they will exceed the 25 tpy NO
The 2013 Ozone Plan, which addresses the CAA section 182(e)(3) requirements on page 4–10, states that District Rules 4306 and 4352 address NO
Rule 4306 “Boilers, Steam Generators, and Process Heaters—Phase 3” as revised on October 16, 2008, applies to any gaseous fuel or liquid fuel fired boiler, steam generator, or process heater with a total rated heat input greater than 5 million Btu per hour. The emission limits in the rule (5 ppm to 30 ppm for gaseous fuels and 40 ppm for liquid fuels) cannot be achieved without the use of advanced control technologies. See “Alternative Control Techniques Document—NO
Rule 4352 “Solid Fuel Fired Boilers, Steam Generators And Process Heaters” as revised December 15, 2011, applies to any boiler, steam generator or process heater fired on solid fuel at a source that has a potential to emit more than 10 tpy of NO
New and modified boilers that will emit or have the potential to emit 25 tpy or more of NO
Based on our review of, and previous approval of, the emission limitations in the District's rules discussed above, we propose to find that the 2013 Ozone Plan meets the clean fuels or advanced control technology for boilers requirement in CAA section 182(e)(3) and 40 CFR 40 CFR 51.1105(a)(1) and 51.1100(o)(6).
Section 182(d)(1)(A) of the Act requires, in relevant part, the state, if subject to its requirements for a given area, to “submit a revision that identifies and adopts specific enforceable transportation control strategies and transportation control measures to offset any growth in emissions from growth in vehicle miles traveled or number of vehicle trips in such area.”
As described above, in 2012, 77 FR 70376 (November 26, 2012), the EPA withdrew the Agency's approvals of the VMT emissions offset demonstrations for the San Joaquin Valley for the 1-hour ozone and 1997 8-hour ozone standards. In both instances, the EPA had based its approvals on the Agency's long-standing interpretation of the VMT emissions offset requirement that was rejected by the Ninth Circuit in the
The August 2012 Guidance discusses the meaning of the terms, “transportation control strategies” (TCSs) and “transportation control measures” (TCMs), and recommends that both TCSs and TCMs be included in the calculations made for the purpose of determining the degree to which any hypothetical growth in emissions due to growth in VMT should be offset. Generally, TCSs is a broad term that encompasses many types of controls including, for example, motor vehicle emission limitations, inspection and maintenance (I/M) programs, alternative fuel programs, other technology-based measures, and TCMs, that would fit within the regulatory definition of “control strategy.” See,
The August 2012 guidance explains how states may demonstrate that the VMT emissions offset requirement is satisfied in conformance with the Court's ruling. States are recommended to estimate emissions for the nonattainment area's base year and the attainment year. One emission inventory is developed for the base year, and three different emissions inventory scenarios are developed for the attainment year. For the attainment year, the state would present three emissions estimates, two of which would represent hypothetical emissions scenarios that would provide the basis to identify the “growth in emissions” due solely to the growth in VMT, and one that would represent projected actual motor vehicle emissions after fully accounting for projected VMT growth and offsetting emissions reductions obtained by all creditable TCSs and TCMs. See the August 2012 guidance for specific details on how states might conduct the calculations.
The base year on-road VOC emissions should be based on VMT in that year and it should reflect all enforceable TCSs and TCMs in place in the base year. This would include vehicle emissions standards, state and local control programs such as I/M programs or fuel rules, and any additional implemented TCSs and TCMs that were already required by or credited in the SIP as of that base year.
The first of the emissions calculations for the attainment year would be based on the projected VMT and trips for that year, and assume that no new TCSs or TCMs beyond those already credited in the base year inventory have been put in place since the base year. This calculation demonstrates how emissions would hypothetically change if no new TCSs or TCMs were implemented, and VMT and trips were allowed to grow at the projected rate from the base year. This estimate would show the potential for an increase in emissions due solely to growth in VMT and trips. This represents a “no action” taken scenario. Emissions in the attainment year in this scenario may be lower than those in the base year due to the fleet that was on the road in the base year gradually being replaced through fleet turnover; however, provided VMT and/or numbers of vehicle trips will in fact increase by the attainment year, they would still likely be higher than they would have been assuming VMT had held constant.
The second of the attainment year's emissions calculations would also assume that no new TCSs or TCMs beyond those already credited have been put in place since the base year, but would also assume that there was no growth in VMT and trips between the base year and attainment year. This estimate reflects the hypothetical emissions level that would have occurred if no further TCMs or TCSs had been put in place and if VMT and trip levels had held constant since the base year. Like the “no action” attainment year estimate described above, emissions in the attainment year may be lower than those in the base year due to the fleet that was on the road in the base year gradually being replaced by cleaner vehicles through fleet turnover, but in this case they would not be influenced by any growth in VMT or trips. This emissions estimate would reflect a ceiling on the attainment emissions that should be allowed to occur under the statute as interpreted by the Court because it shows what would happen under a scenario in which no offsetting TCSs or TCMs have yet been put in place and VMT and trips are held constant during the period from the area's base year to its attainment year. This represents a “VMT offset ceiling” scenario. These two hypothetical status quo estimates are necessary steps in identifying the target level of emissions from which states would determine whether further TCMs or TCSs, beyond those that have been adopted and implemented in reality, would need to be adopted and implemented in order to fully offset any increase in emissions due solely to VMT and trips identified in the “no action” scenario.
Finally, the state would present the emissions that are actually expected to occur in the area's attainment year after taking into account reductions from all enforceable TCSs and TCMs that in reality were put in place after the baseline year. This estimate would be based on the VMT and trip levels expected to occur in the attainment year (
If, instead, the estimated projected actual attainment year emissions are still greater than the ceiling which was established in the second of the attainment year emissions calculations, even after accounting for post-baseline year TCSs and TCMs, the state would need to adopt and implement additional TCSs or TCMs to further offset the
For the revised San Joaquin Valley VMT emissions offset demonstrations, the State used EMFAC2011, the latest EPA-approved motor vehicle emissions model for California. The EMFAC2011 model estimates the on-road emissions from two combustion processes (
Emissions from running exhaust, start exhaust, hot soak, and running losses are a function of how much a vehicle is driven. As such, emissions from these processes are directly related to VMT and vehicle trips, and the State included emissions from them in the calculations that provide the basis for the revised San Joaquin Valley VMT emissions offset demonstrations. The State did not include emissions from resting loss and diurnal loss processes in the analysis because such emissions are related to vehicle population, not to VMT or vehicle trips, and thus are not part of “any growth in emissions from growth in
The revised San Joaquin Valley VMT emissions offset demonstrations address both the 1-hour ozone standard and the 1997 8-hour ozone standard and include two different “base year” scenarios: 1990, for the purposes of the VMT emissions offset demonstration for the 1-hour ozone standard, and 2002, for the purposes of the VMT emissions offset demonstration for the 1997 8-hour ozone standard. The “base year” for VMT emissions offset demonstration purposes should generally be the same “base year” used for nonattainment planning purposes. In 2012, the EPA approved the 2002 base year inventory for the San Joaquin Valley for the purposes of the 1997 8-hour ozone standard, 77 FR 12652, at 12670 (March 1, 2012), and thus, the State's selection of 2002 as the base year for the revised San Joaquin Valley VMT emissions offset demonstration for the 1997 8-hour ozone standard is appropriate. With respect to the 1-hour ozone standard, the attainment demonstration in the 2013 Ozone Plan relies on a base year of 2007, rather than 1990; however, the State's selection of 1990 as the base year for the VMT offset demonstration is appropriate because 1990 was used as the base year for 1-hour ozone SIP planning purposes under the CAA Amendments of 1990, which established, among other requirements, the VMT emissions offset requirement in section 182(d)(1)(A).
The demonstrations also include the previously described three different attainment year scenarios (
The San Joaquin Valley 2013 Ozone Plan, which includes the revised VMT emissions offset demonstrations in appendix D, provides a demonstration of attainment by 2017. The revised San Joaquin Valley 1-hour ozone attainment demonstration thus provides a demonstration of attainment of the 1-hour ozone standard in the San Joaquin Valley by 2017 based on the controlled 2017 emissions inventory. As described in section III.D of this document, the EPA is proposing to approve 2017 as the attainment year for the 1-hour ozone standard in the San Joaquin Valley.
Tables 4 and 5 summarize the relevant distinguishing parameters for each of the emissions scenarios and show the State's corresponding VOC emissions estimates. Table 4 provides the parameters and emissions estimates for the revised VMT emissions offset demonstration for the 1-hour ozone standard, and table 5 provides the corresponding values for the revised demonstration for the 1997 8-hour ozone standard.
For the two “base year” scenarios, the State ran the EMFAC2011 model for the applicable base year (
For the two “no action” scenarios, the State first identified the on-road motor vehicle control programs (
For the “VMT offset ceiling” scenarios, the State ran the EMFAC2011 model for the attainment years but with VMT and starts data corresponding to base year values. Like the “no action” scenarios, the EMFAC2011 model was adjusted to reflect the VOC emissions levels in the attainment years without the benefits of the post-base-year on-road motor vehicle control programs. Thus, the “VMT offset ceiling” scenarios reflect hypothetical VOC emissions in the San Joaquin Valley if the State had not put in place any TCSs or TCMs after the base years and if there had been no growth in VMT or vehicle trips between the base years and the attainment years.
The hypothetical growth in emissions due to growth in VMT and trips can be determined from the difference between the VOC emissions estimates under the “no action” scenarios and the corresponding estimates under the “VMT offset ceiling” scenarios. Based on the values in tables 5 and 6, the hypothetical growth in emissions due to growth in VMT and trips in the San Joaquin Valley would have been 97 tpd (
For the “projected actual” scenario calculations, the State ran the EMFAC2011 model for the attainment years with VMT and starts data at attainment year values and with the full benefits of the relevant post-baseline year motor vehicle control programs. For this scenario, the State included the emissions benefits from TCSs and TCMs put in place since the base year. The most significant measures put in place during the 2002 to 2023 time frame include Low Emission Vehicles II and III standards, Zero Emissions Vehicle standards, and California Reformulated Gasoline Phase 3. These measures are also relied upon for the revised 1-hour ozone attainment demonstration (proposed for approval herein) and the approved 8-hour ozone attainment demonstration.
As shown in tables 5 and 6, the results from these calculations establish projected actual attainment-year VOC emissions of 30 tpd for the 1-hour standard demonstration and 24 tpd for the 1997 8-hour standard demonstration. The State then compared these values against the corresponding VMT offset ceiling values to determine whether additional TCMs or TCSs would need to be adopted and implemented in order to offset any increase in emissions due solely to VMT and trips. Because the “projected actual” emissions are less than the corresponding “VMT Offset Ceiling” emissions, the State concluded that the demonstration shows compliance with the VMT emissions offset requirement and that there are sufficient adopted TCSs and TCMs to offset the growth in emissions from the growth in VMT and vehicle trips in the San Joaquin Valley for both the 1-hour and 1997 8-hour standards. In fact, taking into account of the creditable post-baseline year TCMs and TCSs, the State showed that they offset the hypothetical differences by 148 tpd for the 1-hour standard and by 25 tpd for the 1997 8-hour standards,
Based on our review of revised San Joaquin Valley VMT emissions offset demonstrations in appendix D of the 2013 Ozone Plan and the related technical supplement, we find the State's analysis to be acceptable and agree that the State has adopted sufficient TCSs and TCMs to offset the growth in emissions from growth in VMT and vehicle trips in the San Joaquin Valley for the purposes of the 1-hour ozone and 1997 8-hour ozone standards. As such, we find that the revised San Joaquin Valley VMT emissions offset demonstrations comply with the VMT emissions offset requirement in CAA section 182(d)(1)(A). Therefore, we propose approval of the revised San Joaquin Valley VMT emissions offset demonstrations for the 1-hour ozone and 1997 8-hour ozone standards as a revision to the California SIP.
For the reasons discussed above, the EPA is proposing to approve, under CAA section 110(k)(3), CARB's submittal dated December 20, 2013 of the San Joaquin Valley 2013 Ozone Plan as a revision to the California SIP.
• RACM demonstration as meeting the requirements of CAA section 172(c)(1) and 40 CFR 51.1105(a)(1) and 51.1100(o)(17);
• ROP demonstrations as meeting the requirements of CAA section 172(c)(2) and 182(c)(2)(B), and 40 CFR 51.1105(a)(1) and 51.1100(o)(4);
• Attainment demonstration as meeting the requirements of CAA section 182(c)(2)(A), and 40 CFR 51.1105(a)(1) and 51.1100(o)(12);
• ROP contingency measures as meeting the requirements of CAA sections 182(c)(9) and 40 CFR 51.1105(a)(1) and 51.1100(o)(13); and
• Provisions for clean fuels or advanced control technology for boilers as meeting the requirements of CAA section 182(e)(3) and 40 CFR 51.1105(a)(1) and 51.1100(o)(6).
The EPA is also proposing to approve the 2013 Ozone Plan as meeting the specified requirements for the revoked 1-hour ozone standard and the revoked 1997 8-hour ozone standard:
• VMT emissions offset demonstrations as meeting the requirements of CAA section 182(d)(1)(A) and 40 CFR 51.1105(a)(1) and 51.1100(o)(10).
The EPA is soliciting public comments on the issues discussed in this document or on other relevant matters. We will accept comments from the public on this proposal for the next 30 days. We will consider these comments before taking final action.
Under the CAA, the Administrator is required to approve a SIP submission that complies with the provisions of the Act and applicable Federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in reviewing SIP submissions, the EPA's role is to approve State choices, provided that they meet the criteria of the CAA. Accordingly, this action merely proposes to approve a state plan as meeting Federal requirements and does not impose additional requirements beyond those imposed by State law. For that reason, this proposed action:
• Is not a “significant regulatory action” subject to review by the Office of Management and Budget under Executive Order 12866 (58 FR 51735, October 4, 1993);
• Does not impose an information collection burden under the provisions of the Paperwork Reduction Act (44 U.S.C. 3501
• Is certified as not having a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601
• Does not contain any unfunded mandate or significantly or uniquely affect small governments, as described in the Unfunded Mandates Reform Act of 1995 (Pub. L. 104–4);
• Does not have Federalism implications as specified in Executive Order 13132 (64 FR 43255, August 10, 1999);
• Is not an economically significant regulatory action based on health or safety risks subject to Executive Order 13045 (62 FR 19885, April 23, 1997);
• Is not a significant regulatory action subject to Executive Order 13211 (66 FR 28355, May 22, 2001);
• Is not subject to requirements of Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) because application of those requirements would be inconsistent with the CAA; and
• Does not provide the EPA with the discretionary authority to address disproportionate human health or environmental effects with practical, appropriate, and legally permissible methods under Executive Order 12898 (59 FR 7629, February 16, 1994).
Executive Order 13175, entitled “Consultation and Coordination with Indian Tribal Governments” (65 FR 67249, November 9, 2000), requires the EPA to develop an accountable process to ensure “meaningful and timely input by tribal officials in the development of regulatory policies that have tribal implications.” “Policies that have Tribal implications” is defined in the Executive Order to include regulations that have “substantial direct effects on one or more Indian tribes, on the relationship between the Federal government and the Indian tribes, or on the distribution of power and responsibilities between the Federal government and Indian Tribes.”
Eight Indian tribes are located within the boundaries of the San Joaquin Valley air quality planning area for the 1-hour ozone and 1997 8-hours ozone standards: The Big Sandy Rancheria of Mono Indians of California, the Cold Springs Rancheria of Mono Indians of California, the North Fork Rancheria of Mono Indians of California, the Picayune Rancheria of Chukchansi Indians of California, the Santa Rosa Rancheria of the Tachi Yokut Tribe, the Table Mountain Rancheria of California, the Tejon Indian Tribe, and the Tule River Indian Tribe of the Tule River Reservation.
The EPA's proposed approval of the various SIP elements submitted by CARB to address the 1-hour ozone and 1997 8-hours ozone standards in the San Joaquin Valley would not have tribal implications because the SIP is not approved to apply on any Indian reservation land or in any other area where the EPA or an Indian tribe has demonstrated that a tribe has jurisdiction. In those areas of Indian country, the proposed SIP approvals do not have tribal implications and will not
Environmental protection, Air pollution control, Incorporation by reference, Intergovernmental regulations, Nitrogen dioxide, Ozone, Reporting and recordkeeping requirements, Volatile organic compounds.
42 U.S.C. 7401
Environmental Protection Agency (EPA).
Proposed rule.
The Environmental Protection Agency (EPA) proposes to approve revisions to the Operating Permits Program for the State of Missouri submitted on March 16, 2015. These revisions update the emissions fee for permitted sources as set by Missouri Statute from $40 to $48 per ton of air pollution emitted annually, effective January 1, 2016.
Comments on this proposed action must be received in writing by February 16, 2016.
Submit your comments, identified by Docket ID No. EPA–R07–OAR–2015–0790, to
Stephen Krabbe, Environmental Protection Agency, Air Planning and Development Branch, 11201 Renner Boulevard, Lenexa, Kansas 66219 at 913–551–7991, or by email at
In the final rules section of this
Environmental protection, Air pollution control, Carbon monoxide, Incorporation by reference, Intergovernmental relations, Lead, Nitrogen dioxide, Ozone, Particulate matter, Reporting and recordkeeping requirements, Sulfur oxides, Volatile organic compounds.
Administrative practice and procedure, Air pollution control, Intergovernmental relations, Operating permits, Reporting and recordkeeping requirements.
U.S. Commission on Civil Rights.
Announcement of meeting.
Notice is hereby given, pursuant to the provisions of the rules and regulations of the U.S. Commission on Civil Rights (Commission) and the Federal Advisory Committee Act that the Indiana Advisory Committee (Committee) will hold a meeting on Wednesday, February 03, 2016, from 11:00 a.m.–12:00 p.m. EST for the purpose of reviewing testimony received during their January 20, 2016 Web hearing, and finalizing preparations for their February 17, 2016 hearing on Civil Rights and the School to Prison Pipeline in Indiana.
Members of the public may listen to the discussion. This meeting is available to the public through the following toll-free call-in number: 888–437–9445 conference ID: 3383741. Any interested member of the public may call this number and listen to the meeting. The conference call operator will ask callers to identify themselves, the organization they are affiliated with (if any), and an email address prior to placing callers into the conference room. Callers can expect to incur regular charges for calls they initiate over wireless lines, according to their wireless plan. The Commission will not refund any incurred charges. Callers will incur no charge for calls they initiate over land-line connections to the toll-free telephone number. Persons with hearing impairments may also follow the proceedings by first calling the Federal Relay Service at 1–800–977–8339 and providing the Service with the conference call number and conference ID number.
Members of the public are also invited to make statements during the open comment period at the end of the meeting. In addition, members of the public may submit written comments; the comments must be received in the regional office within 30 days after the meeting. Written comments may be mailed to the Regional Programs Unit, U.S. Commission on Civil Rights, 55 W. Monroe St., Suite 410, Chicago, IL 60615. They may also be faxed to the Commission at (312) 353–8324, or emailed to Administrative Assistant, Carolyn Allen at
Records and documents discussed during the meeting will be available for public viewing prior to and following the meeting at
The meeting will be held on Wednesday February 3, 2016, from 11:00 a.m.–12:00 p.m. EST.
Melissa Wojnaroski, DFO, at 312–353–8311 or
Bureau of Industry and Security.
Notice.
In compliance with the Paperwork Reduction Act (44 U.S.C. 3501
Requests for additional information or copies of the information collection instrument and instructions should be directed to Mark Crace, BIS ICB Liaison, (202) 482–8093,
Over the years, BIS has worked with other Government agencies and the affected public to identify areas where export licensing requirements may be relaxed without jeopardizing U.S. national security or foreign policy. Many of these relaxations have taken the form of licensing exceptions and exclusions. Some of these license exceptions and exclusions have a reporting or recordkeeping requirement to enable the Government to continue to monitor exports of these items. Exporters may choose to utilize the license exception and accept the reporting or recordkeeping burden in lieu of submitting a license application.
Electronic Information on Individual ICRs for Which an Emergency Extension Is Requested:
Title of Collections:
1. Simple Network Application Process and Multi-purpose Application Form.
2. Offsets in Military Exports.
3. Licensing Exemptions and Exclusions.
1. Simple Network Application Process and Multi-purpose Application Form.
2. Offsets in Military Exports.
3. License Exemptions and Exclusions.
Pursuant to Section 766.24 of the Export Administration Regulations, 15 CFR parts 730–774 (2015) (“EAR” or the “Regulations”),
On March 17, 2008, Darryl W. Jackson, the then-Assistant Secretary of Commerce for Export Enforcement (“Assistant Secretary”), signed a TDO denying Mahan Airways' export privileges for a period of 180 days on the grounds that its issuance was necessary in the public interest to prevent an imminent violation of the Regulations. The TDO also named as denied persons Blue Airways, of Yerevan, Armenia (“Blue Airways of Armenia”), as well as the “Balli Group Respondents,” namely, Balli Group PLC, Balli Aviation, Balli Holdings, Vahid Alaghband, Hassan Alaghband, Blue Sky One Ltd., Blue Sky Two Ltd., Blue Sky Three Ltd., Blue Sky Four Ltd., Blue Sky Five Ltd., and Blue Sky Six Ltd., all of the United Kingdom. The TDO was issued
The TDO subsequently has been renewed in accordance with Section 766.24(d), including most recently on July 13, 2015.
On May 21, 2015, the TDO was modified to add Al Naser Airlines, Ali Abdullah Alhay, and Bahar Safwa General Trading as respondents. Sky Blue Bird Group and its chief executive officer Issam Shammout were added to the TDO as related persons as part of the July 13, 2015 renewal order.
On December 18, 2015, BIS, through its Office of Export Enforcement (“OEE”), submitted a written request for renewal of the TDO. The written request was made more than 20 days before the scheduled expiration of the current TDO, which issued on July 13, 2015.
Pursuant to Section 766.24, BIS may issue or renew an order temporarily denying a respondent's export privileges upon a showing that the order is necessary in the public interest to prevent an “imminent violation” of the Regulations. 15 CFR 766.24(b)(1) and 776.24(d). “A violation may be `imminent' either in time or degree of likelihood.” 15 CFR 766.24(b)(3). BIS may show “either that a violation is about to occur, or that the general circumstances of the matter under investigation or case under criminal or administrative charges demonstrate a likelihood of future violations.”
OEE's request for renewal is based upon the facts underlying the issuance of the initial TDO and the TDO renewals in this matter and the evidence developed over the course of this investigation indicating a blatant disregard of U.S. export controls and the TDO. The initial TDO was issued as a result of evidence that showed that Mahan Airways and other parties engaged in conduct prohibited by the EAR by knowingly re-exporting to Iran three U.S.-origin aircraft, specifically Boeing 747s (“Aircraft 1–3”), items subject to the EAR and classified under Export Control Classification Number (“ECCN”) 9A991.b, without the required U.S. Government authorization. Further evidence submitted by BIS indicated that Mahan Airways was involved in the attempted re-export of three additional U.S.-origin Boeing 747s (“Aircraft 4–6”) to Iran.
As discussed in the September 17, 2008 renewal order, evidence presented by BIS indicated that Aircraft 1–3 continued to be flown on Mahan Airways' routes after issuance of the TDO, in violation of the Regulations and the TDO itself.
The March 9, 2010 Renewal Order also noted that a court in the United Kingdom (“U.K.”) had found Mahan Airways in contempt of court on February 1, 2010, for failing to comply with that court's December 21, 2009 and January 12, 2010 orders compelling Mahan Airways to remove the Boeing 747s from Iran and ground them in the Netherlands. Mahan Airways and the Balli Group Respondents had been litigating before the U.K. court
The September 3, 2010 renewal order discussed the fact that Mahan Airways' violations of the TDO extended beyond operating U.S.-origin aircraft and attempting to acquire additional U.S.-origin aircraft. In February 2009, while subject to the TDO, Mahan Airways participated in the export of computer motherboards, items subject to the Regulations and designated as EAR99, from the United States to Iran, via the United Arab Emirates (“UAE”), in violation of both the TDO and the Regulations, by transporting and/or forwarding the computer motherboards from the UAE to Iran. Mahan Airways' violations were facilitated by Gatewick LLC, which not only participated in the transaction, but also has stated to BIS that it acted as Mahan Airways' sole booking agent for cargo and freight forwarding services in the UAE.
Moreover, in a January 24, 2011 filing in the U.K. court, Mahan Airways asserted that Aircraft 1–3 were not being used, but stated in pertinent part that the aircraft were being maintained in Iran especially “in an airworthy condition” and that, depending on the outcome of its U.K. court appeal, the aircraft “could immediately go back into service . . . on international routes into and out of Iran.” Mahan Airways' January 24, 2011 submission to U.K. Court of Appeal, at p. 25, ¶¶ 108, 110. This clearly stated intent, both on its own and in conjunction with Mahan Airways' prior misconduct and statements, demonstrated the need to renew the TDO in order to prevent imminent future violations. Two of these three 747s subsequently were removed from Iran and are no longer in Mahan Airway's possession. The third of these 747s, with Manufacturer's Serial Number (“MSN”) 23480 and Iranian tail number EP–MNE, remained in Iran under Mahan's control. Pursuant to Executive Order 13324, it was designated a Specially Designated Global Terrorist (“SDGT”) by the U.S. Department of the Treasury's Office of Foreign Assets Control (“OFAC”) on September 19, 2012.
In addition, as first detailed in the July 1, 2011 and August 24, 2011 orders, and discussed in subsequent renewal orders in this matter, Mahan Airways also continued to evade U.S. export control laws by operating two Airbus A310 aircraft, bearing Mahan Airways' livery and logo, on flights into and out of Iran.
The August 2012 renewal order also found that Mahan Airways had acquired another Airbus A310 aircraft subject to the Regulations, with MSN 499 and Iranian tail number EP–VIP, in violation of the TDO and the Regulations.
The February 4, 2013 Order laid out further evidence of continued and additional efforts by Mahan Airways and other persons acting in concert with Mahan, including Kral Aviation and another Turkish company, to procure U.S.-origin engines—two GE CF6–50C2 engines, with MSNs 517621 and 517738, respectively—and other aircraft parts in violation of the TDO and the Regulations.
On December 31, 2013, Kral Aviation was added to BIS's Entity List, Supplement No. 4 to Part 744 of the Regulations.
The July 31, 2013 Order detailed additional evidence obtained by OEE showing efforts by Mahan Airways to obtain another GE CF6–50C2 aircraft engine (MSN 528350) from the United States via Turkey. Multiple Mahan employees, including Mehdi Bahrami, were involved in or aware of matters related to the engine's arrival in Turkey from the United States, plans to visually inspect the engine, and prepare it for shipment from Turkey.
Mahan sought to obtain this U.S.-origin engine through Pioneer Logistics Havacilik Turizm Yonetim Danismanlik (“Pioneer Logistics”), an aircraft parts supplier located in Turkey, and its director/operator, Gulnihal Yegane, a Turkish national who previously had conducted Mahan related business with Mehdi Bahrami and Ali Eslamian. Moreover, as referenced in the July 31, 2013 Order, a sworn affidavit by Kosol Surinanda, also known as Kosol Surinandha, Managing Director of Mahan's General Sales Agent in Thailand, stated that the shares of Pioneer Logistics for which he was the
The January 24, 2014 Order outlined OEE's continued investigation of Mahan Airways' activities and detailed an attempt by Mahan, which OEE thwarted, to obtain, via an Indonesian aircraft parts supplier, two U.S.-origin Honeywell ALF–502R–5 aircraft engines (MSNs LF5660 and LF5325), items subject to the Regulations, from a U.S. company located in Texas. An invoice of the Indonesian aircraft parts supplier dated March 27, 2013, listed Mahan Airways as the purchaser of the engines and included a Mahan ship-to address. OEE also obtained a Mahan air waybill dated March 12, 2013, listing numerous U.S.-origin aircraft parts subject to the Regulations—including, among other items, a vertical navigation gyroscope, a transmitter, and a power control unit—being transported by Mahan from Turkey to Iran in violation of the TDO.
The July 22, 2014 Order discussed open source evidence from the March–June 2014 time period regarding two BAE regional jets, items subject to the Regulations, that were painted in the livery and logo of Mahan Airways and operating under Iranian tail numbers EP–MOK and EP–MOI, respectively.
The January 16, 2015 Order detailed evidence of additional attempts by Mahan Airways to acquire items subject the Regulations in further violation of the TDO. Specifically, in March 2014, OEE became aware of an inertial reference unit bearing serial number 1231 (“the IRU”) that had been sent to the United States for repair. The IRU is subject to the Regulations, classified under ECCN 7A103, and controlled for missile technology reasons. Upon closer inspection, it was determined that IRU came from or had been installed on an Airbus A340 aircraft bearing MSN 056. Further investigation revealed that as of approximately February 2014, this aircraft was registered under Iranian tail number EP–MMB and had been painted in the livery and logo of Mahan Airways.
The January 16, 2015 Order described related efforts by the Departments of Justice and Treasury to further thwart Mahan's illicit procurement efforts. Specifically, on August 14, 2014, the United States Attorney's Office for the District of Maryland filed a civil forfeiture complaint for the IRU pursuant to 22 U.S.C. 401(b) that resulted in the court issuing an Order of Forfeiture on December 2, 2014. EP–MMB remains listed as active in Mahan Airways' fleet.
Additionally, on August 29, 2014, OFAC blocked the property and interests in property of Asian Aviation Logistics of Thailand, a Mahan Airways affiliate or front company, pursuant to Executive Order 13224. In doing so, OFAC described Mahan Airway's use of Asian Aviation Logistics to evade sanctions by making payments on behalf of Mahan for the purchase of engines and other equipment.
The May 21, 2015 modification order detailed the acquisition of two aircraft, specifically an Airbus A340 bearing MSN 164 and an Airbus A321 bearing MSN 550, that were purchased by Al Naser Airlines in late 2014/early 2015 and are currently located in Iran under the possession, control, and/or ownership of Mahan Airways.
The May 21, 2015 modification order also laid out evidence showing the respondents' attempts to obtain other controlled aircraft, including aircraft physically located in the United States in similarly-patterned transactions during the same recent time period. Transactional documents involving two Airbus A320s bearing MSNs 82 and 99, respectively, again showed Ali Abdullah Alhay signing sales agreements for Al Naser Airlines.
The July 13, 2015 Order outlined evidence showing that Al Naser Airlines' attempts to acquire aircraft on behalf of Mahan Airways extended
The December 18, 2015 renewal request highlights evidence that Mahan Airways continues to operate EP–MMH and EP–MMR on flights into and out of Iran in further violation of the TDO and Regulations. Evidence provided by OEE indicates that EP–MMD, another of the aircraft Mahan obtained from Al Naser Airlines as discussed in the July 13, 2015 renewal order, also is now in active service with Mahan and flew from Tehran, Iran to Bangkok, Thailand on January 4, 2016, and back to Iran on January 5, 2016. Additionally, publically available aviation databases and flight tracking information indicate that Mahan has acquired Iranian tail numbers for at least two more of the Airbus A340 aircraft it obtained from Al Naser Airlines: EP–MME (MSN 371) and EP–MMF (MSN 376), respectively. Moreover, both aircraft now bear Mahan Airways livery and logo, and since January 1, 2016, EP–MME has logged flights to and from Tehran, Iran involving various destinations, including Guangzhou, China and Dubai, United Arab Emirates.
Under the applicable standard set forth in Section 766.24 of the Regulations and my review of the entire record, I find that the evidence presented by BIS convincingly demonstrates that the denied persons have acted in violation of the EAR and the TDO, that such violations have been significant, deliberate and covert, and that there is a likelihood of future violations. Therefore, renewal of the TDO is necessary to prevent imminent violation of the EAR and to give notice to companies and individuals in the United States and abroad that they should continue to cease dealing with Mahan Airways and the other denied persons under the TDO in connection with export and reexport transactions involving items subject to the EAR.
A. Applying for, obtaining, or using any license, License Exception, or export control document;
B. Carrying on negotiations concerning, or ordering, buying, receiving, using, selling, delivering, storing, disposing of, forwarding, transporting, financing, or otherwise servicing in any way, any transaction involving any item exported or to be exported from the United States that is subject to the EAR, or in any other activity subject to the EAR; or
C. Benefitting in any way from any transaction involving any item exported or to be exported from the United States that is subject to the EAR, or in any other activity subject to the EAR.
A. Export or reexport to or on behalf of a Denied Person any item subject to the EAR;
B. Take any action that facilitates the acquisition or attempted acquisition by a Denied Person of the ownership, possession, or control of any item subject to the EAR that has been or will be exported from the United States, including financing or other support activities related to a transaction whereby a Denied Person acquires or attempts to acquire such ownership, possession or control;
C. Take any action to acquire from or to facilitate the acquisition or attempted acquisition from a Denied Person of any item subject to the EAR that has been exported from the United States;
D. Obtain from a Denied Person in the United States any item subject to the EAR with knowledge or reason to know that the item will be, or is intended to be, exported from the United States; or
E. Engage in any transaction to service any item subject to the EAR that has been or will be exported from the United States and which is owned, possessed or controlled by a Denied Person, or service any item, of whatever origin, that is owned, possessed or controlled by a Denied Person if such service involves the use of any item subject to the EAR that has been or will be exported from the United States. For purposes of this paragraph, servicing means installation, maintenance, repair, modification or testing.
In accordance with the provisions of Sections 766.24(e) of the EAR, Mahan Airways, Al Naser Airlines, Ali Abdullah Alhay, and/or Bahar Safwa General Trading may, at any time, appeal this Order by filing a full written statement in support of the appeal with the Office of the Administrative Law Judge, U.S. Coast Guard ALJ Docketing Center, 40 South Gay Street, Baltimore, Maryland 21202–4022. In accordance with the provisions of Sections 766.23(c)(2) and 766.24(e)(3) of the EAR, Pejman Mahmood Kosarayanifard, Mahmoud Amini, Kerman Aviation, Sirjanco Trading LLC, Ali Eslamian, Mahan Air General Trading LLC, Skyco (UK) Ltd., Equipco (UK) Ltd., Mehdi Bahrami, Sky Blue Bird Group, and/or Issam Shammout may, at any time, appeal their inclusion as a related person by filing a full written statement in support of the appeal with the Office of the Administrative Law Judge, U.S. Coast Guard ALJ Docketing Center, 40 South Gay Street, Baltimore, Maryland 21202–4022.
In accordance with the provisions of Section 766.24(d) of the EAR, BIS may seek renewal of this Order by filing a written request not later than 20 days before the expiration date. A renewal request may be opposed by Mahan Airways, Al Naser Airlines, Ali Abdullah Alhay, and/or Bahar Safwa General Trading as provided in Section 766.24(d), by filing a written submission with the Assistant Secretary of Commerce for Export Enforcement, which must be received not later than seven days before the expiration date of the Order.
A copy of this Order shall be provided to Mahan Airways, Al Naser Airlines, Ali Abdullah Alhay, and Bahar Safwa General Trading and each related person, and shall be published in the
Enforcement and Compliance, International Trade Administration, Department of Commerce.
The Department of Commerce (the Department) preliminarily determines that
Emily Halle or Gene Calvert, AD/CVD Operations, Office VII, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone (202) 482–0176, or (202) 482–3586, respectively.
The products covered by this investigation are hot-rolled steel products from Turkey. For a complete description of the scope of this investigation,
The Department is conducting this countervailing duty (CVD) investigation in accordance with section 701 of the Tariff Act of 1930, as amended (the Act). For a full description of the methodology underlying our preliminary conclusions,
As noted in the Preliminary Decision Memorandum,
In accordance with section 703(d)(1)(A)(i) of the Act, we calculated a CVD rate for each individually investigated producer/exporter of the subject merchandise. We preliminarily determine that
Because we preliminarily determine that the CVD rates in this investigation are
As provided in section 782(i)(1) of the Act, we intend to verify the information submitted by the respondents prior to making our final determination.
In accordance with section 703(f) of the Act, we will notify the International Trade Commission (ITC) of our determination. In addition, we are making available to the ITC all non-privileged and non-proprietary information relating to this investigation. We will allow the ITC access to all privileged and business proprietary information in our files, provided the ITC confirms that it will not disclose such information, either publicly or under an administrative protective order, without the written consent of the Assistant Secretary for Enforcement and Compliance.
In accordance with section 705(b)(2) of the Act, if our final determination is affirmative, the ITC will make its final determination within 45 days after the Department makes its final determination.
The Department intends to disclose to interested parties the calculations performed in connection with this preliminary determination within five days of its public announcement.
This determination is issued and published pursuant to sections 703(f) and 777(i) of the Act and 19 CFR 351.205(c).
The products covered by this investigation are certain hot-rolled, flat-rolled steel products, with or without patterns in relief, and whether or not annealed, painted, varnished, or coated with plastics or other non-metallic substances. The products covered do not include those that are clad, plated, or coated with metal. The products covered include coils that have a width or other lateral measurement (“width”) of 12.7 mm or greater, regardless of thickness, and regardless of form of coil (
(1) Where the nominal and actual measurements vary, a product is within the scope if application of either the nominal or actual measurement would place it within the scope based on the definitions set forth above unless the resulting measurement makes the product covered by the existing antidumping
(2) Where the width and thickness vary for a specific product (
Steel products included in the scope of this investigation are products in which: (1) Iron predominates, by weight, over each of the other contained elements; (2) the carbon content is 2 percent or less, by weight; and (3) none of the elements listed below exceeds the quantity, by weight, respectively indicated:
Unless specifically excluded, products are included in this scope regardless of levels of boron and titanium.
For example, specifically included in this scope are vacuum degassed, fully stabilized (commonly referred to as interstitial-free (IF)) steels, high strength low alloy (HSLA) steels, the substrate for motor lamination steels, Advanced High Strength Steels (AHSS), and Ultra High Strength Steels (UHSS). IF steels are recognized as low carbon steels with micro-alloying levels of elements such as titanium and/or niobium added to stabilize carbon and nitrogen elements. HSLA steels are recognized as steels with micro-alloying levels of elements such as chromium, copper, niobium, titanium, vanadium, and molybdenum. The substrate for motor lamination steels contains micro-alloying levels of elements such as silicon and
Subject merchandise includes hot-rolled steel that has been further processed in a third country, including but not limited to pickling, oiling, levelling, annealing, tempering, temper rolling, skin passing, painting, varnishing, trimming, cutting, punching, and/or slitting, or any other processing that would not otherwise remove the merchandise from the scope of the investigation if performed in the country of manufacture of the hot-rolled steel.
All products that meet the written physical description, and in which the chemistry quantities do not exceed any one of the noted element levels listed above, are within the scope of this investigation unless specifically excluded. The following products are outside of and/or specifically excluded from the scope of this investigation:
• Universal mill plates (
• Products that have been cold-rolled (cold-reduced) after hot-rolling;
• Ball bearing steels;
• Tool steels;
• Silico-manganese steels;
The products subject to this investigation are currently classified in the Harmonized Tariff Schedule of the United States (HTSUS) under item numbers: 7208.10.1500, 7208.10.3000, 7208.10.6000, 7208.25.3000, 7208.25.6000, 7208.26.0030, 7208.26.0060, 7208.27.0030, 7208.27.0060, 7208.36.0030, 7208.36.0060, 7208.37.0030, 7208.37.0060, 7208.38.0015, 7208.38.0030, 7208.38.0090, 7208.39.0015, 7208.39.0030, 7208.39.0090, 7208.40.6030, 7208.40.6060, 7208.53.0000, 7208.54.0000, 7208.90.0000, 7210.70.3000, 7211.14.0030, 7211.14.0090, 7211.19.1500, 7211.19.2000, 7211.19.3000, 7211.19.4500, 7211.19.6000, 7211.19.7530, 7211.19.7560, 7211.19.7590, 7225.11.0000, 7225.19.0000, 7225.30.3050, 7225.30.7000, 7225.40.7000, 7225.99.0090, 7226.11.1000, 7226.11.9030, 7226.11.9060, 7226.19.1000, 7226.19.9000, 7226.91.5000, 7226.91.7000, and 7226.91.8000. The products subject to the investigation may also enter under the following HTSUS numbers: 7210.90.9000, 7211.90.0000, 7212.40.1000, 7212.40.5000, 7212.50.0000, 7214.91.0015, 7214.91.0060, 7214.91.0090, 7214.99.0060, 7214.99.0075, 7214.99.0090, 7215.90.5000, 7226.99.0180, and 7228.60.6000.
The HTSUS subheadings above are provided for convenience and U.S. Customs and Border Protection purposes only. The written description of the scope of the investigation is dispositive.
Enforcement and Compliance, International Trade Administration, Department of Commerce.
The Department of Commerce (the Department) preliminarily determines that countervailable subsidies are being provided to producers and exporters of certain hot-rolled steel flat products (hot-rolled steel) from Brazil. The period of investigation is January 1, 2014, through December 31, 2014. We invite interested parties to comment on this preliminary determination.
Nicholas Czajkowski or Lana Nigro, AD/CVD Operations, Office I, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone: (202) 482–1395 or (202) 482–1779, respectively.
The products covered by this investigation are hot-rolled steel flat products from Brazil. For a complete description of the scope of this investigation,
The Department is conducting this countervailing duty (CVD) investigation in accordance with section 701 of the Tariff Act of 1930, as amended (Act). For each of the subsidy programs found countervailable, we preliminarily determine that there is a subsidy,
In making this preliminary determination, the Department relied, in part, on facts otherwise available.
As noted in the Preliminary Decision Memorandum, in accordance with section 705(a)(1) of the Act and 19 CFR 351.210(b)(4), we are aligning the final
In accordance with section 703(d)(1)(A)(i) of the Act, we calculated a CVD rate for each individually investigated respondent company. Section 705(c)(5)(A)(i) of the Act states that, for companies not individually investigated, we will determine an “all-others” rate equal to the weighted-average countervailable subsidy rates established for exporters and producers individually investigated, excluding any zero and
Consistent with the Department's practice, we normally calculate the all-others rate based on the weighted average of the mandatory respondents' calculated subsidy rates.
We preliminarily determine the countervailable subsidy rates to be:
In accordance with section 703(d)(2) of the Act, we will direct U.S. Customs and Border Protection (CBP) to suspend liquidation of all entries of hot-rolled steel from Brazil as described in the scope of the investigation section entered, or withdrawn from warehouse, for consumption on or after the date of publication of this notice in the
As provided in section 782(i)(1) of the Act, we intend to verify the information submitted by the respondents prior to making our final determination.
In accordance with section 703(f) of the Act, we will notify the International Trade Commission (ITC) of our determination. In addition, we are making available to the ITC all non-privileged and non-proprietary information relating to this investigation. We will allow the ITC access to all privileged and business proprietary information in our files, provided the ITC confirms that it will not disclose such information, either publicly or under an administrative protective order, without the written consent of the Assistant Secretary for Enforcement and Compliance.
In accordance with section 705(b)(2) of the Act, if our final determination is affirmative, the ITC will make its final determination within 45 days after the Department makes its final determination.
The Department intends to disclose to interested parties the calculations performed in connection with this preliminary determination within five days of its public announcement.
This determination is issued and published pursuant to sections 703(f) and 777(i) of the Act and 19 CFR 351.205(c).
The products covered by this investigation are certain hot-rolled, flat-rolled steel products, with or without patterns in relief, and whether or not annealed, painted, varnished, or coated with plastics or other non-metallic substances. The products covered do not include those that are clad, plated, or coated with metal. The products covered include coils that have a width or other lateral measurement (“width”) of 12.7 mm or greater, regardless of thickness, and regardless of form of coil (
(1) Where the nominal and actual measurements vary, a product is within the scope if application of either the nominal or actual measurement would place it within the scope based on the definitions set forth above unless the resulting measurement makes the product covered by the existing antidumping
(2) where the width and thickness vary for a specific product (
Steel products included in the scope of this investigation are products in which: (1) Iron predominates, by weight, over each of the other contained elements; (2) the carbon content is 2 percent or less, by weight; and (3) none of the elements listed below exceeds the quantity, by weight, respectively indicated:
Unless specifically excluded, products are included in this scope regardless of levels of boron and titanium.
For example, specifically included in this scope are vacuum degassed, fully stabilized (commonly referred to as interstitial-free (IF)) steels, high strength low alloy (HSLA) steels, the substrate for motor lamination steels, Advanced High Strength Steels (AHSS), and Ultra High Strength Steels (UHSS). IF steels are recognized as low carbon steels with micro-alloying levels of elements such as titanium and/or niobium added to stabilize carbon and nitrogen elements. HSLA steels are recognized as steels with micro-alloying levels of elements such as chromium, copper, niobium, titanium, vanadium, and molybdenum. The substrate for motor lamination steels contains micro-alloying levels of elements such as silicon and aluminum. AHSS and UHSS are considered high tensile strength and high elongation steels, although AHSS and UHSS are covered whether or not they are high tensile strength or high elongation steels.
Subject merchandise includes hot-rolled steel that has been further processed in a third country, including but not limited to pickling, oiling, levelling, annealing, tempering, temper rolling, skin passing, painting, varnishing, trimming, cutting, punching, and/or slitting, or any other processing that would not otherwise remove the merchandise from the scope of the investigation if performed in the country of manufacture of the hot-rolled steel.
All products that meet the written physical description, and in which the chemistry quantities do not exceed any one of the noted element levels listed above, are within the scope of this investigation unless specifically excluded. The following products are outside of and/or specifically excluded from the scope of this investigation:
• Universal mill plates (
• Products that have been cold-rolled (cold-reduced) after hot-rolling;
• Ball bearing steels;
• Tool steels;
• Silico-manganese steels;
The products subject to this investigation are currently classified in the Harmonized Tariff Schedule of the United States (HTSUS) under item numbers: 7208.10.1500, 7208.10.3000, 7208.10.6000, 7208.25.3000, 7208.25.6000, 7208.26.0030, 7208.26.0060, 7208.27.0030, 7208.27.0060, 7208.36.0030, 7208.36.0060, 7208.37.0030, 7208.37.0060, 7208.38.0015, 7208.38.0030, 7208.38.0090, 7208.39.0015, 7208.39.0030, 7208.39.0090, 7208.40.6030, 7208.40.6060, 7208.53.0000, 7208.54.0000, 7208.90.0000, 7210.70.3000, 7211.14.0030, 7211.14.0090, 7211.19.1500, 7211.19.2000, 7211.19.3000, 7211.19.4500, 7211.19.6000, 7211.19.7530, 7211.19.7560, 7211.19.7590, 7225.11.0000, 7225.19.0000, 7225.30.3050, 7225.30.7000, 7225.40.7000, 7225.99.0090, 7226.11.1000, 7226.11.9030, 7226.11.9060, 7226.19.1000, 7226.19.9000, 7226.91.5000, 7226.91.7000, and 7226.91.8000. The products subject to the investigation may also enter under the following HTSUS numbers: 7210.90.9000, 7211.90.0000, 7212.40.1000, 7212.40.5000, 7212.50.0000, 7214.91.0015, 7214.91.0060, 7214.91.0090, 7214.99.0060, 7214.99.0075, 7214.99.0090, 7215.90.5000, 7226.99.0180, and 7228.60.6000.
The HTSUS subheadings above are provided for convenience and U.S. Customs purposes only. The written description of the scope of the investigation is dispositive.
Enforcement and Compliance, International Trade Administration, Department of Commerce.
Robert Galantucci at (202) 482–2923, AD/CVD Operations, Enforcement and Compliance, International Trade Administration, Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230.
On November 17, 2015, the Department of Commerce (the Department) initiated the countervailing duty (CVD) investigation of certain iron mechanical transfer drive components from the People's Republic of China.
Section 703(b)(1) of the Tariff Act of 1930, as amended (the Act), requires the Department to issue the preliminary determination in a CVD investigation within 65 days after the date on which the Department initiated the investigation. However, if the Department concludes that the parties concerned are cooperating, and that the case is extraordinarily complicated such that additional time is necessary to make the preliminary determination, section 703(c)(1)(B) of the Act allows the Department to postpone making the preliminary determination until no later than 130 days after the date on which the administering authority initiated the investigation. We have concluded that the parties concerned are cooperating and that the case is extraordinarily complicated, such that we will need more time to make the preliminary determination. Specifically, the Department finds that the instant case is extraordinarily complicated by reason of the number and complexity of the alleged countervailable subsidy practices, and the need to determine the extent to which particular alleged countervailable subsidies are used by individual manufacturers, producers and exporters.
Additionally, the Department notes that we issued questionnaires to the respondents in this case on December 18, 2015. The due date for these questionnaires is January 25, 2016, which is after the unextended preliminary determination date. For these reasons, the Department will extend the deadline for completion of the preliminary determination by 65 days (
This notice is issued and published pursuant to section 703(c)(2) of the Act and 19 CFR 351.205(f)(l).
Enforcement and Compliance, International Trade Administration, Department of Commerce.
The Department of Commerce (the Department) is rescinding its administrative review in part on polyethylene retail carrier bags from Thailand for the period of review (POR) August 1, 2014, through July 31, 2015.
Andre Gziryan, AD/CVD Operations Office I, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone: (202) 482–2201.
On August 3, 2015, we published a notice of opportunity to request an administrative review of the antidumping duty order on polyethylene retail carrier bags from Thailand for the POR August 1, 2014, through July 31, 2015.
Pursuant to 19 CFR 351.213(d)(1), the Department will rescind an administrative review, “in whole or in part, if a party that requested a review withdraws the request within 90 days of
The Department will instruct U.S. Customs and Border Protection (CBP) to assess antidumping duties on all appropriate entries. For the aforementioned companies, for which the review is rescinded, antidumping duties shall be assessed at rates equal to the cash deposit of estimated antidumping duties required at the time of entry, or withdrawal from warehouse, for consumption, in accordance with 19 CFR 351.212(c)(1)(i). The Department intends to issue appropriate assessment instructions to CBP within 15 days after publication of this notice.
This notice serves as a final reminder to importers of their responsibility under 19 CFR 351.402(f)(2) to file a certificate regarding the reimbursement of antidumping duties prior to liquidation of the relevant entries during this review period. Failure to comply with this requirement may result in the Department's presumption that reimbursement of antidumping duties occurred and the subsequent assessment of doubled antidumping duties.
This notice also serves as a reminder to parties subject to administrative protective order (APO) of their responsibility concerning the disposition of proprietary information disclosed under APO, in accordance with 19 CFR 351.305(a)(3). Timely written notification of the return or destruction of APO materials or conversion to judicial protective order is hereby requested. Failure to comply with the regulations and the terms of an APO is a sanctionable violation.
This notice is issued and published in accordance with sections 751(a)(1) and 777(i)(1) of the Act and 19 CFR 351.213(d)(4).
Enforcement and Compliance, International Trade Administration, Department of Commerce.
The Department of Commerce (the “Department”) preliminarily determines that
Katie Marksberry or Bob Palmer, AD/CVD Operations, Office V, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone (202) 482–7906 or (202) 482–9068, respectively.
The products covered by this investigation are certain hot-rolled steel flat products from Korea. For a complete description of the scope of this investigation,
The Department is conducting this countervailing duty (“CVD”) investigation in accordance with section 701 of the Tariff Act of 1930, as amended (the “Act”). For a full description of the methodology underlying our preliminary conclusions,
The Department notes that, in making this preliminary determination, we relied, in part, on facts otherwise available.
As noted in the Preliminary Decision Memorandum,
In accordance with section 703(d)(1)(A)(i) of the Act, we calculated a CVD rate for each individually investigated producer/exporter of the subject merchandise. We preliminarily determine that
Because we preliminarily determine that the CVD rates in this investigation are
As provided in section 782(i)(1) of the Act, we intend to verify the information submitted by the respondents prior to making our final determination.
In accordance with section 703(f) of the Act, we will notify the International Trade Commission (“ITC”) of our determination. In addition, we are making available to the ITC all non-privileged and non-proprietary information relating to this investigation. We will allow the ITC access to all privileged and business proprietary information in our files, provided the ITC confirms that it will not disclose such information, either publicly or under an administrative protective order, without the written consent of the Assistant Secretary for Enforcement and Compliance.
In accordance with section 705(b)(3) of the Act, if our final determination is affirmative, the ITC will make its final determination within 75 days after the Department makes its final determination.
The Department intends to disclose to interested parties the calculations performed in connection with this preliminary determination within five days of its public announcement.
This determination is issued and published pursuant to sections 703(f) and 777(i) of the Act and 19 CFR 351.205(c).
The products covered by this investigation are certain hot-rolled, flat-rolled steel products, with or without patterns in relief, and whether or not annealed, painted, varnished, or coated with plastics or other non-metallic substances. The products covered do not include those that are clad, plated, or coated with metal. The products covered include coils that have a width or other lateral measurement (“width”) of 12.7 mm or greater, regardless of thickness, and regardless of form of coil (
(1) where the nominal and actual measurements vary, a product is within the scope if application of either the nominal or actual measurement would place it within the scope based on the definitions set forth above unless the resulting measurement makes the product covered by the existing antidumping
(2) where the width and thickness vary for a specific product (
Steel products included in the scope of this investigation are products in which: (1) Iron predominates, by weight, over each of the other contained elements; (2) the carbon content is 2 percent or less, by weight; and (3) none of the elements listed below exceeds the quantity, by weight, respectively indicated:
Unless specifically excluded, products are included in this scope regardless of levels of boron and titanium.
For example, specifically included in this scope are vacuum degassed, fully stabilized (commonly referred to as interstitial-free (IF)) steels, high strength low alloy (HSLA) steels, the substrate for motor lamination steels, Advanced High Strength Steels (AHSS), and Ultra High Strength Steels (UHSS). IF steels are recognized as low carbon steels with micro-alloying levels of elements such as titanium and/or niobium added to stabilize carbon and nitrogen elements. HSLA steels are recognized as steels with micro-alloying levels of elements such as chromium, copper, niobium, titanium, vanadium, and molybdenum. The substrate for motor lamination steels contains micro-alloying levels of elements such as silicon and aluminum. AHSS and UHSS are considered high tensile strength and high elongation steels, although AHSS and UHSS are covered whether or not they are high tensile strength or high elongation steels.
Subject merchandise includes hot-rolled steel that has been further processed in a third country, including but not limited to pickling, oiling, levelling, annealing, tempering, temper rolling, skin passing, painting, varnishing, trimming, cutting, punching, and/or slitting, or any other processing that would not otherwise remove the merchandise from the scope of the investigations if performed in the country of manufacture of the hot-rolled steel.
All products that meet the written physical description, and in which the chemistry quantities do not exceed any one of the noted element levels listed above, are within the scope of these investigations unless specifically excluded. The following products are outside of and/or specifically excluded from the scope of this investigation:
• Universal mill plates (
• Products that have been cold-rolled (cold-reduced) after hot-rolling;
• Ball bearing steels;
• Tool steels;
• Silico-manganese steels;
The products subject to this investigation are currently classified in the Harmonized Tariff Schedule of the United States (“HTSUS”) under item numbers: 7208.10.1500, 7208.10.3000, 7208.10.6000, 7208.25.3000, 7208.25.6000, 7208.26.0030, 7208.26.0060, 7208.27.0030, 7208.27.0060, 7208.36.0030, 7208.36.0060, 7208.37.0030, 7208.37.0060, 7208.38.0015, 7208.38.0030, 7208.38.0090, 7208.39.0015, 7208.39.0030, 7208.39.0090, 7208.40.6030, 7208.40.6060, 7208.53.0000, 7208.54.0000, 7208.90.0000, 7210.70.3000, 7211.14.0030, 7211.14.0090, 7211.19.1500, 7211.19.2000, 7211.19.3000, 7211.19.4500, 7211.19.6000, 7211.19.7530, 7211.19.7560, 7211.19.7590, 7225.11.0000, 7225.19.0000, 7225.30.3050, 7225.30.7000, 7225.40.7000, 7225.99.0090, 7226.11.1000, 7226.11.9030, 7226.11.9060, 7226.19.1000, 7226.19.9000, 7226.91.5000, 7226.91.7000, and 7226.91.8000. The products subject to the investigation may also enter under the following HTSUS numbers: 7210.90.9000, 7211.90.0000, 7212.40.1000, 7212.40.5000, 7212.50.0000, 7214.91.0015, 7214.91.0060, 7214.91.0090, 7214.99.0060, 7214.99.0075, 7214.99.0090, 7215.90.5000, 7226.99.0180, and 7228.60.6000.
The HTSUS subheadings above are provided for convenience and U.S. Customs purposes only. The written description of the scope of the investigation is dispositive.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice; issuance of an incidental harassment authorization.
In accordance with the Marine Mammal Protection Act (MMPA) implementing regulations, we hereby give notice that we have issued an Incidental Harassment Authorization (Authorization) to Lamont-Doherty Earth Observatory (Lamont-Doherty), a component of Columbia University, in collaboration with the National Science Foundation (NSF), to take marine mammals, by harassment, in the South Atlantic Ocean, January through March 2016.
Effective January 4 through March 31, 2016.
A copy of the final Authorization and application and other supporting documents are available by writing to Jolie Harrison, Chief, Permits and Conservation Division, Office of Protected Resources, National Marine Fisheries Service, 1315 East-West Highway, Silver Spring, MD 20910, by telephoning the contacts listed here, or by visiting the internet at:
The NSF prepared a draft Environmental Analysis in accordance with Executive Order 12114, “Environmental Effects Abroad of Major Federal Actions” for their proposed federal action. The environmental analysis titled “Environmental Analysis of a Marine Geophysical Survey by the R/V
NMFS prepared an Environmental Assessment (EA) titled, “Proposed Issuance of an Incidental Harassment Authorization to Lamont-Doherty Earth Observatory to Take Marine Mammals by Harassment Incidental to a Marine Geophysical Survey in the South Atlantic Ocean, January–March 2016,” in accordance with NEPA and NOAA Administrative Order 216–6. To obtain an electronic copy of these documents, write to the previously mentioned address, telephone the contact listed here (see
NMFS also issued a Biological Opinion under section 7 of the Endangered Species Act (ESA) to evaluate the effects of the survey and Authorization on marine species listed as threatened and endangered. The Biological Opinion is available online at:
Jeannine Cody, NMFS, Office of Protected Resources, NMFS (301) 427–8401.
Section 101(a)(5)(D) of the Marine Mammal Protection Act of 1972, as amended (MMPA; 16 U.S.C. 1361
An Authorization shall be granted for the incidental taking of small numbers of marine mammals if NMFS finds that the taking will have a negligible impact on the species or stock(s), and will not have an unmitigable adverse impact on the availability of the species or stock(s) for subsistence uses (where relevant). The Authorization must also set forth the permissible methods of taking; other means of effecting the least practicable adverse impact on the species or stock and its habitat (
Except with respect to certain activities not pertinent here, the MMPA at 16 U.S.C. 1362(18)(A) defines “harassment” as: Any act of pursuit, torment, or annoyance which (i) has the
On July 29, 2015, NMFS received an application from Lamont-Doherty requesting that NMFS issue an Authorization for the take of marine mammals, incidental to Texas A&M University and the University of Texas conducting a seismic survey in the South Atlantic Ocean, January through March 2016. Following the initial application submission, Lamont-Doherty submitted a revised application with revised take estimates. NMFS considered the revised application adequate and complete on October 30, 2015.
Lamont-Doherty proposes to conduct a two-dimensional (2–D), seismic survey on the R/V
Lamont-Doherty plans to use one source vessel, the
The purpose of the survey is to collect and analyze seismic refraction data from the Mid-Atlantic Ridge westward to the Rio Grande Rise to study the evolution of the South Atlantic Ocean crust on million-year timescales and the evolution and stability of low-spreading ridges over time. NMFS refers the public to Lamont-Doherty's application (see page 3) for more detailed information on the proposed research objectives.
Lamont-Doherty proposes to conduct the seismic survey for approximately 42 days, which includes approximately 22 days of seismic surveying with 10 days of OBS deployment and retrieval. The proposed study (
Lamont-Doherty proposes to conduct the proposed seismic survey in the South Atlantic Ocean, located approximately between 10–35° W, 27–33° S (see Figure 1). Water depths in the survey area range from approximately 1,150 to 4,800 meters (m) (3,773 feet [ft] to 2.98 miles [mi]).
The proposed survey's principal investigators are Drs. R. Reece and R. Carlson (Texas A&M University) and Dr. G. Christeson (University of Texas at Austin).
The
NMFS outlined the vessel's specifications in the notice of proposed Authorization (80 FR 75355, December 1, 2015). NMFS does not repeat the information here as the vessel's specifications have not changed between the notice of proposed Authorization and this notice of an issued Authorization.
NMFS outlined the details regarding Lamont-Doherty's data acquisition activities using the airguns, multibeam echosounder, and the sub-bottom profiler in the notice of proposed Authorization (80 FR 75355, December 1, 2015). NMFS does not repeat the information here as the data acquisition activities have not changed between the notice of proposed Authorization and this notice of an issued Authorization.
For a more detailed description of the authorized action (
NMFS published a notice of receipt of Lamont-Doherty's application and proposed Authorization in the
NMFS addresses any comments specific to Lamont-Doherty's application related to the statutory and regulatory requirements or findings that NMFS must make under the MMPA in order to issue an Authorization. The following is a summary of the public comments and NMFS' responses.
Lamont-Doherty's application (LGL, 2015) and the NSF's draft environmental analyses (NSF, 2015) describe the approach to establishing mitigation exclusion and buffer zones. In summary, Lamont-Doherty acquired field measurements for several array configurations at shallow- and deep-water depths during acoustic verification studies conducted in the northern Gulf of Mexico in 2003 (Tolstoy
In 2015, Lamont-Doherty explored solutions to this issue (
Briefly, Crone's (2015) preliminary analysis, specific to the proposed survey site offshore New Jersey, confirmed that in-situ, site specific measurements and estimates of the 160- and 180-decibel (dB) isopleths collected by the
In 2010, Lamont-Doherty assessed the accuracy of their modeling approach by comparing the sound levels of the field measurements acquired in the Gulf of Mexico study to their model predictions (Diebold
In 2012, Lamont-Doherty used a similar process to model exclusion and buffer zones for a shallow-water seismic survey in the northeast Pacific Ocean offshore Washington in 2012. Lamont-Doherty conducted the shallow-water survey using the same airgun configuration proposed for this seismic survey (
The model Lamont-Doherty currently uses does not allow for the consideration of environmental and site-specific parameters as requested by the Commission. NMFS continues to work with Lamont-Doherty and the NSF to address the issue of incorporating site-specific information to further inform the analysis and development of mitigation measures in oceanic and coastal areas for future seismic surveys with Lamont-Doherty. However, Lamont-Doherty's current modeling approach (supported by the three data points discussed previously) represents the best available information for NMFS to reach determinations for the Authorization. As described earlier, the comparisons of Lamont-Doherty's model results and the field data collected in the Gulf of Mexico, offshore Washington, and offshore New Jersey illustrate a degree of conservativeness built into Lamont-Doherty's model for deep water, which NMFS expects to offset some of the limitations of the model to capture the variability resulting from site-specific factors.
Lamont-Doherty has conveyed to NMFS that additional modeling efforts to refine the process and conduct comparative analysis may be possible with the availability of research funds and other resources. Obtaining research funds is typically through a competitive process, including those submitted to U.S. Federal agencies. The use of models for calculating buffer and exclusion zone radii and for developing take estimates is not a requirement of the MMPA incidental take authorization process. Furthermore, NMFS does not provide specific guidance on model parameters nor prescribe a specific model for applicants as part of the MMPA incidental take authorization process at this time. There is a level of variability not only with parameters in the models, but also the uncertainty associated with data used in models, and therefore, the quality of the model results submitted by applicants. NMFS considers this variability when evaluating applications and the take estimates and mitigation that the model informs. NMFS takes into consideration the model used and its results in determining the potential impacts to marine mammals; however, it is just one component of the analysis during the MMPA consultation process as NMFS also takes into consideration other factors associated with the proposed action, (
Table 1 in this notice provides the following: All marine mammal species with possible or confirmed occurrence in the proposed activity area; information on those species' regulatory status under the MMPA and the Endangered Species Act of 1973 (16 U.S.C. 1531
NMFS refers the public to Lamont-Doherty's application, NSF's draft environmental analysis (see
NMFS provided a summary and discussion of the ways that the types of stressors associated with the specified activity (
The “Estimated Take by Incidental Harassment” section later in this document will include a quantitative discussion of the number of marine
NMFS provided a background of potential effects of Lamont-Doherty's activities in the notice of proposed Authorization (80 FR 75355, December 1, 2015). Operating active acoustic sources, such as airgun arrays, has the potential for adverse effects on marine mammals. The majority of anticipated impacts would be from the use of acoustic sources. The effects of sounds from airgun pulses might include one or more of the following: Tolerance, masking of natural sounds, behavioral disturbance, and temporary or permanent hearing impairment or non-auditory effects (Richardson
As outlined in previous NMFS documents, the effects of noise on marine mammals are highly variable, often depending on species and contextual factors (based on Richardson
In the
NMFS refers the reader to Lamont-Doherty's application and the NSF's environmental analysis for additional information on the behavioral reactions (or lack thereof) by all types of marine mammals to seismic vessels. NMFS has reviewed these data and based our decision on the relevant information.
NMFS included a detailed discussion of the potential effects of this action on marine mammal habitat, including physiological and behavioral effects on marine mammal prey items (
In order to issue an Incidental Harassment Authorization under section 101(a)(5)(D) of the MMPA, NMFS must set forth the permissible methods of taking pursuant to such activity, and other means of effecting the least practicable adverse impact on such species or stock and its habitat, paying particular attention to rookeries, mating grounds, and areas of similar significance, and on the availability of such species or stock for taking for certain subsistence uses (where relevant).
Lamont-Doherty has reviewed the following source documents and has
(1) Protocols used during previous Lamont-Doherty and NSF-funded seismic research cruises as approved by us and detailed in the NSF's 2011 PEIS and 2015 draft environmental analysis;
(2) Previous incidental harassment authorizations applications and authorizations that NMFS has approved and authorized; and
(3) Recommended best practices in Richardson
To reduce the potential for disturbance from acoustic stimuli associated with the activities, Lamont-Doherty, and/or its designees have proposed to implement the following mitigation measures for marine mammals:
(1) Vessel-based visual mitigation monitoring;
(2) Proposed exclusion zones;
(3) Power down procedures;
(4) Shutdown procedures;
(5) Ramp-up procedures; and
(6) Speed and course alterations.
NMFS reviewed Lamont-Doherty's proposed mitigation measures and has proposed an additional measure to effect the least practicable adverse impact on marine mammals. They are:
(1) Expanded power down procedures for concentrations of six or more whales that do not appear to be traveling (
Lamont-Doherty would position observers aboard the seismic source vessel to watch for marine mammals near the vessel during daytime airgun operations and during any start-ups at night. Observers would also watch for marine mammals near the seismic vessel for at least 30 minutes prior to the start of airgun operations after an extended shutdown (
During seismic operations, at least four protected species observers would be aboard the
Two observers on the
The
Lamont-Doherty would immediately power down or shutdown the airguns when observers see marine mammals within or about to enter the designated exclusion zone. The observer(s) would continue to maintain watch to determine when the animal(s) are outside the exclusion zone by visual confirmation. Airgun operations would not resume until the observer has confirmed that the animal has left the zone, or if not observed after 15 minutes for species with shorter dive durations (small odontocetes and pinnipeds) or 30 minutes for species with longer dive durations (mysticetes and large odontocetes, including sperm, pygmy sperm, dwarf sperm, killer, and beaked whales).
Lamont-Doherty would use safety radii to designate exclusion zones and to estimate take for marine mammals. Table 2 shows the distances at which one would expect to receive sound levels (160-, 180-, and 190-dB,) from the airgun array and a single airgun. If the protected species visual observer detects marine mammal(s) within or about to enter the appropriate exclusion zone, the
The 180- or 190-dB level shutdown criteria are applicable to cetaceans and pinnipeds respectively as specified by NMFS (2000). Lamont-Doherty used these levels to establish the exclusion zones as presented in their application.
A power down involves decreasing the number of airguns in use such that the radius of the 180-dB or 190-dB exclusion zone is smaller to the extent that marine mammals are no longer within or about to enter the exclusion zone. A power down of the airgun array can also occur when the vessel is moving from one seismic line to another. During a power down for mitigation, the
If the observer detects a marine mammal outside the exclusion zone and the animal is likely to enter the zone, the crew would power down the airguns to reduce the size of the 180-dB or 190-dB exclusion zone before the animal enters that zone. Likewise, if a mammal is already within the zone after detection, the crew would power-down the airguns immediately. During a power down of the airgun array, the crew would operate a single 40-in
Following a power-down, the
• The observer has visually observed the animal leave the exclusion zone; or
• An observer has not sighted the animal within the exclusion zone for 15 minutes for species with shorter dive durations (
The
NMFS estimates that the
The
(1) If an animal enters the exclusion zone of the single airgun after the crew has initiated a power down; or
(2) If an observer sees the animal is initially within the exclusion zone of the single airgun when more than one airgun (typically the full airgun array) is operating.
During periods of active seismic operations, there are occasions when the
If the full exclusion zone is not visible to the observer for at least 30 minutes prior to the start of operations in either daylight or nighttime, the
If one airgun has operated during a power down period, ramp-up to full power would be permissible at night or in poor visibility, on the assumption that marine mammals would be alerted to the approaching seismic vessel by the sounds from the single airgun and could move away. The vessel's crew would not initiate a ramp-up of the airguns if an observer sees the marine mammal within or near the applicable exclusion zones during the day or close to the vessel at night.
Ramp-up of an airgun array provides a gradual increase in sound levels, and involves a step-wise increase in the number and total volume of airguns firing until the full volume of the airgun array is achieved. The purpose of a ramp-up is to “warn” marine mammals in the vicinity of the airguns, and to provide the time for them to leave the area and thus avoid any potential injury or impairment of their hearing abilities. Lamont-Doherty would follow a ramp-up procedure when the airgun array begins operating after an 8 minute period without airgun operations or when shut down has exceeded that period. Lamont-Doherty has used similar waiting periods (approximately eight to 10 minutes) during previous seismic surveys.
Ramp-up would begin with the smallest airgun in the array (40 in
If the complete exclusion zone has not been visible for at least 30 minutes prior to the start of operations in either daylight or nighttime, Lamont-Doherty would not commence the ramp-up unless at least one airgun (40 in
The
If during seismic data collection, Lamont-Doherty detects marine mammals outside the exclusion zone and, based on the animal's position and direction of travel, is likely to enter the exclusion zone, the
NMFS has carefully evaluated Lamont-Doherty's proposed mitigation measures in the context of ensuring that we prescribe the means of effecting the least practicable impact on the affected marine mammal species and stocks and their habitat. Our evaluation of potential measures included consideration of the following factors in relation to one another:
• The manner in which, and the degree to which, the successful implementation of the measure is expected to minimize adverse impacts to marine mammals;
• The proven or likely efficacy of the specific measure to minimize adverse impacts as planned; and
• The practicability of the measure for applicant implementation.
Any mitigation measure(s) prescribed by NMFS should be able to accomplish, have a reasonable likelihood of accomplishing (based on current science), or contribute to the accomplishment of one or more of the general goals listed here:
1. Avoidance or minimization of injury or death of marine mammals wherever possible (goals 2, 3, and 4 may contribute to this goal).
2. A reduction in the numbers of marine mammals (total number or number at biologically important time or location) exposed to airgun operations that we expect to result in the take of marine mammals (this goal may contribute to 1, above, or to reducing harassment takes only).
3. A reduction in the number of times (total number or number at biologically important time or location) individuals would be exposed to airgun operations that we expect to result in the take of marine mammals (this goal may contribute to 1, above, or to reducing harassment takes only).
4. A reduction in the intensity of exposures (either total number or number at biologically important time or location) to airgun operations that we expect to result in the take of marine mammals (this goal may contribute to 1, above, or to reducing the severity of harassment takes only).
5. Avoidance or minimization of adverse effects to marine mammal habitat, paying special attention to the food base, activities that block or limit passage to or from biologically important areas, permanent destruction of habitat, or temporary destruction/disturbance of habitat during a biologically important time.
6. For monitoring directly related to mitigation—an increase in the probability of detecting marine mammals, thus allowing for more effective implementation of the mitigation.
Based on the evaluation of Lamont-Doherty's proposed measures, as well as other measures proposed by NMFS (
In order to issue an Incidental Harassment Authorization for an activity, section 101(a)(5)(D) of the MMPA states that NMFS must set forth “requirements pertaining to the monitoring and reporting of such taking.” The MMPA implementing regulations at 50 CFR 216.104 (a)(13) indicate that requests for Authorizations must include the suggested means of accomplishing the necessary monitoring and reporting that will result in increased knowledge of the species and of the level of taking or impacts on populations of marine mammals that we expect to be present in the proposed action area.
Lamont-Doherty submitted a marine mammal monitoring plan in section XIII of the Authorization application. NMFS, NSF, or Lamont-Doherty may modify or supplement the plan based on comments or new information received from the public during the public comment period.
Monitoring measures prescribed by NMFS should accomplish one or more of the following general goals:
1. An increase in the probability of detecting marine mammals, both within the mitigation zone (thus allowing for more effective implementation of the mitigation) and during other times and locations, in order to generate more data to contribute to the analyses mentioned later;
2. An increase in our understanding of how many marine mammals would be affected by seismic airguns and other active acoustic sources and the likelihood of associating those exposures with specific adverse effects, such as behavioral harassment, temporary or permanent threshold shift;
3. An increase in our understanding of how marine mammals respond to stimuli that we expect to result in take and how those anticipated adverse effects on individuals (in different ways and to varying degrees) may impact the population, species, or stock (specifically through effects on annual
a. Behavioral observations in the presence of stimuli compared to observations in the absence of stimuli (
b. Physiological measurements in the presence of stimuli compared to observations in the absence of stimuli (
c. Distribution and/or abundance comparisons in times or areas with concentrated stimuli versus times or areas without stimuli;
4. An increased knowledge of the affected species; and
5. An increase in our understanding of the effectiveness of certain mitigation and monitoring measures.
Lamont-Doherty proposes to sponsor marine mammal monitoring during the present project to supplement the mitigation measures that require real-time monitoring, and to satisfy the monitoring requirements of the Authorization. Lamont-Doherty understands that NMFS would review the monitoring plan and may require refinements to the plan. Lamont-Doherty planned the monitoring work as a self-contained project independent of any other related monitoring projects that may occur in the same regions at the same time. Further, Lamont-Doherty is prepared to discuss coordination of its monitoring program with any other related work that might be conducted by other groups working insofar as it is practical for Lamont-Doherty.
Passive acoustic monitoring would complement the visual mitigation monitoring program, when practicable. Visual monitoring typically is not effective during periods of poor visibility or at night, and even with good visibility, is unable to detect marine mammals when they are below the surface or beyond visual range. Passive acoustic monitoring can improve detection, identification, and localization of cetaceans when used in conjunction with visual observations. The passive acoustic monitoring would serve to alert visual observers (if on duty) when vocalizing cetaceans are detected. It is only useful when marine mammals call, but it can be effective either by day or by night, and does not depend on good visibility. The acoustic observer would monitor the system in real time so that he/she can advise the visual observers if they acoustically detect cetaceans.
The passive acoustic monitoring system consists of hardware (
One acoustic observer, an expert bioacoustician with primary responsibility for the passive acoustic monitoring system would be aboard the
One acoustic observer would monitor the acoustic detection system by listening to the signals from two channels via headphones and/or speakers and watching the real-time spectrographic display for frequency ranges produced by cetaceans. The observer monitoring the acoustical data would be on shift for one to six hours at a time. The other observers would rotate as an acoustic observer, although the expert acoustician would be on passive acoustic monitoring duty more frequently.
When the acoustic observer detects a vocalization while visual observations are in progress, the acoustic observer on duty would contact the visual observer immediately, to alert him/her to the presence of cetaceans (if they have not already been seen), so that the vessel's crew can initiate a power down or shutdown, if required. The observer would enter the information regarding the call into a database. Data entry would include an acoustic encounter identification number, whether it was linked with a visual sighting, date, time when first and last heard and whenever any additional information was recorded, position and water depth when first detected, bearing if determinable, species or species group (
Observers would record data to estimate the numbers of marine mammals exposed to various received sound levels and to document apparent disturbance reactions or lack thereof. They would use the data to help better understand the impacts of the activity on marine mammals and to estimate numbers of animals potentially `taken' by harassment (as defined in the MMPA). They will also provide information needed to order a power down or shut down of the airguns when a marine mammal is within or near the exclusion zone.
When an observer makes a sighting, they will record the following information:
1. Species, group size, age/size/sex categories (if determinable), behavior when first sighted and after initial sighting, heading (if consistent), bearing and distance from seismic vessel, sighting cue, apparent reaction to the airguns or vessel (
2. Time, location, heading, speed, activity of the vessel, sea state, visibility, and sun glare.
The observer will record the data listed under (2) at the start and end of each observation watch, and during a watch whenever there is a change in one or more of the variables.
Observers will record all observations and power downs or shutdowns in a standardized format and will enter data into an electronic database. The observers will verify the accuracy of the data entry by computerized data validity checks during data entry and by subsequent manual checking of the database. These procedures will allow the preparation of initial summaries of data during and shortly after the field program, and will facilitate transfer of
Results from the vessel-based observations will provide:
1. The basis for real-time mitigation (airgun power down or shutdown).
2. Information needed to estimate the number of marine mammals potentially taken by harassment, which Lamont-Doherty must report to the Office of Protected Resources.
3. Data on the occurrence, distribution, and activities of marine mammals and turtles in the area where Lamont-Doherty would conduct the seismic study.
4. Information to compare the distance and distribution of marine mammals and turtles relative to the source vessel at times with and without seismic activity.
5. Data on the behavior and movement patterns of marine mammals detected during non-active and active seismic operations.
Lamont-Doherty would submit a report to us and to NSF within 90 days after the end of the cruise. The report would describe the operations conducted and sightings of marine mammals near the operations. The report would provide full documentation of methods, results, and interpretation pertaining to all monitoring. The 90-day report would summarize the dates and locations of seismic operations, and all marine mammal sightings (dates, times, locations, activities, associated seismic survey activities). The report would also include estimates of the number and nature of exposures that occurred above the harassment threshold based on the observations. The report would consider both published literature and previous monitoring results that could inform the detectability of different species and how that information affects post survey exposure estimates.
In the unanticipated event that the specified activity clearly causes the take of a marine mammal in a manner not permitted by the authorization (if issued), such as an injury, serious injury, or mortality (
• Time, date, and location (latitude/longitude) of the incident;
• Name and type of vessel involved;
• Vessel's speed during and leading up to the incident;
• Description of the incident;
• Status of all sound source use in the 24 hours preceding the incident;
• Water depth;
• Environmental conditions (
• Description of all marine mammal observations in the 24 hours preceding the incident;
• Species identification or description of the animal(s) involved;
• Fate of the animal(s); and
• Photographs or video footage of the animal(s) (if equipment is available).
Lamont-Doherty shall not resume its activities until we are able to review the circumstances of the prohibited take. We shall work with Lamont-Doherty to determine what is necessary to minimize the likelihood of further prohibited take and ensure MMPA compliance. Lamont-Doherty may not resume their activities until notified by us via letter, email, or telephone.
In the event that Lamont-Doherty discovers an injured or dead marine mammal, and the lead visual observer determines that the cause of the injury or death is unknown and the death is relatively recent (
In the event that Lamont-Doherty discovers an injured or dead marine mammal, and the lead visual observer determines that the injury or death is not associated with or related to the authorized activities (
Except with respect to certain activities not pertinent here, section 3(18) of the MMPA defines “harassment” as: Any act of pursuit, torment, or annoyance which (i) has the potential to injure a marine mammal or marine mammal stock in the wild [Level A harassment]; or (ii) has the potential to disturb a marine mammal or marine mammal stock in the wild by causing disruption of behavioral patterns, including, but not limited to, migration, breathing, nursing, breeding, feeding, or sheltering [Level B harassment].
Acoustic stimuli (
NMFS' practice is to apply the 160 dB re: 1 μPa received level threshold for underwater impulse sound levels to predict whether behavioral disturbance that rises to the level of Level B harassment is likely to occur. NMFS' practice is to apply the 180 dB or 190 dB re: 1 μPa received level threshold for underwater impulse sound levels to predict whether permanent threshold shift (auditory injury), which we consider as Level A harassment is likely to occur.
Given the many uncertainties in predicting the quantity and types of impacts of sound on marine mammals, it is common practice to estimate how many animals are likely to be present within a particular distance of a given activity, or exposed to a particular level of sound, and use that information to predict how many animals are taken. In practice, depending on the amount of information available to characterize daily and seasonal movement and distribution of affected marine mammals, distinguishing between the numbers of individuals harassed and the instances of harassment can be difficult to parse. Moreover, when one considers the duration of the activity, in the absence of information to predict the degree to which individual animals are likely exposed repeatedly on subsequent days, the simple assumption is that entirely new animals are exposed every day, which results in a take estimate that in some circumstances overestimates the number of individuals harassed.
The following sections describe NMFS' methods to estimate take by incidental harassment. We base these estimates on the number of marine mammals that could be potentially harassed by seismic operations with the airgun array during approximately 3,236 km (2,028 mi) of transect lines in the South Atlantic Ocean.
(1) Calculate the total area that the
(2) Multiply each daily ensonified area above the 160-dB Level B harassment threshold by the species' density (animals/km
(3) Multiply each product (
(4) Multiply the daily ensonified area by each species-specific density to derive the predicted number of instances of exposures to received levels greater than or equal to 180-dB re: 1 μPa for cetaceans on a given day (
(5) Multiply each product by the number of survey days that includes a 25 percent contingency (
In many cases, this estimate of instances of exposures is likely an overestimate of the number of individuals that are taken, because it assumes 100 percent turnover in the area every day, (
NMFS used sighting information from a survey off Namibia, Africa (Rose and Payne, 1991) to estimate a mean group size for southern right whale dolphins (58) and also multiplied that estimate by 28 days to derive an estimate of take from a potential encounter with that species.
Lamont-Doherty did not estimate any additional take from sound sources other than airguns. NMFS does not expect the sound levels produced by the echosounder and sub-bottom profiler to exceed the sound levels produced by
NMFS considers the probability for entanglement of marine mammals as low because of the vessel speed and the monitoring efforts onboard the survey vessel. Therefore, NMFS does not believe it is necessary to authorize additional takes for entanglement at this time.
The
There is no evidence that the planned survey activities could result in serious injury or mortality within the specified geographic area for the requested proposed Authorization. The required mitigation and monitoring measures would minimize any potential risk for serious injury or mortality.
Negligible impact is “an impact resulting from the specified activity that cannot be reasonably expected to, and is not reasonably likely to, adversely affect the species or stock through effects on annual rates of recruitment or survival” (50 CFR 216.103). The lack of likely adverse effects on annual rates of recruitment or survival (
In making a negligible impact determination, NMFS considers:
• The number of anticipated injuries, serious injuries, or mortalities;
• The number, nature, and intensity, and duration of harassment; and
• The context in which the takes occur (
• The status of stock or species of marine mammals (
• Impacts on habitat affecting rates of recruitment/survival; and
• The effectiveness of monitoring and mitigation measures to reduce the number or severity of incidental takes.
To avoid repetition, our analysis applies to all the species listed in Table 5, given that NMFS expects the anticipated effects of the seismic airguns to be similar in nature. Where there are meaningful differences between species or stocks, or groups of species, in anticipated individual responses to activities, impact of expected take on the population due to differences in population status, or impacts on habitat, NMFS has identified species-specific factors to inform the analysis.
Given the required mitigation and related monitoring, NMFS does not anticipate that serious injury or mortality would occur as a result of Lamont-Doherty's proposed seismic survey in the South Atlantic Ocean. Thus the proposed authorization does not authorize any mortality.
NMFS' predicted estimates for Level A harassment take for some species are likely overestimates of the injury that will occur. NMFS expects that successful implementation of the required visual and acoustic mitigation measures would avoid Level A take in some instances. Also, NMFS expects that some individuals would avoid the source at levels expected to result in injury. Nonetheless, although NMFS expects that Level A harassment is unlikely to occur at the numbers proposed to be authorized, because it is difficult to quantify the degree to which the mitigation and avoidance will reduce the number of animals that might incur PTS, we are proposing to authorize, and have included in our analyses, the modeled number of Level A takes, which does not take the mitigation or avoidance into consideration. However, because of the constant movement of the
Of the marine mammal species under our jurisdiction that are known to occur or likely to occur in the study area, the following species are listed as endangered under the ESA: Blue, fin, humpback, sei, Southern right whale, and sperm whales. The western north Atlantic population of humpback whales is known to be increasing. The other marine mammal species that may be taken by harassment during Lamont-Doherty's seismic survey program are not listed as threatened or endangered under the ESA.
Potential impacts to marine mammal habitat were discussed previously in this document (see the “Anticipated Effects on Habitat” section). Although some disturbance is possible to food sources of marine mammals, the impacts are anticipated to be minor enough as to not affect annual rates of recruitment or survival of marine mammals in the area. Based on the size of the South Atlantic Ocean where feeding by marine mammals occurs versus the localized area of the marine survey activities, any missed feeding opportunities in the direct project area will be minor based on the fact that other feeding areas exist elsewhere. Taking into account the planned mitigation measures, effects on cetaceans are generally expected to be restricted to avoidance of a limited area around the survey operation and short-term changes in behavior, falling within the MMPA definition of “Level B harassment.” Animals are not expected to permanently abandon any area that is surveyed, and any behaviors that are interrupted during the activity are expected to resume once the activity ceases. Only a small portion of marine mammal habitat will be affected at any time, and other areas within the South
Many animals perform vital functions, such as feeding, resting, traveling, and socializing, on a diel cycle (
For reasons stated previously in this document and based on the following factors, Lamont-Doherty's specified activities are not likely to cause long-term behavioral disturbance, serious injury, or death, or other effects that would be expected to adversely affect reproduction or survival of any individuals. They include:
• The anticipated impacts of Lamont-Doherty's survey activities on marine mammals are temporary behavioral changes due, primarily, to avoidance of the area;
• The likelihood that, given the constant movement of boat and animals and the nature of the survey design (not concentrated in areas of high marine mammal concentration), PTS incurred would be of a low level;
• The availability of alternate areas of similar habitat value for marine mammals to temporarily vacate the survey area during the operation of the airgun(s) to avoid acoustic harassment;
• The expectation that the seismic survey would have no more than a temporary and minimal adverse effect on any fish or invertebrate species that serve as prey species for marine mammals, and therefore consider the potential impacts to marine mammal habitat minimal; and
• The knowledge that the survey is taking place in the open ocean and not located within an area of biological importance for breeding, calving, or foraging for marine mammals.
Table 4 in this document outlines the number of requested Level A and Level B harassment takes that we anticipate as a result of these activities.
Required mitigation measures, such as special shutdowns for large whales, vessel speed, course alteration, and visual monitoring would be implemented to help reduce impacts to marine mammals. Based on the analysis herein of the likely effects of the specified activity on marine mammals and their habitat, and taking into consideration the implementation of the proposed monitoring and mitigation measures, NMFS finds that Lamont-Doherty's proposed seismic survey would have a negligible impact on the affected marine mammal species or stocks.
As mentioned previously, NMFS estimates that Lamont-Doherty's activities could potentially affect, by Level B harassment, 38 species of marine mammals under our jurisdiction. NMFS estimates that Lamont-Doherty's activities could potentially affect, by Level A harassment, up to 16 species of marine mammals under our jurisdiction.
For each species, the numbers of take being proposed for authorization are small numbers relative to the population sizes: Less than 16 percent for striped dolphins, less than 8 percent of Risso's dolphins, less than 6 percent for pantropical spotted dolphins, and less than 4 percent for all other species. NMFS has provided the regional population and take estimates for the marine mammal species that may be taken by Level A and Level B harassment in Table 4 in this notice. NMFS finds that the proposed incidental take described in Table 4 for the proposed activity would be limited to small numbers relative to the affected species or stocks.
There are no relevant subsistence uses of marine mammals implicated by this action.
There are six marine mammal species listed as endangered under the Endangered Species Act that may occur in the proposed survey area. Under section 7 of the ESA, NSF initiated formal consultation with NMFS on the proposed seismic survey. NMFS (
In January, 2016, the Endangered Species Act Interagency Cooperation Division issued a Biological Opinion with an Incidental Take Statement to us and to the NSF, which concluded that the issuance of the Authorization and the conduct of the seismic survey were not likely to jeopardize the continued existence of blue, fin, humpback, sei, South Atlantic right and sperm whales. The Biological Opinion also concluded that the issuance of the Authorization and the conduct of the seismic survey would not affect designated critical habitat for these species.
NSF has prepared an environmental analysis titled “
NMFS has issued an Incidental Harassment Authorization to Lamont-Doherty for the take of marine mammals, incidental to conducting a marine seismic survey in the South Atlantic Ocean January through March 2016.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Issuance seven new scientific research permits, and fourteen renewal scientific research permits.
Notice is hereby given that NMFS has issued Permit 1440–2R to the Interagency Ecological Program (IEP); Permit 13675–2R to the Fishery Foundation of California (FFC); Permit 13791–2R to the United States Fish and Wildlife Service (USFWS), Stockton Fish and Wildlife Office (SFWO); Permit 14516–2R to Dr. Jerry Smith, Associate Professor in the Department of Biological Sciences at San Jose State University; Permit 15215 to the California Department of Fish and Wildlife (CDFW), Fisheries Branch, Fish Health Laboratory; Permit 16274 to the Mendocino Redwood Company (MRC); Permit 17063 to the United States Forest Service (USFS), Redwood Sciences Laboratory; Permit 17077–2R to Dr. Peter Moyle, with the University of California at Davis, Department of Wildlife, Fish and Conservation Biology; Permit 17219 and Permit 19320 to the NMFS Southwest Fisheries Science Center (SWFSC), Fisheries Ecology Division; Permit 17272 to the USFWS, Arcata Fish and Wildlife Office Fisheries Program (AFWO); Permit 17351 to the Green Diamond Resource Company (GDRC); Permit 17396 to the USFWS, Anadromous Fish Restoration Program (AFRP); Permit 17867 to the Humboldt Redwood Company (HRC); Permit 17877 to the Bureau of Reclamation (BOR); Permit 17916 to the Bureau of Land Management (BLM), Arcata Field Office; Permit 18012 to the CDFW, Bay Delta Region; Permit 18712 to H.T. Harvey & Associates; Permit 18937 to the Scripps Institution of Oceanography, University of California, San Diego, California Sea Grant College Program (CSGCP); Permit 19121 to the United States Geological Survey (USGS), California Water Survey; and Permit 19400 to ICF consulting.
The approved application for each permit is available on the Applications and Permits for Protected Species (APPS),
Jeff Abrams, Santa Rosa, CA (ph.: 707–575–6080), Fax: 707–578–3435, email:
The issuance of permits and permit modifications, as required by the Endangered Species Act of 1973 (16 U.S.C. 1531–1543) (ESA), is based on a finding that such permits/modifications: (1) Are applied for in good faith; (2) would not operate to the disadvantage of the listed species which are the subject of the permits; and (3) are consistent with the purposes and policies set forth in section 2 of the ESA. Authority to take listed species is subject to conditions set forth in the permits. Permits and modifications are issued in accordance with and are subject to the ESA and NMFS regulations (50 CFR parts 222–226) governing listed fish and wildlife permits.
The following listed species are covered in this notice:
Chinook salmon (
Coho salmon (
Steelhead (
North American green sturgeon (
Eulachon (
A notice of receipt of an application for scientific research permit renewal (1440–2R) was published in the
Permit 1440–2R authorizes IEP to take CVSR Chinook salmon, SRWR Chinook salmon, CCV steelhead, CCC steelhead and sDPS green sturgeon while conducting 11 surveys in the San Francisco Bay-Delta region. The studies examine the abundance, and temporal and spatial distribution of various life stages of pelagic fishes of management concern, including listed species, and their food (
A notice of receipt of an application for scientific research permit renewal (13675–2R) was published in the
Permit 13675–2R authorizes the FFC annually take juvenile-CVSR Chinook salmon, SRWR Chinook salmon, CCV steelhead, and sDPS green sturgeon while conducting research designed to monitor the use of the Fremont Landing Conservation Bank (FLCB) and the Bullock Bend Mitigation Bank (BBMB) at the confluence of the Sacramento and Feather rivers in California's Central Valley. The banks are restored areas that provides mitigation for impacts on listed salmonid species in the Central Valley. The monitoring will evaluate the use of the FLCB and the BBMB by listed fish, provide data directly related to success criteria described in the conservation/mitigation bank management plan, and benefit listed fish by informing adaptive management strategies being conducted at the FLCB and the BBMB. The researchers will use beach seines and fyke nets to capture listed fish. Once captured, all listed fish will be identified by species and released. A subsample will be measured for fork length. No anesthesia will be used, and no additional handling procedures would take place. Captured fish will remain completely wetted at all times to minimize stress. Any fish exhibiting signs of physiological stress would be immediately released. The researchers are not proposing to kill any of the fish they capture, but some may die as an unintended result of the research.
A notice of receipt of an application for scientific research permit renewal (13791–2R) was published in the
Permit 13791–2R authorizes the USFWS SFWO to annually take juvenile and smolt CVSR Chinook salmon, SRWR Chinook salmon, CCV steelhead, and juvenile and larval sDPS green sturgeon while conducting seven research studies. The purpose of the studies is to evaluate/monitor the: (1) Abundance, temporal and spatial distribution, and survival of salmonids and other fishes in the lower Sacramento and San Joaquin rivers and the San Francisco Estuary (SFE); (2) occurrence and habitat use of fishes, especially early life history stages, within the Liberty Island and Cache Slough Complex, (3) relative gear efficiencies for all IEP fish survey nets, and also the distribution of delta smelt; (4) littoral habitat use of juvenile Chinook salmon within the Delta; (5) the effect of projected water operations on delta smelt; (6) length at date race criteria of SRWR Chinook salmon sized juvenile Chinook salmon; and (7) SRWR and CVSR Chinook salmon floodplain usage in the Yolo bypass. These studies will result in capture/handle/release take, tissue sampling, and/or intentional directed mortality. Intentional directed mortality will apply to only juvenile hatchery adipose clipped salmonids and larval green sturgeon. Capture methods will include Kodiak trawl, midwater trawl, beach seine, zooplankton net, larval net, gill net, fyke net, purse seine, and boat electrofishing. All listed fish except adipose fin clipped SRWR and CVSR Chinook salmon will be immediately collected from the sampling gears, placed in containers filled with river water collected at the location being sampled, processed, held in a recovery container filled with aerated river water, and subsequently released at the sampled location. A fin tissue sample will be collected from a subset of natural origin SRWR and CVSR Chinook salmon for stock determination. The purpose of intentional mortality of hatchery origin (adipose clipped) SRWR and CVSR Chinook salmon will be to collect coded wire tags (CWT), and up ten green sturgeon larvae will be killed during larval fish collections in order to identify the contents of the larval trawl net, which can only be achieved in the lab. The data provided by these studies will provide natural resource managers real-time biological and population data on fishes to evaluate the effect of water operations and fish management practices within the SFE, thereby benefiting listed fish.
A notice of receipt of an application for scientific research permit renewal (14516–2R) was published in the
Permit 14516–2R authorizes Dr. Jerry Smith, Associate Professor in the Department of Biological Sciences at San Jose State University to annually take multiple life stages of CCC coho salmon and CCC steelhead while conducting two studies: (1) Stream and lagoon surveys in Gazos Creek, Waddell Creek, and Scott Creek; and (2) lagoon surveys in Pescadero Creek Lagoon and San Gregorio Lagoon. The purpose of the studies is to: (1) Provide an annual index of relative abundance for juvenile listed salmonids, provide data on lagoon and upstream habitat utilization and growth, and provide an assessment of trends and year to year response to variations in habitat conditions; and (2) determine juvenile listed salmonid abundance and growth, and provide adult life history information in the lagoons. Capture methods will include backpack electrofishing, and beach seine. Captured salmonids will be measured, and a subset of juvenile captures and all adults will have scale samples taken, before being released at the capture location. A subsample of juvenile steelhead will also be marked via caudal fin clip to perform a mark-recapture analysis. Scale and fin tissue samples will be taken from adult fish carcasses. Captured live fish will be held in flow-through live cars, covered with a towel to provide shade and cover to calm fish. Adult fish will be processed and released first. In lagoons, live cars will be kept in deeper water with cooler temperatures and less turbidity to prevent warming above ambient temperatures or a decrease in dissolved oxygen. The researchers are not proposing to kill any of the fish they capture, but a small number may die as an unintended result of the activities.
A notice of receipt of an application for scientific research permit (15215)
Permit 15215 authorizes the CDFW, Fisheries Branch, Fish Health Laboratory to take endangered SRWR Chinook salmon, CCC coho salmon and SC steelhead for a period of five years. The purpose of the research is to investigate wild fish kills/disease outbreaks that could occur in California that involve federally listed endangered species. The research will benefit the listed species by providing fisheries managers with the necessary information to help alleviate future outbreaks of fish disease through proper management of fishery and water resources. The research will only be conducted in the event of elevated and unexplained endangered species mortality or the presence of clinically diseased animals. Given such a triggering event, endangered fish will be collected in any of the state waters of California in which a disease outbreak/fish die-off occurred. Adult and juvenile endangered fish will be collected by hand or dip-net, as only dead and/or moribund fish, or fish displaying clinical signs of disease, will be collected. Moribund or clinically diseased fish will be euthanized (
A notice of receipt of an application for scientific research permit renewal (16274) was published in the
Permit 16274 authorizes the MRC to take CC Chinook salmon, SONCC coho salmon, CCC coho salmon, NC steelhead, and CCC steelhead while conducting research and monitoring to assess juvenile and adult populations of salmonids and their distribution in streams within MRC's property. Research will be conducted in several watersheds within Mendocino and northern Sonoma counties. The data gathered will benefit listed fish by informing a better understanding of salmonid distribution, abundance, and habitat utilization in these areas. Juvenile salmonids will be captured by backpack electrofishing, anesthetized, weighed, measured to fork length, and released. A subsample of juvenile salmonids will be fin clipped to mark and to collect tissue samples for genetic analysis. Live adults and/or juveniles will be observed via snorkel surveys and spawning surveys. Carcasses will be measured and then marked to ensure duplicate measurements were not made. Outmigrant trapping will be conducted using a rotary screw trap or weir/pipe trap; captured outmigrants will be anesthetized, measured, and released. A subsample of outmigrants will be marked (dye, elastomer, or fin clip) or Passive Integrated Transponder (PIT) tagged. All anesthetized fish will be allowed to recover in a bucket containing aerated natal water prior to being released back into the stream from which they were taken. The researchers are not proposing to kill any of the fish they capture, but a small number may die as an unintended result of the activities.
A notice of receipt of an application for scientific research permit renewal (17063) was published in the
Permit 170963 authorizes the USFS, Redwood Sciences Laboratory to perform eight studies that together will take CC Chinook salmon, SONCC coho salmon, CCC coho salmon, NC steelhead, CC steelhead, and SC steelhead. The purposes of the eight studies are: (1) To investigate the invasion history of non-listed speckled dace in the Van Duzen River and the Eel River, (2) to investigate the invasion history of non-listed California roach in the Van Duzen River and the Eel River, (3) to develop an Individual Based Modeling (IBM) approach to predict the effects of management practices on salmonid population in Northern California, (4) to link abiotic factors (
A notice of receipt of an application for scientific research permit renewal (17077–2R) was published in the
Permit 17077–2R authorizes Dr. Peter Moyle, with the University of California at Davis, Department of Wildlife, Fish and Conservation Biology, to take listed species while conducting research designed to develop a better understanding of how physical habitat, flow and other factors interact to maintain assemblages of native and non-native aquatic species in the upper SFE. This study will provide knowledge about food web and habitat support for native fishes, including listed anadromous fish, which are suspected of utilizing such habitats during development. While listed fish are not the target species for this study, the study will benefit listed fish by improving management decisions regarding creating additional habitat, and helping to anticipate the effects of drought and climate change on food and habitat availability. Sampling will be conducted in three distinct regions of the SFE: (1) The Cache-Lindsey complex, (2) the Sherman Lake complex
A notice of receipt of an application for scientific research permit renewal (17219) was published in the
Permit 17219 authorizes the NMFS SWFSC, Fisheries Ecology Division to conduct research throughout California that will include take of SRWR Chinook salmon, CVSR Chinook salmon, SONCC coho salmon, CCC coho salmon, NC steelhead, CCC steelhead, CCV steelhead, S–CCC steelhead, SC steelhead, and juvenile sDPS green sturgeon. The research will benefit listed fish by supporting conservation and management of listed anadromous salmonids and green sturgeon in California by directly addressing information needs identified by NMFS and other agencies. FED studies address priority topics identified in NMFS technical recovery team reports, NMFS recovery plans, joint programs such as the California Coastal Monitoring Program developed by NMFS and CDFW, and state programs such as the Fisheries Restoration Grant Program. Research objectives of specific studies include: (1) Estimating population abundance and dynamics; (2) evaluating factors affecting growth, survival, and life-history; (3) assessing life-stage specific habitat use and movement; (4) collecting data necessary to construct various types of models (
Research and take will involve various life stages (juvenile, smolt, adult, and carcass). Listed fish will be observed during spawning surveys, and captured by electrofishing, beach seine, rotary screw trap, and/or hook-and-line. The majority of captured fish will be anesthetized, measured to fork length, and released. A subsample of captured fish will be further sampled by collection of scales, fin clips, gill clips or stomach contents; and/or marking or tagging including fin tissue clips, PIT tags, elastomer tags, acoustic tags, or radio tags. Species care after capture will include use of aerated buckets or live cars for holding and recovery, and minimization of handling time. The majority of fish captured will be released alive at their point of capture following recovery from handling. However, in limited cases some fish will be: (1) Retained in enclosures in streams for short-term growth and survival experiments and then released, or (2) euthanized for analysis of otoliths and/or parasitological/pathological studies of parasites and diseases of wild juvenile steelhead.
A notice of receipt of an application for scientific research permit renewal (17272) was published in the
Permit 17272 authorizes the USFWS AFWO to take multiple life stages of hatchery and wild SONCC coho salmon via monitoring and research activities in Northwest California. The purposes of the five studies included are to monitor: (1) Chinook salmon fry production and disease incidence in the Klamath River below Iron Gate dam, (2) Chinook salmon escapement in the mainstem Klamath River below the Shasta River confluence, (3) Chinook salmon escapement in the mainstem Klamath River from Iron Gate dam to the Shasta River confluence, (4) coho salmon escapement between Iron Gate Dam and the Indian Creek confluence, and (5) long-term salmonid disease incidence in the lower Klamath River. Trained AFWO crews will conduct redd surveys, on foot and from rafts, which could observe/harass spawning SONCC coho salmon. Crews will spend minimal time around redds and avoid walking on redds. Trained AFWO crews will also capture juvenile SONCC coho salmon using rotary-screw traps, frame nets, and beach seines. Juvenile coho salmon will be held in aerated holding buckets filled with fresh river water then anesthetized, measured for fork length, weighed, and released back into the river. There will be some intentional mortality of hatchery juvenile coho salmon for disease analysis. Aside from these hatchery fish, the researchers are not proposing to kill any of the fish they capture, but a small number may die as an unintended result of the activities. The studies will benefit listed coho salmon by informing the AFWO goal to develop conservation strategies for aquatic resources and to evaluate the success of aquatic habitat restoration efforts that will lead to the recovery and conservation of fish populations and fisheries in northern California.
A notice of receipt of an application for scientific research permit renewal (17351) was published in the
Permit 17351 authorizes the GDRC to take listed salmonids while conducting research and monitoring under an existing Aquatic Habitat Conservation Plan (AHCP). The AHCP, which was approved in 2007 and is valid until 2057, identifies potential threats to three listed fish species that may result from GDRC's timber harvest activities and describes minimization and mitigation measures and effectiveness monitoring to address potential threats. The requested take limits will allow for implementation of monitoring and research activities in several northern California watersheds including the Winchuk River, Smith River, Lower Klamath basin tributaries, Mad River, Little River, several Humboldt Bay tributaries, and Eel River. The three species identified which will be taken as a direct result of this monitoring are CC Chinook salmon, SONCC coho salmon, and NC steelhead. Research and take will involve various life stages (fry, juvenile, smolt, adult, and carcass). Trained GDRC crews will observe listed salmonids during snorkel surveys and spawning surveys. Crews will avoid walking in suitable spawning habitats (
A notice of receipt of an application for scientific research permit (17396) was published in the
Permit 17396 authorizes the USFWS AFRP to take listed fish while conducting research designed to: (1) Provide data necessary to evaluate the effectiveness of AFRP restoration projects, including appraisal of spawning gravel augmentation, in-channel and floodplain habitat enhancement actions, and water allocation/flow regime alteration actions; and (2) provide reconnaissance-level population and biological data on contemporary anadromous fish population patterns within the Central Valley of California, in order to prioritize and select future restoration projects to benefit anadromous salmonids. All AFRP restoration monitoring projects will serve to benefit anadromous salmonids by providing data on restoration project effectiveness, and providing valuable information relating to adaptive management procedures. Take of listed species including various life stages of CVSR Chinook salmon, CCV steelhead, and sDPS green sturgeon will result from activities in the following five projects: (1) Bobcat flat restoration effectiveness monitoring in the lower Tuolumne River; (2) adult sturgeon acoustic telemetry in the lower San Joaquin basin; (3) San Joaquin River sturgeon spawning habitat assessment; (4) steelhead sampling and acoustic tracking in the lower Stanislaus, Tuolumne and Merced Rivers; and (5) fish reconnaissance in the San Joaquin River system. Observe/harass take will result from snorkel surveys. Capture methods will include beach seine, trammel nets, gill nets, fyke nets, hook-and-line, egg mats, benthic d-nets, and boat and backpack electrofishing. The majority of captured listed fish will be handled and released; a subsample of captures will be anesthetized, scale sampled, fin clipped (to mark and to collect fin tissue for genetic analysis), acoustic tagged, and/or subject to intentional directed mortality. Green sturgeon eggs (n = 100) and larvae (n = 5) will be intentionally sacrificed, which will be necessary to provide voucher tissue specimens, and will benefit the species by providing critical information on green sturgeon spawning habitat. To minimize physiological stress, all sturgeon will be held in a net pen submerged in river or with flowing water through their gills while waiting to be handled. All listed salmonids will be immediately collected from the sampling gears, placed in five gallon buckets filled with fresh river water from the location being sampled, processed, held in another container filled with fresh river water for recovery, and subsequently released in the sampled location. The new information on these species generated by these projects will help prioritize future restoration projects, thus benefiting listed species.
A notice of receipt of an application for scientific research permit renewal (17867) was published in the
Permit 17867 authorizes the HRC to take juvenile and adult CC Chinook salmon, SONCC coho salmon and NC steelhead while conducting research and monitoring that satisfies two objectives: (1) To comply with CDFW's Restorable Class I policy by sampling reaches through snorkel and electrofishing methods to identify Class I habitat within proposed timber harvest plans, and (2) to monitor fish occupancy trends at the reach, sub basin, watershed and HRC property level over time by repeated snorkel surveys at index and randomly selected reaches. Adult and juvenile salmonids will be observed during snorkel surveys, and juvenile salmonids will be captured by backpack electrofishing. Snorkel surveys will be the preferred method of detecting presence/absence of fish species. Captured fish will be identified, and transported upstream of the project area. All captured specimens will be kept in aerated buckets, observed closely, and not released until fully recovered. The monitoring will help to achieve HRC's fisheries program's general goal, which is to determine the occurrence, distribution, population and habitat conditions of anadromous fishes on HRC lands as well as to monitor, protect, restore and enhance the anadromous fishery resources in watersheds owned by HRC. The researchers are not proposing to kill any of the fish they capture, but a small number may die as an unintended result of the activities.
A notice of receipt of an application for scientific research permit renewal (17877) was published in the
Permit 17877 authorizes the BOR to take juvenile, smolt, adult and carcasses of SONCC coho salmon via: (1) Observation/harassment by way of snorkel surveys, hand netting that specifically targets other species, and spawning surveys; and (2) capture by rotary screw trap, boat electrofishing, hook-and-line, beach seine, fyke net, or minnow trapping. The BOR applied for this permit as a contingent of the Trinity River Restoration Program (TRRP), an inter-agency partnership of the BOR, USFWS, Hoopa Valley Tribe, Yurok Tribe, CDFW, Trinity County, USFS, NMFS, and the California Department of Water Resources. The TRRP benefits listed species by conducting large-scale channel restoration and habitat restoration activities in the Trinity River mainstem and watershed as a means of restoring declining fishery resources. The following six specific studies are included: (1) Trinity River juvenile salmonid outmigrant monitoring, (2) juvenile Chinook salmon density monitoring, (3) Trinity River Chinook salmon redd and carcass survey, (4) Trinity River invasive brown trout predation on coho investigation, (5) Trinity River juvenile coho salmon ecology study, and (6) watershed rehabilitation/research. Fin tissue samples will be collected from carcasses. The majority of captured juvenile coho salmon will be anesthetized, measured to fork length and released, but a subsample will also be PIT tagged. Tagged fish will be held in recovery pens post tagging to monitor and enhance post-tagging health. The researchers are not proposing to kill any of the fish they capture, but a small number may die as an unintended result of the activities.
A notice of receipt of an application for scientific research permit renewal
Permit 17916 authorizes the BLM to monitor the effects of current management actions related to the Northwest Forest Plan's Aquatic Conservation Strategy on anadromous salmonids and their habitats. In order to monitor land management actions and implement the Northwest Forest Plan in northern California, BLM needs to obtain updated information on fish distribution and habitat. Sampling will occur in various watersheds, including the Mattole River, Eel River, Lost Coast region tributaries to the Pacific Ocean, and Humboldt Bay tributaries. Take of CC Chinook salmon, SONCC coho salmon, and NC steelhead will result from this monitoring and research. The preponderance of requested take will result from spawning surveys, snorkel surveys, and presence/absence surveys from the bank, all of which will result in observe/harass take of juvenile and/or adult salmonids. Capture methods that will take juvenile salmonids include backpack electrofishing and beach seine. A small number of salmonid fry may also be captured during kick net activities intended to sample invertebrates. Electrofishing will be used only when stream conditions prohibit less invasive sampling methods. Personnel handling fish will have wet hands and experience in fish handling. After length measurements were complete, fish will be placed in a bucket of freshwater for longer than 30 minutes to allow for recovery prior to being released. Recovering fish will be kept in cool, shaded, aerated water and will not be overcrowded. This research will benefit listed fish by informing adaptive management strategies intended to aid in the recovery of at-risk anadromous salmonids. The researchers are not proposing to kill any of the fish they capture, but a small number may die as an unintended result of the activities.
A notice of receipt of an application for scientific research permit renewal (18012) was published in the
Permit 18012 authorizes the CDFW, Bay Delta Region to take listed species while conducting two research projects, the Watershed Restoration Project (WRP) and the Fisheries Management Project (FMP), designed to assess and restore the productivity of CC Chinook salmon, CCC coho salmon, NC steelhead, CCC steelhead, and S–CCC steelhead in Sonoma, Mendocino, Napa, Marin, San Mateo, Santa Cruz and Monterey counties in north central California. Program staff will accomplish this goal by conducting habitat and salmonid surveys to determine potential limiting factors and stock status in order to identify the specific measures and actions needed to protect and increase production of listed salmonids. The authorized studies include: (1) Juvenile salmonid occurrence, distribution and habitat monitoring; (2) adult salmonid occurrence, passage, and distribution; (3) spawning ground surveys; (4) life cycle station monitoring; and (5) juvenile steelhead lagoon beach seining. Listed fish will be observed/harassed during snorkel surveys, spawning surveys, carcass surveys, and by the use of electronic counting stations (
A notice of receipt of an application for scientific research permit (18712) was published in the
Permit 18712 authorizes H.T. Harvey & Associates to take juvenile and smolt CC Chinook salmon, SONCC coho salmon, CCC coho salmon, NC steelhead, and adult sDPS eulachon while completing a project that is intended to meet three Marine Protected Area (MPA) monitoring goals set by the MPA Monitoring Enterprise. The three monitoring goals are: (1) To assess trends in the condition of ecosystems inside and outside of MPA's, (2) to evaluate the effects of specific MPA design criteria such as MPA size and distance between MPAs, and (3) to evaluate the effect of visitors on MPAs. The project will contribute to the goals of the monitoring enterprise by describing the baseline biological community in four northern California estuaries: (1) Mad River Estuary in Humboldt County, (2) South Humboldt Bay State Marine Recreational Management Area in Humboldt County, (3) Ten Mile Estuary State Marine Conservation Area (SMCA) in Mendocino County, and (4) Big River Estuary SMCA in Mendocino County. Beach seines and fyke nets will be used to capture fish whereby take (
A notice of receipt of an application for scientific research permit (18937) was published in the
Permit 18937 authorizes the Scripps Institution of Oceanography, University of California, San Diego, CSGCP to annually take listed CC Chinook salmon, CCC coho salmon, and CCC steelhead while monitoring the status
A notice of receipt of an application for scientific research permit (19121) was published in the
Permit 19121 authorizes the USGS, California Water Survey take of listed species associated with completing two main objectives: (1) To examine research applications of the SmeltCam that have been developed and coordinated with the IEP, and (2) to provide fisheries science support for the BOR's compliance with Biological Opinions. The studies are intended to: (1) Provide new quantitative data addressing the potential benefits of habitat restoration to the SFE and Delta ecosystem and its native fish populations, and (2) determine the vertical and lateral distribution of delta smelt, and the continued evaluation and application of SmeltCam technology for studies of delta smelt and other fishes. The results of these studies are expected to provide net benefits to listed species by improving our understanding of their ecology and habitat use, and by informing the development of new research tools that can guide management decisions and habitat restoration actions. Sampling will be conducted in Suisun Bay, and will take multiple life stages of CVSR Chinook salmon, SRWR Chinook salmon, CCV steelhead, and sDPS green sturgeon. Capture methods will include beach seine, fyke trap, larval net, otter trawl, midwater trawl, boat electrofishing, set line, and gill net. All sampling will follow methods and protocols designed to minimize take of listed species while conducting research and monitoring. For example, sampling gear such as gill nets will be watched closely to monitor the status of any fishes entangled in the net. Set times will be short (approximately one hour), and nets will be set in habitats that listed fish are unlikely to inhabit. Listed salmonids captured in the course of sampling will be identified, carefully measured for length and released. Green sturgeon will be anesthetized using MS–222, scanned for a presence of a PIT tag, PIT tagged if no PIT tag is present, tissue sampled, and allowed to recover prior to release. All fishes collected in any sampling gear will be handled as gently as possible to facilitate safe release back to the water. The researchers are not proposing to kill any of the fish they capture, but a small number may die as an unintended result of the activities.
A notice of receipt of an application for scientific research permit (19320) was published in the
Permit 19320 authorizes the NMFS SWFSC, Fisheries Ecology Division to annually take sub-adult and juvenile listed salmon and steelhead for a period of five years. The permit will authorize research designed to (1) determine the inter-annual and seasonal variability in growth, feeding, and energy status among juvenile salmonids in the coastal ocean off northern and central California; (2) determine migration paths and spatial distribution among genetically distinct salmonid stocks during their early ocean residence; (3) characterize the biological and physical oceanographic features associated with juvenile salmon ocean habitat from the shore to the continental shelf break; (4) identify potential links between coastal geography, oceanographic features, and salmon distribution patterns; and (5) identify and test ecological indices for salmon survival. This research will benefit listed fish by informing comprehensive lifecycle models that incorporate both freshwater and marine conditions and recognize the relationship between the two habitats; it will also identify and predict sources of salmon mortality at sea and thereby help managers develop indices of salmonid survival in the marine environment.
Listed fish will be captured primarily via surface trawling, however midwater trawling and beach seining will be used occasionally. Sub-adult salmonids (
A notice of receipt of an application for scientific research permit (19400) was published in the
Permit 19400 authorizes ICF consulting to take juvenile CVSR Chinook salmon and SRWR Chinook salmon while conducting a study to investigate if longfin smelt in San Pablo Bay shift their vertical distribution under different environmental and biological conditions. Although this study principally targets longfin smelt, ESA listed Chinook salmon will be encountered during sampling. ICF will collect data that will be useful to local researchers on captured and/or photographed listed Chinook salmon, including abundance, length, and potentially tissue samples. Fish will be sampled using a midwater trawl, however the majority of tows will be conducted with only a video device (
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration, Commerce.
Notice.
The National Marine Fisheries Service (NMFS) released its final Environmental Impact Statement (EIS) to Inform Columbia River Basin Hatchery Operations and the Funding of Mitchell Act Hatchery Programs in September 2014 (also known as the Mitchell Act Hatchery EIS). This notice serves as an update on preparation of the agency's record of decision (ROD).
James Dixon, (360) 534–9329 or email:
On September 3, 2004 (69 FR 53892), NMFS announced its intent to prepare an EIS pursuant to the National Environmental Policy Act (NEPA) (42 U.S.C. 4321
NMFS has been preparing its ROD through careful consideration of a range of comments received during public review of the final EIS. NMFS is also considering the anticipated effects of its preferred policy direction on species listed under the Endangered Species Act. It is anticipated that the ROD will be published in 2016.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice; receipt of application.
Notice is hereby given that the NMFS Northeast Fisheries Science Center [Responsible Party: William Karp], 166 Water Street, Woods Hole, MA 02543, has applied in due form for a permit to take Atlantic sturgeon (
Written, telefaxed, or email comments must be received on or before February 16, 2016.
The application and related documents are available for review by selecting “Records Open for Public Comment” from the “Features” box on the Applications and Permits for Protected Species (APPS) home page,
These documents are also available upon written request or by appointment in the Permits and Conservation Division, Office of Protected Resources, NMFS, 1315 East-West Highway, Room 13705, Silver Spring, MD 20910; phone (301) 427–8401; fax (301) 713–0376.
Written comments on this application should be submitted to the Chief, Permits and Conservation Division, at the address listed above. Comments may also be submitted by facsimile to (301) 713–0376, or by email to
Those individuals requesting a public hearing should submit a written request to the Chief, Permits and Conservation Division at the address listed above. The request should set forth the specific reasons why a hearing on this application would be appropriate.
Malcolm Mohead or Amy Hapeman, (301) 427–8401.
The subject permit is requested under the authority of the Endangered Species Act of 1973, as amended (ESA; 16 U.S.C. 1531
The applicant requests a five-year permit to conduct research on sea turtles and Atlantic sturgeon in the U.S. Atlantic exclusive economic zone from Massachusetts to Georgia. The purpose of the research is to evaluate bycatch reduction devices for commercial fishing gear to mitigate sea turtle and
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of intent to prepare an environmental impact statement; request for comments.
Pursuant to the National Environmental Policy Act (NEPA), this notice announces that NMFS intends to obtain information necessary to prepare an Environmental Impact Statement (EIS) for Hatchery and Genetic Management Plans (HGMPs) submitted by the Oregon Department of Fish and Wildlife (ODFW) for NMFS's evaluation and determination under Limit 5 of the Endangered Species Act (ESA) 4(d) Rule for threatened salmon and steelhead. The HGMPs specify the propagation of salmon, steelhead, and trout released in rivers, streams, and lakes throughout the Oregon Coast region.
NMFS provides this notice to: (1) Advise other agencies and the public of its plans to analyze effects related to the action, and (2) obtain suggestions and information that may be useful to the scope of issues and alternatives to include in the EIS. This notice further serves to notify the public of the availability of the HGMPs for comment prior to a decision by NMFS on whether to approve the proposed hatchery programs.
Written or electronic scoping comments must be received at the appropriate address or email mailbox (see
Written comments may be sent by any of the following methods:
• Email to the following address:
• Mail or hand-deliver to NMFS Sustainable Fisheries Division, 2900 NW Stewart Parkway, Roseburg, OR 97471.
• Fax to (541) 957–3386.
Comments received will be available for public inspection, by appointment, during normal business hours at the above address. All Personal Identifying Information (for example, name, address, etc.) voluntarily submitted by the commenter may be publicly accessible. Do not submit Confidential Business Information or otherwise sensitive or protected information.
Additional information to assist with consideration of the notice of intent, as well as the HGMPs themselves, is available on the Internet at
Lance Kruzic, NMFS, by phone at (541) 957–3381, or email to
Coho salmon (
The ODFW has submitted HGMPs for all hatchery programs along the Oregon Coast to NMFS, pursuant to Limit 5 of the 4(d) Rule for salmon and steelhead promulgated under the ESA (65 FR 42422, July 10, 2000). Before a decision is made by NMFS on these HGMPs, NEPA requires Federal agencies to conduct environmental analyses of proposed actions to fully consider their effects on the human environment. NMFS's action of evaluating ODFW's HGMPs under Limit 5 of the 4(d) Rule is a major Federal action subject to environmental review under NEPA. Therefore, NMFS is seeking public input on the scope of the required NEPA analysis, including the range of reasonable alternatives, recommendations for relevant analysis methods, and information associated with impacts of the alternatives to the resources listed below or other relevant resources.
The hatchery facilities to be considered in the analysis are Cole Rivers Hatchery, Indian Hatchery, Elk Hatchery, Bandon Hatchery, Rock Hatchery (Umpqua River), Alsea Hatchery, Salmon Hatchery, Cedar Hatchery, Trask Hatchery, Nehalem Hatchery, and associated satellite facilities. Hatchery fish are released into the following waterbodies: Chetco, Rogue, Elk, Coquille, Coos Umpqua, Siuslaw, Alsea, Yaquina, Siletz, Salmon, Nestucca, Trask, Wilson, and Nehalem Rivers, Tenmile Creek, and various coastal lakes. A list of all of the hatchery programs, including links to the HGMPs themselves, is available on the Internet (see
NMFS will perform an environmental review of the Oregon Coast HGMPs (and associated hatchery facilities) and prepare an EIS that will evaluate potentially significant direct, indirect, and cumulative impacts on the following resources identified to have a potential for effect from the proposed action:
NMFS will rigorously explore and objectively evaluate a full range of reasonable alternatives in the EIS, including the proposed action (implementation of ODFW's HGMPs) and a no-action alternative. Additional alternatives could include a reduction in artificial production and/or elimination of the hatchery programs along the Oregon Coast.
For all potentially significant impacts, the EIS will identify measures to avoid, minimize, and mitigate the impacts, where feasible, to a level below significance.
NMFS provides this notice to: (1) Advise other agencies and the public of
NMFS invites comment from all interested parties to ensure that the full range of issues related to Oregon Coast HGMPs is identified. Comments should be as specific as possible.
Written comments concerning the proposed action and the environmental review should be directed to NMFS as described above (see
The environmental review of the Oregon Coast HGMPs will be conducted in accordance with requirements of the NEPA of 1969 as amended (42 U.S.C. 4321
Under section 4 of the ESA, the Secretary of Commerce is required to adopt such regulations as he deems necessary and advisable for the conservation of species listed as threatened. The ESA salmon and steelhead 4(d) rule (65 FR 42422, July 10, 2000, as updated in 70 FR 37160, June 28, 2005) specifies categories of activities that contribute to the conservation of listed salmonids and sets out the criteria for such activities. Limit 5 of the updated 4(d) rule (50 CFR 223.203(b)(5)) further provides that the prohibitions of paragraph (a) of the updated 4(d) rule (50 CFR 223.203(a)) do not apply to activities associated with artificial propagation programs provided that an HGMP has been approved by NMFS to be in accordance with the salmon and steelhead 4(d) rule (65 FR 42422, July 10, 2000, as updated in 70 FR 37160, June 28, 2005).
Committee for Purchase From People Who Are Blind or Severely Disabled.
Proposed Deletions from the Procurement List.
The Committee is proposing to delete products from the Procurement List that was previously furnished by nonprofit agencies employing persons who are blind or have other severe disabilities.
COMMENTS MUST BE RECEIVED ON OR BEFORE: 2/14/2016.
Committee for Purchase From People Who Are Blind or Severely Disabled, 1401 S. Clark Street, Suite 715, Arlington, Virginia 22202–4149.
Barry S. Lineback, Telephone: (703) 603–7740, Fax: (703) 603–0655, or email
This notice is published pursuant to 41 U.S.C. 8503(a)(2) and 41 CFR 51–2.3. Its purpose is to provide interested persons an opportunity to submit comments on the proposed actions.
The following products are proposed for deletion from the Procurement List:
Bureau of Consumer Financial Protection.
Notice of solicitation of applications.
Section 1013(b)(1) of the Consumer Financial Protection Act, 12 U.S.C. 5493(b)(1), establishes the Consumer Financial Protection Bureau's (Bureau) Office of Research and assigns to it the responsibility of researching, analyzing, and reporting on topics relating to the Bureau's mission, including developments in markets for consumer financial products and services, consumer awareness, and consumer behavior. The Bureau established the Academic Research Council (Council) as a technical advisory body comprised of scholars to provide the Office of Research with guidance as it performs its responsibilities. Director Richard Cordray invites qualified individuals to apply for appointment to the Council. Appointments to the Council are typically for three years. However, the Director may amend the Council charter from time to time during the charter terms as the Director deems necessary to accomplish the purpose of the Council. There are three vacancies on the Academic Research Council. The Bureau expects to announce the selection of new members in April 2016.
Only complete application packets received on or before 5 p.m. eastern standard time on February 12, 2016, will be given consideration for membership on the Council.
Complete application packets must include a curriculum vitae or résumé for each applicant and a completed application. The application can be accessed at:
All applications for membership on the Council should be sent:
•
•
•
Requests for additional information should be directed to Julian Alcazar, Outreach and Engagement Associate, Consumer Financial Protection Bureau, (202) 435–9885.
The Bureau is charged with regulating “the offering and provision of consumer financial products or services under the Federal consumer financial laws,” so as to ensure that “all consumers have access to markets for consumer financial products and services and that markets for consumer financial products and services are fair, transparent, and competitive.” Pursuant to section 1021(c) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, Public Law 111–203 (Dodd-Frank Act), the Bureau's primary functions are:
1. Conducting financial education programs;
2. Collecting, investigating, and responding to consumer complaints;
3. Collecting, researching, monitoring, and publishing information relevant to the function of markets for consumer financial products and services to identify risks to consumers and to the proper functioning of such markets;
4. Supervising persons covered under the Dodd-Frank Act for compliance with Federal consumer financial law, and taking appropriate enforcement action to address violations of Federal consumer financial law;
5. Issuing rules, orders, and guidance implementing Federal consumer financial law; and
6. Performing such support activities as may be needed or useful to facilitate the other functions of the Bureau.
Section 1013(b)(1) of the Consumer Financial Protection Act, 12 U.S.C. 5493(b)(1), establishes the Consumer Financial Protection Bureau's Office of Research and assigns to it the responsibility of researching, analyzing, and reporting on topics relating to the Bureau's mission, including developments in markets for consumer financial products and services, consumer awareness, and consumer behavior. The Bureau established the Council as a technical advisory body comprised of scholars to provide the Office of Research with methodological and technical advice and feedback on its research work by framing research questions; suggesting new data collection strategies and methods of analysis; providing feedback, both backward and forward looking, on the Office of Research's research program; providing input into its research strategic planning process and research agenda; collaborating with the Bureau's research staff on high value research projects which will allow for transfer of specialized expertise; and supporting high quality recruitment.
In appointing members of the Council, the Office of Research seeks to recruit tenured academics with a world class research and publishing background, and a record of public or academic service. We are seeking prominent experts who are recognized for their professional achievements and objectivity in economics, statistics, psychology or behavioral science. In particular, academics with strong methodological and technical expertise in structural or reduced form econometrics, modeling of consumer decision-making, behavioral economics, experimental economics, program evaluation, psychology, and financial choice. The members of the Council will collectively provide a balance of expertise across these areas.
The Council is composed of no more than nine members. Currently we have six Council members. We are looking to fill three additional seats on the Council in 2016. You can learn more about current Academic Research Council members here.
The Bureau has a special interest in ensuring that the perspectives of women and men, all racial and ethnic groups, and individuals with disabilities are adequately represented on the Council and therefore encourages applications from qualified candidates from these groups. The Bureau also has a special interest in establishing a Council that is represented by a diversity of viewpoints and constituencies, and therefore encourages nominations for qualified candidates who:
1. Represent the United States' geographic diversity; and
2. Understand the interests of special populations identified in the Dodd-Frank Act, including servicemembers, older Americans, students, and traditionally underserved consumers and communities.
Any interested person may apply for membership on the Council.
A complete application packet may include a cover letter and must include:
1. A complete résumé or curriculum vitae for the applicant; and
2. Completed application.
To evaluate potential sources of conflicts of interest, the Bureau will ask potential candidates to provide information related to financial holdings and/or professional affiliations, and to allow the Bureau to perform a background check. The Bureau will not review nominations and will not answer questions from internal or external parties regarding applications until the application period has closed.
The Bureau will not entertain nominations of federally registered lobbyists and individuals who have been convicted of a felony for a position on the Council.
Only complete applications will be given consideration for review of membership on the Council.
Bureau of Consumer Financial Protection.
Notice.
Pursuant to the authorities given to the Director of the Consumer Financial Protection Bureau (Bureau) under the Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) Director Richard Cordray invites the public to apply for membership for appointment to its Consumer Advisory Board (Board), Community Bank Advisory Council, and Credit Union Advisory Council (collectively, Advisory Councils). Membership of the Board and Councils includes representatives of consumers, communities, the financial services industry and academics. Appointments to the Board are typically for three years and appointments to the Councils are typically for two years. However, the Director may amend the respective Board and Council charters from time to time during the charter terms, as the Director deems necessary to accomplish the purpose of the Board and Councils. The Bureau expects to announce the selection of new members in August 2016.
Complete application packets received on or before February 29, 2016, will be given consideration for membership on the Board and Councils.
If electronic submission is not feasible, the completed application packet can be mailed to Julian Alcazar, Outreach and Engagement Associate, Consumer Financial Protection Bureau, 1700 G Street NW., Washington, DC 20552.
All applications for membership on the Board and Councils should be sent:
•
•
•
Requests for additional information should be directed to Julian Alcazar, Outreach and Engagement Associate, Consumer Financial Protection Bureau, (202) 435–9885.
The Bureau is charged with regulating “the offering and provision of consumer financial products or services under the Federal consumer financial laws,” so as to ensure that “all consumers have access to markets for consumer financial products and services and that markets for consumer financial products and services are fair, transparent, and competitive.” Pursuant to section 1021(c) of the Wall Street Reform and Consumer Protection Act, Public Law 111–203, Dodd-Frank Act, the Bureau's primary functions are:
1. Conducting financial education programs;
2. Collecting, investigating, and responding to consumer complaints;
3. Collecting, researching, monitoring, and publishing information relevant to the function of markets for consumer financial products and services to identify risks to consumers and the proper functioning of such markets;
4. Supervising persons covered under the Dodd-Frank Act for compliance with Federal consumer financial law, and taking appropriate enforcement action to address violations of Federal consumer financial law;
5. Issuing rules, orders, and guidance implementing Federal consumer financial law; and
6. Performing such support activities as may be needed or useful to facilitate the other functions of the Bureau.
As described in more detail below, section 1014 of the Dodd-Frank Act calls for the Director of the Bureau to establish a Consumer Advisory Board to advise and consult with the Bureau regarding its functions, and to provide information on emerging trends and practices in the consumer financial markets.
Pursuant to section 1014(b) of the Dodd-Frank Act, in appointing members to the Board, “the Director shall seek to assemble experts in consumer protection, financial services, community development, fair lending and civil rights, and consumer financial products or services and representatives of depository institutions that primarily serve underserved communities, and representatives of communities that have been significantly impacted by higher-priced mortgage loans, and seek representation of the interests of covered persons and consumers, without regard to party affiliation.” The determinants of “expertise” shall depend, in part, on the constituency, interests, or industry sector the nominee seeks to represent, and where appropriate, shall include significant experience as a direct service provider to consumers.
Pursuant to section 5 of the Community Bank Advisory Council Charter, in appointing members to the Council the Director shall seek to assemble experts in consumer protection, financial services, community development, fair lending and civil rights, and consumer financial products or services and representatives of community banks that primarily serve underserved communities, and representatives of communities that have been significantly impacted by higher-priced mortgage loans, and shall strive to have diversity in terms of points of view. Only current bank or thrift employees (CEOs, compliance officers, government relations officials, etc.) will be considered for membership. Membership is limited to employees of banks and thrifts with total assets of $10 billion or less that are not affiliates of depository institutions or credit unions with total assets of more than $10 billion.
Pursuant to section 12 of the Credit Union Advisory Council Charter, in appointing members to the Council the Director shall seek to assemble experts in consumer protection, financial services, community development, fair lending and civil rights, and consumer financial products or services and representatives of credit unions that primarily serve underserved communities, and representatives of communities that have been significantly impacted by higher-priced mortgage loans, and shall strive to have diversity in terms of points of view. Only current credit union employees (CEOs, compliance officers, government relations officials, etc.) will be considered for membership. Membership is limited to employees of credit unions with total assets of $10 billion or less that are not affiliates of depository institutions or credit unions with total assets of more than $10 billion.
The Bureau has a special interest in ensuring that the perspectives of women and men, all racial and ethnic groups, and individuals with disabilities are adequately represented on the Board and Councils, and therefore, encourages applications from qualified candidates from these groups. The Bureau also has a special interest in establishing a Board that is represented by a diversity of viewpoints and constituencies, and therefore encourages applications from qualified candidates who:
1. Represent the United States' geographic diversity; and
2. Represent the interests of special populations identified in the Dodd-Frank Act, including service members, older Americans, students, and traditionally underserved consumers and communities.
Any interested person may apply for membership on the Board or Council.
A complete application packet must include:
1. A recommendation letter from a third party describing the applicant's interests and qualifications to serve on the Board or Council;
2. A complete résumé or curriculum vitae for the applicant; and
3. A one-page cover letter, which summarizes the applicant's expertise and provides reason(s) why he or she would like to join the Board or Council.
4. A complete application.
To evaluate potential sources of conflicts of interest, the Bureau will ask potential candidates to provide information related to financial holdings and/or professional affiliations, and to allow the Bureau to perform a background check. The Bureau will not review applications and will not answer questions from internal or external parties regarding applications until the application period has closed.
The Bureau will not entertain applications of federally registered lobbyists for a position on the Board and Councils.
Only complete applications will be given consideration for review of membership on the Board and Councils.
Corporation for National and Community Service.
Notice.
The Corporation for National and Community Service (CNCS), as part of its continuing effort to reduce paperwork and respondent burden, conducts a pre-clearance consultation program to provide the general public and federal agencies with an opportunity to comment on proposed and/or continuing collections of information in accordance with the Paperwork Reduction Act of 1995 (PRA95) (44 U.S.C. Sec. 3506(c)(2)(A)). This program helps to ensure that requested data can be provided in the desired format, reporting burden (time and financial resources) is minimized, collection instruments are clearly understood, and the impact of collection requirement on respondents can be properly assessed.
Currently, CNCS is soliciting comments concerning its proposed establishment of the Disability Accommodation Reimbursement Request Form. This form will be used by grantees to submit required information when requesting reimbursement for the costs associated with the provision of reasonable accommodation services to facilitate accessibility by members with disabilities. Completion of the necessary information is required to obtain grant funding reimbursement support from AmeriCorps State & National.
Copies of the information collection request can be obtained by contacting the office listed in the Addresses section of this Notice.
Written comments must be submitted to the individual and office listed in the
You may submit comments, identified by the title of the information collection activity, by any of the following methods:
(1)
(2)
(3)
Individuals who use a telecommunications device for the deaf (TTY–TDD) may call 1–800–833–3722 between 8:00 a.m. and 8:00 p.m. Eastern Time, Monday through Friday.
Sean R. Scott, 202–606–3866, or by email at
CNCS is particularly interested in comments that:
• Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of CNCS, including whether the information will have practical utility;
• Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
• Enhance the quality, utility, and clarity of the information to be collected; and
• Minimize the burden of the collection of information on those who are expected to respond, including the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology (
Grantees provide the information to request reimbursement for services associated with reasonable accommodation of AmeriCorps service members. The information will be collected electronically via email by submission of this form and the receipt(s) for services.
This is a new information collection request. The form requests a confirmation if outside resources were consulted, the name of the applying organization, grant number, single point of contact for the organization, POC email and telephone number, attention to and address to which the check should be remitted, member NSPID, type of disability, type of accommodation, a brief statement regarding how the accommodation helps the member achieve full participation, requested reimbursement amount, if the reimbursement is quarterly of one-time and the projected cost for ongoing requests. All measures have been taken to reduce the presence of personally identifiable information.
The information collection will otherwise be used in the same manner as the existing application. CNCS also seeks to continue using the current application until the revised application is approved by OMB. The current application is due to expire on TBD.
Comments submitted in response to this notice will be summarized and/or included in the request for Office of Management and Budget approval of the information collection request; they will also become a matter of public record.
Department of the Army, DoD.
Notice.
In accordance with 35 U.S.C. 209(e) and 37 CFR 404.7(a)(1)(i), announcement is made of the intent to grant an exclusive, royalty-bearing, revocable license to U.S. Patents 7,899,687; 8,510,129; and 8,682,692; issued respectively on March 1, 2011, August 13, 2013 and March 25, 2014, entitled respectively “System and method for handling medical information,” “Medical information handling system and method,” and “Medical information handling method, and Australia patent application 2003234535, Canada patent CA2486089 C, issued December 17, 2013, and European Patent Office patent applications EPC 03728877.6 and 12170241.9 to Vista Partners Inc., with its principal place of business at 5645 Saddle Creek Trail, Parker, CO 80134.
Commander, U.S. Army Medical Research and Materiel Command, ATTN: Command Judge Advocate, MCMR–JA, 504 Scott Street, Fort Detrick, MD 21702–5012.
For licensing issues, Mr. Barry Datlof, Office of Research & Technology Assessment, (301) 619–0033. For patent issues, Ms. Elizabeth Arwine, Patent Attorney, (301) 619–7808, both at telefax (301) 619–5034.
Anyone wishing to object to grant of this license can file written objections along with supporting evidence, if any, within 15 days from the date of this publication. Written objections are to be filed with the Command Judge Advocate (see
Notice.
The Department of Defense has submitted to OMB for clearance, the following proposal for collection of information under the provisions of the Paperwork Reduction Act.
Consideration will be given to all comments received by February 16, 2016.
Fred Licari, 571–372–0493.
Comments and recommendations on the proposed information collection should be emailed to Ms. Jasmeet Seehra, DoD Desk Officer, at
You may also submit comments and recommendations, identified by Docket ID number and title, by the following method:
• Federal eRulemaking Portal:
Written requests for copies of the information collection proposal should be sent to Mr. Licari at WHS/ESD Directives Division, 4800 Mark Center Drive, East Tower, Suite 02G09, Alexandria, VA 22350–3100.
Office of Fossil Energy, Department of Energy.
Notice of Renewal.
Pursuant to Section 14(a)(2)(A) of the Federal Advisory Committee Act, App., and section 102–3.65, Title 41, Code of Federal Regulations, and following consultation with the Committee Management Secretariat, General Services Administration, notice is hereby given that the National Petroleum Council has been renewed for a two-year period.
The Council will continue to provide advice, information, and recommendations to the Secretary of Energy on matters relating to oil and natural gas, or the oil and natural gas industries. The Secretary of Energy has determined that renewal of the National Petroleum Council is essential to the conduct of the Department's business and in the public interest in connection with the performance of duties imposed by law upon the Department of Energy. The Council will continue to operate in accordance with the provisions of the Federal Advisory Committee Act (Pub. L. 92–463), the General Services Administration Final Rule on Federal Advisory Committee Management, and other directives and instructions issued in implementation of those Acts.
Ms. Nancy Johnson at (202) 586–6458
Department of Energy.
Notice of open meeting.
This notice announces a meeting of the Environmental Management Site-Specific Advisory Board (EM SSAB), Hanford. The Federal Advisory Committee Act (Pub. L. 92–463, 86 Stat. 770) requires that public notice of this meeting be announced in the
Wednesday, February 3, 2016—8:30 a.m.–5:00 p.m.
Thursday, February 4, 2016—9:00 a.m.–12:00 p.m.
Red Lion Hanford House, 802 George Washington Way, Richland, WA 99352.
Kristen Holmes, Federal Coordinator, Department of Energy Richland Operations Office, 825 Jadwin Avenue, P.O. Box 550, A7–75, Richland, WA, 99352; Phone: (509) 376–5803; or Email:
Office of Science, Department of Energy.
Notice of open meeting.
This notice announces a meeting of the Basic Energy Sciences Advisory Committee (BESAC). The Federal Advisory Committee Act (Pub. L. 92–463, 86 Stat. 770) requires that public notice of these meetings be announced in the
Bethesda North Hotel and Conference Center, 5701 Marinelli Road, Bethesda, MD 20852.
Katie Runkles, Office of Basic Energy Sciences; U.S. Department of Energy; SC–22/Germantown Building, 1000 Independence Avenue SW.; Washington, DC 20585; Telephone: (301) 903–6529.
Reasonable provision will be made to include the scheduled oral statements on the agenda. The Chairperson of the Committee will conduct the meeting to facilitate the orderly conduct of business. Public comment will follow the 10-minute rule.
Department of Energy.
Notice of open meeting.
This notice announces an open meeting of the Secretary of Energy Advisory Board (SEAB). SEAB was reestablished pursuant to the Federal Advisory Committee Act (Pub. L. 92–463, 86 Stat. 770) (the Act). This notice is provided in accordance with the Act.
Tuesday, January 26, 2016, 8:30 a.m.–12:30 p.m. PT.
Lawrence Berkeley National Laboratory, Joint BioEnergy Institute (JBEI), 5885 Hollis Street, 4th Floor, Emeryville, CA 94608.
Karen Gibson, Designated Federal Officer, U.S. Department of Energy, 1000 Independence Avenue SW., Washington, DC 20585; telephone (202) 586–3787;
Individuals and representatives of organizations who would like to offer comments and suggestions may do so during the meeting. Those wishing to speak should register to do so beginning at 8:30 a.m. on January 26th. Approximately 30 minutes will be reserved for public comments. Time allotted per speaker will depend on the number who wish to speak but will not
This meeting is being published less than 15 days prior to the scheduled meeting to allow the public and Board to hear presentations that are unique to this facility, and for the Board to continue to meet their deadlines and reporting schedules. Scheduling conflicts resulted in a delay in securing the venue.
Those not able to attend the meeting or who have insufficient time to address the committee are invited to send a written statement to Karen Gibson, U.S. Department of Energy, 1000 Independence Avenue SW., Washington, DC 20585, email to
On January 5, 2016, Arkansas Electric Cooperative Corporation; Mississippi Delta Energy Agency and its members, Clarksdale Public Utilities Commission of the City of Clarksdale, Mississippi and Public Service Commission of Yazoo City, Mississippi; Hoosier Energy Rural Electric Cooperative, Inc.; and South Mississippi Electric Power Association filed a motion for clarification regarding the submission of briefs on exceptions, in the above-referenced proceeding (Motion). On January 8, 2016, MISO Transmission Owners filed an answer to the Motion. Notice is hereby given that the deadline for submitting briefs on exceptions is set to and including January 21, 2016. The deadline to file briefs opposing exceptions is set to and including February 10, 2016.
Take notice that the following hydroelectric application has been filed with the Commission and is available for public inspection.
a.
b.
c.
d.
e.
f.
g.
h.
i.
j. This application is not ready for environmental analysis at this time.
k.
The project is currently operated in a run-of-river mode with no usable storage capacity. Hawks Nest Hydro proposes to continue run-of-river operation. The project generates an annual average of 41,482 megawatt-hours.
l.
m. You may also register online at
n.
o. Final amendments to the application must be filed with the Commission no later than 30 days from the issuance date of the notice of ready for environmental analysis.
On September 28, 2015, Cameron LNG, LLC filed an application in Docket No. CP15–560–000 requesting Authorization pursuant to section 3 of the Natural Gas Act to construct and operate certain liquefied natural gas (LNG) facilities at the existing Cameron LNG Terminal. The proposed project is known as the Cameron LNG Terminal Expansion Project (Project), and would increase the terminal's capability to liquefy natural gas for export by 515 billion cubic feet per year.
On October 13, 2015, the Federal Energy Regulatory Commission (Commission or FERC) issued its Notice of Application for the Project. Among other things, that notice alerted agencies issuing federal authorizations of the requirement to complete all necessary reviews and to reach a final decision on a request for a federal authorization within 90 days of the date of issuance of the Commission staff's Environmental Assessment (EA) for the Project. This instant notice identifies the FERC staff's planned schedule for the completion of the EA for the Project.
If a schedule change becomes necessary, additional notice will be provided so that the relevant agencies are kept informed of the Project's progress.
Cameron LNG, LLC's Project would add an additional LNG storage tank (Tank 5) and two new systems to liquefy natural gas (Trains 4 and 5) to its existing LNG Terminal in Cameron and Calcasieu Parishes, Louisiana. No construction would occur outside of the existing terminal and no new shipping is proposed as a result of this Project.
On June 18, 2015, the Commission issued a
The U.S. Department of Transportation and U.S. Department of Energy are cooperating agencies in the preparation of the EA.
In order to receive notification of the issuance of the EA and to keep track of all formal issuances and submittals in specific dockets, the Commission offers a free service called eSubscription. This can reduce the amount of time you spend researching proceedings by automatically providing you with notification of these filings, document summaries, and direct links to the documents. Go to
Additional information about the Project is available from the Commission's Office of External Affairs at (866) 208–FERC or on the FERC Web site (
Take notice that the Commission received the following exempt wholesale generator filings:
Take notice that the Commission received the following electric rate filings:
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
Take notice that the following hydroelectric application has been filed with the Commission and is available for public inspection.
a.
b.
c.
d.
e.
f.
g.
h.
i.
j. This application is not ready for environmental analysis at this time.
k.
Hawks Nest Hydro operates the project in a run-of-river mode. The existing license (Article 402) requires that the project release a continuous minimum flow of 100 cubic feet per second into the bypassed reach between the dam and the powerhouse. Hawks Nest Hydro proposes to continue run-of-river operation and a modified minimum flow schedule for the bypassed reach. The project generates an annual average of 544,253 megawatt-hours.
l.
m. You may also register online at
n. Procedural Schedule: The application will be processed according to the following preliminary Hydro Licensing Schedule. Revisions to the schedule may be made as appropriate.
o. Final amendments to the application must be filed with the Commission no later than 30 days from the issuance date of the notice of ready for environmental analysis.
Take notice that the following hydroelectric application has been filed with the Commission and is available for public inspection.
a.
b.
c.
d.
e.
f.
g.
h.
i.
j.
k. Pursuant to section 4.32(b)(7) of the Commission's regulations, if any resource agency, Indian Tribe, or person believes that an additional scientific study should be conducted in order to form an adequate factual basis for a complete analysis of the application on its merit, the resource agency, Indian Tribe, or person must file a request for a study with the Commission not later than 60 days from the date of filing of the application, and serve a copy of the request on the applicant.
l.
The Commission strongly encourages electronic filing. Please file additional study requests and requests for cooperating agency status using the Commission's eFiling system at
m. The application is not ready for environmental analysis at this time.
n. The existing project works are as follows:
The Upper Beaver Falls Project consists of: (1) A 328-foot-long, 25-foot-high concrete gravity dam with an uncontrolled overflow spillway; (2) a 48-acre reservoir with a storage capacity of 800 acre-feet at elevation 799.4 feet North American Vertical Datum of 1988 (NAVD 88); (3) a 17-foot-high, 26.5-foot-wide, 27.5-foot-long intake structure with a steel trash rack; (4) a 90-foot-long, 16-foot-wide, 8-foot-high concrete penstock; (5) a powerhouse containing one turbine-generator with a nameplate rating of 1,500 kilowatts (kW); (6) a tailrace excavated in the riverbed; (7) a 2,120-foot-long, 2.4-kilovolt (kV) overhead transmission line connecting to an existing National Grid substation; and (8) other appurtenances. The project generates about 8,685 megawatt-hours (MWh) annually.
The Lower Beaver Falls Hydroelectric Project consists of: (1) A 400-foot-long concrete gravity dam with a maximum height of 14 feet, including: (i) A 240-foot-long non-overflow section containing an 8-foot-wide spillway topped with flashboards ranging from 6 to 8 inches in height and (ii) a 160-foot-long overflow section with an ice sluice opening; (2) a 4-acre reservoir with a storage capacity of 27.9 acre-feet at a normal elevation of 769.6 feet NAVD 88; (3) an intake structure with a steel trash rack, integral with a powerhouse containing two 500-kW turbine and generator units; (4) a tailrace; (5) a 250-foot-long, 2.4-kV transmission line connected to the Upper Beaver Falls powerhouse; and (6) appurtenant facilities. The project generates about 5,617 MWh annually.
The Lower Beaver Falls Project is located approximately 600 feet downstream of the Upper Beaver Falls Project. The dams and existing project facilities for both projects are owned by the applicant. The applicant proposes no new project facilities or operational changes, but proposes that both projects be combined under a single license.
o. A copy of the application is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's Web site at
You may also register online at
p.
Final amendments to the application must be filed with the Commission no later than 30 days from the issuance date of the notice of ready for environmental analysis.
Take notice that the Commission received the following electric rate filings:
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
The Federal Energy Regulatory Commission (Commission) hereby gives notice that members of its staff may attend the January meetings of the MISO CSRTT. Their attendance is part of the Commission's ongoing outreach efforts.
The first meeting will be held by conference call on January 15, 2016, from 10:00 a.m. to 12:00 p.m. Eastern. Dial-in and webcast information may be found at
The second meeting will be held on January 29, 2016, from 11:00 a.m. to 4:00 p.m. Eastern at the Illinois Commerce Commission Hearing Room, 160 North LaSalle, Suite C–800, Chicago, IL 60601.
The discussions may address matters at issue in the following proceedings:
The meeting is open to the public.
For more information, contact Patrick Clarey, Office of Energy Market Regulation, Federal Energy Regulatory Commission at (317) 249–5937 or
Take notice that the following hydroelectric application has been filed with the Commission and is available for public inspection.
a.
b.
c.
d.
e.
f.
g.
h.
i.
j.This application is not ready for environmental analysis at this time.
k.
The existing Graham Lake Development consists of: (1) A 750-foot-long, 58-foot-high dam that includes: (i) An 80-foot-long, 58-foot-high concrete spillway section with three 20-foot-wide, 22.5-foot-high spillway gates and one 8-foot-wide sluice gate; and (ii) a 670-foot-long, 45-foot-high west earthen embankment section with a concrete and sheet pile core wall; (2) a 10,000-acre impoundment (Graham Lake) with a useable storage volume of 123.97 million acre-feet at a normal maximum elevation of 104.2 National Geodetic Vertical Datum (NGVD); (3) a 720-foot-long, 58-foot-high concrete gravity flood control structure with a 65-foot-diameter, 55-foot-high stone-filled sheet pile retaining structure; (4) a 71-foot-long, 36.5-foot-high concrete wing wall; and (5) appurtenant facilities.
The existing Ellsworth Development consists of: (1) A 377-foot-long, 62.75-foot-high dam that includes: (i) A 102-foot-long, 62.75-foot-high west concrete bulkhead section; and (ii) a 275-foot-long, 57-foot-high concrete overflow spillway with 1.7-foot-high flashboards; (2) an 85-foot-long, 71-foot-high concrete non-over flow wall at the west end of the bulkhead section; (3) a 26-foot-high abutment at the east end of the spillway; (4) a 90-acre impoundment (Lake Leonard) with a gross storage volume of 2.46 million acre-feet at a normal maximum elevation of 66.7 feet NGVD; (5) generating facility No. 1 that includes: (i) A headgate and a trashrack with 2.44-inch clear-bar spacing; (ii) a 10-foot-diameter, 74-foot-long penstock; and (iii) a 30-foot-long, 15-foot-wide concrete and masonry gatehouse that is integral with the dam and contains a single 2.5 MW turbine-generator unit; (6) generating facility No. 2 that includes: (i) An 88.4-foot-wide, 32-foot-high intake structure with three headgates and three trashracks with 1.0- to 2.37-inch clear-bar spacing; (ii) an 8-foot-diameter, 164-foot-long penstock, an 8-foot-diameter, 195-foot-long penstock, and a 12-foot-diameter, 225-foot-long penstock; and (iii) a 52.5-foot-long, 68-foot-wide concrete and masonry powerhouse that contains two 2.0–MW and one 2.4–MW turbine-generator units; (7) downstream fish passage facilities that include three 3-foot-wide surface weirs; (8) upstream fish passage facilities that include a 3-foot-wide vertical slot fishway and collection station; (9) a 320-foot-long transmission line connecting the turbine-generator units to the regional grid; and (10) appurtenant facilities.
The Graham Lake Development operates as a water storage facility where water is stored to reduce downstream flooding during periods of high flow and released during periods of low flow to augment generation at the Ellsworth Development. The Ellsworth Development operates as a peaking facility where Lake Leonard is fluctuated up to one foot on a daily basis to regulate downstream flows and meet peak demands for hydroelectric generation.
The existing license requires an instantaneous minimum flow of 250 cubic feet per second (cfs), or inflow (whichever is less), downstream of each development from May 1 to June 30 each year. The minimum flow for each development is reduced to 105 cfs from July 1 to April 30 each year. In addition to the minimum flows, the existing license requires Black Bear Hydro to maintain Graham Lake and Lake Leonard between elevations 93.4 and 104.2 feet NGVD and 65.7 and 66.7 feet NGVD, respectively. Black Bear Hydro proposes to install upstream eel passage facilities at the Graham Lake and Ellsworth developments, construct a canoe portage at the Graham Lake Development, and improve angler access at the Graham Lake Development.
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m. You may also register online at
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The application will be processed according to the following preliminary Hydro Licensing Schedule. Revisions to the schedule may be made as appropriate.
o. Final amendments to the application must be filed with the Commission no later than 30 days from the issuance date of the notice of ready for environmental analysis.
Environmental Protection Agency (EPA).
Notice.
This document announces the Office of Management and Budget (OMB) responses to Agency Clearance requests, in compliance with the Paperwork Reduction Act (44 U.S.C. 3501 et seq.). An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for EPA regulations are listed in 40 CFR part 9 and 48 CFR chapter 15.
Courtney Kerwin (202) 566–1669, or email at
EPA ICR Number 2067.05; Laboratory Quality Assurance Evaluation Program for Analysis of Cryptosporidum under the Safe Drinking Water Act (Renewal); was approved without change on 3/31/2015; OMB Number 2040–0246; expires on 3/31/2018.
EPA ICR Number 2261.03; Safer Detergent Stewardship Initiative (SDSI) Program (Renewal); was approved without change on 3/16/2015; OMB Number 2070–0171; expires on 3/31/2018.
EPA ICR Number 2020.06; Federal Implementation Plans under the Clean Air Act for Indian Reservations in Idaho, Oregon, and Washington (Renewal); 40 CFR part 49, 49.122, 49.124, 49.126, 49.127, 49.130, 49.131, 49.132, 49.133, 49.134, 49.135, 49.138, and 49.139; was approved without change on 3/16/2015; OMB Number 2060–0558; expires on 3/31/2018.
EPA ICR Number 1974.07; NESHAP for Cellulose Products Manufacturing (Renewal); 40 CFR part 63, subparts UUUU and A; was approved without change on 4/30/2015; OMB Number 2060–0488; expires on 4/30/2018.
EPA ICR Number 0746.09; NSPS for Calciners and Dryers in Mineral Industries (Renewal); 40 CFR part 60, subparts UUU and A; was approved without change on 4/30/2015; OMB Number 2060–0251; expires on 4/30/2018.
EPA ICR Number 1712.09; NESHAP for Shipbuilding and Ship Repair Facilities—Surface Coating (Renewal); 40 CFR part 63, subparts II and A; was approved without change on 4/30/2015; OMB Number 2060–0330; expires on 4/30/2018.
EPA ICR Number 1750.07; National Volatile Organic Compound Emission Standards for Architectural Coatings (Renewal); 40 CFR part 59, subpart D; was approved without change on 4/30/2015; OMB Number 2060–0393; expires on 4/30/2018.
EPA ICR Number 2310.03; Revisions to the RCRA Definition of Solid Waste Final Rule (Revision); 40 CFR parts 260 and 261; was approved without change on 4/28/2015; OMB Number 2050–0202; expires on 4/30/2018.
EPA ICR Number 1947.06; NESHAP for Solvent Extraction for Vegetable Oil Production (Renewal); 40 CFR part 63, subpart GGGG; was approved without change on 4/22/2015; OMB Number 2060–0471; expires on 4/30/2018.
EPA ICR Number 0661.11; NSPS for Asphalt Processing and Roofing Manufacturing (Renewal); 40 CFR part 60, subparts A and UU; was approved without change on 4/22/2015; OMB Number 2060–0002; expires on 4/30/2018.
EPA ICR Number 1812.05; Annual Public Water Systems Compliance Report (Renewal); was approved without change on 4/16/2015; OMB Number 2020–0020; expires on 4/30/2018.
EPA ICR Number 1679.09; NESHAP for Marine Tank Vessel Loading Operations (Renewal); 40 CFR part 63, subpart Y; was approved without change on 4/13/2015; OMB Number 2060–0289; expires on 4/30/2018.
EPA ICR Number 1681.08; NESHAP for Epoxy Resin and Non-Nylon Polyamide Production (Renewal); 40 CFR part 63, subpart W; was approved without change on 4/13/2015; OMB Number 2060–0290; expires on 4/30/2018.
EPA ICR Number 2394.03; Control of Greenhouse Gas Emissions from New Motor Vehicles: Heavy-Duty Engine and Vehicle Standards (Renewal); 40 CFR part 523, 40 CFR part 534, 40 CFR part 535, 40 CFR part 86, 40 CFR part 1036, and 40 CFR 1037; was approved without change on 4/1/2015; OMB Number 2060–0678; expires on 4/30/2018.
EPA ICR Number 1790.07; NESHAP for Phosphoric Acid Manufacturing and Phospate Fertilizers Production (Revision); 40 CFR part 63, subparts A, AA and BB; OMB filed comment on3/30/2015.
EPA ICR Number 2448.02; NESHAP for Ferroalloys (Supplemental Proposed Rule); 40 CFR part 63, subparts XXX and A; OMB filed comment on 3/16/2015.
EPA ICR Number 2503.01; Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units (Proposed Rule); 40 CFR part 60; OMB filed comment on 3/16/2015.
EPA ICR Number 2498.01; NSPS Review for Municipal Solid Waste Landfills; 40 CFR part 60; OMB filed comment on 3/16/2015.
EPA ICR Number 2495.01; Data Requirements Rule for 1-Hour SO
EPA ICR Number 2514.01; Effluent Limitation Guidelines and Standards for the Dental Category (Proposed Rule); 40 CFR part 403 and 40 CFR part 441; OMB filed comment on 4/16/2015.
EPA ICR Number 1664.10; National Oil and Hazardous Substances Pollution Contingency Plans (Proposed Rule); 40 CFR part 300.900; OMB filed comment on 4/8/2015.
EPA ICR Number 2497.01; NSPS for Grain Elevators (Proposed Rule); 40 CFR part 60; OMB filed comment on 4/8/2015.
Environmental Protection Agency (EPA).
Notice.
This notice announces the availability of EPA's draft pollinator-only ecological risk assessment for the registration review of imidacloprid and opens a public comment period on this document. Registration review is EPA's periodic review of pesticide registrations to ensure that each pesticide continues to satisfy the statutory standard for registration, that is, the pesticide can perform its intended function without unreasonable adverse effects on human health or the environment. As part of the registration review process, the Agency has completed a comprehensive draft pollinator-only ecological risk assessment for all registered agricultural uses of imidacloprid, with focus on agricultural crops that are attractive to pollinators. After reviewing comments received during the public comment period, EPA will issue a revised pollinator risk assessment, explain any changes to the draft risk assessment, and respond to comments and may request public input on risk mitigation before completing a proposed registration review decision for imidacloprid. The revised risk assessment will also address the ecological risks for all other taxa, as well as a comprehensive draft human health risk assessment. Through the registration review program, EPA is ensuring that each pesticide's registration is based on current scientific and other knowledge, including its effects on human health and the environment.
Comments must be received on or before March 15, 2016.
Submit your comments, identified by docket identification (ID) number EPA–HQ–OPP–2008–0844, by one of the following methods:
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•
•
Additional instructions on commenting or visiting the docket, along with more information about dockets generally, is available at
This action is directed to the public in general, and may be of interest to a wide range of stakeholders including environmental, human health, farm worker, and agricultural advocates; the chemical industry; pesticide users; and members of the public interested in the sale, distribution, or use of pesticides. Since others also may be interested, the Agency has not attempted to describe all the specific entities that may be affected by this action. If you have any questions regarding the applicability of this action to a particular entity, consult the Chemical Review Manager listed under
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EPA is conducting its registration review of imidacloprid pursuant to section 3(g) of the Federal Insecticide, Fungicide, and Rodenticide Act (FIFRA) and the Procedural Regulations for Registration Review at 40 CFR part 155, subpart C. Section 3(g) of FIFRA provides, among other things, that the registrations of pesticides are to be reviewed every 15 years. Under FIFRA, a pesticide product may be registered or remain registered only if it meets the statutory standard for registration given in FIFRA section 3(c)(5) (7 U.S.C. 136a(c)(5)). When used in accordance with widespread and commonly recognized practice, the pesticide product must perform its intended function without unreasonable adverse effects on the environment; that is, without any unreasonable risk to man or the environment, or a human dietary risk from residues that result from the use of a pesticide in or on food.
As directed by FIFRA section 3(g), EPA is reviewing the pesticide registration for imidacloprid to ensure that it continues to satisfy the FIFRA standard for registration—that is, that imidacloprid can still be used without unreasonable adverse effects on human health or the environment. Imidacloprid is a neonicotinoid insecticide used for the control of sucking insects on a large variety of agricultural and non-agricultural sites, including vegetable crops, tree nuts, tree fruits, stone fruits,
Pursuant to 40 CFR 155.53(c), EPA is providing an opportunity, through this notice of availability, for interested parties to provide comments and input concerning the Agency's draft pollinator-only ecological risk assessment for imidacloprid. Such comments and input could address, among other things, the Agency's risk assessment methodologies and assumptions, as applied to this draft pollinator-only risk assessment. The Agency will consider all comments received during the public comment period and make changes, as appropriate, to the draft pollinator-only risk assessment. EPA will then issue a revised pollinator risk assessment, explain any changes to the draft risk assessment, and respond to comments. In the
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• To ensure that EPA will consider data or information submitted, interested persons must submit the data or information during the comment period. The Agency may, at its discretion, consider data or information submitted at a later date.
• The data or information submitted must be presented in a legible and useable form. For example, an English translation must accompany any material that is not in English and a written transcript must accompany any information submitted as an audiographic or videographic record. Written material may be submitted in paper or electronic form.
• Submitters must clearly identify the source of any submitted data or information.
• Submitters may request the Agency to reconsider data or information that the Agency rejected in a previous review. However, submitters must explain why they believe the Agency should reconsider the data or information in the pesticide's registration review.
As provided in 40 CFR 155.58, the registration review docket for each pesticide case will remain publicly accessible through the duration of the registration review process; that is, until all actions required in the final decision on the registration review case have been completed.
7 U.S.C. 136
Environmental Protection Agency (EPA).
Notice.
EPA has submitted the following information collection request (ICR) to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act (PRA): “Foreign Purchaser Acknowledgement Statement of Unregistered Pesticides” (FPAS) and identified by EPA ICR No. 0161.13 and OMB Control No. 2070–0027. The ICR, which is available in the docket along with other related materials, provides a detailed explanation of the collection activities and the burden estimate that is only briefly summarized in this document. EPA has addressed the comments received in response to the previously provided public review opportunity issued in the
Comments must be received on or before February 16, 2016.
Submit your comments, identified by docket identification (ID) number EPA–HQ–OPP–2015–0231, to both EPA and OMB as follows:
• To EPA online using
• To OMB via email to
EPA's policy is that all comments received will be included in the docket without change, including any personal information provided, unless the comment includes profanity, threats, information claimed to be Confidential Business Information (CBI), or other information whose disclosure is restricted by statute. Do not submit electronically any information you consider to be CBI or other information whose disclosure is restricted by statute.
Scott Drewes, Field and External Affairs, (7506P), Office of Pesticide Programs, Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460–0001; telephone number: (703) 347–0107; email address:
Under PRA, 44 U.S.C. 3501
Section 309(a) of the Clean Air Act requires that EPA make public its comments on EISs issued by other Federal agencies. EPA's comment letters on EISs are available at:
Environmental Protection Agency (EPA).
Notice.
The Environmental Protection Agency has submitted an information collection request (ICR), “Standardized Permit for RCRA Hazardous Waste Management Facilities (Renewal)” (EPA ICR No. 1935.05, OMB Control No. 2050–0182) to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act (44 U.S.C. 3501
Additional comments may be submitted on or before February 16, 2016.
Submit your comments, referencing Docket ID No. EPA–HQ–RCRA–2015–0605, to (1) EPA online using
EPA's policy is that all comments received will be included in the public docket without change including any personal information provided, unless the comment includes profanity, threats, information claimed to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute.
Jeff Gaines, Office of Resource Conservation and Recovery, (5303P), Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone number: 703–308–8655; fax number: 703–308–8617; email address:
Supporting documents which explain in detail the information that the EPA will be collecting are available in the public docket for this ICR. The docket can be viewed online at
Federal Communications Commission.
Notice and request for comments.
As part of its continuing effort to reduce paperwork burdens, and as required by the Paperwork Reduction Act (PRA) of 1995 (44 U.S.C. 3501–3520), the Federal Communications Commission (FCC or Commission) invites the general public and other Federal agencies to take this opportunity to comment on the following information collections. Comments are requested concerning: Whether the proposed collection of information is necessary for the proper performance of the functions of the Commission, including whether the information shall have practical utility; the accuracy of the Commission's burden estimate; ways to enhance the quality, utility, and clarity of the information collected; ways to minimize the burden of the collection of information on the respondents, including the use of automated collection techniques or other forms of information technology; and ways to further reduce the information collection burden on small business concerns with fewer than 25 employees. The FCC may not conduct or sponsor a collection of information unless it displays a currently valid OMB control number. No person shall be subject to
Written comments should be submitted on or before February 16, 2016. If you anticipate that you will be submitting comments, but find it difficult to do so within the period of time allowed by this notice, you should advise the contacts below as soon as possible.
Direct all PRA comments to Nicholas A. Fraser, OMB, via email
For additional information or copies of the information collection, contact Cathy Williams at (202) 418–2918. To view a copy of this information collection request (ICR) submitted to OMB: (1) Go to the Web page
Federal Communications Commission.
Notice and request for comments.
As part of its continuing effort to reduce paperwork burdens, and as required by the Paperwork Reduction Act (PRA) of 1995 (44 U.S.C. 3501–3520), the Federal Communications Commission (FCC or the Commission) invites the general public and other Federal agencies to take this opportunity to comment on the following information collection. Comments are requested concerning: Whether the proposed collection of information is necessary for the proper performance of the functions of the Commission, including whether the information shall have practical utility; the accuracy of the Commission's burden estimate; ways to enhance the quality, utility, and clarity of the information collected; ways to minimize the burden of the collection of information on the respondents, including the use of automated collection techniques or other forms of information technology; and ways to further reduce the information collection burden on small business concerns with fewer than 25 employees. The FCC may not conduct or sponsor a collection of information unless it displays a currently valid control number. No person shall be subject to any penalty for failing to comply with a collection of information subject to the PRA that does not display a valid Office of Management and Budget (OMB) control number.
Written PRA comments should be submitted on or before March 15, 2016. If you anticipate that you will be submitting comments, but find it difficult to do so within the period of time allowed by this notice, you should advise the contact listed below as soon as possible.
Direct all PRA comments to Nicole Ongele, FCC, via email
For additional information about the information collection, contact Nicole Ongele at (202) 418–2991.
Program Reimbursement Forms.
Collection of the information on FCC Form 472 is necessary to establish the process and procedure for an eligible applicant to seek reimbursement from the E-rate program for the discounts on services paid in full to a service provider. The Universal Service Administrative Company (USAC) reviews the information collected on FCC Form 472, along with invoices from the service provider, to verify the eligibility of the services for E-rate support, approve the amount that should be reimbursed, ensure that each service provider has provided discounted services within the current funding year for which it submits an invoice to USAC, and confirm that invoices submitted from service providers for the costs of discounted eligible services do not exceed the amount that has been approved.
Collection of information on FCC Form 473 is necessary to establish that the participating service provider is eligible to participate in the E-rate program, confirm that the invoice forms submitted by the service provide are in compliance with the Federal Communications Commission's E-rate rules, and enable the service provider to certify its compliance with the E-rate rules. The FCC Form 473 is also used by USAC to assure that the dollars paid out by the universal service fund go to eligible providers.
Collection of information on FCC Form 474 is necessary to establish the process and procedure for a service provider to seek payment for the discounted costs of services it provided to billed entities for eligible services. After receiving an invoice from the service provider, together with an FCC Form 474, USAC is able to verify that the eligible and approved amounts can be paid. The FCC Form 474 is also used to ensure that each service provider has provided discounted services within the current funding year for which it submits an invoice to USAC and that invoices submitted from service providers for the costs of discounted eligible services do not exceed the amount that has been approved.
This information collection is being revised pursuant to program and rule changes in the
All of the requirements contained in this information collection are necessary for the Commission to ensure compliance by applicants and/or vendors with the requirement of the E-rate program, to protect the program from waste, fraud and abuse and to evaluate the extent to which the E-rate program is meeting the statutory objectives specified in section 254(h) of the 1996 Act, and the Commission's own performance goals established in the
Based upon the foregoing, the Receiver has determined that the continued existence of the receivership will serve no useful purpose. Consequently, notice is given that the receivership shall be terminated, to be effective no sooner than thirty days after the date of this Notice. If any person wishes to comment concerning the termination of the receivership, such comment must be made in writing and sent within thirty days of the date of this Notice to: Federal Deposit Insurance Corporation, Division of Resolutions and Receiverships, Attention: Receivership Oversight Department 32.1, 1601 Bryan Street, Dallas, TX 75201.
No comments concerning the termination of this receivership will be considered which are not sent within this time frame.
The companies listed in this notice have applied to the Board for approval, pursuant to the Bank Holding Company Act of 1956 (12 U.S.C. 1841
The applications listed below, as well as other related filings required by the Board, are available for immediate inspection at the Federal Reserve Bank indicated. The applications will also be available for inspection at the offices of the Board of Governors. Interested persons may express their views in writing on the standards enumerated in the BHC Act (12 U.S.C. 1842(c)). If the proposal also involves the acquisition of a nonbanking company, the review also includes whether the acquisition of the nonbanking company complies with the standards in section 4 of the BHC Act (12 U.S.C. 1843). Unless otherwise noted, nonbanking activities will be conducted throughout the United States.
Unless otherwise noted, comments regarding each of these applications must be received at the Reserve Bank indicated or the offices of the Board of Governors not later than February 11, 2016.
A. Federal Reserve Bank of Chicago (Colette A. Fried, Assistant Vice President) 230 South LaSalle Street, Chicago, Illinois 60690–1414:
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B. Federal Reserve Bank of Dallas (Robert L. Triplett III, Senior Vice President) 2200 North Pearl Street, Dallas, Texas 75201–2272:
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General Services Administration (GSA).
Notice of availability.
Pursuant to the National Environmental Policy Act (NEPA) of 1969, as implemented by the Council on Environmental Quality regulations, the GSA has prepared and filed with the Environmental Protection Agency (EPA), a Supplement to the Final Environmental Impact Statement (SEIS), from May 2007, analyzing the environmental impacts of site acquisition and development of the Federal Bureau of Investigation (FBI), Central Records Complex (CRC), in Frederick County, Virginia.
The Final SEIS may be viewed online at
Ms. Courtenay Hoernemann, Project Environmental Planner, 100 S Independence Mall West, Philadelphia PA 19106; or email
The proposed FBI facility would consolidate the FBI's records currently housed within the Washington DC area, in addition to field offices and information technology centers nationwide. The project requirements are for an overall square footage of 256,425 gross square feet, and will include the records storage building, support area, visitor's screening facility, service center, and guard booth. Parking is proposed at 427 spaces.
A Notice of Intent to prepare a Supplemental Draft EIS was published in the
The Supplemental Draft EIS incorporated by reference and built upon the analyses presented in the 2007 Final EIS, and documented the section 106 process under the National Historic Preservation Act (NHPA) of 1966, as amended (36 CFR part 800). The Supplemental Draft EIS addressed changes to the proposed action relevant to environmental concerns and assessed any new circumstances or information relevant to potential environmental impacts. The alternatives fully evaluated in the Supplemental Draft EIS include the No Action Alternative, the Arcadia Route 50 property, and Whitehall Commerce Center.
The Final Supplemental EIS identifies XXX as the preferred alternative. The proposed action at XXX will result in impacts to water resources, traffic and transportation, biological resources, and geology/topography/soils. Changes between the Final and Draft Supplemental EIS include conclusion on consultation under section 106 of the NHPA, conclusion of consultation under section 7 of the Endangered Species Act with the U.S. Fish & Wildlife Service, and agreement with Virginia Department of Transportation on the Revised Traffic Impact Analysis and site access. The Final Supplemental EIS addresses and responds to agency and public comments on the Supplemental Draft EIS.
The Final Supplemental EIS has been distributed to various federal, state, and local agencies. The Final Supplemental EIS is available for review on the project Web site
• Handley Library, 100 West Piccadilly Street, P.O. Box 58, Winchester, VA 22604
• Bowman Library, 871 Tasker Road, P.O. Box 1300, Stephens City, VA 22655
• Smith Library, Shenandoah University, 718 Wade Miller Drive, Winchester, VA 22601
Administration for Community Living, HHS.
Notice.
The Administration for Community Living (ACL) is announcing that the proposed collection of information listed below has been submitted to the Office of Management and Budget (OMB) for review and clearance under the Paperwork Reduction Act of 1995.
Submit written comments on the collection of information by February 16, 2016.
Submit written comments on the collection of information by email to
Lori Stalbaum at (202) 357–3452, or
In compliance with 44 U.S.C. 3507, ACL has submitted the following proposed collection of information to OMB for review and clearance.
ACL is requesting to continue an existing approved collection of information for semi-annual and final reports pursuant to the requirements of its discretionary grant programs. ACL estimates the burden of this collection of information as follows:
Food and Drug Administration, HHS.
Notice of public workshop.
The Food and Drug Administrations (FDA) Center for Drug Evaluation and Research (CDER), is sponsoring a public workshop entitled “Navigating CDER: What You Should Know for Effective Engagement.” The purpose of this public workshop is to help the public and patient advocacy groups gain a better understanding of how to effectively engage CDER.
The public workshop will be held on March 31, 2016, from 8:30 a.m. to 5 p.m.
The public workshop will be held at FDA's White Oak campus, 10903 New Hampshire Ave., Building 31 (The Great Room A, B, and C), Silver Spring, MD 20993. Entrance for the public workshop participants (non-FDA employees) is through Building 1 where routine security check procedures will be performed. For parking and security information, please refer to
Shawn Brooks, Center for Drug Evaluation and Research, Food and Drug Administration, 10903 New Hampshire Ave., Silver Spring, MD 20993–0002, 240–402–6509, email:
FDA is announcing a public workshop entitled “Navigating CDER: What You Should Know for Effective Engagement.” This public workshop is intended to enhance the public and advocacy groups' ability to effectively engage FDA's CDER. The presentations are intended to provide information on how best to interact with CDER. There will be an opportunity for questions and answers following each presentation.
If you need special accommodations due to a disability, please contact Shawn Brooks (see
Food and Drug Administration, HHS.
Notice; renewal of advisory committee.
The Food and Drug Administration (FDA) is announcing the renewal of the Vaccines and Related Biological Products Advisory Committee by the Commissioner of Food and Drugs (the Commissioner). The Commissioner has determined that it is in the public interest to renew the Vaccines and Related Biological Products Advisory Committee for an additional 2 years beyond the charter expiration date. The new charter will be in effect until December 31, 2017.
Authority for the Vaccines and Related Biological Products Advisory Committee will expire on December 31, 2017, unless the Commissioner formally determines that renewal is in the public interest.
Sujata Vijh, Division of Scientific Advisors and Consultants, Center for Biologics Evaluation and Research, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 71, Rm. 6128, Silver Spring, MD 20993–0002, 240–402–7107,
Pursuant to 41 CFR 102–3.65 and approval by the Department of Health and Human Services pursuant to 45 CFR part 11 and by the General Services Administration, FDA is announcing the renewal of the
The Committee reviews and evaluates data concerning the safety, effectiveness, and appropriate use of vaccines and related biological products which are intended for use in the prevention, treatment, or diagnosis of human diseases, and, as required, any other products for which the Food and Drug Administration has regulatory responsibility. The Committee also considers the quality and relevance of FDA's research program which provides scientific support for the regulation of these products and makes appropriate recommendations to the Commissioner of Food and Drugs.
The Committee shall consist of a core of 15 voting members including the Chair. Members and the Chair are selected by the Commissioner or designee from among authorities knowledgeable in the fields of immunology, molecular biology, rDNA, virology; bacteriology, epidemiology or biostatistics, vaccine policy, vaccine safety science, federal immunization activities, vaccine development including translational and clinical evaluation programs, allergy, preventive medicine, infectious diseases, pediatrics, microbiology, and biochemistry. Members will be invited to serve for overlapping terms of up to four years. Almost all non-Federal members of this committee serve as Special Government Employees. Ex Officio voting members one each from the Department of Health and Human Services, the Centers for Disease Control and Prevention, and the National Institutes of Health may be included. The core of voting members may include one technically qualified member, selected by the Commissioner or designee, who is identified with consumer interests and is recommended by either a consortium of consumer-oriented organizations or other interested persons. In addition to the voting members, the Committee may include one non-voting member who is identified with industry interests. There may also be an alternate industry representative.
The Commissioner or designee shall have the authority to select members of other scientific and technical FDA advisory committees (normally not to exceed 10 members) to serve temporarily as voting members and to designate consultants to serve temporarily as voting members when: (1) Expertise is required that is not available among current voting standing members of the Committee (when additional voting members are added to the Committee to provide needed expertise, a quorum will be based on the combined total of regular and added members), or (2) to comprise a quorum when, because of unforeseen circumstances, a quorum is or will be lacking. Because of the size of the Committee and the variety in the types of issues that it will consider, FDA may, in connection with a particular committee meeting, specify a quorum that is less than a majority of the current voting members. The Agency's regulations (21 CFR 14.22(d)) authorize a committee charter to specify quorum requirements. If functioning as a medical device panel, a non-voting representative of consumer interests and a non-voting representative of industry interests will be included in addition to the voting members.
Further information regarding the most recent charter and other information can be found at
This document is issued under the Federal Advisory Committee Act (5 U.S.C. app.). For general information related to FDA advisory committees, please visit us at
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA) is announcing an opportunity for public comment on the proposed collection of certain information by the Agency. Under the Paperwork Reduction Act of 1995 (the PRA), Federal Agencies are required to publish notice in the
Submit either electronic or written comments on the collection of information by March 15, 2016.
You may submit comments as follows:
Submit electronic comments in the following way:
•
• If you want to submit a comment with confidential information that you
Submit written/paper submissions as follows:
•
• For written/paper comments submitted to the Division of Dockets Management, FDA will post your comment, as well as any attachments, except for information submitted, marked and identified, as confidential, if submitted as detailed in “Instructions.”
• Confidential Submissions—To submit a comment with confidential information that you do not wish to be made publicly available, submit your comments only as a written/paper submission. You should submit two copies total. One copy will include the information you claim to be confidential with a heading or cover note that states “THIS DOCUMENT CONTAINS CONFIDENTIAL INFORMATION”. The Agency will review this copy, including the claimed confidential information, in its consideration of comments. The second copy, which will have the claimed confidential information redacted/blacked out, will be available for public viewing and posted on
FDA PRA Staff, Office of Operations, Food and Drug Administration, 8455 Colesville Rd., COLE–14526, Silver Spring, MD 20993–0002,
Under the PRA (44 U.S.C. 3501–3520), Federal Agencies must obtain approval from the Office of Management and Budget (OMB) for each collection of information they conduct or sponsor. “Collection of information” is defined in 44 U.S.C. 3502(3) and 5 CFR 1320.3(c) and includes Agency requests or requirements that members of the public submit reports, keep records, or provide information to a third party. Section 3506(c)(2)(A) of the PRA (44 U.S.C. 3506(c)(2)(A)) requires Federal Agencies to provide a 60-day notice in the
With respect to the following collection of information, FDA invites comments on these topics: (1) Whether the proposed collection of information is necessary for the proper performance of FDA's functions, including whether the information will have practical utility; (2) the accuracy of FDA's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques, when appropriate, and other forms of information technology.
Under section 520(m) of the Federal Food, Drug, and Cosmetic Act (the FD&C Act) (21 U.S.C. 360j(m)), FDA is authorized to exempt a humanitarian use device (HUD) from the effectiveness requirements in sections 514 and 515 of the FD&C Act (21 U.S.C. 360d and 360e) provided that the device: (1) Is used to treat or diagnose a disease or condition that affects fewer than 4,000 individuals in the United States; (2) would not be available to a person with such a disease or condition unless the exemption is granted, and there is no comparable device, other than another HUD approved under this exemption, available to treat or diagnose the disease or condition; (3) the device will not expose patients to an unreasonable or significant risk of illness or injury; and (4) the probable benefit to health from using the device outweighs the risk of injury or illness from its use, taking into account the probable risks and benefits of currently available devices or alternative forms of treatment.
HUDs approved under an HDE cannot be sold for an amount that exceeds the costs of research and development, fabrication, and distribution of the device (
Section 520(m)(6)(A)(ii) of the FD&C Act, as amended by FDASIA, provides that the Secretary of Health and Human Services will assign an ADN for devices that meet the eligibility criteria to be permitted to be sold for profit. The ADN is defined as the number of devices
Section 520(m)(6)(A)(iii) of the FD&C Act (
On August 5, 2008, FDA issued a guidance entitled “Guidance for HDE Holders, Institutional Review Boards (IRBs), Clinical Investigators, and Food and Drug Administration Staff—Humanitarian Device Exemption (HDE) Regulation: Questions and Answers” (
FDA is requesting the extension of OMB approval for the collection of information required under the statutory mandate of sections 515A (21 U.S.C. 360e–1) and 520(m) of the FD&C Act as amended.
FDA estimates the burden of this collection of information as follows:
FDA's Center for Devices and Radiological Health receives an estimated average of six HDE applications per year. FDA estimates that three of these applications will be indicated for pediatric use. We estimate that we will receive approximately two requests for determination of eligibility criteria per year. FDA estimates that very few or no HDE holders will notify the Agency that the number of devices distributed in the year has exceeded the ADN. FDA estimates that five HDE holders will petition to have the ADN modified due to additional information on the number of individuals affected by the disease or condition.
Food and Drug Administration, HHS.
Notice of public conference.
The Food and Drug Administration (FDA) is announcing a public conference entitled “How Should Liver Injury and Dysfunction Caused by Drugs Be Measured, Evaluated, and Acted Upon in Clinical Trials?” This conference will be cosponsored with the Critical Path Institute (C-Path). The purpose of the conference is to discuss, debate, and share views among stakeholders in academia, patient groups, regulatory bodies, and the health care and pharmaceutical industries on how best to measure, evaluate, and act upon liver injury and dysfunction caused by drugs used during clinical trials.
This public conference will be held on March 23, 2016, from 8 a.m. to 6 p.m., and on March 24, 2016, from 8 a.m. to 4 p.m.
This public conference will be held at the College Park Marriott Hotel & Conference Center, 3501 University Blvd., East Hyattsville, MD 20783. The hotel's phone number is 301–985–7300.
Lana L. Pauls, Center for Drug Evaluation and Research, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 22, Rm. 4478, Silver Spring, MD 20993–0002, 301–796–0518,
In July 2009, FDA announced the availability of a guidance for industry entitled “Drug-Induced Liver Injury: Premarketing Clinical Evaluation” (74 FR 38035, July 30, 2009,
The purpose of the 2016 conference is to invite participants to present their data and views and to hold an open discussion. The meetings in recent years have been attended by members of industry, regulatory bodies, and academic consultants, and the topics discussed have included several unresolved issues on which consensus was sought.
Additional information on the conference, program, and registration procedures may be obtained on the Internet at
Materials presented at past programs (from 2007 to 2015) (including copies of slides shown, comments made about the slides, and discussions following the slides) may be accessed at
In accordance with section 10(a)(2) of the Federal Advisory Committee Act (Pub. L. 92–463), the President's Advisory Council on Faith-based and Neighborhood Partnerships announces the following meetings:
The meeting will be available to the public through a conference call line. Register to participate in the conference call on Monday, February 1st at the Web site
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meetings.
The meetings will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
This notice is being published less than 15 days prior to the meeting due to the timing limitations imposed by the review and funding cycle.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meetings.
The meetings will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
U.S. Customs and Border Protection, Department of Homeland Security.
Notice of accreditation and approval of Camin Cargo Control, Inc., as a commercial gauger and laboratory.
Notice is hereby given, pursuant to CBP regulations, that Camin Cargo Control, Inc., has been approved to gauge and accredited to test petroleum and certain petroleum products for customs purposes for the next three years as of December 2, 2014.
Effective dates: The accreditation and approval of Camin Cargo Control, Inc., as commercial gauger and laboratory became effective on December 2, 2014. The next triennial inspection date will be scheduled for December 2017.
Approved Gauger and Accredited Laboratories Manager, Laboratories and Scientific Services Directorate, U.S. Customs and Border Protection, 1300 Pennsylvania Avenue NW., Suite 1500N, Washington, DC 20229, tel. 202–344–1060.
Notice is hereby given pursuant to 19 CFR 151.12 and 19 CFR 151.13, that Camin Cargo Control, Inc., 1301 Metropolitan Ave., Thorofare, NJ 08086, has been approved to gauge and accredited to test petroleum and certain petroleum products for customs purposes, in
Camin Cargo Control, Inc., is accredited for the following laboratory analysis procedures and methods for petroleum and certain petroleum products set forth by the U.S. Customs and Border Protection Laboratory Methods (CBPL) and American Society for Testing and Materials (ASTM):
Anyone wishing to employ this entity to conduct laboratory analyses and gauger services should request and receive written assurances from the entity that it is accredited or approved by the U.S. Customs and Border Protection to conduct the specific test or gauger service requested. Alternatively, inquiries regarding the specific test or gauger service this entity is accredited or approved to perform may be directed to the U.S. Customs and Border Protection by calling (202) 344–1060. The inquiry may also be sent to
60-Day Notice of Information Collection for review; I–395; Affidavit in Lieu of Lost Receipt of United States ICE for Collateral Accepted as Security; OMB Control No. 1653–0045.
The Department of Homeland Security, U.S. Immigration and Customs Enforcement (USICE), is submitting the following information collection request for review and clearance in accordance with the Paperwork Reduction Act of 1995. The information collection is published in the
Written comments and suggestions regarding items contained in this notice and especially with regard to the estimated public burden and associated response time should be directed to the Office of Chief Information Office, Forms Management Office, U.S. Immigrations and Customs Enforcement, 801 I Street NW., Mailstop 5800, Washington, DC 20536–5800.
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information should address one or more of the following four points:
(1) Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
(2) Evaluate the accuracy of the agencies estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
(3) Enhance the quality, utility, and clarity of the information to be collected; and
(4) Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology,
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U.S. Citizenship and Immigration Services, Department of Homeland Security.
30-Day notice.
The Department of Homeland Security (DHS), U.S. Citizenship and Immigration Services (USCIS) will be submitting the following information collection request to the Office of Management and Budget (OMB) for review and clearance in accordance with the Paperwork Reduction Act of 1995. The information collection notice was previously published in the
The purpose of this notice is to allow an additional 30 days for public comments. Comments are encouraged and will be accepted until February 16, 2016. This process is conducted in accordance with 5 CFR 1320.10.
Written comments and/or suggestions regarding the item(s) contained in this notice, especially regarding the estimated public burden and associated response time, must be directed to the OMB USCIS Desk Officer via email at
You may wish to consider limiting the amount of personal information that you provide in any voluntary submission you make. For additional information please read the Privacy Act notice that is available via the link in the footer of
USCIS, Office of Policy and Strategy, Regulatory Coordination Division, Samantha Deshommes, Acting Chief, 20 Massachusetts Avenue NW., Washington, DC 20529–2140, Telephone number (202) 272–8377 (This is not a toll-free number. Comments are not accepted via telephone message). Please note contact information provided here is solely for questions regarding this notice. It is not for individual case status inquiries. Applicants seeking information about the status of their individual cases can check Case Status Online, available at the USCIS Web site at
You may access the information collection instrument with instructions, or additional information by visiting the Federal eRulemaking Portal site at:
(1) Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
(2) Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
(3) Enhance the quality, utility, and clarity of the information to be collected; and
(4) Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology,
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Office of the Assistant Secretary for Community Planning and Development, HUD.
Notice.
This Notice identifies unutilized, underutilized, excess, and surplus Federal property reviewed by HUD for suitability for use to assist the homeless.
Juanita Perry, Department of Housing and Urban Development, 451 Seventh Street SW., Room 7266, Washington, DC 20410; telephone (202) 402–3970; TTY number for the hearing- and speech-impaired (202) 708–2565 (these telephone numbers are not toll-free), or call the toll-free Title V information line at 800–927–7588.
In accordance with 24 CFR part 581 and section 501 of the Stewart B. McKinney
Properties reviewed are listed in this Notice according to the following categories: Suitable/available, suitable/unavailable, and suitable/to be excess, and unsuitable. The properties listed in the three suitable categories have been reviewed by the landholding agencies, and each agency has transmitted to HUD: (1) Its intention to make the property available for use to assist the homeless, (2) its intention to declare the property excess to the agency's needs, or (3) a statement of the reasons that the property cannot be declared excess or made available for use as facilities to assist the homeless.
Properties listed as suitable/available will be available exclusively for homeless use for a period of 60 days from the date of this Notice. Where property is described as for “off-site use only” recipients of the property will be required to relocate the building to their own site at their own expense. Homeless assistance providers interested in any such property should send a written expression of interest to HHS, addressed to: Ms. Theresa M. Ritta, Chief Real Property Branch, the Department of Health and Human Services, Room 5B–17, Parklawn Building, 5600 Fishers Lane, Rockville, MD 20857, (301) 443–2265 (This is not a toll-free number.) HHS will mail to the interested provider an application packet, which will include instructions for completing the application. In order to maximize the opportunity to utilize a suitable property, providers should submit their written expressions of interest as soon as possible. For complete details concerning the processing of applications, the reader is encouraged to refer to the interim rule governing this program, 24 CFR part 581.
For properties listed as suitable/to be excess, that property may, if subsequently accepted as excess by GSA, be made available for use by the homeless in accordance with applicable law, subject to screening for other Federal use. At the appropriate time, HUD will publish the property in a Notice showing it as either suitable/available or suitable/unavailable.
For properties listed as suitable/unavailable, the landholding agency has decided that the property cannot be declared excess or made available for use to assist the homeless, and the property will not be available.
Properties listed as unsuitable will not be made available for any other purpose for 20 days from the date of this Notice. Homeless assistance providers interested in a review by HUD of the determination of unsuitability should call the toll free information line at 1–800–927–7588 for detailed instructions or write a letter to Ann Marie Oliva at the address listed at the beginning of this Notice. Included in the request for review should be the property address (including zip code), the date of publication in the
For more information regarding particular properties identified in this Notice (
Fish and Wildlife Service, Interior.
Notice.
We, the U.S. Fish and Wildlife Service (Service), announce a draft methodology for prioritizing status reviews and accompanying 12-month findings on petitions for listing species under the Endangered Species Act. This draft methodology is intended to allow us to address outstanding workload strategically as our resources allow and to provide transparency to our partners and other stakeholders as to how we establish priorities within our upcoming workload.
We will accept comments from all interested parties until February 16, 2016. Please note that if you are using the Federal eRulemaking Portal (see
You may submit comments by one of the following methods:
•
•
We will post all comments on
Douglas Krofta, U.S. Fish and Wildlife Service, Division of Conservation and Classification, MS: ES, 5275 Leesburg Pike, Falls Church, VA 22041–3803; telephone 703/358–2171; facsimile 703/358–1735. If you use a telecommunications device for the deaf (TDD), call the Federal Information Relay Service (FIRS) at 800–877–8339.
Under the Endangered Species Act, as amended (Act; 16 U.S.C. 1531
Recently, as a result of petitions to list a large number of species under the Act, our workload includes more than 500 unresolved status reviews and accompanying 12-month findings on those petitions to complete. At the same time, our resources to complete these findings are limited. Over the last several years, we have streamlined, and continue to find efficiencies in, our procedures for evaluating petitions and conducting listing actions, but these efforts are not sufficient to keep up with the demands of our workload. This draft methodology is intended to allow us to address the outstanding workload of status reviews and accompanying 12-month findings strategically as our resources allow and to provide transparency to our partners and other stakeholders as to how we establish priorities within our upcoming workload.
To balance and manage this existing and anticipated future status review and accompanying 12-month finding workload in the most efficient manner, we have developed a draft methodology to help us use our resources wisely by working on the highest-priority status reviews and accompanying 12-month petition findings first. The draft methodology consists of identifying five prioritization categories for these actions, determining where (into which category) each action belongs, and using that information to establish the order in which we plan to complete status reviews and accompanying 12-month findings on petitions to list species under the Act. This prioritization of petition findings will inform a multi-year National Listing Workplan for completing all types of actions in the listing program workload—including not only status reviews and accompanying 12-month findings, but also status reviews initiated by the Service, proposed and final listing determinations, and proposed and final critical habitat designations. We intend to make the National Listing Workplan publically available on our Web site (
We plan to evaluate unresolved status reviews and accompanying 12-month findings for upcoming listing actions and prioritize them using the prioritization categories and additional considerations identified in this draft methodology to assign each action to one of five priority categories, or “bins,” as described below. In prioritizing status reviews and accompanying 12-month findings, we will consider information from the 90-day finding, any petitions, and any other information in our files. We recognize that we may not always have in our files the information necessary to assign an action to the correct bin, so we plan to also work with State fish and wildlife agencies, Native American Tribes, and other appropriate conservation partners who have management responsibility for these species or relevant scientific data to obtain the information necessary to allow us to accurately prioritize specific actions.
This priority system will assist us in compiling outstanding workload into a multi-year National Listing Workplan designed to address the species with the highest need first. It is our intention that the National Listing Workplan balance addressing the large backlog of status reviews and accompanying 12-month findings with making progress on other listing actions, such as making final listing determinations for candidate species and designating critical habitat. While this draft methodology was developed primarily to prioritize the outstanding status reviews and accompanying 12-month petition findings, the considerations raised in our prioritization categories may also be useful in prioritizing other actions in the listing program as we develop the National Listing Workplan each year. Prior to the start of each fiscal year, we will update the National Listing Workplan as new information is obtained. We will share the National Listing Workplan with other Federal agencies, State fish and wildlife agencies, Native American Tribes, and other stakeholders and the public at large through posting on our Web site (
Below we describe the categories we have identified for prioritizing listing actions and the information that factors into placing specific actions into the appropriate priority bin. Note that an action need not meet every facet of a particular bin in order to be placed in that bin. If an action meets the conditions for more than one bin, the Service will seek to prioritize that action by taking into consideration any case-specific information relevant to determining what prioritization would, overall, best advance the objectives of this draft methodology—including protecting the species that are most in need of, and that would benefit most from, listing under the Act first, and maximizing the efficiency of the listing program.
According to the standard under the Act, we need to make listing decisions based on the best available scientific and commercial data. Because the best available data for species in this bin may be very limited, even if the Service conducts further research, we will place a higher priority on work for those species for which we have more and better data already available.
The following considerations will also be used to inform implementation of the prioritization process, development of the National Listing Workplan, and any necessary internal ranking within each bin (
• The level of complexity surrounding the status review and accompanying 12-month finding, such as the degree of controversy, biological complexity, or whether the status review and accompanying 12-month finding covers multiple species or spans multiple regions of the Service.
• The extent to which the protections of the Act would be able to improve conditions for that species and its habitat or also provide benefits to many other species. For example, a species primarily under threat due to sea level rise from the effects of climate change is unlikely to have its condition much improved by the protections of the Act. By contrast, a species primarily under threat due to habitat destruction from grazing practices on public lands would more directly benefit from the protections of the Act.
• Whether there are opportunities to maximize efficiency by batching multiple species for the purpose of status reviews, petition findings, or listing determinations. For example, actions could be batched by taxon, by species with like threats, by similar geographic location, or other similar circumstances. Batching may result in lower-priority actions that are tied to higher-priority actions being completed earlier than they would otherwise.
• Whether there are any special circumstances whereby an action should be bumped up (or down) in priority when internally ranking actions within a bin or developing the National Listing Workplan. One limitation that might result in divergence from priority order is when the current highest priorities are clustered in a geographic area, such that our scientific expertise at the field office level is fully occupied with their existing workload. We recognize that the geographic distribution of our scientific expertise will in some cases require us to balance workload across geographic areas.
Section 4(h) of the ESA requires that, when the Secretary establishes guidelines to insure that the purposes of Section 4 are achieved efficiently and effectively, the Secretary provide to the public notice of, and opportunity to submit written comments on, those guidelines. In addition, we intend that a final methodology for prioritizing status reviews and accompanying 12-month findings for listing will consider information and recommendations from all interested parties. We therefore solicit comments, information, and recommendations from governmental agencies, Native American Tribes, the scientific community, industry groups, environmental interest groups, and any other interested parties. All comments and materials we receive by the date listed above in
If you submit information via
We seek comments and recommendations in particular on:
(1) Whether this draft methodology sets out clearly defined conditions for the prioritization bins. If not, please provide detailed comments so that we can clarify our methodology.
(2) Whether there may be other factors or considerations that should be incorporated into our methodology.
(3) Whether our draft methodology makes logical sense and will result in an appropriate use of our limited resources.
As mentioned above, we intend to use this methodology to prioritize work on
We are analyzing this draft methodology in accordance with the criteria of the National Environmental Policy Act (NEPA; 42 U.S.C. 4321
This draft methodology does not contain any collections of information that require approval by the Office of Management and Budget (OMB) under the Paperwork Reduction Act (44 U.S.C. 3501
In accordance with the President's memorandum of April 29, 1994, “Government-to-Government Relations with Native American Tribal Governments” (59 FR 22951), Executive Order 13175 “Consultation and Coordination with Indian Tribal Governments,” and the Department of the Interior Manual at 512 DM 2, and the Department of Commerce
The primary authors of this draft policy are the staff members of the Division of Conservation and Classification, U.S. Fish and Wildlife Service, 5275 Leesburg Pike, Falls Church, VA 22041.
The authority for this action is the Endangered Species Act of 1973, as amended (16 U.S.C. 1531
National Park Service, Interior.
Notice; request for comments.
We (National Park Service) will ask the Office of Management and Budget (OMB) to approve the information collection described below. As required by the Paperwork Reduction Act of 1995 and as part of our continuing efforts to reduce paperwork and respondent burden, we invite the general public and other Federal agencies to take this opportunity to comment on this IC. This IC is scheduled to expire on July 31, 2016. We may not conduct or sponsor and a person is not required to respond to a collection of information unless it displays a valid OMB control number.
To ensure we are able to consider your comments, we must receive them on or before March 15, 2016.
Please send your comments on the ICR to Madonna L. Baucum, Information Collection Clearance Officer, National Park Service, 12201 Sunrise Valley Drive, Room 2C114, Mail Stop 242, Reston, VA 20192 (mail); or
Diane Miller, National Manager, National Underground Railroad Network to Freedom Program, National Park Service, c/o Blackwater National Wildlife Refuge, 2145 Key Wallace Drive, Cambridge, Maryland 21613; or via email at
Public Law 105–203 (National Underground Railroad Network to Freedom Act of 1998) authorizes the Secretary of the Interior to establish the Network to Freedom (Network). The Network is a collection of sites, facilities, and programs, both governmental and nongovernmental, around the United States. All entities must have a verifiable association with the historic Underground Railroad movement. The National Park Service administers the National Underground Railroad Network to Freedom Program. The program coordinates preservation and education efforts Nationwide and integrates local historical places, museums, and interpretive programs associated with the Underground Railroad into a mosaic of community, regional, and national stories.
Individuals; businesses; organizations; State, tribal and local governments; and Federal agencies that want to join the Network must complete an application form. The application and instructions are available on our Web site at
Upon approval by OMB of this extension request, the NPS will begin developing a HTML version of the 10–946, “National Park Service National Underground Railroad Network to Freedom Application Form” on the Department of the Interior's Enterprise Forms System (EFS) Web site. The EFS will consolidate all internal forms used by the Department and external forms used by the public into a centralized automated forms program. This will
One of the principal components of the Network to Freedom Program is to validate the efforts of local and regional organizations, and to make it easier for them to share expertise and communicate with us and each other. The vehicle through which this can happen is for these local entities to become Network Partners. Partners of the Network to Freedom Program work alongside and often in cooperation with us to fulfill the program's mission. Prospective partners must submit a letter with the following information:
• Name and address of the agency, company or organization;
• Name, address, and phone, fax, and email information of principal contact;
• Abstract not to exceed 200 words describing the partner's activity or mission statement; and
• Brief description of the entity's association to the Underground Railroad.
We invite comments concerning this information collection on:
• Whether or not the collection of information is necessary, including whether or not the information will have practical utility;
• The accuracy of the burden for this collection of information;
• Ways to enhance the quality, utility, and clarity of the information to be collected; and
• Ways to minimize the burden to respondents, including use of automated information techniques or other forms of information technology.
Please note that the comments submitted in response to this notice are a matter of public record. We will include or summarize each comment in our request to OMB to approve this IC. Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment, including your personal identifying information, may be made publicly available at any time. While you can ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that it will be done.
National Park Service, Interior.
Notice; request for comments.
We (National Park Service, NPS) will ask the Office of Management and Budget (OMB) to approve the information collection (IC) described below. As required by the Paperwork Reduction Act of 1995 and as part of our continuing efforts to reduce paperwork and respondent burden, we invite the general public and other Federal agencies to take this opportunity to comment on this IC. We may not conduct or sponsor and a person is not required to respond to a collection of information unless it displays a currently valid OMB control number.
You must submit comments on or before March 15, 2016.
Send your comments on the IC to Madonna L. Baucum, Information Collection Clearance Officer, National Park Service, 12201 Sunrise Valley Drive (Room 2C114, Mail Stop 242), Reston, VA 20192 (mail); or
To request additional information about this IC, contact Charis Wilson, National Park Service, 12795 W. Alameda Parkway, P.O. Box 25287, Denver, CO 80225–0287 (mail); (303) 969–2959 (phone), or
The NPS maintains law enforcement incident reports in the Department of the Interior's Incident and Management Reporting System (IMARS), which is a Privacy Act System of Records (DOI–10). In accordance with the Privacy Act (5 U.S.C. 552a(b)), the NPS is barred from releasing copies of records contained within IMARS, including but not limited to motor vehicle accident reports, without the prior written request and/or consent of the individual to whom the record pertains unless authorized under appropriate routine-use exceptions.
The NPS requires the submission of NPS Form 10–945, “Case Incident Report Request” in order to verify a requester's identity and retrieve responsive records in order to respond
• Full name of Requester;
• Case Number;
• Social Security Number;
• Current Address;
• Date of Birth; and
• Place of birth.
We invite comments concerning this information collection on:
• Whether or not the collection of information is necessary, including whether or not the information will have practical utility;
• The accuracy of our estimate of the burden for this collection of information;
• Ways to enhance the quality, utility, and clarity of the information to be collected; and
• Ways to minimize the burden of the collection of information on respondents.
Comments that you submit in response to this notice are a matter of public record. Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment, including your personal identifying information, may be made publicly available at any time. While you can ask OMB in your comment to withhold your personal identifying information from public review, we cannot guarantee that it will be done.
National Park Service, Interior.
Notice; request for comments.
We (National Park Service, NPS) will ask the Office of Management and Budget (OMB) to approve the information collection (IC) described below. As required by the Paperwork Reduction Act of 1995 and as part of our continuing efforts to reduce paperwork and respondent burden, we invite the general public and other Federal agencies to take this opportunity to comment on this IC. This is a new collection. We may not conduct or sponsor and a person is not required to respond to a collection of information unless it displays a currently valid OMB control number.
To ensure that we are able to consider your comments on this IC, we must receive them by March 15, 2016.
Send your comments on the IC to Madonna L. Baucum, Information Collection Clearance Officer, National Park Service, 12201 Sunrise Valley Dr., MS–242, Rm. 2C114, Reston, VA 20192 (mail); or
To request additional information about this IC, please contact Dale Carpenter at telephone (304) 535–6401 or via email at
The NPS Common Learning Portal (CLP) will serve as a common location for advertising national, regional, and park specific training events to NPS employees. The CLP is focused on increasing the visibility of training available to NPS employees and is also making the site available to the public to allow NPS partners, retired NPS employees, and other interested persons not directly affiliated with the NPS access. The CLP also establishes communities of practice using interest groups and forums in order to increase communication among the NPS training community. The CLP includes an Ask the Expert feature where industry experts or retired NPS employees who are experts in their field can field questions from NPS employees. Individuals may visit the Common Learning Portal to learn about upcoming training events without providing any information. However, in order to participate in community forum discussions, an account on the site must be created. Registering for an account requires the user provide the following information for use in the community discussion forums:
• Name,
• Email address, and
• Username.
Once registered, the user has the opportunity to voluntarily provide additional information on their portal profile, to include:
• Photo (optional)
• Title
• Location,
• Expertise,
• Duties, and
• Additional personal information such as hobbies or activities.
Additional information provided by the individual in these text fields such
Frequency of Collection: One time.
We invite comments concerning this information collection on:
• Whether or not the collection of information is necessary, including whether or not the information will have practical utility;
• The accuracy of our estimate of the burden for this collection of information;
• Ways to enhance the quality, utility, and clarity of the information to be collected; and
• Ways to minimize the burden of the collection of information on respondents.
Comments that you submit in response to this notice are a matter of public record. We will include or summarize each comment in our request to OMB to approve this IC. Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment, including your personal identifying information, may be made publicly available at any time. While you can ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.
National Park Service, Interior.
Notice.
The National Park Service is soliciting comments on the significance of properties nominated before December 19, 2015, for listing or related actions in the National Register of Historic Places.
Comments should be submitted by February 1, 2016.
Comments may be sent via U.S. Postal Service to the National Register of Historic Places, National Park Service, 1849 C St. NW., MS 2280, Washington, DC 20240; by all other carriers, National Register of Historic Places, National Park Service, 1201 Eye St. NW., 8th floor, Washington, DC 20005; or by fax, 202–371–6447.
The properties listed in this notice are being considered for listing or related actions in the National Register of Historic Places. Nominations for their consideration were received by the National Park Service before December 19, 2015. Pursuant to section 60.13 of 36 CFR part 60, written comments are being accepted concerning the significance of the nominated properties under the National Register criteria for evaluation.
Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment—including your personal identifying information—may be made publicly available at any time. While you can ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.
A request to move has been received for the following resource:
A request to remove has been received for the following resource:
60.13 of 36 CFR part 60
United States International Trade Commission.
Notice.
The Commission hereby gives notice of the institution of investigations and commencement of preliminary phase antidumping and countervailing duty investigation Nos. 701–TA–551–553 and 731–TA–1307–1308 (Preliminary) pursuant to the Tariff Act of 1930 (“the Act”) to determine whether there is a reasonable indication that an industry in the United States is materially injured or threatened with material injury, or the establishment of an industry in the United States is materially retarded, by reason of certain imports of new pneumatic off-the-road-tires from China, India and Sri Lanka provided for in subheadings 4011.20.10, 4011.20.50, 4011.61.00, 4011.62.00, 4011.63.00, 4011.69.00, 4011.92.00, 4011.93.40, 4011.93.80, 4011.94.40, 4011.94.80, 8431.49.90, 8709.90.00, and 8716.90.10 of the Harmonized Tariff Schedule of the United States.
Michael Szustakowski (202–205–3169), Office of Investigations, U.S. International Trade Commission, 500 E Street SW., Washington, DC 20436. Hearing-impaired persons can obtain information on this matter by contacting the Commission's TDD terminal on 202–205–1810. Persons with mobility impairments who will need special assistance in gaining access to the Commission should contact the Office of the Secretary at 202–205–2000. General information concerning the Commission may also be obtained by accessing its internet server (
For further information concerning the conduct of these investigations and rules of general application, consult the Commission's Rules of Practice and Procedure, part 201, subparts A and B (19 CFR part 201), and part 207, subparts A and B (19 CFR part 207).
In accordance with sections 201.16(c) and 207.3 of the rules, each document filed by a party to the investigations must be served on all other parties to the investigations (as identified by either the public or BPI service list), and a certificate of service must be timely filed. The Secretary will not accept a document for filing without a certificate of service.
These investigations are being conducted under authority of title VII of the Tariff Act of 1930; this notice is published pursuant to section 207.12 of the Commission's rules.
By order of the Commission.
United States International Trade Commission.
January 20, 2016 at 11:00 a.m.
Room 101, 500 E Street SW., Washington, DC 20436, Telephone: (202) 205–2000.
Open to the public.
In accordance with Commission policy, subject matter listed above, not disposed of at the scheduled meeting, may be carried over to the agenda of the following meeting.
By order of the Commission.
Notice of registration.
Cambridge Isotope Lab applied to be registered as a
By notice dated October 2, 2015, and published in the
The DEA has considered the factors in 21 U.S.C. 823(a) and determined that the registration of Cambridge Isotope Lab to manufacture the basic class of controlled substance is consistent with the public interest and with United States obligations under international treaties, conventions, or protocols in effect on May 1, 1971. The DEA investigated the company's maintenance of effective controls against diversion by inspecting and testing the company's physical security systems, verifying the company's compliance with state and local laws, and reviewing the company's background and history.
Therefore, pursuant to 21 U.S.C. 823(a), and in accordance with 21 CFR 1301.33, the above-named company is granted registration as a bulk manufacturer of morphine (9300), a basic class of controlled substance listed in schedule II.
The company plans to utilize small quantities of the listed controlled substance in the preparation of analytical standards.
On January 12, 2016, a proposed Stipulation and Settlement Agreement establishing an Environmental Response Trust for the Gulfport, Mississippi Facility (“Gulfport Settlement Agreement”) was filed with the United States Bankruptcy Court for the District of Delaware in the bankruptcy proceeding entitled
Under the proposed Gulfport Settlement Agreement, an Environmental Response Trust will be created to take title to certain property owned by Reichhold Inc., located in Gulfport, Mississippi. The Environmental Response Trust will perform certain environmental actions with respect to the property. The Environmental Response Trust will receive the proceeds of a letter of credit in the approximate amount of $3.5 million and $750,000 provided by the Debtor. The Gulfport Settlement Agreement includes covenants not to sue under the Resource Conservation and Recovery Act (“RCRA”), 42 U.S.C. 6901
The publication of this notice opens a period for public comment on the Gulfport Settlement Agreement. Comments should be addressed to the Assistant Attorney General, Environment and Natural Resources Division, and should refer to
Under section 7003(d) of RCRA, a commenter may request an opportunity for a public meeting in the affected area.
During the public comment period, the Settlement Agreement may be examined and downloaded at this Justice Department Web site:
Please enclose a check or money order for $15.00 (25 cents per page reproduction cost) payable to the United States Treasury.
On January 12, 2016, a proposed Settlement Agreement between the United States and the Debtors (“Settlement Agreement”) was filed with the United States Bankruptcy Court for the District of Delaware in the bankruptcy proceeding entitled
The proposed Settlement Agreement will resolve certain proofs of claim asserted against Debtor Reichhold Inc. under the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), 42 U.S.C. 9601–9675, for costs incurred and to be incurred by the United States in connection with certain sites, and for natural resource damages and costs of assessment at or in connection with certain sites.
Under the proposed Settlement Agreement the United States will have the following allowed general unsecured claims in the above referenced bankruptcy proceeding: 1)With respect to the Peterson/Puritan, Inc. Superfund Site in Rhode Island, the United States on behalf of EPA shall have an Allowed General Unsecured Claim of $205,211; 2) With respect to the Berry's Creek Study Area operable unit of the Ventron/Velsicol Superfund Site in New Jersey, the United States on behalf of EPA shall have an Allowed General Unsecured Claim of $400,000; 3) With respect to the Lower Passaic River Study Area of the Diamond Alkali Superfund Site in New Jersey, the United States on behalf of EPA shall have an Allowed General Unsecured Claim of $8,000,000; 4) With respect to the Yosemite Slough Superfund Site in California, the United States on behalf of EPA shall have an Allowed General Unsecured Claim of $268,000; 5) With respect to the Lower Duwamish Waterway Superfund Site in Washington: (i) The United States on behalf of EPA shall have an Allowed General Unsecured Claim of $4,300,000; (ii) the United States on behalf of National Oceanic and Atmospheric Administration (“NOAA”) shall have an Allowed General Unsecured Claim of $5,937; and (iii) the United States on behalf of the Department of Interior (“DOI”) shall have an Allowed General Unsecured Claim of $558,897.74 (which includes DOI assessment costs of $3,897.74); 6) With respect to the Kin-
The Settlement Agreement includes certain covenants not to sue under Sections 106 and 107 of CERCLA, 42 U.S.C. 9606 or 9607, with respect to the above referenced Sites. DOI and NOAA are providing a covenant not to sue under Section 107 of CERCLA, 42 U.S.C. 9607 with respect to each Site for which they are receiving an allowed claim.
The publication of this notice opens a period for public comment on the Settlement Agreement—Gulfport. Comments should be addressed to the Assistant Attorney General, Environment and Natural Resources Division, and should refer to
During the public comment period, the Settlement Agreement may be examined and downloaded at this Justice Department Web site:
Please enclose a check or money order for $ 9.75 (25 cents per page reproduction cost) payable to the United States Treasury.
Bureau of Alcohol, Tobacco, Firearms and Explosives, Department of Justice.
30-day notice.
The Department of Justice (DOJ), Bureau of Alcohol, Tobacco, Firearms and Explosives (ATF), will submit the following information collection request to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995. The proposed information collection was previously published in the
Comments are encouraged and will be accepted for an additional 30 days until February 16, 2016.
If you have additional comments especially on the estimated public burden or associated response time, suggestions, or need a copy of the proposed information collection instrument with instructions or additional information, please contact Andrew Ashton, NFA Branch Specialist, 244 Needy Road, Martinsburg, WV 25402, at: 304–616–4501 or
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information are encouraged. Your comments should address one or more of the following four points:
• Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
• Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
• Evaluate whether and if so how the quality, utility, and clarity of the information to be collected can be enhanced; and
• Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology,
1.
2.
3.
Form number: ATF F 10 (5320.10).
Component: Bureau of Alcohol, Tobacco, Firearms and Explosives, U.S. Department of Justice.
4.
Primary: State Local or Tribal Governments.
Other: None.
Abstract: The form is required to be submitted by State and local government entities wishing to register
5.
6.
If additional information is required contact: Jerri Murray, Department Clearance Officer, United States Department of Justice, Justice Management Division, Policy and Planning Staff, Two Constitution Square, 145 N Street NE., Room 3E–405B, Washington, DC 20530.
Drug Enforcement Administration, Department of Justice
60-day notice.
The Department of Justice (DOJ), Drug Enforcement Administration (DEA), will be submitting the following information collection request to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995.
Comments are encouraged and will be accepted for 60 days until March 15, 2016.
If you have comments on the estimated public burden or associated response time, suggestions, or need a copy of the proposed information collection instrument with instructions or additional information, please contact Barbara J. Boockholdt, Office of Diversion Control, Drug Enforcement Administration; Mailing Address: 8701 Morrissette Drive, Springfield, Virginia 22152; Telephone: (202) 598–6812.
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information are encouraged. Your comments should address one or more of the following four points:
1.
2.
3.
4.
5.
6.
If additional information is required please contact: Jerri Murray, Department Clearance Officer, United States Department of Justice, Justice Management Division, Policy and Planning Staff, Two Constitution Square, 145 N Street NE., Suite 3E.405B, Washington, DC 20530.
Office of Justice Programs (OJP), Justice.
Notice of meeting.
This is an announcement of a meeting of DOJ's National Motor Vehicle Title Information System (NMVTIS) Federal Advisory Committee to discuss various issues relating to the operation and implementation of NMVTIS.
The meeting will take place on Tuesday, February 9, 2016, from 9:00 a.m. to 4:00 p.m. ET.
The meeting will take place at the Office of Justice Programs, 810 7th Street NW., Washington, DC 20531.
Todd Brighton, Designated Federal Employee (DFE), Bureau of Justice Assistance, Office of Justice Programs, 810 7th Street NW., Washington, DC 20531; Phone: (202) 616–3879 [note: this is not a toll-free number]; Email:
This meeting is open to the public. Members of the public who wish to attend this meeting must register with Mr. Brighton at the above address at least seven (7) days in advance of the meeting. Registrations will be accepted on a space available basis. Access to the meeting will not be allowed without registration. Please bring photo identification and allow extra time prior to the meeting. Interested persons whose registrations have been accepted may be permitted to participate in the discussions at the discretion of the meeting chairman and with approval of the DFE.
Anyone requiring special accommodations should notify Mr. Brighton at least seven (7) days in advance of the meeting.
The NMVTIS Federal Advisory Committee will provide input and recommendations to OJP regarding the operations and administration of NMVTIS. The primary duties of the NMVTIS Federal Advisory Committee will be to advise the Bureau of Justice Assistance Director on NMVTIS-related issues, including but not limited to: Implementation of a system that is self-sustainable with user fees; options for alternative revenue-generating opportunities; determining ways to enhance the technological capabilities of the system to increase its flexibility; and options for reducing the economic burden on current and future reporting entities and users of the system.
Office of Management and Budget (OMB).
Notice.
This report is being published as required by the Statutory Pay-As-You-Go (PAYGO) Act of 2010, 2 U.S.C. 931
Patrick Locke. 202–395–3672.
This report and additional information about the PAYGO Act can be found at
2 U.S.C. 934
This Report describes the budgetary effects of all PAYGO legislation enacted during the first session of the 114th Congress, including legislative provisions designated as emergency requirements under section 4(g) of the PAYGO Act, and presents the 5-year and 10-year PAYGO scorecards maintained by OMB. Because neither the 5-year nor 10-year scorecard shows a debit for the budget year, which for purposes of this Report is fiscal year 2016,
During the first session of the 114th Congress, one law was enacted with emergency requirements under section 4(g) of the PAYGO Act, 2 U.S.C. 933(g) and one law was enacted that authorized a new purpose for prior emergency funding. The scorecards include no current policy adjustments made under section 4(c) of the PAYGO Act, 2 U.S.C. 933(c). The authority for current policy adjustments expired as of December 31, 2011, so the Report does not contain any information about or descriptions of any current policy adjustments.
PAYGO legislation is authorizing legislation that affects direct spending or revenues, and appropriations legislation that affects direct spending in the years beyond the budget year or affects revenues in any year.
The 5-year and 10-year PAYGO scorecards for each congressional session begin with the balances of costs or savings carried over from previous sessions and then tally the costs or savings of PAYGO laws enacted in that session. The 5-year PAYGO scorecard for the first session of the 114th Congress began with balances of costs of $440 million in 2016, and balances of savings of $1,440 million in 2017, $601 million in 2018, and $626 million in 2019. The completed 5-year scorecard for the session shows that PAYGO legislation enacted during the session was estimated to have PAYGO budgetary effects that reduced the deficit by an average of $3,456 million each year from 2016 through 2020.
The 10-year PAYGO scorecard for the first session of the 114th Congress began with balances of savings of $9,730 million in each year from 2016 to 2020, $3,359 million in 2021, $2,649 million in 2022, $1,514 million in 2023, and $1,521 million in 2024. The completed 10-year scorecard for the session shows that PAYGO legislation for the session reduced the deficit by an average of $5,718 million each year from 2016 through 2025. These new savings increased the balances of savings in each year on the 10-year scorecard from 2016 through 2024, and created new savings in 2025.
In the first session of the 114th Congress, 35 laws were enacted that were determined to constitute PAYGO legislation. Of the 35 enacted PAYGO laws, 15 laws were estimated to have PAYGO budgetary effects (costs or savings) in excess of $500,000 over one or both of the 5-year or 10-year PAYGO windows. These were:
• Terrorism Risk Insurance Program Reauthorization Act of 2015, Public Law 114–1;
• Construction Authorization and Choice Improvement Act, Public Law 114–19;
• Justice for Victims of Trafficking Act of 2015, Public Law 114–22;
• A bill to extend the authorization to carry out the replacement of the existing medical center of the Department of Veterans Affairs in Denver, Colorado, to authorize transfers of amounts to carry out the replacement of such medical center, and for other purposes, Public Law 114–25;
• Trade Preferences Extension Act of 2015, Public Law 114–27;
• Steve Gleason Act of 2015, Public Law 114–40;
• Surface Transportation and Veterans Health Care Choice Improvement Act of 2015, Public Law 114–41;
• Department of Veterans Affairs Expiring Authorities Act of 2015, Public Law 114–58;
• Protecting Affordable Coverage for Employees Act, Public Law 114–60;
• Adoptive Family Relief Act, Public Law 114–70;
• Bipartisan Budget Act of 2015, Public Law 114–74;
• National Defense Authorization Act for Fiscal Year 2016, Public Law 114–92;
• Federal Perkins Loan Program Extension Act of 2015, Public Law 114–105;
• Consolidated Appropriations Act of 2016, Public Law 114–113; and
• Patient Access and Medicare Protection Act, Public Law 114–115.
In addition to the laws identified above, 20 laws enacted in this session were estimated to have negligible budgetary effects on the PAYGO scorecards—costs or savings of less than $500,000 over both the 5-year and 10-year PAYGO windows.
As shown on the scorecards, one law was enacted in the first session of the 114th Congress with an emergency designation under the Statutory PAYGO Act: the Surface Transportation and Veterans Health Care Choice Improvement Act of 2015, Public Law 114–41. The effects of the provisions in this law that are designated as emergency requirements appear on the scorecard, but the effects are subtracted before computing the scorecard totals.
Scorekeeping guidelines adopted by the Office of Management and Budget, the Congressional Budget Office, and the congressional budget committees preclude scoring savings for the subsequent repurposing of spending that was designated as emergency spending when enacted. Although the laws repurposing the emergency spending are reported on the PAYGO scorecards maintained by OMB, the associated savings are not included in the balances on the scorecards that are used to determine the need for a sequestration. In this congressional session, the Construction Authorization and Choice Improvement Act, Public Law 114–19, repurposed spending in the VA Choice program by expanding the eligibility for the program to additional veterans. This adjustment resulted in excluding $47 million in savings over 2015–2020 from the scorecard totals.
Four laws enacted in the first session of the 114th Congress had estimated budgetary effects on direct spending and revenues that are not included in the calculations for the PAYGO scorecards due to provisions in law excluding all or part of the law from section 4(d) of the Statutory Pay-As-You-Go Act of 2010. Three laws included provisions excluding their budgetary effects from the PAYGO scorecards entirely: Public Law 114–10, the Medicare Access and CHIP Reauthorization Act of 2015; Public Law 114–26, the Defending Public Safety Employees' Retirement Act; and Public Law 114–94, the FAST Act. In addition, one law included a provision excluding certain portions of the law from the scorecards: Public Law 114–113, Consolidated Appropriations Act of 2016, for which Divisions M, N, O, P, and Q were excluded from the scorecards.
The Bipartisan Budget Act of 2015 (BBA 2015), Public Law 114–74, increased the limits on discretionary spending for 2016 and 2017, reduced direct spending and increased revenues in a number of programs, extended to 2025 the sequestration of direct spending under the Joint Committee enforcement procedures of the Budget Control Act of 2011, and temporarily suspended the statutory limit on Federal debt. The PAYGO effects shown on the scorecard for BBA 2015 are limited to those effects stemming from changes in the authorizations for direct spending programs and revenues. The revised limits on discretionary appropriations and the extension of Joint Committee sequestration of direct spending are not included in the effects on the scorecard. Because the revisions to the discretionary spending limits apply only to future levels of discretionary appropriations and did not change the level of appropriations at the point that BBA 2015 was enacted, OMB determined that these provisions of BBA 2015 do not have budgetary effects under the PAYGO Act. Similarly, because future sequestration of direct spending is triggered one year at a time under the Joint Committee enforcement procedures, providing an opportunity for future congressional action to avoid these enforcement measures, OMB does not include future direct spending sequestration in the baseline it uses to estimate budgetary effects under the PAYGO Act and extension of direct spending sequestration therefore does not have a budgetary effect for purposes of OMB's PAYGO estimates.
The total net budgetary effects of all PAYGO legislation enacted during the first session of the 114th Congress on the 5-year scorecard reduce the deficit by $17,280 million. This total is averaged over the years 2016 to 2020 on the 5-year PAYGO scorecard, resulting in savings of $3,456 million in each year. Combining these savings with balances carried over from prior sessions of the Congress creates total net savings in 2016 of $3,016 million, $4,896 million in 2017, $4,057 million in 2018, and $4,082 million in 2019. The 5-year PAYGO window extended only through 2019 in the second session of the 113th Congress, so there were no 5-year scorecard balances in 2020 to carry over and the 5-year scorecard total is the average $3,456 million savings from this session.
The total 10-year net impact of legislation enacted during the first session of the 114th Congress was savings of $57,183 million. The 10-year PAYGO scorecard shows the total net impact averaged over the 10-year period, resulting in savings of $5,718 million in each year. Combining these savings with balances from prior sessions results in net savings of $15,448 million in 2016 through 2020, $9,077 million in 2021, $8,367 million in 2022, $7,232 million in 2023, and $7,239 million in 2024. The 10-year PAYGO window extended only through 2024 in the second session of the 113th Congress, so there were no 10-year scorecard balances in 2025 to carry over and the 10-year scorecard total is the average $5,718 million savings from this session.
As shown on the scorecards, the budgetary effects of PAYGO legislation enacted in the first session of the 114th Congress, combined with the balances left on the scorecard from previous sessions of the Congress, resulted in net savings on both the 5-year and the 10-year scorecard in the budget year, which is 2016 for the purposes of this Report. Because the costs for the budget year, as shown on the scorecards, do not exceed savings for the budget year, there is no “debit” on either scorecard under section 3 of the PAYGO Act, 2 U.S.C. § 932, and there is no need for a sequestration order.
The savings shown on the scorecards for 2016 will be removed from the scorecards that are used to record the budgetary effects of PAYGO legislation enacted in the second session of the 114th Congress. The totals shown in 2017 through 2025 will remain on the scorecards and will be used in determining whether a sequestration order will be necessary in the future. All of the years of the 5-year and 10-year scorecards that will carry over into the second session of the 114th Congress will show balances of savings.
Marine Mammal Commission.
Notice of public meetings.
The Marine Mammal Commission (Commission) will hold a series of public meetings pursuant to the Government in the Sunshine Act and the Federal Advisory Committee Act in various locations in Alaska from February 3–February 11, 2016. This notice announces the date, time, and location of the public meetings.
Four public meetings will be held: February 3, 2016, 3 p.m.–5 p.m. (Barrow, AK); February, 5, 2016, 1 p.m.–5 p.m. (Kotzebue, AK); February 9, 2016, 3 p.m.–6 p.m. (Nome, AK); February 11, 2016, 8 a.m.–1 p.m. (Anchorage, AK).
The public meetings will be held at the following locations: February 3, 2016, Inupiat Heritage Center, 5421 North Star Street, Barrow, AK 99723; February 5, 2016, Northwest Arctic Borough Assembly Room, 163 Lagoon St, Kotzebue, AK 99752; February 9, 2016, University of Alaska Fairbanks Northwest Campus, 400 East Front Street, Nome, AK 99762, Main Building, Nagozruk Conference Room; February 11, 2016, Bureau of Ocean Energy Management, 3801 Centerpoint Drive, Anchorage, AK 99503. The Anchorage meeting will also be accessible via webinar. Information for accessing the webinar will be posted at
Luis Leandro, Program Specialist, Marine Mammal Commission, 301–504–0087,
The Marine Mammal Commission (Commission) will meet in Barrow, Kotzebue, and Nome to solicit information from these communities and surrounding Native villages regarding environmental changes being observed in these areas, changes in the availability of marine mammals for subsistence and handicraft purposes, and Alaska Native concerns regarding marine mammal and related issues in general. All of these meetings will be open to the public.
Following these meetings, the Commission and its Committee of Scientific Advisors on Marine Mammals will meet in Anchorage, and via webinar, to review the information and views provided at the other public meetings and discuss possible actions by the Commission. This meeting will be open to attendance by the public. The public may also participate in the Anchorage meeting via webinar. The meeting will include an opportunity for comments by the public. Detailed
These meetings are designed to further implementation of the Commission's Strategic Plan, which recognizes that the Arctic warrants special attention because its marine mammals, ecosystems, and marine mammal dependent coastal communities are being impacted profoundly by climate change. The Commission's focus on Alaska and the Arctic includes current work to promote effective consultation procedures between Alaska Native Tribes and federal agencies, efforts to improve understanding of the cumulative impacts of climate change and human activities on Arctic marine mammals, and engagement in domestic and international science and management programs for polar bears, walrus, ice seals, and beluga and bowhead whales.
A proposed agenda for the Anchorage meeting is posted on the Commission's Web site at
Additional information about the Marine Mammal Commission, the Alaska meetings, and documents related to the Commission's consultations with Native communities can be found at
National Aeronautics and Space Administration (NASA).
Notice of proposed revisions to existing Privacy Act systems of records.
Pursuant to the provisions of the Privacy Act of 1974 (5 U.S.C. 552a), the National Aeronautics and Space Administration is issuing public notice of its proposal to modify two of its previously noticed system of records. This notice publishes updates to systems of records as set forth below under the caption
Submit comments within 30 calendar days from the date of this publication. The changes will take effect at the end of that period, if no adverse comments are received.
Patti F. Stockman, Privacy Act Officer, Office of the Chief Information Officer, National Aeronautics and Space Administration Headquarters, Washington, DC 20546–0001, (202) 358–4787,
NASA Privacy Act Officer, Patti F. Stockman, (202) 358–4787,
Pursuant to the provisions of the Privacy Act of 1974, 5 U.S.C. 552a, and as part of its biennial System of Records review, NASA is making modifications to two human resource related systems of records including: Update of Locations and Categories of records; addition of Purpose statements; and elaboration of Safeguards sections. Changes for specific NASA systems of records are set forth below:
NASA Personnel and Payroll Systems/NASA 10NPPS: Updating Locations of Records, adding a Purpose section and elaborating the Safeguards section to be more precise. Special Personnel Records/NASA 10SPER: Updating Locations and Categories of Records, adding a Purpose section and elaborating the Safeguards section to be more complete.
Submitted by:
Locations 9 and 18, as set forth in Appendix A; in the Federal Personnel and Payroll System of the Department of Interior Federal agency Human Resources Shared Service Center located at National Business Center, 7301 W. Mansfield, Denver, Co. 80235; and in the Office of Personnel Management's Electronic Official Personnel File located at the National Business Center 7301 W. Mansfield, Denver, Co. 80235.
This system maintains information on present and former NASA employees.
The data contained in this system of records includes payroll, employee leave, insurance, labor and human resource distribution and overtime information.
Records in this system are used to facilitate NASA administration of payroll functions and personnel decisions.
51 U.S.C. 20113(a); 44 U.S.C. 3101; 5 U.S.C. 5501
Any disclosures of information will be compatible with the purpose for which the Agency collected the information. The following are routine uses: (1) To furnish to a third party a verification of an employee's status upon written request of the employee; (2) to facilitate the verification of employee contributions and insurance data with carriers and collection agents; (3) to report to the Office of Personnel Management (a) withholdings of premiums for life insurance, health benefits, and retirements, and (b) separated employees subject to retirement; (4) to furnish the U.S. Treasury magnetic tape reports and/or electronic files on net pay, net savings allotments and bond transmittal pertaining to each employee; (5) to provide the Internal Revenue Service with details of wages taxable under the Federal Insurance Contributions Act and to furnish a magnetic tape listing on Federal tax withholdings; (6) to furnish various financial institutions itemized listings of employee's pay and savings allotments transmitted to the institutions in accordance with employee requests; (7) to provide various Federal, State, and local taxing authorities itemized listings of withholdings for individual income taxes; (8) to respond to requests for State employment security agencies and the U.S. Department of Labor for employment, wage, and separation data on former employees for the purpose of determining eligibility for unemployment compensation; (9) to report to various Combined Federal Campaign offices total contributions withheld from employee wages; (10) to furnish leave balances and activity to the Office of Personnel Management upon request; (11) to furnish data to labor organizations in accordance with negotiated agreements; (12) to furnish pay data to the Department of State for certain NASA employees located outside the United States; (13) to furnish data to a consumer reporting agency or bureau, private collection contractor or
Records are maintained in electronic format.
Records are retrieved from the system by the individual's name, unique personal identification code and/or Social Security Number.
Electronic records are maintained on secure NASA servers and protected in accordance with all Federal standards. Additionally, NASA server and data management environments employ infrastructure encryption technologies both in data transmission and at rest on servers. Electronic messages sent within and outside of the Agency that convey sensitive data are encrypted and transmitted by staff via pre-approved electronic encryption systems as required by NASA policy. Approved security plans are in place for information systems containing the records in accordance with FISMA and OMB Circular A–130, Management of Federal Information Resources. Only authorized personnel requiring information in the official discharge of their duties are authorized access to records through approved access or authentication methods. Access to electronic records is achieved only from workstations within the NASA Intranet or via a secure Virtual Private Network (VPN) connection that requires two-factor hardware token authentication or via employee PIV badge authentication from NASA-issued computers. The Department of Interior and Office of Personnel Management Federal agency servers in Denver are also compliant with the FISMA and OMB Circular A–130 security standards and requirements.
Records are maintained and transferred to the National Personnel Records Center (NPRC) in accordance with NASA Records Retention Schedules, Schedule 3 Item 47. Records transferred to NPRC will be destroyed when 10 years old by NPRC.
Director, Financial Management Division, Office of the Chief Financial Officer, and Assistant Administrator for Human Capital Management, Office of Human Capital Management, Location 1.
Subsystem Managers: Chief Financial Officers and Human Capital Officers, Locations 2 through 9, and 11, Director, Financial Management Division, and Director, Human Resources Division, Location 18. Locations are as set forth in Appendix A.
Information may be obtained from the cognizant system or subsystem manager listed above.
Requests from individuals should be addressed to the same address as identified in the Notification section above.
The NASA regulations for access to records and for contesting contents and appealing initial determinations by the individual concerned appear at 14 CFR part 1212.
Individual on whom the record is maintained, personnel office(s), and the individual's supervisor.
None.
Special Personnel Records.
None.
Locations 1 through 9 inclusive, and locations 11 and 18 as set forth in Appendix A, and at the Department of Interior Federal Agency Human Resources Shared Service Center located at National Business Center 7301 W. Mansfield, Denver Co, 80235.
This system maintains information on candidates for and recipients of awards or NASA training; civilian and active duty military detailees to NASA; participants in enrollee programs; Faculty, Science, National Research Council and other Fellows, associates and guest workers including those at NASA Centers but not on NASA rolls; NASA contract and grant awardees and their associates having access to NASA premises and records; individuals with interest in NASA matters including Advisory Committee Members; NASA employees and family members, prospective employees and former employees; former and current participants in existing and future educational programs, including the Summer High School Apprenticeship Research Program (SHARP).
Special Program Files including: (1) Foreign National Scientist files; (2) Applications for, and issuance of, passports and visas together with other information for international government travel; (3) Award files; (4) Counseling files, Life and Health Insurance, Retirement, Upward Mobility, and Work Injury Counseling files; (5) Military and Civilian detailee files; (6) Personnel Development files such as nominations for and records of training or education, Upward Mobility Program files, Intern Program files, Apprentice files, and Enrollee Program files; (7) Special Employment files such as Federal Junior Fellowship Program files, Pathways Program files, Summer Employment files, Worker-Trainee Opportunity Program files, NASA Executive Position files, Expert and Consultant files, and Cooperative Education Program files; (8) Welfare to Work files; and (9) Supervisory Appraisals under Competitive Placement Plan. Correspondence and related information including: (1) Claims correspondence and records about insurance such as life, health, and travel; (2) Congressional and other Special Interest correspondence, including employment inquiries; (3) Correspondence and records concerning travel related to permanent change of address; (4) Debt complaint
Special Records and Rosters including: (1) Locator files, (2) Ranking lists of employees; (3) Promotion candidate lists; (4) Retired military employee records; (5) Retiree records; (6) Follow-up records for educational programs, such as the SHARP and other existing or future programs. Agencywide and Center automated personnel information: Rosters, applications, recommendations, assignment information and evaluations of Faculty, Science, National Research Council and other Fellows, associates and guest workers including those at NASA Centers but not on NASA rolls; also, information about NASA contract and grant awardees and their associates having access to NASA premises and records.
Information about members of advisory committees and similar organizations: All NASA-maintained information of the same types as, but not limited to, that information required in systems of records for which the Office of Personnel Management and other Federal personnel-related agencies publish Government wide Privacy Act Notices in the
Records in this system enable NASA to manage Personnel records used to make personnel employment decisions and to facilitate decisions regarding employees' rights and benefits of employees, and other special personnel associated with NASA and listed in Categories of Individuals of this system notice.
51 U.S.C. 20113(a); 44 U.S.C. 3101.
Any disclosures of information will be compatible with the purpose for which the Agency collected the information. The following are routine uses: (1) Disclosures to organizations or individuals having contract, legal, administrative or cooperative relationships with NASA, including labor unions, academic organizations, governmental organizations, non-profit organizations, and contractors and to organizations or individuals seeking or having available a service or other benefit or advantage. The purpose of such disclosures is to satisfy a need or needs, further cooperative relationships, offer information, or respond to a request; (2) disclosures to Federal agencies developing statistical or data presentations having need of information about individuals in the records; (3) responses to other Federal agencies and other organizations having legal or administrative responsibilities related to programs and individuals in the records; and (4) NASA standard routine uses as set forth in Appendix B.
Records in this system are maintained as hard-copy documents and on electronic media.
Records are retrieved from the system by any one or a combination of name, birth date, Social Security Number, or NASA unique identification number.
Electronic records are maintained on secure NASA servers and protected in accordance with all Federal standards and those established in NASA regulations at 14 CFR 1212.605. Additionally, NASA server and data management environments employ infrastructure encryption technologies both in data transmission and at rest on servers. Electronic messages sent within and outside of the Agency that convey sensitive data are encrypted and transmitted by staff via pre-approved electronic encryption systems as required by NASA policy. Approved security plans are in place for information systems containing the records in accordance with the Federal Information Security Management Act of 2002 (FISMA) and OMB Circular A–130, Management of Federal Information Resources. Only authorized personnel requiring information in the official discharge of their duties are authorized access to records through approved access or authentication methods. Access to electronic records is achieved only from workstations within the NASA Intranet or via a secure Virtual Private Network (VPN) connection that requires two-factor hardware token authentication or via employee PIV badge authentication from NASA-issued computers. The Department of Interior Federal agency Human Resources Shared Service Center in Denver is also compliant with the FISMA and OMB Circular A–130 security standards and requirements.
Non-electronic records are secured in locked rooms or locked file cabinets. For information systems maintained by NASA partners, who collect, store and process records on behalf of NASA, NASA requires documentation and verification of commensurate safeguards in accordance with FISMA, NASA Procedural Requirements (NPR) 2810.1A, and NASA ITS–HBK–2810.02–05.
Records are maintained and dispositioned in accordance with NASA Records Retention Schedules (NRRS) 3, Item 19.
Associate Administrator for Human Capital Management, Location 1. Subsystem Managers: Director, Personnel Division, Office of Inspector General, and Chief, Elementary and Secondary Programs Branch, Educational Division, Location 1; Director of Personnel, Locations 1, 3, 4, 6, and 8; Director of Human Resources, Location 2, 5, and 9; Director, Office of Human Resources, Location 7; Human Resources Officer, Location 11; Director, Human Resources Services Division, Location 18. Locations are as set forth in Appendix A.
Apply to the System or Subsystem Manager at the appropriate location above. In addition to personal identification (name, Social Security Number), indicate the specific type of record, the appropriate date or period of time, and the specific category of individual applying (
Same as Notification procedures above.
The NASA regulations pertaining to access to records and for contesting contents and appealing initial
Individual on whom the record is maintained and Personnel Office(s).
None.
Nuclear Regulatory Commission.
Confirmatory order; issuance.
The U.S. Nuclear Regulatory Commission (NRC) is authorizing the licensees to transfer, receive, possess, transport, import, and use certain firearms and large-capacity ammunition feeding devices not previously permitted to be owned or possessed under Commission authority, notwithstanding certain local, State, or Federal firearms laws, including regulations that prohibit such actions, as reflected in the confirmatory orders for the nuclear plant facilities listed above.
Each confirmatory order was issued to the licensees on January 5, 2016. The effective dates are reflected in the attached orders.
Please refer to Docket ID: NRC–2016–0007 when contacting the NRC about the availability of information regarding this document. You may obtain publicly-available information related to this document using any of the following methods:
•
•
•
Siva P. Lingam, Office of Nuclear Reactor Regulation, U.S. Nuclear Regulatory Commission, Washington, DC 20555–0001; telephone: 301–415–1564, email:
The text of each Order is attached.
For the Nuclear Regulatory Commission.
Entergy Nuclear Indian Point 2, LLC, is the owner of Indian Point Nuclear Generating Unit Nos. 1 and 2; Entergy Nuclear Indian Point 3, LLC, is the owner of Indian Point Nuclear Generating Unit No. 3, and Entergy Nuclear Operations, Inc. (“Entergy” or “the licensee”) is the operator of Indian Point Nuclear Generating Unit Nos. 1, 2, and 3, including the general-licensed Independent Spent Fuel Storage Installation (hereinafter “Indian Point” or “the facility”), and holder of Provisional Operating License No. DPR–5, Facility Operating License Nos. DPR–26 and DPR–64, and Docket No. 72–51 issued by the U.S. Nuclear Regulatory Commission (“NRC” or “Commission”) under Title 10, “Energy,” of the
By application dated August 20, 2013 as supplemented by letters dated November 21, 2013, and May 13 and July 24, 2014, and citing letters dated April 27 and October 27, 2011, and January 4, 2012, Entergy requested, under Commission Order EA–13–092, that under the provisions of Section 161A of the Atomic Energy Act of 1954, as amended, the Commission permit the transfer, receipt, possession, transport, import, and use of certain firearms and large-capacity ammunition-feeding devices by security personnel who protect a facility owned or operated by a licensee or certificate holder of the Commission that is designated by the Commission. Section 161A confers on the Commission the authority to permit a licensee's security personnel to possess and use firearms, ammunition or devices, notwithstanding local, State, and certain Federal firearms laws (including regulations) that may prohibit such possession and use.
On review of the Entergy application for Commission authorization to use Section 161A preemption authority at Indian Point, the NRC staff has found the following:
(1) Entergy's application complies with the standards and requirements of Section 161A and the Commission's rules and regulations set forth in 10 CFR part 73, “Physical Protection of Plants and Materials”;
(2) There is reasonable assurance that the facilities will operate in conformance to the application; the provisions of the Atomic Energy Act of 1954, as amended; and the rules and regulations of the Commission;
(3) There is reasonable assurance that the activities permitted by the proposed Commission authorization to use Section161A preemption authority are consistent with the protection of public health and safety, and that such activities will be conducted in compliance with the Commission's regulations and the requirements of this confirmatory order;
(4) The issuance of Commission authorization to use Section 161A preemption authority will not be inimical to the common defense and security or to the health and safety of the public; and
(5) The issuance of this Commission authorization to use Section 161A preemption authority will be in accordance with the Commission's regulations in 10 CFR part 51, “Environmental Protection Regulations for Domestic Licensing and Related Regulatory Functions.”
The findings, set forth above, are supported by an NRC staff safety evaluation under Agencywide Documents Access and Management System (ADAMS) Accession No. ML14259A209.
To carry out the statutory authority discussed above, the Commission has determined that the licenses for Indian Point must be modified to include provisions with respect to the Commission authorization to use Section 161A preemption authority as identified in Section II of this confirmatory order. The requirements needed to exercise the foregoing are set forth in Section IV below.
The NRC staff has found that the license modifications set forth in Section IV are acceptable and necessary. It further concluded that, with the effective implementation of these provisions, the licensee's physical protection program will meet the specific physical protection program requirements set forth in 10 CFR 73.55, “Requirements for Physical Protection of Licensed Activities in Nuclear Power Reactors against Radiological Sabotage” (for nuclear power reactors); and in 10 CFR 72.212(b)(9), “Conditions of the General License Issued Under § 72.210,” and portions of 10 CFR 73.55, “Requirements for Physical Protection of Licensed Activities in Nuclear Power Reactors against Radiological Sabotage” (for general-license independent spent fuel storage installations co-located with a reactor at the reactor site).
On January 16, 2015, Entergy consented to the issuance of this order. The licensee further agreed that this order will be effective 20 days after the date of issuance and that it has waived its right to a hearing on this order.
Accordingly, under Sections 53, 103 and/or 104b, 161b, 161i, 161o, 161A, 182, and 186 of the Atomic Energy Act of 1954, as amended, and the Commission's regulations in 10 CFR 2.202, “Orders”; 10 CFR part 50; 10 CFR part 70; and 10 CFR part 72, IT IS HEREBY ORDERED that:
1. The Entergy application for Commission authorization to use Section 161A preemption authority at Indian Point is approved and permission for security personnel to possess and use weapons, devices, ammunition, or other firearms, notwithstanding local, State, and certain Federal firearms laws (including regulations) that may prohibit such possession and use, is granted.
2. The licensee shall review and revise its NRC-approved security plans, as necessary, to describe how the requirements of this confirmatory order and other applicable requirements of 10 CFR part 73, “Physical Protection of Plants and Materials,” to include those of the appendices to 10 CFR part 73, will be met.
3. The licensee shall establish and maintain a program consistent with Commission Order EA–13–092 such that all security personnel who require access to firearms in the discharge of their official duties are subject to a firearms background check.
The Commission is engaged in an ongoing rulemaking to implement the Commission's authority under Section 161A. Subsequent to the effective date of that final rulemaking, the Director, Office of Nuclear Reactor Regulation (NRR), and the Director, Office of Nuclear Material Safety and Safeguards (NMSS) may take action to relax or rescind any or all of the requirements set forth in this confirmatory order.
The Director, NRR, and the Director, NMSS, may, in writing, relax or rescind this confirmatory order on demonstration by the licensee of good cause.
This confirmatory order is effective 20 days after the date of its issuance.
For further details with respect to this confirmatory order, see the staff's safety evaluation contained in a letter dated January 5, 2016 (ADAMS Accession No. ML14259A209), which is available for public inspection at the Commission's Public Document Room (PDR) located at One White Flint North, Public File Area 01 F21, 11555 Rockville Pike (first floor), Rockville, Maryland. Publicly available documents created or received at the NRC are accessible electronically through ADAMS in the NRC Library at
In accordance with 10 CFR 2.202, any other person adversely affected by this order may submit an answer to this order within 20 days of its publication in the
If a hearing is requested by a person whose interest is adversely affected, the Commission will issue an order designating the time and place of any hearings. If a hearing is held, the issue to be considered at such hearing shall be whether this order should be sustained.
All documents filed in NRC adjudicatory proceedings (including a request for hearing, a petition for leave to intervene, any motion or other document filed in the proceeding before the submission of a request for hearing or petition to intervene, and documents filed by interested governmental entities participating under 10 CFR 2.315(c)) must be filed in accordance with the NRC E-Filing rule (published at 72 FR 49139 on August 28, 2007). The E-Filing process requires participants to submit and serve all adjudicatory documents over the internet or (in some cases) to mail copies on electronic storage media. Participants may not submit paper copies of their filings unless they seek an exemption in accordance with the procedures described below.
To comply with the procedural requirements of E-Filing, the participant should contact the Office of the Secretary (at least 10 days before the
Information about applying for a digital ID certificate is available on NRC's public Web site at
If a participant is electronically submitting a document to the NRC in accordance with the E-Filing rule, the participant must file the document using the NRC's Web-based online submission form. In order to serve documents through the Electronic Information Exchange, users will be required to install a web browser plug-in from the NRC Web site. Further information on the Web-based submission form, including the installation of the Web browser plug-in, is available on the NRC's public Web site at
Once a participant has obtained a digital ID certificate and a docket has been created, the participant can then submit a request for hearing or petition for leave to intervene. Submissions should be Portable Document Format (PDF) documents in accordance with NRC guidance available on the NRC public Web site at
A person filing electronically using the agency's adjudicatory E-Filing system may seek assistance by contacting the NRC Meta System Help Desk through the “Contact Us” link located on the NRC Web site at
Participants who believe that they have a good cause for not submitting documents electronically must file an exemption request, in accordance with 10 CFR 2.302(g), with their initial paper filing requesting authorization to continue to submit documents in paper format. Such filings must be submitted by: (1) First Class mail addressed to the Office of the Secretary of the Commission, U.S. Nuclear Regulatory Commission, Washington, DC 20555–0001, Attention: Rulemaking and Adjudications Staff; or (2) courier, express mail, or expedited delivery service to the Office of the Secretary, Sixteenth Floor, One White Flint North, 11555 Rockville Pike, Rockville, MD 20852, Attention: Rulemaking and Adjudications Staff. Participants filing a document in this manner are responsible for serving the document on all other participants. Filing is considered complete by First Class mail as of the time of deposit in the mail, or by courier, express mail, or expedited delivery service on depositing the document with the provider of the service. A presiding officer, having granted an exemption request from using E-Filing, may require a participant or party to use E-Filing if the presiding officer subsequently determines that the reason for granting the exemption from use of E-Filing no longer exists.
Documents submitted in adjudicatory proceedings will appear in the NRC's electronic hearing docket, available to the public at
If a person other than the licensee requests a hearing, that person shall set forth with particularity the manner in which his or her interest is adversely affected by this order and shall address the criteria set forth in 10 CFR 2.309(d) and (f).
In the absence of any request for hearing or of written approval of an extension of time in which to request a hearing, the provisions specified in Section IV above shall be final 20 days from the date of this order without further order or proceedings. If an extension of time for requesting a hearing has been approved, the provisions specified in Section IV shall be final when the extension expires if a hearing request has not been received.
Dated at Rockville, Maryland, this 5th day of January 2016.
FOR THE NUCLEAR REGULATORY COMMISSION.
Entergy Nuclear FitzPatrick, LLC, is the owner and Entergy Nuclear Operations, Inc. (“Entergy” or “the licensee”) is the operator of the James A. Fitzpatrick Nuclear Power Plant, including the general-licensed Independent Spent Fuel Storage Installation (hereinafter “JAFNPP” or “the facility”), and holder of Provisional Renewed Facility Operating License No. DPR–59 and Docket No. 72–12 issued by the U.S. Nuclear Regulatory Commission (“NRC” or “Commission”) under Title 10, “Energy,” of the
By application dated August 30, 2013, as supplemented by letters dated November 12, 2013, and May 14 and July 11, 2014, Entergy requested, under Commission Order EA–13–092, that under the provisions of Section 161A of the Atomic Energy Act of 1954, as amended, the Commission permit the transfer, receipt, possession, transport, import, and use of certain firearms and large-capacity ammunition-feeding devices by security personnel who protect a facility owned or operated by a licensee or certificate holder of the Commission that is designated by the Commission. Section 161A confers on the Commission the authority to permit a licensee's security personnel to possess and use firearms, ammunition or devices, notwithstanding local, State, and certain Federal firearms laws (including regulations) that may prohibit such possession and use.
On review of the Entergy application for Commission authorization to use Section 161A preemption authority at JAFNPP, the NRC staff has found the following:
(1) Entergy's application complies with the standards and requirements of Section 161A and the Commission's rules and regulations set forth in 10 CFR part 73, “Physical Protection of Plants and Materials”;
(2) There is reasonable assurance that the facilities will operate in conformance to the application; the provisions of the Atomic Energy Act of 1954, as amended; and the rules and regulations of the Commission;
(3) There is reasonable assurance that the activities permitted by the proposed Commission authorization to use Section 161A preemption authority are consistent with the protection of public health and safety, and that such activities will be conducted in compliance with the Commission's regulations and the requirements of this confirmatory order;
(4) The issuance of Commission authorization to use Section 161A preemption authority will not be inimical to the common defense and security or to the health and safety of the public; and
(5) The issuance of this Commission authorization to use Section 161A preemption authority will be in accordance with the Commission's regulations in 10 CFR part 51, “Environmental Protection Regulations for Domestic Licensing and Related Regulatory Functions.”
The findings, set forth above, are supported by an NRC staff safety evaluation under Agencywide Documents Access and Management System (ADAMS) Accession No. ML14259A164.
To carry out the statutory authority discussed above, the Commission has determined that the license for JAFNPP must be modified to include provisions with respect to the Commission authorization to use Section 161A preemption authority as identified in Section II of this confirmatory order. The requirements needed to exercise the foregoing are set forth in Section IV below.
The NRC staff has found that the license modifications set forth in Section IV are acceptable and necessary. It further concluded that, with the effective implementation of these provisions, the licensee's physical protection program will meet the specific physical protection program requirements set forth in 10 CFR 73.55, “Requirements for Physical Protection of Licensed Activities in Nuclear Power Reactors against Radiological Sabotage” (for nuclear power reactors); and in 10 CFR 72.212(b)(9), “Conditions of the General License Issued Under § 72.210,” and portions of 10 CFR 73.55, “Requirements for Physical Protection of Licensed Activities in Nuclear Power Reactors against Radiological Sabotage” (for general-license independent spent fuel storage installations co-located with a reactor at the reactor site).
On January 15, 2015, Entergy consented to the issuance of this order. The licensee further agreed that this order will be effective 20 days after the date of issuance and that it has waived its right to a hearing on this order.
Accordingly, under Sections 53, 103 and/or 104b, 161b, 161i, 161o, 161A, 182, and 186 of the Atomic Energy Act of 1954, as amended, and the Commission's regulations in 10 CFR 2.202, “Orders”; 10 CFR part 50; 10 CFR part 70; and 10 CFR part 72, IT IS HEREBY ORDERED that:
1. The Entergy application for Commission authorization to use Section 161A preemption authority at JAFNPP is approved and permission for security personnel to possess and use weapons, devices, ammunition, or other firearms, notwithstanding local, State, and certain Federal firearms laws (including regulations) that may prohibit such possession and use, is granted.
2. The licensee shall review and revise its NRC-approved security plans, as necessary, to describe how the requirements of this confirmatory order and other applicable requirements of 10 CFR part 73, “Physical Protection of Plants and Materials,” to include those of the appendices to 10 CFR part 73, will be met.
3. The licensee shall establish and maintain a program consistent with Commission Order EA–13–092 such that all security personnel who require access to firearms in the discharge of their official duties are subject to a firearms background check.
The Commission is engaged in an ongoing rulemaking to implement the Commission's authority under Section161A. Subsequent to the effective date of that final rulemaking, the Director, Office of Nuclear Reactor Regulation (NRR) may take action to relax or rescind any or all of the requirements set forth in this confirmatory order.
The Director, NRR, may, in writing, relax or rescind this confirmatory order on demonstration by the licensee of good cause.
This confirmatory order is effective 20 days after the date of its issuance.
For further details with respect to this confirmatory order, see the staff's safety evaluation contained in a letter dated January 5, 2016 (ADAMS Accession No. ML14259A164), which is available for public inspection at the Commission's Public Document Room (PDR), located at One White Flint North, Public File
In accordance with 10 CFR 2.202, any other person adversely affected by this order may submit an answer to this order within 20 days of its publication in the
If a hearing is requested by a person whose interest is adversely affected, the Commission will issue an order designating the time and place of any hearings. If a hearing is held, the issue to be considered at such hearing shall be whether this order should be sustained.
All documents filed in NRC adjudicatory proceedings, including a request for hearing, a petition for leave to intervene, any motion or other document filed in the proceeding before the submission of a request for hearing or petition to intervene, and documents filed by interested governmental entities participating under 10 CFR 2.315(c), must be filed in accordance with the NRC E-Filing rule (published at 72 FR 49139, on August 28, 2007). The E-Filing process requires participants to submit and serve all adjudicatory documents over the internet, or in some cases to mail copies on electronic storage media. Participants may not submit paper copies of their filings unless they seek an exemption in accordance with the procedures described below.
To comply with the procedural requirements of E-Filing, the participant should contact the Office of the Secretary (at least 10 days before the filing deadline) by email to
Information about applying for a digital ID certificate is available on NRC's public Web site at
If a participant is electronically submitting a document to the NRC in accordance with the E-Filing rule, the participant must file the document using the NRC's Web-based online submission form. In order to serve documents through the Electronic Information Exchange, users will be required to install a web browser plug-in from the NRC Web site. Further information on the Web-based submission form, including the installation of the Web browser plug-in, is available on the NRC's public Web site at
Once a participant has obtained a digital ID certificate and a docket has been created, the participant can then submit a request for hearing or petition for leave to intervene. Submissions should be Portable Document Format (PDF) documents in accordance with NRC guidance available on the NRC public Web site at
A person filing electronically using the agency's adjudicatory E-Filing system may seek assistance by contacting the NRC Meta System Help Desk through the “Contact Us” link located on the NRC Web site at
Participants who believe that they have a good cause for not submitting documents electronically must file an exemption request, in accordance with 10 CFR 2.302(g), with their initial paper filing requesting authorization to continue to submit documents in paper format. Such filings must be submitted by: (1) First Class mail addressed to the Office of the Secretary of the Commission, U.S. Nuclear Regulatory Commission, Washington, DC 20555–0001, Attention: Rulemaking and Adjudications Staff; or (2) courier, express mail, or expedited delivery service to the Office of the Secretary, Sixteenth Floor, One White Flint North, 11555 Rockville Pike, Rockville, MD 20852, Attention: Rulemaking and Adjudications Staff. Participants filing a document in this manner are responsible for serving the document on all other participants. Filing is considered complete by First Class mail as of the time of deposit in the mail, or by courier, express mail, or expedited delivery service on depositing the document with the provider of the service. A presiding officer, having granted an exemption request from using E-Filing, may require a participant or party to use E-Filing if the presiding officer subsequently determines that the reason for granting the exemption from use of E-Filing no longer exists.
Documents submitted in adjudicatory proceedings will appear in the NRC's electronic hearing docket, available to the public at
If a person other than the licensee requests a hearing, that person shall set forth with particularity the manner in which his or her interest is adversely affected by this order and shall address the criteria set forth in 10 CFR 2.309(d) and (f).
In the absence of any request for hearing or of written approval of an extension of time in which to request a hearing, the provisions specified in Section IV above shall be final 20 days from the date of this order without further order or proceedings. If an extension of time for requesting a hearing has been approved, the provisions specified in Section IV shall be final when the extension expires if a hearing request has not been received.
Dated at Rockville, Maryland, this 5th day of January 2016.
FOR THE NUCLEAR REGULATORY COMMISSION.
Exelon Generation Company, LLC (Exelon, or the licensee) is the owner and operator of Nine Mile Point Nuclear Station, Units 1 and 2, including the general-licensed Independent Spent Fuel Storage Installation (hereinafter NMPNS or the facility), and holder of Provisional Facility Operating Licenses Nos. DPR–63, NPR–69, and Docket No. 72–1036 issued by the U.S. Nuclear Regulatory Commission (NRC or Commission) under Title 10 “Energy,” of the
By application dated August 14, 2013, as supplemented by letters dated September 10, 2013, and May 14, 2014, Exelon requested, under Commission Order EA–13–092, that under the provisions of Section 161A of the Atomic Energy Act of 1954, as amended, the Commission permit the transfer, receipt, possession, transport, import, and use of certain firearms and large-capacity ammunition-feeding devices by security personnel who protect a facility owned or operated by a licensee or certificate holder of the Commission that is designated by the Commission. Section 161A confers on the Commission the authority to permit a licensee's security personnel to possess and use firearms, ammunition or devices, notwithstanding local, State, and certain Federal firearms laws (including regulations) that may prohibit such possession and use.
On review of the Exelon application for Commission authorization to use Section 161A preemption authority at NMPNS, the NRC staff has found the following:
(1) The Exelon application complies with the standards and requirements of Section 161A and the Commission's rules and regulations set forth in 10 CFR part 73, “Physical Protection of Plants and Materials”;
(2) There is reasonable assurance that the facilities will operate in conformance to the application; the provisions of the Atomic Energy Act of 1954, as amended; and the rules and regulations of the Commission;
(3) There is reasonable assurance that the activities permitted by the proposed Commission authorization to use Section 161A preemption authority are consistent with the protection of public health and safety, and that such activities will be conducted in compliance with the Commission's regulations and the requirements of this confirmatory order;
(4) The issuance of Commission authorization to use Section 161A preemption authority will not be inimical to the common defense and security or to the health and safety of the public; and
(5) The issuance of this Commission authorization to use Section 161A preemption authority will be in accordance with the Commission's regulations in 10 CFR part 51, “Environmental Protection Regulations for Domestic Licensing and Related Regulatory Functions.”
The findings set forth above are supported by an NRC staff safety evaluation under Agencywide Documents Access and Management System (ADAMS) Accession No. ML14254A450.
To carry out the statutory authority discussed above, the Commission has determined that the license for NMPNS must be modified to include provisions with respect to the Commission authorization to use Section 161A preemption authority as identified in Section II of this confirmatory order. The requirements needed to exercise the foregoing are set forth in Section IV below.
The NRC staff has found that the license modifications set forth in Section IV are acceptable and necessary. It further concluded that, with the effective implementation of these provisions, the licensee's physical protection program will meet the specific physical protection program requirements set forth in 10 CFR 73.55, “Requirements for Physical Protection of Licensed Activities in Nuclear Power Reactors against Radiological Sabotage” (for nuclear power reactors); and in 10 CFR 72.212(b)(9), “Conditions of the General License Issued Under § 72.210,” and portions of 10 CFR 73.55, “Requirements for Physical Protection of Licensed Activities in Nuclear Power Reactors against Radiological Sabotage” (for general-license independent spent fuel storage installations co-located with a reactor at the reactor site).
On January 16, 2015, Exelon consented to the issuance of this order. The licensee further agreed that this order will be effective 20 days after the date of issuance and that it has waived its right to a hearing on this order.
Accordingly, under Sections 53, 103 and/or 104b, 161b, 161i, 161o, 161A, 182, and 186 of the Atomic Energy Act of 1954, as amended, and the Commission's regulations in 10 CFR 2.202, “Orders”; 10 CFR part 50; 10 CFR
1. The Exelon application for Commission authorization to use Section 161A preemption authority at NMPNS is approved and permission for security personnel to possess and use weapons, devices, ammunition, or other firearms, notwithstanding local, State, and certain Federal firearms laws (including regulations) that may prohibit such possession and use, is granted.
2. The licensee shall review and revise its NRC-approved security plans, as necessary, to describe how the requirements of this confirmatory order and other applicable requirements of 10 CFR part 73, “Physical Protection of Plants and Materials,” to include those of the appendices to 10 CFR part 73, will be met.
3. The licensee shall establish and maintain a program consistent with Commission Order EA–13–092 such that all security personnel who require access to firearms in the discharge of their official duties are subject to a firearms background check.
The Commission is engaged in an ongoing rulemaking to implement the Commission's authority under Section 161A. Subsequent to the effective date of that final rulemaking, the Director, Office of Nuclear Reactor Regulation (NRR), may take action to relax or rescind any or all of the requirements set forth in this confirmatory order.
The Director, NRR, may, in writing, relax or rescind this confirmatory order on demonstration by the licensee of good cause.
This confirmatory order is effective 20 days after the date of its issuance.
For further details with respect to this confirmatory order, see the staff's safety evaluation contained in a letter dated January 5, 2016 (ADAMS Accession No. ML14254A450), which is available for public inspection at the Commission's Public Document Room (PDR), located at One White Flint North, Public File Area 01 F21, 11555 Rockville Pike (first floor), Rockville, Maryland. Publicly available documents created or received at the NRC are accessible electronically through ADAMS in the NRC Library at
In accordance with 10 CFR 2.202, any other person adversely affected by this order may submit an answer to this order within 20 days of its publication in the
If a hearing is requested by a person whose interest is adversely affected, the Commission will issue an order designating the time and place of any hearings. If a hearing is held, the issue to be considered at such hearing shall be whether this order should be sustained.
All documents filed in NRC adjudicatory proceedings, including a request for hearing, a petition for leave to intervene, any motion or other document filed in the proceeding before the submission of a request for hearing or petition to intervene, and documents filed by interested governmental entities participating under 10 CFR 2.315(c), must be filed in accordance with the NRC E-Filing rule (published at 72 FR 49139, on August 28, 2007). The E-Filing process requires participants to submit and serve all adjudicatory documents over the internet, or in some cases to mail copies on electronic storage media. Participants may not submit paper copies of their filings unless they seek an exemption in accordance with the procedures described below.
To comply with the procedural requirements of E-Filing, the participant should contact the Office of the Secretary (at least 10 days before the filing deadline) by email to
Information about applying for a digital ID certificate is available on NRC's public Web site at
If a participant is electronically submitting a document to the NRC in accordance with the E-Filing rule, the participant must file the document using the NRC's Web-based online submission form. In order to serve documents through the Electronic Information Exchange, users will be required to install a web browser plug-in from the NRC Web site. Further information on the Web-based submission form, including the installation of the Web browser plug-in, is available on the NRC's public Web site at
Once a participant has obtained a digital ID certificate and a docket has been created, the participant can then submit a request for hearing or petition for leave to intervene. Submissions should be Portable Document Format (PDF) documents in accordance with NRC guidance available on the NRC public Web site at
A person filing electronically using the agency's adjudicatory E-Filing system may seek assistance by
Participants who believe that they have a good cause for not submitting documents electronically must file an exemption request, in accordance with 10 CFR 2.302(g), with their initial paper filing requesting authorization to continue to submit documents in paper format. Such filings must be submitted by: (1) First Class mail addressed to the Office of the Secretary of the Commission, U.S. Nuclear Regulatory Commission, Washington, DC 20555–0001, Attention: Rulemaking and Adjudications Staff; or (2) courier, express mail, or expedited delivery service to the Office of the Secretary, Sixteenth Floor, One White Flint North, 11555 Rockville Pike, Rockville, MD 20852, Attention: Rulemaking and Adjudications Staff. Participants filing a document in this manner are responsible for serving the document on all other participants. Filing is considered complete by First Class mail as of the time of deposit in the mail, or by courier, express mail, or expedited delivery service on depositing the document with the provider of the service. A presiding officer, having granted an exemption request from using E-Filing, may require a participant or party to use E-Filing if the presiding officer subsequently determines that the reason for granting the exemption from use of E-Filing no longer exists.
Documents submitted in adjudicatory proceedings will appear in the NRC's electronic hearing docket, available to the public at
If a person other than the licensee requests a hearing, that person shall set forth with particularity the manner in which his or her interest is adversely affected by this order and shall address the criteria set forth in 10 CFR 2.309(d) and (f).
In the absence of any request for hearing or of written approval of an extension of time in which to request a hearing, the provisions specified in Section IV above shall be final 20 days from the date of this order without further order or proceedings. If an extension of time for requesting a hearing has been approved, the provisions specified in Section IV shall be final when the extension expires if a hearing request has not been received.
Dated at Rockville, Maryland, this 5th day of January 2016.
FOR THE NUCLEAR REGULATORY COMMISSION.
Exelon Generation Company, LLC (Exelon, or the licensee) is the owner and operator of R.E. Ginna Nuclear Power Plant (Ginna), including the general-licensed Independent Spent Fuel Storage Installation (hereinafter Ginna or the facility), and holder of Provisional Renewed Facility Operating Licenses No. DPR–18 and Docket No. 72–67 issued by the U.S. Nuclear Regulatory Commission (NRC or Commission) under Title 10, “Energy,” of the
By application dated August 14, 2013, as supplemented by letters dated November 4, 2013, and May 14, 2014, Exelon requested, under Commission Order (EA–13–092), that under the provisions of Section 161A of the Atomic Energy Act of 1954, as amended, the Commission permit the transfer, receipt, possession, transport, import, and use of certain firearms and large capacity ammunition feeding devices, by security personnel who protect a facility owned or operated by a licensee or certificate holder of the Commission that is designated by the Commission. Section 161A confers on the Commission the authority to permit a licensee's security personnel to possess and use firearms, ammunition or devices, notwithstanding local, State, and certain Federal firearms laws (including regulations) that may prohibit such possession and use.
On review of the Exelon application for Commission authorization to use Section 161A preemption authority at Ginna, the NRC staff has found the following:
(1) The Exelon application complies with the standards and requirements of Section 161A and the Commission's rules and regulations set forth in 10 CFR part 73, “Physical Protection of Plants and Materials;”
(2) There is reasonable assurance that the facilities will operate in conformance to the application; the provisions of the Atomic Energy Act of 1954, as amended; and the rules and regulations of the Commission;
(3) There is reasonable assurance that the activities permitted by the proposed Commission authorization to use Section 161A preemption authority are consistent with the protection of public health and safety, and that such activities will be conducted in compliance with the Commission's regulations and the requirements of this confirmatory order;
(4) The issuance of Commission authorization to use Section 161A preemption authority will not be inimical to the common defense and security or to the health and safety of the public; and
(5) The issuance of this Commission authorization to use Section 161A preemption authority will be in accordance with the Commission's regulations in 10 CFR part 51, “Environmental Protection Regulations for Domestic Licensing and Related Regulatory Functions.”
The findings, set forth above, are supported by an NRC staff safety evaluation under Agencywide
To carry out the statutory authority discussed above, the Commission has determined that the license for Ginna, must be modified to include provisions with respect to the Commission authorization to use Section 161A preemption authority as identified in Section II of this confirmatory order. The requirements needed to exercise the foregoing are set forth in Section IV below.
The NRC staff has found that the license modifications set forth in Section IV are acceptable and necessary. It further concluded that, with the effective implementation of these provisions, the licensee's physical protection program will meet the specific physical protection program requirements set forth in 10 CFR 73.55, “Requirements for Physical Protection of Licensed Activities in Nuclear Power Reactors against Radiological Sabotage” (for nuclear power reactors); and in 10 CFR 72.212(b)(9), “Conditions of the General License Issued Under § 72.210,” and portions of 10 CFR 73.55, “Requirements for Physical Protection of Licensed Activities in Nuclear Power Reactors against Radiological Sabotage” (for general-license independent spent fuel storage installations co-located with a reactor at the reactor site).
On January 16, 2015, Exelon consented to the issuance of this order. The licensee further agreed that this order will be effective 20 days after the date of issuance and that it has waived its right to a hearing on this order.
Accordingly, under Sections 53, 103 and/or 104b, 161b, 161i, 161o, 161A, 182, and 186 of the Atomic Energy Act of 1954, as amended, and the Commission's regulations in 10 CFR 2.202, “Orders”; 10 CFR part 50; 10 CFR part 70; and 10 CFR part 72, IT IS HEREBY ORDERED that:
1. The Exelon application for Commission authorization to use Section 161A preemption authority at Ginna is approved and permission for security personnel to possess and use weapons, devices, ammunition, or other firearms, notwithstanding local, State, and certain Federal firearms laws (including regulations) that may prohibit such possession and use, is granted.
2. The licensee shall review and revise its NRC-approved security plans, as necessary, to describe how the requirements of this confirmatory order and other applicable requirements of 10 CFR part 73, “Physical Protection of Plants and Materials,” to include those of the appendices to 10 CFR part 73, will be met.
3. The licensee shall establish and maintain a program consistent with Commission Order EA–13–092 such that all security personnel who require access to firearms in the discharge of their official duties are subject to a firearms background check.
The Commission is engaged in an ongoing rulemaking to implement the Commission's authority under Section 161A. Subsequent to the effective date of that final rulemaking, the Director, Office of Nuclear Reactor Regulation (NRR) may take action to relax or rescind any or all of the requirements set forth in this confirmatory order.
The Director, NRR, may, in writing, relax or rescind this confirmatory order on demonstration by the licensee of good cause.
This confirmatory order is effective 20 days after the date of its issuance.
For further details with respect to this confirmatory order, see the staff's safety evaluation contained in a letter dated January 5, 2016 (ADAMS Accession Nos. ML14260A166 and ML14260A151), which is available for public inspection at the Commission's Public Document Room (PDR), located at One White Flint North, Public File Area 01 F21, 11555 Rockville Pike (first floor), Rockville, Maryland. Publicly available documents created or received at the NRC are accessible electronically through ADAMS in the NRC Library at
In accordance with 10 CFR 2.202, any other person adversely affected by this order may submit an answer to this order within 20 days of its publication in the
If a hearing is requested by a person whose interest is adversely affected, the Commission will issue an order designating the time and place of any hearings. If a hearing is held, the issue to be considered at such hearing shall be whether this order should be sustained.
All documents filed in NRC adjudicatory proceedings, including a request for hearing, a petition for leave to intervene, any motion or other document filed in the proceeding before the submission of a request for hearing or petition to intervene, and documents filed by interested governmental entities participating under 10 CFR 2.315(c), must be filed in accordance with the NRC E-Filing rule (published at 72 FR 49139, on August 28, 2007). The E-Filing process requires participants to submit and serve all adjudicatory documents over the internet, or in some cases to mail copies on electronic storage media. Participants may not submit paper copies of their filings unless they seek an exemption in accordance with the procedures described below.
To comply with the procedural requirements of E-Filing, the participant should contact the Office of the Secretary (at least 10 days before the filing deadline) by email to
Information about applying for a digital ID certificate is available on NRC's public Web site at
If a participant is electronically submitting a document to the NRC in
Once a participant has obtained a digital ID certificate and a docket has been created, the participant can then submit a request for hearing or petition for leave to intervene. Submissions should be Portable Document Format (PDF) documents in accordance with NRC guidance available on the NRC public Web site at
A person filing electronically using the agency's adjudicatory E-Filing system may seek assistance by contacting the NRC Meta System Help Desk through the “Contact Us” link located on the NRC Web site at
Participants who believe that they have a good cause for not submitting documents electronically must file an exemption request, in accordance with 10 CFR 2.302(g), with their initial paper filing requesting authorization to continue to submit documents in paper format. Such filings must be submitted by: (1) First Class mail addressed to the Office of the Secretary of the Commission, U.S. Nuclear Regulatory Commission, Washington, DC 20555–0001, Attention: Rulemaking and Adjudications Staff; or (2) courier, express mail, or expedited delivery service to the Office of the Secretary, Sixteenth Floor, One White Flint North, 11555 Rockville Pike, Rockville, MD 20852, Attention: Rulemaking and Adjudications Staff. Participants filing a document in this manner are responsible for serving the document on all other participants. Filing is considered complete by First Class mail as of the time of deposit in the mail, or by courier, express mail, or expedited delivery service on depositing the document with the provider of the service. A presiding officer, having granted an exemption request from using E-Filing, may require a participant or party to use E-Filing if the presiding officer subsequently determines that the reason for granting the exemption from use of E-Filing no longer exists.
Documents submitted in adjudicatory proceedings will appear in the NRC's electronic hearing docket, available to the public at
If a person other than the licensee requests a hearing, that person shall set forth with particularity the manner in which his or her interest is adversely affected by this order and shall address the criteria set forth in 10 CFR 2.309(d) and (f).
In the absence of any request for hearing or of written approval of an extension of time in which to request a hearing, the provisions specified in Section IV above shall be final 20 days from the date of this order without further order or proceedings. If an extension of time for requesting a hearing has been approved, the provisions specified in Section IV shall be final when the extension expires if a hearing request has not been received.
Dated at Rockville, Maryland, this 5th day of January 2016.
FOR THE NUCLEAR REGULATORY COMMISSION.
Pacific Gas and Electric Company (PG&E), is the owner and operator of Diablo Canyon Nuclear Power Plant Units 1 and 2, including the specific-license Independent Spent Fuel Storage Installation (hereinafter “DCNPP” or “the facility”), and holder of Facility Operating License Nos. DPR–80, DPR–82, and SNM–2511 issued by the U.S. Nuclear Regulatory Commission (“NRC” or “Commission”) under Title 10, “Energy,” of the
By application dated September 24, 2013 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML13268A398), as supplemented by letters dated December 18, 2013 (security-related), May 15, 2014 (ADAMS Accession No. ML14135A379), and March 26, 2015 (ADAMS Accession No. ML15090A278), PG&E requested, under Commission Order EA–13–092, that under the provisions of Section 161A of the Atomic Energy Act of 1954, as amended, the Commission permit the transfer,
On review of the PG&E application for Commission authorization to use Section 161A Preemption authority at DCNPP, the NRC staff has found the following:
(1) PG&E's application complies with the standards and requirements of Section 161A and the Commission's rules and regulations set forth in 10 CFR part 73, “Physical Protection of Plants and Materials,”
(2) There is reasonable assurance that the facilities will operate in conformance to the application; the provisions of the Atomic Energy Act of 1954, as amended; and the rules and regulations of the Commission,
(3) There is reasonable assurance that the activities permitted by the proposed Commission authorization to use Section 161A preemption authority is consistent with the protection of public health and safety, and that such activities will be conducted in compliance with the Commission's regulations and the requirements of this confirmatory order,
(4) The issuance of Commission authorization to use Section 161A preemption authority will not be inimical to the common defense and security or to the health and safety of the public, and
(5) The issuance of this Commission authorization to use Section 161A preemption authority will be in accordance with the Commission's regulations in 10 CFR part 51, “Environmental Protection Regulations for Domestic Licensing and Related Regulatory Functions.”
The findings set forth above are supported by an NRC staff safety evaluation under Accession Number ML15029A249.
To carry out the statutory authority discussed above, the Commission has determined that the licenses for DCNPP must be modified to include provisions with respect to the Commission authorization to use Section 161A preemption authority as identified in Section II of this confirmatory order. The requirements needed to exercise the foregoing are set forth in Section IV below.
The NRC staff has found that the license modifications set forth in Section IV are acceptable and necessary. It further concluded that, with the effective implementation of these provisions, the licensee's physical protection program will meet the specific physical protection program requirements set forth in 10 CFR 73.55, “Requirements for Physical Protection of Licensed Activities in Nuclear Power Reactors against Radiological Sabotage” (for nuclear power reactors) and 10 CFR 73.55, “Requirements for Physical Protection of Licensed Activities in Nuclear Power Reactors against Radiological Sabotage” (for specific-license independent spent fuel storage installations co-located with a reactor at the reactor site).
On March 26, 2015, PG&E consented to the issuance of this order. The licensee further agreed that this order will be effective 20 days after the date of issuance and that it has waived its right to a hearing on this order.
Accordingly, under Sections 53, 103 and/or 104b, 161b, 161i, 161o, 161A, 182, and 186 of the Atomic Energy Act of 1954, as amended, and the Commission's regulations in 10 CFR 2.202, “Orders”; 10 CFR part 50; 10 CFR part 70; and 10 CFR part 72, IT IS HEREBY ORDERED that:
1. The PG&E application for Commission authorization to use Section 161A preemption authority at DCNPP is approved, and permission for security personnel to possess and use weapons, devices, ammunition, or other firearms, notwithstanding local, State, and certain Federal firearms laws (including regulations) that may prohibit such possession and use, is granted.
2. The licensee shall review and revise its NRC-approved security plans, as necessary, to describe how the requirements of this confirmatory order and other applicable requirements of 10 CFR part 73 (including the related appendices) will be met.
3. The licensee shall establish and maintain a program consistent with Commission Order EA–13–092 such that all security personnel who require access to firearms in the discharge of their official duties are subject to a firearms background check.
The Commission is engaged in an ongoing rulemaking to implement the Commission's authority under Section 161A. Subsequent to the effective date of that final rulemaking, the Director, Office of Nuclear Reactor Regulation, and the Director, Office of Nuclear Material Safety and Safeguards may take action to relax or rescind any or all of the requirements set forth in this confirmatory order.
The Directors of the Office of Nuclear Reactor Regulation and the Office of Nuclear Materials Safety and Safeguards may, in writing, relax or rescind this confirmatory order on demonstration by the licensee of good cause.
This confirmatory order is effective 20 days after the date of its issuance.
For further details with respect to this confirmatory order, see the staff's safety evaluation contained in a letter dated January 5, 2016 (ADAMS Accession No. ML15029A249), which is available for public inspection at the Commission's Public Document Room (PDR) located at One White Flint North, Public File Area 01 F21, 11555 Rockville Pike (first floor), Rockville, Maryland. Publicly available documents created or received at the NRC are accessible electronically through ADAMS in the NRC Library at
In accordance with 10 CFR 2.202, any other person adversely affected by this order may submit an answer to this order within 20 days of its publication in the
If a hearing is requested by a person whose interest is adversely affected, the Commission will issue an order designating the time and place of any hearings. If a hearing is held, the issue to be considered at such hearing shall be whether this order should be sustained.
All documents filed in NRC adjudicatory proceedings (including a request for hearing, a petition for leave to intervene, any motion or other document filed in the proceeding before the submission of a request for hearing or petition to intervene, and documents filed by interested governmental entities participating under 10 CFR 2.315(c)) must be filed in accordance with the
To comply with the procedural requirements of E-Filing, the participant should contact the Office of the Secretary (at least 10 days before the filing deadline) by email to
Information about applying for a digital ID certificate is available on the NRC's public Web site at
If a participant is electronically submitting a document to the NRC in accordance with the E-Filing rule, the participant must file the document using the NRC's Web-based online submission form. To serve documents through the Electronic Information Exchange, users will be required to install a Web browser plug-in from the NRC Web site. Further information on the Web-based submission form, including the installation of the Web browser plug-in, is available on the NRC's public Web site at
Once a participant has obtained a digital ID certificate and a docket has been created, the participant can then submit a request for hearing or petition for leave to intervene. Submissions should be Portable Document Format (PDF) documents in accordance with NRC guidance available on the NRC public Web site at
A person filing electronically using the agency's adjudicatory E-Filing system may seek assistance by contacting the NRC Meta System Help Desk through the “Contact Us” link located on the NRC Web site at
Participants who believe that they have a good cause for not submitting documents electronically must file an exemption request, in accordance with 10 CFR 2.302(g), with their initial paper filing requesting authorization to continue to submit documents in paper format. Such filings must be submitted by: (1) First Class mail addressed to the Office of the Secretary of the Commission, U.S. Nuclear Regulatory Commission, Washington, DC 20555–0001, Attention: Rulemaking and Adjudications Staff; or (2) courier, express mail, or expedited delivery service to the Office of the Secretary, 16th Floor, One White Flint North, 11555 Rockville Pike, Rockville, MD 20852, Attention: Rulemaking and Adjudications Staff. Participants filing a document in this manner are responsible for serving the document on all other participants. Filing is considered complete by First Class mail as of the time of deposit in the mail, or by courier, express mail, or expedited delivery service on depositing the document with the provider of the service. A presiding officer, having granted an exemption request from using E-Filing, may require a participant or party to use E-Filing if the presiding officer subsequently determines that the reason for granting the exemption from use of E-Filing no longer exists.
Documents submitted in adjudicatory proceedings will appear in the NRC's electronic hearing docket, available to the public at
If a person other than the licensee requests a hearing, that person shall set forth with particularity the manner in which his or her interest is adversely affected by this order and shall address the criteria set forth in 10 CFR 2.309(d) and (f).
In the absence of any request for hearing or of written approval of an extension of time in which to request a hearing, the provisions specified in Section IV above shall be final 20 days from the date of this order without further order or proceedings. If an extension of time for requesting a hearing has been approved, the provisions specified in Section IV shall be final when the extension expires if a hearing request has not been received.
Dated at Rockville, Maryland, this 5th day of January 2016.
FOR THE NUCLEAR REGULATORY COMMISSION.
Southern California Edison Company (SCE), is the owner and operator of the San Onofre Nuclear Generating Station, Units 2 and 3, including the general-license Independent Spent Fuel Storage Installation (hereinafter “SONGS” or “the facility”), and holder of Facility Operating License Nos. NPF–10, NPF–15, and Docket No. 72–41, issued by the U.S. Nuclear Regulatory Commission (“NRC” or “Commission”) under Title 10, “Energy,” of the
By application dated August 28, 2013 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML13242A277), as supplemented by letters dated December 31, 2013 (ADAMS Accession No. ML14007A496), May 15, 2014 (ADAMS Accession No. ML14139A424), and February 10, 2015 (ADAMS Accession No. ML15044A047), SCE requested, under Commission Order EA–13–092, that under the provisions of Section 161A of the Atomic Energy Act of 1954, as amended, the Commission permit the transfer, receipt, possession, transport, import, and use of certain firearms and large-capacity ammunition-feeding devices by security personnel who protect a facility owned or operated by a licensee or certificate holder of the Commission that is designated by the Commission. Section 161A confers on the Commission the authority to permit a licensee's security personnel to possess and use firearms, ammunition, or devices, notwithstanding local, State, and certain Federal firearms laws (including regulations) that may prohibit such possession and use.
On review of the SCE application for Commission authorization to use Section 161A preemption authority at SONGS, the NRC staff has found the following:
(1) SCE's application complies with the standards and requirements of Section 161A and the Commission's rules and regulations set forth in 10 CFR part 73, “Physical Protection of Plants and Materials.”
(2) There is reasonable assurance that the facilities will operate in conformance to the application; the provisions of the Atomic Energy Act of 1954, as amended; and the rules and regulations of the Commission.
(3) There is reasonable assurance that the activities permitted by the proposed Commission authorization to use Section 161A preemption authority is consistent with the protection of public health and safety, and that such activities will be conducted in compliance with the Commission's regulations and the requirements of this confirmatory order.
(4) The issuance of Commission authorization to use Section 161A preemption authority will not be inimical to the common defense and security or to the health and safety of the public.
(5) The issuance of this Commission authorization to use Section 161A preemption authority will be in accordance with the Commission's regulations in 10 CFR part 51, “Environmental Protection Regulations for Domestic Licensing and Related Regulatory Functions.”
The findings set forth above are supported by an NRC staff safety evaluation under ADAMS Accession No. ML15027A221.
To carry out the statutory authority discussed above, the Commission has determined that the licenses for SONGS must be modified to include provisions with respect to the Commission authorization to use Section 161A preemption authority as identified in Section II of this confirmatory order. The requirements needed to exercise the foregoing are set forth in Section IV below.
The NRC staff has found that the license modifications set forth in Section IV are acceptable and necessary. It further concluded that, with the effective implementation of these provisions, the licensee's physical protection program will meet the specific physical protection program requirements set forth in 10 CFR 73.55, “Requirements for Physical Protection of Licensed Activities in Nuclear Power Reactors against Radiological Sabotage” (for nuclear power reactors); in 10 CFR 72.212(b)(9), “Conditions of the General License Issued Under § 72.210,” and portions of 10 CFR 73.55, “Requirements for Physical Protection of Licensed Activities in Nuclear Power Reactors against Radiological Sabotage” (for general-license independent spent fuel storage installations co-located with a reactor at the reactor site).
On March 31, 2015 (ADAMS Accession No. ML15092A132) SCE consented to the issuance of this order. The licensee further agreed that this order will be effective 20 days after the date of issuance and that it has waived its right to a hearing on this order.
Accordingly, under Sections 53, 103 and/or 104b, 161b, 161i, 161o, 161A, 182, and 186 of the Atomic Energy Act of 1954, as amended, and the Commission's regulations in 10 CFR 2.202, “Orders”; 10 CFR part 50; 10 CFR part 52, “Licenses, Certifications, and Approvals for Nuclear Power Plants”; 10 CFR part 70; and 10 CFR part 72, IT IS HEREBY ORDERED that:
1. The SCE application for Commission authorization to use Section 161A preemption authority at SONGS is approved, and permission for security personnel to possess and use weapons, devices, ammunition, or other firearms, notwithstanding local, State, and certain Federal firearms laws (including regulations) that may prohibit such possession and use, is granted.
2. The licensee shall review and revise its NRC-approved security plans, as necessary, to describe how the requirements of this confirmatory order and other applicable requirements of 10 CFR part 73, “Physical Protection of Plants and Materials,” to include those of the appendices of Part 73, will be met.
3. The licensee shall establish and maintain a program consistent with Commission Order EA–13–092 such that all security personnel who require access to firearms in the discharge of their official duties are subject to a firearms background check.
The Commission is engaged in an ongoing rulemaking to implement the Commission's authority under Section 161A. Subsequent to the effective date of that final rulemaking, the Director, Office of Nuclear Material Safety and
The Director, NMSS, may, in writing, relax or rescind this confirmatory order on demonstration by the licensee of good cause.
This confirmatory order is effective 20 days after the date of its issuance.
For further details with respect to this confirmatory order, see the staff's safety evaluation contained in a letter dated January 5, 2016 (ADAMS Accession No. ML15027A221), which is available for public inspection at the Commission's Public Document Room (PDR) located at One White Flint North, Public File Area 01–F21, 11555 Rockville Pike (first floor), Rockville, Maryland. Publicly available documents created or received at the NRC are accessible electronically through ADAMS in the NRC Library at
In accordance with 10 CFR 2.202, any other person adversely affected by this order may submit an answer to this order within 20 days of its publication in the
If a hearing is requested by a person whose interest is adversely affected, the Commission will issue an order designating the time and place of any hearings. If a hearing is held, the issue to be considered at such hearing shall be whether this Order should be sustained.
All documents filed in NRC adjudicatory proceedings, including a request for hearing, a petition for leave to intervene, any motion or other document filed in the proceeding prior to the submission of a request for hearing or petition to intervene, and documents filed by interested governmental entities participating under 10 CFR 2.315(c), must be filed in accordance with the NRC's E-Filing rule (72 FR 49139; August 28, 2007). The E-Filing process requires participants to submit and serve all adjudicatory documents over the internet, or in some cases to mail copies on electronic storage media. Participants may not submit paper copies of their filings unless they seek an exemption in accordance with the procedures described below.
To comply with the procedural requirements of E-Filing, at least 10 days prior to the filing deadline, the participant should contact the Office of the Secretary by email at
Information about applying for a digital ID certificate is available on the NRC's public Web site at
If a participant is electronically submitting a document to the NRC in accordance with the E-Filing rule, the participant must file the document using the NRC's online, Web-based submission form. In order to serve documents through the Electronic Information Exchange System, users will be required to install a Web browser plug-in from the NRC's Web site. Further information on the Web-based submission form, including the installation of the Web browser plug-in, is available on the NRC's public Web site at
Once a participant has obtained a digital ID certificate and a docket has been created, the participant can then submit a request for hearing or petition for leave to intervene. Submissions should be in Portable Document Format (PDF) in accordance with NRC guidance available on the NRC's public Web site at
A person filing electronically using the NRC's adjudicatory E-Filing system may seek assistance by contacting the NRC Meta System Help Desk through the “Contact Us” link located on the NRC's public Web site at
Participants who believe that they have a good cause for not submitting documents electronically must file an exemption request, in accordance with 10 CFR 2.302(g), with their initial paper filing requesting authorization to continue to submit documents in paper format. Such filings must be submitted by: (1) first class mail addressed to the Office of the Secretary of the Commission, U.S. Nuclear Regulatory Commission, Washington, DC 20555–0001, Attention: Rulemaking and Adjudications Staff; or (2) courier, express mail, or expedited delivery service to the Office of the Secretary, Sixteenth Floor, One White Flint North, 11555 Rockville Pike, Rockville, Maryland, 20852, Attention: Rulemaking and Adjudications Staff. Participants filing a document in this manner are responsible for serving the
Documents submitted in adjudicatory proceedings will appear in the NRC's electronic hearing docket which is available to the public at
If a person other than the licensee requests a hearing, that person shall set forth with particularity the manner in which his or her interest is adversely affected by this order and shall address the criteria set forth in 10 CFR 2.309(d) and (f).
In the absence of any request for hearing or of written approval of an extension of time in which to request a hearing, the provisions specified in Section IV above shall be final 20 days from the date of this order without further order or proceedings. If an extension of time for requesting a hearing has been approved, the provisions specified in Section IV shall be final when the extension expires if a hearing request has not been received.
Dated at Rockville, Maryland, this 5th day of January 2016.
FOR THE NUCLEAR REGULATORY COMMISSION.
January 18, 25, February 1, 8, 15, 22, 2016.
Commissioners' Conference Room, 11555 Rockville Pike, Rockville, Maryland.
Public and Closed.
There are no meetings scheduled for the week of January 18, 2016.
There are no meetings scheduled for the week of January 25, 2016.
There are no meetings scheduled for the week of February 1, 2016.
There are no meetings scheduled for the week of February 8, 2016.
There are no meetings scheduled for the week of February 15, 2016.
This meeting will be webcast live at the Web address—
The schedule for Commission meetings is subject to change on short notice. For more information or to verify the status of meetings, contact Denise McGovern at 301–415–0681 or via email at
The NRC Commission Meeting Schedule can be found on the Internet at
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On November 16, 2015, NYSE Arca, Inc. (“Exchange” or “NYSE Arca”) filed with the Securities and Exchange Commission (“Commission”), pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The Exchange proposes to list and trade the Shares under NYSE Arca Equities Rule 8.600, which governs the listing and trading of Managed Fund Shares. The Shares will be offered by Market Vectors ETF Trust (“Trust”), which is registered with the Commission as an investment company.
The Fund's investment objective will be to seek a positive total return and income. Under normal circumstances,
Cash and cash equivalents, in which the Fund may hold, include U.S. Treasury Bills, repurchase agreements, money market instruments, or investment companies and exchange-traded funds (“ETFs”)
After careful review, the Commission finds that the proposed rule change is consistent with the requirements of Section 6 of the Act
The Commission also finds that the proposal to list and trade the Shares on the Exchange is consistent with Section 11A(a)(1)(C)(iii) of the Act,
The Commission further believes that the proposal to list and trade the Shares is reasonably designed to promote fair disclosure of information that may be necessary to price the Shares appropriately and to prevent trading when a reasonable degree of transparency cannot be assured. The Commission notes that the Exchange will obtain a representation from the issuer of the Shares that the NAV per Share will be calculated daily and that the NAV and the Disclosed Portfolio will be made available to all market participants at the same time.
The Exchange deems the Shares to be equity securities, which subjects trading in the Shares to the Exchange's existing rules governing the trading of equity securities.
In support of this proposal, the Exchange has made additional representations, including:
(1) The Shares will conform to the initial and continued listing criteria under NYSE Arca Equities Rule 8.600.
(2) The Exchange has appropriate rules to facilitate transactions in the Shares during all trading sessions.
(3) The Exchange represents that the trading in the Shares will be subject to the existing trading surveillances, administered by the Exchange or FINRA on behalf of the Exchange, which are designed to detect violations of Exchange rules and applicable federal securities laws. The Exchange represents that these procedures are adequate to properly monitor Exchange trading of the Shares in all trading sessions and to deter and detect violations of Exchange rules and federal securities laws applicable to trading on the Exchange.
(4) Prior to the commencement of trading, the Exchange will inform its Equity Trading Permit (“ETP”) Holders in an Information Bulletin of the special characteristics and risks associated with trading the Shares. Specifically, the Bulletin will discuss the following: (a) The procedures for purchases and redemptions of Shares in Creation Unit (and that Shares are not individually redeemable); (b) NYSE Arca Equities Rule 9.2(a), which imposes a duty of due diligence on its ETP Holders to learn the essential facts relating to every customer prior to trading the Shares; (c)
(5) For initial and continued listing, the Fund will be in compliance with Rule 10A–3
(6) A minimum of 100,000 Shares for the Fund will be outstanding at the commencement of trading on the Exchange.
For the foregoing reasons, the Commission finds that the proposed rule change, as modified by Amendment No. 1, is consistent with Section 6(b)(5) of the Act
Interested persons are invited to submit written data, views, and arguments concerning whether Amendment No. 1 is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an Email to
• Send paper comments in triplicate to Brent J. Fields, Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549–1090.
The Commission finds good cause to approve the proposed rule change, as modified by Amendment No. 1, prior to the thirtieth day after the date of publication of notice in the
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”),
The Exchange proposes to adopt a trading license fee for calendar year 2016. The Exchange proposes to make the rule change operative on January 4, 2016. The proposed rule change is available on the Exchange's Web site at
In its filing with the Commission, the self-regulatory organization included statements concerning the purpose of, and basis for, the proposed rule change and discussed any comments it received on the proposed rule change. The text of those statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below,
The Exchange proposes to amend its Price List to adopt a trading license fee for calendar year 2016. The Exchange proposes to make the rule change operative on January 4, 2016.
NYSE Rule 300(b) provides that, in each annual offering, up to 1366 trading licenses for the following calendar year will be sold annually at a price per trading license to be established each year by the Exchange pursuant to a rule filing submitted to the Securities and Exchange Commission (“Commission”) and that the price per trading license will be published each year in the Exchange's price list.
The Exchange proposes to leave the current trading license fees in place for 2016: $50,000 for the first license held by a member organization and $15,000 for each additional license held by a member organization. Such trading license fees have been in place since March 1, 2015.
The proposed changes are not otherwise intended to address any other problem, and the Exchange is not aware of any significant problem that the affected market participants would have in complying with the proposed changes.
The Exchange believes that the proposed rule change is consistent with Section 6(b) of the Act,
The Exchange believes that it is subject to significant competitive forces, as described below in the Exchange's statement regarding the burden on competition.
For the foregoing reasons, the Exchange believes that the proposal is consistent with the Exchange Act.
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. The proposed rule change will keep trading license fees the same as they have been since March 1, 2015. As a result, the Exchange does not believe that the proposed rule change will place an unreasonable burden on current members because their trading license fees will remain the same. In addition, the Exchange does not believe that the proposed rule change will place an unreasonable burden on potential members because a potential member's fees will be the same as for a current member and pro-rated for licenses held for less than a year.
Finally, the Exchange notes that it operates in a highly competitive market in which market participants can readily favor competing venues if they deem fee levels at a particular venue to be excessive or rebate opportunities available at other venues to be more favorable. In such an environment, the Exchange must continually adjust its fees and rebates to remain competitive with other exchanges and with alternative trading systems that have been exempted from compliance with the statutory standards applicable to exchanges. Because competitors are free to modify their own fees and credits in response, and because market participants may readily adjust their order routing practices, the Exchange believes that the degree to which fee changes in this market may impose any burden on competition is extremely limited. As a result of all of these considerations, the Exchange does not believe that the proposed changes will impair the ability of member organizations or competing order execution venues to maintain their competitive standing in the financial markets.
No written comments were solicited or received with respect to the proposed rule change.
The foregoing rule change is effective upon filing pursuant to Section 19(b)(3)(A)
At any time within 60 days of the filing of such proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings under Section 19(b)(2)(B)
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act.
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549–1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (the “Act”),
The Exchange filed a proposal to authorize the BATS Options Market (“BATS Options”) to delete its rule entitled “Temporary Rule Governing Phase-Out of P and P/A Orders” and amend any references in the rules to the Plan for the Purpose of Creating and Operating an Intermarket Linkage (“Linkage Plan”).
The text of the proposed rule change is available at the Exchange's Web site at
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in Sections A, B, and C below, of the most significant parts of such statements.
The purpose of the proposed rule change is to eliminate existing references to the Linkage Plan and also replace any references to the Linkage Plan with references to the Options Order Protection and Locked/Crossed Market Plan (“Plan”) in order to clarify the current rules in effect.
On February 4, 2010, the Exchange filed the Plan, joining all other approved options exchanges in adopting the Plan.
The Exchange adopted a temporary rule entitled “Temporary Rule Governing Phase-Out of P and P/A Orders” (“Temporary Rule”),
In addition to the changes set forth above, the Exchange proposes to add the letter “(a)” to Rule 27.1 to conform with the typical numbering used in Exchange rules.
The Exchange believes that its proposal is consistent with the requirements of the Act and the rules and regulations thereunder that are applicable to a national securities exchange, and, in particular, with the requirements of Section 6(b) of the Act.
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. The proposal will simply eliminate the Temporary Rule, which is outdated and no longer necessary for the reasons described above. Accordingly, the Exchange does not believe that the proposal has any competitive effect.
The Exchange has not solicited, and does not intend to solicit, comments on this proposed rule change. The Exchange has not received any written comments from members or other interested parties.
The Exchange has filed the proposed rule change pursuant to Section 19(b)(3)(A)(iii) of the Act
A proposed rule change filed under Rule 19b-4(f)(6) normally does not become operative for 30 days after the date of filing. However, Rule 19b–4(f)(6)(iii) permits the Commission to designate a shorter time if such action is consistent with the protection of investors and the public interest. The Exchange has asked the Commission to waive the 30-day operative delay so that the Exchange may eliminate its Temporary Rule, which has been replaced by the Plan. The Commission believes that removal of the obsolete rule could avoid potential confusion by Members and other market participants. Based on the foregoing, the Commission believes that waiving the 30-day operative delay is consistent with the protection of investors and the public interest.
At any time within 60 days of the filing of the proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings to determine whether the proposed rule should be approved or disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549–1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”),
The Exchange proposes to amend BX Rule 7015 to clarify the connectivity options and application of the fees assessed thereunder.
The text of the proposed rule change is available on the Exchange's Web site at
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
Rule 7015 provides the charges BX assesses for equity securities market connectivity to systems operated by BX. BX is amending Rule 7015 in three ways: (1) To clarify the term “port pair”; (2) to clarify the connectivity options available under the rule; and (3) to eliminate internet ports as a connectivity option.
First, BX is proposing to clarify the use of the term “port pair.” For certain ports under Rule 7015 that are used for either trading or data, BX additionally provides a disaster recovery port at no cost. Such a disaster recovery port provides connectivity to BX's disaster recovery location in the event of a failure of BX's primary trading infrastructure. BX has provided disaster recovery ports at no cost since 2009 to encourage member firms to maintain such connectivity in the event of a market disruption so that the market as a whole could continue to operate. In the interest of clarity, the Exchange is proposing to eliminate the term port pair and to separately list disaster recovery ports as a connectivity option available at no cost under the rule.
Second, BX is reorganizing and adding language to Rule 7015 to list all connectivity provided by BX under the rule, which is currently subsumed in a connectivity option and related fee. Specifically, the Exchange currently offers connectivity for $500 per port, per month for each port pair other than Multicast ITCH data feed pairs and TCP ITCH data feed pairs. Under the $500 per port, per month connectivity option a member firm may subscribe to an OUCH protocol trading port, a FIX Trading Port (either a FIX or FIX Lite protocol),
Third, BX is proposing to eliminate Internet Ports. Internet ports are based on outdated technology and BX does not have any subscribers to this connectivity method.
The Exchange believes the proposed rule change is consistent with Section 6(b) of the Act,
The Exchange believes that the clarifying changes to the rule protect investors and the public interest because they explicitly describe the fees assessed for all ports under the rule. Describing all services covered by the rule will serve to avoid investor confusion over the scope of what connectivity options are available, and the costs of such options. The Exchange notes that it is not adding new connectivity options or functionality, but is rather describing more specifically what is currently offered under the rule. In this regard, the Exchange is adding new rule text that describes all functionality available under each subparagraph of the rule and is reorganizing some rule text under the rule in an effort to make the rule clearer. The Exchange notes that much of the new text concerns testing ports and ports used in the event of a disaster or hardware failure. These ports help ensure that a fair and orderly market is maintained by allowing member firms to test their systems prior to connecting to the live trading environment and to provide backup connectivity in the event of a failure or disaster. Thus, the Exchange believes the proposed clarifying changes are consistent with the protection of investors and the public interest.
The Exchange believes that the proposed deletion of the Internet Port connectivity option is reasonable, equitably allocated, and not unfairly discriminatory because there are no subscribers to this connectivity option, which is based on outdated means of connecting to the Exchange. As a consequence, no member firms will be impacted by deletion of the connectivity option. The Exchange notes that it is not altering the charges assessed for the remaining connectivity options under Rule 7015.
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. Specifically, BX is making clarifying changes to Rule 7015, which does not impose any burden on competition whatsoever. To the contrary, the proposed change facilitates competition by clarifying what connectivity options are provided by the Exchange, thereby informing other market venues a better understanding of what connectivity options are available for BX. With that better understanding, other market venues may improve existing connectivity options or offer new connectivity options to compete with BX. Accordingly, the proposed changes do not inhibit market participants' ability to compete among each other, nor do they impose any burden on competition among market venues, but rather may promote competition among market venues.
No written comments were either solicited or received.
Because the foregoing proposed rule change does not: (i) Significantly affect the protection of investors or the public interest; (ii) impose any significant burden on competition; and (iii) become operative for 30 days from the date on which it was filed, or such shorter time as the Commission may designate, it has become effective pursuant to Section 19(b)(3)(A)(ii) of the Act
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549–1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The proposed rule change would update DTC's Custody Service Guide (“Custody Guide”) to codify DTC's current procedures for assigning a value to securities held in DTC's Custody Service for shipping insurance valuation purposes, as more fully described below.
In its filing with the Commission, DTC included statements concerning the purpose of, and basis for, the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. DTC has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
The purpose of the proposed rule filing submitted by DTC is to update the text of the Custody Guide to codify its current procedures for assigning a value to securities held in DTC's Custody Service for shipping insurance valuation purposes only, as described below.
The Custody Service enables Participants that hold physical securities that are not presently eligible for book-entry services at DTC to deposit those securities with DTC for safekeeping and certain limited depository services.
DTC carries insurance relating to the replacement of certificates lost in transit or on its premises. Based on DTC's insurance coverage, it is recommended that the depositing Participant review its holdings and, when possible, submit these high value certificates for breakdowns so that the dollar value remains within DTC's insurance limits.
Prior to shipping high value certificates, when possible, arrangements are made with transfer agents or issuers to cancel these certificates before shipment. DTC limits its liability for loss with respect to high-value certificates to the Limit, as defined below; however DTC's liability for loss is not limited to the Limit to the extent that such loss is caused directly by DTC's gross negligence or willful misconduct; provided that in no event shall DTC be liable for any special, consequential, exemplary, incidental, or punitive damages in this regard. The “Limit” is defined as DTC's insurance coverage at the time of the loss in question, provided that with respect to a loss during shipment, the Limit is the lesser of DTC's insurance coverage at the time of the loss in question and $100 million. Participants may request from time to time information regarding the Limit.
DTC has internal procedures to control, safeguard and limit the risk of potential loss of a high value certificate. For example, DTC staff will work with the depositing Participant's staff to breakdown the deposit into smaller workable denominations so that they fall within a more acceptable range of value. In addition, where possible, arrangements will be made with transfer agents/issuers to cancel these certificates prior to their shipment.
•
•
The proposed rule change would become effective immediately.
Section 17A(b)(3)(F) of the Act requires that the rules of the clearing agency be designed,
Rule 17Ad–22(d)(15) promulgated under the Act requires,
DTC does not believe that the proposed rule change would have any impact, or impose any burden, on competition because it merely codifies DTC's current practice with respect to shipping insurance valuation of Custody Service securities and DTC's identification and management of the risks therein and does not otherwise impact users of DTC's services.
Written comments relating to the proposed rule change have not been solicited or received. DTC will notify the Commission of any written comments received by DTC.
The foregoing rule change has become effective pursuant to Section 19(b)(3)(A) of the Act
Interested persons are invited to submit written data, views and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549–1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”),
The Exchange proposes to amend Chapter VIII of the Pricing Schedule to clarify the connectivity options and application of the fees assessed thereunder.
The text of the proposed rule change is available on the Exchange's Web site at
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
Chapter VIII of the Pricing Schedule provides the charges Phlx assesses for equity securities market connectivity to systems operated by Phlx. Phlx is amending Chapter VIII of the Pricing Schedule in four ways: (1) To clarify the term “port pair”; (2) to clarify the connectivity options available under the rule; (3) to eliminate internet ports as a connectivity option; and (4) to eliminate rule text concerning a waiver of fees of limited duration that has since expired.
First, Phlx is proposing to clarify the use of the term “port pair.” For certain ports under Chapter VIII of the Pricing Schedule that are used for either trading or data, Phlx additionally provides a disaster recovery port at no cost. Such a disaster recovery port provides connectivity to Phlx's disaster recovery location in the event of a failure of Phlx's primary trading infrastructure. Phlx has provided disaster recovery ports at no cost since 2010 to encourage member organization to maintain such connectivity in the event of a market disruption so that the market as a whole could continue to operate. In the interest of clarity, the Exchange is proposing to eliminate the term port pair and to separately list disaster recovery ports as a connectivity option available at no cost under the rule.
Second, Phlx is reorganizing and adding language to Chapter VIII of the Pricing Schedule to list all connectivity provided by Phlx under the rule, which is currently subsumed in a connectivity option and related fee. Specifically, the Exchange currently offers connectivity for $400 per port, per month for each port pair other than Multicast ITCH data feed pairs. Under the $400 per port, per month connectivity option a member organization may subscribe to an OUCH protocol trading port, a FIX Trading Port (either a FIX or FIX Lite protocol),
Similarly, Phlx offers trading ports that may be used only in test mode. Member organizations may subscribe to these test mode trading ports at no cost, which are exclusively used for testing purposes and may not be used for trading in securities in the System. The Exchange is adding rule text noting that these test ports may be subscribed to under the rule. The Exchange also provides data retransmission ports at no cost. Data retransmission ports allow a subscriber to replay market data, in the event the data was missed in a live feed or for verification purposes. Data retransmission ports only allow replay of the current trading day and do not provide data concerning prior trading days' data. The Exchange is adding rule text noting that data retransmission ports may be subscribed to under the rule.
Third, Phlx is proposing to eliminate Internet Ports. Internet ports are based on outdated technology and Phlx does not have any subscribers to this connectivity method.
Fourth, the Exchange is proposing to eliminate rule text concerning a fee waiver of all Access Services fees for the first full six months during which Phlx's equities trading market, NASDAQ OMX PSX, operates. NASDAQ OMX PSX began operations in October, 2010.
The Exchange believes the proposed rule change is consistent with Section 6(b) of the Act,
The Exchange believes that the clarifying changes to the rule protect investors and the public interest because they explicitly describe the fees assessed for all ports under the rule. Describing all services covered by the rule will serve to avoid investor confusion over the scope of what connectivity options are available, and the costs of such options. The Exchange notes that it is not adding new connectivity options or functionality, but is rather describing more specifically what is currently offered under the rule. In this regard, the Exchange is adding new rule text that describes all functionality available under each subparagraph of the rule, and is reorganizing some rule text under the rule in an effort to make the rule clearer. The Exchange notes that much of the new text concerns testing ports, and ports used in the event of a disaster or hardware failure. These ports help ensure that a fair and orderly market is
The Exchange believes that the proposed deletion of the Internet Port connectivity option is reasonable, equitably allocated, and not unfairly discriminatory because there are no subscribers to this connectivity option, which is based on outdated means of connecting to the Exchange. As a consequence, no member organizations will be impacted by deletion of the connectivity option. Likewise, the Exchange believes that the proposed deletion of the expired Access Services fee waiver rule text is reasonable, equitably allocated, and not unfairly discriminatory because the waiver is no longer in effect and therefore no member organizations will be impacted by the deletion. The Exchange notes that it is not altering the charges assessed for the remaining connectivity options under Chapter VIII of the Pricing Schedule.
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. Specifically, Phlx is making clarifying changes to Chapter VIII of the Pricing Schedule, which does not impose any burden on competition whatsoever. To the contrary, the proposed change facilitates competition by clarifying what connectivity options are provided by the Exchange, thereby informing other market venues a better understanding of what connectivity options are available for Phlx. With that better understanding, other market venues may improve existing connectivity options or offer new connectivity options to compete with Phlx. Accordingly, the proposed changes do not inhibit market participants' ability to compete among each other, nor do they impose any burden on competition among market venues, but rather may promote competition among market venues.
No written comments were either solicited or received.
Because the foregoing proposed rule change does not: (i) Significantly affect the protection of investors or the public interest; (ii) impose any significant burden on competition; and (iii) become operative for 30 days from the date on which it was filed, or such shorter time as the Commission may designate, it has become effective pursuant to Section 19(b)(3)(A)(iii) of the Act
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549–1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Securities and Exchange Commission (“Commission”).
Notice of an application under section 6(c) of the Investment Company Act of 1940 (“Act”) for an exemption from section 15(a) of the Act and rule 18f–2 under the Act, as well as from certain disclosure requirements in rule 20a–1 under the Act, Item 19(a)(3) of Form N–1A, Items 22(c)(1)(ii), 22(c)(1)(iii), 22(c)(8) and 22(c)(9) of Schedule 14A under the Securities Exchange Act of 1934, and Sections 6–07(2)(a), (b), and (c) of Regulation S–X (“Disclosure Requirements”). The requested exemption would permit an investment adviser to hire and replace certain sub-advisers without shareholder approval and grant relief
Investment Managers Series Trust (the “Trust”), a Delaware statutory trust registered under the Act as an open-end management investment company with multiple series, on behalf of its series, the State Street/Ramius Managed Futures Strategy Fund (the “SS/R Fund”), Ramius Trading Strategies MF Ltd., a Cayman Islands corporation wholly owned by the SS/R Fund (the “SS/R Subsidiary”), and Ramius Trading Strategies LLC, a Delaware limited liability company registered as an investment adviser under the Investment Advisers Act of 1940 (“Ramius” or the “Advisor,” and, collectively with the Trust and the SS/R Subsidiary, the “Applicants”).
An order granting the application will be issued unless the Commission orders a hearing. Interested persons may request a hearing by writing to the Commission's Secretary and serving applicants with a copy of the request, personally or by mail. Hearing requests should be received by the Commission by 5:30 p.m. on February 5, 2016, and should be accompanied by proof of service on the applicants, in the form of an affidavit or, for lawyers, a certificate of service. Pursuant to rule 0–5 under the Act, hearing requests should state the nature of the writer's interest, any facts bearing upon the desirability of a hearing on the matter, the reason for the request, and the issues contested. Persons who wish to be notified of a hearing may request notification by writing to the Commission's Secretary.
Secretary, U.S. Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549–1090. Applicants: Gregory S. Rowland, Esq., Davis Polk & Wardwell LLP, 450 Lexington Avenue, New York, NY 10017.
Robert Shapiro, Senior Counsel, at (202) 551–7758, or Mary Kay Frech, Branch Chief, at (202) 551–6821 (Division of Investment Management, Chief Counsel's Office).
The following is a summary of the application. The complete application may be obtained via the Commission's Web site by searching for the file number, or an applicant using the Company name box, at
1. The Advisor will serve as the investment adviser to the Funds pursuant to an investment advisory agreement with the Trust (the “Advisory Agreement”).
2. Each Fund may pursue its investment strategies by investing through a direct wholly-owned subsidiary (each such subsidiary, including the SS/R Subsidiary, a “Subsidiary”) or an indirect wholly-owned subsidiary (each, a “Trading Entity”).
3. Applicants request an order exempting Applicants from section 15(a) of the Act and rule 18f–2 thereunder to permit the Trust, on behalf of a Fund, and/or its Advisor, subject to the approval of the Board, to enter into and materially amend investment subadvisory agreements with Subadvisors (“Subadvisory Agreements”) without obtaining shareholder approval.
4. Applicants agree that any order granting the requested relief will be subject to the terms and conditions stated in the application. Such terms and conditions provide for, among other safeguards, appropriate disclosure to Fund shareholders and notification about sub-advisory changes and enhanced Board oversight to protect the interests of the Funds' shareholders.
5. Section 6(c) of the Act provides that the Commission may exempt any person, security, or transaction or any class or classes of persons, securities, or transactions from any provisions of the Act, or any rule thereunder, if such relief is necessary or appropriate in the public interest and consistent with the protection of investors and purposes fairly intended by the policy and provisions of the Act. Applicants believe that the requested relief meets this standard because, as further explained in the application, the Advisory Agreements will remain subject to shareholder approval, while the role of the Subadvisors is substantially similar to that of individual portfolio managers, so that requiring shareholder approval of Subadvisory Agreements would impose unnecessary delays and expenses on the Funds. Applicants believe that the requested relief from the Disclosure Requirements meets this standard because it will improve the Advisor's ability to negotiate fees paid to the Subadvisors that are more advantageous for the Funds.
For the Commission, by the Division of Investment Management, under delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (the “Act”),
The Exchange filed a proposal to amend the fee schedule applicable to Members
The text of the proposed rule change is available at the Exchange's Web site at
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in Sections A, B, and C below, of the most significant parts of such statements.
The Exchange proposes to modify its fee schedule applicable to the Exchange's options platform to modify the criteria necessary to meet the Customer
The Exchange believes that the proposed rule change is consistent with the requirements of the Act and the rules and regulations thereunder that are applicable to a national securities exchange, and, in particular, with the requirements of Section 6 of the Act. Specifically, the Exchange believes that the proposed rule change is consistent with Section 6(b)(4) of the Act, in that it provides for the equitable allocation of reasonable dues, fees and other charges among members and other persons using any facility or system which the Exchange operates or controls. The Exchange notes that it operates in a highly competitive market in which market participants can readily direct order flow to competing venues if they deem fee levels to be excessive.
Volume-based rebates such as those currently maintained on the Exchange
The Exchange believes that this change is reasonable, fair and equitable and non-discriminatory, for the reasons set forth with respect to volume-based pricing generally and because such change will either incentivize participants to further contribute to market quality on the Exchange or will allow the Exchange to earn additional revenue that can be used to offset the addition of new pricing incentives. The Exchange also believes that the proposed rebate remains consistent with pricing previously offered by the Exchange as well as competitors of the Exchange and does not represent a significant departure from the Exchange's general pricing structure.
The Exchange believes the proposed amendment to its fee schedule would not impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. The Exchange does not believe that the proposed change represents a significant departure from previous pricing offered by the Exchange or pricing offered by the Exchange's competitors. Additionally, Members may opt to disfavor the Exchange's pricing if they believe that alternatives offer them better value. Accordingly, the Exchange does not believe that the proposed change will impair the ability of Members or competing venues to maintain their competitive standing in the financial markets. The Exchange does not believe that the proposed change to the Exchange's tiered pricing structure burdens competition, but instead, enhances competition as it is intended to increase the competitiveness of the Exchange by easing the criteria necessary to qualify for the Customer Step-Up Volume tier. Also, the Exchange believes that the decrease to the tier's threshold contributes to, rather than burdens competition, as such change is intended to incentivize participants to increase their participation on the Exchange.
The Exchange has not solicited, and does not intend to solicit, comments on this proposed rule change. The Exchange has not received any written comments from members or other interested parties.
The foregoing rule change has become effective pursuant to Section 19(b)(3)(A) of the Act
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549–1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
On September 22, 2015, NYSE Arca, Inc. (“Exchange” or “Arca”) filed with the Securities and Exchange Commission (“Commission”), pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The Exchange proposes to adopt Rule 7.35P, which relates to auctions for Pillar, the Exchange's new trading technology platform. The Exchange also proposes to amend existing definitions in Rule 1.1.
The Exchange represents that Pillar is an integrated trading technology platform designed to use a single specification for connecting to the equities and options markets operated by Arca and its affiliates, New York Stock Exchange LLC (“NYSE”) and NYSE MKT LLC (“NYSE MKT”).
This filing is the fourth set of proposed rule changes to support Pillar implementation. As proposed, the new rule governing trading on Pillar would have the same numbering as the current rule, but with the modifier “P” appended to the rule number. Specifically, Rule 7.35, which governs auctions, would remain unchanged and continue to apply to any trading in symbols on the current trading platform. Proposed Rule 7.35P would govern auctions for trading in symbols migrated to the Pillar platform.
As stated in the Notice, the Exchange proposes new Rule 7.35P to describe auctions on Pillar, which would be based on Rule 7.35 and Rules 1.1(r) and (s).
The Commission finds that the proposed rule change is consistent with the requirements of the Act and the rules and regulations thereunder applicable to a national securities exchange.
The Commission notes that, in the proposal, the Exchange states its belief that proposed Rule 7.35P, together with rules from the three previous Pillar filings, would remove impediments to and perfect the mechanism of a free and open market because they would promote transparency by using consistent terminology for rules governing equities trading, thereby ensuring that members, regulators, and the public can more easily navigate the Exchange's rulebook and better understand how equity trading would be conducted on Pillar.
The Commission also notes that, with respect to the substantive differences between proposed Rule 7.35P and the current rules, the Exchange states that they would remove impediments to and perfect the mechanism of a fair and orderly market.
Similar to the Core Open Auction, the non-displayed quantity of Reserve Orders eligible to participate in the Early Open Auction would not be included in the Matched Volume or Total Imbalance until the Early Open Auction Imbalance Freeze begins.
There would not be any order entry or cancellation restrictions during the one-minute Auction Imbalance Freeze before the Early Open Auction. According to the Exchange, there is not any trading occurring before the Early Open Auction, and therefore the risk to manipulate market prices before the Early Open Auction is minimal.
As proposed, the non-displayed quantity of Reserve Orders eligible to participate in the Core Open Auction would not be included in the Matched Volume, Total Imbalance, or Market Imbalance until the Core Open Auction Imbalance Freeze begins.
As proposed, the Core Open Auction Imbalance Freeze would be five seconds, instead of one minute.
Under the proposal, because of the shorter Freeze period, MOO and LOO Orders entered during the Freeze would be rejected regardless of side.
As with the Core Open Auction, the non-displayed quantity of Reserve Orders eligible to participate in the Closing Auction would not be included in the Matched Volume, Total Imbalance, or Market Imbalance until the Closing Auction Imbalance Freeze begins.
As proposed, the Exchange would conduct a Closing Auction in Pillar even if there are only Market Orders eligible to participate in the Closing Auction.
As proposed, a Trading Halt Auction would be conducted to re-open trading in an Auction-Eligible Security following a halt or pause of trading in that security in the Early Trading Session, Core Trading Session, or Late Trading Session, as applicable.
Under current Rule 7.35(f)(3)(C), the Corporation, if it deems such action necessary, will disseminate the time, prior to the time that orders are matched pursuant to the Trading Halt Auction, at which orders may no longer be cancelled. The Exchange states that, on the current trading platform, it has not invoked this authority, and it proposes to not include it in the Pillar rules.
As proposed, an IPO Auction would be conducted during the Core Trading Session on the first day of trading for any security, including a Derivative Securities Product,
As proposed, new orders, requests to cancel, and requests to cancel and replace an order that are received during the Auction Processing Period
As proposed, after auction processing concludes, including if there is no Matched Volume and an auction is not conducted, or when transitioning from one trading session to another, orders that are no longer eligible to trade would expire.
As proposed, if orders eligible to trade in the next trading session are marketable, such orders would trade and/or route based on price-time priority of individual orders, as provided in Rule 7.37P.
Based on the Exchange's representations, the Commission believes that the proposed rule change does not raise any novel regulatory considerations and should provide greater specificity with respect to the functionality available on the Exchange as symbols are migrated to the Pillar platform. For these reasons, the Commission believes that the proposal should help prevent fraudulent and manipulative acts and practices, promote just and equitable principles of trade, remove impediments to and perfect the mechanism of a free and open market and a national market system, and, in general, protect investors and the public interest.
As noted above, in Amendment No. 1, the Exchange: (i) Amends proposed Rule 7.35P(h) to provide that the rule would address how orders would be handled not only in the transition to continuous trading following an auction, but also when transitioning from one trading session to the next trading session; (ii) amends proposed Rule 7.35P(h)(3)(B) to provide that, before continuous trading following a prior trading session or an auction begins, the display price and working price of orders would be adjusted as provided for in Rule 7.31P, and that when transitioning to continuous trading, the display price and working price of Day ISOs would be adjusted in the same manner as Arca Only Orders until the Day ISO is either traded in full or displayed at its limit price; and (iii) provides additional discussions related to certain proposed rules. In addition, in Amendment No. 3, the Exchange: (i) Specifies the percentages for the Auction Collar thresholds; (ii) removes the reference to the Trading Halt Auction in the definition of Auction Collar; (iii) states that the Exchange would provide prior notice to ETP Holders if additional UTP Securities are to be designated as Auction-Eligible Securities; (iv) includes cross-references to Rule 7.16P in Commentary .01 to proposed Rule 7.35P to clarify where certain terms are defined; and (v) provides additional discussions related to certain proposed rules. The Commission believes that the changes proposed in Amendment Nos. 1 and 3 do not raise novel regulatory issues and provide further discussions regarding the proposed rules governing Pillar. Accordingly, the Commission finds good cause, pursuant to Section 19(b)(2) of the Act,
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether Amendment Nos. 1 and 3 are consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Brent J. Fields, Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549–1090.
IT IS THEREFORE ORDERED, pursuant to Section 19(b)(2) of the Act,
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (the “Act”),
The Exchange is proposing a rule change to list and trade shares of the SPDR® DoubleLine® Emerging Markets Fixed Income ETF (the “Fund”) of the SSgA Active Trust (the “Trust”) under BATS Rule 14.11(i) (“Managed Fund Shares”). The shares of the Fund are collectively referred to herein as the “Shares.”
The text of the proposed rule change is available at the Exchange's Web site at
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in Sections A, B, and C below, of the most significant parts of such statements.
The Exchange proposes to list and trade the Shares under BATS Rule 14.11(i), which governs the listing and trading of Managed Fund Shares on the Exchange.
SSGA Funds Management, Inc. will be the investment adviser (“SSGA FM” or “Adviser”) to the Fund. The Adviser will serve as the administrator for the Fund (the “Administrator”). DoubleLine Capital LP will be the Fund's sub-adviser (“Sub-Adviser”). State Street Global Markets, LLC (the “Distributor”) will be the principal underwriter and distributor of the Fund's Shares. State Street Bank and Trust Company (the “Sub-Administrator”, “Custodian”, “Transfer Agent” or “Lending Agent”) will serve as sub-administrator, custodian, transfer agent, and, where applicable, lending agent for the Fund.
BATS Rule 14.11(i)(7) provides that, if the investment adviser to the investment company issuing Managed Fund Shares is affiliated with a broker-dealer, such investment adviser shall erect a “fire wall” between the investment adviser and the broker-dealer with respect to access to information concerning the composition and/or changes to such investment company portfolio.
According to the Registration Statement, the Fund will seek to provide high total return from current income and capital appreciation. To achieve its objective, the Fund will invest, under normal circumstances, at least 80% of its net assets (plus the amount of borrowings for investment purposes) in emerging market fixed income securities, as described further in the Principal Holding, Other Portfolio Holdings, and Investment Restrictions sections below.
Under normal market conditions, the Sub-Adviser intends to seek to construct an investment portfolio with a weighted average effective duration of no less than two years and no more than eight years. The effective duration of the portfolio may vary materially from its target, from time to time, and there is no assurance that the effective duration of the Fund's investment portfolio will not exceed its target.
The Fund may invest without limit in investments denominated in any currency, but currently expects to invest a substantial amount of its assets in investments denominated in the U.S. dollar. Securities held by the Fund may be sold at any time. By way of example, sales may occur when the Sub-Adviser perceives deterioration in the credit fundamentals of the issuer, when the Sub-Adviser believes there are negative macro geo-political considerations that may affect the issuer, when the Sub-Adviser determines to take advantage of a better investment opportunity, or the individual security has reached the Sub-Adviser's sell target.
In allocating investments among various emerging market countries, the Sub-Adviser attempts to analyze internal political, market and economic factors. These factors may include public finances, monetary policy, external accounts, financial markets, foreign investment regulations, stability of exchange rate policy, and labor conditions. In certain situations or market conditions, the Fund may temporarily depart from its normal investment policies and strategies provided that the alternative is in the best interest of the Fund. For example, the Fund may hold a higher than normal proportion of its assets in cash in times of extreme market stress.
The Fund intends to achieve its investment objective by investing, under normal circumstances,
The Fund will generally invest in Fixed Income Securities from at least five emerging market countries,
The Fund may invest in corporate bonds.
The Fund may purchase exchange-traded common stocks and exchange-traded preferred securities of foreign corporations. The Fund's investments in common stock of foreign corporations may also be in the form of American Depositary Receipts (“ADRs”), Global Depositary Receipts (“GDRs”) and European Depositary Receipts (“EDRs”) (collectively “Depositary Receipts”).
The Fund may invest in sovereign debt. Sovereign debt obligations are issued or guaranteed by foreign governments or their agencies. Sovereign debt may be in the form of conventional securities or other types of debt instruments such as loans or loan participations. Sovereign debt obligations may be either investment grade or below investment grade.
The Fund may conduct foreign currency transactions on a spot (
In the case of a credit default swap (“CDS”), the contract gives one party (the buyer) the right to recoup the economic value of a decline in the value of debt securities of the reference issuer if the credit event (a downgrade or default) occurs. This value is obtained by delivering a debt security of the reference issuer to the party in return for a previously agreed payment from the other party (frequently, the par value of the debt security).
CDSs may require initial premium (discount) payments as well as periodic payments (receipts) related to the interest leg of the swap or to the default of a reference obligation. The Fund will segregate assets necessary to meet any accrued payment obligations when it is the buyer of CDSs. In cases where the Fund is a seller of a CDS, if the CDS is physically settled or cash settled, the Fund will be required to segregate the full notional amount of the CDS. Such segregation will not limit the Fund's exposure to loss.
While the Adviser and Sub-Adviser, under normal circumstances, will invest at least 80% of the Fund's net assets in the instruments described above, the Adviser and Sub-Adviser may invest up to 20% of the Fund's net assets in other securities and financial instruments, as described below.
The Fund may invest in U.S. Government obligations. U.S. Government obligations are a type of bond. U.S. Government obligations include securities issued or guaranteed as to principal and interest by the U.S. Government, its agencies or instrumentalities.
The Fund may invest in U.S. equity securities. Equity securities are securities that represent an ownership interest (or the right to acquire such an interest) in a company and include common and preferred stock. The Fund's investments in such U.S. equity securities may include securities traded over-the-counter as well as those traded on a securities exchange.
The Fund may invest in repurchase agreements with commercial banks, brokers or dealers to generate income from its excess cash balances and to invest securities lending cash collateral. A repurchase agreement is an agreement under which a fund acquires a financial instrument (
The Fund may also enter into reverse repurchase agreements, which involve the sale of securities with an agreement to repurchase the securities at an agreed-upon price, date and interest payment and have the characteristics of borrowing. The Fund's exposure to reverse repurchase agreements will be covered by securities having a value equal to or greater than such commitments. Under the 1940 Act, reverse repurchase agreements are considered borrowings. Although there is no limit on the percentage of Fund assets that can be used in connection with reverse repurchase agreements, the Fund does not expect to engage, under normal circumstances, in reverse repurchase agreements with respect to more than 10% of its net assets.
The Fund may lend its portfolio securities in an amount not to exceed 33
The Fund may invest in convertible securities traded on an exchange or OTC. Convertible securities are bonds, debentures, notes, or other securities that may be converted or exchanged (by the holder or by the issuer) into shares of the underlying common stock (or cash or securities of equivalent value) at a stated exchange ratio.
In addition to repurchase agreements, the Fund may invest in short-term instruments, including money market instruments, (including money market funds advised by the Adviser), cash and cash equivalents, on an ongoing basis to provide liquidity or for other reasons. Money market instruments are generally short-term investments that may include but are not limited to: (i) Shares of money market funds (including those advised by the Adviser); (ii) obligations issued or guaranteed by the U.S. government, its agencies or instrumentalities (including government-sponsored enterprises); (iii) negotiable certificates of deposit (“CDs”), bankers' acceptances, fixed time deposits and other obligations of U.S. and foreign banks (including foreign branches) and similar institutions; (iv) commercial paper rated at the date of purchase “Prime-1” by Moody's or “A–1” by S&P, or if unrated, of comparable quality as determined by the Adviser; (v) non-convertible corporate debt securities (
The Fund may invest in Restricted Securities. Restricted Securities are securities that are not registered under the Securities Act, but which can be offered and sold to “qualified institutional buyers” under Rule 144A under the Securities Act or securities purchased after the lapse of the appropriate distribution compliance period under Regulation S under the Securities Act.
The Fund may invest in the securities of other investment companies, including affiliated funds and money market funds, subject to applicable limitations under Section 12(d)(1) of the 1940 Act.
The Fund may hold up to an aggregate amount of 15% of its net assets in illiquid assets (calculated at the time of investment), including Restricted Securities deemed illiquid by the Adviser or Sub-Adviser
The Fund intends to qualify each year as a regulated investment company (a “RIC”) under Subchapter M of the Internal Revenue Code of 1986, as amended.
The Fund's investments will be consistent with its investment objective and will not be used to seek to achieve leveraged or inverse leveraged returns (
According to the Registration Statement, the net asset value (“NAV”) of the Fund's Shares generally will be calculated once daily Monday through Friday as of the close of regular trading on the Exchange, generally 4:00 p.m. Eastern Time (the “NAV Calculation Time”) on each day that the Exchange is open for trading, based on prices at the NAV Calculation Time. NAV per Share is calculated by dividing the Fund's net assets by the number of Fund Shares outstanding. The Fund's net assets are valued primarily on the basis of market quotations. Expenses and fees, including the management fees, will be accrued daily and taken into account for purposes of determining NAV.
Restricted Securities, repurchase agreements, and reverse repurchase agreements will generally be valued at bid prices received from independent pricing services as of the announced
According to the Adviser, U.S. Government obligations; U.S.-registered, dollar-denominated bonds of foreign corporations, governments, agencies and supra-national entities; sovereign debt; corporate bonds; and short-term instruments will generally be valued at bid prices received from independent pricing services as of the announced closing time for trading in such instruments in the respective market. In determining the value of such instruments, pricing services determine valuations for normal institutional-size trading units of such securities using valuation models or matrix pricing, which incorporates yield and/or price with respect to bonds that are considered comparable in characteristics such as rating, interest rate and maturity date and quotations from securities dealers to determine current value. Investments having a maturity of 60 days or less are generally valued at amortized cost.
Listed futures will generally be valued at the settlement price determined by the applicable exchange. Listed options will generally be valued at the last sale price on the applicable exchange. Non-exchange traded derivatives, including OTC-traded options, swaps, forwards, and structured investments, will normally be valued on the basis of quotations or equivalent indication of value supplied by a third-party pricing service or broker-dealer who makes markets in such instruments. The Fund's OTC-traded derivative instruments will generally be valued at bid prices.
Common stocks and other exchange-traded equity securities (including shares of preferred securities, convertible securities, and exchange traded investment companies (“ETPs”)) generally will be valued at the last reported sale price or the official closing price on that exchange where the security is primarily traded on the day that the valuation is made. Foreign equities and exchange-listed Depositary Receipts will be valued at the last sale or official closing price on the relevant exchange on the valuation date. If, however, neither the last sale price nor the official closing price is available, each of these securities will be valued at either the last reported sale price or official closing price as of the close of regular trading of the principal market on which the security is listed. Unsponsored ADRs, which are traded in the OTC market, will be valued at the last reported sale price from the OTC Bulletin Board or OTC Link LLC on the valuation date. OTC-traded preferred securities and OTC-traded convertible securities will be valued based on price quotations obtained from a broker-dealer who makes markets in such securities or other equivalent indications of value provided by a third-party pricing service. Securities of non-exchange traded investment companies will be valued at NAV.
According to the Registration Statement, in the event that current market valuations are not readily available or are deemed unreliable, the Trust's procedures require the Oversight Committee (“Committee”) to determine a security's fair value, in accordance with the 1940 Act.
The NAV of Shares of the Fund will be determined once each business day, normally 4:00 p.m. Eastern time. The Fund currently anticipates that a Creation Unit will consist of 50,000 Shares, though this number may change from time to time, including prior to the listing of the Fund. The exact number of Shares that will comprise a Creation Unit will be disclosed in the Registration Statement of the Fund. The Trust will issue and sell Shares of the Fund only in Creation Units on a continuous basis, without a sales load (but subject to transaction fees), at their NAV per Share next determined after receipt of an order, on any business day, in proper form. Creation and redemption will typically occur in cash, however, the Trust retains discretion to conduct such transactions on an in-kind basis or a combination of cash and in-kind, as further described below.
The consideration for purchase of a Creation Unit of the Fund generally will consist of either (i) the in-kind deposit of a designated portfolio of securities (the “Deposit Securities”) per each Creation Unit and the Cash Component (defined below), computed as described below, or (ii) the cash value of the Deposit Securities (“Deposit Cash”) and the “Cash Component,” computed as described below. When accepting purchases of Creation Units for cash, the Fund may incur additional costs associated with the acquisition of Deposit Securities that would otherwise be provided by an in-kind purchaser. Together, the Deposit Securities or Deposit Cash, as applicable, and the Cash Component constitute the “Fund Deposit,” which represents the minimum initial and subsequent investment amount for a Creation Unit of the Fund. The “Cash Component” is an amount equal to the difference between the NAV of the Shares (per Creation Unit) and the market value of the Deposit Securities or Deposit Cash, as applicable. If the Cash Component is a positive number (
The Custodian, through the National Securities Clearing Corporation (“NSCC”), will make available on each business day, prior to the opening of business on the Exchange, the list of the names and the required amount of each Deposit Security or the required amount of Deposit Cash, as applicable, to be included in the current Fund Deposit
Shares may be redeemed only in Creation Units at their NAV next determined after receipt of a redemption request in proper form by the Fund through the Transfer Agent and only on a business day.
With respect to the Fund, the Custodian, through the NSCC, will make available immediately prior to the opening of business on the Exchange (9:30 a.m. Eastern time) on each business day, the list of the names and share quantities of the Fund's portfolio securities that will be applicable (subject to possible amendment or correction) to redemption requests received in proper form on that day (“Fund Securities”). Fund Securities received on redemption may not be identical to Deposit Securities.
Redemption proceeds for a Creation Unit will be paid either in-kind or in cash or a combination thereof, as determined by the Trust. With respect to in-kind redemptions of the Fund, redemption proceeds for a Creation Unit will consist of Fund Securities as announced by the Custodian on the business day of the request for redemption received in proper form plus cash in an amount equal to the difference between the NAV of the Shares being redeemed, as next determined after a receipt of a request in proper form, and the value of the Fund Securities (the “Cash Redemption Amount”), less a fixed redemption transaction fee and any applicable additional variable charge as set forth in the Registration Statement. In the event that the Fund Securities have a value greater than the NAV of the Shares, a compensating cash payment equal to the differential will be required to be made by or through an authorized participant by the redeeming shareholder. Notwithstanding the foregoing, at the Trust's discretion, an authorized participant may receive the corresponding cash value of the securities in lieu of the in-kind securities value representing one or more Fund Securities.
The creation/redemption order cut-off time for the Fund is expected to be 4:00 p.m. Eastern time. Creation/redemption order cut-off times may be earlier on any day that the Securities Industry and Financial Markets Association (“SIFMA”) (or applicable exchange or market on which the Fund's investments are traded) announces an early closing time. On days when the Exchange closes earlier than normal, the Fund may require orders for Creation Units to be placed earlier in the day.
The Fund's Web site, which will be publicly available prior to the public offering of Shares, will include a form of the prospectus for the Fund that may be downloaded. The Web site will include additional quantitative information updated on a daily basis, including, for the Fund: (1) The prior business day's reported NAV, mid-point of the bid/ask spread at the time of calculation of such NAV (the “Bid/Ask Price”),
In addition, for the Fund, an estimated value, defined in BATS Rule 14.11(i)(3)(C) as the “Intraday Indicative Value,” that reflects an estimated intraday value of the Fund's portfolio, will be disseminated. Moreover, the Intraday Indicative Value will be based upon the current value for the components of the Disclosed Portfolio and will be updated and widely disseminated by one or more major market data vendors at least every 15 seconds during the Exchange's Regular Trading Hours.
The dissemination of the Intraday Indicative Value, together with the Disclosed Portfolio, will allow investors to determine the value of the underlying portfolio of the Fund on a daily basis and provide a close estimate of that value throughout the trading day.
Intraday, closing, and settlement prices of common stocks and other exchange-listed instruments (including Depositary Receipts, preferred securities, convertible securities, common stock, and ETPs) will be readily available from the national securities exchanges trading such securities as well as automated quotation systems, published or other public sources, or online information services such as Bloomberg or Reuters. Intraday and closing price information for exchange-traded options and futures will be available from the applicable exchange and from major market data vendors. In addition, price information for U.S. exchange-traded options will be available from the Options Price Reporting Authority. Quotation
Information regarding market price and volume of the Shares will be continually available on a real-time basis throughout the day on brokers' computer screens and other electronic services. The previous day's closing price and trading volume information for the Shares will be published daily in the financial section of newspapers. Quotation and last sale information for the Shares will be available on the facilities of the CTA.
The Shares will be subject to BATS Rule 14.11(i), which sets forth the initial and continued listing criteria applicable to Managed Fund Shares. The Exchange represents that, for initial and/or continued listing, the Fund must be in compliance with Rule 10A–3 under the Act.
With respect to trading halts, the Exchange may consider all relevant factors in exercising its discretion to halt or suspend trading in the Shares of the Fund. The Exchange will halt trading in the Shares under the conditions specified in BATS Rule 11.18. Trading may be halted because of market conditions or for reasons that, in the view of the Exchange, make trading in the Shares inadvisable. These may include: (1) The extent to which trading is not occurring in the securities and/or the financial instruments composing the Disclosed Portfolio of the Fund; or (2) whether other unusual conditions or circumstances detrimental to the maintenance of a fair and orderly market are present. Trading in the Shares also will be subject to Rule 14.11(i)(4)(B)(iv), which sets forth circumstances under which Shares of the Fund may be halted.
The Exchange deems the Shares to be equity securities, thus rendering trading in the Shares subject to the Exchange's existing rules governing the trading of equity securities. BATS will allow trading in the Shares from 8:00 a.m. until 5:00 p.m. Eastern Time. The Exchange has appropriate rules to facilitate transactions in the Shares during all trading sessions. As provided in BATS Rule 14.11(i)(2)(C), the minimum price variation for quoting and entry of orders in Managed Fund Shares traded on the Exchange is $0.01.
The Exchange believes that its surveillance procedures are adequate to properly monitor the trading of the Shares on the Exchange during all trading sessions and to deter and detect violations of Exchange rules and the applicable federal securities laws. Trading of the Shares through the Exchange will be subject to the Exchange's surveillance procedures for derivative products, including Managed Fund Shares. The Exchange may obtain information regarding trading in the Shares and the underlying shares in exchange traded investment companies, U.S. equity securities, foreign securities, futures, and options via the ISG, from other exchanges who are members or affiliates of the ISG, or with which the Exchange has entered into a comprehensive surveillance sharing agreement.
Prior to the commencement of trading, the Exchange will inform its members in an Information Circular of the special characteristics and risks associated with trading the Shares. Specifically, the Information Circular will discuss the following: (1) The procedures for purchases and redemptions of Shares in Creation Units (and that Shares are not individually redeemable); (2) BATS Rule 3.7, which imposes suitability obligations on Exchange members with respect to recommending transactions in the Shares to customers; (3) how information regarding the Intraday Indicative Value and the Disclosed Portfolio is disseminated; (4) the risks involved in trading the Shares during the Pre-Opening
In addition, the Information Circular will advise members, prior to the commencement of trading, of the prospectus delivery requirements applicable to the Fund. Members purchasing Shares from the Fund for resale to investors will deliver a prospectus to such investors. The Information Circular will also discuss any exemptive, no-action, and interpretive relief granted by the Commission from any rules under the Act.
In addition, the Information Circular will reference that the Fund is subject to various fees and expenses described in the Registration Statement. The Information Circular will also disclose the trading hours of the Shares of the Fund and the applicable NAV Calculation Time for the Shares. The Information Circular will disclose that information about the Shares of the Fund will be publicly available on the Fund's Web site. In addition, the Information Circular will reference that the Trust is subject to various fees and expenses described in the Fund's Registration Statement.
The Exchange believes that the proposal is consistent with Section 6(b) of the Act
The Exchange believes that the proposed rule change is designed to prevent fraudulent and manipulative acts and practices in that the Shares will be listed and traded on the Exchange pursuant to the initial and continued listing criteria in BATS Rule 14.11(i). The Exchange believes that its surveillance procedures are adequate to properly monitor the trading of the Shares on the Exchange during all trading sessions and to deter and detect violations of Exchange rules and the applicable federal securities laws. If the investment adviser to the investment company issuing Managed Fund Shares is affiliated with a broker-dealer, such investment adviser to the investment company shall erect a “fire wall” between the investment adviser and the broker-dealer with respect to access to information concerning the composition and/or changes to such investment company portfolio. The Adviser is not a registered broker-dealer, but is affiliated with a broker-dealer and has implemented a “fire wall” with respect to such broker-dealer regarding access to information concerning the composition and/or changes to the Fund's portfolio. In the event (a) the Adviser or Sub-Adviser becomes registered as a broker-dealer or newly affiliated with a broker-dealer, or (b) any new adviser or sub-adviser is a registered broker-dealer or becomes affiliated with a broker-dealer, it will implement a fire wall with respect to its relevant personnel or broker-dealer affiliate regarding access to information concerning the composition and/or changes to the portfolio, and will be subject to procedures designed to prevent the use and dissemination of material non-public information regarding such portfolio. The Exchange may obtain information regarding trading in the Shares and the underlying shares in Depositary Receipts that are not OTC ADRs and exchange traded investment companies, U.S. equity securities, futures, and options via the ISG, from other exchanges who are members or affiliates of the ISG, or with which the Exchange has entered into a comprehensive surveillance sharing agreement.
According to the Registration Statement, the Fund intends to achieve its investment objective by investing, under normal circumstances, at least 80% of its net assets in Fixed Income Securities from at least five emerging market countries, with no more than 20% allocated to a single country. The Fund's investments will be consistent with the Fund's investment objective and will not be used to achieve leveraged or inverse leveraged returns, as stated above. While the Fund is permitted to invest without restriction in corporate bonds, the Sub-Adviser expects that, under normal circumstances, the Fund will generally seek to invest in corporate bond issuances that have at least $100,000,000 par amount outstanding. Further, component corporate bonds that in the aggregate account for at least 75% of the weight of corporate bonds will have a minimum original principal outstanding of $100 million or more.
In addition to the holdings in Fixed Income Securities described above as part of the Fund's principal investment strategy, the Fund may also, to a limited extent (under normal circumstances, less than 20% of the Fund's net assets) and as further described above, engage in transactions in the following:
U.S. Government obligations, U.S. equity securities, repurchase agreements, reverse repurchase agreements, portfolio lending, convertible securities, short-term instruments, Restricted Securities, and securities of other investment companies.
The Fund may hold up to an aggregate amount of 15% of its net assets in illiquid assets (calculated at the time of investment), including Restricted Securities deemed illiquid by the Adviser or Sub-Adviser
The proposed rule change is designed to promote just and equitable principles of trade and to protect investors and the public interest in that the Exchange will obtain a representation from the issuer of the Shares that the NAV per Share will be calculated daily and that the NAV and the Disclosed Portfolio will be made available to all market participants at the same time. In addition, a large amount of information is publicly available regarding the Fund and the Shares, thereby promoting market transparency. Moreover, the Intraday Indicative Value will be disseminated by one or more major market data vendors at least every 15 seconds during Regular Trading Hours. On each business day, before commencement of trading in Shares during Regular Trading Hours, the Fund will disclose on its Web site the Disclosed Portfolio that will form the basis for the Fund's calculation of NAV at the end of the business day. Pricing information will be available on the Fund's Web site including: (1) The prior business day's reported NAV, the Bid/Ask Price of the Fund, and a calculation of the premium and discount of the Bid/Ask Price against the NAV; and (2) data in chart format displaying the frequency distribution of discounts and premiums of the daily Bid/Ask Price against the
Intraday, closing, and settlement prices of common stocks and other exchange-listed instruments (including Depositary Receipts, preferred securities, convertible securities, common stock, and ETPs) will be readily available from the national securities exchanges trading such securities as well as automated quotation systems, published or other public sources, or online information services such as Bloomberg or Reuters. Intraday and closing price information for exchange-traded options and futures will be available from the applicable exchange and from major market data vendors. In addition, price information for U.S. exchange-traded options will be available from the Options Price Reporting Authority. Quotation information from brokers and dealers or pricing services will be available for Fixed Income Securities. Price information regarding spot currency transactions and OTC-traded derivative instruments, including options, swaps, and forward currency transactions, as well as non-exchange listed equity securities traded in the OTC market, including Restricted Securities, repurchase and reverse repurchase agreements, OTC equity securities, OTC-traded preferred securities, and OTC-traded convertible securities, is available from major market data vendors.
The proposed rule change is designed to perfect the mechanism of a free and open market and, in general, to protect investors and the public interest in that it will facilitate the listing and trading of an additional type of actively-managed exchange-traded product that will enhance competition among market participants, to the benefit of investors and the marketplace. As noted above, the Exchange has in place surveillance procedures relating to trading in the Shares and may obtain information via ISG from other exchanges that are members of ISG or with which the Exchange has entered into a comprehensive surveillance sharing agreement. In addition, as noted above, investors will have ready access to information regarding the Fund's holdings, the Intraday Indicative Value, the Disclosed Portfolio, and quotation and last sale information for the Shares.
For the above reasons, the Exchange believes that the proposed rule change is consistent with the requirements of Section 6(b)(5) of the Act.
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purpose of the Act. The Exchange notes that the proposed rule change will facilitate the listing and trading of an additional actively-managed exchange-traded product that will enhance competition among market participants, to the benefit of investors and the marketplace.
The Exchange has neither solicited nor received written comments on the proposed rule change.
Within 45 days of the date of publication of this notice in the
(A) By order approve or disapprove the proposed rule change, or
(B) institute proceedings to determine whether the proposed rule change should be disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549–1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
East Penn Railroad, LLC (ESPN), a Class III rail carrier, has filed a verified notice of exemption under 49 CFR 1150.41 to lease from Norfolk Southern Railway Company (NSR) 1.8 miles of rail line located between milepost VE 0.00 and milepost VE 1.80 near Philadelphia, Pa. (the Line). ESPN will be the operator on the Line.
ESPN states that it will shortly enter into an agreement with NSR for the lease of the Line. As required by 49 CFR 1150.43(h), ESPN has disclosed in this notice that the lease agreement contains a provision that will enable ESPN to reduce its lease payments by receiving a credit for each car interchanged with NSR.
ESPN has certified that its projected annual revenues as a result of the proposed transaction will not result in ESPN becoming a Class II or Class I rail carrier. ESPN has further certified that its projected annual rail freight revenues from operation of the Line, when combined with ESPN's projected revenues from current rail freight operations, would not exceed $5 million.
ESPN states that it intends to consummate the transaction on or after January 29, 2016, the effective date of the exemption (30 days after the exemption was filed).
If the verified notice contains false or misleading information, the exemption is void ab initio. Petitions to revoke the exemption under 49 U.S.C. 10502(d) may be filed at any time. The filing of a petition to revoke will not automatically stay the effectiveness of the exemption. Petitions for stay must be filed no later than January 22, 2016 (at least 7 days before the exemption becomes effective).
An original and 10 copies of all pleadings, referring to Docket No. FD 35988, must be filed with the Surface Transportation Board, 395 E Street SW., Washington, DC 20423–0001. In addition, a copy of each pleading must be served on Karl Morell, Karl Morell & Associates, Suite 225, 655 15th Street NW., Washington, DC 20005.
According to ESPN, this action is categorically excluded from environmental review under 49 CFR 1105.6(c).
Board decisions and notices are available on our Web site at
By the Board, Rachel D. Campbell, Director, Office of Proceedings.
CSX Transportation, Inc. (CSXT) filed a verified notice of exemption under 49 CFR part 1152 subpart F—
CSXT has certified that: (1) No local traffic has moved over the Line for at least two years; (2) there is no overhead traffic on the Line that would have to be rerouted over other lines; (3) no formal complaint filed by a user of rail service on the Line (or by a state or local government entity acting on behalf of such user) regarding cessation of service over the Line is pending either with the Surface Transportation Board or any U.S. District Court or has been decided in favor of a complainant within the two-year period; and (4) the requirements at 49 CFR 1105.12 (newspaper publication), and 49 CFR 1152.50(d)(1) (notice to governmental agencies) have been met.
As a condition to this exemption, any employee adversely affected by the discontinuance shall be protected under
Provided no formal expression of intent to file an offer of financial assistance (OFA) to subsidize continued rail service has been received, this exemption will become effective on February 17, 2016, unless stayed pending reconsideration. Petitions to stay that do not involve environmental issues and formal expressions of intent to file an OFA to subsidize continued rail service under 49 CFR 1152.27(c)(2)
A copy of any petition filed with the Board should be sent to CSXT's representative: Louis E. Gitomer, Law Offices of Louis E. Gitomer, LLC, 600 Baltimore Ave., Suite 301, Towson, MD 21204.
If the verified notice contains false or misleading information, the exemption is void ab initio.
Board decisions and notices are available on our Web site at
By the Board, Rachel D. Campbell, Director, Office of Proceedings.
Federal Motor Carrier Safety Administration (FMCSA), DOT.
Notice of availability; request for comments.
FMCSA announces the availability of a draft Environmental Assessment (EA) prepared for the expansion of the City of El Paso, Texas, commercial zone. The EA was prepared in compliance with the National Environmental Policy Act of 1969 (NEPA); the Council on Environmental Quality Regulations; and FMCSA NEPA Order 5610.1 (NEPA Implementing Procedures and Policy for Considering Environmental Impacts). Interested persons are invited to comment on the draft EA.
Comments on the draft environmental assessment must be received on or before January 28, 2016.
You may submit comments bearing the Federal Docket Management System Docket ID [FMCSA–2015–0372] using any of the following methods:
Each submission must include the Agency name and the docket number for this notice. Note that DOT posts all comments received without change to
Ms. Andrea Pahlevanpour, Environmental Program Analyst, Regulatory Evaluation Division, U.S. Department of Transportation, Federal Motor Carrier Safety Administration, 1200 New Jersey Ave SE., Washington, DC 20590–0001, Telephone number: 202–366–5370,
The County of El Paso submitted a Presidential Permit application on April 14, 2003, to the U.S. Department of State for replacement of the Fabens-Caseta International Bridge (Fabens, Texas connecting Caseta, Chihuahua, Mexico) and port of entry. The Department of State, under its authority under Executive Order 11423, “Delegation of Functions to Secretary of State Respecting Certain Facilities Constructed and Maintained on United States Borders,” 33 FR 11741 (Aug. 16, 1968), for the construction, maintenance, and operation of U.S.-Mexico cross-border facilities, issued the Presidential Permit on March 16, 2005.
Presidential Permit 05–01 is titled “Authorizing the County of El Paso, Texas, to Construct, Operate, and Maintain an International Bridge, Its Approaches and Facilities, at the International Boundary Between the United States and Mexico.” This permit granted permission, subject to the conditions of the permit, to the County of El Paso, Texas, to construct, operate and maintain an international bridge. The permit noted that the name of the bridge was proposed as the “Tornillo-Guadalupe New International Bridge.” The bridge was to be constructed, “approximately 1,950 feet upstream” from the existing Fabens-Caseta International Bridge. The permit specified that, “[T]he proposed Tornillo International Bridge will facilitate passenger vehicles, commercial trucks, and pedestrian traffic.” In June 2011, the General Services Administration (GSA) announced the kick-off of construction of the new port facility, including a six-lane replacement bridge.
Construction is complete on the United States' side of the crossing, and non-commercial passenger-vehicle crossings are ongoing at this location. Northbound traffic is using the existing bridge, built in 1938 that is to be destroyed and replaced along with the port-of-entry facilities, with the traffic detoured to the new Tornillo inspection facilities. The construction of facilities, interchanges, and roads on the Mexican side of the border has been delayed but is expected to be completed in the near future.
The commercial zone of the City of El Paso, Texas (which had a population of 649,121 as of the 2010 census) is currently defined by the general provisions of 49 CFR Sections 372.239, 372.241 and 372.243. It includes the municipality of the City of El Paso, all municipalities contiguous to the City of El Paso, and all other municipalities and all unincorporated areas that are adjacent to the City of El Paso. It also includes “when the base municipality has a population of 500,000 but less than 1 million, all unincorporated areas within 15 miles of its corporate limits and all of any other municipality any part of which is within 15 miles of the corporate limits of the base municipality.” 49 CFR 372.241(c)(6). The unincorporated community of Tornillo, Texas, as well as the area near the location of the new Port of Entry, are more than 15 miles from the closest municipal boundary of the City of El Paso. Therefore, these areas are not included as part of the current City of El Paso, Texas commercial zone.
FMCSA will expand the City of El Paso, TX, commercial zone to include all unincorporated areas within 15 miles of the corporate boundaries of the City of San Elizario, TX. The City of San Elizario (located southeast of the City of El Paso) was incorporated on November 18, 2013 under the general laws of Texas and is thus included within the present commercial zone of the City of El Paso because it is within 15 miles of the boundary of the City of El Paso. By expanding the commercial zone to include those unincorporated areas within 15 miles of the boundaries of San Elizario, the new Tornillo-Guadalupe POE and the roads and highways providing access to the POE will be within the commercial zone of the City of El Paso, TX. Most motor carriers operating entirely in a border commercial zone such as at El Paso are not required to obtain operating authority to perform such transportation. But under 49 U.S.C. 13902(c) and 49 CFR part 368, Mexico-domiciled motor carriers of property must obtain a certificate of registration to operate in border commercial zones. Allowing all of these carriers to continue their operations at El Paso
NEPA (42 U.S.C. 4371
The draft EA also provides an analysis under the Clean Air Act, as amended (CAA), section 176(c) (42 U.S.C. 42 U.S.C. 7506(c)), and implementing regulations promulgated by the Environmental Protection Agency. None of the alternatives considered in the Draft EA are located in a nonattainment or maintenance area for any of the criteria pollutants; therefore, FMCSA has determined that it is not required to perform the CAA general conformity analysis.
Subject to public notice and comment, FMCSA anticipates issuing a Finding of No Significant Impact (FONSI) related to this action.
Issued pursuant to authority delegated in 49 CFR 1.87 on:
Federal Transit Administration, DOT.
Notice of request for comments.
The Federal Transit Administration invites public comment about its intention to request the Office of Management and Budget's (OMB) approval to renew the following information collection:
The information to be collected for the Bus Testing Program is necessary to ensure that buses have been tested at the Bus Testing Center for maintainability, reliability, safety, performance (including breaking performance), structural integrity, fuel economy, emissions, and noise. Specifically, this notice invites comment on FTA's proposal to adopt new streamlined online procedures for accepting and reviewing applications for entry into the New Bus Model Testing Program. The
Comments must be submitted before February 16, 2016. A comment to OMB is most effective, if OMB receives it within 30 days of publication.
Tia Swain, Office of Administration, Office of Management Planning, (202) 366–0354.
All written comments must refer to the docket number that appears at the top of this document and be submitted to the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th Street NW., Washington, DC 20503, Attention: FTA Desk Officer.
Pipeline and Hazardous Materials Safety Administration (PHMSA), DOT.
Notice and request for comments.
On October 5, 2015, in accordance with the Paperwork Reduction Act of 1995, PHMSA published a notice in the
During the 60-day comment period, PHMSA received no comments in response to these collections. PHMSA is publishing this notice to provide the public with an additional 30 days to comment on the renewal of these information collections and announce that these information collections will be submitted to OMB for approval.
Interested persons are invited to submit comments on or before February 16, 2016.
You may submit comments identified by the docket number PHMSA–2015–0009 by any of the following methods:
•
•
•
Requests for a copy of the Information Collection should be directed to Jenny Donohue by telephone at 202–366–4046 or by email at
Angela Dow by telephone at 202–366–1246 or by email at
Section 1320.8(d), Title 5, Code of Federal Regulations, requires PHMSA to provide interested members of the public and affected agencies an opportunity to comment on information collection and recordkeeping requests. This notice identifies several information collection requests that PHMSA will submit to OMB for renewal. The following information is provided for each information collection: (1) Title of the information collection; (2) OMB control number; (3) Current expiration date; (4) Type of request; (5) Abstract of the information collection activity; (6) Description of affected public; (7) Estimate of total annual reporting and recordkeeping burden; and (8) Frequency of collection. PHMSA will request a three-year term of approval for each information collection activity. PHMSA requests comments on the following information collections:
Estimated number of responses: 733.
Estimated annual burden hours: 1,018,807.
Estimated number of responses: 2,702.
Estimated annual burden hours: 127,328.
Estimated number of responses: 9,343.
Estimated annual burden hours: 865,178.
Estimated number of responses: 434.
Estimated annual burden hours: 59,458.
(a) The need for the renewal and revision of these collections of information for the proper performance of the functions of the agency, including whether the information will have practical utility;
(b) The accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
(c) Ways to enhance the quality, utility, and clarity of the information to be collected; and
(d) Ways to minimize the burden of the collection of information on those who are to respond, including the use of appropriate automated, electronic, mechanical, or other technological collection techniques.
The Paperwork Reduction Act of 1995; 44 U.S.C. Chapter 35, as amended; and 49 CFR 1.48.
Notice is hereby given, pursuant to 5 U.S.C. App. 2, 10(a)(2), that a meeting will be held at the Hay-Adams Hotel, 16th Street and Pennsylvania Avenue NW., Washington, DC, on February 2, 2016 at 11:30 a.m. of the following debt management advisory committee:
Treasury Borrowing Advisory Committee of The Securities Industry and Financial Markets Association.
The agenda for the meeting provides for a charge by the Secretary of the Treasury or his designate that the Committee discuss particular issues and conduct a working session. Following the working session, the Committee will present a written report of its recommendations. The meeting will be closed to the public, pursuant to 5 U.S.C. App. 2, 10(d) and Public Law 103–202, 202(c)(1)(B) (31 U.S.C. 3121 note).
This notice shall constitute my determination, pursuant to the authority placed in heads of agencies by 5 U.S.C. App. 2, 10(d) and vested in me by Treasury Department Order No. 101–05, that the meeting will consist of discussions and debates of the issues presented to the Committee by the Secretary of the Treasury and the making of recommendations of the Committee to the Secretary, pursuant to Public Law 103–202, 202(c)(1)(B). Thus, this information is exempt from disclosure under that provision and 5 U.S.C. 552b(c)(3)(B). In addition, the meeting is concerned with information that is exempt from disclosure under 5 U.S.C. 552b(c)(9)(A). The public interest requires that such meetings be closed to the public because the Treasury Department requires frank and full advice from representatives of the financial community prior to making its final decisions on major financing operations. Historically, this advice has been offered by debt management advisory committees established by the several major segments of the financial community. When so utilized, such a committee is recognized to be an advisory committee under 5 U.S.C. App. 2, 3.
Although the Treasury's final announcement of financing plans may not reflect the recommendations provided in reports of the Committee, premature disclosure of the Committee's deliberations and reports would be likely to lead to significant financial speculation in the securities market. Thus, this meeting falls within the exemption covered by 5 U.S.C. 552b(c)(9)(A).
Treasury staff will provide a technical briefing to the press on the day before the Committee meeting, following the release of a statement of economic conditions and financing estimates. This briefing will give the press an opportunity to ask questions about financing projections. The day after the Committee meeting, Treasury will release the minutes of the meeting, any charts that were discussed at the meeting, and the Committee's report to the Secretary.
The Office of Debt Management is responsible for maintaining records of debt management advisory committee meetings and for providing annual reports setting forth a summary of Committee activities and such other matters as may be informative to the public consistent with the policy of 5 U.S.C. 552(b). The Designated Federal Officer or other responsible agency official who may be contacted for additional information is Fred Pietrangeli, Director for Office of Debt Management (202) 622–1876.
United States Sentencing Commission.
Notice of proposed amendments to sentencing guidelines, policy statements, and commentary. Request for public comment, including public comment regarding retroactive application of any of the proposed amendments; public hearing.
Pursuant to section 994(a), (o), and (p) of title 28, United States Code, the United States Sentencing Commission is considering promulgating certain amendments to the sentencing guidelines, policy statements, and commentary. This notice sets forth the proposed amendments and, for each proposed amendment, a synopsis of the issues addressed by that amendment. This notice also sets forth a number of issues for comment, some of which are set forth together with the proposed amendments, and one of which (regarding retroactive application of proposed amendments) is set forth in the
The proposed amendments and issues for comment in this notice are as follows:
(1) A multi-part proposed amendment to the
(2) a two-part proposed amendment to the policy statement pertaining to “compassionate release,” § 1B1.13 (Reduction in Term of Imprisonment as a Result of Motion by Director of Bureau of Prisons), including (A) a detailed request for comment on whether any changes should be made to the policy statement and (B) a proposed amendment illustrating one possible set of changes to the policy statement,
(3) a proposed amendment to §§ 5B1.3 (Conditions of Probation) and 5D1.3 (Conditions of Supervised Release) to revise, clarify, and rearrange the provisions in the
(4) a proposed amendment to § 2E3.1 (Gambling; Animal Fighting Offenses) to provide higher penalties for animal fighting offenses and to respond to two new offenses relating to attending an animal fighting venture that were established by section 12308 of the Agricultural Act of 2014, Public Law 113–79 (Feb. 7, 2014), and related issues for comment;
(5) a proposed amendment to the child pornography guidelines, §§ 2G2.1 (Sexually Exploiting a Minor by Production of Sexually Explicit Visual or Printed Material; Custodian Permitting Minor to Engage in Sexually Explicit Conduct; Advertisement for Minors to Engage in Production), 2G2.2 (Trafficking in Material Involving the Sexual Exploitation of a Minor; Receiving, Transporting, Shipping, Soliciting, or Advertising Material Involving the Sexual Exploitation of a Minor; Possessing Material Involving the Sexual Exploitation of a Minor with Intent to Traffic; Possessing Material Involving the Sexual Exploitation of a Minor), and 2G2.6 (Child Exploitation Enterprises), to address circuit conflicts and application issues that have arisen when applying these guidelines, including issues in (A) application of the vulnerable victim adjustment when the offense involves minors who are unusually young and vulnerable (such as infants or toddlers) and (B) application of the tiered distribution enhancement and, in particular, determining the appropriate tier of enhancement to apply when the offense involves a peer-to-peer file-sharing program or network, and related issues for comment; and
(6) a multi-part proposed amendment to the guidelines for immigration offenses, including (A) revisions to § 2L1.1 (Smuggling, Transporting, or Harboring an Unlawful Alien) to provide options for raising the base offense level for alien smuggling offenses and address offenses involving unaccompanied minors in alien smuggling offenses, and a related issue for comment, and (B) revisions to § 2L1.2 (Unlawfully Entering or Remaining in the United States) to (i) generally reduce the use of the “categorical approach” in applying the guidelines by measuring the seriousness of a defendant's prior conviction by the length of the sentence imposed on the prior conviction rather than by the type of offense (
(1) Written Public Comment.—Written public comment regarding the proposed amendments and issues for comment set forth in this notice, including public comment regarding retroactive application of any of the proposed amendments, should be received by the Commission not later than March 21, 2016.
(2) Public Hearings.—The Commission plans to hold public hearings regarding the proposed amendments and issues for comment set forth in this notice on February 17, 2016, and March 16, 2016. Further information regarding the public hearings, including requirements for testifying and providing written testimony, as well as the location, time, and scope of the hearings, will be provided by the Commission on its Web site at
Public comment should be sent to the Commission by electronic mail or regular mail. The email address for public comment is
Matt Osterrieder, Legislative Specialist, (202) 502–4500,
The United States Sentencing Commission is an independent agency in the judicial branch of the United States Government. The Commission promulgates sentencing guidelines and policy statements for federal courts pursuant to 28 U.S.C. 994(a). The Commission also periodically reviews and revises previously promulgated guidelines pursuant to 28 U.S.C. 994(o) and submits guideline amendments to the Congress not later than the first day of May each year pursuant to 28 U.S.C. 994(p).
The proposed amendments in this notice are presented in one of two formats. First, some of the amendments are proposed as specific revisions to a guideline or commentary. Bracketed text within a proposed amendment indicates a heightened interest on the Commission's part in comment and suggestions regarding alternative policy choices; for example, a proposed enhancement of [2][4][6] levels indicates that the Commission is considering, and invites comment on, alternative policy choices regarding the appropriate level of enhancement. Similarly, bracketed text within a specific offense characteristic or application note means that the Commission specifically invites comment on whether the proposed provision is appropriate. Second, the Commission has highlighted certain issues for comment and invites suggestions on how the Commission should respond to those issues.
The Commission requests public comment regarding whether, pursuant to 18 U.S.C. 3582(c)(2) and 28 U.S.C. 994(u), any proposed amendment published in this notice should be included in subsection (d) of § 1B1.10 (Reduction in Term of Imprisonment as a Result of Amended Guideline Range (Policy Statement)) as an amendment that may be applied retroactively to previously sentenced defendants. The Commission lists in § 1B1.10(d) the specific guideline amendments that the court may apply retroactively under 18 U.S.C. 3582(c)(2). The background commentary to § 1B1.10 lists the purpose of the amendment, the magnitude of the change in the guideline range made by the amendment, and the difficulty of applying the amendment retroactively to determine an amended guideline range under § 1B1.10(b) as among the factors the Commission considers in selecting the amendments included in § 1B1.10(d). To the extent practicable, public comment should address each of these factors.
Publication of a proposed amendment requires the affirmative vote of at least three voting members and is deemed to be a request for public comment on the proposed amendment.
Additional information pertaining to the proposed amendments described in this notice may be accessed through the Commission's Web site at
28 U.S.C. 994(a), (o), (p), (x); USSC Rules of Practice and Procedure, Rule 4.4.
Synopsis of Proposed Amendment: This proposed amendment responds to recently enacted legislation and miscellaneous guideline issues.
Part A of the proposed amendment responds to the Uniting and Strengthening America by Fulfilling Rights and Ensuring Effective Discipline Over Monitoring Act (USA FREEDOM Act) of 2015, Pub. L. 114–23 (June 2, 2015), which, among other things, set forth changes to statutes related to maritime navigation and provided new and expanded criminal offenses to implement certain provisions in international conventions relating to maritime and nuclear terrorism. The Act also added these new offenses to the list of offenses specifically enumerated at 18 U.S.C. 2332b(g)(5) as federal crimes of terrorism.
The USA FREEDOM Act created a new criminal offense at 18 U.S.C. 2280a (Violence against maritime navigation and maritime transport involving weapons of mass destruction) to prohibit certain terrorism acts and threats against maritime navigation committed in a manner that causes or is likely to cause death, serious injury, or damage, when the purpose of the conduct is to intimidate a population or to compel a government or international organization to do or abstain from doing any act. The prohibited acts include (i) the use against or on a ship, or discharge from a ship, of any explosive or radioactive material, biological, chemical, or nuclear weapon or other nuclear explosive device; (ii) the discharge from a ship of oil, liquefied natural gas, or other hazardous or noxious substance; (iii) any use of a ship that causes death or serious injury or damage; and (iv) the transportation aboard a ship of any explosive or radioactive material. Section 2280a also prohibits the transportation on board a ship of any biological, chemical or nuclear weapon or other nuclear explosive device, and any components, delivery means, or materials for a nuclear weapon or other nuclear explosive device, under specified circumstances, but this conduct does not contain a mens rea requirement. Further, section 2280a prohibits the transportation onboard a ship of a person who committed an offense under section 2280 or 2280a, with the intent of assisting that person evade criminal prosecution. The penalties for violations of section 2280a are a fine, imprisonment for no more than 20 years, or both, or, if the death of a person results, imprisonment for any term of years or life. Section 2280a also prohibits threats to commit the offenses not related to transportation on board a ship and provides a penalty of imprisonment of up to five years.
Part A of the proposed amendment addresses these new offenses at section 2280a by referencing them in Appendix A (Statutory Index) to the following Chapter Two guidelines: §§ 2A1.1 (First Degree Murder); 2A1.2 (Second Degree Murder); 2A1.3 (Voluntary Manslaughter); 2A1.4 (Involuntary Manslaughter); 2A2.1 (Assault with Intent to Commit Murder; Attempted Murder); 2A2.2 (Aggravated Assault), 2A2.3 (Assault); 2A6.1 (Threatening or Harassing Communications); 2B1.1 (Fraud); 2B3.2 (Extortion); 2K1.3 (Unlawful Receipt, Possession, or Transportation of Explosive Materials; Prohibited Transactions Involving Explosive Materials); 2K1.4 (Arson); 2M5.2 (Exportation of Arms, Munitions, or Military Equipment or Services Without Required Validated Export License); 2M5.3 (Providing Material Support or Resources to Designated Foreign Terrorist Organizations or Specially Designated Global Terrorists, or For a Terrorist Purpose); 2M6.1 (Nuclear, Biological, and Chemical Weapons, and Other Weapons of Mass Destruction); 2Q1.1 (Knowing Endangerment Resulting From Mishandling Hazardous or Toxic Substances, Pesticides or Other Pollutants); 2Q1.2 (Mishandling of Hazardous or Toxic Substances or Pesticides); 2X1.1 (Conspiracy); 2X2.1 (Aiding and Abetting); and 2X3.1 (Accessory After the Fact).
The USA FREEDOM Act also created a new criminal offense at 18 U.S.C. § 2281a (Additional offenses against maritime fixed platforms) to prohibit certain maritime terrorism acts that occur either on a fixed platform or to a fixed platform committed in a manner that may cause death, serious injury, or damage, when the purpose of the conduct is to intimidate a population or to compel a government or international organization to do or abstain from doing any act. Section 2281a prohibits specific conduct, including (i) the use against or discharge from a fixed platform, of any explosive or radioactive material, or biological, chemical, or nuclear weapon and (ii) the discharge from a fixed platform of oil, liquefied natural gas, or another hazardous or noxious substance. The penalties for violations of section 2281a are a fine, imprisonment for no more than 20 years, or both, or, if the death of a person results, imprisonment for any term of years or life. Section 2281a also prohibits threats to commit the offenses related to acts on or against fixed platforms and provides a penalty of imprisonment of up to five years.
Part A of the proposed amendment amends Appendix A (Statutory Index) so the new offenses at 18 U.S.C. 2281a are referenced to §§ 2A1.1, 2A1.2, 2A1.3, 2A1.4, 2A2.1, 2A2.2, 2A2.3, 2A6.1, 2B1.1, 2B3.2, 2K1.4, 2M6.1, 2Q1.1, 2Q1.2, and 2X1.1.
In addition, the USA FREEDOM Act created a new criminal offense at 18 U.S.C. 2332i that prohibits (i) the possession or production of radioactive material or a device with the intent to cause death or serious bodily injury or to cause substantial damage to property or the environment; and (ii) the use of a radioactive material or a device, or the use, damage, or interference with the operation of a nuclear facility that causes the release of radioactive material, radioactive contamination, or exposure to radiation with the intent (or knowledge that such act is likely) to cause death or serious bodily injury or substantial damage to property or the environment, or with the intent to compel a person, international organization or country to do or refrain from doing an act. Section 2332i also prohibits threats to commit any such acts. The penalties for violations of section 2332i are a fine for not more than $2,000,000 and imprisonment for any term of years or life.
Part A of the proposed amendment amends Appendix A (Statutory Index) to reference the new offenses at 18 U.S.C. 2332i to §§ 2A6.1, 2K1.4, 2M2.1 (Destruction of, or Production of Defective, War Material, Premises, or Utilities), 2M2.3 (Destruction of, or Production of Defective, National Defense Material, Premises, or Utilities), and 2M6.1.
Finally, Part A makes clerical changes to Application Note 1 to § 2M6.1 (Nuclear, Biological, and Chemical Weapons, and Other Weapons of Mass Destruction) to reflect the redesignation of a section in the United States Code by the USA FREEDOM Act.
Part A of the proposed amendment also sets forth two issues for comment.
Part B of the proposed amendment responds to the Bipartisan Budget Act of 2015, Pub. L. 114–74 (Nov. 2, 2015), which, among other things, amended three existing criminal statutes concerned with fraudulent claims under certain Social Security programs.
The three criminal statutes amended by the Bipartisan Budget Act of 2015 are sections 208 (Penalties [for fraud involving the Federal Old-Age and Survivors Insurance Trust Fund]), 811 (Penalties for fraud [involving special benefits for certain World War II veterans]), and 1632 (Penalties for fraud [involving supplemental security income for the aged, blind, and
Part B amends Appendix A (Statutory Index) so that sections 408, 1011, and 1383a of Title 42 are referenced not only to § 2B1.1 but also to § 2X1.1 (Attempt, Solicitation, or Conspiracy (Not Covered by a Specific Office Guideline)).
Part B of the proposed amendment also includes issues for comment.
Section 1715 of title 18, United States Code (Firearms as nonmailable items), makes it unlawful to deposit for mailing or delivery by the mails pistols, revolvers, and other firearms capable of being concealed on the person and declared nonmailable (as prescribed by Postal Service regulations). For any violation of section 1715, the statutory maximum term of imprisonment is two years. The current
The Department of Justice in its annual letter to the Commission has proposed that section 1715 offenses should be assigned a guideline reference, base offense level, and appropriate specific offense characteristics. The Department indicates that in recent years the United States Attorney's Office for the Virgin Islands has brought several cases charging section 1715, where firearms were illegally brought onto the islands by simply mailing them from mainland United States.
Part C of the proposed amendment amends Appendix A (Statutory Index) to reference offenses under section 1715 to § 2K2.1 (Unlawful Receipt, Possession, or Transportation of Firearms or Ammunition; Prohibited Transactions Involving Firearms or Ammunition). It also adds 18 U.S.C. 1715 to subsection (a)(8) of § 2K2.1, establishing a base offense level of 6 for such offenses.
Part C of the proposed amendment also includes an issue for comment regarding section 1715 offenses and whether other changes to the guidelines are appropriate to address these offenses.
The Internal Revenue Code (Title 26, United States Code) requires employers to withhold from their employees' paychecks money representing the employees' personal income and Social Security taxes. The Code directs the employer to collect taxes as wages are paid, but only requires a periodic payment of such taxes to the IRS. If an employer willfully fails to collect, truthfully account for, or pay over such taxes, 26 U.S.C. 7202 provides both civil and criminal remedies. Section 7202 provides as criminal penalty a term of imprisonment with a statutory maximum of five years.
Section 7202 is referenced in Appendix A (Statutory Index) to § 2T1.6 (Failing to Collect or Truthfully Account for and Pay Over Tax). The Background commentary to § 2T1.6 states that “[t]he offense is a felony that is infrequently prosecuted.” The Department of Justice in its annual letter to the Commission has proposed that the “infrequently prosecuted” statement should be deleted. The Department points out that while that statement may have been accurate when the relevant commentary was originally written (in 1987), the number of prosecutions under section 7202 have since increased substantially. The use of § 2T1.6 increased from three cases in 2002 to 46 cases in 2014.
Part D of the proposed amendment amends the Background Commentary to § 2T6.1 to delete the sentence that states “The offense is a felony that is infrequently prosecuted.”
The Commentary to § 2M6.1 captioned “Application Notes” is amended in Note 1 by striking “831(f)(2)” and inserting “831(g)(2)”, and by striking “831(f)(1)” and inserting “831(g)(1)”.
Appendix A (Statutory Index) is amended by inserting after the line referenced to 18 U.S.C. § 2280 the following:
“18 U.S.C. § 2280a 2A1.1, 2A1.2, 2A1.3, 2A1.4, 2A2.1, 2A2.2, 2A2.3, 2A6.1, 2B1.1, 2B3.2, 2K1.3, 2K1.4, 2M5.2, 2M5.3, 2M6.1, 2Q1.1, 2Q1.2, 2X1.1, 2X2.1, 2X3.1”;
by inserting after the line referenced to 18 U.S.C. § 2281 the following:
“18 U.S.C. 2281a 2A1.1, 2A1.2, 2A1.3, 2A1.4, 2A2.1, 2A2.2, 2A2.3, 2A6.1, 2B1.1, 2B3.2, 2K1.4, 2M6.1, 2Q1.1, 2Q1.2, 2X1.1”;
and by inserting after the line referenced to 18 U.S.C. 2332h the following:
“18 U.S.C. 2332i 2A6.1, 2K1.4, 2M2.1, 2M2.3, 2M6.1”.
1. The USA FREEDOM Act was enacted as a reauthorization of the USA PATRIOT Act, Pub. L. 107–56 (October 26, 2001), relating to the collection of telephone metadata by various national security agencies. Title VII of the Act also amended four existing criminal statutes and created three new criminal statutes to implement certain provisions in international conventions relating to maritime and nuclear terrorism. One of the existing criminal statutes amended by the USA FREEDOM Act was 18 U.S.C. 2280. Although the Act did not amend the substantive offense conduct in section 2280, it added 19 new definitions and terms to the statute and made them applicable to other criminal statutes, including the new offenses created by the Act.
The Commission seeks comment on whether the guidelines should be amended to address the changes made by the USA FREEDOM Act. Are the existing provisions in the guidelines adequate to address the changes to existing criminal statutes and the new offenses created by the Act? If not, how should the Commission amend the guidelines to address them?
2. The proposed amendment would reference the offenses under 18 U.S.C. 2280a, 18 U.S.C. 2281a, and 18 U.S.C. 2332i to various guidelines. The Commission invites comment on offenses under these new statutes, including in particular the conduct involved in such offenses and the nature
In addition, the Commission seeks comment on whether the Commission should reference these new offenses to other guidelines instead of, or in addition to, the guidelines covered by the proposed amendment. Alternatively, should the Commission defer action in response to these new offenses this amendment cycle, undertake a broader review of the guidelines pertaining to offenses involving terrorism and weapons of mass destruction, and include responding to the new offenses as part of that broader review?
Appendix A (Statutory Index) is amended in each of the lines referenced to 42 U.S.C. 408, 1011, and 1383a(a) by inserting “, 2X1.1” at the end.
1. Part B of the proposed amendment would reference the new conspiracy offenses under 42 U.S.C. 408, 1011, and 1383a to § 2X1.1 (Attempt, Solicitation, or Conspiracy (Not Covered by a Specific Office Guideline)). The Commission invites comment on whether the guidelines covered by the proposed amendment adequately account for these offenses. If not, what revisions to the guidelines would be appropriate to account for these offenses?
2. In addition to the amendments to the criminal statutes described above, the Bipartisan Budget Act of 2015 also amended sections 408, 1011, and 1383a of Title 42 to add increased penalties for certain persons who commit fraud offenses under the relevant social security programs. The Act included a provision in all three statutes identifying such persons as:
a person who receives a fee or other income for services performed in connection with any determination with respect to benefits under this title (including a claimant representative, translator, or current or former employee of the Social Security Administration), or who is a physician or other health care provider who submits, or causes the submission of, medical or other evidence in connection with any such determination . . . .
In light of this new provision, a person who meets this criteria and is convicted of a fraud offense under one of the three amended statutes may be imprisoned for not more than ten years, double the otherwise applicable five-year penalty for other offenders. The new increased penalties apply to all of the fraudulent conduct in subsection (a) of the three statutes.
The Commission seeks comment on whether the guidelines should be amended to address cases involving defendants convicted of a fraud offense under one of the three amended statutes and who meet this new criteria set forth by the Bipartisan Budget Act of 2015. Are the existing provisions in the guidelines, such as the provisions at § 2B1.1 and the Chapter Three adjustment at § 3B1.3 (Abuse of Position of Trust or Use of Special Skill), adequate to address these cases? If not, how should the Commission amend the guidelines to address them?
Section 2K2.1 is amended in subsection (a)(8) by inserting “, or § 1715” before the period at the end.
The Commentary to § 2K2.1 captioned “Statutory Provisions” is amended by inserting after “(k)–(o),” the following: “1715,”.
Appendix A (Statutory Index) is amended by inserting after the line referenced to 18 U.S.C. 1712 the following:
“18 U.S.C. 1715 2K2.1”.
1. Part C of the proposed amendment would reference offenses under 18 U.S.C. 1715 to § 2K2.1. The Commission invites comment on offenses under section 1715, including in particular the conduct involved in such offenses and the nature and seriousness of the harms posed by such offenses. What guideline or guidelines are appropriate for these offenses? Does § 2K2.1 adequately account for these offenses? To the extent the Commission does provide a reference to one or more guidelines, what revisions, if any, to those guidelines would be appropriate to account for offenses under section 1715?
The Commentary to § 2T1.6 captioned “Background” is amended by striking “The offense is a felony that is infrequently prosecuted.”.
The proposed amendment contains two parts. Part A sets forth a detailed request for comment on whether any changes should be made to the Commission's policy statement at § 1B1.13 (Reduction in Term of Imprisonment as a Result of Motion by Director of Bureau of Prisons). Part B illustrates one possible set of changes to the policy statement at § 1B1.13.
1.
In light of its review, the OIG recommended that the Bureau of Prisons should consider revising its compassionate release program to facilitate the release of appropriate elderly inmates. The report provided the following specific recommendations, among others: (1) Revising the inmate age provisions to define an aging inmate as age 50 or above; and (2) revising the time-served provision for those inmates 65 and older without medical conditions to remove the requirement that they serve 10 years, and require only that they serve 75 percent of their sentence. In April 2015, the Bureau of Prisons responded to a draft of the OIG report and concurred with each of the recommendations made by the OIG.
Should the list of extraordinary and compelling reasons in the
In addition, the Commission seeks comment on how, if at all, the policy statement at § 1B1.13 should be revised to address the recommendations in the OIG report. Should the Commission adopt the recommendations in the OIG report as part of its revision of the policy statement at § 1B1.13? Should the Commission expand upon these recommendations to revise the Bureau's requirements that limit the availability of compassionate release for aging inmates? Alternatively, should the Commission defer action on this issue during this amendment cycle to consider any possible changes that the Bureau of Prisons might promulgate to its compassionate release program statement in response to the OIG report?
Finally, the Commission adopted the policy statement at § 1B1.13 to implement the directive in 28 U.S.C. 994(t). As noted above, the directive requires the Commission to “describe what should be considered extraordinary and compelling reasons for sentence reduction, including the criteria to be applied and a list of specific examples.” The Commission also has authority to promulgate general policy statements regarding application of the guidelines or other aspects of sentencing that in the view of the Commission would further the purposes of sentencing (18 U.S.C. 3553(a)(2)), including, among other things, the appropriate use of the sentence modification provisions set forth in 18 U.S.C. 3582(c).
The Commentary to § 1B1.13 captioned “Application Notes” is amended in Note 1(A) by striking “following circumstances” and inserting “circumstances set forth below”; by redesignating clause (iv) as clause (viii); by striking clauses (i) through (iii) and inserting the following:
“(i) The defendant (I) has been diagnosed with a terminal, incurable disease; and (II) has a life expectancy of 18 months or less.
(ii) The defendant has an incurable, progressive illness.
(iii) The defendant has suffered a debilitating injury from which he or she will not recover.
(iv) The defendant meets the following criteria—
(I) the defendant is at least 65 years old;
(II) the defendant has served at least 50 percent of his or her sentence;
(III) the defendant suffers from a chronic or serious medical condition related to the aging process;
(IV) the defendant is experiencing deteriorating mental or physical health that substantially diminishes his or her ability to function in a correctional facility; and
(V) conventional treatment promises no substantial improvement to the defendant's mental health or physical condition.
(v) The defendant (I) is at least 65 years old; and (II) has served at least 10 years or 75 percent of his or her sentence, whichever is greater.
(vi) The death or incapacitation of the family member caregiver of the defendant's child.
[“Incapacitation” means the family member caregiver suffered a severe injury or suffers from a severe illness that renders the caregiver incapable of caring for the child. “Child” means an individual who had not attained the age of 18 years.]
(vii) The incapacitation of the defendant's spouse or registered partner when the defendant would be the only available caregiver for the spouse or registered partner.
[“Incapacitation” means the spouse or registered partner (I) has suffered a serious injury or suffers from a debilitating physical illness and the result of the injury or illness is that the spouse or registered partner is completely disabled, meaning that the spouse or registered partner cannot carry on any self-care and is totally confined to a bed or chair; or (II) has a severe cognitive deficit, caused by an illness or injury, that has severely affected the spouse's or registered partner's mental capacity or function but may not be confined to a bed or chair. “Spouse” means an individual in a relationship with the defendant, where that relationship has been legally recognized as a marriage, including a legally-recognized common-law marriage. “Registered partner” means an individual in relationship with the defendant, where the relationship has been legally recognized as a civil union or registered domestic partnership.]”;
and in clause (viii), as so redesignated, by striking “(i), (ii), and (iii)” and inserting “(i) through (vii)”.
Specifically, the Seventh Circuit has found several of the standard conditions to be unduly vague, overbroad, or inappropriately applied.
When imposing a sentence of probation, the court is required to impose certain conditions of probation listed by statute.
In addition, the court is required to direct that the probation officer provide the defendant with a written statement that sets forth all the conditions to which he or she is subject, which must be “sufficiently clear and specific to serve as a guide for the defendant's conduct and for such supervision as is required.”
The Commission is directed by its organic statute to promulgate policy statements on the appropriate use of the conditions of probation and supervised release.
The changes made by the proposed amendment would revise, clarify, and rearrange the provisions in the
In general, the changes are intended to make the conditions more focused and precise as well as easier for defendants to understand and probation officers to enforce. For some conditions that do not have a mens rea standard, a “knowing” standard is inserted.
First, the proposed amendment amends the “mandatory” conditions set forth in subsection (a) of §§ 5B1.3 and 5D1.3. It inserts new language directing that, if there is a court-established payment schedule for making restitution or paying a special assessment, the defendant shall adhere to the schedule.
Second, the proposed amendment amends the “standard” conditions set forth in subsection (c) of §§ 5B1.3 and 5D1.3. Paragraphs (1)–(3), (5)–(6), and (9)–(13) are revised, clarified, and rearranged into a new set of paragraphs (1) through (12). A new paragraph (13) is added, which provides that the defendant “must follow the instructions of the probation officer related to the conditions of supervision.”
Several provisions are moved from the “standard” conditions list to the “special” conditions list, or vice versa. Specifically, paragraph (1) of the “special” conditions list (relating to possession of a firearm or dangerous weapon) is moved to the “standard” conditions list. Paragraphs (4) and (7) of the “standard” conditions list (relating to support of dependents and child support, and alcohol use, respectively) are moved to the “special” conditions list. In addition, as mentioned above, paragraph (14) on the “standard” conditions list (relating to payment of special assessment) is incorporated into the “mandatory” conditions list. Finally, paragraph (8) of the “standard” conditions list (relating to frequenting places where controlled substances are trafficked) is deleted.
Third, the proposed amendment adds two new provisions to the “special” conditions set forth in subsection (d) of §§ 5B1.3 and 5D1.3. The first new provision, based on paragraph (7) of the “standard” conditions, would specify that the defendant must not use or possess alcohol. The second new provision, based on paragraph (4) of the “standard” conditions, would specify that, if the defendant has one or more dependents, the defendant must support his or her dependents; and if the defendant is ordered by the government to make child support payments or to make payments to support a person caring for a child, the defendant must make the payments and comply with the other terms of the order.
Issues for comment are also included.
Section 5B1.3 is amended in subsection (a)(6) by inserting before the semicolon at the end the following: “. If there is a court-established payment schedule for making restitution or paying the assessment (
in subsection (b) by striking “The” and inserting the following:
The”;
in subsection (c) by striking “(Policy Statement) The” and inserting the following:
The”;
and by striking paragraphs (1) through (14) and inserting the following:
“(1) The defendant must report to the probation office in the federal judicial district where he or she is authorized to reside within 72 hours of the time the defendant was sentenced, unless the probation officer tells the defendant to report to a different probation office or within a different time frame.
(2) After initially reporting to the probation office, the defendant will receive instructions from the court or the probation officer about how and when to report to the probation officer, and the defendant must report to the probation officer as instructed.
(3) The defendant must not knowingly leave the federal judicial district where he or she is authorized to reside without first getting permission from the court or the probation officer.
(4) The defendant must [answer truthfully][be truthful when responding to] the questions asked by the probation officer.
(5) The defendant must live at a place approved by the probation officer. If the defendant plans to change where he or she lives or anything about his or her living arrangements (such as the people the defendant lives with), the defendant must notify the probation officer at least 10 calendar days before the change. If notifying the probation officer in advance is not possible due to unanticipated circumstances, the defendant must notify the probation officer within 72 hours of becoming aware of a change or expected change.
(6) The defendant must allow the probation officer to visit the defendant at his or her home or elsewhere, and the defendant must permit the probation officer to take any items prohibited by the conditions of the defendant's supervision that he or she observes in plain view.
(7) The defendant must work full time (at least 30 hours per week) at a lawful type of employment, unless the probation officer excuses the defendant from doing so. If the defendant does not have full-time employment he or she must try to find full-time employment, unless the probation officer excuses the defendant from doing so. If the defendant plans to change where the defendant works or anything about his or her work (such as the position or the job responsibilities), the defendant must notify the probation officer at least 10 calendar days before the change. If notifying the probation officer in advance is not possible due to unanticipated circumstances, the defendant must notify the probation officer within 72 hours of becoming aware of a change or expected change.
(8) The defendant must not communicate or interact with someone the defendant knows is engaged in criminal activity. If the defendant knows someone has been convicted of a felony, the defendant must not knowingly communicate or interact with that person without first getting the permission of the probation officer.
(9) If the defendant is arrested or has any official contact with a law enforcement officer, the defendant must notify the probation officer within 72 hours.
(10) The defendant must not own, possess, or have access to a firearm, ammunition, destructive device, or dangerous weapon (
(11) The defendant must not act or make any agreement with a law enforcement agency to act as a confidential human source or informant without first getting the permission of the court.
(12) If the probation officer determines that the defendant poses a risk to another person (including an organization), the probation officer may require the defendant to tell the person
(13) The defendant must follow the instructions of the probation officer related to the conditions of supervision.”;
and in subsection (d) by striking “(Policy Statement) The” and inserting the following:
“ `
The”;
by striking paragraph (1) and inserting the following:
If the defendant—
(A) has one or more dependents—a condition specifying that the defendant must support his or her dependents; and
(B) is ordered by the government to make child support payments or to make payments to support a person caring for a child—a condition specifying that the defendant must make the payments and comply with the other terms of the order.”;
and in paragraph (4) by striking “
Section 5D1.3 is amended in subsection (a)(6) by inserting before the semicolon at the end the following: “. If there is a court-established payment schedule for making restitution or paying the assessment (
in subsection (b) by striking “The” and inserting the following:
The”;
in subsection (c) by striking “(Policy Statement) The” and inserting the following:
“ `
The”;
and by striking paragraphs (1) through (15) and inserting the following:
“(1) The defendant must report to the probation office in the federal judicial district where he or she is authorized to reside within 72 hours of release from imprisonment, unless the probation officer tells the defendant to report to a different probation office or within a different time frame.
(2) After initially reporting to the probation office, the defendant will receive instructions from the court or the probation officer about how and when to report to the probation officer, and the defendant must report to the probation officer as instructed.
(3) The defendant must not knowingly leave the federal judicial district where he or she is authorized to reside without first getting permission from the court or the probation officer.
(4) The defendant must [answer truthfully][be truthful when responding to] the questions asked by the probation officer.
(5) The defendant must live at a place approved by the probation officer. If the defendant plans to change where he or she lives or anything about his or her living arrangements (such as the people the defendant lives with), the defendant must notify the probation officer at least 10 calendar days before the change. If notifying the probation officer in advance is not possible due to unanticipated circumstances, the defendant must notify the probation officer within 72 hours of becoming aware of a change or expected change.
(6) The defendant must allow the probation officer to visit the defendant at his or her home or elsewhere, and the defendant must permit the probation officer to take any items prohibited by the conditions of the defendant's supervision that he or she observes in plain view.
(7) The defendant must work full time (at least 30 hours per week) at a lawful type of employment, unless the probation officer excuses the defendant from doing so. If the defendant does not have full-time employment he or she must try to find full-time employment, unless the probation officer excuses the defendant from doing so. If the defendant plans to change where the defendant works or anything about his or her work (such as the position or the job responsibilities), the defendant must notify the probation officer at least 10 calendar days before the change. If notifying the probation officer in advance is not possible due to unanticipated circumstances, the defendant must notify the probation officer within 72 hours of becoming aware of a change or expected change.
(8) The defendant must not communicate or interact with someone the defendant knows is engaged in criminal activity. If the defendant knows someone has been convicted of a felony, the defendant must not knowingly communicate or interact with that person without first getting the permission of the probation officer.
(9) If the defendant is arrested or has any official contact with a law enforcement officer, the defendant must notify the probation officer within 72 hours.
(10) The defendant must not own, possess, or have access to a firearm, ammunition, destructive device, or dangerous weapon (
(11) The defendant must not act or make any agreement with a law enforcement agency to act as a confidential human source or informant without first getting the permission of the court.
(12) If the probation officer determines that the defendant poses a risk to another person (including an organization), the probation officer may require the defendant to tell the person about the risk and the defendant must comply with that instruction. The probation officer may contact the person and confirm that the defendant has told the person about the risk.
(13) The defendant must follow the instructions of the probation officer related to the conditions of supervision.
(14) The defendant shall notify the probation officer of any material change in the defendant's economic circumstances that might affect the defendant's ability to pay any unpaid amount of restitution, fines, or special assessments.”;
and in subsection (d) by striking “(Policy Statement) The” and inserting the following:
“ `
The”;
by striking paragraph (1) and inserting the following:
If the defendant—
(A) has one or more dependents—a condition specifying that the defendant must support his or her dependents; and
(B) is ordered by the government to make child support payments or to make payments to support a person caring for a child — a condition specifying that the defendant must make the payments and comply with the other terms of the order.”;
1. The Commission seeks comment on the bracketed options in paragraph (3) of the “special” conditions, which would
2. The Commission seeks comment on the standard condition of supervised release in § 5D1.3(c)(15), which states that the defendant “shall notify the probation officer of any material change in the defendant's economic circumstances that might affect the defendant's ability to pay any unpaid amount of restitution, fines, or special assessments.” Under the proposed amendment, this would remain a standard condition and would be redesignated as subsection (c)(14). The Commission seeks comment on whether this condition should be made a special condition rather than a standard condition.
Animal fighting ventures are prohibited by the Animal Welfare Act, 7 U.S.C. 2156. Under that statute, an “animal fighting venture” is an event that involves a fight between at least two animals for purposes of sport, wagering, or entertainment.
• sponsor or exhibit an animal in an animal fighting venture,
• sell, buy, possess, train, transport, deliver, or receive an animal for purposes of having the animal participate in an animal fighting venture,
• advertise an animal (or a sharp instrument designed to be attached to the leg of a bird) for use in an animal fighting venture or promoting or in any other manner furthering an animal fighting venture,
• sell, buy, transport, or deliver a sharp instrument designed to be attached to the leg of a bird for use in an animal fighting venture,
The criminal penalties for violations of section 2156 are provided in 18 U.S.C. 49. For any violation of section 2156 listed above, the statutory maximum term of imprisonment is 5 years.
However, two new types of animal fighting offenses were added by the Agricultural Act of 2014. They make it unlawful to knowingly—
• attend an animal fighting venture,
• cause an individual under 16 to attend an animal fighting venture,
The statutory maximum is 3 years if the offense of conviction is causing an individual under 16 to attend an animal fighting venture,
All offenses under section 2156 are referenced in Appendix A (Statutory Index) to § 2E3.1 (Gambling Offenses; Animal Fighting Offenses). Under the penalty structure of that guideline, a defendant convicted of an animal fighting offense receives a base offense level of 12 if the offense involved gambling—specifically, if the offense was engaging in a gambling business, transmitting wagering information, or part of a commercial gambling operation—and a base offense level of 10 otherwise. The guideline contains no specific offense characteristics. There is an upward departure provision if an animal fighting offense involves exceptional cruelty.
First, the proposed amendment revises § 2E3.1 to provide a base offense level of [14][16] if the offense involved an animal fighting venture.
In addition, it revises the existing upward departure provision to cover not only offenses involving exceptional cruelty but also offenses involving animal fighting on an exceptional scale.
Next, the proposed amendment responds to the two new offenses relating to attendance at an animal fighting venture. It establishes new base offense levels for such offenses. Specifically, a base offense level of [8][10] in § 2E3.1 would apply if the defendant was convicted under section 2156(a)(2)(B) (causing an individual under 16 to attend an animal fighting venture). The class A misdemeanor at section 2156(a)(2)(A) (attending an animal fighting venture) would not be referenced in Appendix A (Statutory Index) to § 2E3.1; it would receive a base offense level of 6 in § 2X5.2 (Class A Misdemeanors (Not Covered by Another Specific Offense Guideline)).
Issues for comment are also included.
Section 2E3.1 is amended in subsection (a) by striking subsection (a)(2); by redesignating subsections (a)(1) and (a)(3) as subsections (a)(2) and (a)(4), respectively; by striking “or” in subsection (a)(2), as so redesignated; by inserting before subsection (a)(2) (as so redesignated) the following new subsection (a)(1):
“(1) [14][16], if the offense involved an animal fighting venture, except as provided in subdivision (3) below;”;
and by inserting before subsection (a)(4), as so redesignated, the following new subsection (b)(3):
“(3) [8][10], if the defendant was convicted under 7 U.S.C. 2156(a)(2)(B); or”.
The Commentary to § 2E3.1 captioned “Statutory Provisions” is amended by inserting after “7 U.S.C. 2156” the following: “(felony provisions only)”.
The Commentary to § 2E3.1 captioned “Application Notes” is amended in Note 2 by striking “If the offense involved extraordinary cruelty to an animal that resulted in, for example, maiming or death to an animal, an upward departure may be warranted.”, and inserting “There may be cases in which the offense level determined under this guideline substantially understates the seriousness of the offense. In such cases, an upward departure may be warranted. For example, an upward departure may be warranted if (A) the offense involved extraordinary cruelty to an animal; or (B) the offense involved animal fighting on an exceptional scale (such as an offense involving an unusually large number of animals).”.
Appendix A (Statutory Index) is amended in the line referenced to 7 U.S.C. 2156 by inserting after “§ 2156” the following: “(felony provisions only)”.
1. The Commission seeks comment on offenses involving animal fighting. How prevalent are these offenses, and do the guidelines adequately address these offenses? If not, how should the
What, if any, aggravating and mitigating factors are involved in these offenses that the guidelines should take into account? Should the Commission provide new departure provisions, enhancements, adjustments, or minimum offense levels to account for such aggravating or mitigating factors? If so, what should the Commission provide, and with what penalty levels?
For example, should the Commission provide an enhancement if the defendant possessed a dangerous weapon (including a firearm)? Should the Commission provide an enhancement if the defendant was in the business of breeding, selling, buying, possessing, training, transporting, delivering, or receiving animals for use in animal fighting ventures, or brokering such activities?
2. The proposed amendment includes an upward departure provision if the offense involved animal fighting “on an exceptional scale (such as an offense involving an unusually large number of animals).” What additional guidance, if any, should the Commission provide on what constitutes animal fighting on an exceptional scale?
Under the proposed amendment, the factors of exceptional cruelty and exceptional scale are departure provisions. Should the Commission provide enhancements, rather than departure provisions, for these factors? If so, what penalty levels should be provided?
3. The Commission seeks comment on how the multiple count rules should operate when the defendant is convicted of multiple counts of animal fighting offenses. How, if at all, should the guideline calculation be affected by the presence of multiple counts of conviction? For example, should the Commission specify that multiple counts involving animal fighting ventures are to be grouped together under subsection (d) of § 3D1.2 (Groups of Closely Related Counts)? Should the Commission specify that multiple counts involving animal fighting ventures are not to be grouped together?
First, the proposed amendment responds to differences among the circuits in cases in which the offense involves minors who are unusually young and vulnerable (such as infants or toddlers). The production guideline provides a 4-level enhancement if the offense involved a minor who had not attained the age of 12 years and a 2-level enhancement if the minor had not attained the age of 16 years.
These three guidelines do not provide a further enhancement for cases in which the victim was unusually young and vulnerable. However, the adjustment at § 3A1.1(b)(1) provides a 2-level increase if the defendant knew or should have known that the victim was a “vulnerable victim,”
Do not apply subsection (b) if the factor that makes the person a vulnerable victim is incorporated in the offense guideline. For example, if the offense guideline provides an enhancement for the age of the victim, this subsection would not be applied unless the victim was unusually vulnerable for reasons unrelated to age.
There are differences among the circuits over whether the vulnerable victim adjustment applies when the victim is extremely young, such as an infant or toddler. The Ninth Circuit has indicated that the under-12 enhancement “does not take especially vulnerable stages of childhood into account” and that, “[t]hough the characteristics of being an infant or toddler tend to correlate with age, they can exist independently of age, and are not the same thing as merely not having `attained the age of twelve years.' ”
The Fourth Circuit, in contrast, has indicated that the vulnerable victim adjustment may not be applied based solely on extreme youth or on factors that are for conditions that “necessarily are related to . . . age.”
The proposed amendment generally adopts the approach of the Fifth and Ninth Circuits. It amends the Commentary in the child pornography guidelines to provide that application of the age enhancement does not preclude application of the vulnerable victim adjustment. Specifically, if the minor's extreme youth and small physical size made the minor especially vulnerable compared to most minors under the age of 12 years, § 3A1.1(b) applies, assuming the mens rea requirement of § 3A1.1(b) is also met (
Second, the proposed amendment responds to differences among the circuits in applying the tiered enhancement for distribution in § 2G2.2(b)(3), which provides an enhancement ranging from 2 levels to 7 levels depending on specific factors.
There are two related issues that typically arise in child pornography cases when the offense involves a peer-to-peer file-sharing program or network. The first issue is when a participant's use of a peer-to-peer file sharing
The Fifth, Tenth, and Eleventh Circuits have each held that the 2-level distribution enhancement applies if the defendant used a file sharing program, regardless of whether he did so purposefully, knowingly, or negligently.
The Second, Fourth, and Fifth Circuits, in contrast, have held that the 2-level distribution enhancement requires a showing that the defendant knew, or at least acted in reckless disregard of, the file sharing properties of the program.
Other circuits appear to follow somewhat different approaches. The Eighth Circuit has stated that knowledge is required, but knowledge may be inferred from the fact that a file sharing program was used, absent “concrete evidence” of ignorance.
The proposed amendment generally adopts the approach of the Second, Fourth, and Fifth Circuits. It amends subsection (b)(3)(F) to provide that the 2-level enhancement requires “knowing” distribution by the defendant.
As a conforming change, the proposed amendment also revises the 2-level distribution enhancement at § 2G2.1(b)(3) to provide that the enhancement requires that the defendant knowingly distributed.
The 5-level distribution enhancement at subsection (b)(3)(B) applies if the offense involved distribution “for the receipt, or expectation of receipt, of a thing of value, but not for pecuniary gain.” The Commentary provides, as one example, that in a case involving the bartering of child pornographic material, the “thing of value” is the material received in exchange.
The circuits have taken different approaches to this issue. The Fifth Circuit has indicated that when the defendant knowingly uses file sharing software, the requirements for the 5-level enhancement are generally satisfied.
The Fourth Circuit appears to have a higher standard. It has required the government to show that the defendant (1) “knowingly made child pornography in his possession available to others by some means”; and (2) did so “for the specific purpose of obtaining something of valuable consideration, such as more pornography.”
The proposed amendment revises subsection (b)(3)(B) to clarify that the enhancement applies if the defendant distributed in exchange for any valuable consideration. Specifically, this means that the defendant agreed to an exchange with another person under which the defendant knowingly distributed to that other person for the specific purpose of obtaining something of valuable consideration from that other person, such as other child pornographic material, preferential access to child pornographic material, or access to a child.
Section 2G2.1 is amended in subsection (b)(3) by striking “offense involved distribution” and inserting “defendant knowingly distributed”.
The Commentary to § 2G2.1 captioned “Application Notes” is amended by redesignating Notes 2 through 6 as Notes 3 through 7, respectively, and by inserting after Note 1 the following new Note 2:
“2.
Section 2G2.2 is amended in subsection (b)(3) by striking “If the offense involved”;
in subparagraphs (A), (C), (D), and (E) by striking “Distribution” and inserting “If the offense involved distribution”;
in subparagraph (B) by striking “Distribution for the receipt, or expectation of receipt, of a thing of value,” and inserting “If the defendant distributed in exchange for any valuable consideration,”;
and in subparagraph (F) by striking “Distribution” and inserting “If the defendant knowingly distributed,”.
The Commentary to § 2G2.2 captioned “Application Notes” is amended in Note 1 by striking the paragraph that begins “ `Distribution for the receipt, or expectation of receipt, of a thing of value, but not for pecuniary gain' means” and inserting “ `The defendant distributed in exchange for any valuable consideration' means the defendant agreed to an exchange with another person under which the defendant knowingly distributed to that other person for the specific purpose of obtaining something of valuable consideration from that other person, such as other child pornographic material, preferential access to child pornographic material, or access to a child.”;
and by redesignating Notes 2 through 7 as Notes 3 through 8, respectively, and by inserting after Note 1 the following new Note 2:
“2.
The Commentary to § 2G2.6 captioned “Application Notes” is amended by redesignating Notes 2 and 3 as Notes 3
“2.
1. With respect to the interaction of the age enhancements and the vulnerable victim adjustment, the proposed amendment would respond to the circuit conflict by clarifying the circumstances under which the vulnerable victim adjustment would also apply. Should the Commission use a different approach to resolving the circuit conflict? If so, what approach should the Commission use to clarify how the age enhancements interact with the vulnerable victim adjustment? For example, should the Commission revise the tiered age enhancements to provide an additional tier, 2 levels higher than the existing tiers, for cases involving unusually young and vulnerable victims, such as infants or toddlers? In the alternative, should the Commission provide an upward departure provision to address this factor?
Application Note 2 to § 3A1.1 provides that, “if the offense guideline provides an enhancement for the age of the victim, this subsection would not be applied unless the victim was unusually vulnerable for reasons unrelated to age.” Should the Commission revise this provision to change or clarify how age enhancements in the guidelines (whether for child pornography offenses or otherwise) interact with the vulnerable victim adjustment? For example, should the Commission change “unless the victim was unusually vulnerable for reasons unrelated to age” to “unless the victim was unusually vulnerable for reasons not based on age
2. With respect to the 2-level distribution enhancement, the proposed amendment generally adopts the approach of the circuits that require “knowing” distribution. The Commission seeks comment on whether a different approach should be used, particularly in cases involving a file sharing program or network. For example, should the Commission provide a bright-line rule that use of a file sharing program qualifies for the 2-level enhancement, even in cases where the defendant was in fact ignorant that use of the program would result in files being shared to others?
3. With respect to the 5-level distribution enhancement, the proposed amendment would generally require an agreement with another person in which the defendant trades child pornography for other child pornography or another thing of value, such as access to a child. The Commission seeks comment on whether a different approach should be used, particularly in cases involving a file sharing program or network. For example, should the Commission provide a bright-line rule that use of a file sharing program qualifies for the 5-level enhancement?
4. The proposed amendment amends § 2G2.2 to provide that the 2-level enhancement at subsection (b)(3) requires “knowing” distribution by the defendant. Should the Commission change any other enhancements in subsection (b) from an “offense involved” approach to a “defendant-based” approach? If so, should the Commission include a culpable state of mind requirement, such as, for example, requiring “knowing” distribution by the defendant?
5. The guideline for obscenity offenses, § 2G3.1 (Importing, Mailing, or Transporting Obscene Matter; Transferring Obscene Matter to a Minor; Misleading Domain Names), contains a tiered distribution enhancement similar to the tiered distribution enhancement in § 2G2.2. If the Commission were to make revisions to the tiered distribution enhancement in § 2G2.2, should the Commission make similar revisions to § 2G3.1?
The proposed amendment contains two parts. The Commission is considering whether to promulgate any one or both of these parts, as they are not necessarily mutually exclusive. They are as follows—
First, the proposed amendment revises the alternative base offense levels at § 2L1.1(a). Two options are provided. Option 1 would raise the base offense level at subsection (a)(3) from 12 to [16]. Option 2 adds an alternative base offense level of [16] if the defendant smuggled, transported, or harbored an unlawful alien as part of an ongoing commercial organization.
Second, the proposed amendment addresses offenses involving unaccompanied minors in alien smuggling offenses. The Department of Justice in its annual letter to the Commission has suggested that the enhancement for smuggling, transporting, or harboring unaccompanied minors under § 2L1.1(b)(4) is inadequate in light of the serious nature of such offenses. The Department states that “[t]hese smugglers often treat children as human cargo and subject them to a multitude of abuses throughout a long and dangerous journey, including sexual assault, extortion, and other crimes.” The proposed amendment would amend § 2L1.1 to address the issue of unaccompanied minors. The proposed amendment first amends § 2L1.1(b)(4) to make the enhancement offense-based (with a mens rea requirement) as opposed to exclusively defendant-based. The proposed amendment would also amend the commentary to § 2L1.1 to clarify that the term “serious bodily injury” included in subsection (b)(7)(B) has the meaning given to that term in the Commentary to § 1B1.1 (Application Instructions), which states that “serious bodily injury” is deemed to have occurred if the offense involved conduct constituting criminal sexual abuse under 18 U.S.C. 2241 or § 2242 or any similar offense under state law.
Finally, the proposed amendment would revise the definition of “minor” for purposes of the “unaccompanied minor” enhancement at § 2L1.1(b)(4) and change it from minors under the age of 16 to minors under the age of [18]. The proposed amendment also brackets the possibility of including a new departure provision in the commentary to § 2L1.1 for cases in which the offense involved the smuggling, transporting, or harboring of six or more unaccompanied minors.
An issue for comment is also provided.
Section 2L1.1 is amended—
[Option 1:
in subsection (a)(3) by striking “12, otherwise” and inserting “[16], otherwise”;]
[Option 2:
in subsection (a) by redesignating paragraph (3) as paragraph (4), and by inserting after paragraph (2) the following new paragraph (3):
“(3) [16], if the defendant smuggled, transported, or harbored an unlawful alien as part of an ongoing commercial organization; or”;]
and in subsection (b)(4) by striking “If the defendant smuggled, transported, or harbored a minor who was unaccompanied by the minor's parent or grandparent” and inserting “If the offense involved the smuggling, transporting, or harboring of a minor who the defendant knew [or had reason to believe] was unaccompanied by the minor's parent or grandparent”.
The Commentary to § 2L1.1 captioned “Application Notes” is amended—
in Note 1—
[Option 2 (continued):
by inserting before the paragraph that begins “ `The offense was committed other than for profit' means” the following new paragraph:
“ `As part of an ongoing commercial organization' means that the defendant participated (A) in a continuing organization or enterprise of five or more persons that had as one of its primary purposes the smuggling, transporting, or harboring of unlawful aliens for profit, and (B) with knowledge [or reason to believe] that the members of the continuing organization or enterprise smuggled, transported, or harbored different groups of unlawful aliens on more than one occasion.”;]
in the paragraph that begins “ `Minor' means” by striking “16 years” and inserting “[18] years”;
and by inserting after the paragraph that begins “`Parent' means” the following new paragraph:
“ `Bodily injury,' `serious bodily injury,' and `permanent or life-threatening bodily injury' have the meaning given those terms in the Commentary to § 1B1.1 (Application Instructions).”;
by redesignating Notes 2 through 6 as Notes 3 through 7, respectively, and by inserting after Note 1 the following new Note 2:
“2.
and in Note 4, as so redesignated, by inserting at the end the following new subdivision:
“[(D) The offense involved the smuggling, transporting, or harboring of six or more minors who were unaccompanied by their parents or grandparents.]”.
1. The Department of Justice has stated that alien smuggling offenses often involved sexual abuse of the aliens smuggled, transported, or harbored, particularly of unaccompanied minors. The proposed amendment would amend the commentary to § 2L1.1 to clearly state that the term “serious bodily injury” included in subsection (b)(7)(B) has the meaning given to that term in the Commentary to § 1B1.1 (Application Instructions), which is deemed to have occurred if the offense involved conduct constituting criminal sexual abuse under 18 U.S.C. 2241 or § 2242 or any similar offense under state law. The Commission invites comment on whether the 4-level enhancement at § 2L1.1(b)(7)(B) adequately accounts for cases in which the offense covered by this guideline involved sexual abuse of an alien who was smuggled, transported, or harbored. If not, what revisions to § 2L1.1 would be appropriate to account for this conduct? For example, should the Commission provide one or more specific offense characteristics or departure provisions to better account for this conduct? If so, what should the Commission provide?
The key findings from the report include—
• the average sentence for illegal reentry offenders was 18 months;
• all but two of the 18,498 illegal reentry offenders—including the 40 percent with the most serious criminal histories triggering a statutory maximum penalty of 20 years under 8 U.S.C. 1326(b)(2)—were sentenced at or below the ten-year statutory maximum under 8 U.S.C. 1326(b)(1) for offenders with less serious criminal histories (
• the rate of within-guideline range sentences was significantly lower among offenders who received 16-level enhancements pursuant to § 2L1.2(b)(1)(A) for predicate convictions (31.3%), as compared to the within-range rate for those who received no enhancements under § 2L1.2(b) (92.7%);
• significant differences in the rates of application of the various enhancements in § 2L1.2(b) appeared among the districts where most illegal reentry offenders were prosecuted;
• the average illegal reentry offender was deported 3.2 times before his instant illegal reentry prosecution, and over one-third (38.1%) were previously deported after a prior illegal entry or illegal reentry conviction;
• 61.9 percent of offenders were convicted of at least one criminal offense after illegally reentering the United States;
• 4.7 percent of illegal reentry offenders had no prior convictions and not more than one prior deportation before their instant illegal reentry prosecutions; and
• most illegal reentry offenders were apprehended by immigration officials at or near the border.
The statutory penalty structure for illegal reentry offenses is based on whether the defendant had a criminal conviction
•
•
•
The penalty structure of the guideline is similar to the statutory penalty structure. The guideline provides a base offense level of 8 and a tiered enhancement based on whether the defendant had a criminal conviction before he or she was deported. Specifically, the enhancement is—
•
•
•
•
The penalties in the illegal reentry statute apply based on the criminal convictions the defendant had before he or she was deported, regardless of the age of the prior conviction. Likewise, until 2011, the enhancements in § 2L1.2 applied regardless of the age of the prior conviction. In 2011, the Commission revised the guideline to provide that the 16- and 12-level enhancements would be reduced to 12 and 8 levels, respectively, if the conviction was too remote in time (too “stale”) to receive criminal history points under the timing limits set forth in Chapter Four (Criminal History and Criminal Livelihood).
Part B of the proposed amendment amends § 2L1.2 to lessen the emphasis on pre-deportation convictions by providing new enhancements for more recent, post-reentry convictions and a corresponding reduction in the enhancements for past, pre-deportation convictions. The enhancements for these convictions would be based on the sentence imposed rather than on the type of offense (
First, the proposed amendment amends subsection (a) of § 2L1.2 to provide alternative base offense levels of [14] and [12] if the defendant had one or more prior convictions for illegal reentry offenses under 8 U.S.C. 1253, § 1325(a), or § 1326. For defendants without such prior convictions, the proposed amendment increases the otherwise applicable base offense level from 8 to [10]. The alternative base offense levels at subsection (a) apply without regard to whether the prior conviction receives criminal history points.
Second, the proposed amendment changes how subsection (b)(1) accounts for pre-deportation convictions—basing them not on the type of offense (
Third, the proposed amendment would permit prior convictions to be considered under subsection (b)(1) only if they receive criminal history points under Chapter Four.
To account for post-reentry criminal activity, the proposed amendment inserts a new subsection (b)(2) to provide a tiered enhancement for a defendant who engaged in criminal conduct resulting in a conviction for one or more felony offenses after the defendant's first deportation or first order of removal. The structure of the new subsection (b)(2) parallels the proposed changes to subsection (b)(1), both in the sentence length required and the level of enhancement to be applied. As with subsection (b)(1), prior convictions would be considered under subsection (b)(2) only if they receive criminal history points under Chapter Four.
Finally, the proposed amendment provides a new departure provision for cases in which the defendant was previously deported on multiple occasions not reflected in prior convictions under 8 U.S.C. 1253, § 1325(a), or § 1326. It also revises the departure provision based on seriousness of a prior conviction to bring it more into parallel with § 4A1.3 (Adequacy of Criminal History Category) and provide examples related to: (1) cases in which serious offenses do not qualify for an adjustment under subsection (b)(1) and the new subsection (b)(2) because they did not receive criminal history points; and (2) for cases in which a defendant committed one or more felony offenses but no conviction resulted from the commission of such offense or offenses. The proposed amendment also brackets the possibility of deleting the departure based on time served in state custody.
In addition, the proposed amendment would make conforming changes to the application notes, including the consolidation of all guideline definitions in one place.
Issues for comment are also included.
Section 2L1.2 is amended—
in subsection (a) by striking “Base Offense Level: 8” and inserting the following:
“Base Offense Level (Apply the Greatest):
(1) [14], if the defendant committed the instant offense of conviction after sustaining two or more convictions for illegal reentry offenses;
(2) [12], if the defendant committed the instant offense of conviction after sustaining a conviction for an illegal reentry offense;
(3) [10], otherwise.”;
in subsection (b) by striking “Characteristic” in the heading and inserting “Characteristics”; by striking subsection (b)(1) and inserting the following new subsection (b)(1):
“(1) Apply the Greatest:
If, before the defendant's first deportation or first order of removal, the defendant sustained—
(A) a conviction for a felony offense (other than an illegal reentry offense) for which the sentence imposed was [24] months or more, increase by [8] levels;
(B) a conviction for a felony offense (other than an illegal reentry offense) for
(C) a conviction for a felony offense (other than an illegal reentry offense) for which the sentence imposed was less than [12] months, increase by [4] levels; or
(D) three or more convictions for misdemeanors involving drugs, crimes against the person, or both, increase by [2] levels.”;
and by inserting at the end the following new subsection (b)(2):
“(2) Apply the Greatest:
If, at any time after the defendant's first deportation or first order of removal, the defendant engaged in criminal conduct resulting in—
(A) a conviction for a felony offense (other than an illegal reentry offense) for which the sentence imposed was [24] months or more, increase by [8] levels;
(B) a conviction for a felony offense (other than an illegal reentry offense) for which the sentence imposed was at least [12] months but less than [24] months, increase by [6] levels;
(C) a conviction for a felony offense (other than an illegal reentry offense) for which the sentence imposed was less than [12] months, increase by [4] levels; or
(D) three or more convictions for misdemeanors involving drugs, crimes against the person, or both, increase by [2] levels.”.
The Commentary to § 2L1.2 captioned “Statutory Provisions” is amended by inserting after “8 U.S.C.” the following: “§ 1253,”.
The Commentary to § 2L1.2 captioned “Application Notes” is amended—
in Note 1, in the heading, by striking “Subsection (b)(1)” and inserting “Subsections (b)(1) and (b)(2)”;
in Note 1(A) by striking “For purposes of subsection (b)(1)” and inserting “For purposes of this guideline”;
by striking Notes 1(B) and 1(C), and inserting the following new Note 1(B):
“(B)
by striking Notes 2 through 7 and inserting the following new Notes 2, 3, 4, and 5:
“2.
`Felony' means any federal, state, or local offense punishable by imprisonment for a term exceeding one year.
`Illegal reentry offense' means (A) an offense under 8 U.S.C. 1253 or § 1326, or (B) a second or subsequent offense under 8 U.S.C. 1325(a) (regardless of whether the conviction was designated a felony or misdemeanor).
`Misdemeanor' means any federal, state, or local offense punishable by a term of imprisonment of one year or less.
`Sentence imposed' has the meaning given the term `sentence of imprisonment' in Application Note 2 and subsection (b) of § 4A1.2 (Definitions and Instructions for Computing Criminal History), without regard to the date of the conviction. The length of the sentence imposed includes any term of imprisonment given upon revocation of probation, parole, or supervised release, but only if the revocation occurred before the defendant was deported or unlawfully remained in the United States.
`Three or more convictions' means at least three convictions for offenses that are not treated as a single sentence pursuant to subsection (a)(2) of § 4A1.2 (Definitions and Instructions for Computing Criminal History).
3.
A conviction taken into account under subsection (a) or (b) is not excluded from consideration of whether that conviction receives criminal history points pursuant to Chapter Four, Part A (Criminal History).
4.
5.
[by striking Note 8 as follows:
8.
Such a departure should be considered only in cases where the departure is not likely to increase the risk to the public from further crimes of the defendant. In determining whether such a departure is appropriate, the court should consider, among other things, (A) whether the defendant engaged in additional criminal activity after illegally reentering the United States; (B) the seriousness of any such additional criminal activity, including (1) whether the defendant used violence or credible threats of violence or possessed a firearm or other dangerous
and by redesignating Note 9 as Note 6.
1. Some commentators have expressed concern about the operation of the illegal reentry guideline and the severity of the enhancements available in subsection (b) for some offenders. The Commission's recent report found that the rate of within-range sentences differed substantially depending on the level of enhancement under § 2L1.2(b)(1). The rate of within-guideline range sentences was significantly lower among defendants who received the 16-level enhancement (31.3%) as compared to the within-range rate for those who received no enhancements (92.7%). The report showed that the greater enhancements result in the lowest within-range sentences (52.5% within range for 4-level enhancement, 46.7% within range for 8-level enhancement, 32.8% within range for 12-level enhancement).
The Commission seeks comment on whether illegal reentry offenses are adequately addressed by the guidelines. Should the Commission consider amending § 2L1.2 and, if so, how?
2. Currently, § 2L1.2 requires the court to classify the defendant's prior convictions by type (
The proposed amendment would eliminate the use of the “categorical approach” for predicate felony convictions and provide for enhancements based on the sentence imposed rather than on the type of offense. What are the advantages and disadvantages of basing the enhancement on the type of the prior conviction? What are the advantages and disadvantages of basing the enhancement on the length of the sentence imposed on the prior conviction? If the Commission were to adopt the sentence-imposed model, are the 24- and 12-month gradations included in the proposed amendment appropriate? Should the Commission adopt different gradations, such as the ones currently used in Chapter Four of the
3. As noted in the Commission's recent report, both the illegal reentry statute and § 2L1.2 provide enhanced penalties only if the defendant sustained a conviction before being deported. A defendant receives at most a single enhancement under § 2L1.2—based on the most serious conviction. Additional convictions that occurred before the defendant's most recent deportation, and convictions that occurred after the defendant's most recent illegal reentry, are not taken into account in the calculation of the offense level (although they may be taken into account in the criminal history score).
Should the Commission amend how the enhancements at § 2L1.2 work and, if so, how? Should the Commission amend § 2L1.2 to account not only for pre-deportation convictions but also for other aggravating factors relevant to a defendant's culpability and need for incapacitation and deterrence?
For example, the proposed amendment would amend subsection (a) of § 2L1.2 to provide alternative base offense levels if the defendant had one or more prior convictions for illegal reentry offenses under 8 U.S.C. § 1253, § 1325(a), or § 1326. What are the advantages and disadvantages of basing alternative base offense levels on illegal reentry convictions? Should the Commission use a different approach for such alternative base offense levels? Should the Commission use deportations and orders of removal instead to apply the base offense levels?
If the Commission provided additional enhancements to account for aggravating factors relevant to a defendant's culpability other than pre-deportation convictions, how should these enhancements interact? How much weight should be given to pre-deportation convictions in relation to prior illegal reentry convictions or post-reentry convictions in driving the guideline range? Should the guideline provide greater emphasis on one or more of these factors? For example, should the guideline give more weight to post-reentry convictions and less weight to pre-deportation convictions (
What other aggravating factors, if any, should the Commission incorporate into § 2L1.2, and how should the Commission incorporate them? Should the factor be an enhancement, an alternative base offense level, a minimum offense level, an upward departure provision, or some combination of these? If so, what level of enhancement should apply?
What mitigating factors, if any, should the Commission incorporate into § 2L1.2, and how should the Commission incorporate them? For example, should the Commission provide a new departure provision for cases in which the defendant's predicate felony conviction is based on an offense that was classified by the laws of the state as a misdemeanor?
4. Currently, § 2L1.2 provides enhanced penalties based on convictions sustained prior to the defendant's most recent deportation from the United States. The proposed amendment would modify how the enhancements work in the illegal reentry guideline. Specifically, it would divide the defendant's criminal history
What are the advantages and disadvantages of using a particular deportation or order of removal as the determining event for whether a prior conviction qualifies for an enhancement under subsection (b)(1) or subsection (b)(2)? Should the Commission use a different approach to distinguish pre-deportation convictions from post-reentry convictions? For example, should the Commission provide instead that a prior conviction sustained before any deportation would qualify for an enhancement for pre-deportation convictions? If so, how should such enhancement interact with an enhancement based on post-reentry convictions as provided in the proposed amendment?
5. In 2014, the Commission amended the Commentary to § 2L1.1 to add a departure provision for cases in which the defendant is located by immigration authorities while the defendant is in state custody for a state offense unrelated to the federal illegal reentry offense. In such a case, the time served is not covered by adjustment under § 5G1.3 (Imposition of a Sentence on a Defendant Subject to an Undischarged Term of Imprisonment or Anticipated State Term of Imprisonment) and, accordingly, is not covered by a departure under § 5K2.23 (Discharged Terms of Imprisonment). Under the current guideline, the departure allows courts to depart to reflect all or part of the time served in state custody for the unrelated offense, from the time federal immigration authorities locate the defendant until the service of the federal sentence commences, that the court determines will not be credited to the federal sentence by the Bureau of Prisons. The proposed amendment brackets the possibility of deleting the departure provision at Application Note 8 to § 2L1.2.
If the Commission were to promulgate the proposed amendment revising how the enhancements at the illegal reentry guideline work, should the Commission delete the departure based on time served in state custody? If not, how should the new enhancements at § 2L1.2 interact with the departure provision? For example, should the Commission limit the applicability of the departure provision?
6. The Commission recently promulgated an amendment that amends the definition of “crime of violence” in subsection (a) of § 4B1.2 (Definitions of Terms Used in Section 4B1.1), effective August 1, 2016 (to be published in a forthcoming edition of the
The proposed amendment would eliminate the use of the term “crime of violence” in § 2L1.2. In the event that the Commission does not promulgate the proposed amendment, and retains the term “crime of violence” in § 2L1.2, should the Commission incorporate all or part of the definition of “crime of violence” provided in the recently amended § 4B1.2 into § 2L1.2? If the Commission were to conform § 2L1.2 to the new definition in § 4B1.2(a), are there any particular offenses that would no longer qualify as a “crime of violence” but that nonetheless should receive an enhancement under subsection (b)(1) (
Veterans Health Administration, VA.
Notice of fund availability.
Funding Opportunity Title: Supportive Services for Veteran Families Program.
Announcement Type: Initial.
Funding Opportunity Number: VA–SSVF–011516.
Catalog of Federal Domestic Assistance Number: 64.033, VA Supportive Services for Veteran Families Program.
The Department of Veterans Affairs (VA) is announcing the availability of funds for supportive services grants under the Supportive Services for Veteran Families (SSVF) Program. This Notice of Fund Availability (NOFA) contains information concerning the SSVF Program, initial supportive services grant application processes, and the amount of funding available. Awards made for supportive services grants will fund operations beginning October 1, 2016.
Applications for supportive services grants under the SSVF Program must be received by the SSVF Program Office by 4:00 p.m. Eastern Time on February 5, 2016. In the interest of fairness to all competing applicants, this deadline is firm as to date and hour, and VA will treat as ineligible for consideration any application that is received after the deadline. Applicants should take this practice into account and make early submission of their materials to avoid any risk of loss of eligibility brought about by unanticipated delays, computer service outages, or other delivery-related problems.
For a Copy of the Application Package: Copies of the application can be downloaded directly from the SSVF Program Web site at:
Submission of Application Package: Applicants are strongly encouraged to submit applications electronically following instructions found at
Technical Assistance: Information regarding how to obtain technical assistance with the preparation of an initial supportive services grant application is available on the SSVF Program Web site at:
Mr. John Kuhn, Supportive Services for Veteran Families Program Office, National Center on Homelessness Among Veterans, 4100 Chester Avenue, Suite 201, Philadelphia, PA 19104;
A. Purpose: The SSVF Program's purpose is to provide supportive services grants to private non-profit organizations and consumer cooperatives, who will coordinate or provide supportive services to very low-income Veteran families who: (i) Are residing in permanent housing; (ii) are homeless and scheduled to become residents of permanent housing within a specified time period; or (iii) after exiting permanent housing within a specified time period, are seeking other housing that is responsive to such very low-income Veteran family's needs and preferences.
B. Funding Priorities: VA will provide up to $300 million for existing grantees seeking to renew their grants.
C. Definitions: Part 62 of title 38, Code of Federal Regulations (38 CFR part 62), contains definitions of terms used in the SSVF Program.
D. Approach: Respondents to this NOFA should base their proposals and applications on the current requirements of part 62. Grantees will be expected to leverage supportive services grant funds to enhance the housing stability of very low-income Veteran families who are occupying permanent housing. In doing so, grantees are required to establish relationships with local community resources. Therefore, agencies must work through coordinated partnerships built either through formal agreements or the informal working relationships commonly found amongst strong social service providers. The scoring criteria for grantees applying for renewal supportive services grants are at 38 CFR 62.24, which provides for points to be awarded based on the success of the grantee's program. As part of the application, all applicants are strongly encouraged to provide letters of support from their respective VA Network Homeless Coordinator (or their designee). In addition, applicants are strongly encouraged to provide letters of support from the Continuum of Care (CoC) where they plan to deliver services that reflect the applicant's engagement in the CoC's efforts to coordinate services. The CoC may elect to provide VA with a rank order of their support in lieu of providing individual letters of support. A CoC is a community plan to organize and deliver housing and services to meet the needs of people who are homeless as they move to stable housing and maximize self-sufficiency. It includes action steps to end homelessness and prevent a return to homelessness (CoC locations and contact information can be found at the Department of Housing and Urban Development's (HUD) Web site,
Assistance in obtaining or retaining permanent housing is a fundamental goal of the SSVF Program. Grantees must provide case management services in accordance with 38 CFR 62.31. Such case management should include tenant counseling, mediation with landlords and outreach to landlords.
E. Authority: Funding applied for under this NOFA is authorized by 38 U.S.C. 2044. VA implements the SSVF Program by regulation in 38 CFR part 62. Funds made available under this NOFA are subject to the requirements of the aforementioned regulations and other applicable laws and regulations.
F. Requirements for the Use of Supportive Services Grant Funds: The grantee's request for funding must be consistent with the limitations and uses of supportive services grant funds set forth in 38 CFR part 62 and this NOFA. In accordance with the regulations and this NOFA, the following requirements apply to supportive services grants awarded under this NOFA:
1. Grantees may use a maximum of 10 percent of supportive services grant funds for administrative costs identified in 38 CFR 62.70.
2. Grantees must use a minimum of 60 percent of the temporary financial assistance portion of their supportive services grant funds to serve very low-income Veteran families who qualify under 38 CFR 62.11(b). (NOTE: Grantees may request a waiver to decrease this minimum, as discussed in section V.B.3.a.)
3. Grantees may use a maximum of 50 percent of supportive services grant funds to provide the supportive service of temporary financial assistance paid directly to a third party on behalf of a participant for child care, emergency housing assistance, transportation, rental assistance, utility-fee payment assistance, security deposits, utility deposits, moving costs, and general housing stability assistance (which includes emergency supplies) in accordance with 38 CFR 62.33 and 38 CFR 62.34.
G. Guidance for the Use of Supportive Services Grant Funds: It is VA policy to support a “Housing First” model in
Grantees must develop plans that will ensure that Veteran participants have the level of income and economic stability needed to remain in permanent housing after the conclusion of the SSVF intervention. Both employment and benefits assistance from VA and non-VA sources represent a significant underutilized source of income stability for homeless Veterans. The complexity of program rules and the stigma some associate with entitlement programs contributes to their lack of use. To this effect, grantees are encouraged to consider strategies that can lead to prompt and successful access to employment and benefits that are essential to retaining housing.
1. Consistent with the Housing First model supported by VA, grantees are expected to offer the following supportive services: Housing counseling; assisting participants in understanding leases; securing utilities; making moving arrangements; providing representative payee services concerning rent and utilities when needed; and mediation and outreach to property owners related to locating or retaining housing. Grantees may also assist participants by providing rental assistance, security or utility deposits, moving costs or emergency supplies; or using other Federal resources, such as the HUD's ESG, or supportive services grant funds subject to the limitations described in this NOFA and 38 CFR 62.34.
2. As SSVF is a short-term crisis intervention, grantees must develop plans that will produce sufficient income to sustain Veteran participants in permanent housing after the conclusion of the SSVF intervention. Grantees must ensure the availability of employment and vocational services either through the direct provision of these services or their availability through formal or informal service agreements. Agreements with Homeless Veteran Reintegration Programs funded by the U.S. Department of Labor are strongly encouraged. For participants unable to work due to disability, income must be established through available benefits programs.
3. Per 38 CFR 62.33, grantees must assist participants in obtaining public benefits. Grantees must screen all participants for eligibility for a broad range of entitlements such as TANF, Social Security, the Supplemental Nutrition Assistance Program (SNAP), the Low Income Home Energy Assistance Program (LIHEAP), the Earned Income Tax Credit (EITC), and local General Assistance programs. Grantees are expected to access the Substance Abuse and Mental Health Services Administration's SSI/SSDI Outreach, Access, and Recovery (SOAR) program either though community linkages or by training staff to deliver SOAR services. In addition, where available grantees should access information technology tools to support case managers in their efforts to link participants to benefits.
4. Grantees are encouraged to provide, or assist participants in obtaining, legal services relevant to issues that interfere with the participants' ability to obtain or retain permanent housing. (
5. Access to mental health and addiction services are required by SSVF; however, grantees cannot fund these services directly through the SSVF grant. Therefore, applicants must demonstrate, through either formal or informal agreements, their ability to promote rapid access and engagement to mental health and addiction services for the Veteran and family members.
6. VA recognizes that extremely low-income Veterans, with incomes below 30 percent of the area median income, face greater barriers to permanent housing placement. Grantees should consider how they can support these participants.
7. When serving participants who are residing in permanent housing, the defining question to ask is: “Would this individual or family be homeless but for this assistance?” The grantee must use a VA-approved screening tool with criteria that targets those most at-risk of homelessness. To qualify for SSVF services, a participant who is served under 38 CFR 62.11(a) (homeless prevention) must not have sufficient resources or support networks (
(a) Has moved because of economic reasons two or more times during the 60 days immediately preceding the application for homelessness prevention assistance;
(b) Is living in the home of another because of economic hardship;
(c) Has been notified in writing that their right to occupy their current housing or living situation will be terminated within 21 days after the date of application for assistance;
(d) Lives in a hotel or motel and the cost of the hotel or motel stay is not paid by charitable organizations or by Federal, State, or local government programs for low-income individuals;
(e) Is exiting a publicly funded institution or system of care (such as a health care facility, a mental health facility, or correctional institution) without a stable housing plan; or
(f) Otherwise lives in housing that has characteristics associated with instability and an increased risk of homelessness, as identified in the recipient's approved screening tool.
8. SSVF grantees are required to participate in local planning efforts designed to end Veteran homelessness. Grantees may use grant funds to support SSVF involvement in such community planning by sub-contracting with CoCs, when such funding is essential to create or sustain the development of these data driven plans.
9. When other funds from community resources are not readily available to assist program participants, grantees may choose to utilize supportive services grants, to the extent described in this NOFA and in 38 CFR 62.33 and 62.34, to provide temporary financial
A. Overview: This NOFA announces the availability of funds for supportive services grants under the SSVF Program and pertains to proposals for renewal of existing supportive services grant programs. New applications for SSVF grant awards will not be funded through this NOFA. Up to $300 million will be available through this NOFA.
B. Funding: To be eligible for renewal of a supportive services grant, the grantee's program concept must be substantially the same with the program concept of the grantee's current grant award. Renewal applications can request funding that is equal to or less than their current award. If sufficient funding is available, VA may provide an increase of up to 2 percent from the previous year's award. Any percentage increase, if provided, will be awarded uniformly to all grant recipients regardless of their grant award. As provided in section V.5., VA may in its discretion offer to award a non-renewed grant to the highest-ranked applicant that is awarded a renewal grant in the same community as, or a proximate community to, the non-renewed grant, so long as that applicant has the capacity to promptly begin providing services in connection with all awards. In such instance, the amount of the award will be equal to or less than the prior award which was not renewed.
C. Allocation of Funds: Funding will be awarded under this NOFA to existing grantees for a 1- to 3-year period beginning October 1, 2016. The following requirements apply to supportive services grants awarded under this NOFA:
1. In response to this NOFA, only existing grantees can apply.
2. Each grant request cannot exceed the current award.
3. Applicants may request an amount less than their current award (this will not be considered a substantial change to the program concept).
4. If a grantee failed to use all of awarded funds in the previous fiscal year (2016), VA may elect to limit renewal award to the amount of funds used in the previous fiscal year.
5. Applicants should fill out separate applications for each supportive services renewal funding request.
D. Supportive Services Grant Award Period: Grant awards are generally made for a 1-year period, although selected grants may be eligible for a 3-year award (see VI.C.6). All grants are eligible to be renewed subject to the availability of funding.
A. Eligible Applicants: Only eligible entities that are existing grantees can apply in response to this NOFA. In order to be eligible, an applicant must qualify as a private non-profit organization (section 501(c)(3) or 501(c)(19) tax exempt status is required) or a consumer cooperative as defined in 38 U.S.C. 2044(f). In addition, tribally designated housing entities (as defined in section 4 of the Native American Housing Assistance and Self-Determination Act of 1996 (25 U.S.C. 4103)) are eligible.
B. Cost Sharing or Matching: None.
A. Address to Request Application Package: Download directly from the SSVF Program Web site at
B. Content and Form of Application: Applicants are strongly encouraged to submit applications electronically following instructions found at
C. Submission Dates and Times: Applications for supportive services grants under the SSVF Program must be received by the SSVF Program Office by 4:00 p.m. Eastern Time on February 5, 2016. Awards made for supportive services grants will fund operations beginning October 1, 2016. Applications must arrive as a complete package. Materials arriving separately will not be included in the application package for consideration and may result in the application being rejected. Additionally, in the interest of fairness to all competing applicants, this deadline is firm as to date and hour, and VA will treat as ineligible for consideration any application that is received after the deadline. Applicants should take this practice into account and make early submission of their materials to avoid any risk of loss of eligibility brought about by unanticipated delays, computer service outages, or other delivery-related problems.
D. Intergovernmental Review: This section is not applicable to the SSVF Program.
E. Funding Restrictions: Up to $300 million may be awarded depending on funding availability and subject to available appropriations for supportive services grants to be funded under this NOFA. Applicants should fill out separate applications for each supportive services funding request. Funding will be awarded under this NOFA to existing grantees for a 1- to 3-year period beginning October 1, 2016.
F. Other Submission Requirements:
1. Applicants may apply only as renewal applicants using the application designed for renewal grants.
2. At the discretion of VA, multiple grant proposals submitted by the same lead agency may be combined into a single grant award if the proposals provide services to contiguous areas. Any funds awarded pursuant to section V.5. will be combined into a single award.
3. Additional supportive services grant application requirements are specified in the application package. Submission of an incorrect or incomplete application package will result in the application being rejected during threshold review. The application packages must contain all required forms and certifications. Selections will be made based on criteria described in 38 CFR part 62 and this NOFA. Applicants and grantees will be notified of any additional information needed to confirm or clarify information provided in the application and the deadline by which to submit such information. Applicants are strongly encouraged to submit applications electronically. If mailed, applications and CDs must be submitted
A. Criteria:
1. VA will only score applicants that meet the following threshold requirements:
(a) The application is filed within the time period established in the NOFA, and any additional information or documentation requested by VA under 38 CFR 62.20(c) is provided within the time frame established by VA;
(b) The application is completed in all parts;
(c) The applicant is an eligible entity;
(d) The activities for which the supportive services grant is requested are eligible for funding under 38 CFR part 62;
(e) The applicant's proposed participants are eligible to receive supportive services under this part;
(f) The applicant agrees to comply with the requirements of 38 CFR part 62;
(g) The applicant does not have an outstanding obligation to the Federal Government that is in arrears and does not have an overdue or unsatisfactory response to an audit; and
(h) The applicant is not in default by failing to meet the requirements for any previous Federal assistance.
2. VA will use the following criteria to score grantees applying for renewal of a supportive services grant:
(a) VA will award up to 55 points based on the success of the grantee's program.
(b) VA will award up to 30 points based on the cost-effectiveness of the grantee's program.
(c) VA will award up to 15 points based on the extent to which the grantee's program complies with SSVF Program goals and requirements.
3. VA will use the following process to select applicants to receive supportive services grants: VA will score all applicants that meet the threshold requirements set forth in 38 CFR 62.21 using the scoring criteria set forth in 38 CFR 62.24.
B. Review and Selection Process: VA will review all supportive services renewal grant applications in response to this NOFA according to the following steps:
1. Score all applications that meet the threshold requirements described in 38 CFR 62.21.
2. Rank those applications who score at least 75 cumulative points and receive at least one point under each of the categories identified for renewal applicants in 38 CFR 62.24. The applications will be ranked in order from highest to lowest scores in accordance with 38 CFR 62.25.
3. Utilize the ranked scores of applications as the primary basis for selection. However, VA will also utilize the following considerations in 38 CFR 62.23(d) to select applicants for funding:
(a) Give preference to applications that provide or coordinate the provision of supportive services for very low-income Veteran families transitioning from homelessness to permanent housing. Consistent with this preference, where other funds from community resources are not readily available for temporary financial assistance, applicants are required to spend no less than 60 percent of all budgeted temporary financial assistance on participants occupying permanent housing as defined in 38 CFR 62.11(b)). Waivers to this 60 percent requirement may be requested when grantees can demonstrate significant local progress towards eliminating homelessness in the target service area. Waiver requests must include data from authoritative sources such as HUD's Annual Homeless Assessment Report, annual Point-In-Time Counts and evidence of decreased demand for emergency shelter and transitional housing. Waivers for the 60 percent requirement may also be requested for services provided to rural Indian tribal areas and other rural areas where shelter capacity is insufficient to meet local need. Waiver requests must include an endorsement by the impacted CoC explicitly stating that a shift in resources from rapid re-housing to prevention will not result in an increase in homelessness.
(b) To the extent practicable, ensure that supportive services grants are equitably distributed across geographic regions, including rural communities and tribal lands. This equitable distribution criteria will be used to ensure that SSVF resources are provided to those communities with the highest need as identified by authoritative sources such as HUD's Annual Homeless Assessment Report, annual Point-In-Time Counts and VA Homeless Registry data.
4. Subject to the considerations noted in paragraph B.3 above, VA will fund the highest-ranked applicants for which funding is available.
5. VA may in its discretion offer to award a non-renewed grant to the highest-ranked applicant that is awarded a renewal grant in the same community as, or a proximate community to, the non-renewed grant, so long as that applicant has the capacity to promptly begin providing services in connection with all awards. If that applicant declines the award, VA will offer the award to the next highest-ranked applicant and continue in that manner until a qualifying grantee accepts the award.
A. Award Notices: Although subject to change, the SSVF Program Office expects to announce grant recipients for all applicants in the fourth quarter of fiscal year 2016 with grants beginning October 1, 2016. Prior to executing a funding agreement, VA will contact the applicants and make known the amount of proposed funding and verify that the applicant would still like the funding. Once VA verifies that the applicant is still seeking funding, VA will execute an agreement and make payments to the grant recipient in accordance with 38 CFR part 62 and this NOFA.
B. Administrative and National Policy Requirements: It is VA policy to support a “Housing First” model in addressing and ending homelessness. Housing First establishes housing stability as the primary intervention in working with homeless persons. The Housing First approach is based on research that shows that a homeless individual or household's first and primary need is to obtain stable housing, and that other issues that may affect the household can and should be addressed as housing is obtained. Housing is not contingent on compliance with services; instead, participants must comply with a standard lease agreement and are provided with the services and supports that are necessary to help them do so successfully. Research supports this approach as an effective means to end homelessness.
Consistent with the Housing First model supported by VA, grantees are expected to offer the following supportive services: Housing counseling; assisting participants in understanding leases; securing utilities; making moving arrangements; providing representative payee services concerning rent and utilities when needed; and mediation and outreach to property owners related to locating or retaining housing. Grantees may also assist participants by providing rental assistance, security or utility deposits, moving costs or emergency supplies, using other Federal resources, such as the ESG, or supportive services grant funds to the extent described in this NOFA and 38 CFR 62.34.
As SSVF grants cannot be used to fund treatment for mental health or substance use disorders, applicants must provide evidence that they can provide access to such services to all program participants through formal and informal agreements with community providers.
C. Reporting: VA places great emphasis on the responsibility and accountability of grantees. As described in 38 CFR 62.63 and 62.71, VA has procedures in place to monitor supportive services provided to participants and outcomes associated with the supportive services provided under the SSVF Program. Applicants should be aware of the following:
1. Upon execution of a supportive services grant agreement with VA, grantees will have a VA regional coordinator assigned by the SSVF Program Office who will provide oversight and monitor supportive services provided to participants.
2. Grantees will be required to enter data into a Homeless Management Information System (HMIS) Web-based software application. This data will consist of information on the participants served and types of supportive services provided by grantees. Grantees must treat the data for activities funded by the SSVF Program separate from that of activities funded by other programs. Grantees will be required to work with their HMIS Administrators to export client-level data for activities funded by the SSVF Program to VA on at least a monthly basis.
3. VA shall complete annual monitoring evaluations of each grantee. Monitoring will also include the submittal of quarterly and annual financial and performance reports by the grantee. The grantee will be expected to demonstrate adherence to the grantee's proposed program concept, as described in the grantee's application. All grantees are subject to audits conducted by the VA Financial Services Center.
4. Grantees will be required to provide each participant with a satisfaction survey which can be submitted by the participant directly to VA within 30 days of such participant's pending exit from the grantee's program.
5. Grantees will be assessed based on their ability to meet critical performance measures. In addition to meeting program requirements defined by the regulations and applicable NOFA(s), grantees will be assessed on their ability to place participants into housing and the housing retention rates of participants served. Higher placement for homeless participants and higher housing retention rates for at-risk participants are expected for very-low income Veteran families when compared to extremely low-income Veteran families with incomes below 30 percent of the area median income.
6. Organizations receiving renewal awards and that have had ongoing SSVF program operation for at least 1 year (as measured from the start of initial SSVF services until January 16, 2016) may be eligible for a 3-year award. Grantees meeting outcome goals defined by VA and in substantial compliance with their grant agreements (defined by meeting targets and having no outstanding corrective action plans) and who, in addition, receive 3-year accreditation from the Commission on Accreditation of Rehabilitation Facilities (CARF) in Employment and Community Services: Rapid Rehousing and Homeless Prevention standards or a 4-year accreditation from the Council on Accreditation's (COA) accreditation in Supported Community Living Services standards are eligible for a 3-year grant renewal subject to funding availability (NOTE: Multi-year awards are contingent on funding availability). If awarded a multiple year renewal, grantees may be eligible for funding increases as defined in NOFAs that correspond to years 2 and 3 of their renewal funding.
John Kuhn, Supportive SSVF Program Office, National Center on Homelessness Among Veterans, 4100 Chester Avenue, Suite 201, Philadelphia, PA 19104; (877) 737–0111 (this is a toll-free number);
A. VA Goals and Objectives for Funds Awarded Under this NOFA: In accordance with 38 CFR 62.24(c), VA will evaluate an applicant's compliance with VA goals and requirements for the SSVF Program. VA goals and requirements include the provision of supportive services designed to enhance the housing stability and independent living skills of very low-income Veteran families occupying permanent housing across geographic regions and program administration in accordance with all applicable laws, regulations, and guidelines. For purposes of this NOFA, VA goals and requirements also include the provision of supportive services designed to rapidly re-house or prevent homelessness among people in the following target populations who also meet all requirements for being part of a very low-income Veteran family occupying permanent housing:
1. Veteran families earning less than 30 percent of area median income as most recently published by HUD for programs under section 8 of the United States Housing Act of 1937 (42 U.S.C. 1437f) (
2. Veterans with at least one dependent family member.
3. Veterans returning from Operation Enduring Freedom, Operation Iraqi Freedom, or Operation New Dawn.
4. Veteran families located in a community, as defined by HUD's CoC, or a county not currently served by a SSVF grantee.
5. Veteran families located in a community, as defined by HUD's CoC, where current level of SSVF services is not sufficient to meet demand of Category 2 and 3 (currently homeless) Veteran families.
6. Veteran families located in a rural area.
7. Veteran families located on Indian Tribal Property.
B. Payments of Supportive Services Grant Funds: Grantees will receive payments electronically through the U.S. Department of Health and Human Services Payment Management System. Grantees will have the ability to request payments as frequently as they choose subject to the following limitations:
1. During the first quarter of the grantee's supportive services annualized grant award period, the grantee's cumulative requests for supportive services grant funds may not exceed 35 percent of the total supportive services grant award without written approval by VA.
2. By the end of the second quarter of the grantee's supportive services annualized grant award period, the grantee's cumulative requests for supportive services grant funds may not exceed 60 percent of the total supportive services grant award without written approval by VA.
3. By the end of the third quarter of the grantee's supportive services annualized grant award period, the grantee's cumulative requests for supportive services grant funds may not exceed 80 percent of the total supportive services grant award without written approval by VA.
4. By the end of the fourth quarter of the grantee's supportive services annualized grant award period, the grantee's cumulative requests for supportive services grant funds may not exceed 100 percent of the total supportive services grant award.
The Secretary of Veterans Affairs, or designee, approved this document and authorized the undersigned to sign and
Office of Energy Efficiency and Renewable Energy, Department of Energy.
Final rule.
The Energy Policy and Conservation Act of 1975 (EPCA), as amended, prescribes energy conservation standards for various consumer products and certain commercial and industrial equipment, including residential boilers. EPCA also requires the U.S. Department of Energy (DOE) to periodically determine whether more-stringent, amended standards would be technologically feasible and economically justified, and would save a significant amount of energy. In this final rule, DOE is adopting more-stringent energy conservation standards for residential boilers. It has determined that the amended energy conservation standards for these products would result in significant conservation of energy, and are technologically feasible and economically justified.
The effective date of this rule is March 15, 2016. Compliance with the amended standards established for residential boilers in this final rule is required on and after January 15, 2021.
The docket for this rulemaking, which includes
A link to the docket Web page can be found at:
For further information on how to review the docket, contact Ms. Brenda Edwards at (202) 586–2945 or by email:
Mr. John Cymbalsky, U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Building Technologies Office, EE–5B, 1000 Independence Avenue SW., Washington, DC 20585–0121. Telephone: (202) 287–1692. Email:
Mr. Eric Stas, U.S. Department of Energy, Office of the General Counsel, GC–33, 1000 Independence Avenue SW., Washington, DC 20585–0121. Telephone: (202) 586–9507. Email:
Title III, Part B
Pursuant to EPCA, any new or amended energy conservation standard must be designed to achieve the maximum improvement in energy efficiency that DOE determines is technologically feasible and economically justified. (42 U.S.C. 6295(o)(2)(A)) Furthermore, the new or amended standard must result in a significant conservation of energy. (42 U.S.C. 6295(o)(3)(B)) EPCA specifically provides that DOE must conduct a second round of energy conservation standards rulemaking for residential boilers. (42 U.S.C. 6295(f)(4)(C)) The statute also provides that not later than 6 years after issuance of any final rule establishing or amending a standard, DOE must publish either a notice of determination that standards for the product do not need to be amended, or a notice of proposed rulemaking including new proposed energy conservation standards (proceeding to a final rule, as appropriate). (42 U.S.C. 6295(m)) DOE initiated this rulemaking as required by 42 U.S.C. 6295(f)(4)(C), but once complete, this rulemaking will also satisfy the 6-year review provision under 42 U.S.C. 6295(m).
Furthermore, EISA 2007 amended EPCA to require that any new or amended energy conservation standard adopted after July 1, 2010, shall address standby mode and off mode energy consumption pursuant to 42 U.S.C. 6295(o). (42 U.S.C. 6295(gg)(3)) If feasible, the statute directs DOE to incorporate standby mode and off mode energy consumption into a single standard with the product's active mode energy use. If a single standard is not feasible, DOE may consider establishing a separate standard to regulate standby mode and off mode energy consumption.
In accordance with these and other statutory provisions discussed in this document, DOE is adopting amended annual fuel utilization efficiency (AFUE) energy conservation standards and adopting new standby mode off mode electrical energy conservation standards for residential boilers. The AFUE standards for residential boilers are expressed as minimum AFUE, as determined by the DOE test method (described in section III.B), and are shown in Table I.1, as are the design requirements. Table I.2 shows the standards for standby mode and off mode. These standards apply to all residential boilers listed in Table I.1 and Table I.2 and manufactured in, or imported into, the United States starting on the date five years after January 15, 2021.
Table I.3 presents DOE's evaluation of the economic impacts of the adopted AFUE and standby mode and off mode standards on consumers of residential boilers, as measured by the average life-cycle cost (LCC) savings and the simple payback period (PBP).
Estimates of the combined impact of the adopted AFUE and standby mode and off mode standards on consumers are shown in Table I.5.
DOE's analysis of the impacts of the adopted standards on consumers is described in section IV.F of this document.
The industry net present value (INPV) is the sum of the discounted cash flows to the industry from the base year through the end of the analysis period (2014 to 2050). Using a real discount rate of 8.0 percent, DOE estimates that the (INPV) for manufacturers of residential boilers in the base case without amended standards is $367.83 million in 2014$.
DOE analyzed the impacts of AFUE energy conservation standards and standby/off mode electrical energy consumption energy conservation standards on manufacturers separately. Under the adopted AFUE standards, DOE expects that the change in INPV will range from −0.71 to 0.44 percent, which is approximately equivalent to a reduction of −$2.63 million to an increase of $1.62 million. DOE estimates industry conversion costs from the amended AFUE standards to total $2.27 million.
Under the adopted standby mode and off mode standards, DOE expects the change in INPV will range from −0.46 to 0.12 percent, which is approximately equivalent to a decrease of $1.71 million to an increase of $0.45 million. DOE estimates industry conversion costs from the standby mode and off mode standards to total $0.21 million.
DOE's analysis of the impacts of the adopted standards on manufacturers is described in section IV.J of this final rule.
DOE's analyses indicate that the adopted AFUE energy conservation standards for residential boilers are expected to save a significant amount of energy. Relative to the case without amended standards, the lifetime energy savings for residential boilers purchased in the 30-year period that begins in the first full year of compliance with the amended standards (2021–2050) amount to 0.16 quadrillion Btu (quads).
The cumulative net present value (NPV) of total consumer costs and savings for the amended residential boilers AFUE standards ranges from $0.35 billion to $1.20 billion at 7-percent and 3-percent discount rates, respectively. This NPV expresses the estimated total value of future operating-cost savings minus the estimated increased product costs for residential boilers purchased in 2021–2050.
In addition, the amended AFUE standards for residential boilers are expected to have significant environmental benefits. DOE estimates that the AFUE standards would result in cumulative emission reductions (over the same period as for energy savings) of 9.33 million metric tons (Mt)
The value of the CO
Table I.6 summarizes the national economic benefits and costs expected to result from the adopted AFUE standards for residential boilers.
For the adopted standby mode and off mode standards, the lifetime energy savings for residential boilers purchased in the 30-year period that begins in the first full year of compliance with amended standards (2021–2050) amount to 0.0026 quads. This is a savings of 1.2 percent relative to the standby energy use of these products in the no-new-standards case.
The cumulative NPV of total consumer costs and savings for the adopted standby mode and off mode standards for residential boilers ranges from $0.003 billion to $0.014 billion at 7-percent and 3-percent discount rates, respectively. This NPV expresses the estimated total value of future operating-cost savings minus the estimated increased product costs for residential boilers purchased in 2021–2050.
In addition, the standby mode and off mode standards are expected to have significant environmental benefits. The energy savings are expected to result in cumulative emission reductions (over the same period as for energy savings) of 0.154 Mt of CO
As noted above, the value of the CO
Table I.7 summarizes the national economic benefits and costs expected to result from the adopted standby mode and off mode standards for residential boilers.
The benefits and costs of the adopted energy conservation standards, for residential boiler products sold in 2021–2050, can also be expressed in terms of annualized values. Benefits and costs for the AFUE standards are considered separately from benefits and costs for the standby mode and off mode electrical consumption standards, because for the reasons explained in section I.D below, it was not technically feasible to develop a single, integrated standard. The monetary values for the total annualized net benefits are the sum of: (1) The national economic value of the benefits in reduced consumer operating cost, minus (2) the increases in product purchase price and installation costs, plus (3) the value of the benefits of CO
Although the value of operating cost savings and CO
Estimates of annualized benefits and costs of the adopted AFUE standards for residential boilers are shown in Table I.8.
The results under the primary estimate are as follows. Using a 7-percent discount rate for benefits and costs other than CO
Estimates of annualized benefits and costs of the adopted standby mode and off mode standards are shown in Table I.9. The results under the primary estimate are as follows. Using a 7-percent discount rate for benefits and costs other than CO
DOE's analysis of the national impacts of the adopted standards is described in sections IV.H, IV.K, and IV.L of this notice.
Based on the analyses culminating in this final rule, DOE found the benefits to the Nation of the standards (energy savings, positive NPV of consumer benefits, consumer LCC savings, and emission reductions) for both AFUE as well as standby mode and off would outweigh the burdens (loss of INPV for manufacturers and LCC increases for some consumers). DOE has concluded that the standards in this final rule represent the maximum improvement in energy efficiency that is technologically feasible and economically justified, and would result in significant conservation of energy.
DOE also added the annualized benefits and costs from the individual annualized tables to provide a combined benefit and cost estimate of the adopted AFUE and standby mode and off mode standards, as shown in Table I.10.
As discussed in section II.A of this final rule, any final rule for amended or new energy conservation standards that is published on or after July 1, 2010 must address standby mode and off mode energy use. (42 U.S.C. 6295(gg)(3)) As a result, DOE has analyzed and is adopting new energy conservation standards for the standby mode and off mode electrical energy consumption of residential boilers.
AFUE, the statutory metric for residential boilers, does not incorporate standby mode or off mode use of electricity, although it already fully addresses use in these modes of fossil fuels by gas-fired and oil-fired boilers. In the October 2010 test procedure final rule for residential furnaces and boilers, DOE determined that incorporating standby mode and off mode electricity consumption into a single standard for residential furnaces and boilers is not technically feasible. 75 FR 64621, 64626–27 (Oct. 20, 2010). DOE concluded that a metric that integrates standby mode and off mode electricity consumption into AFUE is not technically feasible, because the standby mode and off mode energy usage, when measured, is essentially lost in practical terms due to rounding conventions for certifying furnace and boiler compliance with Federal energy conservation standards.
DOE is using the metrics just described—AFUE, P
The following section briefly discusses the statutory authority underlying this final rule, as well as some of the relevant historical background related to the establishment of standards for residential boilers.
Title III, Part B of the Energy Policy and Conservation Act of 1975 (EPCA or the Act), Pub. L. 94–163 (codified as 42 U.S.C. 6291–6309) established the Energy Conservation Program for Consumer Products Other Than Automobiles, a program covering most major household appliances (collectively referred to as “covered products”). These products include the residential boilers that are the subject of this rulemaking. (42 U.S.C. 6292(a)(5)) EPCA, as amended, prescribed energy conservation standards for these products (42 U.S.C. 6295(f)(1) and (3)), and directed DOE to conduct future rulemakings to determine whether to amend these standards (42 U.S.C. 6295(f)(4)). Under 42 U.S.C. 6295(m), the agency must periodically review its already-established energy conservation standards for a covered product no later than 6 years from the issuance of a final rule establishing or amending a standard for a covered product. This rulemaking satisfies both statutory provisions (42 U.S.C. 6295(f)(4) and (m)).
Pursuant to EPCA, DOE's energy conservation program for covered products consists essentially of four parts: (1) Testing; (2) labeling; (3) establishment of Federal energy conservation standards; and (4) certification and enforcement procedures. The Federal Trade Commission (FTC) is primarily responsible for labeling, and DOE implements the remainder of the program. Subject to certain criteria and conditions, DOE is required to develop test procedures to measure the energy efficiency, energy use, or estimated annual operating cost of each covered product. (42 U.S.C. 6295(o)(3)(A) and (r)) Manufacturers of covered products must use the prescribed DOE test procedure as the basis for certifying to DOE that their products comply with the applicable energy conservation standards adopted under EPCA and when making representations to the public regarding the energy use or efficiency of those products. (42 U.S.C. 6293(c) and 6295(s)) Similarly, DOE must use these test procedures to determine whether the products comply with standards adopted pursuant to EPCA. (42 U.S.C. 6295(s)) The DOE test procedure for residential boilers appears at title 10 of the Code of Federal Regulations (CFR) part 430, subpart B, appendix N. In 2012, DOE initiated a rulemaking to review the residential furnaces and boilers test procedure. In March 2015, DOE published a notice of proposed rulemaking (NOPR) outlining the proposed changes to the test procedure. 80 FR 12876 (March 11, 2015). In January 2016, DOE published a final rule outlining the final changes made to the test procedure. (See EERE–2012–BT–TP–0024). Details regarding this rulemaking are discussed in section III.B.
DOE must follow specific statutory criteria for prescribing new or amended standards for covered products, including residential boilers. Any new or amended standard for a covered product must be designed to achieve the maximum improvement in energy efficiency that is technologically feasible and economically justified. (42 U.S.C. 6295(o)(2)(A) and (3)(B)) Furthermore, DOE may not adopt any standard that would not result in the significant conservation of energy. (42 U.S.C. 6295(o)(3)) Moreover, DOE may not prescribe a standard: (1) For certain products, including residential boilers, if no test procedure has been established for the product, or (2) if DOE determines by rule that the standard is not technologically feasible or economically justified. (42 U.S.C. 6295(o)(3)(A)–(B)) In deciding whether a proposed standard is economically justified, after receiving comments on the proposed standard, DOE must determine whether the benefits of the standard exceed its burdens. (42 U.S.C. 6295(o)(2)(B)(i)) DOE must make this determination by, to the greatest extent practicable, considering the following seven statutory factors:
(1) The economic impact of the standard on manufacturers and consumers of the products subject to the standard;
(2) The savings in operating costs throughout the estimated average life of the covered products in the type (or class) compared to any increase in the price, initial charges, or maintenance expenses for the covered products that are likely to result from the standard;
(3) The total projected amount of energy (or as applicable, water) savings likely to result directly from the standard;
(4) Any lessening of the utility or the performance of the covered products likely to result from the standard;
(5) The impact of any lessening of competition, as determined in writing by the Attorney General, that is likely to result from the standard;
(6) The need for national energy and water conservation; and
(7) Other factors the Secretary of Energy (Secretary) considers relevant. (42 U.S.C. 6295(o)(2)(B)(i)(I)–(VII))
Further, EPCA, as codified, establishes a rebuttable presumption that a standard is economically justified if the Secretary finds that the additional cost to the consumer of purchasing a product complying with an energy conservation standard level will be less than three times the value of the energy savings during the first year that the consumer will receive as a result of the standard, as calculated under the applicable test procedure. (42 U.S.C. 6295(o)(2)(B)(iii))
EPCA, as codified, also contains what is known as an “anti-backsliding” provision, which prevents the Secretary from prescribing any amended standard that either increases the maximum allowable energy use or decreases the minimum required energy efficiency of a covered product. (42 U.S.C. 6295(o)(1)) Also, the Secretary may not prescribe an amended or new standard if interested persons have established by
Additionally, EPCA specifies requirements when promulgating an energy conservation standard for a covered product that has two or more subcategories. DOE must specify a different standard level for a type or class of product that has the same function or intended use, if DOE determines that products within such group: (A) Consume a different kind of energy from that consumed by other covered products within such type (or class); or (B) have a capacity or other performance-related feature that other products within such type (or class) do not have and such feature justifies a higher or lower standard. (42 U.S.C. 6295(q)(1)) In determining whether a performance-related feature justifies a different standard for a group of products, DOE must consider such factors as the utility to the consumer of such a feature and other factors DOE deems appropriate.
Federal energy conservation requirements generally supersede State laws or regulations concerning energy conservation testing, labeling, and standards. (42 U.S.C. 6297(a)–(c)) DOE may, however, grant waivers of Federal preemption for particular State laws or regulations, in accordance with the procedures and other provisions set forth under 42 U.S.C. 6297(d).
Finally, pursuant to the amendments contained in the Energy Independence and Security Act of 2007 (EISA 2007), Pub. L. 110–140, any final rule for new or amended energy conservation standards promulgated after July 1, 2010, is required to address standby mode and off mode energy use. (42 U.S.C. 6295(gg)(3)) Specifically, when DOE adopts a standard for a covered product after that date, it must, if justified by the criteria for adoption of standards under EPCA (42 U.S.C. 6295(o)), incorporate standby mode and off mode energy use into a single standard, or, if that is not feasible, adopt a separate standard for such energy use for that product. (42 U.S.C. 6295(gg)(3)(A)–(B)). DOE's current test procedures for residential boilers address standby mode and off mode energy use. In this rulemaking, DOE adopts separate energy conservation standards to address standby mode and off mode energy use.
In a final rule published on July 28, 2008 (2008 final rule), DOE prescribed energy conservation standards for residential boilers manufactured on or after September 1, 2012. 73 FR 43611. These standards are set forth in DOE's regulations at 10 CFR 430.32(e)(2)(ii) and are repeated in Table II.1 below.
Given the somewhat complicated interplay of recent DOE rulemakings and statutory provisions related to residential boilers, DOE provides the following regulatory history as background leading to the present rulemaking. On November 19, 2007, DOE published a final rule in the
Only July 15, 2008, DOE issued a final rule technical amendment to the 2007 final rule, which was published in the
DOE initiated this rulemaking pursuant to 42 U.S.C. 6295(f)(4)(C), which requires DOE to conduct a second round of amended standards rulemaking for residential boilers. EPCA, as amended by EISA 2007, also
Furthermore, EISA 2007 amended EPCA to require that any new or amended energy conservation standard adopted after July 1, 2010, shall address standby mode and off mode energy consumption pursuant to 42 U.S.C. 6295(o). (42 U.S.C. 6295(gg)(3)) If feasible, the statute directs DOE to incorporate standby mode and off mode energy consumption into a single standard with the product's active mode energy use. If a single standard is not feasible, DOE may consider establishing a separate standard to regulate standby mode and off mode energy consumption. Consequently, DOE considered standby mode and off mode energy use as part of this rulemaking for residential boilers.
DOE initiated this current rulemaking by issuing an analytical Framework Document, “Rulemaking Framework for Residential Boilers” (February 11, 2013). DOE published the notice of public meeting and availability of the Framework Document for residential boilers in the
The Framework Document explained the issues, analyses, and process that DOE anticipated using to develop energy conservation standards for residential boilers. DOE held a public meeting on March 13, 2013, to solicit comments from interested parties regarding DOE's analytical approach. The comment period for the Framework Document closed on March 28, 2013.
To further develop the energy conservation standards for residential boilers, DOE gathered additional information and performed an initial technical analysis. This process culminated in publication in the
A PDF copy of the supporting documentation is available at
On March 31, 2015, DOE published a notice of proposed rulemaking in the
In the March 2015 NOPR, DOE identified twenty four issues on which it was particularly interested in receiving comments and views of interested parties. 80 FR 17222, 17303–17304 (March 31, 2015). The comment period was initially set to end June 1, 2015, but it was subsequently extended to July 1, 2015 in a
The NOPR TSD described in detail DOE's analysis of potential standard levels for residential boilers. The document also described the analytical framework used in considering standard levels, including a description of the methodology, the analytical tools, and the relationships between the various analyses. In addition, the NOPR TSD presented each analysis that DOE performed to evaluate residential boilers, including descriptions of inputs, sources, methodologies, and results. DOE included the same analyses that were conducted at the preliminary analysis stage, with revisions based on comments received and additional research.
Statements received after publication of the Framework Document, at the Framework public meeting, and comments received after the publication of the NODA and NOPR have helped identify issues involved in this rulemaking and have provided information that has contributed to DOE's resolution of these issues. The Department considered these statements and comments in developing revised engineering and other analyses for this final rule.
DOE developed this final rule after considering verbal and written comments, data, and information from interested parties that represent a variety of interests. The following discussion addresses issues raised by these commenters.
DOE received 21 comments in response to the March 2015 NOPR. These commenters include: A joint comment from the American Council for an Energy-Efficient Economy (ACEEE), the Appliance Standards Awareness Project (ASAP), the Alliance to Save Energy (ASE), the Consumer Federation of America (CFA), the National Consumer Law Center (NCLC), the Natural Resources Defense Council (NRDC), and the Northeast Energy Efficiency Partnerships (NEEP); four comments from the Air-Conditioning, Heating, and Refrigeration Institute (AHRI); a comment from the Air Conditioning Contractors of America (ACCA); a comment from the Plumbing-Heating-Cooling Contractors National Association (PHCC); a comment from U.S. Chamber of Commerce; a comment from the Cato Institute; a comment from Oilheat Manufacturers Association; a comment from Exquisite Heat; and an anonymous comment. Manufacturers submitting written comments include: Energy Kinetics, Weil-McLain, Burnham
When evaluating and establishing energy conservation standards, DOE divides covered products into product classes by the type of energy used or by capacity or other performance-related features that justify differing standards. In making a determination whether a performance-related feature justifies a different standard, DOE must consider such factors as the utility of the feature to the consumer and other factors DOE determines are appropriate. (42 U.S.C. 6295(q))
Existing energy conservation standards divide residential boilers into six product classes based on the fuel type (
The scope and product classes analyzed for this final rule are the same as those initially set forth in the Framework Document and examined in DOE's initial analysis, as well as what was proposed in the NOPR. Comments received relating to the scope of coverage are described in section IV.A of this final rule.
DOE's current energy conservation standards for residential boilers are expressed in terms of AFUE (
On October 20, 2010, DOE updated its test procedures for residential boilers in a final rule published in the
On July 10, 2013, DOE published a final rule in the
EPCA, as amended by EISA 2007, requires that DOE must review test procedures for all covered products at least once every 7 years. (42 U.S.C 6293(b)(1)(A)) Accordingly, on March 11, 2015, DOE published a NOPR for the test procedure in the
• Clarifying the definition of the electrical power term PE;
• Adopting a smoke stick test for determining the use of minimum default draft factors;
• Allowing for the measurement of condensate under steady-state conditions;
• Referencing the manufacturer's installation and operations (I&O) manual and providing clarification if the I&O manual does not specify test set up;
• Specifying ductwork for units installed without a return duct;
• Specifying testing requirements for units with multiposition configurations; and
• Revising the required reporting precision for AFUE.
• Adopting a verification method for determining whether a boiler incorporates an automatic means for adjusting water temperature and whether this design requirement functions as required.
DOE received several comments from stakeholders relating to the residential furnace and boiler test procedure. These comments were considered and addressed in that rulemaking proceeding.
In each energy conservation standards rulemaking, DOE conducts a screening analysis based on information gathered on all current technology options and prototype designs that could improve the efficiency of the products or equipment that are the subject of the rulemaking. As the first step in such an analysis, DOE develops a list of technology options for consideration in consultation with manufacturers, design engineers, and other interested parties. DOE then determines which of those means for improving efficiency are technologically feasible. DOE considers technologies incorporated in commercially-available products or in working prototypes to be technologically feasible. 10 CFR part 430, subpart C, appendix A, section 4(a)(4)(i).
After DOE has determined that particular technology options are technologically feasible, it further evaluates each technology option in light of the following additional screening criteria: (1) Practicability to manufacture, install, and service; (2) adverse impacts on product utility or availability; and (3) adverse impacts on health or safety. 10 CFR part 430, subpart C, appendix A, section 4(a)(4)(ii)–(iv). Additionally, it is DOE policy not to include in its analysis any proprietary technology that is a unique pathway to achieving a certain efficiency level. Section IV.B of this notice discusses the results of the screening analysis for residential boilers, particularly the designs DOE considered, those it screened out, and those that are the basis for the standards in this rulemaking. For further details on the screening analysis for this rulemaking, see chapter 4 of the final rule technical support document (TSD).
When DOE proposes to adopt an amended standard for a type or class of covered product, it must determine the maximum improvement in energy efficiency or maximum reduction in energy use that is technologically feasible for such product. (42 U.S.C. 6295(p)(1)) Accordingly, in the engineering analysis, DOE determined the maximum technologically feasible (“max-tech”) improvements in energy efficiency for residential boilers, using the design parameters for the most efficient products available on the market or in working prototypes. The max-tech levels that DOE determined for this rulemaking are described in section IV.C of this final rule and in chapter 5 of the final rule TSD.
For each trial standard level (TSL), DOE projected energy savings from application of the TSL to residential boilers purchased in the 30-year period that begins in the year of compliance with any amended standards (2021–2050).
DOE used its national impact analysis (NIA) spreadsheet model to estimate national energy savings (NES) from potential amended standards for residential boilers. The NIA spreadsheet model (described in section IV.H of this final rule) calculates energy savings in terms of site energy, which is the energy directly consumed by products at the locations where they are used. For electricity, DOE calculates NES on an annual basis in terms of primary energy
In addition to primary energy savings, DOE also calculates full-fuel-cycle (FFC) energy savings. As discussed in DOE's statement of policy and notice of policy amendment, the FFC metric includes the energy consumed in extracting, processing, and transporting primary fuels (
To adopt standards for a covered product, DOE must determine that such action would result in “significant” energy savings. (42 U.S.C. 6295(o)(3)(B)) Although the term “significant” is not defined in the Act, the U.S. Court of Appeals for the District of Columbia Circuit, in
As noted above, EPCA provides seven factors to be evaluated in determining whether a potential energy conservation standard is economically justified. (42 U.S.C. 6295(o)(2)(B)(i)(I)–(VII)) The following sections discuss how DOE has addressed each of those seven factors in this rulemaking.
In determining the impacts of a potential amended standard on manufacturers, DOE conducts a manufacturer impact analysis (MIA), as discussed in section IV.J. DOE first uses an annual cash-flow approach to determine the quantitative impacts. This step includes both a short-term assessment—based on the cost and capital requirements during the period between when a regulation is issued and when entities must comply with the regulation—and a long-term assessment over a 30-year period. The industry-wide impacts analyzed include: (1) Industry net present value (INPV), which values the industry on the basis of expected future cash flows; (2) cash flows by year; (3) changes in revenue and income; and (4) other measures of impact, as appropriate. Second, DOE analyzes and reports the impacts on different types of manufacturers, including impacts on small manufacturers. Third, DOE considers the impact of standards on domestic manufacturer employment and manufacturing capacity, as well as the potential for standards to result in plant closures and loss of capital investment. Finally, DOE takes into account cumulative impacts of various DOE regulations and other regulatory requirements on manufacturers.
For individual consumers, measures of economic impact include the changes in LCC and PBP associated with new or amended standards. These measures are discussed further in the following section. For consumers in the aggregate, DOE also calculates the national net present value of the economic impacts applicable to a particular rulemaking. DOE also evaluates the LCC impacts of potential standards on identifiable subgroups of consumers that may be affected disproportionately by a national standard.
EPCA requires DOE to consider the savings in operating costs throughout the estimated average life of the covered product in the type (or class) compared to any increase in the price of, or in the initial charges for, or maintenance expenses of, the covered product that are likely to result from a standard. (42 U.S.C. 6295(o)(2)(B)(i)(II)) DOE conducts this comparison in its LCC and PBP analysis.
The LCC is the sum of the purchase price of a product (including its installation) and the operating cost (including energy, maintenance, and repair expenditures) discounted over the lifetime of the product. The LCC analysis requires a variety of inputs, such as product prices, product energy consumption, energy prices, maintenance and repair costs, product lifetime, and discount rates appropriate for consumers. To account for uncertainty and variability in specific inputs, such as product lifetime and discount rate, DOE uses a distribution of values, with probabilities attached to each value.
The PBP is the estimated amount of time (in years) it takes consumers to recover the increased purchase cost (including installation) of a more-efficient product through lower operating costs. DOE calculates the PBP by dividing the change in purchase cost due to a more-stringent standard by the change in annual operating cost for the year that standards are assumed to take effect.
For its LCC and PBP analysis, DOE assumes that consumers will purchase the covered products in the first year of compliance with amended standards. The LCC savings for the considered efficiency levels are calculated relative to the case that reflects projected market trends in the absence of amended standards. DOE's LCC and PBP analysis is discussed in further detail in section IV.F.
Although significant conservation of energy is a separate statutory requirement for adopting an energy conservation standard, EPCA requires DOE, in determining the economic justification of a standard, to consider the total projected energy savings that are expected to result directly from the standard. (42 U.S.C. 6295(o)(2)(B)(i)(III)) As discussed in section IV.H, DOE uses the NIA spreadsheet model to project national energy savings.
In establishing product classes and in evaluating design options and the impact of potential standard levels, DOE evaluates potential standards that would not lessen the utility or performance of the considered products. (42 U.S.C. 6295(o)(2)(B)(i)(IV)) Based on data available to DOE, the standards adopted in this final rule will not reduce the utility or performance of the products under consideration in this rulemaking.
EPCA directs DOE to consider the impact of any lessening of competition, as determined in writing by the Attorney General, that is likely to result from a standard. (42 U.S.C. 6295(o)(2)(B)(i)(V)) It also directs the Attorney General to determine the impact, if any, of any lessening of competition likely to result from a standard and to transmit such determination to the Secretary within 60 days of the publication of a proposed rule, together with an analysis of the nature and extent of the impact. (42 U.S.C. 6295(o)(2)(B)(ii)) To assist the Department of Justice (DOJ) in making such a determination, DOE transmitted copies of both its proposed rule and NOPR TSD to the Attorney General for review, with a request that DOJ provide its determination on this issue. In its assessment letter responding to DOE, DOJ concluded that the proposed energy conservation standards for residential boilers are unlikely to have a significant adverse impact on competition. DOE is publishing the Attorney General's assessment at the end of this final rule.
DOE also considers the need for national energy conservation in determining whether a new or amended standard is economically justified. (42 U.S.C. 6295(o)(2)(B)(i)(VI)) The energy savings from the adopted standards are likely to provide improvements to the security and reliability of the nation's energy system. Reductions in the demand for electricity also may result in reduced costs for maintaining the reliability of the nation's electricity system. DOE conducts a utility impact analysis to estimate how standards may affect the nation's needed power generation capacity, as discussed in section IV.M.
The adopted standards also are likely to result in environmental benefits in the form of reduced emissions of air pollutants and greenhouse gases associated with energy production and use. DOE conducts an emissions impacts analysis to estimate how potential standards may affect these emissions, as discussed in section IV.K; the emissions impacts are reported in section V.B.6 of this final rule. DOE also estimates the economic value of emissions reductions resulting from the considered TSLs, as discussed in section IV.L.
EPCA allows the Secretary of Energy, in determining whether a standard is economically justified, to consider any other factors that the Secretary deems to be relevant. (42 U.S.C. 6295(o)(2)(B)(i)(VII)) To the extent interested parties submit any relevant information regarding economic justification that does not fit into the other categories described above, DOE could consider such information under “other factors.” For this final rule, DOE did not consider other factors.
As set forth in 42 U.S.C. 6295(o)(2)(B)(iii), EPCA creates a rebuttable presumption that an energy conservation standard is economically justified if the additional cost to the consumer of a product that meets the standard is less than three times the value of the first year's energy savings resulting from the standard, as calculated under the applicable DOE test procedure. DOE's LCC and PBP analyses generate values used to calculate the effect potential amended energy conservation standards would have on the payback period for consumers. These analyses include, but are not limited to, the 3-year payback period contemplated under the rebuttable-presumption test. In addition, DOE routinely conducts an economic analysis that considers the full range of impacts to consumers, manufacturers, the Nation, and the environment, as required under 42 U.S.C. 6295(o)(2)(B)(i). The results of this analysis serve as the basis for DOE's evaluation of the economic justification for a potential standard level (thereby supporting or rebutting the results of any preliminary determination of economic justification). The rebuttable presumption payback calculation is discussed in section V.B.1 of this final rule.
During the April 30, 2015 public meeting, and in subsequent written comments in response to the March 2015 NOPR, stakeholders provided input regarding general issues pertinent to the rulemaking, such as issues regarding the proposed standard levels, as well as issues related to changes made to the test procedure. These issues are discussed in this section.
In response to the levels proposed in the NOPR (TSL 3), the joint efficiency commenters stated their support for the proposed standard levels and encouraged DOE to evaluate condensing levels for hot water boilers, noting that the national energy savings at TSL 4 would be more than five times greater than the savings at TSL 3. (The joint efficiency commenters, No. 62 at pp. 1–2)
AHRI, Burnham, Lochinvar, Weil-McLain, and PHCC stated their opposition to the proposed standards at TSL 3 based on their concerns about several areas within the analysis. (AHRI, No. 64 at p. 1; Burnham, No. 60 at p. 1; Lochinvar, No. 63 at p. 1; Weil-McLain, No. 55 at p. 1; PHCC, No. 61 at p. 1) Lochinvar encouraged DOE to consider adopting TSL 2, and PHCC suggested that DOE make minimal increases (one percentage point) to standards. (Lochinvar, No. 63 at p. 5; PHCC, No. 61 at p. 1) AHRI and Lochinvar also suggested that the efficiency levels presented in the NOPR at TSL 4 are not economically justified as minimum standards. (AHRI, No. 64 at p. 1; Lochinvar, No. 63 at p. 5)
Burnham stated that under the proposed standards, tens of thousands of consumers will lose choice, be effectively required to retain and repair old, inefficient units, or be forced into costly and even dangerous retrofits. (Burnham, No. 60 at p. 1) Burnham stated that DOE's proposed standards are based in part on energy use characterizations, installation costs, operating costs, and lifecycle costs which are flawed and tend to overstate the benefit of the proposed standards, and thereby, they do not meet EPCA's requirements of maximum improvements in energy efficiency that are technologically feasible and economically justified. Burnham stated that after correcting for the various technical issues, the LCC savings for 85-percent AFUE and higher gas-fired hot water boilers decrease substantially, even becoming negative. (Burnham, No. 60 at pp. 2, 4) Burnham stated that the DOE analysis either needs to be reanalyzed or that DOE needs to set standards for gas-fired hot water boilers at a level below 85-percent AFUE. (Burnham, No. 60 at p. 20)
Weil-McLain stated that significant additional costs will be imposed on consumers to achieve a hypothetical increase in energy savings by installing an 85-percent AFUE gas hot water boiler rather than an 82- or 83-percent AFUE boiler that would not entail all of these additional costs. (Weil-McLain, No. 55 at p. 3)
U.S. Boiler stated that a better alternative to the proposed rule would be to set a minimum efficiency level of 83 percent AFUE, which would allow most existing chimneys to stay in use without alteration. U.S. Boiler stated that such a standard gives homeowners choices regarding installation of higher-efficiency boilers. (U.S. Boiler, Public Meeting Transcript, No. 50 at p. 291)
ACCA stated that, if not properly addressed, the issues with the analysis can lead to unintended consequences, such as driving some homeowners to repair and maintain older systems instead of replacing their equipment. (ACCA, No. 65 at p. 3)
The Department appreciates stakeholder comments with regard to the TSL selection and notes that DOE is required to set a standard that achieves the maximum energy savings that is determined to be technologically feasible and economically justified. In making such a determination, DOE must consider, to the extent practicable, the benefits and burdens based on the seven criteria described in EPCA (see 42 U.S.C. 6295(o)(2)(B)(i)(I)–(VII)). DOE's weighing of the benefits and burdens based on the final rule analysis and rationale for the TSL selection is discussed in section V. DOE notes that much of the commentary regarding the selection of TSL levels for the standards is based on more detailed comments regarding specific portions of the final rule analysis. These comments related to specific analyses are addressed within the specific analysis section to which they pertain. However, as a general matter, DOE notes that in light of the comments and data provided by stakeholders, the agency carefully reexamined its data and analyses for residential boilers, ultimately reassessing the appropriate efficiency levels for some product classes. Specifically, DOE determined to adopt a standard level at 84-percent AFUE for gas-fired hot water boilers and 85-percent AFUE for oil-fired steam boilers, which DOE determined meet the criteria for TSL 3 without causing harms described by the stakeholders. Regarding safety issues at 84-percent
Several stakeholders expressed legal, procedural, and practical concerns regarding the timing of the proposed test procedures and energy conservation standards revisions for residential boilers. Several stakeholders requested that DOE delay any further work on the rulemakings to amend efficiency standards for residential boilers until after the finalization of the test procedure. (AHRI, No. 64 at p. 2; Lochinvar, No. 63 at p. 1; Burnham, No. 60 at p. 5; AGA/APGA, No. 54 at p. 11; ACCA, No. 65 at p. 1) Specifically, AHRI requested that DOE reopen the docket for the March 2015 residential boiler standards NOPR once the test procedure has been finalized. (AHRI, No. 64 at p. 2) AHRI argued that the non-final status of the test procedure inhibits stakeholders' fair evaluation of the proposed standards and stressed the importance of having a known efficiency test procedure. AHRI commented that when a test procedure is in flux, manufacturers must spend resources collecting potentially unusable data which undermines their ability to effectively provide input on the proposed efficiency standards. Similarly, AHRI added that when a test procedure is not finalized, a manufacturer has no way of determining whether the test procedure will affect its ability to comply with a proposed revised standard. (AHRI, No. 64 at p. 2)
Many of these commenters were concerned about the timing of the energy conservation standards and test procedures rulemakings, given their expectation that the proposed changes to the test procedures for residential boilers would result in changes to the AFUE rating metric. Specifically, AHRI, Burnham, and Weil-McLain stated that the changes to the test procedure presented in the March 2015 TP NOPR would result in significant changes to the AFUE measurement. (AHRI, No. 64 at p. 1; Burnham, No. 60 at p. 6; Weil-McLain, No. 55 at p. 7) Burnham noted that the fact that the test procedure rulemaking is ongoing makes it impossible to gauge the effects of its final rule on proposed energy conservation standards. (Burnham, No. 60 at p. 6) AHRI stated that the proposed test procedure, if finalized, is not neutral and will require an adjustment of the AFUE standard to accommodate for the test effects. AHRI disagreed with DOE's tentative determination in the March 2015 TP NOPR that the proposed updates to the AFUE test method would not affect the AFUE ratings. AHRI stated that test data it is collecting shows that the proposed test procedure changes the resulting AFUE measurement. AHRI noted that one such change affecting AFUE is the proposed change to the procedure for burner set-up. (AHRI, No. 64 at p. 3)
Several stakeholders also contended that the timing of the test procedures and standards rulemakings violated certain procedural requirements, or DOE's own procedural policies. Burnham asserted that the simultaneous test procedure and standards rulemaking raises concerns under the Data Quality Act, and stated that the law and OMB guidelines require agency actions aimed at “maximizing the quality, objectivity, utility, and integrity of information (including statistical information) disseminated by the agency.” Burnham commented that DOE has considerable work ahead to comply with this requirement, and cited section 515 of the Treasury and General Government Appropriations Act for Fiscal Year 2001 (Pub. L. 106–554; HR 5658) at section 515(b)(2)(a). (Burnham, No. 60 at pp. 3, 6) AHRI, ACCA, and Burnham stated that by publishing the March 2015 TP NOPR within weeks of the proposed efficiency standards, DOE has failed to abide by its codified procedures at 10 CFR part 430, subpart C, appendix A(7)(c). (AHRI, No. 64 at p. 2; ACCA, No. 65 at p. 1; Burnham, No. 60 at p. 6) AHRI stated that The Administrative Procedure Act (APA) requires agencies to abide by their policies and procedures, especially where those rules have a substantive effect, and that the non-final test procedure has the substantive effect of increasing costs to stakeholders and diminishing their ability to comment on the efficiency standards. (AHRI, No. 64 at p. 2) AHRI noted that DOE is required to give stakeholders the opportunity to provide meaningful comments (see 42 U.S.C. 6295(p)(2), 6306(a)), and asserted that the close timing of the test procedures and standards NOPRs diminishes that opportunity. (AHRI, No. 64 at p. 2)
DOE does not believe that the timing of the test procedure and standards rulemakings has negatively impacted stakeholder's ability to provide comment. DOE has afforded interested parties an opportunity to provide comment on both the residential boiler standards rulemaking and the residential furnace and boiler test procedure rulemaking, consistent with the requirements of EPCA and all other relevant statutory provisions. Further, given the publication of the boilers test procedure final rule and the fact that none of the adopted changes will impact AFUE, DOE has determined it is not necessary to delay this standards rulemaking.
With regard to the specific concerns raised by stakeholders regarding changes to the AFUE metric, DOE determined in the March 2015 TP NOPR that the proposed test procedure amendments would have a
Second, with regard to Burnham's assertion that DOE has not met the requirements of the Data Quality Act (DQA), DOE does not believe that the timing of the test procedure and standards rulemakings are matters within the Department's guidelines implementing the DQA. DOE has concluded that the data, analysis, and models it has used in this rulemaking adhered to the requirements of the Data Quality Act. Further, DOE strived to maximize the quality, objectivity, utility, and integrity of the information disseminated in this rulemaking (see section VI.J for more information on these requirements and DOE's determination). As noted above, the January 2016 test procedure final rule removed all of the provisions within the March 2015 test procedure NOPR that could significantly impact AFUE ratings.
Finally, with regard to the comments stating that DOE has failed to abide by its codified procedures at 10 CFR 430, subpart C, appendix A (7)(c), Appendix A establishes procedures, interpretations, and policies to guide DOE in the consideration and promulgation of new or revised appliance efficiency standards under EPCA. (See section 1 of 10 CFR 430 subpart C, appendix A) Those procedures are a general guide to the steps DOE typically follows in promulgating energy conservation standards. The guidance recognizes that DOE can and will, on occasion, deviate from the typical process. Accordingly, DOE has concluded that there is no basis to delay the final rule adopting standards for residential boilers.
Lochinvar stated that the DOE analysis does not account for the impact of the proposed residential boiler standards on public safety. Specifically, Lochinvar stated that if 85–percent AFUE becomes the standard for gas-fired hot water boilers, the likelihood that the boilers will consistently have proper product installations and venting system design diminishes. (Lochinvar, No. 63 at p. 5) AHRI stated that the consumer safety impacts should eliminate consideration of a minimum efficiency standard appreciably above the current minimum standards for gas-fired and oil-fired boilers. (AHRI, No. 64 at pp. 3–4) Burnham stated that consumer safety hazards, along with the imposition of liability on manufacturers concordant with such safety hazards, alone justify the exclusion of Category I gas boilers at the 85–percent and 84–percent efficiency levels. (Burnham, No. 60 at p. 13)
Burnham stated that an 85–percent AFUE standard will risk hazards associated with old products being left in service long after it should be replaced due to higher replacement costs, and old boilers being replaced by less safe alternatives such as kerosene heaters. (Burnham, No. 60 at p. 3) Burnham stated that for 85–percent AFUE boilers, there are too many potential installations which breach acceptable safety levels. Furthermore, low-income consumers who do not have the resources to afford the necessary venting system upgrades required with condensing or near-condensing products will be imperiled. (Burnham, No. 60 at p. 7)
Burnham also stated that by selecting an 85–percent AFUE standard for gas-fired hot water boilers, DOE is risking carbon monoxide poisoning in situations where there are venting approaches used that meet building codes but which may not be adequate for full safety. (Burnham, No. 60 at pp. 3–4) Lochinvar stated that the condensation of flue gasses in venting will corrode conventional venting and may lead to spilling carbon monoxide into occupied spaces and death. (Lochinvar, No. 63 at p. 3)
Weil-McLain stated that the issues associated with the proposed retrofit venting requirements also create a potential safety hazard because positive pressure venting could push flue gases into the building. (Weil-McLain, No. 55 at p. 3) ACCA and Weil-McLain stated that there will be some less-skilled installers or do-it-yourselfers who may install the higher efficiency models incorrectly, resulting in safety problems. (ACCA, No. 65 at pp. 2–3; Weil-McLain, No. 55 at p. 3)
AHRI stated that the results of the analysis done by Gas Technology Institute (GTI), as contained in a report prepared for AHRI using a Vent-II tool, show that at an 84–percent or 85–percent AFUE level, the potential for excessive wetting in the vent system increases. As explained in the report, the “wet time” limits are values that have been used to establish the coverage for properly sized and configured vent systems for atmospheric gas-fired boilers in the National Fuel Gas Code (NFGC). When the Vent-II analysis shows wet times exceeding these limits, it is an indication of excessive condensation which increases the potential for condensate-induced corrosion and subsequent vent system failure, resulting in safety problems. (AHRI, No. 67 at p. 1)
In response, DOE has concluded that manufacturers will provide adequate guidance for installers to ensure that the venting system is safe. Furthermore, DOE assumed that 85–percent AFUE boilers would either be Category I or Category III appliances, and DOE accounted for a fraction of installations that would require a stainless steel vent connector or stainless steel venting to mitigate the dangers of potential corrosion issues. In any case, DOE is not adopting a standard at 85–percent AFUE for gas-fired boilers, so the potential problems raised by the stakeholders will not be an issue.
Regarding safety issues at to 84–percent AFUE, based on Burnham's data, AHRI's contractors' survey, and models available in the AHRI directory, DOE determined that the fraction of shipments and model availability with mechanical draft for the 82–percent to 84–percent AFUE boilers is about the same. In addition, AHRI's Vent-II analysis showed that for all 21 different scenario cases, 82–percent to 84–percent AFUE boilers demonstrated no difference in terms of their ability to meet the dryout wet times required to achieve the minimum NFGC safety requirements.
The Laclede group stated that DOE is not adhering to the process transparency and scientific integrity policies as set forth in 1996 “Process Improvement Rule” and outlined in 10 CFR 430, subpart C, appendix A (7)(g). 61 FR 36974 (July 15, 1996). Laclede also asserted that through the inconsistent application of the process improvement rule, DOE is not adhering to the consistency and transparency requirements outlined in the Treasury and General Government Appropriations Act of 2001, the Paperwork Reduction Act of 1995 (primarily Section 515), and the “Presidential Scientific Integrity Memorandum” issued on March 9, 2009, which was further clarified by the Director of the Office of Science and Technology Policy “Memorandum to the Heads of Departments and Agencies” of December 17, 2010. (Laclede, No. 58 at pp. 7–9)
As discussed in sections VI.C, J, and L and illustrated elsewhere in this document, DOE has developed analytical processes and data that ensure the quality of its information and the transparency of its analytical processes. In furtherance of these objectives and requirements, DOE has offered several opportunities for public comment on multiple documents, including documents made available prior to proposing any rule, and addressed stakeholder concerns at the April 30, 2015 public meeting, providing clarifications in an open and transparent fashion.
The Laclede group also stated that DOE failed to meet the requirements of Executive Order 12866, “Regulatory Planning and Review,” through the refusal to consider the alternative of not regulating. (Laclede, No. 58 at p. 7) DOE considered alternatives to regulating, including no new regulatory action. A full discussion of the non-regulatory alternatives considered by DOE is presented in the regulatory impact analysis found in chapter 17 of the final rule TSD.
As discussed previously, DOE believes it is in compliance with the requirements of 515 of the Treasury and Gen. Government Appropriations Act for fiscal year 2001 (Public Law 106–554; HR 5658) at section 515(b)(2)(a). (See section VI.J of this document.) For the final rule stage, DOE has incorporated feedback from interested parties, as appropriate, related to the energy use characterization, installation costs, operating costs, and lifecycle costs, leading to revisions in this analysis as compared to the analysis presented for the March 2015 NOPR. The specific comments and any related revisions are discussed in more detail in the applicable subsections of section IV of this document.
AHRI stated that DOE bears the burden, on the basis of substantial evidence, to demonstrate that the proposed standards are technologically feasible and economically justified. AHRI claimed that the DOE has attempted to impermissibly shift its statutory burden of data production onto stakeholders by forcing them to disprove several unreasonable assumptions including the price elasticity of boilers, as well as the lifetime of condensing boilers. AHRI stated that at a minimum, DOE has the responsibility to explain the basis for its assumptions. (AHRI, No. 64 at p. 4)
In response to AHRI, DOE notes that it conducts its analyses with the best available information that it is aware of, and seeks comment from interested parties as a way to ensure analytical robustness and verify the accuracy of the assumptions and information used in the rulemaking process. DOE then revises its analyses based on comments, information, and data collected through additional research and presented by stakeholders, as applicable, in later rulemaking stages. In some cases, additional relevant but unpublished data may reside with the regulated community and can be considered by DOE only if provided by those regulated parties. DOE has provided detailed comment responses regarding the specific assumptions outlined by AHRI in sections IV.F.2.d and IV.G.
In response to the NOPR, Weil-McLain stated that DOE had changed its position outlined in the NODA to not amend energy conservation standards for residential boilers. Weil-McLain added that DOE did so without explanation for the change in recommendation. (Weil-McLain, No. 55 at p.8)
In response, DOE emphasizes that the 2014 NODA was not a determination on whether to amend standards for residential boilers. Rather, it was a publication of the analysis and results at a preliminary stage (
This section addresses the analyses DOE has performed for this rulemaking with regard to residential boilers. Separate subsections address each component of DOE's analyses.
DOE used several analytical tools to estimate the impact of the standards considered in this document. The first tool is a spreadsheet that calculates the LCC and PBP of potential amended or new energy conservation standards. The national impact analysis uses a second spreadsheet set that provides shipments forecasts and calculates national energy savings and net present value of total consumer costs and savings expected to result from potential energy conservation standards. DOE uses the third spreadsheet tool, the Government Regulatory Impact Model (GRIM), to assess manufacturer impacts of potential standards. These spreadsheet tools are available on the DOE Web site for this rulemaking at:
DOE develops information in the market and technology assessment that provides an overall picture of the market for the products concerned, including the purpose of the products, the industry structure, manufacturers, market characteristics, and technologies used in the products. This activity includes both quantitative and qualitative assessments, based primarily on publicly-available information. The subjects addressed in the market and technology assessment for this rulemaking include: (1) A determination of the scope of the rulemaking and product classes; (2) manufacturers and industry structure; (3) existing efficiency programs; (4) shipments information; (5) market and industry trends; and (6) technologies or design options that could improve the energy efficiency of residential boilers. The key findings of DOE's market assessment are summarized below. See chapter 3 of the final rule TSD for further discussion of the market and technology assessment.
In the NOPR, DOE proposed to maintain the scope of coverage as defined by its current regulations for this analysis of new and amended standards, which includes six product classes of residential boilers: (1) Gas-fired hot water boilers, (2) gas-fired steam boilers, (3) oil-fired hot water boilers, (4) oil-fired steam boilers, (5) electric hot water boilers, and (6) electric steam boilers. As discussed in further detail in the paragraphs below, DOE excluded several types of residential boilers from the analysis in both the March 2015 NOPR and, subsequently, in this final rule.
DOE did not consider combination space and water heating appliances for this final rule. Combination appliances provide both space heating and domestic hot water to a residence. These products are available on the market in two major configurations, including a water heater fan-coil combination unit and a boiler tankless coil combination unit. Currently, manufacturers certify
DOE did not include electric boilers in the analysis of amended AFUE standards. (However, DOE has considered standby mode and off mode standards for electric boilers.) Electric boilers do not currently have an AFUE requirement under 10 CFR 430.32(e)(2)(ii). Electric boilers typically use electric resistance coils as their heating elements, which are highly efficient. Furthermore, the current DOE test procedure for determining AFUE classifies boilers as indoor units and, thus, considers jacket losses to be usable heat, because those losses would go to the conditioned space. The efficiency of these products already approaches 100 percent AFUE. Therefore, there are no options for increasing the rated AFUE of this product, and the impact of setting AFUE energy conservation standards for these products would be negligible. DOE proposed not to analyze amended AFUE standards for electric boilers in the March 2015 NOPR and did not receive any comments relating to this proposal. 80 FR 17222, 17238 (March 31, 2015).
DOE also did not include boilers that are manufactured to operate without the need for electricity in the analysis of amended AFUE standards. As was noted in the March 2015 NOPR, an exception already exists for boilers which are manufactured to operate without any need for electricity. (42 U.S.C. 6295(f)(3)(C); 10 CFR 430.32(e)(2)(iv)) 80 FR 17222, 17238 (March 31, 2015). Thus, DOE did not consider such products in the course of this analysis, and such products are not covered by the amended standards. DOE did not receive any comments in response to its proposal to exclude these products in the March 2015 NOPR.
In summary, DOE did not receive any comments in response to the NOPR regarding scope of coverage. Therefore, the scope used for the analysis of this final rule is the same as the scope used for the NOPR analysis.
When evaluating and establishing energy conservation standards, DOE divides covered products into product classes by the type of energy used or by capacity or other performance-related features that justify a different standard. In making a determination whether a performance-related feature justifies a different standard, DOE must consider such factors as the utility to the consumer of the feature and other factors DOE determines are appropriate. (42 U.S.C. 6295(q)) For this rulemaking, as discussed in the preceding section, DOE proposes to maintain the scope of coverage as defined by its current regulations for this analysis of standards, which includes six product classes of boilers. Table IV.1 lists the six product classes examined in the final rule.
In response to the proposed product classes included in the March 2015 NOPR, AGA, APGA, and PGW requested that DOE establish separate product classes for residential condensing and non-condensing boilers. (AGA, No. 54 at p. 11; PGW, No. 57 at p. 2) AGA stated that non-condensing boilers provide customers unique performance-related characteristics and consumer utility due to distinct venting characteristics and building constraints on installations. AGA stated that failure to adopt separate product classes would be inconsistent with DOE precedent. (AGA, No. 54 at p. 6)
Burnham stated that loss of the ability to use Category I venting (suitable for non-condensing boilers) is a loss in utility because the circumstances of many real world installations offer no practical alternatives to Category I venting, particularly in urban areas with closely-spaced residences. Burnham argued that providing heat and hot water are not the only utility functions, features, and performance characteristics of boilers, and that designs that allow proper installation in a variety of dwellings are a critical aspect of utility so that such products can be installed and used safely. Burnham stated limited exterior wall space and building or safety code or physical restrictions on where exhaust terminals can be located can cause venting issues, and that these constraints can be a particular problem in urban areas with homes that are either closely spaced or conjoined. Burnham gave the example of older “row homes” found in Northeastern cities, which Burnham asserted represent a large part of the U.S. residential boiler market. (Burnham, No. 60 at p. 14) In addition, Burnham stated that there is a point at which increasing installation costs become large enough to effectively create a “loss of utility,” and this situation in the real world is as likely to “result in the unavailability” of appropriate non‐condensing boilers as a pure design issue. Burnham stated that this is a direct violation of the “safe harbor rule” in 42 U.S.C. 6295(o)(4), among other provisions. (Burnham, No. 60 at pp. 4–16)
DOE received similar comments in response to the February 11, 2014 NODA and preliminary analysis, and addressed the comments in the March 31, 2015 NOPR. 79 FR 8122; 80 FR 17222. DOE maintains its position from the NOPR and reiterates that the utility derived by consumers from boilers is in the form of the space heating function that a boiler performs, rather than the type of venting the boiler uses. Condensing and non-condensing boilers perform equally well in providing this heating function. Likewise, a boiler requiring Category I venting and a boiler requiring Category IV venting are capable of providing the same heating function to the consumer, and, thus, provide virtually the same utility with respect to their primary function. DOE does not consider reduced costs associated with Category I venting in certain installations as a special utility, but rather, as was done in the March 2015 NOPR, the costs were considered as an economic impact on consumers that is considered in the rulemaking's cost-benefit analysis. DOE does not agree with Burnham's assertion that costs can become so prohibitively expensive that they should be considered a loss of utility of the product. Rather, the larger expense should be considered as an economic impact on consumers in the rulemaking's cost-benefit analysis and ultimately the analysis will determine if a cost is economically prohibitive. DOE considered the additional cost of adding vent length required to change the vent location to avoid the code limitations outlined by Burnham. Details regarding installation costs can be located in section IV.F.2. DOE maintains that this final rule is not in violation of the 42 U.S.C. 6295(o)(4), because it does not result in the unavailability of any covered product class of performance
As part of the market and technology assessment, DOE develops a comprehensive list of technologies to improve the energy efficiency of residential boilers. In the final rule analysis, DOE identified ten technology options that would be expected to improve the AFUE of residential boilers, as measured by the DOE test procedure: (1) Heat exchanger improvements; (2) modulating operation; (3) dampers; (4) direct vent; (5) pulse combustion; (6) premix burners; (7) burner derating; (8) low-pressure air-atomized oil burner; (9) delayed-action oil pump solenoid valve; and (10) electronic ignition.
DOE received no comments suggesting additional technology options in response to the NOPR analysis, and thus, DOE has maintained the same list of technologies in the final rule analysis. After identifying all potential technology options for improving the efficiency of residential boilers, DOE performed the screening analysis (see section IV.B of this final rule or chapter 4 of the final rule TSD) on these technologies to determine which could be considered further in the analysis and which should be eliminated.
DOE uses the following four screening criteria to determine which technology options are suitable for further consideration in an energy conservation standards rulemaking:
1.
2.
3.
4.
In sum, if DOE determines that a technology, or a combination of technologies, fails to meet one or more of the above four criteria, it will be excluded from further consideration in the engineering analysis. Additionally, it is DOE policy not to include in its analysis any proprietary technology that is a unique pathway to achieving a certain efficiency level. The reasons for eliminating any technology are discussed below.
The subsequent sections include comments from interested parties pertinent to the screening criteria, DOE's evaluation of each technology option against the screening analysis criteria, and whether DOE determined that a technology option should be excluded (“screened out”) based on the screening criteria.
During the NODA and NOPR phases, DOE screened out pulse combustion as a technology option for improving AFUE and screened out control relay for boiler models with brushless permanent magnet motors as a technology option for reducing standby electric losses. DOE decided to screen out pulse combustion based on manufacturer feedback during the Framework public meeting indicating that pulse combustion boilers have had reliability issues in the past, and therefore, manufacturers do not consider this a viable option to improve efficiency. Further, manufacturers indicated that similar or greater efficiencies than those of pulse combustion boilers can be achieved using alternative technologies. DOE did not receive any comments related to screening out pulse combustion and maintained this position for the final rule, and accordingly, maintained its position from the NOPR to screen out pulse combustion as a technology option.
In the NODA and NOPR analysis, DOE decided to screen out the option of using a control relay to depower BPM motors due to feedback received during the residential furnace rulemaking (which was reconfirmed during manufacturer interviews for the residential boiler rulemaking), which indicated that using a control relay to depower brushless permanent magnet motors could reduce the lifetime of the motors. The result of such a design would likely be excessively frequent repair and maintenance of the boiler to replace the motor.
DOE also screened out burner derating as a technology option in the NOPR and final rule analysis. Burner derating reduces the burner firing rate while keeping heat exchanger geometry and surface area and the fuel-air ratio the same, which increases the ratio of heat transfer surface area to energy input, and increases the efficiency. However, the lower energy input means that less heat is provided to the user than with conventional burner firing rates. As a result of the decreased heat output of the boiler with derated burners, DOE has screened out burner derating as a technology option, as it could reduce consumer utility.
The efficiency advocates recommended that DOE assess whether the de-powering could be done in a manner to minimize the number of power cycles to address concerns regarding potential product life impacts, for example by only disconnecting when the boiler has been inactive for more than 24 hours. The efficiency advocates suggested that this approach would achieve the desired results during long periods of inactivity, such as during the summer, without cycling on and off during periods of regular activity. (Efficiency Advocates, No. 62 at p. 2)
DOE has not found any residential boilers which utilize control relays to completely depower the BPM motors. The feedback received from the residential furnace rulemaking indicated that it was not only the number of power cycles which could reduce product utility but the potential for large current upon start up. Therefore, DOE has maintained its position from the NOPR in this final
Through a review of each technology, DOE found that all of the other identified technologies met all four screening criteria and consequently, are suitable for further examination in DOE's analysis. In summary, DOE did not screen out the following technology options to improve AFUE: (1) heat exchanger improvements; (2) modulating operation; (3) direct vent; (4) premix burners; (5) low-pressure air-atomized oil burner; and (6) delayed-action oil pump solenoid valve. DOE also maintained the following technology options to improve standby mode and off mode energy consumption: (1) transformer improvements; and (2) switching mode power supply. All of these technology options are technologically feasible, given that the evaluated technologies are being used (or have been used) in commercially-available products or working prototypes. Therefore, all of the trial standard levels evaluated in this notice are technologically feasible. DOE also finds that all of the remaining technology options also meet the other screening criteria (
In the engineering analysis (corresponding to chapter 5 of the final rule TSD), DOE establishes the relationship between the manufacturer selling price (MSP) and improved residential boiler energy efficiency. This relationship serves as the basis for cost-benefit calculations for individual consumers, manufacturers, and the Nation. DOE typically structures the engineering analysis using one of three approaches: (1) design option; (2) efficiency level; or (3) reverse engineering (or cost-assessment). The design-option approach involves adding the estimated cost and efficiency of various efficiency-improving design changes to the baseline to model different levels of energy efficiency. The efficiency-level approach uses estimates of cost and efficiency at distinct levels of efficiency from publicly-available information, and information gathered in manufacturer interviews that is supplemented and verified through technology reviews. The reverse-engineering approach involves testing products for efficiency and determining cost from a detailed bill of materials (BOM) derived from the reverse-engineering of representative products. The efficiency values under consideration range from that of a least-efficient boiler sold today (
As noted in section III.B, the AFUE metric fully accounts for the fossil-fuel energy consumption in active, standby and off modes, whereas the electrical energy consumption in standby mode and off mode is accounted for with separate metrics that measure the power drawn during standby mode and off mode (P
For the NOPR analysis of AFUE efficiency levels, DOE conducted the engineering analysis for residential boilers using a combination of the efficiency level and cost-assessment approaches. More specifically, DOE identified the efficiency levels for analysis and then used the cost-assessment approach to determine the technologies used and the associated manufacturing costs at those levels.
For the standby mode and off mode analyses, DOE adopted a design option approach, which allowed for the calculation of incremental costs through the addition of specific design options to a baseline model. DOE decided on this approach because it did not have sufficient data to execute an efficiency-level analysis, as manufacturers typically do not rate or publish data on the standby mode and or off mode energy consumption of their products.
DOE continued to use the same analytical approaches for the final rule as used in the NOPR. In response to the NOPR, DOE received specific comments from interested parties on certain aspects of the engineering analysis. A brief overview of the methodology, a discussion of the comments DOE received, and DOE's response to those comments, as well as any adjustments made to the engineering analysis methodology or assumptions as a result of those comments, are presented in the sections below. See chapter 5 of the final rule TSD for additional details about the engineering analysis.
As noted previously, for analysis of amended AFUE standards, DOE used an efficiency-level approach to identify incremental improvements in efficiency for each product class. The efficiency-level approach enabled DOE to identify incremental improvements in efficiency for efficiency-improving technologies that boiler manufacturers already incorporate in commercially-available models. After identifying efficiency levels for analysis, DOE used a cost-assessment approach (section IV.C.2) to determine the MPC at each efficiency level identified for analysis. This method estimates the incremental cost of increasing product efficiency. For the analysis of amended standby mode and off mode energy conservation standards, DOE used a design-option approach and identified efficiency levels that would result from implementing certain design options for reducing power consumption in standby mode and off mode.
In its analysis, DOE selected baseline units typical of the least-efficient commercially-available residential boilers. DOE selected baseline units as
DOE uses the baseline unit for comparison in several phases of the analyses, including the engineering analysis, LCC analysis, PBP analysis, and the NIA. To determine energy savings that will result from an amended energy conservation standard, DOE compares energy use at each of the higher energy efficiency levels to the energy consumption of the baseline unit. Similarly, to determine the changes in price to the consumer that will result from an amended energy conservation standard, DOE compares the price of a baseline unit to the price of a unit at each higher efficiency level.
DOE received no comments regarding the baseline efficiency levels chosen for the NOPR analysis of amended AFUE standards. Thus, DOE has maintained these baseline efficiency levels for the final rule analysis, which are equal to the current Federal minimum standards for each product class in the final rule analysis. Table IV.2 presents the baseline AFUE levels identified for each product class. Additional details on the selection of baseline AFUE efficiency levels are in chapter 5 of the final rule TSD.
The input capacity is a factor that influences the MPC of a residential boiler. The impact of efficiency ratings on residential boiler prices can be captured by calculating the incremental price for each efficiency level higher than the baseline at a given input capacity. To provide a singular set of incremental price results for the engineering analysis, DOE selected a single input capacity for each product class analyzed for AFUE standards. DOE selected these input capacities by referencing a number of sources, including information obtained during manufacturer interviews, information collected for the market and technology assessment, as well as information obtained from product literature.
In response to the representative input capacities selected in the engineering analysis from each product class, Burnham presented shipment information of their aggregated subsidiaries indicating the average input capacity sold in for each product class. Based upon this data, Burnham suggested that the representative input capacity for gas-fired hot water boilers should be changed to 120 kBtu/hr. (Burnham, No. 60 at p. 20)
In response, DOE notes that the representative input capacity is meant to describe the most typical boiler sold. Therefore, DOE believes that although the average of all shipments sold may be 120 kBtu/hr, the most often sold would be 100 kBtu/hr. AHRI stated that the analysis does not adequately evaluate the effect of revised efficiency standards on larger input boilers. AHRI stated that boilers are a very small segment of the U.S. residential heating market and commented that larger input boilers are the smallest segment of the residential boiler market. For these larger input models, AHRI argued that there is no economy of scale, and because relatively so few are manufactured, the costs of components are higher. The units are physically larger and weigh more so their shipping costs are larger. Accordingly, AHRI asserted that the information developed by the tear down analysis cannot be validly scaled up to these models which have input rates 2 to 2.5 times higher than the baseline models. (AHRI, No. 64 at p. 14) Similarly, Burnham stated that due to the size of the residential boiler market, the manufacturing costs for a 250,000 Btu/hr boiler may not be a simple linear scale. (Burnham, public meeting transcript, No. 50 at p. 34)
In response to these comments, DOE examined the parts catalogs of various manufacturers for a variety of boiler types within each product class. From this examination, DOE determined that the same materials, as well as purchase parts are utilized in the manufacture of both representative and larger capacity boilers. For example, a representative capacity heat exchanger may be comprised of four cast iron sections, including two end sections with two intermediate sections. A larger capacity unit would generally be comprised of a larger number of the same sections, typically two end sections with six intermediate sections for a 250 kBtu/hr boiler. Although the amount of material used increases as capacity increases, DOE has not found reason to believe that the cost of the material would increase due to a lack of economy of scale.
In addition, DOE found that the large majority of components used for larger-capacity boilers were identical to those used in lower capacity boilers, although larger quantities of those components may be necessary in the manufacturing of higher-capacity boilers. For example, a larger-capacity burner may require a larger number of burner tubes. In several cases, the cost of the higher-capacity unit could be expected to be less than the result of a linear scaling upward of the cost, due to the need for only one component per unit regardless of capacity. In other words, there are certain fixed production costs that are present no matter the size of the boiler and only the variable costs increase with boiler size. For instance, a larger boiler would utilize the same controls and wiring harness as a smaller boiler, the cost of which would remain fixed regardless of the input capacity. DOE did find one relevant example, a higher-capacity premix burner, which may be purchased at a higher cost due to a lack of economy of scale. However, DOE believes that the potential increase in price of this purchase part would be offset by the many instances in which the production costs remain fixed regardless of capacity.
DOE notes that shipping costs are considered a sales expense and not a production cost. As discussed in section IV.C.2.e, when translating MPCs to MSPs, DOE applies a manufacturer mark-up to the MPC. This mark-up, based on an analysis of manufacturer SEC 10–K reports, includes outbound freight costs. Therefore, any increase in MPC would account for larger shipping costs via a higher MSP.
“Standby mode” and “off mode” power consumption are defined in the DOE test procedure for residential furnaces and boilers. DOE defines “standby mode” as “any mode in which the furnace or boiler is connected to a mains power source and offers one or more of the following space heating functions that may persist: a.) To facilitate the activation of other modes (including activation or deactivation of active mode) by remote switch (including thermostat or remote control), internal or external sensors, or timer; b.) Continuous functions, including information or status displays or sensor based functions.” 10 CFR part 430, subpart B, appendix N, section 2.12. “Off mode” is defined as “a mode in which the furnace or boiler is connected to a mains power source and is not providing any active mode or standby mode function, and where the mode may persist for an indefinite time.
Through review of product literature and discussions with manufacturers, DOE has found that boilers typically do not have an off switch. Manufacturers stated that if a switch is included with a product, it is primarily used as a service/repair switch, not for turning off the product during the off season. However, these switches could possibly be used as off switches by the consumer. In cases where no off switch is present, no separate measurement for off mode is taken during testing, and the DOE test procedure sets off mode power equal to standby mode power (P
To determine the baseline standby mode and off mode power consumption, DOE identified baseline components as those that consume the most electricity during the operation of those modes. Since it would not be practical for DOE to test every boiler on the market to determine the baseline and since manufacturers do not currently report standby mode and off mode energy consumption, DOE “assembled” the most consumptive baseline components from the models tested to model the electrical system of a boiler with the expected maximum system standby mode and off mode power consumption observed during testing of boilers and similar equipment. The baseline standby mode and off mode power consumption levels used in the NOPR and final rule analysis are presented in Table IV.3.
In response to the NOPR standby mode and off mode analysis, Lochinvar suggested DOE should not regulate standby electricity consumption, because the standby electrical power consumption releases useful heat inside the home. Lochinvar highlighted that DOE's test method for residential boilers affirms its position by assigning a jacket loss factor of 0 for “boilers intended to be installed indoors.” However, Lochinvar agreed that DOE should regulate off mode power consumption. Lochinvar also agreed with DOE's assumption that most consumers do not turn off power to their boilers seasonally and suggested that DOE should invest effort into promoting turning off power to the boiler when there is no need for heating. Lochinvar stated that baseline power consumption predicted by DOE is reasonable, but that the assumption that the standby mode energy consumption is the same as the off mode energy consumption is erroneous. (Lochinvar, No. 63 at pp. 1–4)
In response to the suggestion that DOE not regulate standby mode, DOE notes that it is statutorily required to consider both standby mode and off mode electrical power consumption under EPCA at 42 U.S.C. 6295(gg)(3). As outlined in section III.B, the DOE test procedure references two industry standards, ASHRAE 103–1993, which is used to determine the heating efficiency of a residential boiler, and IEC 62301, which is used to determine the standby mode and off mode energy consumption of a residential boiler. As noted by Lochinvar, ASHRAE 103 considers the jacket losses as usable heat for boilers intended to be installed indoors. However, the power consumption as measured by IEC Standard 62301 is a consumption metric and not an efficiency metric and is considered separately from the AFUE. The DOE test procedure for standby mode does not treat those boilers intended to be installed indoors any differently than those intended to be installed outdoors or in other unconditioned spaces, where the heat produced by the standby mode use would be a loss. While the majority of residential boilers may be installed indoors (as is assumed by the DOE test procedure), there are boilers available on the market that are designed for installation in unconditioned spaces or outdoors where any heat released by standby electrical power consumption would not be useful. Therefore, DOE has concluded it is appropriate to regulate the standby mode power consumption.
In response to the assertion that standby mode and off mode consumption are not equal, DOE agrees that standby mode energy consumption and off mode energy consumption are not equal in all cases (
In response to the methodology presented in the NOPR for determining the efficiency levels by focusing on energy consumptive components, AHRI stated the component analysis methodology did not include any analysis of the standby mode and off mode energy consumptions of current
In response, DOE tested the standby consumption of several boilers, including those with outdoor reset controls. However, DOE chose to use a component analysis approach in the standby mode and off mode analysis in order to take into account the energy use of all possible accessories so as to prevent any possible limitation on the use of such accessories. For each product class, the baseline selected was greater than any model tested by DOE. During manufacturer interviews, no manufacturer indicated that any of their models exceeded the baseline selected by DOE for each product class. In the absence of any data showing that the standby mode and off mode energy consumption is higher than the DOE baseline levels, DOE has maintained the same levels for the final rule. DOE believes that this approach benefits manufacturers by allowing for flexibility of designs and ensuring that the standard will be set at a reasonable level that does not restrict the inclusion of technologies that could improve energy efficiency or provide consumer utility. DOE notes that AHRI's comment regarding higher baselines contradicts Burnham's comment which indicate that the standby mode and off mode baseline levels are high for most product classes. Further, Lochinvar's comment indicated that the baseline power consumption predicted by DOE is reasonable.
Regarding the standby mode data provided by Burnham, DOE notes that the DOE test procedure measures standby and off mode electricity consumption in terms of real power (watts) rather than apparent power (VA). The data provided by Burnham cannot be incorporated into the standby mode and off mode analysis without the power factor of the units tested. DOE notes that there are hundreds of residential boiler models on the market with varying accessories, control systems, and power supplies. The assumptions made in the component analysis used for the determination for the baseline levels are rooted upon actual test data. DOE used a component-focused analysis that considered the most energy consumptive individual components in order to prevent setting a standard which could limit manufacturers' ability to utilize accessories which may consume power in standby mode, but reduce active mode energy use, or provide other consumer utility.
Table IV.4 through Table IV.7 show the efficiency levels DOE selected for the final rule analysis of amended AFUE standards, along with a description of the typical technological change at each level. These efficiency levels are the same as were presented in the NOPR, and following the same rationale, they are based upon the most common efficiency levels found on the market or a significant technology (
Several stakeholders raised concerns in response to the consideration of efficiency levels 1 through 3 selected for the gas-fired hot water boiler product class in the NOPR analysis. (Burnham, No. 60 at p. 17; Lochinvar, No. 63 at p. 2; AGA, No. 54 at p. 11) Lochinvar and Burnham expressed concern that the designs necessary to reach these efficiency levels increase the cost of the boiler, as well as the risk of condensation and carbon monoxide issues occurring. Lochinvar and Burnham argued that more frequent and prolonged exposure to condensate as a result of these designs, as well as the automatic means requirement, will increase the potential of condensation-related problems, such as nuisance faults, blocked heat exchangers, and corroding vents. Lochinvar and Burnham further argued that the corrosion of conventional venting by condensate may lead to the spilling of carbon monoxide into occupied spaces, thereby resulting in safety concerns. (Lochinvar, No. 63 at p. 2; Burnham No. 60 at p. 4) Lochinvar also stated that the sizing, installation, and operating conditions also influence the potential for condensation. (Lochinvar, No. 63 at p. 3)
The Department recognizes that certain efficiency levels could pose health or safety concerns under certain conditions if they are not installed properly in accordance with manufacturer specifications. However, these concerns can be resolved with proper product installations and venting system design. This is evidenced by the significant shipments of products that are currently commercially available at these efficiency levels, as well as the lack of restrictions on the installation location of these units in installation manuals. In addition, DOE notes that products achieving these efficiency levels have been on the market since at least 2002, which demonstrates their reliability, safety, and consumer acceptance. Given the significant product availability and the amount of time products at these efficiency levels have been available on the market, DOE continues to believe that products at these efficiency levels are safe and reliable when installed correctly. Therefore, DOE has maintained the efficiency levels above 82 percent and below 90 percent in its final rule analysis. Discussion related to the costs associated with the installation of venting systems to prevent condensation and corrosion issues are outlined in section IV.F.2 of this final rule.
In addition, DOE considered whether changes to the residential furnaces and boilers test procedure adopted by the January 2016 test procedure final rule would necessitate changes to the AFUE levels being analyzed. The primary changes adopted in the test procedure are listed in section III.B. Adopting these provisions was assessed as having no impact on the AFUE for residential boilers. (See EERE–2012–BT–TP–0024) In response to the March 2015 NOPR, several stakeholders submitted comments suggesting that the proposed changes outlined in the March 2015 TP NOPR would impact the measured AFUE of products and ultimately impact the standards rulemaking. As described in section III.F, the January 2016 TP FR did not adopt any provisions impacting AFUE. Consequently, DOE used the same AFUE efficiency levels in the final rule analysis as were used in the NOPR analysis.
Table IV.8 through Table IV.13 show the efficiency levels DOE selected for the final rule analysis of standby mode and off mode standards, along with a description of the typical technological change at each level. DOE maintained the efficiency levels used in the NOPR stage of the analysis.
At the start of the engineering analysis, DOE identified the energy efficiency levels associated with residential boilers on the market using data gathered in the market assessment. DOE also identified the technologies and features that are typically incorporated into products at the baseline level and at the various energy efficiency levels analyzed above the baseline. Next, DOE selected products for the physical teardown analysis having characteristics of typical products on the market at the representative input capacity. DOE gathered information by performing a physical teardown analysis (see section
During the development of the engineering analysis for the NOPR, DOE held interviews with manufacturers to gain insight into the residential boiler industry, and to request feedback on the engineering analysis and assumptions that DOE used. DOE used the information gathered from these interviews, along with the information obtained through the teardown analysis and public comments, to refine the assumptions and data in the cost model. Next, DOE derived manufacturer markups using publicly-available residential boiler industry financial data in conjunction with manufacturers' feedback. The markups were used to convert the MPCs into MSPs. Further information on comments received and the analytical methodology is presented in the subsections below. For additional detail, see chapter 5 of the final rule TSD.
To assemble BOMs and to calculate the manufacturing costs for the different components in residential boilers, DOE disassembled multiple units into their base components and estimated the materials, processes, and labor required for the manufacture of each individual component, a process referred to as a “physical teardown.” Using the data gathered from the physical teardowns, DOE characterized each component according to its weight, dimensions, material, quantity, and the manufacturing processes used to fabricate and assemble it.
DOE also used a supplementary method, called a “virtual teardown,” which examines published manufacturer catalogs and supplementary component data to estimate the major physical differences between a product that was physically disassembled and a similar product that was not. For supplementary virtual teardowns, DOE gathered product data such as dimensions, weight, and design features from publicly-available information, such as manufacturer catalogs. The initial teardown analysis for the NODA included 6 physical and 5 virtual teardowns of residential boilers. The NOPR teardown analysis included 16 physical and 4 virtual teardowns of residential boilers. DOE performed no further teardowns in the final rule analysis, but updated the costs data inputs based on the most recent materials and purchased part price information available.
DOE selected the majority of the physical teardown units in the gas hot water product class because it has the largest number of shipments. DOE conducted physical teardowns of twelve gas hot water boilers, five of which were non-condensing cast iron boilers, two of which were non-condensing copper boilers, and the remaining five of which were condensing boilers. DOE performed an additional two virtual teardowns of gas hot water boilers.
DOE also performed physical teardowns on two gas-fired steam boilers, as well as two oil-fired hot water boilers. DOE conducted one virtual teardown of an oil-fired steam boiler, as well as a virtual teardown of an oil-fired hot water boiler.
The teardown analysis allowed DOE to identify the technologies that manufacturers typically incorporate into their products, along with the efficiency levels associated with each technology or combination of technologies. The end result of each teardown is a structured BOM, which DOE developed for each of the physical and virtual teardowns. The BOMs incorporate all materials, components, and fasteners (classified as either raw materials or purchased parts and assemblies), and characterize the materials and components by weight, manufacturing processes used, dimensions, material, and quantity. The BOMs from the teardown analysis were then used as inputs to the cost model to calculate the MPC for each product that was torn down. The MPCs resulting from the teardowns were then used to develop an industry average MPC for each product class analyzed.
More information regarding details on the teardown analysis can be found in chapter 5 of the final rule TSD.
The cost model is a spreadsheet that converts the materials and components in the BOMs into dollar values based on the price of materials, average labor rates associated with manufacturing and assembling, and the cost of overhead and depreciation, as determined based on manufacturer interviews. To convert the information in the BOMs to dollar values, DOE collected information on labor rates, tooling costs, raw material prices, and other factors. For purchased parts, the cost model estimates the purchase price based on volume-variable price quotations and detailed discussions with manufacturers and component suppliers. For fabricated parts, the prices of raw metal materials
Once the cost estimates for all the components in each teardown unit were finalized, DOE totaled the cost of materials, labor, and direct overhead used to manufacture a product in order to calculate the manufacturer production cost. The total cost of the product was broken down into two main costs: (1) The full manufacturer production cost, referred to as MPC; and (2) the non-production cost, which includes selling, general, and administration (SG&A) expenses; the cost of research and development; and interest from borrowing for operations or capital expenditures. DOE estimated the MPC at each efficiency level considered for each product class, from the baseline through the max-tech. After incorporating all of the assumptions into the cost model, DOE calculated the percentages attributable to each element of total production cost (
DOE considered the draft type (
In response to the MPC's presented in the NOPR, Weil-McLain stated that increasing efficiencies would require not just larger heat exchangers, but also different burners and flue dampers, in addition to the mechanical venting inducer necessary for fan-assisted draft. Weil-McLain added that non-product cost increases would be created by additional electric power consumption required to run the inducer or blower, new electric service installation in some instances, new venting and/or chimney lining, re-piping, and higher maintenance costs due to inducers/blowers and positive pressure vent systems. (Weil-McLain, No. 55 at p. 3)
Similarly, AHRI stated that DOE mischaracterized the design changes required to achieve the proposed minimum standards, and, therefore, the resulting cost to manufacturers is underestimated. Specifically, AHRI stated that DOE assumed that the only design change necessary to achieve the proposed revised minimum AFUE levels is to increase the heat exchanger area. AHRI argued that this analysis is incomplete because it fails to recognize the additional changes. AHRI suggested that in some cases models may become bigger to accommodate the larger heat exchanger. In those cases, a larger model will require more material for the jacket and other design modifications. (AHRI, No. 64 at p. 12) Burnham stated that DOE did not include the cost of the system pump that manufacturers send along with the residential boiler. (Burnham, No. 60 at p. 24)
In response to the commenters' statements, DOE notes that the intent of listing the technology option corresponding to each efficiency level was to give stakeholders information on the specific design change that has been observed as the primary driver of improved efficiency; it was not intended to convey every component that will change from one efficiency level to the next. The increase in heat exchanger surface area was the primary technological driver in improving efficiency for many of the efficiency levels, and is, therefore, the technology option listed in those cases. The ancillary costs associated with increasing efficiency were included in the development of the MPC's at all efficiency levels, including those that primarily rely on increases in heat exchanger surface area noted by AHRI and Weil-McLain. When DOE performed the physical teardown analysis, it observed and accounted for any differences in other ancillary components at higher efficiency levels. DOE notes that the cost of the system pump is included in the manufacturer production costs for hot water boilers. The non-product costs highlighted by Weil-McLain related to installation and energy costs are captured in the installation and maintenance cost of the LCC analysis, described in section IV.F of this final rule.
Burnham suggested there would be a significant cost increase for oil-fired and steam boilers as a result of a reduction in the production of cast iron gas-fired hot water boilers due to standards. Burnham stated that the fixed cost associated with foundry operation would be spread over a smaller number of castings. (Burnham, No. 60 at p. 17)
DOE notes that the standard level set for gas-fired hot water boilers still allows for the use of cast iron heat exchanger designs. DOE does not anticipate a reduction in shipments for this product class as a result of new standards. Therefore, DOE does not anticipate an increase cost for oil-fired and steam product classes.
In the final rule analysis, DOE revised the cost model assumptions it used for the NOPR analysis based on updated pricing information (for raw materials and purchased parts). These changes resulted in refined MPCs and production cost percentages. Table IV.14 through Table IV.17 present DOE's estimates of the MPCs by AFUE efficiency level for this rulemaking.
Table IV.18 through Table IV.23 present DOE's estimates of the MPCs at each standby mode and off mode efficiency level for this rulemaking.
Chapter 5 of the final rule TSD presents more information regarding the development of DOE's estimates of the MPCs for this rulemaking.
The result of the engineering analysis is a cost-efficiency relationship. DOE created cost-efficiency curves representing the cost-efficiency relationship for each product class that it examined. To develop the cost-efficiency relationships for residential boilers, DOE examined the cost differential to move from one efficiency level to the next for each manufacturer. DOE used the results of teardowns on a market-share-weighted average basis to determine the industry average cost increase to move from one efficiency level to the next. Additional details on how DOE developed the cost-efficiency relationships and related results are available in chapter 5 of the final rule TSD, which also presents these cost-efficiency curves in the form of energy efficiency versus MPC.
The results indicate that cost-efficiency relationships are nonlinear. In other words, as efficiency increases, manufacturing becomes more costly. A large cost increase is evident between non-condensing and condensing efficiency levels due to the requirement for a heat exchanger that can withstand corrosive condensate.
To account for manufacturers' non-production costs and profit margin, DOE applies a non-production cost multiplier (the manufacturer markup) to the full MPC. The resulting MSP is generally the price at which the manufacturer can recover all production and non-production costs and earn a profit. To meet new or amended energy conservation standards, manufacturers typically introduce design changes to their product lines that increase manufacturer production costs. Depending on the competitive environment for these particular products, some or all of the increased production costs may be passed from manufacturers to retailers and eventually to consumers in the form of higher purchase prices. As production costs increase, manufacturers typically incur additional overhead. For a profitable business, the MSP should be high enough to recover the full cost of the product (
To calculate the manufacturer markups, DOE used 10–K reports
Throughout the rulemaking process, DOE has sought feedback and insight from interested parties that would improve the information used in its analyses. DOE interviewed manufacturers as a part of the manufacturer impact analysis (see section IV.J.3). During the interviews, DOE sought feedback on all aspects of its analyses for residential boilers. For the engineering analysis, DOE discussed the analytical inputs, assumptions, and estimates, and cost-efficiency curves with residential boiler manufacturers. DOE considered all the information manufacturers provided when refining its analytical inputs and assumptions. However, DOE incorporated equipment and manufacturing process figures into the analysis as averages in order to avoid disclosing sensitive information about individual manufacturers' products or manufacturing processes. More details about the manufacturer interviews are contained in chapter 12 of the final rule TSD.
DOE uses appropriate markups (
Commenting on the NOPR, AHRI stated that based on preliminary survey feedback, contractors only apply a single markup regardless of the product efficiency. (AHRI, Public Meeting Transcript, No. 50 at pp. 71–72) Burnham further stated that AHRI's comments demonstrate that DOE's use of “incremental” markups through the distribution channel has no foundation either in theory or actual practice. Burnham stated that DOE must eliminate the use of incremental markups before it promulgates a new rule for boilers. (Burnham, No. 60 at pp. 19–20)
DOE believes that AHRI's comments on the NOPR referred to more extensive comments that it provided in response to the 2014 NOPR for small, large, and very large commercial package air conditioning and heating equipment. (EERE–2013–BT–STD–0007) In these comments, AHRI included a report that laid out three main arguments: (1) The incremental markup approach relies on an assumption of perfect competition, which is an outdated model of the economy; (2) relatively constant percent gross margins observed in aggregated HVAC industry data imply the use of fixed-percent markups over time; and (3) interview responses from wholesalers and contractors are consistent with the use of fixed-percent markups. ([Docket No. EERE–2013–BT–STD–0007], AHRI, No. 68 at p. 29)
DOE responds to these points as follows:
(1) DOE's incremental markup approach is based on the widely accepted economic view that prices closely reflect marginal costs in competitive markets and in those with a limited degree of concentration. Economic theory permits that an incremental cost can have a markup on it that is different from the markup on the baseline product, and DOE's incremental markup approach follows this assumption. AHRI does not provide sufficient proof that such theory should be abandoned in the case of the HVAC industry.
(2) In examining the relatively constant HVAC percent margin trend and its underlying prices, DOE found that the average inflation-adjusted prices of HVAC products are relatively fixed during this period as well. This set of historical data has no bearing on firm markup behavior under product price increases, such as DOE projects would occur when higher-efficiency products are introduced. If prices are relatively constant, the incremental markup approach will arrive at the same price prediction as applying fixed-percent margin; hence, the historically constant percent margins do not necessarily imply a constant percent margin in the future, especially in the case of increased input prices. DOE evaluated time series margin and price data from three industries that experienced rapidly changing input prices—the LCD television retail market, the U.S. oil and gasoline market, and the U.S. housing market. The results indicate that dollar margins vary across different markets to reflect changes in input price, but the percent margins do not remain fixed over time in any of these industries. Appendix 6B in the final rule TSD describes DOE's findings.
(3) It is not clear whether the interview responses received by AHRI reflect an accurate understanding of DOE's incremental markup approach. In contrast to the characterization of those responses by AHRI, an in-depth interview with an HVAC consultant conducted by DOE indicates that while HVAC contractors aim to maintain fixed percent markups, market pressures force them to reevaluate and adjust markups over time to stay competitive.
DOE concludes that there is not sufficient evidence to support the application of fixed percent markups to the cost increment on efficient equipment. Further discussion is found in section 6.4 and appendix 6B of the final rule TSD. In spite of their efforts to do so, firms in this market generally cannot maintain fixed percent margins in the long run under changing cost conditions. DOE's incremental markup approach allows the part of the cost that is thought to be affected by the standard to scale with the change in manufacturer price.
For the NOPR, DOE characterized three distribution channels to describe how residential boiler products pass from the manufacturer to residential and commercial consumers: (1) Replacement market; (2) new construction, and (3) national accounts.
The new construction distribution channel is characterized as follows:
In the third distribution channel, the manufacturer sells the product to a wholesaler and then to the commercial consumer through a national account:
DOE did not receive any comments on the distribution channels, and used the same distribution channels for the final rule.
To develop markups for the parties involved in the distribution of the product, for the NOPR, DOE utilized several sources, including: (1) The Heating, Air-Conditioning & Refrigeration Distributors International (HARDI) 2012 Profit Report
Commenting on the NOPR, ACCA expressed its concern that DOE used ACCA's 2005 Financial Analysis for the HVACR Contracting Industry Report for its markup analysis because this report is more than a decade old and not a relevant resource. (ACCA, No. 65 at p. 2) In response, DOE only uses the ACCA 2005 Report to derive the ratios of the markup in new construction applications and in replacement applications to the markup for all installations. ACCA's 2005 Financial Analysis is the only public source available that disaggregates HVAC contracting industry into replacement and new construction markets. DOE acknowledges that many financial conditions of the HVAC contracting industry have changed since 2005, but DOE believes that markups would tend to fluctuate in a similar manner for both new construction and replacement applications, and, thus, the ratios for 2005 mentioned above are not likely to change significantly over time. Therefore, DOE continued to use ACCA's 2005 Financial Analysis in the markup analysis for the final rule for this limited purpose.
In addition to the markups, DOE derived State and local taxes from data provided by the Sales Tax Clearinghouse.
Chapter 6 of the final rule TSD provides further detail on the estimation of markups.
The energy use analysis determines the annual energy consumption of residential boilers at different efficiencies in representative U.S. single-family homes, multi-family residences, and commercial buildings, and assesses the energy savings potential of increased boiler efficiency. DOE estimated the annual energy consumption of residential boilers at specified energy efficiency levels across a range of climate zones, building characteristics, and heating applications. The annual energy consumption includes the natural gas, liquid petroleum gas (LPG), oil, and/or electricity use by the boiler for space and water heating. The annual energy consumption of residential boilers is used in subsequent analyses, including the LCC and PBP analysis and the national impacts analysis.
For the NOPR, for the residential sector, DOE used the Energy Information Administration's (EIA) 2009 Residential Energy Consumption Survey (RECS 2009) to establish a sample of households using residential boilers for each boiler product class.
Commenting on the NOPR, AHRI stated that it appears that DOE significantly overestimated the number of buildings that use a residential boiler for space heating, as RECS 2009 indicates 11 million housing units use a gas-fired or oil-fired hydronic heating system, and not 16.6 million as shown in the NOPR TSD. (AHRI, No. 64 at p. 10) In response, it appears that AHRI is referring to Table 7.2.1 in the NOPR TSD, which shows the number of RECS records (and the corresponding number of houses represented by those records) used for each boiler product class. The total of these records and corresponding number of houses is not an estimate of the number of buildings that use a residential boiler for space heating. In fact, the total is not relevant in any way. Because RECS 2009 does not report the heating medium (hot water or steam), DOE used samples for hot water and steam boiler product classes that include all houses that might use either hot water or steam. For steam boilers in particular, this results in a sample size that represents many more houses than actually use steam boilers.
DOE accounted for applications of residential boilers in commercial buildings because the intent of the analysis of consumer impacts is to capture the full range of usage conditions for these products. DOE considers the definition of “residential boiler” to be limited only by its capacity.
AHRI stated that an analysis that uses national data is not adequately evaluating the market for residential boilers in the U.S., which is concentrated in the Northeast and in older homes, and for which national average statistics are not representative. (AHRI, No. 64 at p. 10) In response, DOE is well aware of the regionality of the residential boiler market. The LCC analysis does not select buildings across the nation at random, but rather selects the homes and buildings reported by RECS 2009 and CBECS 2003 that have residential boilers; the RECS 2009- and CBECS 2003-derived sample reflects the actual distribution of residential gas-fired or oil-fired boilers in the U.S., and the weighting of the samples is adjusted to match the shipments by State from 2008–2012 provided by AHRI.
For the NOPR, to estimate the annual energy consumption of boilers meeting higher efficiency levels, DOE first calculated the heating load based on the RECS and CBECS estimates of the annual energy consumption of the boiler for each household. DOE estimated the house heating load by reference to the existing boiler's characteristics, specifically its capacity and efficiency (AFUE), as well as by the heat generated from the electrical components. DOE used an oversize factor of 0.7 (
Commenting on the NOPR, AHRI stated that DOE's average annual energy use estimates (95.3 MMBtu/year for gas-fired hot water boilers, 98.1 MMBtu/year for gas-fired steam boilers, 98.1 MMBtu/year for oil-fired hot water boilers, 99.9 MMBtu/year for oil-fired steam boilers) are almost twice the RECS national average annual space heating energy consumption for housing units using natural gas of 51.4 million Btus and almost 40 percent higher than the RECS national average annual space heating energy consumption for housing units using fuel oil of 70.3 million Btus. (AHRI, No. 64 at p. 12)
The primary reasons for the differences between the national RECS result and DOE's estimates are: (1) DOE's analysis recognizes that the boilers are mostly installed in colder climates, and (2) DOE accounts for residential boilers in commercial buildings. Since boilers are mostly installed in colder climates, the average energy use of boilers is significantly higher than the average space heating national energy use. Based on 2008–2012 AHRI shipments data by State and RECS 2009 households, almost 70 percent of gas-fired boilers and 90 percent of oil-fired boilers are installed in the Northeast. In 2009, based on RECS 2009 and 2008–2012 AHRI shipments data, the average annual space heating energy consumption is 75.8 MMBtu/yr for housing units with gas-fired hot water boilers. For the NOPR, DOE assumed that 7 percent of residential boilers are installed in commercial applications. In 2003, based on CBECS 2003 data and 2008–2012 AHRI shipments data, DOE estimated that average annual space heating energy consumption is 356.8 MMBtu/yr for buildings with gas-fired hot water boilers. The resulting weighted average results are 95.3 MMBtu/yr for buildings with gas-fired hot water boilers. For the NOPR and final rule, these numbers are adjusted to take into account: 2008–2012 AHRI shipments data by State, typical heating degree days (HDD) for an average year, HDD trends, building shell efficiency, number of boilers per household or building, automatic means, and secondary heating equipment. Based on these adjustments, for the final rule, DOE estimated that the average annual shipment-weighted energy use is 56.7 MMBtu/yr for gas-fired hot water boilers in residential applications and 205.9 MMBtu/yr in commercial applications in 2021 (or 68.6 MMBtu/yr for both residential and commercial buildings). For gas-fired hot water boilers, the 2021 estimates are about 30 percent lower than the estimated values in RECS 2009 or CBECS 2003. The results for the other boiler product classes are similar. See chapter 7 of the final rule TSD for more details about the energy use methodology and results.
Commenting on the NOPR, Energy Kinetics stated that DOE should use both the 0.7 oversizing factor and the demonstrated oversizing factors between three and four used in the NODA for the installed base of equipment. (Energy Kinetics, No. 52 at p. 3) DOE agrees that the oversize factor varies for each household. For the final rule, DOE revised the equipment sizing criteria to match historical shipments by capacity, which accounts for the variability of the oversize factor found in the field.
DOE adjusted the energy use to normalize for weather by using long-term heating degree-day (HDD) data for each geographical region.
AHRI questioned the applicability of the building shell efficiency index to multi-family or row houses with shared walls. (AHRI, Public Meeting Transcript, No. 50 at p. 83) In response, the
For the NOPR, DOE accounted for boiler operational efficiency in specific installations by adjusting the AFUE of the sampled boiler based on an average system return water temperature. The criteria used to determine the return water temperature of the boiler system included consideration of building vintage, product type (condensing or non-condensing, single-stage or modulating), and whether the boiler employed an automatic means for adjusting water temperature. Using product type and system return water temperature, DOE developed and applied the AFUE adjustments based on average heating season return water temperatures.
Commenting on the NOPR, Burnham tested a condensing gas boiler and a non-condensing oil boiler to determine the impact of return water temperature on boiler efficiency. Burnham stated that, based on its test results, DOE is overstating the impact of water temperature on both gas-fired and oil-fired non-condensing boilers. Burnham recommended that the correction factor for non-condensing boilers should be about half that estimated by DOE for the NOPR (which was 1 percent). (Burnham, No. 60 at pp. 21–22) For condensing boilers, Burnham stated that DOE's assumed 2.5-percent reduction to adjust for return water temperature is low, especially at 92-percent and 96-percent AFUE, where the reduction is probably more like 4.5 percent and 6.5 percent, respectively. (Burnham, No. 60 at p. 66)
For the final rule, for non-condensing boilers, DOE used the data provided by Burnham to determine the impact of return water temperature on boiler efficiency. To determine the adjustment for condensing boilers, DOE collected data on several more model series in addition to the data provided by Burnham, which appear to refer to a 91-percent AFUE boiler and to show a decrease of approximately 3.3 to 3.5 percent in efficiency for boilers operating with return water temperatures between 120 and 140 °F. The other sources indicate a lower decrease than the data on a single Burnham boiler. Based upon all of the data, DOE estimated a reduction in efficiency of about 2.1 percent for condensing boilers. Regarding Burnham's comment that the reduction is higher at 92-percent and 96-percent AFUE, DOE did not find sufficient evidence to justify varying the percent decrease by AFUE. See appendix 7B of the final rule TSD for additional details.
For the NOPR, DOE incorporated the impact of automatic temperature reset means on boiler energy use by adjusting AFUE based on a reduction in average return water temperature (RWT). DOE calculated the reduction in average RWT for single-stage boilers based on the duration of burner operating hours at reduced RWT. For modulating boilers, DOE used the average relationship
AHRI stated that DOE's underestimated the benefit of the “automatic means” that is now provided with residential boilers. AHRI acknowledged that the TSD provides the calculation for adjusting the AFUE to account for the benefit of the automatic means; however, the adjustment for single-stage non-condensing boilers results in only a 0.05-percent AFUE improvement, which is based on the improvement of steady-state efficiency with a 2 °F reduction of the return water temperature. According to AHRI, studies have shown that this device or control feature does reduce the energy consumption of boilers in the field. A conservative estimate of the savings from automatic means would be 5 percent, but a more realistic range is 5 to 8 percent. (AHRI, No. 64 at p. 12)
DOE found that the majority of single-stage products sampled utilized a pre-purge control function that allows the purging of residual heat within the boiler prior to ignition of the burner. DOE also found that the majority of boiler models sampled incorporate a time limit and a low temperature limit function within the control strategy. The time limits range from two to three minutes (by default), with some boilers allowing for user-defined durations. DOE's research has shown that there is limited field and test data on the effectiveness of the pre-purge technology, which is the primary technology in single-stage non-condensing boilers to implement the automatic means design requirement. Based on the logic described in appendix 7B of the final rule TSD, the impact on boiler steady-state efficiency appears to be small. In its analysis, DOE accounts for the variability of idle losses during the non-heating season, which already takes into account for some automatic means improvements from different technologies (
For the NOPR, DOE also accounted for jacket losses when the boiler is located in a non-conditioned space (
AHRI stated that DOE assumes that 35 percent of residential gas-fired boilers and 53 percent of residential oil-fired boilers are installed in unconditioned spaces. AHRI questioned the validity of these estimates, since most boilers in homes in the Northeast Census region are installed in unconditioned basements that are part of the home, which still adds heat to the interior of
DOE estimates the location of the boiler based on the household characteristics in the RECS 2009 housing sample.
DOE is aware that some residential boilers have the ability to provide both space heating and domestic water heating, and that these products are widely available and may vary greatly in design. For these applications, DOE accounted for the boiler energy used for domestic water heating, which is part of the total annual boiler energy use. For the NOPR, DOE used the RECS 2009 and/or CBECS 2003 data to identify households or buildings with boilers that use the same fuel type for space and water heating, and then assumed that a fraction of these identified households/buildings use the boiler for both applications.
Burnham stated that gas-fired steam boilers are seldom used to make domestic hot water due to technological challenges, and gas-fired steam boilers that can produce domestic hot water are not readily available in the market. Burnham believes that the fraction of gas-fired steam boilers used to make domestic hot water is less than 10 percent of all such boilers. Burnham stated that there is greater incentive to use oil-fired steam boilers to also make domestic hot water, in order to eliminate the additional maintenance and potential fuel piping complexities of a second oil burner. (Burnham, No. 60 at pp. 22–24, 66) For the final rule, based on AHRI's contractor survey, DOE assumed that 5 percent of gas-fired steam boilers and 10 percent of oil-fired steam boilers are used to make domestic hot water.
For the NOPR, to calculate the annual water-heating energy use for each boiler efficiency level, DOE first calculated the water-heating load by multiplying the annual fuel consumption for water heating (derived from RECS or CBECS) by the recovery efficiency for water heating of the existing boiler, which was calculated based on an adjustment to AFUE. DOE then calculated the boiler energy use for each efficiency level by multiplying the water-heating load by the recovery efficiency of the selected efficiency level.
Commenting on the NOPR, AHRI stated that the average water heating energy use values seem high. (AHRI, Public Meeting Transcript, No. 50 at p. 114) In response, the water heating energy use is higher for the boiler sample than the national average because boilers are primarily located in the northeast, with colder inlet water and colder ambient temperature. In addition, the NOPR-reported value included idle losses and commercial applications, which comprise seven percent of the entire boiler sample and use significantly more hot water than residential households.
Idle loss, as the term applies to residential heating boilers, is heat wasted when the burner is not firing. The idle losses are the heat from combustion that is not transferred to the heating of water, including the products of combustion up the flue, the loss out of the heat exchanger walls and boiler's jacket (in the form of radiant, conductive, or convective transfer), and the loss down the drain as a condensate. Because no fuel is being consumed in the off-cycle, off-cycle losses are important only to the extent that they must be replaced during the on-cycle by the burning of extra fuel (
For the NOPR analysis, DOE accounted for idle losses during non-space heating operation based on the installation location of the boiler (conditioned or unconditioned space), type of boiler (high mass or low mass), and whether or not the boiler served domestic hot water loads. For boilers that serve only space heating loads, the idle losses are accounted for in the heating season efficiency. For boilers that provided domestic hot water heating, idle losses occur in both heating and non-heating seasons. These idle losses were accounted for by applying heat loss values to the boiler and storage tank (when necessary) for a fraction of the off-cycle time. DOE also accounted for the losses for boilers that are installed with indirect tanks or tankless coils.
Energy Kinetics and PHCC stated that for non-condensing boilers, increasing the heat exchanger area to increase efficiency will add mass to the boiler, thereby increasing the idle loss of the system. Energy Kinetics stated that this significantly impacts the actual annual efficiency, and PHCC further elaborated that the increased losses could offset the operating efficiency gains. (Energy Kinetics, Public Meeting Transcript, No. 50 at p. 286; PHCC, No. 61 at p. 1)
For non-condensing boilers, DOE assumes that the idle loss does not necessarily increase with increased efficiency, based upon DOE's models series at different efficiency and available test data.
For the NOPR, DOE calculated boiler electricity consumption for the circulating pump, the draft inducer,
Commenting on the NOPR, Weil-McLain and Burnham stated that boilers at 85-percent AFUE are likely to require mechanical draft assistance, which would increase electricity use. (Weil-McLain, No. 55 at pp. 2–3; Burnham, No. 60 at p. 25) As stated in section IV.F.2, for the final rule, DOE revised the mechanical draft fractions for 85-percent AFUE gas-fired hot water boilers based on shipments data from Burnham, AHRI's contractor survey, and the updated reduced set of residential boiler models (hereinafter referred to as the “reduced set”; see appendix 7D of the final rule TSD for details). (
Burnham stated that natural draft burner systems generally use a 40VA transformer to power the burner and controls, rendering DOE's estimate of 40W for non-condensing gas-fired hot water boilers and gas-fired steam boilers very conservative. (Burnham, No. 60 at p. 66) For the final rule, DOE revised the boiler power use estimates based on the updated reduced set of residential boiler models, which resulted in an estimate of 92 W for non-condensing gas-fired hot water boilers and 84 W for non-condensing gas-fired steam boilers.
Burnham stated that all oil-fired boilers are equipped with a fan as part of burner, so it is unclear what model DOE would consider an oil-fired boiler without an induced/forced draft. (Burnham, No. 60 at p. 24) For the final rule, DOE agrees that all oil-fired boilers are equipped with burner fans and revised the boiler power use estimates to include the burner fan electricity.
Burnham stated that DOE's analysis failed to recognize that condensing boilers typically have a separate pump to circulate water through the boiler's heat exchanger in addition to the pump used to circulate water through the heating system. (Burnham, No. 60 at p. 24, 66) In addition, Burnham stated that the power consumption for the boiler pump should be at least 160W. (Burnham, No. 60 at p. 24) For the final rule, for condensing boilers, DOE included the electricity use of both a boiler pump and circulating pump. DOE maintained the NOPR assumption that the circulating pump uses 80W. The engineering analysis determined that the most commonly used boiler pumps (
Lochinvar stated that the DOE erroneously presumes that standby power consumption is lost energy, but because boilers are typically installed inside homes, standby power consumption is converted into heat that is transmitted into the home. In contrast, Lochinvar stated that off mode power consumption should be considered a loss because there is likely no need for heating when the boiler is in off mode. (Lochinvar, No. 63 at pp. 2–3) For the final rule, DOE assumed that a fraction of standby power used by boilers installed indoors contributes to heating the home during the heating season. DOE agrees that off mode energy use does not contribute to heating the home.
For the NOPR, DOE accounted for the impact of water heating energy use during the non-heating season on air conditioner (AC) electricity use for boilers installed in conditioned spaces. DOE assumed that only boilers installed in indoor spaces impact the cooling load and that a fraction of this electricity use impacts the cooling load. EEI stated that if the boiler is not located near the thermostat, it will not have an impact on the cooling load, especially because the heat losses of the boiler are miniscule compared to the cooling load. (EEI, Public Meeting Transcript, No. 50 at p. 120) In NOPR and in the final rule, DOE assumed that about half of the energy use losses related water heating by the boiler as impacting cooling load to account boiler installation location, distance from thermostat, and non-coincidental loads.
DOE calculated boiler standby mode and off mode electricity consumption for times when the boiler is not in use for each efficiency level identified in the engineering analysis for standby mode and off mode standards. DOE calculated boiler standby mode and off mode electricity consumption by multiplying the power consumption at each efficiency level by the number of standby mode and off mode hours. To calculate the annual number of standby mode and off mode hours for each sample household, DOE subtracted the estimated total burner operating hours (for both space heating and water heating) from the total hours in a year (8,760). Details of the method are provided in chapter 7 of the final rule TSD.
DOE conducted LCC and PBP analyses to evaluate the economic impacts on individual consumers of potential energy conservation standards for residential boilers. The effect of new or amended energy conservation standards on individual consumers usually involves a reduction in operating cost and an increase in purchase cost. DOE used the following two metrics to measure consumer impacts:
• The LCC (life-cycle cost) is the total consumer expense of an appliance or product over the life of that product, consisting of total installed cost (manufacturer selling price, distribution chain markups, sales tax, and installation costs) plus operating costs (expenses for energy use, maintenance, and repair). To compute the operating costs, DOE discounts future operating costs to the time of purchase and sums them over the lifetime of the product.
• The PBP (payback period) is the estimated amount of time (in years) it takes consumers to recover the increased purchase cost (including installation) of a more-efficient product
For any given efficiency level, DOE measures the change in LCC relative to the LCC in the no-new-standards case, which reflects the estimated efficiency distribution of residential boilers in the absence of new or amended energy conservation standards. In contrast, the PBP for a given efficiency level is measured relative to the baseline product.
For each considered efficiency level in each product class, DOE calculated the LCC and PBP for a nationally representative set of housing units and commercial buildings. As stated previously, DOE developed household and building samples from the RECS 2009 and CBECS 2003. For each sample building, DOE determined the energy consumption for the residential boilers and the appropriate energy prices. By developing a representative sample of buildings, the analysis captured the variability in energy consumption and energy prices associated with the use of residential boilers.
Inputs to the calculation of total installed cost include the cost of the product—which includes MPCs, manufacturer markups, retailer and distributor markups, and sales taxes—and installation costs. Inputs to the calculation of operating expenses include annual energy consumption, energy prices and price projections, repair and maintenance costs, product lifetimes, and discount rates. DOE created distributions of values for product lifetime, discount rates, and sales taxes, with probabilities attached to each value, to account for their uncertainty and variability.
DOE conducts a stochastic analysis that employs a computer spreadsheet model to calculate the LCC and PBP, which incorporates Crystal Ball
Commenting on the NOPR, AHRI stated that information from a recently completed study conducted by the Gas Technology Institute (GTI)
In response, the method used to estimate the boiler efficiency that a given sample household would choose in the no-new-standards case is not entirely random. For gas boilers, DOE assigned a higher fraction of condensing boilers to regions with a higher fraction of condensing shipments, as reported in the shipments data. That is, the method assumes that the factors that currently cause consumers to choose condensing boilers in specific areas will continue to operate in the future. Development of a complete consumer choice model for boiler efficiency would require data that are not currently available, as well as recognition of the various factors that impact the purchasing decision, such as incentives, the value that some consumers place on efficiency apart from economics (
DOE calculated the LCC and PBP for all consumers of residential boilers as if each were to purchase a new product in the expected year of required compliance with amended standards. Any amended standards would apply to residential boilers manufactured 5 years after the date on which any amended standard is published.
As noted above, DOE's LCC and PBP analyses generate values that calculate the payback period for consumers under potential energy conservation standards, which includes, but is not limited to, the three-year payback period contemplated under the rebuttable presumption test. However, DOE routinely conducts a full economic analysis that considers the full range of impacts, including those to the consumer, manufacturer, Nation, and environment, as required under 42 U.S.C. 6295(o)(2)(B)(i). The results of this analysis serve as the basis for DOE to definitively evaluate the economic justification for a potential standard level (thereby supporting or rebutting the results of any preliminary determination of economic justification).
Table IV.24 summarizes the approach and data DOE used to derive inputs to the LCC and PBP calculations. The subsections that follow provide further discussion. Details of the spreadsheet model, and of all the inputs to the LCC and PBP analyses, are contained in chapter 8 of the final rule TSD and its appendices.
To calculate consumer product costs, DOE multiplied the MPCs developed in the engineering analysis by the markups described in section IV.D (along with sales taxes). DOE used different markups for baseline products and higher-efficiency products, because DOE applies an incremental markup to the increase in MSP associated with higher-efficiency products.
To project future product prices, DOE considered the historic trend in the Producer Price Index (PPI) for cast iron heating boilers and steel heating boilers
Installation cost includes labor, overhead, and any miscellaneous materials and parts needed to install the product, such as venting and piping modifications and condensate disposal that might be required when installing products at various efficiency levels. DOE estimated the costs associated with installing a boiler in a new housing unit or as a replacement for an existing boiler.
For the NOPR, DOE calculated the basic installation cost, which is applicable to both replacement and new construction boiler installations and includes the cost of putting in place and setting up the boiler, permitting, and removal or disposal fees.
For the NOPR, DOE considered additional costs (“adders”) for a fraction of replacement installations of non-condensing and condensing boilers. These additional costs may account for chimney relining, updating of flue vent connectors, vent resizing, and the costs for a stainless steel vent, if required. Each of these cost adders is discussed in further detail below.
To determine the installations that would require chimney relining upon boiler replacement, DOE assumed for the NOPR that all boilers that were installed before 1995, the year that the National Fuel Gas Code (the first building code to require chimney lining) was established for all buildings built before 1995, would require relining upon boiler replacement in 2020.
Commenting on the NOPR, for the replacement of a non-condensing boiler with another non-condensing boiler, Crown Boiler stated that the National Fuel Gas Code (NFGC) does not always require relining indoor terracotta chimneys for all efficiency levels, and assuming that all boilers installed in homes built before 1995 or replaced before 1995 require relining upon replacement is incorrect and overstates the cost of a non-condensing boiler replacement. (Crown Boiler, Public Meeting Transcript, No. 50 at pp. 163–164, 197) Weil-McLain and AHRI stated that section 12.6.4.2 of the NFGC does not require chimneys to be relined when an appliance is replaced by an appliance of similar type. Therefore, the majority of boiler replacements involving a non-condensing cast iron boiler being replaced with the same type of equipment would not have included chimney relining, regardless of whether such replacement occurred prior to or after 1995. (Weil-McLain, No. 55 at p. 5; AHRI, No. 64 at p. 11)
For the final rule, DOE did not change its methodology to determine the fraction of unlined chimneys that would require relining applied in the NOPR analysis. Similar to the NOPR, DOE estimated that only 6 percent of all replacement boiler installations in 2021 would require relining of unlined chimneys, which overall seems to coincide with stakeholder input regarding the fraction of non-condensing replacement installations requiring venting modifications. Regarding the comments by Weil-McLain and AHRI, DOE notes that the exception in section 12.6.4.2 of the NFGC states that existing chimneys shall be permitted to have their use continued when an appliance is replaced by an appliance of similar type, input rating, and efficiency. However, DOE has concluded that many of the current non-condensing boiler designs (82-percent to 83-percent AFUE) cannot be considered to be of similar input rating and efficiency compared to old boilers below 80-percent AFUE that were primarily installed before 1992. Furthermore, DOE notes that section 12.6.4.4 of the NFGC states that “When inspection revels that an existing chimney is not safe for the intended application, it shall be repaired, rebuilt, relined, or replaced with a vent or chimney to conform to National Fire Protection Association (NFPA) 211.”
Weil-McLain stated that DOE used incorrect assumptions to calculate the percentage of households with an unlined chimney and the percentage of masonry chimneys that would need to be relined in 2021, because DOE incorrectly applied the NFGC in determining the number of relined chimneys. Weil-McLain also stated that there are significantly more households with a boiler in the north than in the south; therefore, using a midpoint between the percentages assigned to the north and to the south significantly underestimates the actual percentage of households with unlined chimneys. (Weil-McLain, No. 55 at p. 5)
DOE did not apply a national average fraction to determine the number of chimneys that would need to be relined in 2021. Rather, DOE used regional fractions of the number of masonry chimneys and the age of each individual boiler to determine whether a chimney would need to be relined in 2021. For both the NOPR and the final rule, DOE assumed that 73 percent of buildings in the Northeast, 53 percent of buildings in the Midwest, 10 percent of buildings in the South, and 27 percent of buildings in the West have masonry chimneys.
For the NOPR, DOE assumed that any chimney relining would require an aluminum liner. Burnham questioned whether the unit costs DOE used for double wall kit “aluminum liners” are actually for “all fuel” stainless steel liner kits (which are appropriate for oil-fired boilers). (Burnham, No. 60 at p. 26) For the NOPR, DOE used an average cost of different liners, including double wall kit “aluminum liners” that are actually for “all fuel” stainless steel liner kits. Burnham also stated that DOE does not need to extrapolate costs for 5″ and 6″ liners, as costs that better reflect true market costs are provided by DOE's data source.
For the final rule, DOE updated its liner prices for different liner types and sizes (including 5″ and 6″) from the mentioned data source. It also applied the “aluminum liner” kit costs to Category I non-condensing gas-fired boilers and AL29–4C stainless steel liner kit costs to Category III non-condensing gas-fired boilers to meet the requirements of each venting category.
Burnham stated that DOE erroneously assumed that aluminum would be used as the liner material for oil-fired boilers, when it should be stainless steel. Burnham provided the cost for stainless steel liner systems for use with fuel oil from DOE's online vent source.
(2)
For the NOPR, to determine the venting installation costs, DOE considered vent categories as defined in the National Fuel Gas Code. DOE determined that all natural draft boilers and a fraction of mechanical draft boilers would be vented as a Category I appliance (negative pressure vent system with high temperature flue gases). DOE determined that the remaining fraction of mechanical draft boilers would be vented as a Category III appliance (positive pressure vent system with high temperature flue gases). DOE determined that very few non-condensing would be installed as a Category II appliance (negative pressure vent system with low temperature flue gases) or a Category IV appliance (positive pressure vent system with low flue gases temperatures). However, DOE determined that all condensing installations would be vented as a Category IV appliance.
DOE included additional venting cost associated with Category III stainless steel venting for a fraction of non-condensing installations that require such venting. Such inclusion addresses potential safety concerns by preventing the corrosive impacts of condensation in the venting system. Because use of an inducer or forced draft fan is associated with conditions under which stainless steel venting is necessary to avoid condensation in some cases, DOE based the fraction of boilers requiring stainless steel venting on the percentage of models with inducer or forced draft fans in the AHRI directory
Commenting on the NOPR, Weil-McLain, Burnham, AGA/APGA and PGW stated that replacement of existing non-condensing boilers (installed with current venting systems) with near-condensing boilers that do not use an inducer or forced draft fan requires Category II venting, because such units operate with a non-positive vent static pressure and with vent gas temperature that may cause excessive condensate production in the vent. Such venting uses materials (such as stainless steel alloy, AL29–4C) that can resist the corrosive nature of the condensate. (Weil-McLain, No. 55 at pp. 1–2, 4; Burnham, No. 60 at p. 9; AGA and APGA, No. 54 at p. 2; PGW, No. 57 at p. 1)
For the final rule, DOE estimated that in cases of replacement with near-condensing gas-fired boilers (85–89 percent AFUE), instead of using Category II stainless steel venting, installers would use Category III stainless steel venting with mechanical draft.
Burnham stated that the ANSI Z223.1 code defers to the manufacturer's installation and operation manual for Category II, III, and IV boilers. If the boiler has ANSI Z21.13 certification, the boiler manufacturer must either supply or specify venting materials meeting certain requirements for corrosion resistance and/or gas tightness in its manual. For Category II, III, and IV non-condensing boilers, the most common method of meeting this requirement is to specify the AL29–4C stainless steel special gas vent. (Burnham, No. 60 at p. 10) Burnham found from its review of 61 models in the AHRI directory that almost all non-condensing, non-Category I boilers are vented with an AL29–4C special gas vent, which increases the installation cost of these products. (Burnham, No. 60 at p. 27) For the NOPR and final rule, as stated
Burnham stated that horizontal venting of a Category III or IV gas-fired boiler at 85-percent AFUE is limited by safety codes, building codes, I&O manuals, location of surrounding buildings, and limited access to an eligible exterior wall. It noted that this is particularly a problem in urban areas with homes that are closely spaced. Burnham stated that in cases where horizontal venting is impossible, it may be unreasonably expensive to use the old chimney as a chase for a special gas vent system. (Burnham, No. 60 at pp. 14–15) PGW stated that the installation of Category II and IV venting systems presents particular problems in Philadelphia's 400,000 row houses because replacing a boiler will require a new venting system, including abandonment of the existing venting system, structural changes to accommodate a new venting system path, and relocation of the boiler to meet the code and installation requirements of a new condensing boiler system. (PGW, No. 57 at p. 2) In addition, Burnham stated that conversion from a non-condensing Category I boiler to a non-condensing or condensing Category II, III, or IV boiler can result in an orphaned water heater. Burnham stated that if there is no way to horizontally vent the new boiler, and if the old chimney is used as a chase for the special vent system, the water heater and any other appliances vented into that chimney will need to be removed. Burnham stated that DOE needs to include the additional installation costs associated with complete replacement of “orphaned water heaters” for a fraction of installations. (Burnham, No. 60 at p. 28)
DOE acknowledges that a small fraction of replacement installations may be difficult, but DOE does not believe that the difficulties are insurmountable. DOE's analysis accounts for additional costs for those installations that would require re-routing of the vent system for Category III non-condensing boilers and Category IV condensing boilers to account for the limitations described by Burnham and PGW. The analysis does not include installations that would require the use of existing chimneys in lieu of horizontal venting, but rather included the cost for longer vent runs. DOE notes that in response to the NOPR for the current residential furnaces rulemaking, the American Council for an Energy-Efficient Economy (ACEEE) stated that the Energy Coordinating Agency, a major weatherization program in Philadelphia that has installed many condensing furnaces in row houses, has developed moderate cost solutions (at most $350) to common problems such as having no place to horizontally vent directly from the basement. ([Docket No. EERE–2014–BT–STD–0031], ACEEE, No. 113 at p. 7) Both in the NOPR and final rule, DOE accounted for a fraction of installations that would require chimney relining or vent resizing for the orphaned water heater. DOE did not consider the complete replacement of the orphaned water heater, but instead added additional installation costs associated with venting of the Category III or IV boiler, so that the orphaned water heater could be vented through the chimney.
Boilers that use mechanical draft (Category I) are required to meet the NFGC venting requirements, while Category III systems require mechanical draft and stainless steel venting. Burnham and Weil-McLain stated that DOE overstated the market share of units that use mechanical draft (Category I or III) because DOE used number of models instead of shipments. (Burnham, No. 60 at pp. 24–25; Weil-McLain, No. 55 at p. 5) In addition to data on models from the AHRI directory, for the final rule, DOE also used shipments data from Burnham and AHRI's contractor survey to estimate the share of installations that would use mechanical draft. (AHRI, No. 67) For the final rule, DOE also took into account a fraction of mechanical draft (Category I) gas-fired boilers that would need the vents to be resized to meet the NFGC venting requirements.
Weil-McLain stated that the vast majority of near-condensing gas-fired boilers
For the final rule, DOE used shipments data from Burnham
Commenting on the NOPR, Burnham stated that in addition to straight pipes, the installation manuals of the models in the AHRI directory require at least one other fitting (90 degree elbow) in almost all Category III/IV installations. (Burnham, No. 60 at p. 28) For the NOPR and the final rule, DOE accounted for other fittings, such as a 90 degree elbow, for all venting installations.
For the NOPR, the additional installation costs for condensing boilers in replacement installations included new either 2-inch or 3-inch polyvinyl chloride (PVC), polypropylene (PP), or chlorinated polyvinyl chloride (CPVC) combustion air venting for direct vent installations (PVC); concealing vent pipes for indoor installations, addressing an orphaned water heater (by updating flue vent connectors, vent resizing, or chimney relining), and condensate removal.
Weil-McLain stated that with a Category IV boiler, the venting system must be able to handle positive pressure. This often eliminates the ability for the boiler to continue to use the same chimney as other appliances, which makes a retrofit with such an appliance all the more costly to the
Commenting on the NOPR, Burnham reviewed 44 condensing boiler models in the AHRI directory and found that most of the units with an input capacity of 100 MBH use 3-inch venting. Burnham stated that if DOE uses a representative gas-fired hot water boiler input capacity of 120 MBH as it recommends, the use of 3-inch venting is almost universal. (Burnham, No. 60 at p. 28) AHRI stated that after a certain input level, the standard PVC pipe in the vent system will be 3 inches. (AHRI, Public Meeting Transcript, No. 50 at p. 168) Crown Boiler added that with input rates at the upper limit of the residential range, some condensing boilers may need 4-inch vents. (Crown Boiler, Public Meeting Transcript, No. 50 at p. 169) For the final rule, DOE assumed that most condensing boilers use 3-inch PVC, PP, or CPVC pipes, and those at the highest capacities use 4-inch vents.
The Advocates encouraged DOE to incorporate the lower-cost DuraVent technologies in the analysis, and more broadly to consider innovative installation technology that would likely emerge with increasing experience and learning. The Advocates stated that the DuraVent technology can help address difficult installation situations with condensing boilers by allowing for venting both a new condensing boiler and an existing atmospheric water heater through the existing chimney. (The Advocates, No. 62 at p. 2) DOE did not include lower-cost venting solutions for condensing boilers because these technologies are still immature.
In the NOPR and final rule, DOE added condensate withdrawal costs for condensing boilers. Burnham stated that according to the I&O manuals of the boilers it examined, the vast majority of Category II, III, and IV vent systems require a means of disposing of condensate for non-condensing boilers, which DOE did not account for in its installation cost calculations. (Burnham, No. 60 at p. 28) Lochinvar stated that even non-condensing boilers will condense when the heat exchanger is cold. Lochinvar also stated that automatic means measures extend the time that heat exchangers are exposed to condensate, and increases the potential for condensate-related problems. (Lochinvar, No. 63 at pp. 2–3)
For the final rule, based on a review of installation manuals, DOE assumed that 75 percent of non-condensing mechanical draft category III boilers require condensate collection. DOE accounted for condensate issues in the venting by including a condensate trap and piping to either a collector or drain. DOE has determined that these measures also address the impact of automatic means as part of the overall condensate collection process.
For the NOPR, DOE assumed that the circulating pump and boiler pump are provided by the manufacturer, and, therefore, included the cost of both pumps as part of the product cost. Commenting on the NOPR, Burnham stated that in some cases, neither the circulation pump nor the boiler pump are supplied with the boiler, thereby increasing the installation cost. Burnham added that a second ramification of the need for two pumps are the associated piping requirements. In most cases, this piping is not supplied with the boiler and must be fabricated by the installer, which results in an additional cost. Burnham estimated that the contractor's cost associated with the second (boiler) pump and the piping is $239. (Burnham, No. 60 at pp. 29–31) For the final rule, DOE assumed that neither the circulation pump nor the boiler pump is supplied with the boiler. DOE included the installation of the secondary and primary piping 75 percent of the time for condensing boiler installations.
Burnham stated that 35 percent of the condensing gas-fired hot water boiler models it investigated requires a Y strainer. Burnham estimated that the contractor's cost of a 1-inch Y strainer is $45. (Burnham, No. 60 at pp. 29–31) For the final rule, DOE included the cost of a Y-strainer for one-third of condensing boiler installations based on a review of condensing model installation manuals, with an average installed cost of $48 (including labor and parts) from RS Means 2015.
DOE also included installation adders for new construction, as well as for new owner installations for hot water gas-fired boilers. For non-condensing boilers, the only adder is a new metal flue vent (including a fraction with stainless steel venting) and condensate withdrawal for a fraction of category III models. For condensing gas boilers, the additional costs for new construction installations related to potential amended standards include a new flue vent, combustion air venting for direct vent installations and accounting for a commonly-vented water heater, and condensate withdrawal.
ACCA stated that its members found the installation cost for gas-fired hot water boilers, regardless of efficiency level or existing venting options, to be nearly twice as high as the average basic installation cost assumed by DOE of $2,741. ACCA stated that, for gas-fired steam boilers, the DOE analysis produced an average basic installation cost of $2,917, but feedback from ACCA's contractors suggest the real costs are twice that amount. ACCA also stated that the same discrepancy applies to both the oil-fired hot water boilers and the oil-fired steam boilers. (ACCA, No. 65 at p. 2)
In response, DOE notes that the basic installation cost, which consists of the installation costs that are common to all boilers, is only part of the total installation cost. In addition to the basic installation cost, the total installation cost includes venting costs and additional costs for condensing boiler installations. For the final rule, DOE's updated installation cost analysis, based on updated RS Means 2015 and stakeholder comments discussed above, resulted in an average total installation cost of $4,288 for a baseline (82-percent AFUE) gas-fired hot water boiler, which is close to the value suggested by ACCA. DOE's value is also close to the $4,500 installation cost for gas-fired hot water boilers (natural draft) from 82.0 to 83.9 percent AFUE in AHRI's contractor survey.
For each sampled building, DOE determined the energy consumption for a residential boiler at different efficiency levels using the approach
DOE considered whether boiler energy use would likely be impacted by a direct rebound effect, which occurs when a product that is made more efficient is used more intensively, such that the expected energy savings from the efficiency improvement may not fully materialize. Such change in behavior when operating costs decline is known as a (direct) rebound effect. The take-back in energy consumption associated with the rebound effect provides consumers with increased value (
For the NOPR, DOE derived 2012 average and marginal monthly residential and commercial natural gas, fuel oil, LPG, and electricity prices using monthly data by State from Energy Information Administration. DOE assigned an appropriate energy price to each household or commercial building in the sample, depending on its location. To do this, DOE used the average 2008–2012 fraction of boiler shipments by State
Commenting on the NOPR, AGA and APGA argued that DOE's method of calculating marginal energy prices overstates the operating cost savings of higher-efficiency boilers. AGA and APGA stated that the marginal prices that AGA derived by deducting the fixed charge portion of the bill from the total bill range from 7 percent to 16 percent lower than the prices developed by DOE. (AGA and APGA, No. 54 at p. 2) Laclede stated that DOE's estimates for what is called “marginal monthly natural gas prices” are much higher than actual marginal prices that customers pay as reflected by impacts in energy consumption changes in their utility bills. (Laclede, No. 58 at p. 3)
In response to similar comments provided on the Residential Furnace notice of proposed rulemaking,
For the NOPR, to estimate energy prices in future years, DOE multiplied the average regional energy prices by the forecast of annual change in national-average residential energy prices in the Reference case from
AHRI and Laclede stated that DOE should use
For a detailed discussion of the development of energy prices, see appendix 8D of the final rule TSD.
Maintenance costs are associated with maintaining the operation of the product. For the NOPR, DOE estimated maintenance costs at each considered efficiency level using a variety of sources, including
For the final rule, DOE update the maintenance cost using the latest
The repair cost is the cost to the consumer for replacing or repairing components in the boiler that have failed (such as ignition, controls, gas valve, and inducer fan). For the NOPR, DOE estimated repair costs at each considered efficiency level using a variety of sources, including
Crown Boiler questioned the applicability of the GRI data from the 1990s on the lifetimes of boiler parts because at that time, there were far fewer condensing boilers. (Crown Boiler, Public Meeting Transcript, No. 50 at p. 207) DOE understands that data from the GRI survey are still representative of the major furnace and boiler components. Further, due to improvements in the components of condensing boilers since the 1990s, the estimated service lifetime applied in DOE's analysis is likely conservative.
Based on typical contractor prices that Burnham collected from wholesalers for six non-condensing models and six condensing models, Burnham found that the cost to repair non-condensing boiler parts (
For more details on DOE's methodology for calculating maintenance and repair costs, see appendix 8E of the final rule TSD.
Product lifetime is the age at which an appliance is retired from service. For the NOPR, DOE conducted an analysis of boiler lifetimes using a combination of historical boiler shipments (see section IV.G), American Housing Survey data on historical stock of boilers,
U.S. Boiler, Crown Boiler, Energy Kinetic, Burnham, Lochinvar, and AHRI stated that condensing boilers generally have a shorter lifetime than non-condensing boilers. Lochinvar, Burnham, Energy Kinetics, and Crown Boiler stated that various sources cite condensing boilers as having a lifetime of 15 years or less. (US Boiler, Public Meeting Transcript, No. 50 at pp. 210–211; Crown Boiler, Public Meeting Transcript, No. 50 at p. 212; Energy Kinetic, No. 52 at p. 2; Burnham, No. 60 at pp. 33–36, pp. 54–55; Lochinvar, No. 63 at p. 4; AHRI, No. 64 at p. 4). Both Burnham and AHRI commented that their contractor surveys show a clear difference between condensing and non-condensing boiler lifetimes. (Burnham, No. 60 at pp. 35–36; AHRI, No. 66 at pp. 17–18) Burnham added that DOE's sources that are specific to condensing boilers
After carefully considering these comments, DOE has concluded that there is not enough data available to accurately distinguish the lifetime of condensing boilers because, as Burnham stated, they have not been prevalent in the U.S. market long enough to demonstrate whether their average lifetime is less than or greater than 15 years. In addition, condensing boiler technologies have been improving since their introduction to the U.S. market; therefore, the lifetime of the earliest condensing boilers may not be representative of current or future condensing boiler designs. Therefore, condensing lifetime results from the Burnham's and AHRI's contractor survey might be biased towards earliest condensing boiler designs and lack the number of condensing boilers installed 15 years or older. Based on the lack of clear and convincing information that condensing boilers have a shorter lifetime, DOE maintained the same
In the calculation of LCC, DOE applies discount rates appropriate to households to estimate the present value of future operating costs. DOE estimated a distribution of residential and commercial discount rates for residential boilers based on consumer financing costs and opportunity cost of funds related to appliance energy cost savings and maintenance costs.
To establish residential discount rates for the LCC analysis, DOE identified all relevant household debt or asset classes in order to approximate a consumer's opportunity cost of funds related to appliance energy cost savings. For the NOPR, it estimated the average percentage shares of the various types of debt and equity by household income group using data from the Federal Reserve Board's Survey of Consumer Finances
To establish commercial discount rates for the LCC analysis, DOE estimated the weighted-average cost of capital using data from Damodaran Online.
EEI stated that it seems counterintuitive that the lowest income group has a lower discount rate than the higher income groups. (EEI, Public Meeting Transcript, No. 50 at p. 214) EEI stated that usually the lower income groups pay the highest interest rates for any sort of credit. (EEI, Public Meeting Transcript, No. 50 at p. 216) In DOE's analysis, the consumer discount rate is used to evaluate the present value of energy cost savings over the lifetime of the boiler. The interest rate on credit alone is not appropriate for this calculation. DOE instead calculates the residential discount rates by estimating the consumer's opportunity cost via a process analogous to the CAPM model used in the commercial sector, in which the discount rate is a weighted average of rates on debt and equity holdings. While consumers in the lowest income group are likely to face somewhat higher interest rates on credit than other income groups, this is balanced by the fact that they also tend to have assets with low interest rates (
For the final rule, DOE included data from the 2013 SCF
To accurately estimate the share of consumers that would be affected by a potential energy conservation standard at a particular efficiency level, DOE's LCC analysis considered the projected distribution (market shares) of product efficiencies that consumers will purchase in the first compliance year under the no-new-standards case (
For the NOPR, DOE first developed data on the current share of residential boiler models in each product class that are of the different efficiencies based on the September 2013 AHRI certification directory,
Commenting on the NOPR, Burnham stated that over the past 12 years, since condensing boilers started to gain significant market share, the sales of gas-fired hot water boiler models with efficiencies between 85 percent and 90 percent have virtually disappeared, even though some models remain in the AHRI directory. (Burnham, No. 60 at p. 17) For the final rule, DOE modified its efficiency distribution in the no-new-
For the NOPR boiler standby mode and off mode standards analysis, DOE assumed that 50 percent of shipments would be at the baseline efficiency level and 50 percent would be at the max-tech efficiency level (EL 3) for all product classes, based on characteristics of available models.
The estimated AFUE market shares for the no-new-standards case for residential boilers are shown in Table IV.25, and estimated standby mode and off mode market shares for the no-new-standards case are shown in Table IV.26.
The payback period is the amount of time it takes the consumer to recover the additional installed cost of more-efficient products, compared to baseline products, through energy cost savings. Payback periods are expressed in years. Payback periods that exceed the life of the product mean that the increased total installed cost is not recovered in reduced operating expenses.
The inputs to the PBP calculation for each efficiency level are the change in total installed cost of the product and the change in the first-year annual operating expenditures relative to the baseline product. The PBP calculation uses the same inputs as the LCC analysis, except that discount rates are not needed.
As noted above, EPCA, as amended, establishes a rebuttable presumption that a standard is economically justified if the Secretary finds that the additional cost to the consumer of purchasing a product complying with an energy conservation standard level will be less than three times the value of the first year's energy savings resulting from the standard, as calculated under the applicable test procedure. (42 U.S.C. 6295(o)(2)(B)(iii)) For each considered efficiency level, DOE determined the value of the first year's energy savings by calculating the energy savings in accordance with the applicable DOE test procedure, and multiplying those savings by the average energy price forecast for the year in which compliance with the amended standards would be required. However, DOE's LCC and PBP analyses generate values that calculate the payback period for consumers under potential energy conservation standards, which includes, but is not limited to, the three-year payback period contemplated under the rebuttable presumption test. DOE routinely conducts a full economic analysis that considers the full range of impacts, including those to the consumer, manufacturer, Nation, and environment, as required under 42 U.S.C. 6295(o)(2)(B)(i). The results of this analysis serve as the basis for DOE to definitively evaluate the economic justification for a potential standard level (thereby supporting or rebutting the results of any preliminary determination of economic justification).
DOE uses forecasts of annual product shipments to calculate the national impacts of potential amended energy conservation standards on energy use, NPV, and future manufacturer cash flows.
For the NOPR, to project boiler replacement shipments, DOE developed retirement functions based on the boiler lifetime estimates used in the LCC analysis and applied them to the existing products in the building stock. The existing stock of products is tracked by vintage and developed from historical shipments data.
For the NOPR, to project shipments to the new housing market, DOE utilized a forecast of new housing or building construction and historic saturation rates of various boiler product types in new housing or building construction. DOE used
For the NOPR, to estimate future shipments to new owners, DOE based its estimates on market trends and historical shipment data from 2008 to 2012. The new owners primarily consist of households that during a major remodel add hydronic heating using a gas-fired hot water boiler and households that choose to install a boiler with a hydronic air handler to replace a gas furnace. New owners also include households switching between different boiler product classes (
Commenting on the NOPR, ACCA stated that, based on feedback from a select number of ACCA members, the percentage of gas-fired boiler installations associated with new construction falls within DOE's range (
The NOPR analysis accounted for the impact of increased product price for the considered efficiency levels on shipments by incorporating relative price elasticity in the shipments model. This approach gives some weight to the operating cost savings from higher-efficiency products. In general, price elasticity reflects the expectation that demand will decrease when prices increase. The price elasticity value is derived from data on refrigerators, clothes washers, and dishwashers.
AHRI stated that the price elasticity data used for DOE's analysis is not a good match for boilers because consumers look for different attributes, such as appearance or special functions, when buying refrigerators and clothes washers, whereas with boilers, the same considerations do not apply. (AHRI, Public Meeting Transcript, No. 50 at pp. 239–240) AHRI stated that DOE has a responsibility to explain why a price analysis for washing machines and refrigerators is an acceptable substitute for residential boilers. (AHRI, No. 64 at p. 5)
In response, DOE first notes that there are very few estimates of consumer demand elasticity for durable goods. For the final rule, DOE updated its price elasticity to a value calculated from price, shipments, and efficiency data over 1989–2009 for five common residential appliances (clothes washers, refrigerators, freezers, dishwashers, and room air conditioners).
Weil-McLain stated that a homeowner will often decide to repair their existing boiler and delay replacement if the total installed cost is too great. (Weil-McLain, No. 55 at p. 6) Burnham stated that
In response, at the higher efficiency levels where installed cost is much higher than the boiler in the no-new-standards case, DOE accounts for repair of old boilers to extend their lifetime through the price elasticity parameters described above. This parameter relates the repair decision to the incremental installed cost and the operating cost savings of higher-efficiency boilers, both of which have some weight in the consumer decision. DOE estimated that the average extension of life of the repaired unit would be six years, and then that unit is replaced with a new boiler. In the NIA, the cost of the repair and the energy costs of the repaired unit are accounted for.
For the NOPR and final rule, DOE evaluated the potential for switching from gas-fired and oil-fired hot water boilers to other heating systems in response to amended standards. The main alternative to hot water boilers would be installation of an electric boiler, a forced-air furnace, heat pump, or a mini-split heat pump. These alternatives would require significant installation costs such as adding ductwork or an electrical upgrade, and an electric boiler would have very high relative energy costs. Given that the increase in installed cost of boilers meeting the amended standards, relative to the no-new-standards case, is small, DOE has concluded that consumer switching from hot water boilers would be rare.
The details and results of the shipments analysis can be found in chapter 9 of the final rule TSD.
The NIA assesses the national energy savings (NES) and the national net present value (NPV) from a national perspective of total consumer costs and savings expected to result from new or amended energy conservation standards at specific efficiency levels. (“Consumer” in this context refers to consumers of the product being regulated.) DOE calculates the NES and NPV for the potential standard levels considered for the residential boiler product classes analyzed based on projections of annual product shipments, along with the annual energy consumption and total installed cost data from the energy use and LCC analyses. For the NOPR analysis, DOE forecasted the energy savings, operating cost savings, product costs, and NPV of consumer benefits over the lifetime of residential boilers sold from 2020 through 2049. For the final rule analysis, DOE performed the same analyses over the lifetime of residential boilers sold from 2021 through 2050.
DOE evaluates the impacts of new and amended standards by comparing a case without such standards with standards-case projections. The no-new-standards case characterizes energy use and consumer costs for each product class in the absence of new or amended energy conservation standards. For this projection, DOE considers historical trends in efficiency and various forces that are likely to affect the mix of efficiencies over time. DOE compares the no-new-standards case with projections characterizing the market for each product class if DOE adopted new or amended standards at specific energy efficiency levels (
DOE uses a spreadsheet model to calculate the energy savings and the national consumer costs and savings from each TSL. Interested parties can review DOE's analyses by changing various input quantities within the spreadsheet. The NIA spreadsheet model uses typical values (as opposed to probability distributions) as inputs. To assess the effect of input uncertainty on NES and NPV results, DOE developed its spreadsheet model to conduct sensitivity analyses by scenarios on specific input variables. In the NIA, DOE forecasted the lifetime energy savings, energy cost savings, product costs, and NPV of consumer benefit for each product class over the lifetime of products sold from 2021 through 2050.
Table IV.27 summarizes the inputs and methods DOE used for the NIA analysis for the final rule. Discussion of these inputs and methods follows the table. See chapter 10 of the final rule TSD for further details.
A key component of the NIA is the trend in energy efficiency projected for the no-new-standards case and each of the standards cases. Section IV.F of this notice describes how DOE developed an energy efficiency distribution for the no-new-standards case (which yields a shipment-weighted average efficiency) for each of the considered residential boiler product classes for the first year of the forecast period (
For the NOPR, regarding the efficiency trend in the years after compliance, for the no-new-standards case, DOE estimated that the overall market share of condensing gas-fired hot water boilers would grow from 44 percent to 63 percent by 2049, and the overall market share of condensing oil-fired hot water boilers would grow from 7 percent to 13 percent. DOE estimated that the no-new-standards case market shares of condensing gas-fired and oil-fired steam boilers will be negligible during the period of analysis. DOE assumed similar trends for the standards cases (albeit starting from a higher point).
For the final rule, DOE modified its efficiency trend in the no-new-standards case in 2021, as described in section IV.F. Based on this updated data, DOE estimated that the overall market share of condensing gas-fired hot water boilers would grow from 54 percent in 2021 to 74 percent by 2050, and the overall market share of condensing oil-fired hot water boilers would grow from 4 percent to 8 percent. The no-new-standards case market shares of condensing gas-fired and oil-fired steam boilers remain negligible. Details on
For the NOPR and final rule boiler standby mode and off mode standard analysis, DOE assumed that the efficiency level distributions would remain constant over the analysis period.
For the NOPR and final rule, for the standards cases, DOE used a “roll-up” scenario to establish the shipment-weighted efficiency for the year that standards are assumed to become effective. In this scenario, the market of products in the no-new-standards case that do not meet the standard under consideration would “roll up” to meet the new standard level, and the market share of products above the standard would remain unchanged.
Burnham stated that if DOE were to adopt the 85-percent level for gas-fired hot water boilers, most of the gas-fired hot water boiler sales would move to the condensing level due to the very limited ability to use Category I venting, combined with the cost of AL29‐4C stainless steel generally required at near-condensing (85 to 89 percent) efficiencies. (Burnham, No. 60 at p. 16) AGA agreed that a certain percentage of the market will be forced to the condensing level with an 85-percent standard, which could incur a net cost for consumers. (AGA, Public Meeting Transcript, No. 50 at pp. 289–290)
In the current analysis, on average, going to 85-percent AFUE has a lower total installed cost than going to the condensing level (
The national energy savings analysis involves a comparison of national energy consumption of the considered products between each potential standards case (TSL) and the case with no new or amended energy conservation standards. DOE calculated the national energy consumption by multiplying the number of units (stock) of each product (by vintage or age) by the unit energy consumption (also by vintage). Vintage represents the age of the product. DOE calculated annual NES based on the difference in national energy consumption for the case without amended efficiency standards and for each higher efficiency standard. For the NOPR, DOE estimated energy consumption and savings based on site energy and converted the electricity consumption and savings to primary energy using annual conversion factors derived from the
DOE considered whether boiler energy use would likely be impacted by a direct rebound effect, which occurs when a product that is made more efficient is used more intensively, such that the expected energy savings from the efficiency improvement may not fully materialize. For the NOPR, after reviewing several studies on the direct rebound effect, DOE included a 15-percent rebound effect for residential boilers due to an AFUE standard. For the final rule, DOE updated the rebound effect value to range from 9 to 11 percent depending on the product class, taking into account differences in the rebound effect associated with space heating and water heating energy use, as well as residential and commercial applications based on a review of the studies on the direct rebound effect. In both the NOPR and final rule, DOE did not consider a rebound effect for standby mode and off mode standards, because consumers typically have no awareness of any efficiency change in standby mode and off mode. See chapter 10 of the final rule TSD for DOE's assessments of rebound effect literature.
In 2011, in response to the recommendations of a committee on “Point-of-Use and Full-Fuel-Cycle Measurement Approaches to Energy Efficiency Standards” appointed by the National Academy of Sciences, DOE announced its intention to use full-fuel-cycle (FFC) measures of energy use and greenhouse gas and other emissions in the national impact analyses and emissions analyses included in future energy conservation standards rulemakings. 76 FR 51281 (August 18, 2011). After evaluating the approaches discussed in the August 18, 2011 notice, DOE published a statement of amended policy in the
NPGA stated that it is not clear in the NOPR that DOE applied the FFC evaluation to the entire energy path of electric-powered residential boilers. NPGA requested that the agency apply to electric-powered residential boilers the same FFC analysis utilized to assess primary fuels. NPGA requested that DOE clarify the extent to which electric-powered residential boilers were evaluated through the FFC analysis. (NPGA, No. 53, pp. 1–3)
In response, DOE did not analyze electric boilers for AFUE standards because their efficiency is close to 100-percent AFUE. However, DOE did analyze electric boilers for the standby mode and off mode standards, and applied the FFC analysis, including power plant and upstream energy use, to electric boilers as well as gas-fired and oil-fired boilers.
The approach used for deriving FFC measures of energy use and emissions is described in appendix 10B of the final rule TSD.
The inputs for determining NPV are: (1) Total annual installed cost; (2) total annual savings in operating costs; (3) a discount factor to calculate the present value of costs and savings; (4) present value of costs; and (5) present value of savings. DOE calculated net savings each year as the difference between the no-new-standards case and each standards case in terms of total savings in operating costs versus total increases in installed costs. DOE calculated savings over the lifetime of products shipped in the forecast period. DOE calculated NPV as the difference between the present value of operating cost savings and the present value of total installed costs.
For the NPV analysis, DOE calculates increases in total installed costs as the difference in total installed cost between the no-new-standards case and standards cases (
To evaluate the effect of uncertainty regarding the price trend estimates, DOE investigated the impact of different product price forecasts on the consumer NPV for the considered TSLs for residential boilers. In addition to the default price trend, DOE considered two product price sensitivity cases: (1) A high price decline case based on 1980–1998 PPI data; and (2) a low price decline case based on
Operating cost savings are estimated by comparing total energy expenditures and repair and maintenance costs for the no-new-standards case and the standards cases. Total savings in operating costs are the product of savings per unit and the number of units of each vintage that survive in a given year. DOE calculates annual energy expenditures from annual energy consumption by incorporating forecasted energy prices. To calculate future energy prices, DOE applied the projected trend in national-average commercial energy prices from the
The aggregate difference each year between operating cost savings and increased equipment expenditures is the net savings or net costs. In calculating the NPV, DOE multiplies the net savings in future years by a discount factor to determine their present value. For this final rule, DOE estimated the NPV of consumer benefits using both a 3-percent and a 7-percent real discount rate. DOE uses these discount rates in accordance with guidance provided by the Office of Management and Budget (OMB) to Federal agencies on the development of regulatory analysis.
In analyzing the potential impact of new or amended energy conservation standards on consumers, DOE evaluates the impact on identifiable subgroups of consumers that comprise a subset of the population that may be disproportionately affected by a new or amended national standard (
For the NOPR and final rule, DOE analyzed the impacts of the considered standard levels on two subgroups: (1) Low-income households and (2) senior-only households. DOE identified these households in the RECS 2009 sample and used the LCC and PBP spreadsheet model to estimate the impacts of the considered efficiency levels on these subgroups. To the extent possible, it utilized inputs appropriate for these subgroups.
The consumer subgroup results for the residential boilers TSLs are presented in section V.B.1.b of this notice and chapter 11 of the final rule TSD.
DOE performed an MIA to estimate the financial impacts of amended energy conservation standards on manufacturers of residential boilers and to estimate the potential impacts of such standards on employment and manufacturing capacity. The MIA has both quantitative and qualitative aspects and includes analyses of forecasted industry cash flows, the industry net present value (INPV), investments in research and development (R&D) and manufacturing capital, and domestic manufacturing employment. Additionally, the MIA seeks to determine how amended energy conservation standards might affect manufacturing employment, capacity, and competition, as well as how standards contribute to overall regulatory burden. Finally, the MIA serves to identify any disproportionate impacts on manufacturer subgroups, including small business manufacturers.
The quantitative part of the MIA primarily relies on the Government Regulatory Impact Model (GRIM), an industry cash-flow model with inputs specific to this rulemaking. The key GRIM inputs include data on the industry cost structure, unit production costs, product shipments, manufacturer markups, and investments in R&D and manufacturing capital required to produce compliant products (conversion costs). The key GRIM outputs are the INPV, which is the sum of industry annual cash flows over the analysis period, discounted using the industry-weighted average cost of capital, and the impact to domestic manufacturing employment. The model uses standard accounting principles to estimate the impacts of more-stringent energy conservation standards on a given industry by comparing changes in INPV and domestic manufacturing employment between a no-new-standards case and the various TSLs (the standards cases). To capture the uncertainty relating to manufacturer pricing strategies and profitability following amended standards, the GRIM estimates a range of possible impacts under different markup scenarios.
The qualitative part of the MIA addresses manufacturer characteristics and market/product trends. Specifically, the MIA considers such factors as a potential standard's impact on manufacturing capacity, competition within the industry, the cumulative impact of other DOE and non-DOE regulations, and impacts on manufacturer subgroups. The complete MIA is outlined in chapter 12 of the final rule TSD.
DOE conducted the MIA for this rulemaking in three phases. In the first phase of the MIA, DOE prepared a profile of the residential boiler
In second phase of the MIA, DOE prepared an industry cash-flow analysis to quantify the potential impacts of new and amended energy conservation standards. The GRIM uses several factors to determine a series of annual cash flows starting with the announcement of the standard and extending over a 30-year period following the compliance date of the standard. These factors include annual expected revenues, costs of sales, SG&A and R&D expenses, taxes, and capital expenditures. In general, energy conservation standards can affect manufacturer cash flow in three distinct ways: (1) Creating a need for increased investment; (2) raising production costs per unit; and (3) altering revenue due to higher per-unit prices and changes in sales volumes. DOE estimated industry cash flows in the GRIM at various potential standard levels using industry financial parameters derived in the first phase and the shipment scenario used in the NIA. The GRIM modeled both impacts from the AFUE energy conservation standards and impacts from standby mode and off mode energy conservation standards (
In addition, during the second phase of the MIA, DOE developed interview guides to distribute to manufacturers of residential boilers in order to develop other key GRIM inputs, including product and capital conversion costs, and to gather additional information on the anticipated effects of energy conservation standards on revenues, direct employment, capital assets, industry competitiveness, and subgroup impacts.
In the third phase of the MIA, DOE conducted structured, detailed interviews with a variety of manufacturers that represent approximately 46 percent of domestic residential boiler sales covered by this rulemaking. During these interviews, DOE discussed engineering, manufacturing, procurement, and financial topics to validate assumptions used in the GRIM and to identify key issues or concerns. See section IV.J.4 for a description of the key issues raised by manufacturers during the interviews.
Additionally, in the third phase, DOE also evaluated subgroups of manufacturers that may be disproportionately impacted by amended standards or that may not be accurately represented by the average cost assumptions used to develop the industry cash-flow analysis. For example, small manufacturers, niche players, or manufacturers exhibiting a cost structure that largely differs from the industry average could be more negatively affected by amended energy conservation standards. DOE identified one subgroup (small manufacturers) for a separate impact analysis.
To identify small businesses for this analysis, DOE applied the small business size standards published by the Small Business Administration (SBA) to determine whether a company is considered a small business. 65 FR 30836, 30848 (May 15, 2000), as amended at 65 FR 53533, 53544 (Sept. 5, 2000) and codified at 13 CFR part 121. To be categorized as a small business under North American Industry Classification System (NAICS) code 333414, “Heating Equipment (except Warm Air Furnaces) Manufacturing,” a residential boiler manufacturer and its affiliates may employ a maximum of 500 employees. The 500-employee threshold includes all employees in a business's parent company and any other subsidiaries. Based on this classification, DOE identified at least 13 residential boiler companies that qualify as small businesses.
The residential boiler small manufacturer subgroup is discussed in section VI.B of this final rule and in chapter 12 of the final rule TSD.
DOE uses the GRIM to quantify the potential changes in cash flow due to amended standards that result in a higher or lower industry value. The GRIM was designed to conduct an annual cash-flow analysis using standard accounting principles that incorporates manufacturer costs, markups, shipments, and industry financial information as inputs. DOE thereby calculated a series of annual cash flows, beginning in 2014 (the base year of the analysis) and continuing to 2050. DOE summed the stream of annual discounted cash flows during this period to calculate INPVs at each TSL. For residential boiler manufacturers, DOE used a real discount rate of 8.0 percent, which was derived from industry financial information and then modified according to feedback received during manufacturer interviews. DOE also used the GRIM to model changes in costs, shipments, investments, and manufacturer margins that could result from amended energy conservation standards.
After calculating industry cash flows and INPV, DOE compared changes in INPV between the no-new-standards case and each standards case. The difference in INPV between the no-new-standards case and a standards case represents the financial impact of the amended energy conservation standard on manufacturers at a particular TSL. As discussed previously, DOE collected this information on GRIM inputs from a number of sources, including publicly-available data and confidential interviews with a number of manufacturers. GRIM inputs are discussed in more detail in the next section. The GRIM results are discussed in section V.B.2. Additional details about the GRIM, the discount rate, and other financial parameters can be found in chapter 12 of the final rule TSD.
For consideration of standby mode and off mode regulations, DOE modeled the impacts of the technology options for reducing electricity usage discussed in the engineering analysis (chapter 5 of the final rule TSD). The GRIM analysis incorporates the incremental additions to the MPC of standby mode and off mode features and the resulting impacts on markups.
Due to the small cost of standby mode and off mode components relative to the overall cost of a residential boiler, DOE assumes that standards regarding standby mode and off mode features alone would not impact product shipment numbers. Additionally, DOE has concluded that the incremental cost
The electric boiler product classes were not analyzed in the GRIM for AFUE energy conservation standards. As a result, quantitative numbers for those product classes are not available in the GRIM analyzing standby mode and off mode standards. However, the standby mode and off mode technology options considered for electric boilers are identical to the technology options for all other residential boiler product classes. As a result, DOE expects the standby mode and off mode impacts on electric boilers to be of the same order of magnitude as the impacts on all other residential boiler product classes.
Manufacturing a higher-efficiency product is typically more expensive than manufacturing a baseline product due to the use of more complex components, which are typically more costly than baseline components. The changes in the MPCs of the analyzed products can affect the revenues, gross margins, and cash flow of the industry, making these product cost data key GRIM inputs for DOE's analysis.
In the MIA, DOE used the MPCs for each considered efficiency level calculated in the engineering analysis, as described in section IV.C and further detailed in chapter 5 of the final rule TSD. In addition, DOE used information from its teardown analysis (described in chapter 5 of the final rule TSD) to disaggregate the MPCs into material, labor, and overhead costs. To calculate the MPCs for products at and above the baseline, DOE performed teardowns and cost modeling that allowed DOE to estimate the incremental material, labor, and overhead costs for products above the baseline. These cost breakdowns and product markups were validated and revised with input from manufacturers during manufacturer interviews.
The GRIM estimates manufacturer revenues based on total unit shipment forecasts and the distribution of these values by efficiency level. Changes in sales volumes and efficiency mix over time can significantly affect manufacturer finances. For this analysis, the GRIM uses the NIA's annual shipment forecasts derived from the shipments analysis from 2014 (the base year) to 2050 (the end year of the analysis period). The shipments model divides the shipments of residential boilers into specific market segments. The model starts from a historical base year and calculates retirements and shipments by market segment for each year of the analysis period. This approach produces an estimate of the total product stock, broken down by age or vintage, in each year of the analysis period. In addition, the product stock efficiency distribution is calculated for the base case and for each standards case for each product class. The NIA shipments forecasts are, in part, based on a roll-up scenario. The forecast assumes that a product in the base case that does not meet the standard under consideration would “roll up” to meet the amended standard beginning in the compliance year of 2021. See section IV.G and chapter 9 of the final rule TSD for additional details.
Amended energy conservation standards would cause manufacturers to incur one-time conversion costs to bring their production facilities and product designs into compliance. DOE evaluated the level of conversion-related expenditures that would be needed to comply with each considered efficiency level in each product class. For the MIA, DOE classified these conversion costs into two major groups: (1) Capital conversion costs; and (2) product conversion costs. Capital conversion costs are one-time investments in property, plant, and equipment necessary to adapt or change existing production facilities such that new compliant product designs can be fabricated and assembled. Product conversion costs are one-time investments in research, development, testing, marketing, and other non-capitalized costs necessary to make product designs comply with amended energy conservation standards.
To evaluate the level of capital conversion expenditures manufacturers would likely incur to comply with amended energy conservation standards, DOE used manufacturer interviews to gather data on the anticipated level of capital investment that would be required at each efficiency level. Based on manufacturer feedback, DOE developed a market-share-weighted manufacturer average capital expenditure which it then applied to the entire industry. DOE also made assumptions about which manufacturers would develop their own condensing heat exchanger production lines, in the event that efficiency levels using condensing technology were proposed. DOE supplemented manufacturer comments and tailored its analyses with estimates of capital expenditure requirements derived from the product teardown analysis and engineering analysis described in chapter 5 of the final rule TSD.
DOE assessed the product conversion costs at each considered efficiency level by integrating data from quantitative and qualitative sources. DOE considered market-share-weighted feedback regarding the potential costs of each efficiency level from multiple manufacturers to estimate product conversion costs (
In general, DOE assumes that all conversion-related investments occur between the year of publication of the final rule and the year by which manufacturers must comply with the amended standards. The conversion cost figures used in the GRIM can be found in section V.B.2.a of this notice. For additional information on the estimated product and capital conversion costs, see chapter 12 of the final rule TSD.
As discussed in the previous section, MSPs include direct manufacturing production costs (
Under the preservation of gross margin percentage markup scenario, DOE applied a single uniform “gross margin percentage” markup across all efficiency levels, which assumes that following amended standards, manufacturers would be able to maintain the same amount of profit as a percentage of revenue at all efficiency levels within a product class. As production costs increase with efficiency, this scenario implies that the absolute dollar markup will increase as well. Based on publicly-available financial information for manufacturers of residential boilers, as well as comments from manufacturer interviews, DOE assumed the average non-production cost markup—which includes SG&A expenses, R&D expenses, interest, and profit—to be 1.41 for all product classes. This markup scenario represents the upper bound of the residential boiler industry's profitability in the standards case because manufacturers are able to fully pass through additional costs due to standards to consumers.
DOE decided to include the preservation of per-unit operating profit scenario in its analysis because manufacturers stated that they do not expect to be able to mark up the full cost of production in the standards case, given the highly competitive nature of the residential boiler market. In this scenario, manufacturer markups are set so that operating profit one year after the compliance date of amended energy conservation standards is the same as in the base case on a per-unit basis. In other words, manufacturers are not able to garner additional operating profit from the higher production costs and the investments that are required to comply with the amended standards; however, they are able to maintain the same operating profit in the standards case that was earned in the base case. Therefore, operating margin in percentage terms is reduced between the base case and standards case. DOE adjusted the manufacturer markups in the GRIM at each TSL to yield approximately the same earnings before interest and taxes in the standards case as in the base case. The preservation of per-unit operating profit markup scenario represents the lower bound of industry profitability in the standards case. This is because manufacturers are not able to fully pass through to consumers the additional costs necessitated by residential boiler standards, as they are able to do in the preservation of gross margin percentage markup scenario.
DOE interviewed manufacturers representing approximately 55 percent of the residential boiler market by revenue. DOE contractors endeavor to conduct interviews with a representative cross-section of manufacturers (including large and small manufacturers, covering all equipment classes and product offerings). DOE contractors reached out to all the small business manufacturers that were identified as part of the analysis, as well as larger manufacturers that have significant market share in the residential boilers market. These interviews were in addition to those DOE conducted as part of the engineering analysis. The information gathered during these interviews enabled DOE to tailor the GRIM to reflect the unique financial characteristics of the residential boiler industry. The information gathered during these interviews enabled DOE to tailor the GRIM to reflect the unique financial characteristics of the residential boiler industry. All interviews provided information that DOE used to evaluate the impacts of potential amended energy conservation standards on manufacturer cash flows, manufacturing capacities, and employment levels.
In interviews, DOE asked manufacturers to describe their major concerns with potential standards arising from a rulemaking involving residential boilers. Manufacturer interviews are conducted under non-disclosure agreements (NDAs), so DOE does not document these discussions in the same way that it does public comments in the comment summaries and DOE's responses throughout the rest of this notice. The following sections highlight the most significant of manufacturers' statements that helped shape DOE's understanding of potential impacts of an amended standard on the industry. Manufacturers raised a range of general issues for DOE to consider, including a diminished ability to serve the replacement market, concerns that condensing boilers may not perform as rated without heating system modifications, and concerns about reduced product durability. (DOE also considered all other concerns expressed by manufacturers in this analysis.) Below, DOE summarizes these issues, which were raised in manufacturer interviews, in order to obtain public comment and related data.
In interviews, several manufacturers pointed out that over 90 percent of residential boiler sales are transacted in the replacement channel, rather than the new construction channel. They stated that the current residential boiler market is structured around the legacy venting infrastructures that exist in the vast majority of homes and that any regulation that eliminated 82 to 83-percent efficient products would be very disruptive to the market. Manufacturers argued that under this scenario, consumers would face much higher installation costs, as well as complex challenges in changing the layout of the boiler room and upgrading their venting and heat distribution systems. Manufacturers argued that these considerations may induce consumers to explore other HVAC options and may cause them to leave the boiler market entirely. Manufacturers also asserted that the elimination of 82 to 83-percent efficient products could be disruptive to the market because several manufacturers would have to eliminate commodity products that generate a majority of their sales and be forced to sell products for which they are less vertically integrated, which may cause them to exit the market entirely. Some manufacturers speculated that if this scenario were to play out, it could result in the loss of a substantial number of American manufacturing jobs.
Accordingly, DOE has considered this feedback when developing its analysis of installation costs (see section IV.F.2), shipments analysis (see section IV.G), and employment impacts analysis (see section IV.N).
Several manufacturers argued that condensing boilers may have overstated efficiencies in terms of actual results in the field if they are installed as replacements in legacy distribution systems that were designed to maintain hot water supply temperatures of 180–200 °F. Manufacturers stated that in these systems, return water temperatures will often be too high for condensing boilers to operate in condensing mode, thereby causing the boiler to be less efficient than its express rating. Manufacturers also stated that because condensing boilers are designed for lower maximum supply water temperatures, the heat distribution output of the heating system as a whole is often reduced, and the boiler may not be able to meet heat distribution requirements. This may require the
DOE recognizes this issue and considered it in the energy use analysis for residential boilers. See chapter 7 of the final rule TSD for additional details.
Several manufacturers commented that higher-efficiency condensing boilers on the market have not demonstrated the same level of durability and reliability as lower-efficiency products. Manufacturers stated that condensing products require more upkeep and maintenance and generally do not last as long as non-condensing products. Several manufacturers pointed out that they generally incur large after-sale costs with their condensing products because of additional warranty claims. Maintenance calls for these boilers require more skilled technicians and occur more frequently than they do with non-condensing boilers.
DOE considered these comments when developing its estimates of repair and maintenance costs for residential boilers (see section IV.F.2.c) and product lifetime (IV.F.2.d).
During the NOPR public comment period, interested parties commented on assumptions and results described in the NOPR document and accompanying TSD, addressing several topics related to manufacturer impacts. These include: small business impacts and industry direct employment.
Energy Kinetics commented that the introduction of new products in response to the proposed standard will put significant burden on small manufacturers due to the product development costs, carrying costs, distribution costs, and warehousing costs that will be incurred. Further, Energy Kinetics argued that the standard may result in consumers switching to high-mass cast iron products which would also put small manufacturers at a market disadvantage. (Energy Kinetics, No. 52 at p. 2) Consistent with the requirements of the Regulatory Flexibility Act (5 U.S.C. 601,
Burnham commented that a standard requiring condensing units would have significant impacts on direct employment due to the elimination of cast iron products. (Burnham, No. 60 at pp. 1 & 4) In the manufacturer impact analysis, DOE analyzes the impacts on regulated residential boiler manufacturers. In this analysis, DOE estimates the decrease in direct employment due to an energy conservation standard in section V.B.2.b. Burnham also raised concerns about the impact of a standard requiring condensing efficiency levels on their cast iron foundries. (Burnham, No. 60 at p. 38) However, this rule does not adopt a condensing level for any equipment classes. A full explanation of the efficiency requirements by product class is provided in section V.B.2.a.
The emissions analysis consists of two components. The first component estimates the effect of potential energy conservation standards on power sector and site (where applicable) combustion emissions of CO
For the final rule, the analysis of power sector emissions used marginal emissions factors that were derived from data in
Combustion emissions of CH
The emissions intensity factors are expressed in terms of physical units per MWh or MMBtu of site energy savings. Total emissions reductions are estimated using the energy savings calculated in the national impact analysis.
For CH
Because the on-site operation of residential boilers requires use of fossil fuels and results in emissions of CO
The amended standards will reduce use of fuel at the site and slightly reduce electricity use, thereby reducing power sector emissions. However, the highest efficiency levels (
The
SO
EIA was not able to incorporate CSAPR into
The attainment of emissions caps is typically flexible among EGUs and is enforced through the use of emissions allowances and tradable permits. Under existing EPA regulations, any excess SO
Beginning in 2016, however, SO
CAIR established a cap on NO
The MATS limit mercury emissions from power plants, but they do not include emissions caps, and as such, DOE's energy conservation standards would likely reduce Hg emissions. DOE estimated mercury emissions reduction using emissions factors based on
AHRI criticized DOE's inclusion of CO
EEI stated that the analysis and
As part of the development of this rule, DOE considered the estimated monetary benefits from the reduced emissions of CO
For this final rule, DOE relied on a set of values for the social cost of carbon (SCC) that was developed by a Federal interagency process. The basis for these values is summarized in the next section, and a more detailed description of the methodologies used is provided as an appendix to chapter 14 of the final rule TSD.
The SCC is an estimate of the monetized damages associated with an incremental increase in carbon emissions in a given year. It is intended to include (but is not limited to) climate-change-related changes in net agricultural productivity, human health, property damages from increased flood risk, and the value of ecosystem services. Estimates of the SCC are provided in dollars per metric ton of CO
Under section 1(b)(6) of Executive Order 12866, “Regulatory Planning and Review,” 58 FR 51735 (Oct. 4, 1993), agencies must, to the extent permitted by law, assess both the costs and the benefits of the intended regulation and, recognizing that some costs and benefits are difficult to quantify, propose or adopt a regulation only upon a reasoned determination that the benefits of the intended regulation justify its costs. The purpose of the SCC estimates presented here is to allow agencies to incorporate the monetized social benefits of reducing CO
As part of the interagency process that developed these SCC estimates, technical experts from numerous agencies met on a regular basis to consider public comments, explore the technical literature in relevant fields, and discuss key model inputs and assumptions. The main objective of this process was to develop a range of SCC values using a defensible set of input assumptions grounded in the existing scientific and economic literatures. In this way, key uncertainties and model differences transparently and consistently inform the range of SCC estimates used in the rulemaking process.
When attempting to assess the incremental economic impacts of CO
Despite the limits of both quantification and monetization, SCC estimates can be useful in estimating the social benefits of reducing CO
It is important to emphasize that the interagency process is committed to updating these estimates as the science and economic understanding of climate change and its impacts on society improves over time. In the meantime, the interagency group will continue to explore the issues raised by this analysis and consider public comments as part of the ongoing interagency process.
In 2009, an interagency process was initiated to offer a preliminary assessment of how best to quantify the benefits from reducing carbon dioxide emissions. To ensure consistency in how benefits are evaluated across Federal agencies, the Administration sought to develop a transparent and defensible method, specifically designed for the rulemaking process, to quantify avoided climate change damages from reduced CO
After the release of the interim values, the interagency group reconvened on a regular basis to generate improved SCC estimates. Specially, the group considered public comments and further explored the technical literature in relevant fields. The interagency group relied on three integrated assessment models commonly used to estimate the SCC: The FUND, DICE, and PAGE models. These models are frequently cited in the peer-reviewed literature and were used in the last assessment of the Intergovernmental Panel on Climate Change (IPCC). Each model was given equal weight in the SCC values that were developed.
Each model takes a slightly different approach to model how changes in emissions result in changes in economic damages. A key objective of the interagency process was to enable a consistent exploration of the three models, while respecting the different approaches to quantifying damages taken by the key modelers in the field. An extensive review of the literature was conducted to select three sets of input parameters for these models: climate sensitivity, socio-economic and emissions trajectories, and discount rates. A probability distribution for climate sensitivity was specified as an input into all three models. In addition, the interagency group used a range of scenarios for the socio-economic parameters and a range of values for the discount rate. All other model features were left unchanged, relying on the model developers' best estimates and judgments.
In 2010, the interagency group selected four sets of SCC values for use in regulatory analyses. Three sets of values are based on the average SCC from the three integrated assessment models, at discount rates of 2.5 percent, 3 percent, and 5 percent. The fourth set, which represents the 95th-percentile SCC estimate across all three models at a 3-percent discount rate, was included to represent higher-than-expected impacts from climate change further out in the tails of the SCC distribution. The values grow in real terms over time. Additionally, the interagency group determined that a range of values from 7 percent to 23 percent should be used to adjust the global SCC to calculate domestic effects,
The SCC values used for this document were generated using the most recent versions of the three integrated assessment models that have been published in the peer-reviewed literature, as described in the 2013 update from the interagency working group (revised July 2015).
Commenting on the NOPR, The Associations objected to DOE's continued use of the Social Cost of Carbon (“SCC”) and stated that the SCC calculation should not be used in any rulemaking or policymaking until it undergoes a more rigorous notice, review, and comment process. (The Associations, No. 56 at p. 4) Both The Associations
In response, DOE notes that the General Accounting Office (GAO) reviewed the Interagency Working Group's (IWG) development of SCC estimates and found that OMB and EPA participants reported that the IWG documented all major issues consistent with Federal standards for internal control. The GAO also found, according to its document review and interviews, that the IWG's development process followed three principles: (1) it used consensus-based decision making; (2) it relied on existing academic literature and models; and (3) it took steps to disclose limitations and incorporate new information.
AHRI and the Cato Institute criticized DOE's use of SCC estimates that DOE has acknowledged are subject to considerable uncertainty. (AHRI, No. 64 at pp. 5–6; Cato Institute, No. 51 at p. 3) The Cato Institute stated that until the integrated assessment models (IAMs) are made consistent with mainstream climate science, the SCC should be barred from use in this and all other Federal rulemakings. The Cato Institute criticized several aspects of the determination of the SCC values by the IWG as being discordant with the best climate science and not reflective of climate change impacts. (Cato Institute, No. 51 at p. 1–2, 4–22) AHRI also criticized the determination of the SCC values. (AHRI, No. 64 at p. 8)
In conducting the interagency process that developed the SCC values, technical experts from numerous agencies met on a regular basis to consider public comments, explore the technical literature in relevant fields, and discuss key model inputs and assumptions. Key uncertainties and model differences transparently and consistently inform the range of SCC estimates. These uncertainties and model differences are discussed in the interagency working group's reports, which are reproduced in appendices 14A and 14B of the final rule TSD, as are the major assumptions. Specifically, uncertainties in the assumptions regarding climate sensitivity, as well as other model inputs such as economic growth and emissions trajectories, are discussed and the reasons for the specific input assumptions chosen are explained. However, the three integrated assessment models used to estimate the SCC are frequently cited in the peer-reviewed literature and were used in the last assessment of the IPCC. In addition, new versions of the models that were used in 2013 to estimate revised SCC values were published in the peer-reviewed literature (see appendix 14B of the final rule TSD for discussion). Although uncertainties remain, the revised estimates that were issued in November 2013 are based on the best available scientific information on the impacts of climate change. The current estimates of the SCC have been developed over many years, using the best science available, and with input from the public. In November 2013, OMB announced a new opportunity for public comment on the interagency technical support document underlying the revised SCC estimates. 78 FR 70586 (Nov. 26, 2013). In July 2015, OMB published a detailed summary and formal response to the many comments that were received.
AHRI, the Cato Institute, and Laclede criticized DOE's use of global rather than domestic SCC values, pointing out that EPCA references weighing of the need for national energy conservation. The Cato Institute recommended reporting the results of the domestic SCC calculation in the main body of the proposed regulation. (AHRI, No. 64 at p. 6; Cato Institute, No. 51 at pp. 2–3; Laclede, No. 58 at p. 9)
In response, DOE's analysis estimates both global and domestic benefits of CO
AHRI disputed DOE's assumption that SCC values will increase over time, because AHRI reasons that the more economic development that occurs, the more adaptation and mitigation efforts that will be undertaken. (AHRI, No. 64 at p. 7) In response, the SCC increases over time because future emissions are expected to produce larger incremental damages as physical and economic systems become more stressed in response to greater climatic change (see appendix 14A of the final rule TSD). The approach used by the Interagency Working Group allowed estimation of the growth rate of the SCC directly using the three IAMs, which helps to ensure that the estimates are internally consistent with other modeling assumptions. Adaptation and mitigation efforts, while necessary and important, are not without cost, particularly if their implementation is delayed.
Laclede recommended using market prices to value carbon reduction benefits to U.S. residents. Laclede provided a chart of DOE's SCC values compared to three market prices from 2008 to 2015, which shows that the market prices are as low as or lower than the SCC value at a 5-percent discount rate ($12). (Laclede, No. 58 at pp. 9–10) In response, DOE notes that market prices are simply a reflection of the conditions in specific emissions markets in which emissions caps have been set. Neither the caps nor the resulting prices of traded emissions are intended to reflect the full range of domestic and global impacts from anthropogenic climate change over the appropriate time scales.
Even though the SCC embodies the best data currently available, it is important to recognize that a number of key uncertainties remain, and that current SCC estimates should be treated as provisional and revisable because they will evolve with improved scientific and economic understanding. The interagency group also recognizes that the existing models are imperfect and incomplete. The National Research Council report mentioned previously points out that there is tension between the goal of producing quantified estimates of the economic damages from an incremental ton of carbon and the limits of existing efforts to model these effects. There are a number of analytical challenges that are being addressed by the research community, including research programs housed in many of the Federal agencies participating in the interagency process to estimate the SCC. The interagency group intends to periodically review and reconsider those estimates to reflect increasing knowledge of the science and economics of climate impacts, as well as improvements in modeling.
In summary, in considering the potential global benefits resulting from reduced CO
DOE multiplied the CO
As noted previously, DOE has estimated how the considered energy conservation standards would reduce site NO
DOE estimated the monetized value of NO
DOE multiplied the emissions reduction (tons) in each year by the associated $/ton values, and then discounted each series using discount rates of 3 percent and 7 percent as appropriate. DOE will continue to evaluate the monetization of avoided NO
DOE is evaluating appropriate monetization of avoided SO
The utility impact analysis estimates several effects on the electric power generation industry that would result from the adoption of new or amended energy conservation standards. The utility impact analysis estimates the changes in installed electrical capacity and generation that would result for each TSL. The analysis is based on published output from the NEMS associated with
The output of this analysis is a set of time-dependent coefficients that capture the change in electricity generation, primary fuel consumption, installed capacity and power sector emissions due to a unit reduction in demand for a given end use. These coefficients are multiplied by the stream of electricity savings calculated in the NIA to provide estimates of selected utility impacts of new or amended energy conservation standards.
DOE considers employment impacts in the domestic economy as one factor in selecting a standard. Employment impacts from new or amended energy conservation standards include both direct and indirect impacts. Direct employment impacts are any changes in the number of employees of manufacturers of the products subject to standards. The MIA addresses those impacts. Indirect employment impacts are changes in national employment that occur due to the shift in expenditures and capital investment caused by the purchase and operation of more-efficient appliances. Indirect employment impacts from standards consist of the net jobs created or eliminated in the national economy, other than in the manufacturing sector being regulated, caused by: (1) Reduced spending by end users on energy; (2) reduced spending on new energy supply by the utility industry; (3) increased consumer spending on new products to which the new standards apply; and (4) the effects of those three factors throughout the economy.
One method for assessing the possible effects on the demand for labor of such shifts in economic activity is to compare sector employment statistics developed by the Labor Department's Bureau of Labor Statistics (BLS).
DOE estimated indirect national employment impacts for the standard levels considered in this final rule using an input/output model of the U.S. economy called Impact of Sector Energy Technologies version 3.1.1 (ImSET).
DOE notes that ImSET is not a general equilibrium forecasting model, and understands the uncertainties involved in projecting employment impacts, especially changes in the later years of the analysis. Because ImSET does not incorporate price changes, the employment effects predicted by ImSET may over-estimate actual job impacts over the long run for this rule. Therefore, DOE generated results for near-term timeframes (through 2023), where these uncertainties are reduced. For more details on the employment impact analysis, see chapter 16 of the final rule TSD.
The following section addresses the results from DOE's analyses with respect to the considered energy conservation standards for residential boilers. It addresses the TSLs examined by DOE, the projected impacts of each of these levels if adopted as energy conservation standards for residential boilers, and the standards levels that DOE is adopting in this final rule. Additional details regarding DOE's analyses are contained in the final rule TSD supporting this notice.
DOE analyzed the benefits and burdens of five TSLs for residential boilers for AFUE standards and three TSLs for standby mode and off mode standards. These TSLs were developed by combining specific efficiency levels for each of the product classes analyzed by DOE. DOE presents the results for the TSLs in this document, while the results for all efficiency levels that DOE analyzed are in the final rule TSD.
Table V.1 and Table V.2 present the TSLs and the corresponding product classes that DOE considered for residential boilers by efficiency levels and AFUE levels, respectively TSL 5 consists of the max-tech efficiency levels. TSL 4 consists of intermediate efficiency levels between the max-tech and TSL3, including the minimum condensing efficiency levels for hot water boiler product classes. TSL 3 consists of the efficiency levels that provide the highest NPV using a 7-percent discount rate (see section V.B.3 for NPV results)., and that also result in a higher percentage of consumers that receive an LCC benefit than experience an LCC loss (see section V.B.1 for LCC results). TSL 2 consists of the intermediate efficiency levels. TSL 1 consists of the most common efficiency levels in the current market.
Table V.3 presents the TSLs and the corresponding product class efficiency levels (by efficiency level) that DOE considered for boiler standby mode and off mode power consumption. Table V.4 presents the three TSLs and the corresponding product class efficiency levels (expressed in watts) that DOE considered for boiler standby mode and off mode power consumption. TSL 3 consists of efficiency levels that utilize the technology option Switching Mode Power Supply with Low-Loss Transformer (LLTX). TSL 2 consists of efficiency levels that utilize the technology option Switching Mode Power Supply. TSL 1 consists of efficiency levels that utilize the technology option Linear Power Supply with LLTX.
DOE analyzed the economic impacts on residential boilers consumers by looking at the effects potential amended standards at each TSL would have on the LCC and PBP. DOE also examined the impacts of potential standards on consumer subgroups. These analyses are discussed below.
In general, higher-efficiency products affect consumers in two ways: (1) Purchase price increases and (2) annual operating costs decrease. Inputs used for calculating the LCC and PBP include total installed costs (
Table V.5 through Table V.12 show the LCC and PBP results for the AFUE TSLs considered for each product class. In the first of each pair of tables, the simple payback is measured relative to the baseline product. In the second table, the impacts are measured relative to the efficiency distribution in the no-new-standards case in the compliance year (see section IV.F.8 of this notice). Because some consumers purchase products with higher efficiency in the no-new-standards case, the average savings are less than the difference between the average LCC of the baseline product and the average LCC at each TSL. The savings refer only to consumers who are affected by a standard at a given TSL. Those who already purchase a product with efficiency at or above a given TSL are not affected. Consumers for whom the LCC increases at a given TSL experience a net cost.
Table V.13 through Table V.24 show the key LCC and PBP results for each product class for standby mode and off mode.
In the consumer subgroup analysis, DOE estimated the impact of the considered AFUE TSLs on low-income households and senior-only households. Table V.25 through Table V.28 compare the average LCC savings and simple PBPs at each efficiency level for the two consumer subgroups, along with the average LCC savings for the entire sample. Chapter 11 of the final rule TSD presents the complete LCC and PBP results for the subgroups, as well as the standby mode and off mode standards results.
As discussed in section III.E.2, EPCA establishes a rebuttable presumption that an energy conservation standard is economically justified if the increased purchase cost for a product that meets the standard is less than three times the value of the first-year energy savings resulting from the standard. In calculating a rebuttable presumption payback period for each of the considered TSLs, DOE used discrete values, and, as required by EPCA, based the energy use calculation on the DOE test procedures for residential boilers. In contrast, the PBPs presented in section V.B.1.a were calculated using distributions that reflect the range of energy use in the field.
Table V.29 presents the rebuttable-presumption PBPs for the considered AFUE TSLs for the residential boilers product classes. Table V.30 shows the rebuttable-presumption PBPs for the considered standby mode and off mode TSLs for the residential boilers product classes. While DOE examined the rebuttable-presumption criterion, it considered whether the standard levels considered for this rule are economically justified through a more detailed analysis of the economic impacts of those levels, pursuant to 42 U.S.C. 6295(o)(2)(B)(i), that considers the full range of impacts to the
DOE performed an MIA to estimate the impact of amended energy conservation standards on manufacturers of residential boilers. The section below describes the expected impacts on manufacturers at each considered TSL. DOE first discusses the impacts of potential AFUE standards and then turns to the impacts of potential standby mode and off mode standards. Chapter 12 of the final rule TSD explains the analysis in further detail.
Table V.31 and Table V.32 depict the estimated financial impacts (represented by changes in INPV) of amended energy conservation standards on manufacturers of residential boilers, as well as the conversion costs that DOE expects manufacturers would incur for all product classes at each TSL. To evaluate the range of cash-flow impacts on the residential boiler industry, DOE modeled two different markup scenarios using different assumptions that correspond to the range of anticipated market responses to amended energy conservation standards: (1) The preservation of gross margin percentage scenario; and (2) the preservation of per-unit operating profit scenario. Each of these scenarios is discussed immediately below.
To assess the lower (less severe) end of the range of potential impacts, DOE modeled a preservation of gross margin percentage markup scenario, in which a uniform “gross margin percentage” markup is applied across all potential efficiency levels. In this scenario, DOE assumed that a manufacturer's absolute dollar markup would increase as production costs increase in the standards case.
To assess the higher (more severe) end of the range of potential impacts, DOE modeled the preservation of per-unit operating profit markup scenario, which assumes that manufacturers would not be able to generate greater operating profit on a per-unit basis in the standards case as compared to the no-new-standards case. Rather, as manufacturers make the necessary investments required to convert their facilities to produce new standards-compliant products and incur higher costs of goods sold, their percentage markup decreases. Operating profit does not change in absolute dollars and decreases as a percentage of revenue.
As noted in the MIA methodology discussion (see IV.J.2), in addition to markup scenarios, the MPC, shipments, and conversion cost assumptions also affect INPV results.
The results in Table V.31 and Table V.32 show potential INPV impacts for residential boiler manufacturers; Table V.31 reflects the lower bound of impacts, and Table V.32 represents the upper bound of impacts.
Each of the modeled scenarios in the AFUE standards analysis results in a unique set of cash flows and corresponding industry values at each TSL. In the following discussion, the INPV results refer to the difference in industry value between the no-new-standards case and each standards case that results from the sum of discounted cash flows from the base year 2014 through 2050, the end of the analysis period.
To provide perspective on the short-run cash-flow impact, DOE discusses the change in free cash flow between the no-new-standards case and the standards case at each TSL in the year before new standards would take effect. These figures provide an understanding of the magnitude of the required conversion costs at each TSL relative to the cash flow generated by the industry in the no-new-standards case.
TSL 1 represents EL 1 for all product classes. At TSL 1, DOE estimates impacts on INPV for residential boiler manufacturers to range from −0.58 percent to −0.09 percent, or a change in INPV of −$2.12 million to −$0.33 million. At this potential standard level, industry free cash flow would be estimated to decrease by approximately 1.52 percent to $26.01 million, compared to the no-new-standards case value of $26.42 million in 2020, the year before the compliance date.
At TSL 1, DOE does not anticipate manufacturers would lose a significant portion of their INPV. This is largely due to the fact that the vast majority of shipments would already meet or exceed the efficiency levels prescribed at TSL 1. Today, approximately 85 percent of residential boiler product listings would meet or exceed the efficiency levels at TSL 1. DOE expects residential boiler manufacturers to incur $1.34 million in product conversion costs for boiler redesign and testing. DOE does not expect the modest efficiency gains at this TSL to require any major product upgrades or capital investments.
At TSL 1, under the preservation of gross margin percentage scenario, the shipment-weighted average MPC increases by approximately 1 percent relative to the no-new-standards case MPC. Manufacturers are able to fully pass on this cost increase to consumers by design in this markup scenario. This slight price increase would not mitigate the $1.34 million in conversion costs estimated at TSL 1, resulting in slightly negative INPV impacts at TSL 1 under the this scenario.
Under the preservation of per-unit operating profit markup scenario, manufacturers earn the same operating profit as would be earned in the no-new-standards case, but do not earn additional profit from their investments. The 1-percent MPC increase is outweighed by a slightly lower average markup and $1.34 million in conversion costs, resulting in small negative impacts at TSL 1.
TSL 2 sets the efficiency level at EL 1 for three product classes (gas-fired steam boilers, gas-fired hot water boilers, and oil-fired steam boilers) and EL 2 for one product classes (oil-fired hot water boilers). At TSL 2, DOE estimates impacts on INPV for residential boiler manufacturers to range
DOE does not anticipate manufacturers would lose a substantial portion of their INPV, because a large percentage of shipments would still meet or exceed the efficiency levels prescribed at this TSL. At TSL 2, DOE estimates that today, 74 percent of residential boiler product listings would meet or exceed the efficiency levels analyzed. The drop in the percentage of compliant products is due to the fact that the oil-fired hot water product class would move to EL 2. The non-compliant products would not have a large impact on INPV because oil-fired boilers would only comprise approximately 30 percent of residential boiler shipments in 2021 according to DOE projections, while gas-fired boilers would comprise over 70 percent of shipments.
DOE expects conversion costs would increase, but would still remain small compared to total industry value, as most manufacturers have gas-fired boilers at the prescribed efficiency levels on the market and would only have to make minor changes to their production processes. While the percentage of oil-fired boilers at these efficiency levels on the market is lower, manufacturers did not cite any major investments that would have to be made to reach the efficiency levels at EL 2 for oil-fired hot water products. Manufacturers also pointed out that gas-fired boiler shipments vastly out-pace oil-fired boiler shipments and that the market is continuing to trend towards gas-fired products. Overall, DOE estimates manufacturers would incur $1.60 million in product conversion costs for product redesign and testing and $0.43 million in capital conversion costs to make minor changes to their production lines.
At TSL 2, under the preservation of gross margin percentage scenario, the shipment-weighted average MPC increases by 2 percent relative to the no-new-standards case MPC. In this scenario, INPV impacts are slightly positive because of manufacturers' ability to pass the higher production costs to consumers outweighs the $2.03 million in total conversion costs. Under the preservation of per-unit operating profit markup scenario, the 2-percent MPC increase is outweighed by a slightly lower average markup and $2.03 million in total conversion costs, resulting in minimally negative impacts at TSL 2.
TSL 3 represents EL 1 for one product class (gas-fired steam boilers) and EL 2 for three product classes (oil-fired hot water boilers, gas-fired hot water boilers, and oil-fired steam boilers). At TSL 3, DOE estimates impacts on INPV for residential boiler manufacturers to range from −0.71 percent to 0.44 percent, or a change in INPV of −$2.63 million to $1.62 million. At this potential standard level, industry free cash flow would be estimated to decrease by approximately 2.92 percent in 2020, the year before compliance, to $25.64 million compared to the no-new-standards case value of $26.42 million.
While more significant than the impacts at TSL 2, the impacts on INPV at TSL 3 would still be relatively minor compared to the total industry value. Percentage impacts on INPV would be slightly positive to slightly negative at TSL 3. DOE does not anticipate that manufacturers would lose a significant portion of their INPV at this TSL. While less than the previous TSLs, today, 63 percent of product listings already meet or exceed the efficiency levels prescribed at TSL 3. DOE expects conversion costs to remain small at TSL 3 compared to the total industry value. DOE estimates that product conversion costs would increase as manufacturers would have to redesign a larger percentage of their offerings and may have to design new products to replace lower-efficiency commodity products. At this TSL, DOE estimates that residential boiler manufacturers would incur $1.66 million in product conversion costs. Manufacturers, however, did not cite any major changes that would need to be made to production equipment to achieve the efficiency levels at this TSL. DOE, therefore, estimates that capital conversion costs would remain relatively low at $0.61 million for the industry.
At TSL 3, under the preservation of gross margin percentage markup scenario, the shipment-weighted average MPC increases by 2 percent relative to the no-new-standards case MPC. In this scenario, INPV impacts are slightly positive because manufacturers' ability to pass the higher production costs to consumers outweighs the $2.27 million in total conversion costs. Under the preservation of per-unit operating profit markup scenario, the 2 percent MPC increase is slightly outweighed by a slightly lower average markup and $2.27 million in total conversion costs, resulting in minimally negative to minimally positive impacts at TSL 3.
TSL 4 represents EL 1 for one product class (gas-fired steam boilers), EL 3 for two product classes (oil-fired hot water boilers and oil-fired steam boilers), and EL 4 for one product class (gas-fired hot water boilers). At TSL 4, DOE estimates impacts on INPV for residential boiler manufacturers to range from −22.73 percent to −4.99 percent, or a change in INPV of −$83.61 million to −$18.35 million. At this potential standard level, industry free cash flow would be estimated to decrease by approximately 131.93 percent in the year before compliance (2020) to −$8.43 million relative to the no-new-standards case value of $26.42 million.
Percentage impacts on INPV are moderately to significantly negative at TSL 4. Today, only 27 percent of residential boiler product listings would meet or exceed the efficiency levels at TSL 4. DOE expects that conversion costs would increase significantly at this TSL due to the fact that manufacturers would meet these efficiency levels by using condensing heat exchangers in their gas-fired and oil-fired hot water boiler products.
While condensing products and condensing technology are not entirely unfamiliar to the companies that already make condensing products domestically, most manufacturers in the residential boiler industry have relatively little experience in manufacturing the heat exchanger itself. If manufacturers choose to develop their own heat exchanger production capacity, a great deal of testing, prototyping, design, and manufacturing engineering resources will be required to design the heat exchanger and the more advanced control systems found in more-efficient products.
These capital and production conversion expenses lead to the large reduction in cash flow in the years preceding the standard. DOE believes that only a few domestic manufacturers have the resources for this undertaking and believes that some large manufacturers and many smaller manufacturers would continue to source their heat exchangers. Ultimately, DOE estimates that manufacturers would incur $24.53 million in product conversion costs, as some manufacturers would be expected to attempt to add production capacity for condensing heat exchangers and others would have to design baseline products around a sourced condensing heat exchanger. In addition, DOE estimates that manufacturers would incur $61.10 million in capital conversion costs, which would be driven by capital investments in heat exchanger production lines.
At TSL 4, under the preservation of gross margin percentage markup scenario, the shipment-weighted average MPC increases by approximately 30 percent relative to the no-new-standards case MPC. In this scenario, INPV impacts are slightly negative because manufacturers' ability to pass the higher production costs to consumers is slightly outweighed by the $85.63 million in total conversion costs. Under the preservation of per-unit operating profit markup scenario, the 30-percent MPC increase is outweighed by a lower average markup of 1.39 (compared to 1.41 in the preservation of gross margin percentage markup scenario) and $85.63 million in total conversion costs, resulting in significantly negative impacts at TSL 4.
TSL 5 represents EL 2 for one product class (gas-fired steam boilers), EL 3 for two product classes (oil-fired hot water boilers and oil-fired steam boilers), and EL 6 for one product class (gas-fired hot water boilers). TSL 5 represents max-tech for all product classes. At TSL 5, DOE estimates impacts on INPV for residential boiler manufacturers to range from −38.59 percent to −0.30 percent, or a change in INPV of −$141.95 million to −$1.12 million. At this potential standard level, industry free cash flow would be estimated to decrease by approximately 160.65 percent in the year before compliance (2020) to −$16.02 million relative to the no-new-standards case value of $26.42 million.
At TSL 5, percentage impacts on INPV range from slightly negative to significantly negative. Today, only 4 percent of residential boiler product listings would already meet or exceed the efficiency levels prescribed at TSL 5. DOE expects conversion costs to continue to increase at TSL 5, as almost all products on the market would have to be redesigned and new products would have to be developed. As with TSL 4, DOE believes that at these efficiency levels, some manufacturers would choose to develop their own condensing heat exchanger production, rather than continuing to source these components. DOE estimates that product conversion costs would increase to $37.19 million, as manufacturers would have to redesign a larger percentage of their offerings, implement complex control systems, and meet max-tech for all product classes. DOE estimates that manufacturers would incur $69.52 million in capital conversion costs due to some manufacturers choosing to develop their own heat exchanger production and others having to increase the throughput of their existing condensing boiler production lines.
At TSL 5, under the preservation of gross margin percentage markup scenario, the shipment-weighted average MPC increases by approximately 61 percent relative to the no-new-standards case MPC. In this scenario, INPV impacts are negative because manufacturers' ability to pass the higher production costs to consumers is outweighed by the $106.71 million in total conversion costs. Under the preservation of per-unit operating profit markup scenario, the 61-percent MPC increase is outweighed by a lower average markup of 1.36 and $106.71 million in total conversion costs, resulting in significantly negative impacts at TSL 5.
Standby mode and off mode standards results are presented in Table V.33 and Table V.34. The impacts of standby mode and off mode features were analyzed for the same product classes as the amended AFUE standards, but at different efficiency levels, which correspond to a different set of technology options for reducing standby mode and off mode energy consumption. Therefore, the TSLs in the standby mode and off mode analysis do not correspond to the TSLs in the AFUE analysis. Also, the electric boiler product classes were not analyzed in the GRIM for AFUE standards. As a result, quantitative numbers are also not available for the GRIM analyzing standby mode and off mode standards. However, the standby mode and off mode technology options considered for electric boilers are identical to the technology options for all other residential boiler product classes. Consequently, DOE expects the standby mode and off mode impacts on electric boilers to be of the same order of magnitude as the impacts on all other boiler product classes.
The impacts of standby mode and off mode features were analyzed for the same two markup scenarios to represent the upper and lower bounds of industry impacts for residential boilers that were used in the AFUE analysis: (1) A preservation of gross margin percentage scenario; and (2) a preservation of per-unit operating profit scenario. As with the AFUE analysis, the preservation of gross margin percentage represents the lower bound of impacts, while the preservation of per-unit operating profit scenario represents the upper bound of impacts.
Each of the modeled scenarios in the standby mode and off mode analyses results in a unique set of cash flows and corresponding industry values at each TSL. In the following discussion, the INPV results refer to the difference in industry value between the no-new-standards case and each standards case that results from the sum of discounted cash flows from the base year 2014 through 2050, the end of the analysis period.
To provide perspective on the short-run cash flow impact, DOE discusses
TSL 1 represents EL 1 for all product classes. At TSL 1, DOE estimates impacts on INPV for residential boiler manufacturers to decrease by less than one tenth of a percent in both markup scenarios, which corresponds to a change in INPV of −$0.22 million to −$0.10 million. At this potential standard level, industry free cash flow is estimated to decrease by approximately 0.24 percent to $26.35 million, compared to the no-new-standards case value of $26.42 million in 2020, the year before the compliance date.
At TSL 1, DOE does not anticipate that manufacturers would lose a significant portion of their INPV. This is largely due to the small incremental costs of standby mode and off mode components relative to the overall costs of residential boiler products. DOE expects residential boiler manufacturers to incur $0.21 million in product conversion costs at TSL 1, primarily for testing. DOE does not expect that manufacturers would incur any capital conversion costs, as the product upgrades will only involve integrating a purchase part.
TSL 2 sets the efficiency level at EL 2 for all product classes. At TSL 2, DOE estimates impacts on INPV for residential boilers manufacturers to range from −0.02 percent to −0.01 percent, or a change in INPV of −$0.09 million to −$0.04 million. At this potential standard level, industry free cash flow is estimated to decrease by approximately 0.24 percent to $26.35 million, compared to the no-new-standards case value of $26.42 million in 2020, the year before the compliance date.
At TSL 2, DOE does not anticipate that manufacturers would lose a significant portion of their INPV. This is largely due to the small incremental costs of standby mode and off mode components relative to the overall costs of residential boiler products. DOE expects residential boiler manufacturers to incur $0.21 million in product conversion costs at TSL 2, primarily for testing. DOE does not expect that manufacturers would incur any capital conversion costs, as the product upgrades will only involve integrating a purchase part.
TSL 3 represents EL 3 for all product classes. At TSL 3, DOE estimates impacts on INPV for residential boiler manufacturers to range from −0.46 percent to 0.12 percent, or a change in INPV of −$1.71 million to $0.45 million. At this potential standard level, industry free cash flow is estimated to decrease by approximately 0.24 percent in the year before compliance to $26.35 million compared to the no-new-standards case value of $26.42 million in 2020, the year before the compliance date.
At TSL 3, DOE does not anticipate that manufacturers would lose a
As noted in section III.B, DOE analyzed the AFUE standard and the standby mode and off mode standard independently. The AFUE metric accounts for the fossil fuel consumption, whereas the standby mode and off mode metric accounts for the electrical energy use in standby mode and off mode. There are five trial standard levels under consideration for the AFUE standard and three trial stand levels under consideration for the standby mode and off mode standard.
Both the AFUE standard and the standby mode and off mode standard could necessitate changes in manufacturer production costs, as well as conversion cost investments. The assumed design changes for the two standards in the engineering analysis are independent; therefore, changes in manufacturing production costs and the conversion costs are additive. DOE expects that the costs to manufacturers would be mathematically the same regardless of whether or not the standby mode and off mode standards were combined or analyzed separately.
Using the current approach that considers AFUE and standby mode and off mode standards separately, the range of potential impacts of combined standards on INPV is determined by summing the range of potential changes in INPV from the AFUE standard and from the standby mode and off mode standard. Similarly, to estimate the combined conversion costs, DOE sums the estimated conversion costs from the two standards. DOE does not present the combined impacts of all possible combinations of AFUE and standby mode and off mode TSLs in this notice. However, DOE expects the combined impact of the TSLs proposed for AFUE and standby mode and off mode electrical consumption in this final rule to range from −1.18 to 0.56 percent, which is approximately equivalent to a reduction of $4.34 million to an increase of $2.08 million.
To quantitatively assess the impacts of energy conservation standards on direct employment in the residential boiler industry, DOE used the GRIM to estimate the domestic labor expenditures and number of employees in the no-new-standards case and at each TSL in 2021. DOE used statistical data from the U.S. Census Bureau's 2011 Annual Survey of Manufacturers (ASM),
The total labor expenditures in the GRIM are converted to domestic production employment levels by dividing production labor expenditures by the annual payment per production worker (production worker hours times the labor rate found in the U.S. Census Bureau's 2011 ASM). The estimates of production workers in this section cover workers, including line-supervisors who are directly involved in fabricating and assembling a product within the manufacturing facility. Workers performing services that are closely associated with production operations, such as materials handling tasks using forklifts, are also included as production labor. DOE's estimates only account for production workers who manufacture the specific products covered by this rulemaking. The total direct employment impacts calculated in the GRIM are the sum of the changes in the number of production workers resulting from the amended energy conservation standards for residential boilers, as compared to the no-new-standards case. In general, more-efficient boilers are more complex and more labor intensive and require specialized knowledge about control systems, electronics, and the different metals needed for the heat exchanger. Per-unit labor requirements and production time requirements increase with higher energy conservation standards. As a result, the total labor calculations described in this paragraph (which are generated by the GRIM) are considered an upper bound to direct employment forecasts.
On the other hand, some manufacturers may choose not to make the necessary investments to meet the amended standards for all product classes. Alternatively, they may choose to relocate production facilities where conversion costs and production costs are lower. To establish a lower bound to negative employment impacts, DOE estimated the maximum potential job loss due to manufacturers either leaving the industry or moving production to foreign locations as a result of amended standards. In the case of residential boilers, most manufacturers agreed that higher standards would probably not push their production overseas due to shipping considerations. Rather, high enough standards could force manufacturers to rethink their business models. Instead of vertically integrated manufacturers, they would become assemblers and would source most of their components from overseas. This would mean any workers involved in casting metals that would be corroded in a condensing product would likely lose their jobs. These lower bound estimates were based on GRIM results, conversion cost estimates, and content from manufacturers interviews. The lower bound of employment is presented in Table V.35 below.
DOE estimates that in the absence of amended energy conservation standards, there would be 761 domestic production workers in the residential boiler industry in 2021, the year of compliance. DOE estimates that 90 percent of residential boilers sold in the United States are manufactured domestically. Table V.35 shows the range of the impacts of potential amended energy conservation standards on U.S. production workers of residential boilers.
At the upper end of the range, all examined TSLs show positive impacts on domestic employment levels. Producing more-efficient boilers tends to require more labor, and DOE estimates that if residential boiler manufacturers chose to keep their current production in the U.S., domestic employment could increase at each TSL. In interviews, several manufacturers who produce high-efficiency boiler products stated that a standard that went to condensing levels could cause them to hire more employees to increase their production capacity. Others stated that a condensing standard would require additional engineers to redesign production processes, as well as metallurgy experts and other workers with experience working with higher-efficiency products. DOE, however, acknowledges that particularly at higher standard levels, manufacturers may not keep their production in the U.S. and also may choose to restructure their businesses or exit the market entirely.
DOE does not expect any significant changes in domestic employment at TSL 1 or TSL 2. Most manufactures agreed that these efficiency levels would require minimal changes to their production processes and that most employees would be retained. DOE estimates that there could be a small loss of domestic employment at TSL 3 due to the fact that some manufacturers would have to drop their 82-percent-efficient products, except for their gas-fired steam boiler products. Several manufacturers commented that those products were their commodity products and drove a high percentage of their sales. Several manufacturers expressed that they could lose a significant number of employees at TSL 4 and TSL 5, due to the fact that these TSLs contain condensing efficiency levels for the gas-fired hot water boiler product class. These manufacturers have employees who work on production lines that produce cast iron sections and carbon steel or copper heat exchangers for lower to mid-efficiency products. If amended energy conservation standards were to require condensing efficiency levels, these employees would no longer be needed for that function, and manufacturers would have to decide whether to develop their own condensing heat exchanger production, source heat exchangers from Asia or Europe and assemble higher-efficiency products, or leave the market entirely.
DOE notes that its estimates of the impacts on direct employment are based on the analysis of amended AFUE energy efficiency standards only. Standby mode and off mode technology options considered in the engineering analysis would result in component swaps, which would not make the product significantly more complex and would not be difficult to implement. While some product development effort would be required, DOE does not expect the standby mode and off mode standard to meaningfully affect the amount of labor required in production. Consequently, DOE does not anticipate that the proposed standby mode and off mode standards will have a significant impact on direct employment.
DOE notes that the employment impacts discussed here are independent of the indirect employment impacts to the broader U.S. economy, which are documented in chapter 15 of the final rule TSD.
Most residential boiler manufacturers stated that their current production is only running at 50-percent to 70-percent capacity and that any standard that does not propose efficiency levels where manufacturers would use condensing technology for hot water boilers would not have a large effect on capacity. The impacts of a potential condensing standard on manufacturer capacity are difficult to quantify. Some manufacturers who are already making condensing products with a sourced heat exchanger said they would likely be able to increase production using the equipment they already have by utilizing a second shift. Others said a condensing standard would idle a large portion of their business, causing stranded assets and decreased capacity. These manufactures would have to determine how to best increase their condensing boiler production capacity. DOE believes that some larger domestic manufacturers may choose to add production capacity for a condensing heat exchanger production line.
Manufacturers stated that in a scenario where a potential standard would require efficiency levels at which manufacturers would use condensing technology, there is concern about the level of technical resources required to redesign and test all products. The engineering analysis shows that increasingly complex components and control strategies are required as standard levels increase. Manufacturers commented in interviews that the industry would need to add electrical engineering and control systems engineering talent beyond current staffing to meet the redesign requirements of higher TSLs. Additional training might be needed for manufacturing engineers, laboratory technicians, and service personnel if condensing products were broadly adopted. However, because TSL 3 (the adopted level) would not require condensing standards, DOE does not expect manufacturers to face long-term capacity constraints due to the standard levels proposed in this notice.
Small manufacturers, niche equipment manufacturers, and manufacturers exhibiting a cost structure substantially different from the industry average could be affected disproportionately. Using average cost assumptions developed for an industry cash-flow estimate is inadequate to assess differential impacts among manufacturer subgroups.
For the residential boiler industry, DOE identified and evaluated the impact of amended energy conservation
While any one regulation may not impose a significant burden on manufacturers, the combined effects of recent or impending regulations may have serious consequences for some manufacturers, groups of manufacturers, or an entire industry. Assessing the impact of a single regulation may overlook this cumulative regulatory burden. In addition to energy conservation standards, other regulations can significantly affect manufacturers' financial operations. Multiple regulations affecting the same manufacturer can strain profits and lead companies to abandon product lines or markets with lower expected future returns than competing products. For these reasons, DOE conducts an analysis of cumulative regulatory burden as part of its rulemakings pertaining to appliance efficiency.
For the cumulative regulatory burden analysis, DOE looks at other regulations that could affect residential boiler manufacturers that will take effect approximately three years before or after the 2021 compliance date of amended energy conservation standards for these products. In interviews, manufacturers cited Federal regulations on equipment other than residential boilers that contribute to their cumulative regulatory burden. The compliance years and expected industry conversion costs of relevant amended energy conservation standards are indicated in the Table V.36. DOE has included certain Federal regulations in the Table V.36 that have compliance dates beyond the three-year range of DOE's analysis, because those regulations were cited multiple times by manufacturers in interviews and written comments; they are included here for reference.
In addition to Federal energy conservation standards, DOE identified revisions to the DOE test procedure as another regulatory burdens that would affect manufacturers of residential boilers. On July 28, 2008, DOE published a technical amendment to the 2007 furnaces and boilers final rule, whose purpose was to add design requirements established in the Energy Independence and Security Act of 2007 (EISA 2007). 73 FR 43611. In relevant part, these design requirements mandate the use of an automatic means for adjusting the water temperature for gas-fired hot water boilers, oil-fired hot water boilers, and electric hot water boilers. DOE recently published revisions to its test procedure for
To estimate the energy savings attributable to potential standards for residential boilers, DOE compared their energy consumption under the no-new-standards case to their anticipated energy consumption under each TSL. The savings are measured over the entire lifetime of products purchased in the 30-year period that begins in the year of anticipated compliance with amended standards (2021–2050). Table V.37 presents DOE's projections of the national energy savings for each TSL considered for residential boilers AFUE standards.
Table V.38 present DOE's projections of the national energy savings for each TSL considered for residential boilers standby mode and off mode standards. The savings were calculated using the approach described in section IV.H of this notice.
OMB Circular A–4
DOE estimated the cumulative NPV of the total costs and savings for consumers that would result from the TSLs considered for residential boilers. In accordance with OMB's guidelines on regulatory analysis,
Table V.41 shows the consumer NPV results for each standby mode and off mode TSL considered for residential boilers. In each case, the impacts cover the lifetime of products purchased in 2021–2050.
The NPV results based on the aforementioned 9-year analytical period are presented in Table V.42 for AFUE standards. The impacts are counted over the lifetime of products purchased in 2021–2029. As mentioned previously, such results are presented for informational purposes only and are not indicative of any change in DOE's analytical methodology or decision criteria.
The above results reflect the use of a constant price trend (reference case) to estimate the future prices for residential boilers over the analysis period (see section IV.H of this document). DOE also conducted a sensitivity analysis that considered one scenario with an increasing price trend than the reference case and one scenario with a decreasing price trend. The results of these alternative cases are presented in appendix 10C of the final rule TSD. In the increasing price trend case, the NPV of consumer benefits is lower than in the reference case. In the decreasing price trend case, the NPV of consumer benefits is higher than in the reference case.
DOE expects energy conservation standards for residential boilers to reduce energy bills for consumers of those products, with the resulting net savings being redirected to other forms of economic activity. These expected shifts in spending and economic activity could affect the demand for labor. As described in section IV.N, DOE used an input/output model of the U.S. economy to estimate indirect employment impacts of the TSLs that DOE considered in this rulemaking. DOE understands that there are uncertainties involved in projecting employment impacts, especially changes in the later
The results suggest that the adopted standards are likely to have a negligible impact on the net demand for labor in the economy. The net change in jobs is so small that it would be imperceptible in national labor statistics and might be offset by other, unanticipated effects on employment. Chapter 16 of the final rule TSD presents detailed results regarding anticipated indirect employment impacts.
DOE has concluded that the amended standards adopted in this final rule would not reduce the utility or performance of the residential boilers under consideration in this rulemaking. Manufacturers of these products currently offer units that meet or exceed the adopted standards.
As discussed in section III.E.1.e, DOE considered any lessening of competition that is likely to result from new or amended standards. The Attorney General of the United States (Attorney General) determines the impact, if any, of any lessening of competition likely to result from a proposed standard and transmits such determination in writing to the Secretary, together with an analysis of the nature and extent of such impact. To assist the Attorney General in making such determination, DOE provided the Department of Justice (DOJ) with copies of the NOPR and the TSD for review. In its assessment letter responding to DOE, DOJ concluded that the proposed energy conservation standards for residential boilers are unlikely to have a significant adverse impact on competition. DOE is publishing the Attorney General's assessment at the end of this final rule.
Enhanced energy efficiency, where economically justified, improves the Nation's energy security, strengthens the economy, and reduces the environmental impacts (costs) of energy production. Energy conservation resulting from amended AFUE and new standby mode and off mode standards for residential boilers is expected to yield environmental benefits in the form of reduced emissions of air pollutants and greenhouse gases. As a measure of this reduced demand, chapter 15 in the final rule TSD presents the estimated reduction in generating capacity, relative to the no-new-standards case, for the TSLs that DOE considered in this rulemaking.
Table V.43 and Table V.44 provide DOE's estimate of cumulative emissions reductions expected to result from the TSLs considered in this rulemaking for AFUE standards and standby mode and off mode standards, respectively. The tables include site and power sector emissions and upstream emissions. The emissions were calculated using the multipliers discussed in section IV.K. DOE reports annual emissions reductions for each TSL in chapter 13 of the final rule TSD.
As noted in section IV.K, the estimated CO
As part of the analysis for this final rule, DOE estimated monetary benefits likely to result from the reduced emissions of CO
Table V.45 presents the global value of CO
DOE is well aware that scientific and economic knowledge about the contribution of CO
DOE also estimated the cumulative monetary value of the economic benefits associated with NO
The Secretary of Energy, in determining whether a standard is economically justified, may consider any other factors that the Secretary deems to be relevant. (42 U.S.C. 6295(o)(2)(B)(i)(VII)) No other factors were considered in this analysis.
The NPV of the monetized benefits associated with emissions reductions can be viewed as a complement to the NPV of the consumer savings calculated for each TSL considered in this rulemaking. Table V.49 presents the NPV values that result from adding the estimates of the potential economic benefits resulting from reduced CO
Table V.50 presents the NPV values that result from adding the estimates of the potential economic benefits resulting from reduced CO
In considering the above results, two issues are relevant. First, the national operating cost savings are domestic U.S. consumer monetary savings that occur as a result of market transactions, while the value of CO
When considering standards, the new or amended energy conservation standards that DOE adopts for any type (or class) of covered product, including residential boilers, must be designed to achieve the maximum improvement in energy efficiency that the Secretary determines is technologically feasible and economically justified. (42 U.S.C. 6295(o)(2)(A)) In determining whether a standard is economically justified, the Secretary must determine whether the benefits of the standard exceed its burdens by, to the greatest extent practicable, considering the seven statutory factors discussed previously. (42 U.S.C. 6295(o)(2)(B)(i)) The new or amended standard must also result in significant conservation of energy. (42 U.S.C. 6295(o)(3)(B))
For this final rule, DOE considered the impacts of amended standards for residential boilers at each TSL, beginning with the maximum technologically feasible level, to determine whether that level was economically justified. Where the max-tech level was not justified, DOE then considered the next most efficient level and undertook the same evaluation until it reached the highest efficiency level that is both technologically feasible and economically justified and saves a significant amount of energy.
To aid the reader as DOE discusses the benefits and/or burdens of each TSL, tables in this section present a summary of the results of DOE's quantitative analysis for each TSL. In addition to the quantitative results presented in the tables, DOE also considers other burdens and benefits that affect economic justification. These include the impacts on identifiable subgroups of consumers who may be disproportionately affected by a national standard and impacts on employment.
DOE also notes that the economics literature provides a wide-ranging discussion of how consumers trade off upfront costs and energy savings in the absence of government intervention. Much of this literature attempts to explain why consumers appear to undervalue energy efficiency improvements. There is evidence that consumers undervalue future energy savings as a result of: (1) A lack of information; (2) a lack of sufficient salience of the long-term or aggregate benefits; (3) a lack of sufficient savings to warrant delaying or altering purchases; (4) excessive focus on the short term, in the form of inconsistent weighting of future energy cost savings relative to available returns on other investments; (5) computational or other difficulties associated with the evaluation of relevant tradeoffs; and (6) a divergence in incentives (for example, between renters and owners, or builders and purchasers). Having less than perfect foresight and a high degree of uncertainty about the future, consumers may trade off these types of investments at a higher than expected rate between current consumption and uncertain future energy cost savings. This undervaluation suggests that regulation that promotes energy efficiency can produce significant net private gains (as well as producing social gains by, for example, reducing pollution).
In DOE's current regulatory analysis, potential changes in the benefits and costs of a regulation due to changes in consumer purchase decisions are included in two ways. First, if consumers forego the purchase of a product in the standards case, this decreases sales for product manufacturers, and the impact on manufacturers attributed to lost revenue is included in the MIA. Second, DOE accounts for energy savings attributable only to products actually used by consumers in the standards case; if a regulatory option decreases the number of products purchased by consumers, this decreases the potential energy savings from an energy conservation standard. DOE provides estimates of shipments and changes in the volume of product purchases in chapter 9 of the final rule TSD. However, DOE's current analysis does not explicitly control for
While DOE is not prepared at present to provide a fuller quantifiable framework for estimating the benefits and costs of changes in consumer purchase decisions due to an energy conservation standard, DOE is committed to developing a framework that can support empirical quantitative tools for improved assessment of the consumer welfare impacts of appliance standards. DOE has posted a paper that discusses the issue of consumer welfare impacts of appliance energy conservation standards, and potential enhancements to the methodology by which these impacts are defined and estimated in the regulatory process.
Table V.51 and Table V.52 summarize the quantitative impacts estimated for each AFUE TSL for residential boilers. The national impacts are measured over the lifetime of residential boilers purchased in the 30-year period that begins in the anticipated year of compliance with amended standards (2021–2050). The energy savings, emissions reductions, and value of emissions reductions refer to full-fuel-cycle results. The efficiency levels contained in each TSL are described in section V.A of this notice.
DOE first considered TSL 5, which represents the max-tech efficiency levels. TSL 5 would save an estimated 1.6 quads of energy, an amount DOE considers significant. Under TSL 5, the NPV of consumer benefit would be $−2.127 billion using a discount rate of 7 percent, and $0.597 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 5 are 86.90 Mt of CO
At TSL 5, the average LCC impact is a savings of $303 for gas-fired hot water boilers, $207 for gas-fired steam boilers, $192 for oil-fired hot water boilers, and $505 for oil-fired steam boilers. The simple payback period is 11.8 years for gas-fired hot water boilers, 10.7 years for gas-fired steam boilers, 16.5 years for oil-fired hot water boilers, and 7.8 years for oil-fired steam boilers. The share of consumers experiencing a net LCC cost is 55.5 percent for gas-fired hot water boilers, 30.8 percent for gas-fired steam boilers, 58.9 percent for oil-fired hot water boilers, and 34.2 percent for oil-fired steam boilers.
At TSL 5, the projected change in INPV ranges from a decrease of $141.95 million to a decrease of $1.12 million. If the decrease of $141.95 million were to occur, TSL 5 could result in a net loss of 38.59 percent in INPV to manufacturers of covered residential boilers.
The Secretary concludes that at TSL 5 for residential boilers, the benefits of energy savings, positive NPV of consumer benefits at a 3-percent discount rate, emission reductions, and the estimated monetary value of the emissions reductions would be outweighed by the negative NPV of consumer benefits at a 7-percent discount rate, the economic burden on some consumers, and the impacts on manufacturers, including the conversion costs and profit margin impacts that could result in a large reduction in INPV. Consequently, the Secretary has concluded that TSL 5 is not economically justified.
DOE then considered TSL 4. TSL 4 would save an estimated 0.77 quads of energy, an amount DOE considers significant. Under TSL 4, the NPV of consumer benefit would be $−1.349 billion using a discount rate of 7 percent, and $0.082 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 4 are 43.76 Mt of CO
At TSL 4, the average LCC impact is a savings of $632 for gas-fired hot water boilers, $333 for gas-fired steam boilers, $192 for oil-fired hot water boilers, and $505 for oil-fired steam boilers. The simple payback period is 8.4 years for gas-fired hot water boilers, 2.7 years for gas-fired steam boilers, 16.5 years for oil-fired hot water boilers, and 7.8 years for oil-fired steam boilers. The share of consumers experiencing a net LCC cost is 21.9 percent for gas-fired hot water boilers, 0.9 percent for gas-fired steam boilers, 58.9 percent for oil-fired hot water boilers, and 34.2 percent for oil-fired steam boilers.
At TSL 4, the projected change in INPV ranges from a decrease of $83.61 million to a decrease of $18.35 million. If the decrease of $83.61 million were to occur, TSL 4 could result in a net loss of 22.73 percent in INPV to manufacturers of covered residential boilers.
The Secretary concludes that at TSL 4 for residential boilers, the benefits of energy savings, positive NPV of consumer benefits at a 3-percent discount rate, emission reductions, and the estimated monetary value of the emissions reductions would be outweighed by the negative NPV of consumer benefits at a 7-percent discount rate, the economic burden on some consumers, and the impacts on manufacturers, including the conversion costs and profit margin impacts that could result in a large reduction in INPV. Consequently, the Secretary has concluded that TSL 4 is not economically justified.
DOE then considered TSL 3. TSL 3 would save an estimated 0.16 quads of energy, an amount DOE considers significant. Under TSL 3, the NPV of consumer benefit would be $0.350
The cumulative emissions reductions at TSL 3 are 9.33 Mt of CO
At TSL 3, the average LCC impact is a savings of $364 for gas-fired hot water boilers, $333 for gas-fired steam boilers, $626 for oil-fired hot water boilers, and $434 for oil-fired steam boilers. The simple payback period is 1.2 years for gas-fired hot water boilers, 2.7 years for gas-fired steam boilers, 5.8 years for oil-fired hot water boilers, and 6.7 years for oil-fired steam boilers. The share of consumers experiencing a net LCC cost is 0.4 percent for gas-fired hot water boilers, 0.9 percent for gas-fired steam boilers, 8.8 percent for oil-fired hot water boilers, and 19.7 percent for oil-fired steam boilers.
At TSL 3, the projected change in INPV ranges from a decrease of $2.63 million to an increase of $1.62 million. If the decrease of $2.63 million were to occur, TSL 3 could result in a net loss of 0.71 percent in INPV to manufacturers of covered residential boilers.
After considering the analysis and weighing the benefits and the burdens, the Secretary has concluded that at TSL 3 for residential boilers, the benefits of energy savings, positive NPV of consumer benefit at both 3-percent and 7-percent discount rates, emission reductions, the estimated monetary value of the emissions reductions, and positive average LCC savings would outweigh the negative impacts on some consumers and on manufacturers, including the conversion costs that could result in a reduction in INPV for manufacturers. Accordingly, the Secretary of Energy has concluded that TSL 3 offers the maximum improvement in efficiency that is technologically feasible and economically justified, and would result in the significant conservation of energy.
Therefore, based on the above considerations, DOE is adopting the AFUE energy conservation standards for residential boilers at TSL 3. The amended energy conservation standards for residential boilers, which are expressed as AFUE, are shown in Table V.53.
Table V.54 and Table V.55 summarize the quantitative impacts estimated for each TSL considered for residential boiler standby mode and off mode power standards. The national impacts are measured over the lifetime of residential boilers purchased in the 30-year period that begins in the year of anticipated compliance with new standards (2021–2050). The energy savings, emissions reductions, and value of emissions reductions refer to full-fuel-cycle results. The efficiency levels contained in each TSL are described in section V.A of this notice.
DOE first considered TSL 3, which represents the max-tech efficiency levels. TSL 3 would save an estimated 0.0026 quads of energy. Under TSL 3, the NPV of consumer benefit would be $0.003 billion using a discount rate of 7 percent, and $0.014 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 3 are 0.153 Mt of CO
At TSL 3, the average LCC impact is a savings of $15 for gas-fired hot water boilers, $18 for gas-fired steam boilers, $20 for oil-fired hot water boilers, $13 for oil-fired steam boilers, $8 for electric hot water boilers, and $6 for electric steam boilers. The simple payback period is 6.7 years for gas-fired hot water boilers, 6.4 years for gas-fired
At TSL 3, the projected change in INPV ranges from a decrease of $1.71 million to an increase of $0.45 million, depending on the manufacturer markup scenario. If the larger decrease is realized, TSL 3 could result in a net loss of 0.46 percent in INPV to manufacturers of covered residential boilers.
Accordingly, the Secretary concludes that at TSL 3 for residential boiler standby mode and off mode power, the benefits of energy savings, positive NPV of consumer benefits at both 7-percent and 3-percent discount rates, emission reductions, the estimated monetary value of the emissions reductions, and positive average LCC savings would outweigh the negative impacts on some consumers and on manufacturers, including the conversion costs that could result in a reduction in INPV for manufacturers. Accordingly, the Secretary has concluded that TSL 3 would offer the maximum improvement in efficiency that is technologically feasible and economically justified, and would result in the significant conservation of energy.
Therefore, based on the above considerations, DOE is adopting the standby mode and off mode energy conservation standards for residential boilers at TSL 3. The new energy conservation standards for standby mode and off mode, which are expressed as maximum power in watts, are shown in Table V.56.
The benefits and costs of the adopted standards can also be expressed in terms of annualized values. The annualized monetary value of net benefits is the sum of: (1) The annualized national economic value (expressed in 2014$) of the benefits from operating products that meet the adopted standards (consisting primarily of operating cost savings from using less energy, minus increases in product purchase costs), which is another way of representing consumer NPV, and (2) the annualized monetary value of the benefits of CO
Table V.57 shows the annualized benefit and cost values for residential boilers under TSL 3 for AFUE standards, expressed in 2014$. The results under the primary estimate are as follows. Using a 7-percent discount rate for benefits and costs other than CO
Using a 3-percent discount rate for all benefits and costs and the average SCC series that has a value of $40.0/t in 2015, the estimated cost of the AFUE standards is $15.9 million per year in increased equipment costs, while the estimated benefits are $86.8 million per year in reduced operating costs, $15.5 million per year in CO
Table V.58 shows the annualized benefit and cost values for residential boilers under TSL 3 for standby mode and off mode standards, expressed in 2014$. The results under the primary estimate are as follows. Using a 7-percent discount rate for benefits and costs other than CO
Using a 3-percent discount rate for all benefits and costs and the average SCC series that has a value of $40.0/t in 2015, the estimated cost of the AFUE standards is $0.46 million per year in increased equipment costs, while the estimated benefits are $1.28 million per year in reduced operating costs, $0.25 million per year in CO
In order to provide a complete picture of the overall impacts of this final rule, the following combines and summarizes the benefits and costs for both the amended AFUE standards and the new standby mode and off mode standards for residential boilers. Table V.59 shows the combined annualized benefit and cost values for the AFUE standards and the standby mode and off mode standards for residential boilers. The results under the primary estimate are as follows. Using a 7-percent discount rate for benefits and costs other than CO
Using a 3-percent discount rate for all benefits and costs and the average SCC series that has a value of $40.0/t in 2015, the estimated cost of the residential boiler AFUE, standby mode, and off mode standards in this rule is $16.4 million per year in increased equipment costs, while the estimated benefits are $88.1 million per year in reduced equipment operating costs, $15.8 million per year in CO
Section 1(b)(1) of Executive Order 12866, “Regulatory Planning and Review,” 58 FR 51735 (Oct. 4, 1993), requires each agency to identify the problem that it intends to address, including, where applicable, the failures of private markets or public institutions that warrant new agency action, as well as to assess the significance of that problem. The problems that the adopted standards for residential boilers are intended to address are as follows:
(1) Insufficient information and the high costs of gathering and analyzing relevant information lead some consumers to miss opportunities to make cost-effective investments in energy efficiency.
(2) In some cases, the benefits of more-efficient equipment are not realized due to misaligned incentives between purchasers and users. An example of such a case is when the equipment purchase decision is made by a building contractor or building owner who does not pay the energy costs of operating the equipment.
(3) There are external benefits resulting from improved energy efficiency of appliances that are not captured by the users of such equipment. These benefits include externalities related to public health, environmental protection, and national energy security that are not reflected in energy prices, such as reduced emissions of air pollutants and greenhouse gases that impact human health and global warming. DOE attempts to qualify some of the external
The Administrator of the Office of Information and Regulatory Affairs (OIRA) in the OMB has determined that the regulatory action in this document is a “significant regulatory action” under section (3)(f) of Executive Order 12866. Accordingly, pursuant to section 6(a)(3)(B) of the Executive Order, DOE has provided to OIRA: (i) The text of the draft regulatory action, together with a reasonably detailed description of the need for the regulatory action and an explanation of how the regulatory action will meet that need; and (ii) An assessment of the potential costs and benefits of the regulatory action, including an explanation of the manner in which the regulatory action is consistent with a statutory mandate. DOE has included these documents in the rulemaking record.
In addition, the Administrator of OIRA has determined that the proposed regulatory action is an “economically significant regulatory action” under section (3)(f)(1) of Executive Order 12866. Accordingly, pursuant to section 6(a)(3)(C) of the Executive Order, DOE has provided to OIRA a regulatory impact analysis (RIA), including the underlying analysis, of benefits and costs anticipated from the regulatory action, together with, to the extent feasible, a quantification of those costs; and an assessment, including the underlying analysis, of costs and benefits of potentially effective and reasonably feasible alternatives to the planned regulation, and an explanation why the planned regulatory action is preferable to the identified potential alternatives. These assessments prepared pursuant to Executive Order 12866 can be found in the technical support document for this rulemaking. These documents have also been included in the rulemaking record.
DOE has also reviewed this regulation pursuant to Executive Order 13563, issued on January 18, 2011. 76 FR 3281 (Jan. 21, 2011). Executive Order 13563 is supplemental to and explicitly reaffirms the principles, structures, and definitions governing regulatory review established in Executive Order 12866. To the extent permitted by law, agencies are required by Executive Order 13563 to: (1) Propose or adopt a regulation only upon a reasoned determination that its benefits justify its costs (recognizing that some benefits and costs are difficult to quantify); (2) tailor regulations to impose the least burden on society, consistent with obtaining regulatory objectives, taking into account, among other things, and to the extent practicable, the costs of cumulative regulations; (3) select, in choosing among alternative regulatory approaches, those approaches that maximize net benefits (including potential economic, environmental, public health and safety, and other advantages; distributive impacts; and equity); (4) to the extent feasible, specify performance objectives, rather than specifying the behavior or manner of compliance that regulated entities must adopt; and (5) identify and assess available alternatives to direct regulation, including providing economic incentives to encourage the desired behavior, such as user fees or marketable permits, or providing information upon which choices can be made by the public.
DOE emphasizes as well that Executive Order 13563 requires agencies to use the best available techniques to quantify anticipated present and future benefits and costs as accurately as possible. In its guidance, OIRA has emphasized that such techniques may include identifying changing future compliance costs that might result from technological innovation or anticipated behavioral changes. For the reasons stated in the preamble, DOE believes that this final rule is consistent with these principles, including the requirement that, to the extent permitted by law, benefits justify costs and that net benefits are maximized.
The Regulatory Flexibility Act (5 U.S.C. 601
For manufacturers of residential boilers, the Small Business Administration (SBA) has set a size threshold, which defines those entities classified as “small businesses” for the purposes of the statute. DOE used the SBA's small business size standards to determine whether any small entities would be subject to the requirements of the rule. See 13 CFR part 121. The size standards are listed by North American Industry Classification System (NAICS) code and industry description and are available at
To estimate the number of companies that could be small business manufacturers of products covered by this rulemaking, DOE conducted a market survey using publically-available information to identify potential small manufacturers. DOE's research involved industry trade association membership directories (including AHRI), public databases (
DOE identified 36 manufacturers of residential boilers sold in the U.S. DOE then determined that 23 are large manufacturers or manufacturers that are foreign owned and operated. The remaining 13 domestic manufacturers meet the SBA's definition of a “small business.” Of these 13 small businesses, nine manufacture the boilers covered by this rulemaking, while the other four manufacturers rebrand imported
Before issuing this final rule, DOE attempted to contact all the small business manufacturers of residential boilers it had identified. Two of the small businesses agreed to take part in an MIA interview. DOE also obtained information about small business impacts while interviewing large manufacturers.
DOE estimates that small manufacturers control approximately 15 percent of the residential boiler market. Based on DOE's research, three small businesses manufacture all four product classes of boilers domestically; four small businesses primarily produce condensing boiler products (and rely heat exchangers sourced from other manufacturers); and two manufacturers primarily produce oil-fired hot water boiler products. The remaining four small businesses wholesale or rebrand products that are imported from Europe or Asia, or design products and source manufacturing to a domestic firm.
When confronted with new or amended energy conservation standards, small businesses must make investments in research and development to redesign their products, but because they have lower sales volumes, they must spread these costs across fewer units. Moreover, smaller manufacturers may experience higher per-model testing costs relative to larger manufacturers, as they may not possess their own test facilities and, therefore, must outsource all testing at a higher per-unit cost.
These considerations could affect the three small manufacturers that offer all four product classes, the two manufacturers that only produce one or two product classes, and the four small businesses that rebrand boilers that do their own design work could see negative impacts. Being small businesses, it is likely that these manufacturers have fewer engineers and product development resources and may have greater difficulty bringing their portfolio of products into compliance with the new and amended energy conservation standards within the allotted timeframe. Also, these small manufacturers may have to divert engineering resources from customer and new product initiatives for a longer period of time.
Smaller manufacturers often lack the purchasing power of larger manufacturers. For example, suppliers of bulk purchase parts and components (such as gas valves) give boiler manufacturers discounts based on the quantities purchased. Therefore, larger manufacturers may have a pricing advantage because they have higher volume purchases. This purchasing power differential between high-volume and low-volume orders applies to other residential boiler components as well, such as ignition systems and inducer fan assemblies.
To meet the new and amended standards, manufacturers may have to seek outside capital to cover expenses related to testing and product design equipment. Smaller firms typically have a higher cost of borrowing due to higher perceived risk on the part of investors, largely attributed to lower cash flows and lower per-unit profitability. In these cases, small manufacturers may observe higher costs of debt than larger manufacturers.
While DOE does not expect high capital conversion costs at TSL 3, DOE does expect smaller businesses would have to make significant product conversion investments relative to larger manufacturers. As previously noted, some of these smaller manufacturers are heavily weighted toward baseline products and other products below the efficiency levels adopted in this notice. As Table VI.1 illustrates, smaller manufacturers would have to increase their R&D spending to bring products into compliance and to develop new products at TSL 3, the adopted level.
At TSL 3, the level adopted in this notice, DOE estimates capital conversion costs of $0.01 million and product conversion costs of $0.05 million for an average small manufacturer. DOE estimates that an average large manufacturer will incur capital conversion costs of $0.02 million and product conversion costs of $0.05 million. Based on the results in Table VI.1, DOE recognizes that small manufacturers will generally face a relatively higher conversion cost burden than larger competitors.
Manufacturers that have the majority of their products and sales at efficiency levels above the adopted standards may have lower conversion costs than those listed in Table VI.1. In particular, the four small manufacturers that primarily sell condensing products are unlikely to be affected by the efficiency levels at TSL 3, as all of their products are already above the efficiency levels being adopted.
Furthermore, DOE recognizes that small manufacturers that primarily sell low-efficiency products today will face a greater burden relative to the small manufacturers that primarily sell high-efficiency products. At TSL 3, the level adopted in this notice, DOE believes that the three manufacturers that manufacture across all four product classes would have higher conversion costs because many of their products do not meet the standard adopted in this notice and would require redesign. Consequently, these manufacturers would have to expend funds to redesign their commodity products, or develop a new, higher-efficiency baseline product.
The two companies that primarily produce oil-fired hot water boilers could also be impacted, as they are generally much smaller than the small businesses that produce all product classes, have fewer shipments and smaller revenues, and are likely to have limited R&D resources. Both of these companies, however, do have oil-fired hot water boiler product listings that meet the efficiency standards adopted in this notice.
DOE estimates that one of the four companies that rebrands imported or sourced products does its own design work, while the other three import high-efficiency products from Europe or Asia. It is possible that the company that
Based on this analysis, DOE notes that on average, small businesses will experience total conversion costs on the order of $60,000. However, some companies will fall below and above the average. In particular, DOE has identified two small manufacturers that could experience greater conversion costs burdens than indicated by the average due to not having any products meeting the standard in one or two product classes.
DOE is not aware of any rules or regulations that duplicate, overlap, or conflict with the final rule being adopted.
The discussion in the previous section analyzes impacts on small businesses that would result from DOE's final rule, represented by TSL 3. In reviewing alternatives to the final rule, DOE examined energy conservation standards set at lower efficiency levels. While TSL 1 and TSL 2 would reduce the impacts on small business manufacturers, it would come at the expense of a reduction in energy savings. TSL 1 for the AFUE standards achieves 57 percent lower energy savings compared to the energy savings at TSL 3. TSL 2 for the AFUE standards achieves 36 percent lower energy savings compared to the energy savings at TSL 3.
DOE believes that establishing standards at TSL 3 balances the benefits of the energy savings at TSL 3 with the potential burdens placed on residential boiler manufacturers, including small business manufacturers. Accordingly, DOE is not adopting one of the other TSLs considered in the analysis, or the other policy alternatives examined as part of the regulatory impacts analysis and included in chapter 17 of the NOPR TSD.
Additional compliance flexibilities may be available through other means. For example, individual manufacturers may petition for a waiver of the applicable test procedure. (See 10 CFR 431.401) Further, EPCA provides that a manufacturer whose annual gross revenue from all of its operations does not exceed $8 million may apply for an exemption from all or part of an energy conservation standard for a period not longer than 24 months after the effective date of a final rule establishing the standard. Additionally, section 504 of the Department of Energy Organization Act, 42 U.S.C. 7194, provides authority for the Secretary to adjust a rule issued under EPCA in order to prevent “special hardship, inequity, or unfair distribution of burdens” that may be imposed on that manufacturer as a result of such rule. Manufacturers should refer to 10 CFR part 430, subpart E, and part 1003 for additional details.
Manufacturers of residential boilers must certify to DOE that their products comply with any applicable energy conservation standards. In certifying compliance, manufacturers must test their products according to the DOE test procedure for residential boilers, including any amendments adopted for those test procedures. DOE has established regulations for the certification and recordkeeping requirements for all covered consumer products and commercial equipment, including residential boilers. 76 FR 12422 (March 7, 2011); 80 FR 5099 (Jan. 30, 2015). The collection-of-information requirement for the certification and recordkeeping is subject to review and approval by OMB under the Paperwork Reduction Act (PRA). This requirement has been approved by OMB under OMB control number 1910–1400. Public reporting burden for the certification is estimated to average 30 hours per response, including the time for reviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the collection of information.
Notwithstanding any other provision of the law, no person is required to respond to, nor shall any person be subject to a penalty for failure to comply with, a collection of information subject to the requirements of the PRA, unless that collection of information displays a currently valid OMB Control Number.
Pursuant to the National Environmental Policy Act (NEPA) of 1969, DOE has determined that this rule fits within the category of actions included in Categorical Exclusion (CX) B5.1 and otherwise meets the requirements for application of a CX. See 10 CFR part 1021, App. B, B5.1(b); 1021.410(b) and App. B, B(1)–(5). The rule fits within this category of actions because it is a rulemaking that establishes energy conservation standards for consumer products or industrial equipment, and for which none of the exceptions identified in CX B5.1(b) apply. Therefore, DOE has made a CX determination for this rulemaking, and DOE does not need to prepare an Environmental Assessment or Environmental Impact Statement for this rule. DOE's CX determination for this rule is available at
Executive Order 13132, “Federalism,” 64 FR 43255 (Aug. 10, 1999), imposes certain requirements on Federal agencies formulating and implementing policies or regulations that preempt State law or that have Federalism implications. The Executive Order requires agencies to examine the constitutional and statutory authority supporting any action that would limit the policymaking discretion of the States and to carefully assess the necessity for such actions. The Executive Order also requires agencies to have an accountable process to ensure meaningful and timely input by State and local officials in the development of regulatory policies that have Federalism implications. On March 14, 2000, DOE published a statement of policy describing the intergovernmental consultation process it will follow in the development of such regulations. 65 FR 13735. DOE has examined this rule and has determined that it would not have a substantial direct effect on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government. EPCA governs and prescribes Federal preemption of State regulations as to energy conservation for the products that are the subject of this final rule. States can petition DOE for exemption from such preemption to the extent, and based on criteria, set forth in EPCA. (42 U.S.C. 6297) Therefore, no further action is required by Executive Order 13132.
With respect to the review of existing regulations and the promulgation of new regulations, section 3(a) of Executive Order 12988, “Civil Justice Reform,” imposes on Federal agencies the general duty to adhere to the following requirements: (1) Eliminate drafting errors and ambiguity; (2) write regulations to minimize litigation; (3) provide a clear legal standard for affected conduct rather than a general standard; and (4) promote simplification and burden reduction. 61 FR 4729 (Feb. 7, 1996). Regarding the review required by section 3(a), section 3(b) of Executive
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA) requires each Federal agency to assess the effects of Federal regulatory actions on State, local, and Tribal governments and the private sector. Public Law 104–4, sec. 201 (codified at 2 U.S.C. 1531). For a regulatory action likely to result in a rule that may cause the expenditure by State, local, and Tribal governments, in the aggregate, or by the private sector of $100 million or more in any one year (adjusted annually for inflation), section 202 of UMRA requires a Federal agency to publish a written statement that estimates the resulting costs, benefits, and other effects on the national economy. (2 U.S.C. 1532(a), (b)) The UMRA also requires a Federal agency to develop an effective process to permit timely input by elected officers of State, local, and Tribal governments on a “significant intergovernmental mandate,” and requires an agency plan for giving notice and opportunity for timely input to potentially affected small governments before establishing any requirements that might significantly or uniquely affect them. On March 18, 1997, DOE published a statement of policy on its process for intergovernmental consultation under UMRA. 62 FR 12820. DOE's policy statement is also available at
Although it does not contain a Federal intergovernmental mandate, DOE has concluded that this final rule adopting amended and new energy conservation standards for residential boilers may require annual expenditures of $100 million or more in any one year by the private sector. Such expenditures may include: (1) Investment in research and development and in capital expenditures by residential boiler manufacturers in the years between the final rule and the compliance date for the new standards, and (2) incremental additional expenditures by consumers to purchase higher-efficiency residential boilers, starting at the compliance date for the applicable standard.
Section 202 of UMRA authorizes a Federal agency to respond to the content requirements of UMRA in any other statement or analysis that accompanies the final rule. (2 U.S.C. 1532(c)) The content requirements of section 202(b) of UMRA relevant to a private sector mandate substantially overlap the economic analysis requirements that apply under section 325(o) of EPCA and Executive Order 12866. The
Under section 205 of UMRA, the Department is obligated to identify and consider a reasonable number of regulatory alternatives before promulgating a rule for which a written statement under section 202 is required. (2 U.S.C. 1535(a)) DOE is required to select from those alternatives the most cost-effective and least burdensome alternative that achieves the objectives of the rule unless DOE publishes an explanation for doing otherwise, or the selection of such an alternative is inconsistent with law. As required by 42 U.S.C. 6295(f) and (o), this final rule establishes amended and new energy conservation standards for residential boilers that are designed to achieve the maximum improvement in energy efficiency that DOE has determined to be both technologically feasible and economically justified. A full discussion of the alternatives considered by DOE is presented in the “Regulatory Impact Analysis” section of the TSD (chapter 17) for this final rule.
Section 654 of the Treasury and General Government Appropriations Act, 1999 (Pub. L. 105–277) requires Federal agencies to issue a Family Policymaking Assessment for any rule that may affect family well-being. This rule would not have any impact on the autonomy or integrity of the family as an institution. Accordingly, DOE has concluded that it is not necessary to prepare a Family Policymaking Assessment.
Pursuant to Executive Order 12630, “Governmental Actions and Interference with Constitutionally Protected Property Rights,” 53 FR 8859 (March 18, 1988), DOE has determined that this rule would not result in any takings that might require compensation under the Fifth Amendment to the U.S. Constitution.
Section 515 of the Treasury and General Government Appropriations Act, 2001 (44 U.S.C. 3516 note) provides for Federal agencies to review most disseminations of information to the public under information quality guidelines established by each agency pursuant to general guidelines issued by OMB. OMB's guidelines were published at 67 FR 8452 (Feb. 22, 2002), and DOE's guidelines were published at 67 FR 62446 (Oct. 7, 2002). DOE has reviewed this final rule under the OMB and DOE guidelines and has concluded that it is consistent with applicable policies in those guidelines.
Executive Order 13211, “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use,” 66 FR 28355 (May 22, 2001), requires Federal agencies to prepare and submit to OIRA at OMB, a Statement of Energy Effects for any significant energy action. A “significant energy action” is defined as any action by an agency that promulgates or is expected to lead to promulgation of a final rule, and that: (1) Is a significant regulatory action under Executive Order 12866, or any successor order; and (2) is likely to have a significant adverse effect on the supply, distribution, or use of energy, or (3) is designated by the Administrator of OIRA as a significant energy action. For any significant energy action, the agency must give a detailed statement of any adverse effects on energy supply, distribution, or use should the proposal be implemented, and of reasonable alternatives to the action and their expected benefits on energy supply, distribution, and use.
DOE has concluded that this regulatory action, which sets forth amended and new energy conservation standards for residential boilers, is not a significant energy action because the standards are not likely to have a significant adverse effect on the supply,
On December 16, 2004, OMB, in consultation with the Office of Science and Technology Policy (OSTP), issued its Final Information Quality Bulletin for Peer Review (the Bulletin). 70 FR 2664 (Jan. 14, 2005). The Bulletin establishes that certain scientific information shall be peer reviewed by qualified specialists before it is disseminated by the Federal Government, including influential scientific information related to agency regulatory actions. The purpose of the bulletin is to enhance the quality and credibility of the Government's scientific information. Under the Bulletin, the energy conservation standards rulemaking analyses are “influential scientific information,” which the Bulletin defines as “scientific information the agency reasonably can determine will have, or does have, a clear and substantial impact on important public policies or private sector decisions.”
In response to OMB's Bulletin, DOE conducted formal in-progress peer reviews of the energy conservation standards development process and analyses and has prepared a Peer Review Report pertaining to the energy conservation standards rulemaking analyses. Generation of this report involved a rigorous, formal, and documented evaluation using objective criteria and qualified and independent reviewers to make a judgment as to the technical/scientific/business merit, the actual or anticipated results, and the productivity and management effectiveness of programs and/or projects. The “Energy Conservation Standards Rulemaking Peer Review Report” dated February 2007, has been disseminated and is available at the following Web site:
As required by 5 U.S.C. 801, DOE will report to Congress on the promulgation of this rule prior to its effective date. The report will state that it has been determined that the rule is a “major rule” as defined by 5 U.S.C. 804(2).
The Secretary of Energy has approved publication of this final rule.
Administrative practice and procedure, Confidential business information, Energy conservation, Household appliances, Imports, Intergovernmental relations, Small businesses.
For the reasons set forth in the preamble, DOE amends part 430 of chapter II, subchapter D, of title 10 of the Code of Federal Regulations, as set forth below:
42 U.S.C. 6291–6309; 28 U.S.C. 2461 note.
The addition reads as follows:
(e) * * *
(2) * * *
(iii)(A) Except as provided in paragraph (e)(2)(v) of this section, the AFUE of residential boilers, manufactured on and after January 15, 2021, shall not be less than the following and must comply with the design requirements as follows:
(B) Except as provided in paragraph (e)(2)(v) of this section, the standby mode power consumption (P
The following letter will not appear in the Code of Federal Regulations.
I am responding to your March 13, 2015 letters seeking the views of the Attorney General about the potential impact on competition of proposed energy conservation standards for residential boilers. Your request was submitted under Section 325(o)(2)(B)(i)(V) of the Energy Policy and Conservation Act, as amended (ECPA), 42 U.S.C. 6295(o)(2)(B)(i)(V), which requires the Attorney General to make a determination of the impact of any lessening of competition that is likely to result from the imposition of proposed energy conservation standards. The Attorney General's responsibility for responding to requests from other departments about the effect of a program on competition has been delegated to the Assistant Attorney General for the Antitrust Division in 28 CFR 0.40(g).
In conducting its analysis, the Antitrust Division examines whether a proposed standard may lessen competition, for example, by substantially limiting consumer choice or increasing industry concentration. A lessening of competition could result in higher prices to manufacturers and consumers.
We have reviewed the proposed energy conservation standards contained in the Notice of Proposed Rulemaking (80 FR 17222, March 31, 2015) (NOPR) and the related Technical Support Documents. We have also reviewed supplementary information submitted to the Attorney General by the Department of Energy, as well as material presented at the public meeting held on the proposed standards on April 30, 2015. Based on this review, our conclusion is that the proposed energy conservation standards for residential boilers are unlikely to have a significant adverse impact on competition.
Office of Energy Efficiency and Renewable Energy, Department of Energy.
Direct final rule.
The Energy Policy and Conservation Act of 1975, as amended (EPCA), prescribes energy conservation standards for various consumer products and certain commercial and industrial equipment, including small, large, and very large air-cooled commercial package air conditioning and heating equipment and commercial warm air furnaces. EPCA also requires that the U.S. Department of Energy (DOE) periodically review and consider amending its standards for specified categories of industrial equipment, including commercial heating and air conditioning equipment, in order to determine whether more-stringent, amended standards would be technologically feasible and economically justified, and save a significant additional amount of energy. In this direct final rule, DOE is amending the energy conservation standards for both small, large, and very large air-cooled commercial package air conditioning and heating equipment and commercial warm air furnaces after determining that the amended energy conservation standards being adopted for these equipment would result in the significant conservation of energy and be technologically feasible and economically justified.
The effective date of this rule is May 16, 2016 unless adverse comment is received by May 4, 2016. If adverse comments are received that DOE determines may provide a reasonable basis for withdrawal of the direct final rule, a timely withdrawal of this rule will be published in the
The dockets, which include
A link to the docket Web page for small, large, and very large air-cooled commercial package air conditioning and heating equipment can be found at:
For further information on how to review the dockets, contact Ms. Brenda Edwards at (202) 586–2945 or by email:
Mr. John Cymbalsky, U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Building Technologies, EE–5B, 1000 Independence Avenue SW., Washington, DC 20585–0121. Telephone: (202) 286–1692. Email:
Title III, Part C
DOE received a statement submitted jointly by interested persons that are fairly representative of relevant points of view (including representatives of manufacturers of the covered equipment at issue, States, and efficiency advocates) containing recommendations with respect to energy conservation standards for the above equipment (see section III.B for description of the jointly-submitted statement). DOE has determined that the recommended standards contained in that jointly-submitted statement (hereinafter “Joint Statement”) are in accordance with 42 U.S.C. 6313(a)(6)(B), which prescribes the conditions for adoption of a uniform national standard more stringent than the applicable levels prescribed by ASHRAE/IES Standard 90.1 for the above equipment. (The acronym “ASHRAE/IES” stands for the American Society of Heating, Refrigerating, and Air-Conditioning Engineers/Illuminating Engineering Society.) Under the authority provided by 42 U.S.C. 6295(p)(4) and 6316(b)(1), DOE is issuing this direct final rule establishing amended energy conservation standards for CUACs, CUHPs, and CWAFs.
The amended minimum standards for CUACs and CUHPs are shown in Table I–1, with the CUAC and CUHP cooling efficiency standards presented in terms of an integrated energy efficiency ratio (“IEER”) and the CUHP heating efficiency standards presented as a coefficient of performance (“COP”). The
For CWAFs, the amended standards, which prescribe the minimum allowable thermal efficiency (“TE”), are shown in Table I–2. These standards apply to all equipment listed in Table I–2 manufactured in, or imported into, the United States starting on January 1, 2023.
Table I–3 presents DOE's evaluation of the economic impacts of the energy conservation standards on commercial consumers of CUACs and CUHPs, as measured by the average life-cycle cost (“LCC”) savings and the payback period (“PBP”).
Table I–4 presents DOE's evaluation of the economic impacts of the energy conservation standards on commercial consumers of CWAFs, as measured by the average LCC savings and the PBP. The average LCC savings are positive for both equipment classes, and the PBP is less than the average lifetime of the equipment, which is estimated to be 23 years for both gas-fired and oil-fired CWAFs (see section IV.F.6).
DOE's analysis of the impacts of the adopted standards on commercial consumers of CUACs/CUHPs and CWAFs is described in section IV.F of this document.
The industry net present value (“INPV”) is the sum of the discounted cash flows to the industry from the base year through the end of the analysis period (2015 to 2048). Using a real discount rate of 6.2 percent, DOE estimates that the INPV for CUAC/CUHP manufacturers is $1,638.2 million in 2014$. Under the standards adopted in this direct final rule, DOE expects INPV may change approximately −26.8 percent to −2.3 percent, which corresponds to approximately −$440.4 million and −$38.5 million in 2014$. In order to bring equipment into compliance with the standards adopted in this direct final rule, DOE expects the industry to incur $520.8 million in total conversion costs.
As indicated above, the INPV is the sum of the discounted cash flows to the industry from the base year through the end of the analysis period (2015 to 2048). Using a real discount rate of 8.9 percent, DOE estimates that the INPV for CWAF manufacturers is $96.3 million in 2014$. Under the standards adopted in this direct final rule, DOE expects INPV may be reduced by approximately 13.9 percent to 6.1 percent, which corresponds to −$13.4 million and −$5.9 million in 2014$. In order to bring products into compliance with the standards in this direct final rule, DOE expects the industry to incur $22.2 million in conversion costs.
DOE's analysis of the impacts of the standards in this direct final rule on manufacturers is described in section IV.J of this document.
DOE's
The cumulative net present value (“NPV”) of total consumer costs and savings of the standards for CUACs and CUHPs ranges from $15.2 billion (at a 7-percent discount rate) to $50 billion (at a 3-percent discount rate). This NPV expresses the estimated total value of future operating-cost savings minus the estimated increased product and installation costs for CUACs and CUHPs purchased in 2018–2048.
In addition, the CUAC and CUHP equipment standards that are being adopted in this direct final rule are projected to yield significant environmental benefits as a result of the improvement in the conservation of energy. DOE estimates that the standards would result in cumulative greenhouse gas (“GHG”) emission reductions (over the same period as for energy savings) of 873 million metric tons (Mt)
The value of the CO
Table I–5 summarizes the national economic benefits and costs expected to result from the adopted standards for CUACs and CUHPs.
The benefits and costs of the adopted CUAC and CUHP standards for equipment sold in 2018–2048 can also be expressed in terms of annualized values. The monetary values for the total annualized net benefits are the sum of (1) the national economic value of the benefits in reduced operating costs, minus (2) the increases in product purchase prices and installation costs, plus (3) the value of the benefits of CO
Although the value of operating cost savings and CO
Estimates of annualized benefits and costs of the adopted standards are shown in Table I–6. The results under the primary estimate are as follows. Using a 7-percent discount rate for benefits and costs other than CO
DOE's analysis of the national impacts of the adopted standards is described in sections IV.H, IV.K and IV.L of this document.
DOE's analyses indicate that the adopted energy conservation standards for CWAFs would save a significant amount of energy. Relative to the case without amended standards (referred to as the “no-new-standards case”), the lifetime energy savings for CWAFs purchased in 2023–2048 amount to 0.23 quads. This represents a savings of 0.8 percent relative to the energy use of these products in the case without amended standards (
The cumulative NPV of total consumer costs and savings of the standards for CWAFs ranges from $0.3 billion (at a 7-percent discount rate) to $1.0 billion (at a 3-percent discount rate). This NPV expresses the estimated total value of future operating-cost savings minus the estimated increased product and installation costs for CWAFs purchased in 2023–2048.
In addition, the CWAF equipment standards that are being adopted in this direct final rule are projected to yield significant environmental benefits as a result of the improvement in the conservation of energy. Specifically, these standards are projected to result in cumulative GHG emission reductions (over the same period as for energy savings) of 12.4 Mt of CO
The value of the CO
Table I–7 summarizes the national economic benefits and costs expected to result from the adopted CWAF standards.
The benefits and costs of the adopted standards, for CWAFs sold in 2023–2048, can also be expressed in terms of annualized values. The monetary values for the total annualized net benefits are the sum of (1) the national economic value of the benefits in reduced operating costs, minus (2) the increases in product purchase prices and installation costs, plus (3) the value of the benefits of CO
Estimates of annualized benefits and costs of the adopted standards are shown in Table I–8. The results under the primary estimate are as follows. Using a 7-percent discount rate for benefits and costs other than CO
DOE's analysis of the national impacts of the adopted standards is described in sections IV.H, IV.K and IV.L of this document.
DOE's analyses indicate that energy conservation standards being adopted in this direct final rule for CUAC and CUHP equipment and CWAFs would save a significant amount of energy. Relative to the no-new-standards case, the lifetime energy savings for CUAC and CUHP equipment purchased in 2018–2048 and CWAFs purchased in 2023–2048 amount to 15.0 quads. This represents a savings of 24 percent relative to the energy use of these products in the no-new-standards case.
The cumulative NPV of total consumer costs and savings of the standards for CUACs and CUHPs and CWAFs ranges from $15.5 billion (at a 7-percent discount rate) to $51 billion (at a 3-percent discount rate). This NPV expresses the estimated total value of future operating-cost savings minus the estimated increased product and installation costs for CUACs and CUHPs purchased in 2018–2048 and CWAFs purchased in 2023–2048.
In addition, the standards that are being adopted in this direct final rule are projected to yield significant environmental benefits as a result of the improvement in the conservation of energy. DOE estimates that the standards would result in cumulative GHG emission reductions (over the same period as for energy savings) of 885 million Mt of CO
The value of the CO
Table I–9 summarizes the combined national economic benefits and costs expected to result from the adopted standards for CUACs and CUHPs and CWAF.
The benefits and costs of the adopted standards for CUAC and CUHP and CWAFs can also be expressed in terms of annualized values. Estimates of annualized benefits and costs of the adopted standards are shown in Table I–10. The results under the primary estimate are as follows. Using a 7-percent discount rate for benefits and costs other than CO
DOE has determined that the statement containing recommendations with respect to energy conservation standards for CUACs, CUHPs and CWAFs was submitted jointly by interested persons that are fairly representative of relevant points of view, in accordance with 42 U.S.C.
Under the authority provided by 42 U.S.C. 6295(p)(4) and 6316(b)(1), DOE is issuing this direct final rule establishing amended energy conservation standards for CUACs/CUHPs and CWAFs. Consistent with this authority, DOE is also publishing elsewhere in this
The following section briefly discusses the statutory authority underlying this direct final rule, as well as some of the relevant historical background related to the establishment of standards for small, large, and very large, CUAC/CUHP and CWAF equipment.
As indicated above, EPCA includes provisions covering the equipment addressed by this document.
Section 342(a) of EPCA concerns energy conservation standards for small, large, and very large, CUACs and CUHPs. (42 U.S.C. 6313(a)) This category of equipment has a rated capacity between 65,000 Btu/h and 760,000 Btu/h. This equipment is designed to heat and cool commercial buildings and is often located on the building's rooftop.
The initial Federal energy conservation standards for CWAFs were added to EPCA by the Energy Policy Act of 1992 (EPACT 1992), Public Law No. 102–486 (Oct. 24, 1992). See 42 U.S.C. 6313(a)(4). These types of covered equipment have a rated capacity (rated maximum input
Pursuant to section 342(a)(6) of EPCA, DOE is to consider amending the energy efficiency standards for certain types of commercial and industrial equipment whenever ASHRAE amends the standard levels or design requirements prescribed in ASHRAE/IES Standard 90.1, and whenever more than 6 years had elapsed since the issuance of the most recent final rule establishing or amending a standard for the equipment as of the date of AEMTCA's enactment, December 18, 2012. (42 U.S.C. 6313(a)(6)(C)(vi)) Because more than six years had elapsed since DOE issued a final rule with standards for CUACs and CUHPs or CWAFs on October 18, 2005 (see 70 FR 60407), DOE initiated the process to review these standards.
Pursuant to EPCA, DOE's energy conservation program for covered equipment consists essentially of four parts: (1) Testing; (2) labeling; (3) the establishment of Federal energy conservation standards; and (4) certification and enforcement procedures. Subject to certain criteria and conditions, DOE is required to develop test procedures to measure the energy efficiency, energy use, or estimated annual operating cost of covered equipment. (42 U.S.C. 6314) Manufacturers of covered equipment must use the prescribed DOE test procedure as the basis for certifying to DOE that their equipment comply with the applicable energy conservation standards adopted under EPCA and when making representations to the public regarding their energy use or efficiency. (42 U.S.C. 6314(d)) Similarly, DOE must use these test procedures to determine whether a given manufacturer's equipment complies with standards adopted pursuant to EPCA. The DOE test procedures for small, large, and very large CUACs/CUHPs and CWAFs currently appear at title 10 of the Code of Federal Regulations (“CFR”) parts 431.96 and 431.76, respectively.
When setting standards for the equipment addressed by this document, EPCA prescribes specific statutory criteria for DOE to consider. See generally 42 U.S.C. 6313(a)(6)(A)–(C). In deciding whether a proposed standard is economically justified, DOE must determine whether the benefits of the standard exceed its burdens. DOE must make this determination after receiving comments on the proposed standard, and by considering, to the maximum extent practicable, the following seven statutory factors:
1. The economic impact of the standard on manufacturers and consumers of products subject to the standard;
2. The savings in operating costs throughout the estimated average life of the covered products in the type (or class) compared to any increase in the price, initial charges, or maintenance expenses for the covered products which are likely to result from the standard;
3. The total projected amount of energy savings likely to result directly from the standard;
4. Any lessening of the utility or the performance of the covered products likely to result from the standard;
5. The impact of any lessening of competition, as determined in writing by the Attorney General, that is likely to result from the standard;
6. The need for national energy conservation; and
7. Other factors the Secretary of Energy considers relevant. (42 U.S.C. 6313(a)(6)(B)(ii))
With respect to the types of equipment at issue in this rule, EPCA also contains what is known as an “anti-backsliding” provision, which prevents the Secretary from prescribing any
With respect to the equipment addressed by this direct final rule, DOE notes that EPCA prescribes limits on the Agency's ability to promulgate a standard if DOE has made a finding that interested persons have established by a preponderance of the evidence that a standard is likely to result in the unavailability of any product type (or class) of performance characteristics that are substantially the same as those generally available in the United States at the time of the finding. See 42 U.S.C. 6313(B)(iii)(II).
With particular regard to direct final rules, the Energy Independence and Security Act of 2007 (“EISA 2007”), Public Law 110–140 (December 19, 2007), amended EPCA, in relevant part, to grant DOE authority to issue a type of final rule (
DOE last amended its standards for small, large, and very large, CUACs/CUHPs on October 18, 2005. At that time, DOE codified both the amended standards for small and large equipment and the then-new standards for very large equipment set by the Energy Policy Act of 2005 (“EPAct 2005”), Pub. L. 109–58. See also 70 FR 60407 (August 8, 2005). The current standards are set forth in Table II–1.
As noted above, EPACT 1992 amended EPCA to set the current minimum energy conservation standards for CWAFs. (42 U.S.C. 6313(a)(4)(A) and (B)) These standards, which apply to all CWAFs manufactured on or after January 1, 1994, are set forth in Table II–2.
On October 29, 1999, the American Society of Heating, Refrigerating, and Air-Conditioning Engineers (ASHRAE)/Illuminating Engineering Society of North America (IESNA) adopted Standard 90.1–1999, “Energy Standard for Buildings Except Low-Rise Residential Building,” which included amended efficiency levels for CUACs and CUHPs. On June 12, 2001, the Department published a Framework Document that described a series of analytical approaches to evaluate energy conservation standards for CUACs and CUHPs with rated capacities between 65,000 Btu/h and 240,000 Btu/h, and presented this analytical framework to stakeholders at a public workshop. On July 29, 2004, DOE issued an Advance Notice of Proposed Rulemaking (“ANOPR”) (hereafter referred to as the “2004 ANOPR”) to solicit public comments on its preliminary analyses for this equipment. 69 FR 45460. Subsequently, Congress enacted EPAct 2005, which, among other things, established amended standards for small and large CUACs and CUHPs and new standards for very large CUACs and CUHPs. As a result, EPAct 2005 displaced the rulemaking effort that DOE had already begun. DOE codified these new statutorily-prescribed standards on October 18, 2005. 70 FR 60407.
Section 5(b) of AEMTCA amended Section 342(a)(6) of EPCA (42 U.S.C. 6313(a)(6)) by requiring DOE to initiate a rulemaking to consider amending the standards for any covered equipment as to which more than 6 years has elapsed since the issuance of the most recent final rule establishing or amending a standard for the equipment as of the date of AEMTCA's enactment, December 18, 2012. (42 U.S.C. 6313(a)(6)(C)(vi)) Under this provision, DOE was also obligated to publish a notice of proposed rulemaking to amend the applicable standards by December 31, 2013. See 42 U.S.C. 6313(a)(6)(C)(vi). Consequently, DOE initiated a rulemaking effort to determine whether to amend the current standards for CUACs and CUHPs.
On February 1, 2013, DOE published a request for information (“RFI”) and notice of document availability for small, large, and very large, air cooled CUACs and CUHPs. 78 FR 7296. The document sought to solicit information from the public to help DOE determine whether national standards more stringent than those already in place would result in a significant amount of additional energy savings and whether those national standards would be technologically feasible and economically justified. Separately, DOE also sought information on the merits of adopting the IEER metric as the energy efficiency descriptor characterizing cooling-mode efficiency for small, large, and very large CUACs and CUHPs, rather than the current EER metric. (See section III.G for more details).
DOE notes that in October 2010, ASHRAE published ASHRAE Standard 90.1–2010, which amended its requirements for CUACs and CUHPs to include, among other things, new requirements for IEER. In October 2013, ASHRAE published ASHRAE Standard 90.1–2013, which further amended those IEER requirements. The provisions relating to EER and COP contained in ASHRAE Standard 90.1–2010 and ASHRAE Standard 90.1–2013, however, remained the same as the current DOE standards for this equipment. As discussed in section IV.C.2, DOE considered efficiency levels associated with the IEER requirements in both ASHRAE Standard 90.1–2010 and ASHRAE Standard 90.1–2013.
On September 30, 2014, DOE published a NOPR for small, large, and very large CUACs and CUHPs. 79 FR 58948. The document solicited information from the public to help DOE determine whether more-stringent energy conservation standards for small, large, and very large CUACs and CUHPs would result in a significant additional amount of energy savings and whether those standards would be technologically feasible and economically justified.
The September 2014 document also announced that a public meeting would be held on November 6, 2014 at DOE headquarters in Washington, DC At this meeting, DOE presented the methodologies and results of the analyses set forth in the NOPR, and interested parties that participated in the public meeting discussed a variety of topics.
DOE also received a number of written comments from interested parties in response to the NOPR. DOE considered these comments, as well as comments from the public meeting, in preparing the direct final rule. The commenters are summarized in Table II–3. Relevant comments, and DOE's responses, are provided in the appropriate sections of this document.
On October 21, 2004, DOE published a final rule in the
As with CUACs and CUHPs, DOE was obligated to publish either: (1) A notice of determination that the current standards do not need to be amended, or (2) a notice of proposed rulemaking containing proposed standards for CWAFs by December 31, 2013. (42 U.S.C. 6313(a)(6)(C)(i) and (vi)) Consequently, DOE initiated a rulemaking to determine whether to amend the current standards for CWAFs.
In starting this rulemaking process, DOE published an RFI and notice of document availability for CWAFs. See 78 FR 25627 (May 2, 2013). The document solicited information from the public to help DOE determine whether more-stringent energy conservation standards for CWAFs would result in a significant additional amount of energy savings and whether those standards would be technologically feasible and economically justified.
Based on feedback and additional analysis, on February 4, 2015, DOE published a NOPR for CWAFs. See 80 FR 6182. The NOPR, in addition to announcing a public meeting to discuss the proposal's details, solicited information from the public to help DOE determine whether more-stringent energy conservation standards for
DOE received a number of written comments from interested parties in response to the NOPR. DOE considered these comments, as well as comments from the public meeting, in the preparation of this final rule. The commenters are identified in Table II–4. Relevant comments, and DOE's responses, are provided in the appropriate sections of this document.
As discussed in section II.B.2, DOE had been conducting separate standards rulemakings for two sets of interrelated equipment: (1) Small, large, and very large, CUACs and CUHPs; and (2) CWAFs. In response to the CUAC/CUHP NOPR, Lennox and Goodman requested that DOE align the rulemakings for these equipment because of their inherent impact on each other. The commenters asserted that combining the rulemakings would reduce manufacturer burden by allowing manufacturers to consider both of these regulatory changes in one design cycle. (CUAC: Lennox, No. 60 at p. 8; Goodman, No. 65 at p. 5)
In light of the broad overlap between these equipment, DOE agreed that a combined rulemaking for small, large, and very large, CUACs and CUHPs and CWAFs had certain advantages. For example, DOE observed that a large fraction of CWAFs are part of combined single-package CUACs/CWAF equipment, combining both air conditioning and gas-fired heating. Combining the rulemakings allowed simultaneous consideration of both functions of what is generally a single piece of equipment, thus allowing DOE to accurately account for the relations between the different systems. This approach also ensured that there would be no divergence of equipment development timelines for the separate functions, thus reducing costs and manufacturer impacts. As a result, DOE is setting standards for these equipment that aligns the effective dates of the CUAC/CUHP and CWAF rulemakings. DOE expects that aligning the effective dates will reduce total conversion costs and cumulative regulatory burden, while also allowing industry to gain clarity on potential regulations that could affect refrigerant availability before the higher appliance standard takes effect in 2023. Approximately 68.5 percent of industry equipment listings currently meet the 2018 standard, while 20.4 percent of current industry equipment listings meet the 2023 standard level.
In response to the September 2014 CUAC/CUHP NOPR, Lennox suggested that DOE adopt the ASHRAE 90.1–2013 standards for the equipment subject to this rulemaking but also offered in the alternative that DOE should convene a negotiated rulemaking to address potential amendments to the current standards, which would enhance stakeholder input into the discussion, analysis and outcome of the rulemaking. (CUAC: Lennox, No. 60 at p. 3) Other manufacturers made similar suggestions. (CUAC: Trane, No. 63 at p. 14; Goodman, No. 65 at p. 22) In response to the CWAF NOPR, AHRI stated that the best approach to resolve the issues it identified, as well as the concerns of other stakeholders on this rulemaking and on the CUAC rulemaking, would be for DOE to conduct a negotiated rulemaking at
Subsequently, after careful consideration, DOE determined that, given the complexity of the CUAC/CUHP rulemaking and the logistical challenges presented by the related CWAF proposal, a combined effort to address these equipment types was appropriate to ensure a comprehensive vetting of issues and related analyses that would support any final rule settting standards for this equipment. To this end while highly unusual to do so after issuing a proposed rule, DOE solicited the public for membership nominations to the working group that would be formed under the ASRAC charter by issuing a Notice of Intent to Establish the Commercial Package Air Conditioners and Commercial Warm Air Furnaces Working Group To Negotiate Potential Energy Conservation Standards for Commercial Package Air Conditioners and Commercial Warm Air Furnaces. 80 FR 17363 (April 1, 2015). The CUAC/CUHP–CWAF Working Group (in context, “the Working Group”) was established under ASRAC in accordance with the Federal Advisory Committee Act and the Negotiated Rulemaking Act—with the purpose of discussing and, if possible, reaching consensus on a set of energy conservation standards to propose or finalize for CUACs, CUHPs and CWAFs. The Working Group was to consist of fairly representative parties having a defined stake in the outcome of the proposed standards, and would consult, as appropriate, with a range of experts on technical issues.
DOE received 17 nominations for membership. Ultimately, the Working Group consisted of 17 members, including one member from ASRAC and one DOE representative.
DOE carefully considered the consensus recommendations submitted by the Working Group in the form of a single Term Sheet, and adopted by ASRAC, related to amending the energy conservation standards for CUACs, CUHPs, and CWAFs. Based on this consideration, DOE has determined that these recommendations comprise a statement submitted by interested persons that are fairly representative of relevant points of view, consistent with 42 U.S.C. 6295(p)(4). In reaching this determination, DOE took into consideration the fact that the Working Group, in conjunction with ASRAC members who approved the recommendations, consisted of representatives of manufacturers of the covered equipment at issue, States, and efficiency advocates. Thus all of the groups specifically identified by Congress as potentially relevant parties to any consensus recommendation submitted by ASRAC participated in approving the recommendations submitted to DOE. (42 U.S.C. 6295(p)(4)(A)) As delineated above, the Term Sheet was signed and submitted by a broad cross-section of interests, including the manufacturers of the subject equipment, trade associations representing these manufacturers and installation contractors, environmental and energy-efficiency advocacy organizations, and electric utility companies. The ASRAC Committee approving the Working Group's recommendations included at least two members representing States—one representing the National Association of State Energy Officials (NASEO) and one representing the State of California.
By its plain terms, the statute contemplates that the Secretary will exercise discetion to determine whether a given statement is “submitted jointly by interested persons that are fairly representative of relevant points of view (including representatives of manufacturers of covered products, States, and efficiency advocates).” In this case, given the broad range of persons participating in the process that led to the submission—in the Working Group and in ASRAC—and given the breadth of perspectives expressed in that process, DOE has determined that the statement it received meets this criterion.
Pursuant to 42 U.S.C. 6295(p)(4), the Secretary must also determine whether a jointly-submitted recommendation for an energy or water conservation standard satisfies 42 U.S.C. 6295(o) or 42 U.S.C. 6313(a)(6)(B), as applicable. In making this determination, DOE has conducted an analysis to evaluate whether the potential energy conservation standards under consideration would meet these requirements. This evaluation is similar to the comprehensive approach that DOE typically conducts whenever it considers potential energy conservation standards for a given type of product or equipment. DOE applies these principles to any consensus recommendations it may receive to satisfy its statutory obligation to ensure that any energy conservation standard that it adopts achieves the maximum improvement in energy efficiency that is
In sum, as the relevant criteria under 42 U.S.C. 6295(p)(4) have been satisfied, the Secretary has determined that it is appropriate to adopt the amended energy conservation standards recommended in the Joint Statement for CUACs, CUHPs, and CWAFs through this direct final rule.
Pursuant to the same statutory provision, DOE is also simultaneously publishing a NOPR proposing that the identical standard levels contained in this direct final rule be adopted. Consistent with the statute, DOE is providing a 110-day public comment period on both the direct final rule and the NOPR. Based on the comments received during this period, the direct final rule will either become effective or DOE will withdraw it if (1) one or more adverse comments is received and (2) DOE determines that those comments, when viewed in light of the rulemaking record related to the direct final rule, provide a reasonable basis for withdrawal of the direct final rule under 42 U.S.C. 6313(a)(6)(B) and for DOE to continue this rulemaking under the NOPR. (Receipt of an alternative joint recommendation may also trigger a DOE withdrawal of the direct final rule in the same manner.) See 42 U.S.C. 6295(p)(4)(C). Typical of other rulemakings, it is the substance, rather than the quantity, of comments that will ultimately determine whether a direct final rule will be withdrawn. To this end, the substance of any adverse comment(s) received will be weighed against the anticipated benefits of the jointly-submitted recommendations and the likelihood that further consideration of the comment(s) would change the results of the rulemaking. DOE notes that, to the extent an adverse comment had been previously raised and addressed in the rulemaking proceeding, such a submission will not typically provide a basis for withdrawal of a direct final rule.
For commercial package air conditioners and heat pumps (
The ASRAC Working Group also recommended that DOE separately define double-duct air conditioners and heat pumps, as discussed further in section IV.A.2.a, and that the current energy conservation standards continue to apply to these equipment. See 10 CFR 431.97, Table 1.
For CWAFs, the Working Group recommended that the standards provided in Table III–5 apply to equipment manufactured starting on January 1, 2023.
When DOE amends the standards for CUACs, CUHPs, and CWAFs through an ordinary notice-and-comment process, EPCA prescribes a set of timelines based on the particular circumstances surrounding that amendment. The proposed rule that eventually led to the formation of the Working Group was the beginning of DOE's six-year evaluation of the standards for these products. Consistent with 42 U.S.C. 6313(a)(6)(C)(iv), DOE originally proposed a compliance date of December 2018.
Commenting on the CUAC/CUHP NOPR, AHRI, Nordyne and Goodman disagreed with DOE's interpretation of the statutory lead time requirements for amended standards for CUACs and CUHPs. They argued that section 6313(a)(6)(D), which specifies a lead time of four years, should apply to any new standard that DOE promulgates. (CUAC: AHRI, No. 68 at pp. 14–17; Nordyne, No. 61 at pp. 11–15; Goodman, No. 65 at p. 3) Lennox added that DOE's proposed 3-year time frame is not feasible and stated that at least a 5-year development cycle would be required to meet the proposed standard. (CUAC: Lennox, No. 60 at p. 8)
In resolving these timeline differences, the Working Group gave careful consideration to these concerns and recommended to ASRAC, which ASRAC then adopted, a set of jointly-submitted recommendations that specified a compliance date of January 1, 2018, for the first tier of standards, and January 1, 2023 for the second tier. These tiered dates were accepted and recommended by the signatories to the Term Sheet, which included
While the January 1, 2018 compliance date is earlier than the proposed three-year lead time, DOE has the authority under section 325(p)(4) to accept recommendations for compliance dates contained in a joint submission recommending amended standards. In DOE's view, the direct final rule authority provision specifies the finding DOE has to make. Specifically, Congress specified that if DOE determines that the recommended standard is in accordance with 42 U.S.C. 6295(o) or section 342(a)(6)(B) of EPCA (
For CWAFs, the consensus agreement specifies a compliance date of January 1, 2023. As with the lead time for CUACs and CUHPs, DOE has the authority when adopting recommended standards submitted in a consensus agreement pursuant to section 325(p)(4), to accept recommendations regarding compliance dates. See 42 U.S.C. 6295(p)(4) and 6316(b)(1). See also 76 FR at 37426. DOE has made the determination that the rulemaking record in this case supports the adoption of this recommended lead time for CWAFs.
In its analysis of the other TSLs considered for the direct final rule, DOE used a compliance date that is 3 years after the expected publication of the final rule establishing amended standards (see discussion at the beginning of this section).
In each energy conservation standards rulemaking, DOE conducts a screening analysis based on information gathered on all current technology options and prototype designs that could improve the efficiency of the products or equipment that are the subject of the rulemaking. As the first step in such an analysis, DOE develops a list of technology options for consideration in consultation with manufacturers, design engineers, and other interested parties. See chapter 3 of the direct final rule's Technical Support Documents (“TSDs”) for a discussion of the list of technology options that were identified. DOE then determines which of those means for improving efficiency are technologically feasible. DOE considers technologies incorporated in commercially-available equipment or in working prototypes to be technologically feasible. 10 CFR part 430, subpart C, appendix A, section 4(a)(4)(i).
After DOE has determined that particular technology options are technologically feasible, it further evaluates each technology option in light of the following additional screening criteria: (1) Practicability to manufacture, install, and service; (2) adverse impacts on equipment utility or availability; and (3) adverse impacts on health or safety. 10 CFR part 430, subpart C, appendix A, section 4(a)(4)(ii)–(iv). Section IV.B of this document discusses the results of the screening analysis, particularly the designs DOE considered, those it screened out, and those that are the basis for the trial standard levels (TSLs) in this rulemaking. For further details on the screening analysis for this rulemaking, see chapter 4 of the direct final rule TSDs.
Additionally, DOE notes that these screening criteria do not directly address the proprietary status of design options. DOE only considers efficiency levels achieved through the use of proprietary designs in the engineering analysis if they are not part of a unique path to achieve that efficiency level (
DOE assessed the recommended standards by accounting for the elements contained in 42 U.S.C. 6313(a)(6)(B). That provision requires DOE to determine in cases where standards more stringent than those already prescribed by ASHRAE 90.1 whether those more stringent standards will yield a significant amount of additional conservation of energy and will be technologically feasible and economically justified. In determining whether the “economically justified” prong is met, DOE must, after receiving views and comments on the standard, determine whether the benefits of the standard exceed the burdens that the standard would impose by, to the maximum extent practiable, considering seven different factors. See generally, 42 U.S.C. 6313(a)(6)(B)(ii)(I)–(VII). Consistent with this approach, DOE's engineering analysis helped identify the maximum technologically feasible (“max-tech”) improvements in energy efficiency for CUACs/CUHPs and CWAFs by using the design parameters for the most efficient equipment available on the market. (See chapter 5 of the direct final rule TSDs.) The max-tech levels that DOE determined for this rulemaking are described in section IV.C.2.b of this direct final rule.
For the adopted standards, DOE projected energy savings over the entire lifetime of equipment purchased in 2018–2048 for CUACs/CUHPs and 2023–2048 for CWAFs. DOE quantified the energy savings attributable to each TSL as the difference in energy consumption between each standards case and the no-new-standards case. The no-new-standards case represents a projection of energy consumption that reflects how the market for a type of equipment would likely evolve in the absence of amended energy conservation standards.
DOE used its national impact analysis (“NIA”) spreadsheet model to estimate energy savings from potential amended standards for CUACs/CUHPs and CWAFs. The NIA spreadsheet model (described in section IV.H of this document) calculates savings in site energy, which is the energy directly consumed by products at the locations where they are used. Based on the calculated site energy, DOE calculates
To adopt more-stringent standards for the covered equipment at issue, DOE must determine on the basis of clear and convincing evidence that such action would result in the significant additional conservation of energy over levels that would be achieved through the adoption of the relevant ASHRAE standards. (42 U.S.C. 6313(a)(6)(A)(ii)(II)) Although the term “significant” is not defined in the Act, the U.S. Court of Appeals, in
As noted above, EPCA provides seven factors to be evaluated in determining whether a potentially more-stringent energy conservation standard for the equipment addressed by this direct final rule is economically justified. (42 U.S.C. 6313(a)(6)(B)(ii)(I)–(VII)) The following sections discuss how DOE has addressed each of those seven factors in this rulemaking.
Commenting on the CUAC/CUHP NOPR, AHRI stated that DOE is not performing the full cost-benefit analysis that EPCA Section 6313(a)(6)(B)(ii) requires. It stated that DOE performed cost-benefit considerations at various points of its analysis yet never fully reconciled those analyses or the assumptions and scope of coverage underlying them. It added that DOE's cost-benefit analyses to the Nation, to manufacturers, and on employment take very different geographic scopes, ignore the immediately apparent effects on employment, and rely on unsupported analyses for effects on the general economy. In its view, DOE must reconcile these various approaches and their assumptions and also make available any models or inputs/outputs it relies upon. AHRI stated that DOE should remedy these shortcomings by performing an integrated, full cost-benefit analysis considering all factors including the effects on all directly related domestic industries. (CUAC: AHRI, No. 68 at pp. 26–29)
As noted above, EPCA Section 6313(a)(6)(B)(ii) lays out the factors DOE shall, to the maximum extent practicable, consider in determining whether the benefits of a given standard exceed the burdens. EPCA does not mention or require the type of integrated cost-benefit analysis that AHRI envisions. It does not state or imply that all of the benefits and burdens need to be quantified in monetary terms. DOE's historical practice has been to analyze each of the factors to the maximum extent practicable. EPCA does not provide guidance as to the relative importance that DOE should attach to the listed factors. Therefore, in considering the factors listed in EPCA, DOE has historically used data and analysis to determine whether standards that satisfy other EPCA requirements are also economically justified.
DOE also notes that it laid out a process to elaborate on the procedures, interpretations and policies that will guide the Department in establishing new or revised energy efficiency standards for consumer products. 61 FR 36974 (July 15, 1996). That process provides for greatly enhanced opportunities for public input, improved analytical approaches, and encouragement of consensus-based standards. This enhanced approach was developed by the Department on the basis of extensive consultations with many stakeholders.
In determining the impacts of a potential amended standard on manufacturers, DOE conducts a manufacturer impact analysis (“MIA”), as discussed in section IV.J. (42 U.S.C. 6313(a)(6)(B)(ii)(I)) DOE first uses an annual cash-flow approach to determine the quantitative impacts. This step includes both a short-term assessment—based on the cost and capital requirements during the period between when a regulation is issued and when entities must comply with the regulation—and a long-term assessment over the analysis period. The industry-wide impacts analyzed include: (1) Industry net present value (“INPV”), which values the industry on the basis of expected future cash flows; (2) cash flows by year; (3) changes in revenue and income; and (4) other measures of impact, as appropriate. Second, DOE analyzes and reports the impacts on different subgroups of manufacturers, including impacts on small manufacturers. Third, DOE considers the impact of standards on domestic manufacturer employment and manufacturing capacity, as well as the potential for standards to result in plant closures and loss of capital investment. Finally, DOE takes into account cumulative impacts of various DOE regulations and other regulatory requirements on manufacturers.
For individual commercial consumers, measures of economic impact include the changes in LCC and PBP associated with new or amended standards. These measures are discussed further in the following section. For consumers in the aggregate, DOE also calculates the national net present value of the economic impacts applicable to a particular rulemaking. DOE also evaluates the LCC impacts of potential standards on identifiable subgroups of consumers that may be affected disproportionately by a national standard.
EPCA requires DOE to consider the savings in operating costs throughout the estimated average life of the covered equipment in the type (or class) compared to any increase in the price of, or in the initial charges for, or maintenance expenses of, the covered product that are likely to result from a standard. (42 U.S.C. 6313(a)(6)(B)(ii)(II))
The LCC is the sum of the purchase price of a product (including its installation) and the operating cost (including energy, maintenance, and repair expenditures) discounted over the lifetime of the equipment. The LCC analysis requires a variety of inputs, such as equipment prices, equipment energy consumption, energy prices, maintenance and repair costs, equipment lifetime, and discount rates appropriate for commercial consumers. To account for uncertainty and variability in specific inputs, such as equipment lifetime and discount rate, DOE uses a distribution of values, with probabilities attached to each value.
The PBP is the estimated amount of time (in years) it takes commercial consumers to recover the increased purchase cost (including installation) of more-efficient equipment through lower operating costs. DOE calculates the PBP by dividing the change in purchase cost due to a more-stringent standard by the change in annual operating cost for the year that standards are assumed to take effect.
For its LCC and PBP analysis, DOE assumes that commercial consumers will purchase the covered equipment in the first year of compliance with amended standards. The LCC savings for the considered efficiency levels are calculated relative to the case that reflects projected market trends in the absence of amended standards. DOE's LCC and PBP analysis is discussed in further detail in section IV.F.
Although the significant conservation of energy is a separate statutory requirement for adopting an energy conservation standard, EPCA requires DOE, in determining the economic justification of a standard, to consider the total projected energy savings that are expected to result directly from the standard. (42 U.S.C. 6313(a)(6)(B)(ii)(III)) As discussed in section IV.H, DOE uses the NIA spreadsheet to project national energy savings.
Commenting on the CUAC NOPR, AHRI stated that DOE gave energy savings disproportionate weight in its analysis, which conflicts with 42 U.S.C. 6313(a)(6)(A)(ii)(II) and 6313(a)(6)(B)(ii)(I)–(VII). In its view, DOE should consider seven different factors in determining whether the benefits of a proposed standard exceed its burdens, and stated that there is no indication in the statute or otherwise that Congress intended this to be anything other than a roughly equal weighting of factors where no particular factor is king over all the others. (CUAC: AHRI, No. 68 at p. 22)
Section 6313(a)(6)(A)(ii)(II) concerns DOE's authority to adopt a national standard more stringent than the amended ASHRAE/IES Standard 90.1 if such standard would result in the significant additional conservation of energy and is technologically feasible and economically justified. Section V.C of this document sets forth in detail the reasons why DOE has concluded that the adopted standards for CUACs/CUHPs would result in the significant additional conservation of energy and are technologically feasible and economically justified.
Section 6313(a)(6)(B)(ii)(I)–(VII) lists the factors that DOE must consider in determining whether a standard is economically justified for the purposes of subparagraph (A)(ii)(II). Weighing these factors, in DOE's view, requires a careful balancing of each factor to help ensure the comprehensiveness of the Agency's review of any potential standard under consideration. Accordingly, DOE has weighed these factors in assessing the energy efficiency levels recommended by the Working Group.
In establishing equipment classes, and in evaluating design options and the impact of potential standard levels, DOE evaluates potential standards that would not lessen the utility or performance of the considered equipment. (42 U.S.C. 6313(a)(6)(B)(ii)(IV)) Based on data available to DOE, the standards adopted in this final rule would not reduce the utility or performance of the equipment under consideration in this rulemaking.
EPCA directs DOE to consider the impact of any lessening of competition, as determined in writing by the Attorney General, that is likely to result from a proposed standard. (42 U.S.C. 6313(a)(6)(B)(ii)(V)) Specifically, it instructs DOE to consider the impact of any lessening of competition, as determined in writing by the Attorney General, that is likely to result from the imposition of the standard. DOE is simultaneously publishing a NOPR containing proposed energy conservation standards identical to those set forth in this direct final rule and has transmitted a copy of the rule and the accompanying TSD to the Attorney General, requesting that the U.S. Department of Justice (“DOJ”) provide its determination on this issue. DOE will consider DOJ's comments on the direct final rule in determining whether to proceed with finalizing its standards. DOE will also publish and respond to the DOJ's comments in the
DOE also considers the need for national energy conservation in determining whether a new or amended standard is economically justified. (42 U.S.C. 6313(a)(6)(B)(ii)(VI)) The energy savings from the adopted standards for CUACs/CUHPs and CWAFs are likely to provide improvements to the security and reliability of the Nation's energy system. Reductions in the demand for electricity also may result in reduced costs for maintaining the reliability of the Nation's electricity system. DOE conducts a utility impact analysis to estimate how standards may affect the Nation's needed power generation capacity, as discussed in section IV.M.
The adopted standards also are likely to result in environmental benefits in the form of reduced emissions of air pollutants and GHGs associated with energy production and use. DOE conducts an emissions analysis to estimate how potential standards may affect these emissions, as discussed in section IV.K; the emissions impacts are reported in section V.B.6 of this document. DOE also estimates the economic value of emissions reductions resulting from the considered TSLs, as discussed in section IV.L.
Commenting on the CUAC/CUHP NOPR, AHRI questioned DOE's inclusion of environmental benefits in its consideration since none of the more specific factors in section 6313(a)(6)(B)(ii)(I)–(VI) refer to environmental matters. (AHRI asserted that DOE must have based its inclusion of environmental and SCC benefits on the catch-all “other factors” provision of 42 U.S.C. 6313(a)(6)(B)(ii)(VII).) AHRI stated that DOE must clarify precisely why and how it believes that it has the statutory authority under section 6313(a)(6)(B)(ii) to consider SCC issues in any fashion, and, if so, under what sub-provision (
DOE maintains that environmental and public health benefits associated with the more efficient use of energy are important to take into account when considering the need for national energy and water conservation, which is one of the factors to consider under EPCA. (42 U.S.C. 6295(o)(2)(B)(i)(VI)) Given the threats posed by global climate change to the economy, public health,
In determining whether an energy conservation standard is economically justified, DOE may consider any other factors that the Secretary deems to be relevant. (42 U.S.C. 6313(a)(6)(B)(ii)(VII)) In developing the direct final rule, DOE has also considered the submission of the jointly-submitted Term Sheet from the Working Group and approved by ASRAC. In DOE's view, the Term Sheet sets forth a statement by interested persons that are fairly representative of relevant points of view (including representatives of manufacturers of covered equipment, States, and efficiency advocates) and contains recommendations with respect to energy conservation standards that are in accordance with 42 U.S.C. 6313(a)(6)(B), as required by EPCA's direct final rule provision. See 42 U.S.C. 6295(p)(4). DOE has encouraged the submission of agreements such as the one developed and submitted by the CUAC–CUHP–CWAF Working Group as a way to bring diverse stakeholders together, to develop an independent and probative analysis useful in DOE standard setting, and to expedite the rulemaking process. DOE also believes that standard levels recommended in the Term Sheet may increase the likelihood for regulatory compliance, while decreasing the risk of litigation.
EPCA creates a rebuttable presumption that an energy conservation standard is economically justified if the additional cost to the commercial consumer of an equipment that meets the standard is less than three times the value of the first year's energy savings resulting from the standard, as calculated under the applicable DOE test procedure. 42 U.S.C. 6295(o)(2)(B)(iii) Although this rebuttable presumption is not specifically mentioned in section 6316(b)(1) as applying to CUACs/CUHPs and CWAFs, DOE nonetheless considered the rebuttable presumption criteria as part of its analysis. DOE's LCC and PBP analyses generate values used to calculate the effect potential amended energy conservation standards would have on the payback period for consumers. These analyses include, but are not limited to, the 3-year payback period contemplated under the rebuttable-presumption test. In addition, DOE routinely conducts an economic analysis that considers the full range of impacts to consumers, manufacturers, the Nation, and the environment, as required under 42 U.S.C. 6295(o)(2)(B)(i), and 42 U.S.C. 6313(a)(6)(B)(ii). The results of this analysis serve as the basis for DOE's evaluation of the economic justification for a potential standard level (thereby supporting or rebutting the results of any preliminary determination of economic justification). The rebuttable presumption payback calculation is discussed in section IV.F of this document.
The current energy conservation standards for CUACs and CUHPs are based on the metrics EER for cooling efficiency and COP for CUHP heating efficiency. See 10 CFR 431.97(b). In this direct final rule, DOE is adopting energy conservation standards based on IEER for cooling efficiency and is continuing to use COP for denoting CUHP heating efficiency.
In the CUAC/CUHP RFI, DOE noted that it was considering whether to replace the existing cooling efficiency descriptor, EER, with a new energy-efficiency descriptor, IEER. 78 FR at 7299. Unlike the EER metric, which only uses the efficiency of the equipment operating at full-load in high-ambient-temperature conditions (
EPCA requires that test procedures be reasonably designed to produce test results that measure the energy efficiency of covered equipment during a representative average use cycle or period of use. (42 U.S.C. 6314(a)(2)) As discussed above, the IEER metric weights the efficiency of operating at different part-loads and full-load based on usage patterns, which collectively provide a more representative measure of annual energy use than the EER metric. A manufacturer that was involved in the development of the IEER metric indicated that the usage pattern weights for the IEER metric were developed by analyzing equipment usage patterns of several buildings across the 17 ASHRAE Standard 90.1–2010 (appendix B) climate zones. (Docket ID: EERE–2013–BT–STD–0007–0018, Carrier, at p. 1) These usage patterns and climate zones were based on a comprehensive analysis performed by industry in assessing the manner in which CUAC and CUHP equipment operate in the field, both in terms of actual usage and the climatic conditions in which they are used. The weighting factors accounted for the hours of operation where mechanical cooling was active—
AHRI, Nordyne, Rheem, Trane, the Joint Efficiency Advocates, and Southern Company all generally supported using IEER as the proposed metric. (CUAC: AHRI, No. 68 at p. 42; Nordyne, No. 61 at p. 35; Rheem, No. 70 at p. 2; Trane, No. 63 at p. 6; Joint Efficiency Advocates, No. 69 at pp. 1–2; Southern Company, Public Meeting Transcript, No. 104 at p. 25) The Joint Efficiency Advocates supported DOE's proposal to replace EER with IEER. In their view, DOE could retain the EER standards while adding IEER. They added that if DOE decided to use a single metric, IEER would better reflect annual energy consumption than EER since this equipment rarely operates at full-load. (CUAC: Joint Efficiency Advocates, No. 69 at pp. 1–2)
While supporting the use of IEER, AHRI, Nordyne, and Lennox recognized that EER will continue to be an important metric for utilities when managing peak load electricity usage. (CUAC: AHRI, No. 68 at p. 42; Nordyne, No. 61 at p. 35; Lennox, No. 60 at p. 14) The California IOUs recommended that DOE establish standards using both EER and IEER metrics to prevent poor equipment performance at high temperature full-load conditions. Given the low weighting (2 percent) of the full-load condition for the IEER metric, there is an incentive for manufacturers to optimize equipment at the part-load conditions with ambient temperatures between 65 °F and 82 °F. The California IOUs indicated that moving to an IEER-only metric could potentially mean that a new standard could result in equipment that is designed with full-load EER values lower than the current standards. (CUAC: California IOUs, No. 67 at p. 2; California IOUs, ASRAC Public Meeting, No. 102 at p. 99) The California IOUs commented that, in the absence of dual metrics using both EER and IEER, they supported standards based on EER, or use of IEER accompanied by required reporting of each of the IEER test points, including full-load EER. (CUAC: California IOUs, No. 67 at pp. 2, 7–8) The Joint Efficiency Advocates similarly supported the reporting of each IEER test point. (CUAC: Joint Efficiency Advocates, No. 69 at p. 8)
However, the California IOUs and other members of the ASRAC Working Group more recently agreed as Term Sheet signatories to recommend that DOE adopt standards for CUACs and CUHPs based on IEER for cooling efficiency. (CUAC: ASRAC Term Sheet, No. 93 at pp. 2–4) DOE also notes that ASHRAE Standard 90.1 includes requirements and reporting for both EER and IEER. As a result, although DOE is setting energy conservation standards for CUACs and CUHPs based on the IEER metric, EER ratings of equipment would still be available through the AHRI certification database. DOE notes that AHRI and manufacturers agreed to continue to require verification and reporting of EER for equipment through AHRI's certification program. AHRI also agreed to submit a letter to the docket for this rulemaking committing to continuing to require verification and reporting of EER for it's certification program. (CUAC: ASRAC Public Meeting, No. 101 at pp. 9, 55; ASRAC Public Meeting, No. 103 at pp. 113–116) Thus, utilities, and others, would still be able to consider full-load efficiency in their energy efficiency programs. For these reasons, and for the reasons stated previously that the IEER metric provides a more accurate representation of the annual energy use for this equipment, DOE is adopting standards for small, large, and very large, CUACs and CUHPs cooling efficiency based on the IEER metric.
DOE notes that a change in metrics (
As discussed in section IV.A.2.a, DOE is establishing separate equipment classes for double-duct CUACs and CUHPs and is maintaining the current energy conservation standards for this equipment. As a result, DOE is maintaining the existing EER metric for the double-duct CUAC and CUHP equipment classes.
The current energy conservation standards for small, large, and very large air-cooled CUHPs heating efficiency are based on the COP metric.
AHRI, Nordyne, Goodman and Rheem supported the continued use of COP as the heating efficiency metric for CUHPs. (CUAC: AHRI, No. 68 at p. 42; Nordyne, No. 61 at p. 35; Goodman, No. 65 at p. 12; Rheem, No. 70 at p. 2) In addition, members of the ASRAC Working Group agreed as signatories to the Term Sheet to standards for air-cooled CUHPs based on COP for heating efficiency. (CUAC: ASRAC Term Sheet, No. 93 at pp. 2–4) As discussed in section IV.A, DOE is adopting standards for air-cooled CUHPs in this direct final rule based on COP for heating efficiency.
In response to the CUAC/CUHP NOPR, AHRI commented that DOE did not explain how it concluded that the proposed rulemaking would result in the significant additional conservation
Trane stated that DOE's CUAC/CUHP NOPR analysis grossly underestimated the costs at all the TSL levels and, therefore, overstated the benefits to the nation. (CUAC: Trane, No. 63 at p. 8)
AHRI also commented that the proposed minimum efficiency level (EL3) represents a significant increase from the ASHRAE 90.1–2013 levels that will become effective in 2016. It stated that in order to achieve EL 3 levels it will be necessary to redesign approximately 80 percent of all units that are commercially-available today, and as a result, many classes of products will be eliminated, causing a significant contraction of the market. AHRI stated that the required design modifications will come at a significant cost to the consumer, and consumers who are unable to afford more efficient units will likely continue to repair and not replace units in service. It added that the situation could potentially alter the competitive landscape as other technologies are favored as alternatives (
Trane stated that the LCC savings for gas-fired CWAFs at the proposed standard are hardly measurable, and any slight change in the increase in product cost, installation or maintenance costs, and energy prices can change these savings to an increase in LCC. Similar results would occur in the NPV calculation where a positive NPV could easily become an increase in costs to the nation. (CWAF: Trane, No. 27 at p. 7)
DOE notes that while it is not adopting the proposed standards from the CUAC/CUHP and CWAF NOPRs, these comments, along with the intensive feedback received during the Working Group discussions contributed to the modified approach and revised standards recommended by the ASRAC Working Group that DOE is presenting in this direct final rule. As discussed in section V.C, DOE has determined that the recommendations are in accordance with the provisions of 42 U.S.C. 6313(a)(6)(B), as required by 42 U.S.C. 6295(p)(4) and 6316(b)(1). The evidence supporting this determination is clearly described in detail in the direct final rule TSDs and the accompanying spreadsheets. The evidence that the adopted standards would result in the significant additional conservation of energy and are technologically feasible is convincing, as the projected energy savings exceed the threshold for significance by a wide margin (see section III.E.2), and their technological feasibility, based on DOE's examination, is well-established (see section III.D). The evidence that the adopted standards are economically justified is also convincing. In particular, the economic impact of the standards on the consumers of CUACs/CUHPs and CWAFs is positive by a wide margin, as discussed in section V.C.
Commenting on the CUAC/CUHP NOPR, a number of parties stated that DOE should rely on the ASHRAE process in setting amended commercial equipment efficiency standards.
ASHRAE urged DOE to rely on the efficiencies established in ASHRAE Standard 90.1–2013 for the equipment listed in this rulemaking. It noted that: (1) ASHRAE 90.1–2013 underwent the fully open ANSI/ASHRAE consensus process with buy-in and consensus from manufacturers, energy advocates, representatives from DOE, and other materially affected and interested parties; (2) the efficiency levels were established in a cost-effective manner using the ASHRAE “scalar ratio” economic analysis methodology; and (3) many interested parties, including DOE, invested a significant amount of time and energy in establishing the efficiency levels currently found in ASHRAE 90.1–2013 with ample opportunities to provide input. ASHRAE recommended that DOE no longer pursue the proposed rulemaking, and approve the ASHRAE 90.1–2013 efficiency levels for this equipment. (CUAC: ASHRAE, No. 59 at pp. 1–4). AHRI, Goodman and Lennox made a similar comment. (CUAC: AHRI, No. 68 at pp. 2, 10–11; Goodman, No. 65 at pp. 2–3; Lennox, No. 60 at pp. 8–9) A number of other parties made similar comments. (CUAC: Huntley, No. 62 at p. 1; Viridis, No. 56 at p. 1; Merryman-Farr, No. 49 at p. 1; KJWW, No. 46 at p. 1; Smith-Goth, No. 45 at p. 1; A2H, No. 44 at p. 1)
Notwithstanding DOE's participation in the development of ASHRAE Standard 90.1–2013, which did not impact the EER standards for which DOE already incorporated into its regulations, amendments to EPCA established by AEMTCA required DOE to initiate the current rulemaking, which DOE began in advance of the ASHRAE 90.1–2013 amendments (see section II.A). EPCA, as amended, also directs DOE to prescribe standards that are designed to achieve the maximum improvement in energy efficiency that is technologically feasible and economically justified, and would result in the significant additional conservation of energy. (42 U.S.C. 6313(a)(6)(A)(ii)(II)) It also provides the factors that DOE has considered to select and adopt standards for which the benefits exceed the burdens. (42 U.S.C. 6313(a)(6)(B)(ii)) In DOE's view, the standards being adopted in this direct final rule satisfy these elements. DOE further notes that AHRI, Goodman and Lennox are parties to the recommendations that form the basis for this direct final rule, pursuant to 42 U.S.C. 6295(p)(4) and 6316(b)(1), indicating that the direct final rule's standard levels and supporting analyses resolved their concerns related to DOE's initial NOPR.
Referring to section VI.A of the CUAC/CUHP NOPR, AHRI stated that DOE did not present evidence to support two of the market failures that it identified pursuant to section 1(b)(1) of Executive Order 12866.
Section 1(b)(1) of Executive Order (E.O.) 12866, “Regulatory Planning and Review,” 58 FR 51735 (Oct. 4, 1993), requires each agency to identify the problem that it intends to address (including, where applicable, the failures of private markets or public institutions that warrant new agency action), as well as to assess the significance of that problem. As discussed in section VI.A of this direct final rule, DOE identified two problems that would generally be considered “market barriers” (numbers 1 and 2 in section VI.A, which are related to certain features concerning consumer decision-making), and one problem that most economists would consider a “market failure” (number 3, which concerns environmental externalities).
Miller indicated that neither of the potential market failures cited by DOE (externalities related to GHG emissions and asymmetric information (and related misaligned incentives) regarding high-efficiency commercial appliances is solved by its proposed energy efficiency standards, leaving the proposal economically unjustifiable. Miller further stated that DOE does not explain why sophisticated, profit-motivated purchasers of CUACs and CUHPs would suffer from either informational deficits or cognitive biases that would cause them to purchase products with high lifetime costs without demanding higher-price, higher-efficiency products. Miller added that this asymmetric information, if it exists, could be remedied by improved labeling or other types of consumer education campaigns rather than banning products from the marketplace. (Miller, No. 39 at p. 13)
The proposed standards, as well as the adopted standards contained in this direct final rule, are intended to address the above-cited problems, but DOE's action is primarily responsive to the statutes that govern the amendment of energy efficiency standards (see section II.A). Neither the relevant statutes nor the relevant Executive Order (Executive Order 12866, “Regulatory Planning and Review”)
Miller stated that DOE expects only 10 percent of the externality benefits of carbon reductions to accrue to Americans, so the costs to American citizens outweigh the social benefits of the standard by almost 3 to 1, calling into question whether the proposal is economically justified. (Miller, No. 39 at p. 13)
DOE notes that the domestic SCC values were estimated by the interagency Working Group as a range from 7 percent to 23 percent of the global values. Using the central SCC value, the domestic CO
Miller stated that DOE's proposal does not maintain flexibility and freedom of choice for purchasers of CUAC and CUHP equipment. (Miller, No. 39 at p. 13) In contrast to the proposed standards, which DOE is not adopting, the standards adopted for CUACs and CUHPs allow a much higher share of currently-produced models to remain on the market. The models that would be allowed under the standards cover a wide range of efficiencies and other attributes, thereby maintaining considerable choice for purchasers of CUACs and CUHPs.
This section addresses the analyses DOE has performed for this rulemaking. Separate subsections address each component of DOE's analyses.
DOE used several analytical tools to estimate the impact of the standards considered in support of this direct final rule. The first tool is a spreadsheet that calculates the LCC savings and PBP of potential amended or new energy conservation standards. The national impacts analysis uses a second spreadsheet set that provides shipments forecasts and calculates national energy savings and net present value of total consumer costs and savings expected to result from potential energy conservation standards. DOE uses the third spreadsheet tool, the Government Regulatory Impact Model (GRIM), to assess manufacturer impacts of potential standards. These spreadsheet tools are available on the DOE Web site for the rulemaking for CUACs/CUHPs:
For the market and technology assessment, DOE developed information that provided an overall picture of the market for the equipment concerned, including the purpose of the equipment, the industry structure, market characteristics, and the technologies used in the equipment. This activity included both quantitative and qualitative assessments, based primarily on publicly-available information. The subjects addressed in the market and technology assessment for this rulemaking include scope of coverage, equipment classes, types of equipment sold and offered for sale, manufacturers, and technology options that could improve the energy efficiency of the equipment under examination. The key findings of DOE's market and technology assessment are summarized below. For additional detail, see chapter 3 of the CUAC/CUHP and CWAF direct final rule TSDs.
The energy conservation standards adopted in this direct final rule cover small, large, and very large, CUACs and CUHPs under section 342(a) of EPCA. (42 U.S.C. 6313(a)) This category of equipment has a rated capacity between 65,000 Btu/h and 760,000 Btu/h. It is designed to heat and cool commercial buildings. In the case of single-package units, which house all of the components (
When evaluating and establishing energy conservation standards, DOE divides covered equipment into equipment classes by the type of energy used, capacity, or other performance-related features that would justify a different standard. In determining whether a performance-related feature would justify a different standard, DOE considers such factors as the utility to the consumer of the feature and other factors DOE determines are appropriate. All of the different air conditioning and heat pump equipment addressed by this rule are air-cooled unitary air-conditioners and heat pumps.
The current equipment classes that EPAct 2005 established for small, large, and very large CUACs and CUHPs divide this equipment into twelve classes characterized by rated cooling capacity, equipment type (air conditioner versus heat pump), and heating type. Table IV–1 shows the current equipment class structure.
In the CUAC/CUHP NOPR, DOE proposed energy conservation standards based on this existing equipment class structure, which is also provided in Table 1 of 10 CFR 431.97. 79 FR 58964.
United CoolAir Corporation (“UCA”) submitted a request that DOE exempt a specific type of air conditioning equipment (“double-duct air-cooled air conditioners”). See UCA, EERE–2013–BT–STD–0007–0020. These units are designed for indoor installation in constrained spaces using ducting to an outside wall for the supply and discharge of condenser air to and from the condensing unit. The sizing of these units is constrained both by the space available in the installation location and the available openings in the building through which the unit's sections must be moved to reach the final installation location. These size constraints, coupled with the higher power required by the condenser fan to provide sufficient pressure to move the condenser air through the supply and return ducts, affect the energy efficiency of these types of systems. More conventional designs for which condensers are located outdoors can more easily draw in condenser air through the condenser (or outdoor coil for heat pumps) and can move the air using direct-drive propeller fans. These design differences allow a manufacturer to maximize condenser surface area, reduce the pressure rise requirement of the fan, significantly reduce condenser (outdoor) fan power and improve equipment efficiency.
Currently, double-duct air conditioners are tested and rated under the same test conditions as single-duct air conditioners, without any ducting connected to, or an external static pressure applied on, the condenser side. UCA has asserted that the double-duct design provides customer utility in that it allows interior field installations in existing buildings in circumstances where space constraints make an outdoor unit impractical to use. Id. DOE noted in the CUAC/CUHP NOPR that the design features associated with the described double-duct designs may affect energy use while providing justifiable customer utility. 79 FR at 58964.
In response to the CUAC/CUHP NOPR, a number of heating, ventilating and air conditioning (“HVAC”) equipment distributors—MWSK Equipment Sales Inc. (“MWSK”), H & H Sales Associates, Inc. (“H&H”), Gardiner Trane, Heat Transfer Solutions (“HTS”), HVAC Equipment Sales, Inc., Havtech, and Slade Ross, Inc.—all supported establishing a new equipment class for the indoor horizontal double-duct units. These commenters explained that UCA's double-duct units are unique in that they are modular and are applied completely inside buildings where rooftop air conditioners and split systems are not practical or possible. (CUAC: MSWK, No. 72 at pp. 1–2; H&H,
Goodman commented that if DOE creates a separate equipment class for double-duct units, the definitions should be very clearly specified to prevent gaming. Goodman stated that the definition should include (a) physical properties of the equipment (fan type and orientation, maximum product height/width/depth, duct connection sizes, or other such parameters), (b) application properties (minimum external static pressure for condenser airflow, refrigerant line set lengths, maximum capacities, etc.), (c) literature requirements (statements within installation and operation manuals and specification sheets), and (d) certification requirements. (CUAC: Goodman, No. 65 at pp. 12–13)
Members of the ASRAC Working Group agreed that a separate equipment class should be established for double-duct CUACs and CUHPs. The ASRAC Term Sheet recommended the following approach with respect to these equipment:
• The existing EER standard levels provided in Table 1 of 10 CFR 431.97 shall continue to apply for double-duct CUACs and CUHPs.
• Double-duct air conditioner or heat pump would be defined as meaning air-cooled commercial package air conditioning and heating equipment that satisfies the following elements:
○ It is either a horizontal single package or split-system unit; or a vertical unit that consists of two components that may be shipped or installed either connected or split;
○ It is intended for indoor installation with ducting of outdoor air from the building exterior to and from the unit, where the unit and/or all of its components are non-weatherized and are not marked (or listed) as being in compliance with UL 1995, “Heating and Cooling Equipment,” or equivalent requirements for outdoor use;
○ (a) If it is a horizontal unit, the complete unit has a maximum height of 35 inches or the unit has components that do not exceed a maximum height of 35 inches; (b) If it is a vertical unit, the complete (split, connected, or assembled) unit has components that do not exceed maximum depth of 35 inches; and
○ It has a rated cooling capacity greater than or equal to 65,000 Btu/h and up to 300,000 Btu/h. (CUAC: ASRAC Term Sheet, No. 93 at pp. 4–5)
Based on DOE's review of double-duct CUACs and CUHPs available on the market, DOE agrees with the ASRAC Term Sheet recommendations. First, DOE agrees that these units have features that justify establishing separate equipment classes for them. Double-duct units, as evidenced by several commenters, offer a unique utility that may otherwise become unavailable if these units were subjected to the more rigorous standards required by this direct final rule for other CUAC and CUHP equipment. DOE notes that double-duct units, which are installed within the building envelope and use ductwork to transfer outdoor air to and from the outdoor unit, would have added challenges in meeting more stringent energy conservation standards due to space constraints and added condenser fan power.
Second, DOE agrees that the definition for these units recommended in the ASRAC Term Sheet, with minor modifications, appropriately distinguish them from other classes. Double-duct units must have limited width or height to be able to fit through doorways and to fit in above-ceiling space (for horizontal units) or in closets (for vertical units) for interior installation. DOE's research showed that vertical and horizontal double-duct units had a width or height of 34 inches or less, respectively. As a result, DOE agrees that specifying a maximum width or height of 35 inches to include only units that can be installed indoors, as presented in the ASRAC Term Sheet recommendations, is appropriate. To this end, DOE is adopting this approach by clarifying the provision. Specifically, since a complete unit cannot be smaller than its largest component, placing the 35-inch restriction on the finished equipment itself addresses the dimensional restrictions intended by the Working Group while simplifying the text of the definition itself. DOE also notes that because these units are designed for indoor installation, as noted by UCA, DOE agrees that these units would require ducting of outdoor air from the building exterior and that units intended for outdoor use should not be considered in the same equipment class. As a result, DOE agrees with the ASRAC Term Sheet recommendations that double-duct units and/or all of their components should be non-weatherized and not marked as being in compliance with UL Standard 1995 or equivalent requirements for outdoor use. DOE also notes that single package vertical units (“SPVUs”) are already covered under separate standards (10 CFR 431.97(d)). As a result, to ensure that SPVUs are not covered under the definition of double-duct CUACs and CUHPs, DOE agrees with the ASRAC Term Sheet recommendations that for vertical double-duct units, only those with split configurations (that may be installed with the two components attached together) should be included as part of this separate equipment class. For these reasons, DOE is adopting the definition proposed in the ASRAC Term Sheet for double-duct CUACs and CUHPs and is maintaining the existing EER standards contained in Table 1 of 10 CFR 431.97 for this equipment.
The energy conservation standards adopted in this direct final rule cover CWAFs, as defined by EPCA and DOE. EPCA defines a “warm air furnace” as “a self-contained oil- or gas-fired furnace designed to supply heated air through ducts to spaces that require it and includes combination warm air furnace/electric air conditioning units but does not include unit heaters and duct furnaces.” (42 U.S.C. 6311(11)(A)) DOE defines the term “commercial warm air furnace” as meaning “a warm air furnace that is industrial equipment, and that has a capacity (rated maximum input) of 225,000 Btu per hour or more.” 10 CFR 431.72. Accordingly, this rulemaking covers equipment in these categories having a rated capacity of 225,000 Btu/h or higher and that are designed to supply heated air in commercial and industrial buildings via ducts (excluding unit heaters and duct furnaces).
As discussed above for CUACs/CUHPs, DOE divides covered equipment into equipment classes based on the type of energy used, capacity, or other performance-related features that would justify having a higher or lower standard from that which applies to other equipment classes.
The equipment classes for CWAFs were defined in the EPACT 1992
In response to the CWAFs NOPR, Nordyne commented that the CWAF definition should include gas-fired “makeup” air furnaces.
As part of the market and technology assessment, DOE uses information about existing and past technology options and prototype designs to help identify technologies that manufacturers could use to improve CUAC/CUHP and CWAF energy efficiency. Initially, these technologies encompass all those that DOE believes are technologically feasible. Chapter 3 of the CUAC/CUHP and CWAF direct final rule TSDs includes the detailed list and descriptions of all technology options identified for this equipment.
For the CUAC/CUHP NOPR, DOE considered the technology options presented in Table IV–3. 79 FR at 58969.
In the CUAC/CUHP NOPR, DOE noted that for the majority of the identified technology options, the analysis considered designs that are generally consistent with existing equipment on the market (
Goodman commented that all of the technology options listed by DOE are available in the market today and manufacturers can and do use such options whenever they are cost effective. All of the proposed technology options can be used to provide minor improvements to the HVAC system's efficiency, specifically IEER, but have minimal, if any, impact on EER. (CUAC: Goodman, No. 65 at p. 13) Goodman stated that the majority of the technology options increase physical size of the components and/or unit. Face area of indoor/outdoor coils can be held constant while improving heat transfer by either additional coil rows or increased fin density. However, Goodman noted that both of those options also increase the fan power required to move air through the coils which at least partially counteracts the gains from more coil surface area. Goodman stated that some of the proposed technology options such as increased condenser fan diameter, while technologically feasible, are not practically feasible. (CUAC: Goodman, No. 65 at p. 13)
Rheem commented that a larger diameter forward-curved indoor fan performs well at the low static test condition but can be unstable when the system is installed with a high static duct system. Rheem also stated that the applicability of the backward-inclined blower wheel requires a complete redesign of a package unit outside envelope, which will add cost to the system. Other options, such as multiple compressors or variable frequency drives, are not as disruptive to the footprint design. Rheem noted that the footprint of the unit intended for the replacement market is restricted to existing roof curbs and duct configurations. Rheem added that additional unit height on very large equipment may be restricted by internal tractor trailer clearances when the equipment is shipped. (CUAC: Rheem, No. 70 at p. 3)
As discussed in section IV.A, DOE selected and analyzed currently available models using their rated efficiency to characterize the energy use and manufacturing production costs at each efficiency level. As a result, DOE analyzed equipment designs, including unit dimensions, expansion devices, and indoor and outdoor coils and fans/
Regarding copper rotor motors, DOE noted in the CUAC/CUHP NOPR that manufacturing more efficient copper rotor motors requires using copper instead of aluminum for critical components of an induction motor's rotor (
Nidec commented that the reduction in electric motor total energy losses estimated by DOE to be achievable with copper rotors when compared to aluminum rotors is not consistent with what has been reported as achievable in previous DOE rulemakings for electric motors nor is it consistent with Nidec's experience. Nidec noted that the TSD for electric motors showed a reduction in total losses of less than 10 percent when changing from an aluminum rotor to a die-cast copper rotor along with additional enhancements to the motor design such as increased stack length, increased slot fill, and/or different lamination steel material. Nidec added that DOE may also be overstating in the electric motors rulemaking the reduction in total losses that can typically be achieved, citing comments made by the National Electrical Manufacturers Association (“NEMA”) on that rulemaking indicating that the full-load loss for a prototype 10-hp motor was only 5.9 percent less than that for the motor with the aluminum rotor. (CUAC: Nidec, No. 55 at pp. 2–5)
DOE appreciates the additional information regarding the reduction in total losses associated with copper rotors. As discussed above, DOE considered design options for the engineering analysis consistent with equipment currently available on the market and considered the efficiency of the equipment as a whole rather than quantifying the energy savings associated with individual components. Accordingly, as part of its technology options analysis, DOE screened in copper rotors as one possible option to improve overall CUAC/CUHP efficiency. However, DOE notes that, based on its review of equipment available on the market, it did not observe any models that incorporated copper rotor motors. Because DOE analyzed the full system design of equipment and specific design options consistent with actual equipment available on the market, DOE did not specifically analyze copper rotor motors as part of the engineering analysis.
Regal-Beloit commented that DOE should consider electronically commutated motors (“ECMs”) as an alternate technology for the indoor fan. ECM technology is now a viable alternative to variable frequency drives (“VFDs”) for CUACs and CUHPs. Regal-Beloit also commented that DOE should consider ECM technology at efficiency levels other than the max-tech. (CUAC: Regal-Beloit, No. 66 at p. 1) As noted in Table IV–3, DOE considered ECMs as a technology option. As discussed in section IV.C.3.a, DOE revised the engineering analysis to be based on rated models at each efficiency level so that equipment design and specific design options analyzed were consistent with actual equipment at each efficiency level. Based on DOE's review of equipment available on the market, DOE did not observe any models using ECMs for the indoor fan. In addition, Carrier commented as part of the ASRAC Working Group meetings that ECMs are not currently used for indoor fan motor above 1 horsepower. (CUAC: Carrier, ASRAC Public Meeting, No. 94 at p. 186) However, DOE notes that manufacturers would not be precluded from incorporating ECMs for the indoor fan. Details of the design options at each efficiency level are presented in chapter 5 of the CUAC/CUHP direct final rule TSD.
In the analyses for this direct final rule, DOE reviewed the market for CWAFs, as well as information gathered from interviews with CWAF manufacturers during the NOPR analyses, to determine the common technologies implemented to improve CWAF efficiency. Based on this information, DOE primarily considered the following technology options to improve CWAF thermal efficiency:
DOE notes that a secondary heat exchanger for condensing operation is a possible technology option for CWAFs, but also that this technology has considerable issues to overcome when used in weatherized equipment. These issues relate specifically to the handling of acidic condensate produced by a condensing furnace in the secondary heat exchanger. Condensate must be drained from the furnace to prevent build-up in the secondary heat exchanger, and properly disposed of after exiting into the external environment. Some building codes limit the disposal of condensate into the municipal sewage system, so the condensate must be passed through a neutralizer to reduce its acidity to appropriate levels prior to disposal. In weatherized installations, it is more difficult to access the municipal sewage system than in non-weatherized installations. Condensate produced by a weatherized condensing furnace must flow naturally or be pumped through pipes to the nearest disposal drain, which may not be in close proximity to the furnace. In cold environments, there is a risk of the condensate freezing as it flows through these pipes, which can cause an eventual back-up of condensate into the heat exchanger, resulting in significant damage to the furnace.
Despite these issues, DOE found in its review of the market that multiple manufacturers offer weatherized HVAC equipment with a condensing furnace heating section. DOE believes that this fact indicates that many of the issues related to a condensing secondary heat exchanger can be overcome, and thus, DOE considered a condensing secondary heat exchanger as a technology option. As discussed in section IV.B.1, this technology was ultimately passed through the screening analysis and considered in the engineering analysis. Regarding condensate disposal, DOE included the cost of condensate disposal lines for all condensing installations; for further details on the installation costs of a
DOE also identified the following additional technology options for improving CWAF efficiency. Many of these technologies were either removed from the analysis because they were screened out or because they did not improve the rated TE of CWAFs as measured by the DOE test procedure (see section IV.B for further details):
After DOE identified the technologies that might improve CUAC/CUHP and CWAF energy efficiency, DOE conducted a screening analysis. The purpose of the screening analysis is to determine which options to consider further and which to screen out. DOE consulted with industry, technical experts, and other interested parties in developing a list of design options. DOE then applied the following set of screening criteria to determine which design options are unsuitable for further consideration in the rulemaking:
•
•
•
•
Additionally, DOE notes that these screening criteria do not directly address the proprietary status of technology options. DOE only considers efficiency levels achieved through the use of proprietary designs in the engineering analysis if they are not part of a unique path to achieve that efficiency level (
Technologies that pass through the screening analysis are referred to as “design options” and are subsequently examined in the engineering analysis for consideration in DOE's downstream cost-benefit analysis.
For CUACs and CUHPs, DOE screened out the following technology options in the CUAC/CUHP NOPR. 79 FR at 58969–58970.
Regarding the use of potential refrigerants, in the CUAC/CUHP NOPR, DOE considered ammonia, carbon dioxide, and various hydrocarbons (such as propane and isobutane) as alternative refrigerants to those that are currently in use, such as R–410A. DOE noted that safety concerns need to be taken into consideration when using ammonia and hydrocarbons in air conditioning systems. The Environmental Protection Agency (“EPA”) created the Significant New Alternatives Policy (“SNAP”) Program to evaluate alternatives to ozone-depleting substances. Substitutes are reviewed on the basis of ozone depletion potential, global warming potential, other environmental impacts, toxicity, flammability, and exposure potential. DOE noted at the time of the CUAC/CUHP NOPR that ammonia used in vapor compression cycles, carbon dioxide, and hydrocarbons were approved or were being considered under SNAP for certain uses, but these or other low global warming potential (“GWP”) alternatives were not listed as acceptable substitutes for this equipment.
Danfoss and the Environmental Investigation Agency (EIA Global) commented that the United States is supporting a phasedown of HFC refrigerants, including HFC–410A, through the Montreal Protocol. (CUAC: Danfoss, No. 53 at p. 2; EIA Global, No. 58 at pp. 3–4) Danfoss added that Europe has already mandated a 40-percent reduction in HFC production by 2020. Danfoss stated that it is likely that EPA will also set limits on the use of HFC–410A in the future, but the timing and impact on the use of R–410A is unknown at this time. Danfoss encouraged DOE to work closely with EPA and to align standards for CUACs and CUHPs with EPA SNAP rules, so that major equipment redesigns can be
EIA Global expressed its concern that DOE's analysis will be incomplete without the inclusion of alternative hydrocarbon refrigerants and that the high GWP of current HFC refrigerants for this equipment category will further damage the stability of the climate, thus offsetting the efficiency gains associated with standards. EIA Global commented that DOE should consider currently available systems using alternative refrigerants and the effects of the EPA's finalization of its proposed rule, “Protection of Stratospheric Ozone: Listing Substitutes for Refrigeration and Air-Conditioning and Revision of the Venting Prohibition for Certain Refrigerant Substitutes,” which lists propane (R–290) and hydrocarbon blend R–441A as acceptable alternatives under the EPA's SNAP program for end uses including light commercial air conditioners and heat pumps. EIA Global commented that DOE should consider the energy efficiency savings and the reduction in GHG emissions from these alternative low-GWP refrigerants. EIA Global also urged DOE to include provisions to enable persons to petition for an interim revisiting of the standard in light of the EPA SNAP rule approving the use of these alternative refrigerants. (CUAC: EIA Global, No. 58 at pp. 1–2, 4–8)
EIA Global stated that, given the President's recent Executive Action, “Invest in New Technologies to Support Safer Alternatives,” DOE should be using its authority to not only conduct its own research and commercialization of HFC-free technologies, but also to incentivize U.S. industry to manufacture HFC-free and energy efficient CUACs and CUHPs, so they can lead the world in the development and marketing of the next generation of this equipment. (CUAC: EIA Global, No. 58 at pp. 1–4)
DOE recognizes that EPA published a final rule approving alternative refrigerants, subject to use conditions, in specific end-uses. 80 FR 19454 (Apr. 10, 2015). However, DOE notes that these end-use applications did not include CUACs and CUHPs that are the subject of this rulemaking. DOE notes that hydrocarbon refrigerants have not yet been approved by the EPA SNAP program for these types of equipment and, hence, cannot be considered as a technology option in DOE's analysis. DOE also notes that, while it is possible that HFC refrigerants currently used in CUACs and CUHPs may be restricted by future rules, DOE cannot speculate on the outcome of a rulemaking in progress and can only consider in its rulemakings rules that are currently in effect. Therefore, DOE has not included possible outcomes of potential EPA SNAP rulemakings. This position is consistent with past DOE rulings, such as in the 2014 final rule for commercial refrigeration equipment (79 FR 17725, 17753–54 (March 28, 2014)) and the 2015 final rule for automatic commercial icemakers (80 FR 4646, 4670–71 (Jan. 28, 2015)) DOE notes that recent rules by the EPA that allow use of hydrocarbon refrigerants or that impose new restrictions on the use of HFC refrigerants do not address air-cooled CUACs and CUHPs applications. 80 FR 19454 (April 10, 2015) and 80 FR 42879 (July 20, 2015). DOE acknowledges that there are government-wide efforts to reduce emissions of HFCs, and such actions are being pursued both through international diplomacy as well as domestic actions. DOE, in concert with other relevant agencies, will continue to work with industry and other stakeholders to identify safer and more sustainable alternatives to HFCs while evaluating energy efficiency standards for this equipment.
DOE also recognizes that while some alternative refrigerants may be under consideration as potential future replacements for CUACs and CUHPs, including low-GWP blends submitted to EPA's SNAP program, the development of safety and other related building code standards that will impact decisions regarding the final selected alternatives are still under way. DOE cannot consider all of the potential alternatives to accurately analyze the efficiency impacts for this equipment. Goodman similarly noted as part of the ASRAC Working Group meetings that the safety standards for alternative refrigerants are in the process of being developed, and the current standards, UL 1995, “Heating and Cooling Equipment” and UL 60335–2–40, “Safety of Household and Similar Electrical Appliances, Part 2–34: Particular Requirements for Motor-Compressors,” specifically ban any flammable refrigerant from comfort air conditioning products. (CUAC: Goodman, ASRAC Public Meeting, No. 99 at pp. 43–44)
DOE also notes that performance information regarding all alternative refrigerants, such as CUACs and CUHPs with proven test data and publicly available compressor performance information, are not available at this time to properly evaluate the impacts of alternative refrigerants on energy use.
As mentioned in section VI.B.4, if a manufacturer believes that its design is subjected to undue hardship by regulations, the manufacturer may petition DOE's Office of Hearing and Appeals (OHA) for exception relief or exemption from the standard pursuant to OHA's authority under section 504 of the DOE Organization Act (42 U.S.C. 7194), as implemented at subpart B of 10 CFR part 1003. OHA has the authority to grant such relief on a case-by-case basis if it determines that a manufacturer has demonstrated that meeting the standard would cause hardship, inequity, or unfair distribution of burdens. DOE also notes that any person may petition DOE for an amended standard applicable to a variety of consumer products and commercial/industrial equipment. See 42 U.S.C. 6295(r) and 42 U.S.C. 6313(a). This provision, however, does not apply to the equipment addressed by this rulemaking. See 42 U.S.C. 6316(b).
In recognition of the issues related to alternative refrigerants, members of the ASRAC Working Group agreed as part of the Term Sheet to delay implementation of the second phase of increased energy conservation standard levels until January 1, 2023, in part to align dates with potential refrigerant phase-outs and to provide sufficient development lead time after safety requirements for acceptable alternatives have been established. (CUAC: ASRAC Term Sheet, No. 93 at pp. 3–4; ASRAC Public Meeting, No. 100 at pp. 82; ASRAC Public Meeting, No. 101 at pp. 48–49) Delaying the implementation of the second phase of standards in the manner recommended and agreed to by the Working Group will provide manufacturers with flexibility and additional time to comply with both energy conservation standards and potential refrigerant changes, allowing manufacturers to better coordinate equipment redesign to reduce the cumulative burden. As discussed in section III.C, DOE is adopting the proposed two-phased approach recommended in the ASRAC Term Sheet.
With respect to copper rotors, Nidec disagreed with DOE's determination not to screen out this option. In its view, copper rotor motors do not satisfy either the screening criteria of (a) practicability to manufacture, install, and service; or (b) adverse impacts on equipment utility or equipment availability. (CUAC: Nidec, No. 55 at p. 2–5) Nidec stated that the very short lifespans for the end ring dies and casting pistons for copper die-casting presses would prevent motor manufacturers from mass producing copper rotors on a sufficient scale due to the constant need to replace this tooling. (CUAC: Nidec, No. 55 at p. 5) Nidec also noted that there is a lack of die-cast copper rotor production
As noted in the electric motors final rule, DOE noted that two large motor manufacturers currently offer die-cast copper rotor motors up to 30-horsepower. DOE also noted in the electric motors rule that full scale deployment of copper would likely require considerable capital investment and that such investment could increase the production cost of copper rotor motors considerably. 79 FR 30934, 30963–65 (May 29, 2014). However, increased motor cost alone would not be a reason to screen out this technology. For these reasons, DOE did not screen out this technology on the basis of practicability to manufacture, install, and service, or adverse impacts on equipment utility or equipment availability.
Based on the screening analysis, DOE identified the design options listed in Table IV–5 for further consideration in the engineering analysis:
A full description of each technology option is included in chapter 3 of the CUAC/CUHP direct final rule TSD, and additional discussion of the screening analysis is included in chapter 4 of the CUAC/CUHP direct final rule TSD.
For CWAFs, DOE screened out the technology options listed in Table IV–6. Each of these technology options failed to meet at least one of the four screening criteria: (1) technological feasibility; (2) practicability to manufacture, install, and service; (3) impacts on equipment utility or equipment availability; and (4) adverse impacts on health or safety. See 10 CFR part 430, subpart C, appendix A, 4(a)(4) and 5(b).
In addition, the following technology options met all four of the screening criteria, but were removed from further consideration in the engineering analysis because they do not impact the CWAF efficiency as measured by the DOE test procedure:
Based on the screening analysis, DOE identified the following five technology options for further consideration in the engineering analysis:
A full description of each technology option is included in chapter 3 of the CWAF direct final rule TSD, and additional discussion of the screening analysis is included in chapter 4 of the CWAF direct final rule TSD.
The engineering analysis establishes the relationship between an increase in energy efficiency of equipment and the increase in manufacturer selling price (“MSP”) required to achieve that efficiency increase. This relationship serves as the basis for the cost-benefit calculations for commercial customers, manufacturers, and the Nation. In determining the cost-efficiency relationship, DOE estimates the increase in manufacturer cost associated with increasing the efficiency of equipment to incrementally higher efficiency levels above the baseline efficiency level, up to the maximum technologically feasible (“max-tech”) efficiency level for each equipment class.
DOE typically structures its engineering analysis using one or more of three identified basic methods for generating manufacturing costs: (1) The design-option approach, which provides the incremental costs of adding individual technology options (as identified in the market and technology assessment and passed through the screening analysis) that can be added alone or in combination with a baseline model in order to improve its efficiency (
For CUACs and CUHPs, DOE conducted the engineering analyses using a combination of the efficiency-level approach and the reverse-engineering approach and analyzed three specific capacities, one representing each of the three equipment class capacity ranges (
For CWAFs, DOE conducted the engineering analysis using the reverse-engineering approach to estimate the costs of achieving various efficiency levels. DOE selected two gas-fired CWAF units in the non-condensing efficiency range for physical teardowns, both at a heating input rating of 250,000 Btu/h, which was considered to be the representative heating input rating for the gas-fired equipment class. In addition, DOE purchased a condensing, 92-percent TE gas-fired makeup air furnace for physical examination. Makeup air furnaces are the only type of 92-percent TE gas-fired CWAFs currently available on the market. DOE also performed a physical teardown of an oil-fired CWAF at 81-percent TE at an input rating of 400,000 Btu/h, which was subsequently scaled down via cost estimation techniques to represent a unit with a 250,000 Btu/h heating input rating. Similar to gas-fired CWAFs, 250,000 Btu/h was also considered the representative heating input rating for oil-fired CWAFs. GTI commented that at around a heating input of 400,000 Btu/h, in gas-fired CWAFs, it may be common practice for manufacturers to transition from a single furnace to two furnaces in packaged equipment. This would necessitate additional components associated with the second furnace including additional gas valves and inducer fans, which may contribute to a different price regime (CWAF: GTI, NOPR Public Meeting Transcript, No. 17 at pp. 74–75). DOE agrees that gas-fired CWAFs are generally not manufactured with individual combustion modules (
DOE used catalog data, information from the physical teardown examinations, and manufacturer feedback to estimate the manufacturing costs for gas-fired CWAFs at the 80-percent, 81-percent, 82-percent and 92-percent TE levels, as well as the manufacturing costs for oil-fired CWAFs at the 81-percent, 82-percent and 92-percent TE levels. Additional detail on the teardowns performed is provided in chapter 5 of the CWAF direct final rule TSD.
The baseline model is used as a reference point for each equipment class in the engineering analysis and the life-cycle cost and payback-period analyses, which provides a starting point for analyzing potential technologies that provide energy efficiency improvements. Generally, DOE considers “baseline” equipment to refer to a model or models having features and technologies that just meet, but do not exceed, the minimum energy conservation standard.
As discussed in section III.G, for CUACs and CUHPs, DOE decided to replace the current cooling performance energy efficiency descriptor, EER, with IEER. With this change in metrics (
In the CUAC/CUHP NOPR, DOE noted that it is typically obligated either to adopt those standards developed by ASHRAE or to adopt levels more stringent than the ASHRAE levels if there is clear and convincing evidence in support of doing so. (42 U.S.C. 6313(a)(6)(A)) DOE noted that ASHRAE Standard 90.1–2010 specifies minimum efficiency requirements using both the EER and IEER metrics. As discussed in the CUAC/CUHP RFI, DOE evaluated the relationship between EER and IEER by considering models that are rated at the current DOE standard levels based on the EER metric for each equipment class. DOE then analyzed the distribution of corresponding rated IEER values for each equipment class, noting that a single EER level can correspond to a range of IEERs. DOE also noted that the lowest IEER values associated with the current DOE standards for EER generally correspond with the ASHRAE Standard 90.1–2010 minimum efficiency requirements. See 78 FR at 7299. Based on this evaluation, because DOE is considering energy conservation standards based on the IEER metric, DOE proposed in the CUAC/CUHP NOPR to use the ASHRAE Standard 90.1–2010 minimum IEER requirements to characterize the baseline cooling efficiency for each equipment class. Because the baseline efficiency level is intended to be representative of the minimum efficiency of equipment, DOE did not consider higher IEER levels for the baseline. (79 FR at 58972.)
For CUHPs, DOE considered heating efficiency standards based on the COP metric. As discussed in section II.B.1, EPAct 2005 established minimum COP levels for small, large, and very large air-cooled CUHPs, which DOE codified in a final rule on October 18, 2005. 70 FR 60407. DOE proposed in the CUAC/CUHP NOPR to use these current COP standard levels to characterize the baseline heating efficiency for each equipment class. (79 FR at 58972.)
Table IV–7 presents the baseline efficiency levels for each equipment class considered in the CUAC/CUHP NOPR.
Based on a review of equipment available on the market, DOE notes that an IEER of 10.6 is more representative of the baseline cooling efficiency for major manufacturers of units falling into the very large CUACs with “electric resistance heating or no heating” equipment class. As a result, DOE revised the baseline cooling efficiency level for this equipment class. DOE also revised the baseline cooling efficiency levels for the very large equipment classes for (1) all other types of heating and (2) heat pumps by using the corresponding differences in IEER specifications for these pairs of equipment classes prescribed in ASHRAE Standard 90.1–2010. For all other equipment classes, DOE maintained the baseline efficiency levels from the CUAC/CUHP NOPR. The efficiency levels considered in this final rule are presented below in Table IV–8.
In establishing the baseline efficiency level for this analysis, DOE used the existing minimum energy conservation standards for CWAFs to identify baseline units. The baseline TE levels for each equipment class are presented in Table IV–9.
For each equipment class, DOE analyzes several efficiency levels and determines the incremental cost at each of these levels.
For the CUAC/CUHP NOPR, DOE developed efficiency levels based on a review of industry standards and available equipment. For Efficiency Level 1, DOE used the IEER levels specified in the draft of addendum CL
For the CUHP equipment classes, DOE proposed cooling mode efficiency levels equal to the CUAC efficiency levels minus the difference in IEER specifications for these two equipment types prescribed in Draft Addendum CL. DOE stated that these decreases in IEER are representative of the efficiency differences that occur due to losses from the reversing valve and the reduced potential for optimization of coil circuitry for cooling, since coils in heat pumps must work for both heating and cooling operation.
For the CUHP equipment classes, DOE proposed heating efficiency levels in the CUAC/CUHP NOPR based on a variation of COP with IEER. 79 FR at 58973. In the previous standards rulemaking from 2004 for these equipment, DOE proposed to address the energy efficiency of air-cooled CUHP by developing functions relating COP to EER. 69 FR at 45468. DOE noted that this method was also used by industry to establish minimum performance requirements for ASHRAE Standard 90.1–1999.
The efficiency levels for each equipment class proposed in the CUAC/CUHP NOPR are presented in Table IV–10.
Lennox commented that DOE is required to consider ASHRAE 90.1–2013 according to 42 U.S.C. 6313(a)(6)(A). Lennox noted that Efficiency Level 1 mirrors the values in ASHRAE 90.1–2013 except for large CUAC/CUHP equipment class. (CUAC: Lennox, No. 60 at p. 7) As discussed above, DOE based the CUAC/CUHP NOPR Efficiency Level 1 IEERs on ASHRAE 90.1–2010 Addendum CL. After the NOPR, DOE reviewed ASHRAE 90.1–2013 and updated the IEERs for Efficiency Level 1 accordingly for this direct final rule.
The Joint Efficiency Advocates and California IOUs reacted to the CUAC/CUHP NOPR by urging DOE to evaluate intermediate efficiency levels between Efficiency Level 3 and Efficiency Level 4, noting that the presence of gaps between these levels. The Joint Efficiency Advocates and California IOUs noted that there are models at various IEER levels available between Efficiency Level 3 and Efficiency Level 4 across the equipment classes. (CUAC: Joint Efficiency Advocates, No. 69 at p. 2; California IOUs, No. 67 at pp. 3–5; ASAP, ASRAC Public Meeting, No. 102 at pp. 202, 209–210, 211–212, 217–218).
The Joint Efficiency Advocates and the California IOUs urged DOE to reevaluate the max-tech levels and noted that for each equipment class, the highest IEERs of commercially-available equipment listed in the AHRI directory are higher than the max-tech levels. (CUAC: Joint Efficiency Advocates, No. 69 at pp. 2–3; California IOUs, No. 67 at pp. 6–7)
Carrier supported DOE's approach for determining the max-tech efficiency levels based on recently introduced models. These models represent technologies that are both available for all of the capacity sizes within a given equipment class and that are economically justified for their performance improvement. (CUAC: Carrier, No. 48 at p. 3) Goodman commented during the negotiated rulemaking that DOE should also consider an additional efficiency level between the CUAC/CUHP NOPR Efficiency Level 2 and Efficiency Level 3. (CUAC: Goodman, ASRAC Public Meeting No. 102 at pp. 208—209)
Based on DOE's review of equipment listed in the AHRI directory, DOE agreed with interested parties that additional efficiency levels should be considered in its analysis. For all equipment classes, DOE added an efficiency level between Efficiency Level 2 and Efficiency Level 3 from the CUAC/CUHP NOPR, identified in this direct final rule as Efficiency Level 2.5. DOE also added an efficiency level, identified in this direct final rule as efficiency level 5, above CUAC/CUHP NOPR Efficiency Level 4, to represent the max-tech models available on the market. For small and large equipment, DOE added an efficiency level between Efficiency Level 3 and Efficiency Level 4 from the CUAC/CUHP NOPR, identified in this direct final rule as Efficiency Level 3.5. As part of the ASRAC Working Group meeting, interested parties agreed on these additional efficiency levels for the analysis. (CUAC: ASRAC Public Meeting, No. 94 at pp. 170—171)
For this direct final rule, the IEER values for the baseline efficiency level and Efficiency Level 1 for the “all other types of heating equipment” classes are based on the IEER difference of 0.2 as compared to the electric resistance heating or no heating equipment class specified in ASHRAE 90.1–2010 and ASHRAE 90.1–2013. As discussed further in section IV.E.1, DOE chose cooling efficiency levels for CUACs coupled with all other types of heating above Efficiency Level 1 that provided the same energy savings between incremental efficiency levels as was determined for the electric resistance or no heating equipment classes within each equipment class capacity range (
Based on DOE's review of equipment available on the market, the majority of models with electric resistance heating or no heating equipment are designed on the same basic platform and cabinet size as the equivalent models with all other types of heating equipment. Because these equipment have the same or similar designs, DOE estimates that implementing the same design changes
For the CUHP equipment classes, DOE used a similar approach for determining the IEER differentials relative to the CUAC equipment classes. The IEER values for the baseline efficiency level and Efficiency Level 1 for the CUHP equipment classes are based on the IEER differences as compared to the CUAC equipment classes specified in ASHRAE 90.1–2010 and ASHRAE 90.1–2013. As discussed further in section IV.E.1, DOE chose cooling efficiency levels for the CUHP equipment classes above Efficiency Level 1 that provided the same energy savings between incremental efficiency levels as was determined for the CUAC equipment classes within each equipment class capacity range (
Regarding the incremental COP heating efficiency levels for CUHPs, AHRI, Nordyne, Carrier, Goodman and Rheem commented that they did not support DOE's approach for determining the COP levels based on a correlation with IEER. These commenters stated that there is no technical or statistical justification to support that a correlation exists between IEER and COP. IEER is a part-load metric while COP is a full-load heating metric similar to EER for cooling. (CUAC: AHRI, No. 68 at p. 32; Nordyne, No. 61 at p. 27; Carrier, No. 48 at pp. 3–4; Goodman, No. 65 at p. 14; Rheem, No. 70 at p. 4)
Members of the ASRAC Working Group were not able to suggest a more appropriate approach for assigning COP values to the efficiency levels analyzed. Because the use of correlations between
Based on the discussion above, DOE considered the efficiency levels presented in Table IV–13 for this direct final rule.
For CWAFs, DOE developed efficiency levels for analysis higher than the baseline efficiency level (
In its analysis, DOE focused on specific incremental TE levels above the baseline for each equipment class. The incremental TE levels are representative of efficiency levels along the technology paths that CWAF manufacturers commonly use to maintain cost-effective designs while increasing the TE of equipment. DOE reviewed its Compliance Certification Management
DOE found several manufacturers that offer gas-fired equipment at 81-percent TE. In the analysis for the direct final rule, DOE found only one manufacturer of gas-fired equipment rated at 82-percent TE, which is available across a limited range of input capacities. In addition, all of the 82-percent TE units offered by this manufacturer are non-weatherized, and are thus not representative of the large majority of gas-fired CWAF model offerings, which are weatherized. Therefore, in its analyses for the direct final rule, DOE did not identify any weatherized gas-fired CWAFs at 82-percent TE. However, in the analyses for the CWAF NOPR, DOE identified a different manufacturer of gas-fired 82-percent TE CWAFs. These particular units were weatherized. This manufacturer offered equipment at this efficiency level across a wide range of input capacities, indicating that meeting the 82-percent TE level is technologically feasible for weatherized gas-fired CWAFs at most input capacities. Thus, DOE considered 81-percent and 82-percent as incrementally higher TE levels for the gas-fired CWAF analysis.
DOE also considered the max-tech efficiency level. As discussed in section IV.C.1, DOE purchased a 92-percent thermally efficient gas-fired makeup air furnace for teardown, as makeup air units are currently the only type of gas-fired CWAF at a condensing efficiency level. There are substantially more non-makeup air CWAFs product offerings than makeup air furnace product offerings. However, based on manufacturer feedback, physical teardowns and examination of equipment, and product literature, DOE observed that gas-fired makeup air furnaces are technologically very similar to non-makeup air CWAFs.
Further, DOE identified a residential-sized (
As discussed above, for the engineering analysis, DOE specifically analyzed representative capacities of 7.5 tons, 15 tons, and 30 tons to develop incremental cost-efficiency relationships.
For the CUAC/CUHP NOPR, DOE selected four 7.5-ton, two 15-ton, and one 30-ton CUAC models, and one 7.5-ton CUHP model. The models were selected to develop a representative sample of the market at different efficiency levels. DOE based the selection of units for testing and reverse engineering on the efficiency data available in the AHRI certification database and the CEC equipment database. 79 FR at 58974. DOE conducted testing on each unit according to the IEER test method specified in AHRI Standard 340/360–2007. DOE then conducted physical teardowns on each test unit to develop a manufacturing cost estimation process and to evaluate key design features (
For CUACs, DOE conducted energy modeling using the modeling tools developed by the Center for Environmental Energy Engineering from the University of Maryland at College Park. The tools include a detailed heat exchanger modeling program and a refrigeration cycle modeling program. The refrigeration cycle modeling program can integrate the heat exchanger and compressor models to perform a refrigeration cycle model. Details regarding the energy modeling tools are discussed in section 5.5.5 and 5.6.4 of chapter 5 of the CUAC/CUHP direct final rule TSD.
As explained in the CUAC/CUHP NOPR, DOE applied the key design features identified during physical equipment teardowns and used the energy modeling tool to generate detailed performance data (
Lennox expressed concern regarding the differences between using tested and rated IEER values to validate the energy modeling simulations. Lennox noted that Efficiency Level 1 for 7.5 tons (12.9 IEER) was based on a unit with a rated IEER of 11.4, but which DOE tested at 12.9 IEER. Lennox's modeling of this unit predicted an IEER of 12.2. Lennox commented that using a single test point to extrapolate well above manufacturer ratings to justify the proposed standard levels is arbitrary and not a valid approach. (CUAC: Lennox, No. 60 p. 13)
AHRI, Nordyne and Lennox commented that the design features that DOE used to characterize the energy use and costs for the baseline and incremental efficiency levels for 7.5 tons are not representative of realistic models. (CUAC: AHRI, No. 68 at p. 35; Nordyne, No. 61 at p. 29; Lennox, No. 60 at p. 13) They added that DOE's approach for the 7.5 ton analysis of developing a design for the baseline efficiency level by decreasing the size of the heat exchangers of the Efficiency Level 1 design results in a loss of EER performance below the current DOE minimum standard levels. (CUAC: AHRI, No. 68 at p. 35; Nordyne, No. 61 at p. 29; Lennox, No. 60 at p. 13) Goodman commented that manufacturers' published performance documents includes data for a specific model with specific physical parameters. Goodman stated that using these data and attempting to perform energy model modifications to these physical parameters could lead to inaccurate predictions of the effects of these design changes on performance and energy consumption. Goodman also expressed concern that there was no confirmation testing of the simulation results for the higher efficiency equipment and, based on their assessment, the performance of equipment at higher efficiency levels is overstated. (CUAC: Goodman, No. 65 at pp. 15, 17)
To address these concerns with DOE's engineering analysis (
The IEER ratings for the units selected for energy modeling match the corresponding efficiency level's target IEER within ±0.2. In the case where selected unit's IEER rating differs from the target IEER, the model was first calibrated to match the unit's ratings. The dimensions of the heat exchangers were then slightly adjusted such that the adjusted model would produce the target IEER. With regards to the comments concerning the modeled full-load EER values, because the revised analysis is based on actual models available on the market that comply with the current standards for these equipment, none of the representative units have EER values that would not comply with the currently required EER-based standards. Details of the design features, corresponding component wattage profiles and performance correlations for each efficiency level and equipment class are presented in chapter 5 of the CUAC/CUHP direct final rule TSD.
AHRI and Nordyne commented that the modeling used in the NOPR-phase energy analysis of the equipment was extremely complex and very dependent upon the precision and accuracy of the parameters entered. AHRI, Nordyne, and Goodman commented that DOE did not provide sufficient details and data (
For each representative model analyzed at each efficiency level for the direct final rule analysis, DOE reviewed details of the assumptions for the equipment design parameters and the energy modeling results (
AHRI, Nordyne, Carrier and Goodman also commented that the geometry input for the CoilDesigner energy modeling tool that DOE used in preparing its NOPR analysis did not accurately model heat exchanger performance because it did not include inputs required for modeling the internally enhanced (
As noted in chapter 5 of the CUAC/CUHP NOPR TSD, DOE's analysis for 7.5-ton units assumed that the baseline and Efficiency Level 1 both used a single refrigerant circuit design. AHRI and Nordyne disagreed with this approach and commented that use of a single-stage compressor and a single refrigerant circuit rather than multiple circuits and compressor stages is not broadly consistent with the current market trends for 7.5-ton units. AHRI and Nordyne added that nearly 90 percent of all units sold in this size have multiple compressors, which is required by ASHRAE 90.1 standards. (CUAC: AHRI, No. 68 at p. 35; Nordyne, No. 61 at p. 29) Lennox also commented that using a single compressor design to represent Efficiency Level 1 for the small equipment class is not consistent with current industry equipment designs. Lennox noted that nearly 90 percent of their current sales of 7.5 ton units use multiple compressors and that over 95 percent of 7.5 to 10 ton units use multiple compressors. (CUAC: Lennox, No. 60 at pp. 12–13) Carrier commented that the split for single- and dual-compressor units may be even at 7.5 tons, but that for 10-ton units and up to the high end of the capacity range for small equipment, everything uses dual-compressor designs. (CUAC: Carrier, ASRAC Public Meeting, No. 102 at pp. 129, 132–133) ASAP, the California IOUs, NEEA, and ACEEE commented that DOE should consider both single- and dual-compressor designs for the small equipment classes. (CUAC: ASAP, California IOUs, NEEA, ACEEE, ASRAC Public Meeting, No. 102 at pp. 129–140)
Based on DOE's review of models in the small CUAC and CUHP equipment classes, DOE noted that the majority of models at Efficiency Level 1 used a dual-compressor design. Based on this review, a dual-compressor design is more representative of models at Efficiency Level 1. As a result, DOE revised its analysis to use a dual-compressor design to characterize the energy use and manufacturing production cost for Efficiency Level 1. DOE noted that single- and dual-compressor designs are both available at the baseline efficiency level for the small equipment class. As a result, DOE conducted energy modeling to develop component wattage profiles and performance for both single- and dual-compressor designs for the 7.5-ton baseline efficiency level. As discussed in section IV.A, DOE also developed separate manufacturing production cost estimates for both single- and dual-compressor designs for the 7.5-ton baseline efficiency level.
AHRI, Nordyne, Carrier and Lennox commented in response to the CUAC/CUHP NOPR that a significant number of units at Efficiency Level 1 and Efficiency Level 2 for all equipment classes already incorporate multiple-speed indoor fans based on the requirements in ASHRAE 90.1 and California Title 24, and that the percentage of equipment with this feature will increase over the next several years. As a result, these commenters stated that DOE is overestimating the fan energy savings in ventilation mode at higher efficiency levels by considering only constant speed indoor fans at the lower efficiency levels. (CUAC: AHRI, No. 68 at pp. 33–34; Nordyne, No. 61 at p. 27–28; Carrier, No. 48 at pp. 2–3, 11; Lennox, No. 60 at pp. 9–11)
As discussed in section III.G.1, SAV and VAV CUACs/CUHPs incorporate multiple-speed or variable-speed indoor fan motors, as commented by interested parties, to stage indoor air flow rates. In contrast, constant-air volume (“CAV”) CUACs/CUHPs, which typically use a single- or constant-speed indoor fan motor, operate at a fixed indoor air flow rate. Based on DOE's review of equipment available on the market, CAV, SAV and VAV units are available at different efficiency levels for each of the equipment class cooling capacity ranges. Based on DOE's review of the indoor fan staging for models on the market, DOE notes that CAV units are available at Efficiency Level 2 and lower for the small and large equipment classes, and at Efficiency Level 2.5 and lower for the very large class. DOE notes that SAV or VAV units are available at Efficiency Level 1 and higher for all equipment classes. As a result, DOE revised the engineering analysis for this direct final rule to be based on two design paths for the different indoor fan staging options. Table IV–16 shows the design paths for each equipment class.
AHRI, Nordyne, and Lennox stated that the power input that DOE used for the condenser fans and indoor fan in the CUAC/CUHP NOPR modeling analysis does not appear realistic across the efficiency levels. These commenters noted that the high-speed indoor fan power on the 7.5-ton model at Efficiency Level 3 and Efficiency Level 4, and 15 ton model at all efficiency levels is unrealistically low. (CUAC: AHRI, No. 68 at p. 44; Nordyne, No. 61 at p. 37; Lennox, No. 60 at p. 15) AHRI and Nordyne commented with regards to variable-speed fans that the negative impact on mechanical efficiency from high load and low fan speed is not considered. (CUAC: AHRI, No. 68 at p.
For this direct final rule, as discussed above, DOE analyzed actual models using their rated IEER values to represent each target efficiency level. DOE calculated indoor fan power using fan performance tables provided in manufacturer equipment literature for these models, including for variable-speed fans as noted by AHRI and Nordyne, and motor efficiency based on compliance with DOE electric motor standards established by EPCA (10 CFR 431.25). The indoor fan motors used in equipment are selected to overcome a wide range of external static pressures (“ESPs”). The actual horsepower delivered by the motors at the rated air flow and minimum ESP required by the test procedure are typically less than the nameplate horsepower. For CAV units, the calculation for horsepower loss is based on the approach adopted in DOE's rulemaking for commercial and industrial fans and blowers.
ASRAC Working Group participants commented that DOE should further investigate the pressure drop associated with conversion curbs and the percentage of shipments that will require conversion curbs for each efficiency level, including the base case. Carrier and Trane both suggested discussing this issue with conversion curb suppliers. (CUAC: NEEA, ASAP, SMACNA, Carrier, Trane, ASRAC Public Meeting, No. 94 at pp. 147–167) Trane and Carrier commented that DOE should look across the range of capacities within each equipment class to determine the efficiency levels at which curb size changes. (CUAC: Trane, Carrier, ASRAC Public Meeting, No. 94 at pp. 193–199)
DOE collected information from major conversion curb vendors, including MicroMetl and Thybar (who were both identified during the Working Group's public discussions), regarding pressure drops, costs, and the size of the existing market for these products. (CUAC: ASRAC Public Meeting, No. 96 at pp. 75–77) DOE developed a distribution of efficiency levels at which conversion curbs are required by reviewing equipment size trends for key capacities of the equipment classes for four major manufacturers with equipment spanning the range of efficiencies considered for the analysis. DOE selected the efficiency levels that would require cabinet size increases for each manufacturer/capacity combination. DOE then developed a distribution of the percentage of shipments at each efficiency level that would require a conversion curb based on equal manufacturer market share. Regarding the pressure drop associated with conversion curbs, conversion curb vendors provided information regarding typical pressure drops for units installed with conversion curbs. Based on DOE's review of these data and discussions with conversion curb vendors, DOE determined that a pressure drop of 0.2 inch water column (in. wc.) represents the average pressure drop associated with CUAC/CUHP installations that include a conversion curb. Based on this evaluation, DOE applied a pressure drop of 0.2 in. wc. for full air flow across all equipment classes as a result of applying a conversion curb. ASRAC Working Group participants agreed to using a 0.2 in. wc. pressure drop for conversion curbs. (ASRAC Public Meeting, No. 97 at pp. 132–136) Using the 0.2 in. wc. conversion curb pressure drop at full air flow, DOE revised the cooling capacity and indoor fan power correlations used for the energy use analysis.
In the CUAC/CUHP NOPR, DOE did not conduct similar energy modeling for CUHP units since CUHP shipments represent a very small portion of industry shipments compared to CUACs shipments (9 percent versus 91 percent). With these small numbers, in DOE's view, modeling for CUHPs was unnecessary because DOE accounted for the difference in efficiency as compared to that which occurs with the CUAC equipment classes due to losses from the reversing valve and the reduced potential for optimization of coil circuitry for cooling, as discussed in section IV.C.2.b. In addition, because CUHPs represent a small portion of shipments, DOE noted, based on equipment teardowns and an extensive review of equipment literature
As discussed above, for the engineering analysis, DOE analyzed a representative input capacity of 250,000 Btu/h for both the gas-fired and oil-fired CWAF equipment classes to develop incremental cost-efficiency relationships. CWAF models selected for reverse engineering (physical teardown/examination) were used to estimate the costs to manufacture CWAFs at each efficiency level available on the market, ranging from the baseline 80-percent TE for gas-fired units, and baseline 81-percent TE for oil-fired units, up to the max-tech 92-percent TE for both gas-fired and oil-fired units. Because this reverse engineering was first conducted to inform the engineering analyses for the CWAF NOPR, the selection of units for testing and reverse engineering was based on the efficiency data available in the AHRI certification database,
DOE conducted physical teardowns on each unit tested to inform manufacturing cost estimations and to evaluate key design features (
For gas-fired CWAFs, DOE performed two teardowns on weatherized CWAFs units at non-condensing efficiency levels. Each CWAFs unit was part of a packaged CUAC/CWAF rooftop unit. One unit was rated at 80-percent TE and the other unit was rated at 82-percent TE. Prior to teardown, the units were tested by a third-party test lab and both tested at approximately 82-percent TE. The units were from the same manufacturer and had similarly designed furnace sections with different air conditioner sections. DOE determined that the similarity of the test results on both units indicated that the furnace designs that were torn down are representative of equipment with 82-percent TE. Using the cost-assessment methodology, DOE determined the manufacturing cost of each CWAFs torn down via reverse engineering.
Based on the CWAF teardowns, manufacturer feedback, product literature, and experience from the residential furnaces rulemaking, DOE determined that the primary method manufacturers use to achieve efficiency levels above baseline is to increase heat exchanger size. In the analyses for the February 2015 CWAF NOPR (80 FR 6181), DOE used feedback from manufacturer interviews to estimate that manufacturers will typically increase the surface area of the heat exchanger by 10 percent in order to increase TE by 1 percent.
In response to the costs presented in the NOPR, multiple stakeholders commented that the methodology for estimating the manufacturing cost of an 82-percent TE gas-fired CWAF did not account for significant technological modifications required to maintain equipment reliability at that efficiency level. Specifically, DOE's cost estimates in the NOPR for the 80-percent through 82-percent TE levels incorporated the use of aluminized steel to construct key heat exchanger and inducer assembly components. Multiple stakeholders commented that the estimated manufacturing cost of an 82-percent TE unit was not accurate, and that heat exchanger and inducer assembly components would need to be constructed out of more resilient materials at 82-percent TE. AHRI commented that to meet an 82-percent TE standard without sacrificing safety, reliability, and durability, manufacturers would need to significantly modify their CWAFs offerings to account for the risk of corrosion in the heat exchanger and venting system as a result of condensation formation under certain ambient conditions. In its view, accounting for this factor would require that the incremental manufacturer production cost (“MPC”) over baseline be higher than that presented in the NOPR engineering analysis. (CWAF: AHRI, No. 26 at p. 2) The Advocates commented that if it is determined that some portion of CWAF sales will necessitate stainless steel heat exchangers to accommodate condensate formation during operation, then the engineering analysis should be modified to account for the additional costs associated with this engineering modification. (CWAF: The Advocates, No. 24 at p. 1–2) Lennox commented that at 82-percent TE, the combination of higher TE and reduced dilution air decreases the safety factor between flue gas temperature and condensation point temperature by 40 percent, which greatly increases the risk for condensation formation. To overcome this, more expensive corrosion-resistant heat exchanger materials are needed. As a result, for smaller heating input capacity products, Lennox estimates the incremental MPC to achieve 82-percent TE over baseline efficiency is 12 times higher than the DOE estimate of $10. For larger capacity products, Lennox estimates the incremental MPC will be over 20 times higher than the $10 estimate. Additionally, Lennox noted that at 82-percent TE, the inducer motor would need to be constructed out of more corrosion-resistant materials. (CWAF: Lennox, No. 22 at p. 7) Rheem commented that at 82-percent TE, excessive condensation will occur to the point of causing heat exchanger or vent system corrosion. As a result, it would need to redesign the combustion system, evaluate alternative materials, conduct reliability testing, and other field tests—none of which were captured in the manufacturer costs presented in the TSD. (CWAF: Rheem, No. 25 at p. 2) Rheem added that to increase TE to 82-percent above baseline, the estimated $10 incremental MPC is not accurate with regard to Rheem's product offerings. In its view, the $10 incremental cost included in DOE's analysis would not allow them to add turbulators to their designs to enhance furnace efficiency. (CWAF: Rheem, No.
In the engineering analyses for the direct final rule, DOE modified its cost estimates for the 82-percent TE level in response to the above comments. To account for the use of corrosion-resistant materials in both the heat exchanger and inducer assemblies at 82-percent TE, DOE estimated the costs of implementing both 409-grade stainless steel (SS409) and 316-grade stainless steel (SS316) into these assemblies, rather than aluminized steel. In addition, DOE has observed that a certain portion of units at 80-percent and 81-percent TE also utilize heat exchanger and inducer assemblies that incorporate corrosion-resistant materials into their designs in order to improve durability. As such, for the 80-percent, 81-percent, and 82-percent TE levels, DOE estimated individual MPCs for each of the specific material options that may be incorporated into the heat exchanger/inducer assembly at that efficiency level. For more information on the methodology used to estimate the MPCs for the 80-percent, 81-percent, and 82-percent TE levels, see chapter 5 of the CWAF direct final rule TSD. In the life-cycle cost and payback period analysis, DOE assigned a percentage of models at each efficiency level that would incorporate each of the various material types analyzed. (See chapter 8 of the CWAF direct final rule TSD for further details.)
As discussed in section IV.C.1, to estimate the manufacturing cost of a 92-percent TE (max-tech) CWAF, DOE obtained a condensing, 92-percent TE gas-fired makeup air furnace for physical examination. In addition, DOE used information gathered from a teardown of a condensing weatherized residential furnace to further inform the cost estimation. DOE examined the heat exchanger, inducer fan, condensate management system, and other aspects of the gas-fired makeup air furnace to develop an estimate of the cost to manufacture these specific sub-assemblies in a condensing CWAF. DOE then used information from the residential condensing weatherized furnace teardown to refine estimates of the specific costs of a condensate management system for a condensing efficiency level CWAF. Using these sub-assembly cost estimates, and additional information provided by the two teardowns of 82-percent TE gas-fired CWAFs, DOE estimated the MPC for a 92-percent TE gas-fired CWAF. For further information on the estimation of the manufacturing cost of a 92-percent TE gas-fired CWAF, see chapter 5 of the direct final rule TSD.
For oil-fired CWAFs, DOE performed a teardown of a non-weatherized unit at 81-percent TE. DOE used this teardown, along with product literature, prior industry experience, manufacturer feedback, and analysis previously performed on oil-fired residential furnaces to develop estimates of the manufacturing costs of both 82-percent and 92-percent TE oil-fired CWAFs.
In a previous analysis of residential non-weatherized oil-fired furnaces, DOE developed an estimate of the cost-efficiency relationship across a range of efficiency levels. In examining product literature for oil-fired CWAFs, DOE found that commercial units are very similar to residential units, except with higher input ratings and overall larger size. Based on information obtained from the physical teardown of the 81-percent TE oil-fired CWAF, in addition to the information gained from the residential furnace analysis and product literature, DOE was able to conduct a virtual teardown to estimate the manufacturing costs for an 82-percent TE unit. Key to this cost estimate was the growth in heat exchanger size necessary for a 1-percent increase in TE, which necessitates a larger cabinet to accommodate it. Sheet metal and other components sensitive to size changes were scaled in order to match the larger size of the unit, while components that are not sensitive to heat exchanger size changes remained unchanged.
Similarly, DOE relied on the physical teardown at the 81-percent TE level, as well as prior comparisons of residential oil-fired furnaces at condensing and non-condensing efficiency levels, to conduct a virtual teardown at the 92-percent TE level. At 92-percent TE, a secondary condensing heat exchanger made from a high-grade stainless steel was added in order to withstand the formation of condensate from the flue gases coupled with increased heat extraction into the building airstream (and, thus, higher TE). This additional heat exchanger was appropriately-sized based on information gathered from teardowns of oil-fired residential furnaces. According to product specification sheets, 92-percent TE oil-fired CWAFs use similar heat exchanger technology as condensing residential oil-fired furnaces. To accommodate the secondary heat exchanger, the cabinet was increased in size, and all associated sheet metal, wiring, and other components sensitive to cabinet size changes were also scaled as a result. In addition, the size of the blower fan blade was increased appropriately to account for the additional airflow needed over the secondary heat exchanger (however, based on observations in product literature, the rated fan power was unchanged). The manufacturing costs obtained from these physical and virtual teardowns served as the basis for the cost-efficiency relationship for this equipment class. The teardown analyses for oil-fired CWAFs are described in further detail in chapter 5 of the direct final rule TSD.
DOE developed a systematic process to estimate the MPCs of CUACs/CUHPs and CWAFs. The process utilizes a spreadsheet that calculates costs based on information about the materials and components in the bills of materials (“BOMs”), based on the price of materials, average labor rates associated with fabrication and assembly, and the costs of overhead and depreciation, as determined based on manufacturer interviews and DOE expertise. To support cost calculations using the information in the BOMs, DOE collected information on labor rates, tooling costs, raw material prices, and other factors. For purchased parts, DOE estimates the purchase price based on volume-variable price quotations and detailed discussions with manufacturers and component suppliers. For fabricated parts, the prices of raw metal materials (
As discussed previously, for both CUACs/CUHPs and CWAFs, DOE calculated manufacturing costs at each efficiency level by totaling the costs of materials, labor, depreciation and direct overhead incurred in the manufacturing process. The total manufacturing cost of equipment at each efficiency level is
For the CUAC/CUHP NOPR, DOE developed the cost-efficiency results using the design information of tested units and design changes identified as part of the energy modeling analysis. DOE developed cost-efficiency relationships for each cooling capacity range. DOE also noted in the CUAC/CUHP NOPR that the incremental manufacturing production and shipping costs for each efficiency level developed for the CUACs with electric resistance heating or no heat equipment class would apply to all of the other equipment classes (
AHRI, Nordyne, Rheem, Trane, Lennox and Goodman commented that DOE has underestimated the costs of complying with the proposed standards. (CUAC: AHRI, No. 68 at pp. 29, 37–38, 44; Nordyne, No. 61 at pp. 24, 33, 37; Rheem, No. 70 at p. 4; Trane, No. 63 at p. 8; Lennox, No. 60 at p. 15; Goodman, No. 65 at pp. 13, 16)
DOE updated the raw materials and purchased parts costs used in the manufacturing cost estimation analysis based on U.S. Bureau of Labor Statistics and American Metals Market data. To address manufacturers concerns regarding DOE's estimated incremental MPCs, DOE provided detailed cost data, broken out by production factors (materials, labor, depreciation, and overhead) and also by major subassemblies (
For this direct final rule, DOE revised its analysis to be based on the physical and catalog teardown models using their IEER ratings at each efficiency level. For each equipment class, DOE estimated the incremental MPCs using the physical and catalog teardown models individually for each manufacturer that included sufficient information in their equipment literature to conduct the cost estimation analysis, then averaged the results across the manufacturers considered. As discussed above, DOE specifically focused its analysis on 7.5-ton, 15-ton, and 30-ton CUAC units with electric resistance heating or no heating. This approach for determining costs, which is different from the approach used for the energy modeling analysis discussed above, considers the full range of manufacturers and equipment offerings for which sufficient data were available to conduct the manufacturing estimation analysis using their rated IEER values. As discussed in section IV.C.3.a, DOE evaluated air flow design paths separately for CUAC and CUHP units with CAV and SAV/VAV air flow designs and also developed two separate costs for the baseline efficiency level for 7.5 tons for single- and dual-compressor designs.
Where the rated IEER values did not match exactly with the efficiency levels being considered, DOE's primary method to determine the MPCs for each efficiency level was to interpolate or extrapolate results. For example, to determine the costs at 7.5-ton Efficiency Level 1 (12.9 IEER), DOE determined the MPC for one manufacturer by interpolating the results for models rated at 12.2 IEER and 13.0 IEER. For efficiency levels with limited numbers of models, DOE developed incremental costs to be representative of the industry average cost to achieve those levels. For example, for Efficiency Level 4 for 7.5- and 15-ton units, DOE applied the relative percentage increase in cost for the one manufacturer with commercially-available equipment at that level across the other manufacturers to better represent average labor and production factors.
Based on this revised approach of considering the full range of manufacturers and equipment offerings using their rated IEER values and the consideration of additional feedback from manufacturers, DOE believes its revised cost estimates for this direct final rule provide a more accurate representation of the incremental manufacturing production costs required to achieve each efficiency level. Table IV–18 through Table IV–20 presents the cost-efficiency results developed for this direct final rule.
Based on the analytical methodology discussed in the sections above, DOE developed the cost-efficiency results for both gas-fired and oil-fired CWAFs shown in Table IV–21 and Table IV–22 for each TE level analyzed. As discussed in section IV.A, for each of the 80-percent, 81-percent, and 82-percent TE levels for gas-fired CWAFs, DOE developed multiple MPCs accounting for the use of either aluminized steel, SS409, or SS316 as a material type in the heat exchanger and inducer motor assemblies. The results shown in Table IV–21 represent the MPCs developed for each equipment class and efficiency level. Table IV–22 shows the incremental MPC increases, relative to the baseline MPC, needed to produce equipment at each specific efficiency level above baseline. Details of the cost-efficiency analysis, including descriptions of the technologies DOE analyzed at each efficiency level to develop the incremental manufacturing costs, are presented in chapter 5 of the CWAF direct final rule TSD.
To account for manufacturers' non-production costs and profit margin, DOE applies a non-production cost multiplier (the manufacturer markup) to the MPC. The resulting manufacturer selling price (“MSP”) is the price at which the manufacturer can recover all production and non-production costs and earn a profit. To meet new or amended energy conservation standards, manufacturers often introduce design changes to their equipment lines that result in increased MPCs. Depending on competitive pressures, some or all of the increased production costs may be passed from manufacturers to retailers and eventually to customers in the form of higher purchase prices. As production costs increase, manufacturers typically incur additional overhead. The MSP should be high enough to recover the full cost of the equipment (
HVAC equipment manufacturers typically pay for shipping during the first step in the distribution chain. Freight is not a manufacturing cost, but because it is a substantial cost incurred by the manufacturer, DOE is accounting for the shipping costs of CUACs/CUHPs and CWAFs separately from other non-production costs that comprise the manufacturer markup. To calculate the MSP at each efficiency level for CUACs/CUHPs and CWAFs, DOE multiplied the MPC at each efficiency level by the manufacturer markup and added shipping costs for equipment at the given efficiency level.
DOE calculated shipping costs at each efficiency level based on the average outer dimensions of equipment at the given efficiency and the use of a typical flat-bed, step-deck, or double-drop trailer to ship the equipment.
For CUACs and CUHPs, DOE's estimated shipping costs for each efficiency level are presented in Table IV–23 through Table IV–25. DOE notes that the shipping costs differ between CAV CUACs/CUHPs and SAV/VAV CUACs/CUHPs because of the design changes used in each type of unit to reach the higher efficiency levels. CAV CUACs/CUHPs generally rely on increasing the size of the heat exchangers to achieve higher efficiencies. As a result, CAV CUACs/CUHPs may require a larger overall cabinet size and thus a higher shipping cost compared to SAV or VAV CUACs/CUHPs at the same efficiency level, which generally rely on implementing airflow and compressor staging to achieve higher efficiencies that may not require an increase in cabinet size. DOE also notes that for the very large equipment class, the cabinet size increases associated with the higher efficiency levels did not change the number of units that fit on the trailer.
Gas-fired CWAF equipment is typically enclosed within a cabinet that also contains a CUAC.
At each step in the distribution channel, companies mark up the price of their equipment to cover business costs and profit margin. The markups analysis develops appropriate markups (
In both the CUAC/CUHP and CWAF NOPRs, DOE characterized three distribution channels to describe how the equipment passes from the manufacturer to the commercial consumer. The first of these channels, the replacement distribution channel, was characterized as follows:
The second distribution channel—new construction—was characterized as follows:
In the third distribution channel, which applies to both the replacement and new construction markets, the manufacturer sells the equipment directly to the customer through a national account:
In response to the CWAF NOPR, Lennox and Trane stated that the national account channel still requires a contractor to perform the installation, who has a markup on labor and materials as well. (CWAF: Lennox, Public Meeting Transcript, No. 17 at pp. 80–81; Trane, Public Meeting Transcript, No. 17 at pp. 82–83) In contrast, ACEEE stated that the markup refers to the value added by someone who takes ownership of the equipment. ACEEE questioned whether the installing contractor marks up the equipment itself. (CWAF: ACEEE, Public Meeting Transcript, No. 17 at pp. 83–84)
DOE notes that the markups analysis develops markups that are applied to the cost of purchasing only the equipment. Therefore, if the installing contractor only performs the installation, but does not purchase the equipment, the contractor is not part of the distribution channel. The installation, maintenance, and repair costs, including labor and material costs, are marked up separately using markups from RS Means data (see section IV.F).
DOE used the same distribution channels for the direct final rule analysis.
The manufacturer markup converts MPC to MSP. DOE developed an average manufacturer markup by examining the annual SEC 10–K reports filed by publicly-traded manufacturers primarily engaged in appliance manufacturing and whose combined product range includes CUACs/CUHPs and CWAFs.
For all parties except for the manufacturer, DOE developed separate markups for baseline products (baseline markups) and for the incremental cost of more-efficient products (incremental markups). Incremental markups are coefficients that relate the change in the MSP of higher-efficiency models to the change in the retailer sales price.
AHRI stated in its response to the CUAC/CUHP NOPR that DOE unreasonably utilized incremental, rather than average markups, which significantly understates the cost of equipment meeting the proposed standards. (CUAC: AHRI, No. 68 at p. 3) It stated that DOE's analysis does not comport with empirical observations of markups in the air conditioning or heating equipment industries. (CUAC: AHRI, No. 68 at p. 29) According to AHRI, in using this technique, DOE is stating what should be happening in the market, which does not accurately reflect what is actually occurring. AHRI attached a report from Shorey Consulting to its comment to help explain what it perceives as fundamental flaws in using incremental markups as opposed to average markups. AHRI stated that average markups should be used in the DOE analysis, as these markups are, in its view, representative of the real-world HVAC marketplace. (CUAC: AHRI, No. 68 at p. 35)
DOE is not aware of any representative empirical observations of markups in the air conditioning or heating equipment industries, except at an aggregate level. The Shorey Consulting Report describes a survey of HVAC distributor/wholesalers and HVAC contractors that Shorey Consulting conducted in November 2014 to determine the actual pricing practices of both groups. The report states that (1) both distributor/wholesalers and HVAC contractors manage to target constant margin percentages across their whole businesses and do not vary margins for individual products; and (2) these entities respond to manufacturer price increases (or rare decreases) by passing these price changes through with their traditional markups. (CUAC: AHRI, No. 68, markups attachment at pp. 17–20)
To investigate the claims in the Shorey Consulting Report, DOE held discussions with Construction Programs & Results, Inc. (“CPR”), a company with long experience in the HVAC contracting field. Laying out a scenario that resembles what it expects to occur after amended standards take effect, DOE asked CPR whether HVAC contractors would be able to retain the same markup that they currently use if equipment prices increase while other relevant costs (
The above characterization of contractor behavior is consistent with DOE's markup approach, which assumes that the markup changes for standards-compliant equipment that have a higher cost than non-compliant equipment. DOE also believes its approach is not entirely inconsistent with the information provided by the survey described in the Shorey Consulting Report. DOE does not mean to suggest that HVAC distributor/wholesalers and contractors will directly adjust their markups on equipment if the price they pay goes up as a result of appliance standards. Rather, the approach assumes that such adjustment will occur over a (relatively short) period of time as part of a business management process. This approach embodies the same perspective as the “preservation of per-unit operating profit markup scenario” used in the MIA (see section IV.J of this document).
In summary, DOE acknowledges that its approach to estimating distributor and contractor markup practices after amended standards become required is necessarily an approximation of real-world practices that are both complex and varying with business conditions. However, given the supportive remarks from CPR, and the lack of any evidence that standards facilitate a sustainable increase in profitability for distributors and contractors (as would be implied by AHRI's recommendation), DOE continues to maintain that its use of incremental markups is reasonable. DOE welcomes information that could support improvement in its methodology.
To develop markups for the parties involved in the distribution of CUAC/CUHP and CWAF equipment, DOE utilized several sources, including: (1) The Heating, Air-Conditioning & Refrigeration Distributors International (“HARDI”) 2012 Profit Report
Trane questioned how the overall markup of CWAFs compared to that of CUACs/CUHPs. (CWAF: Trane, No. 17 p. 89–90) DOE notes that the overall markups for gas-fired CWAFs and CUACs/CUHPs are almost identical to each other.
In addition to the markups, DOE derived State and local taxes from data provided by the Sales Tax Clearinghouse.
Chapter 6 of the direct final rule TSDs for CUACs/CUHPs and CWAFs provides details on DOE's development of markups.
The purpose of the energy use analysis is to determine the annual energy consumption of CUACs and CWAFs at different efficiencies in representative U.S. commercial buildings and (in the case of CWAFs) multi-family buildings, and to assess the energy savings potential of increased equipment efficiency. DOE did not analyze CUHP energy use because, for the reasons explained in section IV.C.4, the energy modeling in the engineering analysis was performed only for CUAC equipment.
The energy use analysis estimates the range of energy use of the equipment in the field (
Chapter 7 of the direct final rule TSDs provides details on DOE's energy use analysis for CUACs and CWAFs.
DOE developed energy consumption estimates only for the CUAC equipment classes that have electric resistance heating or no heating. As described in section IV.C.2.b, for equipment classes with all other types of heating, the incremental change in IEER for each efficiency level increases to maintain the same energy savings as was determined for the equipment classes with electric resistance heating or no heating within each equipment class capacity range (
In its analysis of the recommended TSL, DOE applied Efficiency Level 3 to the small and large “all other types of heating equipment” classes and Efficiency Level 2.5 to the very large “all other types of heating equipment” class. These were the IEER values recommended by the ASRAC Working Group, using an IEER differential of 0.2 compared to the “electric resistance heating or no heating equipment” classes. See supra, section IV.C.2.b. At Efficiency Level 3, based on an approach of maintaining a constant energy savings differential with the electric resistance heating or no heating equipment classes, the IEER differential should be 0.3 for both the small and large “all other types of heating equipment” classes. Since reducing the differential increases the efficiency of the equipment, additional energy savings are realized from reducing the IEER differential to 0.2 for the small and large “all other types of heating equipment” classes. The method for determinining the additional energy savings benefit is described in section IV.H.2.
The energy use analysis consists of two related parts. In the first part, DOE calculated energy savings for small, large, and very large CUACs at the considered efficiency levels based on modifications to the energy use simulations conducted for the 2004 ANOPR. These building simulation data are based on the 1995 CBECS. Because the simulation data reflect the building stock in 1995 that uses CUAC equipment, in the second part of the analysis, DOE developed a “generalized building sample” to represent the current installation conditions for CUACs. This part of DOE's analysis involved making adjustments to update the building simulation data to reflect the current building stock that uses CUAC equipment.
DOE's simulation database includes hourly profiles for more than 1,000 commercial buildings, which were based on building characteristics from the 1995 CBECS for the subset of buildings that uses CUAC equipment. Each building was assigned to a specific location along with a typical meteorological year (“TMY”) hourly weather file (referred to as “TMY2”) to represent local weather. The simulations capture variability in cooling loads due to factors such as building activity, schedule, occupancy, local weather, and shell characteristics.
For the NOPR, DOE modified the energy use simulations conducted for the 2004 ANOPR to improve the modeling of equipment performance. The modifications that DOE performed included changes to the ventilation rates and economizer usage assumptions, the default part-load performance curve, and the minimum saturated condensing temperature limit. A more detailed description of the simulation model modifications can be found in appendix 7A of the direct final rule TSD.
Neither fan operation during ventilation nor economizer usage are accounted for in the DOE test procedure and, therefore, do not impact the rated efficiency of a CUAC. Although ventilation rates and economizer usage do not directly affect the rated equipment performance, they do impact how often the equipment needs to operate, whether at full or part-load. The building simulations for the 2004 ANOPR used ventilation rates based on ASHRAE Standard 62–1999.
The issue of economizer usage was first discussed in the Working Group meeting on May 11, 2015. (ASRAC Public Meeting, No. 94 at pp. 82–135) One concern was whether the model used in the simulations properly modelled the performace of economizers. Another was the market share of units that use economizers. The third concern was the fraction of economizers that are operating properly. DOE presented a sensitivity analysis that showed that even if it assumed that all economizers are operating properly below an outdoor ambient temperature of 60 °F,
DOE used a two-step process to represent the performance of equipment at baseline and higher efficiency levels. For the NOPR, DOE first calculated the hourly cooling loads and hourly fan operation for each building from the compressor and fan energy consumption results that were generated from the modified building simulations based on equipment with an efficiency level of 11 EER. It was estimated that these simulated cooling loads had to be met by the CUACs equipment for every hour of the year that the equipment operates. Refer to chapter 7 of the CUAC/CUHP direct final rule TSD for more details.
The number of units serving a given building was based on the cooling load of the building and the cooling capacity of the representative CUAC unit at an outdoor ambient temperature of 95 °F—the specific ambient temperature at which manufacturers report a given unit's cooling capacity. In its informal meetings, the Working Group determined that the cooling capacity of the representative CUAC unit should instead be based on the 1-percent design temperature corresponding to the climate where the building is located. The 1-percent design temperature would generally be less than 95 °F, which means that the cooling capacity increases and the number of units needed to serve the building decreases. (ASRAC Public Meeting, No. 94 at pp. 80–82) As part of implementing the suggested approach, DOE allowed a fractional number of units, equivalent to system size increments of 2.5 tons, to be installed in a building as part of DOE's model. (ASRAC Public Meeting, No. 96 at p. 143)
In the second step, DOE coupled the hourly cooling loads and fan operation with equipment performance data, developed from laboratory and modeled IEER testing conducted according to AHRI Standard 340/360–2007, to generate the hourly energy consumption of baseline and more efficient CUAC equipment. DOE's use of the laboratory and modeled IEER test data allowed it to specifically address how capacity and control strategies vary with outdoor temperature and building load. The laboratory and modeled IEER test data were used to calculate the compressor efficiency (COP) and capacity at varying outdoor temperatures. The IEER rating test consists of measuring the net capacity, compressor power, condenser fan power, indoor fan power, and control power at three to five different rating conditions. The number of rated conditions the equipment is tested at is determined by the equipment's capabilities and control strategies. For the NOPR, the net capacity and compressor(s) power were determined as a linear function of outdoor temperature from the test results. If the indoor or outdoor fan was staged, its power consumption was also calculated as a linear function of outdoor temperature. The power for controls is a constant, but may vary by staging.
As described in section IV.C.3.a, DOE updated its approach by replacing the linear function described above with new correlations between outdoor temperature and the net capacity and compressor(s) power based on the design of the equipment. The considered designs included CAV, SAV, and VAV designs. Indoor and outdoor fan(s) power as well as control power were determined based on equipment staging. Based on informal Working Group meetings, the indoor fan power in heating mode assumes that the fan operates at its highest (
For the NOPR, the determination of fan power was based on ESP values found in AHRI Standard 340/360–2007, which are also used in the DOE test procedure. The Working Group discussed the appropriate ESP to use in the analysis and agreed that DOE should use higher ESPs than those found in the DOE test procedure to help better simulate actual field conditions. For the direct final rule, the values used (0.75 and 1.25 in.w.c.) correspond to the ESPs used in the modified building simulations of the cooling load. (ASRAC Public Meeting, No. 94 at pp. 80–82; ASRAC Public Meeting, No. 95 at pp. 28–31; ASRAC Public Meeting, No. 96 at pp. 145–164) In addition, as described earlier in section IV.C.3.a, DOE accounted for the fraction of the market at each efficiency level that would require the installation of a conversion curb. The determination of fan power accounted for an increase in the ESP (0.2 in.w.c.) associated with a conversion curb. (ASRAC Public Meeting, No. 95 at pp. 28–52; ASRAC Public Meeting, No. 98 at pp. 10–15) The new correlations between outdoor temperature and the net capacity and compressor(s) power were based on the new ESPs as well as the impact of a conversion curb.
The compressor(s) power and capacity of the equipment for each hour of the year was calculated based on the outdoor temperature for the simulated buildings. The cooling capacity was calculated such that it met the simulated building cooling load for each hour. For multi-stage equipment, the
Members of the ASRAC Working Group discussed the load factor in informal meetings and, after closely examining DOE's calculation methods, the group shared its finding that DOE misinterpreted the determination of the load factor and degradation coefficient. The equation that DOE was using to determine the compressor load factor did not properly account for the way loads are distributed on multi-stage equipment when more than one stage is operating. As a result, DOE corrected the calculation for compressor power to ensure that the load factor and degradation coefficient were based only on the highest stage of operation. In addition, the same load factor and degradation coefficient were used to determine the indoor fan power at its upper stage. (ASRAC Public Meeting, No. 94 at pp. 80–82)
The NOPR analysis assumed that when there are multiple units in a building, all units serve the same share of the total cooling load. The validity of this assumption was discussed with the Working Group, and DOE conducted a sensitivity analysis with alternative assumptions. Assuming that the units serve different shares of the load, the total annual energy use of the units changes by approximately 1 percent. (ASRAC Public Meeting, No. 96 at pp. 174–176) Given this outcome, the Working Group recommended that DOE maintain the assumption applied in the NOPR for the direct final rule analysis (ASRAC Public Meeting, No. 96 at pp. 177–182). DOE followed this recommendation and a description of the sensitivity analysis of equipment loading can be found in appendix 7B of the direct final rule TSD.
Each building simulation determines the indoor fan run-time for each hour of the year. Energy use was calculated separately for the compressor, condenser fan, indoor fan, and controls for each hour of the year for the simulated building. Compressor and condenser fan energy were summed to reflect cooling energy use. Indoor fan and control energy were combined into a single category to represent indoor fan energy use during all modes of operation.
A number of stakeholders stated that it is inappropriate to incorporate energy savings attributed to fan operation (for ventilation) during modes of operation other than cooling. (AHRI, No. 68 at p. 33; Carrier, No. 48 at p. 5; Lennox, No. 60 at p. 14) ASAP agreed with the inclusion of supply fan power in the energy use analysis. (ASAP, No. 69 at p. 5)
This issue was discussed in informal meetings by a number of members of the Working Group. The outcome of these discussions was presented at the May 11, 2015 meeting of the Working Group. (ASRAC Public Meeting, No. 94 at p. 82) The Working Group agreed to include fan operation energy during all modes of operation in the energy use calculations, so DOE maintained the approach used in the NOPR for the direct final rule.
The calculations provided the annual hourly cooling and fan energy use profiles for each building. The incremental energy savings between the baseline equipment and the equipment at higher efficiency levels was calculated for every hour for each of the 1,033 simulated buildings.
The building simulations were initially performed to analyze the energy use of small and large CUAC equipment, but the building cooling loads that were modeled are representative of CUACs irrespective of equipment cooling capacity. Therefore, DOE believes that its method of using these simulations provides a good representation of very large equipment performance as well as small and large equipment performance.
The NOPR analysis used a “generalized building sample” (GBS) to represent the installation conditions for the equipment covered in this rulemaking. The GBS was developed using data from the 2003 CBECS and from the Commercial Demand Module of the National Energy Modeling System version distributed with
Only floor space cooled by the covered equipment was included in the sample. Conceptually, the main difference between the GBS and the sample of specific commercial buildings compiled in CBECS is that the GBS aggregates all building floor space associated with a particular set of building characteristics into a single category. The set of characteristics that is used to define a category includes all building features that are expected to influence either (1) the cooling load and energy use or (2) the energy costs. As an outcome of the Working Group meetings, it was decided that the building ventilation system type should be included as a feature because it affects energy use. Thus, for the direct final rule, a category was added, defining whether the building ventilation system is CAV or VAV. The primary motivation for specifying the building ventilation system was twofold: (1) To only assign CAV designs to CAV buildings and (2) to prevent CAV designs from being assigned to VAV buildings. The first issue addressed current equipment selection practices,
The region in which the building is located affects both the cooling loads (through the weather) and the cost of electricity. The building activity affects building schedules and occupancy, which in turn influence the demand for cooling. The building size influences the cost of electricity, because larger facilities tend to have lower marginal prices. The building vintage may influence shell characteristics that can affect the cooling loads. The building ventilation system type dictates the type of equipment design assigned to a building.
As discussed with the Working Group, for the direct final rule, the amount of floor space allocated to each category for buildings built in or before 2012 was updated using the 2012 CBECS. The GBS was projected to 2019 (the year of the LCC analysis) using the
Load profiles for each category in the GBS were developed from the simulation data just described. For each equipment class, a subset of the 1,033 buildings was used to develop the cooling energy use profiles. The subset included all buildings with a capacity requirement equal to or greater than 90 percent of the capacity of the particular representative unit. For each GBS type, a weighted average energy use profile, along with energy savings from the considered efficiency levels, was compiled from the simulated building subset. The average was taken over all buildings in the subset that have the same region, building type, size, and vintage category as the GBS category (load profiles were assumed to be independent of the building ventilation system type). This average was weighted by the number of units required to meet each building's cooling load. For some of the GBS categories, no simulation data were available. In these cases, the weighted-average energy use profile for the same building type and a nearby region or vintage were used.
Updating the sample to 2019 required some additional adjustments to the energy use data. The 1,033 building simulations used TMY2 weather data that were based on 1961–1990 data. The TMY2 weather data files were updated to TMY3, which also incorporates 1991–2005 data, in 2008. A comparison of the two datasets showed that total annual cooling degree-days (“CDD”) increased by 5 percent at all locations used in this analysis. This is accounted for by increasing the energy use (for all efficiency levels) by 5 percent at all locations. The TMY3 dataset is representative of calendar year 2005. To account for changes in CDD (and energy use) between 2005 and 2019, DOE used the projected
Changes to building shell characteristics and internal loads can lead to a change in the energy required to meet a given cooling load. The National Energy Modeling System (“NEMS”) commercial demand module accounts for these trends by adjusting the cooling energy use with a factor that is a function of region and building activity. These factors assume 100 percent compliance with existing building codes. In the GBS, these same factors were used to adjust the cooling energy use for floor space constructed after 1999. To account for more realistic levels of code compliance, the factors were multiplied by 0.35.
For the Working Group's analysis, DOE removed buildings with a cooling load of under five tons from the original sample because these buildings would be more likely to be served by smaller equipment than the CUACs covered in this rulemaking. DOE also screened out buildings with more than four stories for the 7.5-ton equipment class, since such equipment would likely be too small to meet the cooling load. (ASRAC Public Meeting, No. 95 at pp. 27–28) For the 15-ton and 30-ton equipment classes, DOE removed buildings from consideration that have cooling loads low enough that multiple smaller units would likely be used instead of a single 15-ton or 30-ton unit. The Working Group did not object to these changes, and DOE incorporated them in the direct final rule analysis.
Commenting on the NOPR, Rheem stated that the 1,033 simulated samples have limited applicability when predicting energy consumption in commercial buildings. Rheem questioned whether unoccupied or underutilized buildings were included. (Rheem, No. 70 at p. 5) AHRI and Nordyne commented that a generalized building sample may not accurately represent the energy consumption of equipment in the commercial building stock. They stated that benchmarked buildings are more effective in estimating actual energy use. (AHRI, No. 68 at p. 44; Nordyne, No. 61 at p. 37) Goodman commented that the ASHRAE 90.1 committee utilized a broad spectrum of buildings from the existing building stock, not a generalized building sample, which Goodman contends is less accurate. (Goodman, No. 65 at pp. 17–18)
The GBS includes only buildings that use covered equipment and are occupied with the equipment in use. Benchmarking may provide better estimates of energy use in individual buildings, but DOE requires a representation of the entire building stock, for which the only available data source is CBECS combined with information from building simulations. The ASHRAE 90.1 committee evaluated the cost-effectiveness of ASHRAE 90.1–2010 for new construction based on simulations of six building types in five
For CWAFs, DOE calculated the energy use associated with providing space heating in a representative sample of U.S commercial buildings and multi-family residential buildings. The CWAF annual energy consumption includes the gas and oil fuel used for space heating and the auxiliary electrical use associated with the furnace electrical components.
DOE estimated the heating load of CWAFs in commercial buildings and multi-family buildings by developing building samples for each of the two equipment classes covered by the standards based on CBECS 2003 and 2009 Residential Energy Consumption Survey (RECS 2009).
Commenting on the NOPR, Goodman, Rheem, and AHRI stated that CBECS 2003 is outdated. (CWAF: Goodman, No. 23 at p. 4; Rheem, No. 23 at p. 6; AHRI, No. 26 at pp. 5–6) Goodman and AHRI further stated that DOE should use CBECS 2012 data when it is released in May 2015. (CWAF: Goodman, No. 23 at p. 4; AHRI, No. 26 at pp. 5–6) For the direct final rule, DOE used CBECS 2012 building sample characteristics to determine the CWAFs sample;
In addition, Goodman and AHRI stated that DOE should not consider RECS data as part of the CWAF rulemaking. (CWAF: Goodman, No. 23 at p. 4; AHRI, No. 26 at pp. 5–6) Goodman stated that CWAFs installed in residential homes comprise a negligible percentage of CWAF installations. (CWAF: Goodman, No. 23 at p. 4) DOE believes that including CWAFs used in residential buildings provides a more complete picture of CWAF energy use, and that RECS provides data that reasonably represent multi-family buildings that use CWAFs. Based on RECS 2009 data, DOE estimates that about two percent of commercial furnaces are used in multi-family residential applications.
To calculate CWAF energy consumption at each considered efficiency level, DOE determined the burner operating hours and equipment input capacity for each building. DOE used the equipment output capacity (determined using the TE rating) and the heating load in each building to determine the burner operating hours. DOE assigned the representative 250 kBtu/h input capacity for all CWAF efficiency levels.
Commenting on the CWAF NOPR, Rheem stated that it is unreasonable to assume that the burner and blower run-time will vary to the extent that DOE estimated (nearly 0-percent on-time to 100-percent on-time in any range of applications). Rheem stated that the unreasonable burner and blower on-time assumption inflates the energy consumption at the baseline efficiency level and proportionately inflates the savings from higher efficiency. (CWAF: Rheem, No. 26 at p. 6) On the other hand, GTI stated that on any given building there is significant diversity in unit run-times. (GTI, Public Meeting Transcript, No. 17 at p. 105) In response, DOE did not arbitrarily assume burner operating hours would apply to each CWAF sample. Rather, the burner operating hours are based on the annual heating energy use reported for sample buildings in CBECS 2003 and RECS 2009, as well as the assumed representative equipment input capacity. A wide range of burner operating hours is reflective of actual CWAF operation because some CWAFs in buildings with multiple furnaces may have limited use, while other CWAFs may serve very large building heating loads.
Trane stated that many local building codes require major building renovations to meet new building standards, affecting the energy efficiency of the building stock and in turn, the calculation of energy use. (CWAF: Trane, No. 27 at p. 8) Goodman made a similar comment. (CWAF: Goodman, No. 23 at p. 4)
DOE accounted for changes in building shell efficiency using the building shell efficiency index derived from the NEMS simulation performed for EIA's
For the NOPR, DOE assumed that all CWAFs use single-stage permanent split capacitor motors. Lennox suggested that the analysis should take into account the impact of variable frequency drives that are called for under ASHRAE 90.1. Lennox stated that variable frequency drives will adjust the speed of the fans and reduce the energy use in certain applications. (CWAF: Lennox, Public Meeting Transcript, No. 17 at p. 101)
For the direct final rule, DOE used the average fan power values from the CUAC analysis. These fan power values include variable frequency drives for the very large CUAC equipment class.
For condensing CWAFs, DOE's NOPR analysis accounted for the increased blower fan electricity use in the field in both heating and cooling mode due to the presence of the secondary heat exchanger. DOE also accounted for condensate line freeze protection or a condensate pump electricity use for a fraction of installations. Condensing CWAFs installed outdoors that are located in regions with an outdoor design temperature of ≤32 °F, which constitute roughly 90 percent of gas-fired CWAFs based on location data from CBECS 2003 and RECS 2009, were assumed to require condensate freeze protection. All oil-fired CWAFs are assumed to be installed indoors so condensate line freeze protection was assumed to not be needed.
Lennox stated that condensing CWAFs designs require secondary heat exchangers, which increase static pressure in the airstream and pressure drop within the heat exchanger. This additional resistance must be overcome
GTI, Goodman, AHRI, and Rheem stated that an 82-percent TE minimum standard will require a larger heat exchanger or other design changes that will restrict the airflow through the unit, which will increase the electricity use of the blower motor. (CWAF: GTI, Public Meeting Transcript, No. 17 at p. 104; Goodman, No. 23 at p. 2; Rheem, No. 25 at pp. 4–5; AHRI, No. 26 at p. 6) DOE concluded that the static pressure difference for 82-percent TE compared to baseline equipment is very small in terms of increased electricity use, because the increase in heat exchanger size in going from baseline equipment to 82-percent TE is not large enough to cause an increase in static pressure that would be relevant in terms of DOE's analysis. Therefore, DOE did not include higher electricity use for this efficiency level.
DOE conducted LCC and PBP analyses to evaluate the economic impacts on representative commercial consumers of potential energy conservation standards for CUACs
• The LCC (life-cycle cost) is the total commercial consumer expense of an equipment over the life of that equipment, consisting of total installed cost (manufacturer selling price, distribution chain markups, sales tax, and installation costs) plus operating costs (expenses for energy use, maintenance, and repair). To compute the operating costs, DOE discounts future operating costs to the time of purchase and sums them over the lifetime of the equipment.
• The PBP (payback period) is the estimated amount of time (in years) it takes commercial consumers to recover the increased purchase cost (including installation) of more-efficient equipment through lower operating costs. DOE calculates the PBP by dividing the change in purchase cost at higher efficiency levels by the change in annual operating cost for the year that amended or new standards are assumed to take effect.
For any given efficiency level, DOE measures the change in LCC relative to the LCC in the no-new-standards case, which reflects the estimated efficiency distribution of CUACs or CWAFs in the absence of new or amended energy conservation standards. In contrast, the PBP for a given efficiency level is measured relative to the baseline equipment.
For each considered efficiency level in each equipment class, DOE calculated the LCC and PBP for the nationally representative sets of commercial consumers described in the preceding section. For each sample building, DOE determined the energy consumption for the covered equipment and the appropriate energy prices, thereby capturing variability in energy consumption and energy prices.
Inputs to the calculation of total installed cost include the cost of the equipment—which includes MPCs, manufacturer, wholesaler, and contractor markups, and sales taxes—and installation costs. Inputs to the calculation of operating expenses include annual energy consumption, energy prices and price projections, repair and maintenance costs, equipment lifetimes, and discount rates. DOE created distributions of values for equipment lifetime, discount rates, and sales taxes to account for their uncertainty and variability.
The computer model DOE uses to calculate the LCC and PBP, which incorporates Crystal Ball
DOE calculates the LCC and PBP for commercial consumers as if each were to purchase new equipment in the expected year of compliance with amended standards. As discussed in section III.C, for the TSLs that represent the recommended standards, the compliance dates for CUACs are January 1, 2018, for the first tier of standards, and January 1, 2023 for the second tier of standards, For CWAFs, the compliance date for the new standards is January 1, 2023. For all other TSLs examined by DOE, the compliance January 1, 2019 compliance date would apply. For purposes of the LCC and PBP analysis, DOE used 2019 as the first full year of compliance for all TSLs.
For CUACs, the energy savings estimates for the efficiency levels associated with the equipment classes that have electric resistance heating or no heating were used in the LCC and PBP analysis to represent the equipment classes with all other types of heating.
Table IV–28 and Table IV–29 summarize the approach and data DOE used to derive inputs to the LCC and PBP calculations. The subsections that follow provide further discussion. Details of the spreadsheet models, and of all the inputs to the LCC and PBP analyses, are contained in chapter 8 of the direct final rule TSDs and their appendices.
To calculate commercial consumer equipment costs, DOE multiplied the MPCs developed in the engineering analysis by the markups described in section IV.D (along with sales taxes). DOE used different markups for baseline equipment and higher-efficiency equipment, because DOE applies an incremental markup to the increase in MSP associated with higher-efficiency equipment.
The equipment costs estimated in the engineering analysis refer to costs when the analysis was conducted. To project the costs in the compliance years, DOE developed cost trends based on historical trends.
For CUACs, DOE derived an inflation-adjusted index of the producer price index (PPI) for “unitary air-conditioners, except air source heat pumps” from 1978 to 2014.
Commenting on the CUAC/CUHP NOPR, ASAP encouraged DOE to attempt to capture price trends of technologies that can improve efficiency of air conditioners and heat pumps. In its view, the prices of technologies used in high-efficiency equipment are likely to decline much faster than the total price of the equipment. With respect to CUACs and CUHPs, ASAP expects the prices of brushless permanent magnet fan motors and variable-speed supply fans to decline faster than the total price of the equipment. ASAP recommended that DOE use a component-based price trend. (ASAP, No. 69 at p. 8)
DOE acknowledges that the price of more recently introduced components may decline faster than the total price of the equipment. However, it is not aware of data that would allow estimation of a trend for such components and ASAP provided none. Accordingly, DOE did not use a separate price trend for technologies used in high-efficiency equipment.
For CWAFs, DOE used the historic trend in the PPI for “Warm air furnaces”
Installation cost includes labor, overhead, and any miscellaneous materials and parts needed to install the equipment.
For the CUAC/CUHP NOPR, DOE derived installation costs for CUACs equipment from current RS Means data.
Commenting on the CUAC/CUHP NOPR, Carrier stated that RS Means should be used for installation cost based on unit tonnage, not weight or physical characteristics. (Carrier, No. 48 at p. 6) Trane and Goodman commented that RS Means underestimates installation costs. (Trane, No. 63 at p. 9; Goodman, No. 65 at p. 19) Rheem stated that the costs should include regional adjustments and demolition costs for removal of existing equipment. (Rheem, No. 70 at p. 5)
The Working Group debated the validity of DOE's method to vary installation costs in direct proportion to the physical weight of the equipment, and also discussed the cost of using a crane and whether the cost varies with efficiency. (ASRAC Public Meeting, No. 95 at pp. 103–126) DOE found that crane costs do not vary except past a threshold that is not relevant for this equipment. Because the Working Group did not find a compelling basis to recommend changes to DOE's method, DOE retained the approach used in the NOPR for the direct final rule (ASRAC Public Meeting, No. 96 at pp. 202–235). However, for a certain fraction of the market, DOE included additional costs for installing a conversion curb to accommodate equipment designs with large footprints. The cost was based on several factors, including equipment class, weight, and brand. As discussed by the Working Group, the fraction of the market that would require a conversion curb increases with efficiency. (ASRAC Public Meeting, No. 98 at pp. 17–20) The conversion curb costs for the small, large and very large CUAC equipment classes are $1,000, $1,750, and $4,000, respectively. (ASRAC Public Meeting, No. 96 at pp. 235–237) The installation costs used for the direct final rule include removal of existing equipment.
Carrier expressed concern that the variable-speed fan technology applied to supply fans at higher efficiency levels may have an additional cost increase to customers who are replacing equipment. It noted that many of these older building designs may need either the ductwork and/or the diffusers to be modified or replaced, as their designs may not be capable of managing the lower velocities that will occur with variable-speed supply fans. It added that if the ductwork/diffuser designs are not capable of these reduced velocities, then significant thermal discomfort can result and may actually cause increased equipment run-time due to poor air distribution within the occupied space. (Carrier, No. 48 at p. 2)
Based on the Working Group discussions, DOE included additional installed costs for adding controls (
For the CWAF NOPR, DOE used data from the 2013 RS Means Mechanical Cost Data
Commenting on the CWAF NOPR, AGA stated that if the revised standard mandates condensing technology, installing condensing furnaces in many existing buildings would require additional installation requirements and costs to properly address condensate disposal issues, including the freezing of the condensate for commercial furnaces in outdoor installations that are typical for commercial buildings. AGA stated that DOE has not fully considered these added installation costs in its analysis. (CWAF: AGA, No. 20 at p. 2)
In the NOPR (as well as for the direct final rule), DOE included the cost of condensate disposal in the installation cost for condensing CWAFs in indoor and outdoor installations. It included the cost of a condensate pipe, condensate pump, use of heat tape for outdoor installations, additional electrical outlet for heat tape and condensate pump, and condensate neutralizer, when applicable, based on the installation location of the CWAFs and building characteristics reported in CBECS 2003 and RECS 2009. The use of heat tape was determined based on weather data from NOAA. DOE notes that the adopted standards do not require condensing technology. The details of the condensate removal costs are provided in appendix 8D of the direct final rule TSD.
AHRI stated that the standards may increase the size of the unit, which would potentially require rework of the installation platform. (CWAF: AHRI, No. 17 at pp. 185–186) Similarly, Lennox stated that DOE should consider the cost involved in converting existing building stock to accept larger footprint products and the renovation needed to accept a larger roof curb or an adapter curb. (CWAF: Lennox, No. 22 at p. 10)
DOE assumed in the engineering analysis that the increase in condensing CWAF unit size from the use of larger heat exchangers would only impact the height, and no change in the cabinet size of higher efficiency non-condensing CWAFs would be needed. Furthermore, the CUAC analysis already accounted for additional costs for installing a
AHRI stated that although 82-percent TE CWAFs are not designed for condensing, there will be conditions that make condensate production a much greater concern than for indoor furnaces. (CWAF: AHRI, No. 26 at p. 2) Goodman stated that in field installations, the likelihood of condensate production in 82-percent TE weatherized CWAFs is much higher than in the lab, particularly in cold climates and at higher altitudes. Goodman stated that prolonged exposure to condensate in 82-percent TE CWAFs will corrode major components within the CWAFs and will lead to reliability issues. (CWAF: Goodman, No. 23 at pp. 2–3) Similarly, Trane stated that there are condensate issues for both 82-percent TE and condensing CWAFs that will need to be addressed by the installer. Trane stated that to have a redundant protection against roof membrane failure, builders or installers may need to upgrade the roof around the CWAFs, which was not taken into account in DOE's analysis. Trane added that 82-percent TE CWAFs still need heat tape to be energized continuously in the winter months for the condensate not to freeze, which DOE's analysis did not take into account. (CWAF: Trane, No. 27 at p. 7) Lennox stated that due to the introduction of condensate at 82-percent TE and above, many components will be susceptible to corrosion. (CWAF: Lennox, No. 22 at p. 10)
As discussed with the Working Group, for the direct final rule analysis, DOE did not apply a cost of a condensate withdrawal system or heat tape for non-condensing CWAFs (
Trane stated that calculating the total installed cost for the furnace separately from the entire rooftop unit (“RTU”) is not realistic, as replacing a failed CWAF would incur the full cost of the RTU even if the cooling side was still operating. (CWAF: Trane, Public Meeting Transcript, No. 17 at p. 128) Lennox agreed with this view. (CWAF: Lennox, Public Meeting Transcript, No. 17 at p. 130)
DOE's analyses for CWAFs and CUACs accounted for the likelihood that failure of either the CWAF or the CUAC would lead to replacement of the entire RTU. In calculating installation costs for CWAFs, DOE took into account only the additional costs that would be required for the furnace component, since all other installation components are already accounted for in the CUAC analysis.
The calculation of annual per-unit energy consumption at each considered efficiency level is described above in section IV.E.
DOE typically considers the potential for a rebound effect, which occurs when a piece of equipment that is made more efficient is used more intensively, such that the expected energy savings from the efficiency improvement may not fully materialize.
Commenting on the CUAC/CUHP NOPR, Rheem agreed that it is appropriate to not include a rebound effect. (CUAC: Rheem, No. 70 at p. 7) Commenting on the CWAF NOPR, Rheem stated generally that no rebound effect exists for a commercial furnace because the person who pays the energy bill is usually not the building occupant, but such an effect could exist where the person who pays the energy bill is also the building occupant. (CWAF: Rheem, No. 25 at p. 7) AHRI agreed that there is minimum rebound effect associated with a higher efficiency standard for commercial furnaces. (CWAF: AHRI, No. 26 at p. 6) In contrast, Trane commented that DOE had previously included a rebound effect for residential air conditioners and furnaces, and it noted that EIA includes a rebound effect for CWAFs in the AEO. It recommended that this effect be included in DOE's analyses until data are developed proving it is not warranted or until EIA drops it from the AEO. (CWAF: Trane, No. 27 at p. 7)
DOE conducted a literature review on the direct rebound effect in commercial buildings, and found very few studies, especially with regard to space heating and cooling. In a paper from 1993, Nadel describes several studies on takeback in the wake of utility lighting efficiency programs in the commercial and industrial sectors.
Regarding Trane's comment, DOE has confirmed that EIA includes a rebound effect for several end-uses in the commercial sector, including heating and cooling, as well as improvements in building shell efficiency in its AEO reports.
For the CUAC/CUHP NOPR, DOE used the electricity tariff data developed for the 2004 ANOPR, which were based on tariffs from a representative sample of electric utilities, to derive marginal and average electricity prices for each member of the GBS. The approach uses tariff data that have been processed into commercial building marginal and average electricity prices.
The CBECS 1992 and CBECS 1995 surveys provide monthly electricity consumption and demand for a large sample of buildings. DOE used these values to help develop usage patterns associated with various building types. Using these monthly values in conjunction with the tariff data, DOE calculated monthly electricity bills for each building. The average price of electricity is defined as the total electricity bill divided by total electricity consumption. Two marginal prices are defined, one for electricity demand (in $/kW) and one for electricity consumption (in $/kWh). These marginal prices are calculated by applying a five-percent decrement to the CBECS demand or consumption data and recalculating the electricity bill.
Using the prices derived from the above method, an average price and a marginal price were assigned to each building in the GBS. For each member of the GBS, these prices were calculated as the average, weighted by floor space and survey sample weight, of all buildings in the CBECS 1992 and 1995 data meeting the set of characteristics defining the generalized building (
The average summer or winter electricity price multiplied by the baseline summer or winter electricity consumption for equipment of a given capacity defines the baseline LCC. For each efficiency level, the operating cost savings are calculated by multiplying the electricity consumption savings (relative to the baseline) by the marginal consumption price and the electricity demand reduction by the marginal demand price. The consumer's electricity bill is only affected by the electricity demand reduction that is coincident with the building's monthly peak load. Air-conditioning loads are strongly, but not perfectly, peak-coincident. Divergences between the building peak and the air conditioning peak were accounted for by multiplying the electricity demand reduction by a random factor drawn from a triangular distribution centered at 0.9 +/− 0.1.
The tariff-based prices were updated to 2013 using the commercial electricity price index published in the
There were no comments on the NOPR methodology, and DOE retained the approach used for NOPR for the direct final rule.
For CWAFs, DOE derived average and marginal monthly energy prices for a number of geographic areas in the United States using the latest data from EIA (Form 861 data
AGA stated that DOE's methodology for calculating marginal natural gas prices results in higher prices than using individual natural gas utility tariffs, thus overstating the energy cost savings. (CWAF: AGA, No. 20 at p. 2) However, AGA did not provide data on natural gas utility tariffs that would enable DOE to modify its method. As a result, DOE could not evaluate whether AGA's claim is based on a sample that is representative of CWAFs users. Thus, DOE retained the approach used in the NOPR for the direct final rule.
For CUACs and CWAFs, to estimate energy prices in future years, DOE multiplied the recent energy prices by the forecast of annual change in national-average commercial energy prices in the Reference case from
For further discussion of energy prices, see chapter 8 of the direct final rule TSDs.
Maintenance costs are expenses associated with ensuring continued operation of the covered equipment over time. DOE developed maintenance costs for its analysis using 2013 RS Means Facilities Maintenance & Repair Cost Data.
In response to the CUAC/CUHP NOPR, AHRI and Nordyne commented that RS Means maintenance costs do not reflect the normal amounts incurred by customers, which is double RS Means. (AHRI, No. 68 at p. 44; Nordyne, No. 61
The Working Group discussed maintenence costs and generally agreed with DOE's approach. (ASRAC Public Meeting, No. 95 at pp. 139–143). Accordingly, DOE retained this approach for the direct final rule.
For the CWAF NOPR, DOE included increased maintenance costs for condensing equipment. For condensing gas-fired commercial warm air furnaces, DOE added labor and material costs to account for checking the condensate withdrawal system, including: Inspecting, cleaning, and flushing the condensate trap and drain tubes; inspecting the grounding and power connection of heat tape; checking condensate neutralizer; and checking condensate pump for corrosion and proper operation. For condensing oil-fired commercial warm air furnaces, DOE added additional maintenance for installations in non-low-sulfur regions to account for extra cleaning of the heat exchanger for condensing designs, as well as checking of the condensate withdrawal system. DOE did not receive any comments on this issue, and retained the same approach for the direct final rule.
Repair costs are expenses associated with repairing or replacing components of the covered equipment that have failed.
For the CUAC/CUHP NOPR, DOE assumed that any routine or minor repairs are included in the maintenance costs. As a result, repair costs were not explicitly modeled in the LCC and PBP analysis. Instead, DOE incorporated a one-time cost for major repair (compressor replacement) as a primary input to the repair/replace consumer choice model in the shipments analysis, which models the decision between repairing a broken unit and replacing it.
DOE proposed to the Working Group to include compressor repairs in the LCC and PBP analysis because such repair work would occur regardless of whether new standards are set (ASRAC Public Meeting, No. 96 at pp. 247–248) The Working Group agreed with this proposal, and, because the Working Group estimated that compressor repairs occur later in a CUAC's life, suggested that this type of repair be assumed to take place in the 13th year. For the direct final rule, compressor repair costs are based on material costs from Grainger (a provider of commercial and industrial supplies) and labor costs from RS Means, and are assumed to scale with equipment price. The cost is applied to 20 percent of consumers, representing the portion of the population that chooses to repair rather than replace in the no-standards case. DOE also included non-compressor repairs, conducted in the 7th year, for all consumers (ASRAC Public Meeting, No. 96 at pp. 247–248).
For CWAFs, DOE developed repair costs for its analysis using 2013 RS Means Facilities Maintenance & Repair Cost Data.
Lennox stated that due to the introduction of condensate at a TE level of 82-percent and above, many components will be susceptible to corrosion, thus requiring components to be replaced more frequently. (CWAF: Lennox, No. 22 at p. 10) For the direct final rule, DOE assumed that all 82-percent TE CWAFs use stainless steel heat exchangers to resist corrosion; therefore, DOE did not assume any difference in repair frequency for 82-percent TE CWAFs.
See chapter 8 of the direct final rule TSDs for more details on maintenance and repair costs.
Equipment lifetime is the age at which a unit of covered equipment is retired from service. For the LCC and PBP analysis, DOE develops a distribution of lifetimes to reflect variability in equipment lifetimes in the field.
For the CUAC/CUHP NOPR, DOE used lifetime distributions based on calibration of the shipments model (see section IV.G.1). The mean lifetimes were 18.4 years for CUACs and 15.2 years for CUHPs. AHRI and Nordyne commented that the equipment lifetime assumptions are incorrect and that a lifetime range of 12–15 years is more appropriate for equipment in this rulemaking. (AHRI, No. 68 at p. 45; Nordyne, No. 61 at p. 35) Goodman commented that the lifetimes should be different for each equipment class. (Goodman, No. 65 at pp. 20–21)
The Working Group accepted DOE's approach of using the shipments model to determine equipment lifetime, along with extension of the equipment lifetime due to inclusion of compressor repairs. The group asked DOE to use more recent shipments data. AHRI provided recent data, but it was not representative of entire industry shipments, so DOE continued to use the shipments data from the NOPR analysis (ASRAC Public Meeting, No. 98 at pp. 125–133). Also, as discussed later in section IV.F.8.a, DOE also incorporated AHRI's more recent data into its analysis. For the direct final rule, the LCC analysis used lifetime distributions based on the revised shipments model (see section IV.G.1), which makes distinct estimates for each of the CUAC equipment classes.
In addressing gas-fired CWAFs, DOE's CWAF NOPR used the same lifetime probability distribution that was developed in the NOPR analysis for small, large, and very large air-cooled commercial package air conditioning and heating equipment.
Commenting on the CWAF NOPR, AHRI stated that the analysis overestimates the average lifetime of a commercial furnace, and that the proposed standard of 82-percent TE will reduce the life of the equipment. (CWAF: AHRI, No. 26 at pp. 2, 6)
As discussed with the Working Group, for the direct final rule analysis, DOE based the lifetime estimate for both gas-fired and oil-fired CWAFs on the revised CUAC lifetime. (ASRAC Public Meeting, No. 43 at p. 8) DOE does not believe a standard at 82-percent TE would reduce the life of equipment that use stainless steel heat exchangers for installations where such material would prevent corrosion issues. Therefore, as described in section IV.C.3.b, DOE assumed in its analysis that all 82-percent TE CWAFs would use stainless steel heat exchangers. In any case, DOE
The discount rate is the rate at which future expenditures or savings are discounted to estimate their present value. The weighted average cost of capital is commonly used to estimate the present value of cash flows to be derived from a typical company project or investment. Most companies use both debt and equity capital to fund investments, so their cost of capital is the weighted average of the cost to the firm of equity and debt financing. DOE estimated the cost of equity using the capital asset pricing model, which assumes that the cost of equity for a particular company is proportional to the systematic risk faced by that company.
The primary source of data for this analysis was Damodaran Online, a widely used source of information about company debt and equity financing for most types of firms.
To accurately estimate the share of commercial consumers that would be affected by a potential energy conservation standard at a particular efficiency level, DOE's LCC analysis considered the distribution (market shares) of equipment efficiencies projected for the compliance years in the no-new-standards case (
For the CUAC/CUHP NOPR, DOE used a consumer choice model to estimate efficiency market shares in the expected compliance year. The consumer choice model considers customer sensitivity to total installation cost and annual operating cost. DOE used efficiency market share data for 1999–2001, based on model availability data from the AHRI-certified directory, to develop the parameters of the consumer choice model in the shipments analysis. Using these parameters, the model estimated the shipments at each IEER level based on the installed cost and operating cost at each efficiency level.
During the Working Group meetings, DOE requested data that might improve the efficiency distribution in the no-new-standards case. AHRI provided recent market share data by efficiency based on shipments. Using these data in preparing the analysis for the direct final rule, DOE extended the AHRI data to 2019 to estimate efficiency market shares for each equipment class in the no-new-standards case.
As discussed in section IV.E.1, DOE assigned CAV designs to CAV buildings and SAV and VAV designs to VAV buildings. Therefore, DOE needed to develop separate efficiency distributions for CAV, SAV, and VAV designs for each equipment class. AHRI provided market share data based on shipments of each design, which DOE used for the direct final rule analysis. (ASRAC Public Meeting, No. 98 at pp. 22–37). These data were incorporated into the NIA spreadsheet model that DOE developed. The distributions used are presented in chapter 8 of the direct final rule TSD.
For the CWAF NOPR, DOE developed the current distribution of equipment shipments by efficiency level for the CWAF equipment classes for 2013 based on the number of models at different efficiency levels from AHRI's Certification Directory for Commercial Furnaces.
Commenting on the NOPR, Lennox stated that its CWAFs are expected to remain at 80-percent TE for the foreseeable future, as there is little market demand for higher-efficiency furnaces in the commercial sector. (CWAF: Lennox, No. 22 at pp. 10–11) As discussed with the Working Group, to estimate the efficiency distribution of CWAFs for the direct final rule, DOE updated its analysis using the most recent AHRI Certification Directory for Commercial Furnaces.
See chapter 8 of the direct final rule TSDs for further information on the derivation of the efficiency distributions.
The payback period is the amount of time it takes the consumer to recover the additional installed cost of more-efficient equipment, compared to baseline equipment, through energy cost savings. Payback periods are expressed in years. Payback periods that exceed the life of the equipment mean that the increased total installed cost is not recovered in reduced operating expenses.
The inputs to the PBP calculation for each efficiency level are the change in total installed cost of the equipment and the change in the first-year annual operating expenditures relative to the baseline efficiency level. The PBP calculation uses the same inputs as the LCC analysis, except that discount rates are not needed.
As noted above, EPCA establishes a rebuttable presumption that a standard is economically justified if the Secretary finds that the additional cost to the consumer of purchasing equipment complying with an energy conservation standard level will be less than three times the value of the first year's energy savings resulting from the standard, as
DOE uses projections of annual equipment shipments to calculate the national impacts of potential amended energy conservation standards on energy use, NPV, and future manufacturer cash flows.
The shipments model for CUACs and CUHPs uses a stock accounting approach, tracking the number of units and vintage for each equipment class. The vintage (or age) distribution of in-service equipment is a key input to calculations of both the NES and NPV, because equipment efficiency varies with vintage, and this in turn affects the energy use and operating costs.
The primary inputs to the shipments model are time series of total commercial floor space, market share by equipment class, new construction market saturations, and equipment lifetimes. Floor space estimates are based on historic CBECS surveys and projections from
The shipments model includes three market segments: (1) New commercial buildings acquiring new equipment, (2) existing buildings acquiring new equipment for the first time, and (3) existing buildings replacing broken equipment.
DOE estimated new equipment shipments to new buildings by multiplying the market saturation values by the total new floor space in each year. DOE estimated new shipments to existing buildings as the total floor space multiplied by the change in saturation with time. This market segment is approximately zero for the analysis period, as saturations are no longer changing significantly.
Replacement shipments are those that go into existing buildings to replace broken equipment. The number of units that break each year is equal to the total equipment stock minus the number of units that survive. The number of units that survive is calculated by multiplying the equipment stock as a function of age by the survival function. The survival function is the integral of the lifetime function used in the LCC. If all units that break are replaced, then the number of replacement shipments in each year is equal to the total number of broken units. However, in general, some fraction of broken units will be replaced, which reduces the number of replacement shipments.
For CUACs and CUHPs, the end of lifetime is generally associated with compressor failure. Installing a new compressor is costly, so customers typically replace the entire unit rather than simply replace the compressor. If standards significantly increase the cost of new equipment, however, one would expect that the repair option would become more attractive.
For the CUAC/CUHP NOPR, DOE modeled the repair rates for the small and large CUACs and CUHP equipment classes using a consumer choice model.
ASAP commented that DOE's model overestimated the impact of higher efficiency levels on shipments. It stated that there are only 3 years of data on market share and cost (which are 15 years old), and a customer's repair/replace decision is more complex than the decision to purchase a baseline or higher efficiency unit. ASAP commented that the DOE model fails to capture a number of complex factors affecting purchase and repair decisions, such as the fact that some manufacturers offer leases that include no upfront costs. It noted that many units use R–22 as a refrigerant and since it is being phased out those units will be more expensive to service and repair. (CUAC: ASAP, No. 69 at pp. 6–7) The California IOUs, through PG&E, stated that the decision model should include factors such as the need for immediate resumption of operation to avoid placing too much weight on the first cost of more efficient equipment. (CUAC: California IOUs, No. 67 at p. 6) Rheem commented that the repair/replace decision depends on the commercial use of the building, how extensive the repair is, whether a warranty covers the repair, the cost of removal, purchase cost and installation cost. (CUAC: Rheem, No. 70 at p. 7)
For the direct final rule, DOE examined a variety of potential modifications to the modeling approach used for the NOPR. The primary difficulty is that there are multiple parameters that need to be simultaneously estimated, including the actual repair costs, consumer price sensitivity, the fraction of consumers whose repair/replace decision is not driven solely by price, and the mean lifetime of a repaired unit. As very little additional data were available for the direct final rule, DOE adopted a simpler and more transparent modeling approach.
The simplified approach still uses logistic regression to estimate the rate of purchase of new equipment by owners of broken equipment, but does not attempt to explicitly model repair costs.
For the CUAC/CUHP NOPR, DOE assumed that if the unit is repaired (
Carrier commented that while replacing a failed part with a new part returns a unit to service, it does not believe that the lifetime is reset after a repair, and therefore does not expect repaired units to last as long as new equipment. (Carrier, No. 48 at p. 7) The California IOUs, through PG&E, made a similar comment. (California IOUs, No. 67 at p. 6) Trane commented that assuming a compressor repair results in a new lifetime for the equipment is flawed—in its view, the lifetime is more likely cut in half. (Trane, No. 63 at p. 10) ASAP does not believe that a compressor repair will extend the life of the equipment by one whole lifetime, as there are also other components that could fail before the new compressor fails. (ASAP, No. 69 at p. 6)
Based on stakeholder comments, for the direct final rule, DOE assumed that the mean lifetime for repaired equipment is equal to one half the mean lifetime of new equipment.
The approach described in the preceding section provides total shipments in each equipment class for each year. To estimate the market shares of the considered efficiency levels in future shipments, DOE developed a customer choice model. The model was calibrated by estimating values for two parameters, representing customer sensitivity to total installation cost and annual operating cost.
To estimate values for the parameters, for the direct final rule the calibration method was changed to better fit the historic market shares. DOE used a maximum log likelihood approach that optimized the customer choice model fit to historical market shares at each efficiency level for the small and large CUAC equipment classes. To calibrate the model, DOE used IEER market share data for each CUAC equipment class provided by AHRI for the Working Group. These market shares are for 2011 and 2014. Starting in 2015, application of the parameters, along with data on the installed cost and operating cost at each efficiency level for each year in the analysis period, determines the market shares of each efficiency level in each year. Different sets of parameters were used to estimate market shares for CUACs and CUHP equipment classes. The details of the data and the method used can be found in chapter 9 of the CUAC/CUHP direct final rule TSD.
For the CWAF NOPR, DOE developed shipment projections based on historical data and an analysis of key market drivers for each product. Historical shipments data were used to build up an equipment stock and also to calibrate the shipments model. Historical shipments data for CWAF equipment are very limited. DOE used 1994 shipments data from AHRI (previously the Gas Appliance Manufacturers Association, or “GAMA”) that were presented in a report from PNNL,
For the NOPR, since shipments data for oil-fired CWAFs were not publicly available, DOE used the ratio of oil-fired versus gas-fired residential furnace shipments from AHRI
Commenting on the CWAF NOPR, Lennox stated that most weatherized CWAFs are integrated into rooftop equipment that also provide cooling, so it is not logical that the CWAF NOPR has much different shipment projections than the projections for CUACs and CUHPs. (CWAF: Lennox, No. 22 at p. 11) As discussed with the Working Group, for the direct final rule, DOE modified the projection for CWAF shipments, with the results indicating that the magnitude is similar to the projected shipments for CUACs and CUHPs. (ASRAC Public Meeting, No. 41 at p. 28) Chapter 9 of the direct final rule TSD described the modifications.
For the CWAF NOPR, for cases with potential CWAFs standards, DOE considered whether the increase in price would cause some commercial consumers to choose to repair rather than replace their CWAF equipment. The shipments model used a relative price elasticity to account for the combined effects of changes in purchase price and annual operating cost on the purchase versus repair decision. Because data for commercial consumers were lacking, DOE used a relative price elasticity that has been derived for residential consumers.
Commenting on the CWAF NOPR, AHRI stated that DOE's reliance on residential purchases to establish commercial product price elasticity and on car purchases to extend the elasticity over time is not appropriate. (CWAF: AHRI, No. 26 at p. 5) Lennox stated that the CUAC/CUHP NOPR projects a severe decline in shipments with amended standards, so CWAF shipment impacts should reflect a similar decline, since the two product categories are usually combined in one piece of
AHRI stated that the proposed standard of 82 percent TE for gas-fired CWAFs may cause some equipment switching because of installation complications resulting from larger units and modifications to handle condensate disposal. (CWAF: AHRI, No. 26 at p. 6) Trane argued that some businesses will elect to switch to less expensive electric heating options in response to a standard, and it is concerned that DOE has not modeled the possibility of fuel switching. While the effects of fuel switching would be greatest at the condensing level, Trane stated that there could be fuel switching at the lower levels as well. (CWAF: Trane, No. 27 at pp. 7–8) AGA stated that DOE did not account for fuel/product switching that will occur as a result of the proposed standard if manufacturers eliminate the manufacturing of non-condensing commercial furnaces because the 82 percent TE minimum level is no longer practical from a safety and durability point of view. (CWAF: AGA, No. 20 at p. 2)
DOE believes that a standard at 82 percent TE would cause minimal switching to electricity because of the very high operating costs of an electric furnace and significant additional electrical installation costs. DOE did not analyze such switching for the direct final rule because it is adopting a standard at 81 percent TE, a level where consumers would have no incentive to switch away from gas.
The details of the shipments analysis can be found in chapter 9 of the direct final rule TSDs.
The NIA assesses the national energy savings (“NES”) and the national net present value (“NPV”) from a national perspective of total consumer costs and savings that would be expected to result from new or amended standards at specific efficiency levels.
DOE evaluates the impacts of new and amended standards by comparing a case without such standards with standards-case projections. The no-new-standards case characterizes energy use and consumer costs for each equipment class in the absence of new or amended energy conservation standards. For this projection, DOE considers historical trends in efficiency and various forces that are likely to affect the mix of efficiencies over time. DOE compares the no-new-standards case with projections characterizing the market for each equipment class if DOE adopted new or amended standards at specific energy efficiency levels (
DOE uses a spreadsheet model to calculate the energy savings and the national consumer costs and savings from each TSL. Interested parties can review DOE's analyses by changing various input quantities within the spreadsheet. The NIA spreadsheet model uses typical values (as opposed to probability distributions) as inputs.
Table IV–30 summarizes the inputs and methods DOE used for the NIA analyses for the direct final rule. Discussion of these inputs and methods follows the table. See chapter 10 of the direct final rule TSDs for further details.
A key component of the NIA is the trend in energy efficiency projected for the no-new-standards case. Section IV.F.8 describes how DOE developed an energy efficiency distribution for the no-new-standards case for each of the considered equipment classes for the first year of the forecast period.
For CUACs and CUHPs, DOE used the consumer choice model described in section IV.G to estimate efficiency market shares in each year of the shipments projection period. For each standards case, the efficiency levels that are below the standard are removed from the possible choices available to customers. The no-new-standards case shows a slight increasing trend in efficiency for small CUACs and CUHPs, but the shares were fairly constant for large and very large CUACs and CUHPs.
For the CWAF NOPR, DOE assumed no change in efficiency for non-condensing CWAFs over the shipments projection period in the no-new-standards case. For condensing gas-fired CWAFs, however, it estimated that market interest in efficiency would lead to a modest growth in market share.
Trane stated that the equipment minimum energy efficiency requirements (including CWAFs) in ASHRAE 90.1 have been updated a number of times and there is every reason to believe they will continue to be updated without further DOE equipment standards (
For the CWAFs standards cases, DOE used a “roll-up” scenario to establish the shipment-weighted efficiency for the compliance year. In this scenario, the market of products in the no-new-standards case that do not meet the standard under consideration would “roll up” to meet the new standard level, and the market share of products above the standard would remain unchanged. After the compliance year, DOE assumed no change in efficiency over time.
The projections of efficiency trends for CUACs/CUHPs and CWAFs are further described in chapter 10 of the direct final rule TSDs.
The NES analysis involves a comparison of national energy consumption of the considered products in each potential standards case (TSL) with consumption in the case without amended energy conservation standards. DOE calculated the national energy consumption by multiplying the number of units (stock) of each product (by vintage or age) by the unit energy consumption (also by vintage). Annual NES is based on the difference in national energy consumption for the no-new-standards case and for each standard case. Part of the reduction in energy consumption in a standards case may be due to decreasing shipments resulting from customers choosing to repair than replace broken equipment. Therefore, the NES calculation includes the estimated energy use of units that are repaired rather than replaced.
For CUACs, the per-unit annual site energy savings for each considered efficiency level come from the energy use analysis, which estimated energy consumption for the compliance year. For later years, DOE adjusted the per-unit annual site energy savings to account for changes in climate (cooling degree-days) and building shell efficiency based on projections in
For CUHPs, DOE did not conduct an energy use analysis. Because the cooling-side performance of CUHPs is nearly identical to that of CUACs, DOE used the energy consumption estimates developed for CUACs to characterize the cooling-side performance of CUHPs of the same size. To characterize the heating-side performance, DOE analyzed CBECS 2003 data to develop a national-average annual energy use per square foot for buildings that use CUHPs. DOE assumed that the average COP of the CUHPs was 2.9.
DOE converted site electricity consumption and savings to primary energy (
As noted in section IV.C.2.b and section IV.E.1, for Efficiency Level 3 for the small and large “all other types of heating equipment” classes and Efficiency Level 2.5 for the very large “all other types of heating equipment” class, the IEER values included in the ASRAC Working Group recommendations (discussed in section III.B.2) were based on an IEER differential of 0.2 compared to the “electric resistance heating or no heating” equipment classes. At Efficiency Level 3, based on an approach of maintaining a constant energy savings differential with the “electric resistance heating or no heating” equipment classes, the IEER
For the CUHP equipment classes, DOE used the same “top-down” method for determining the additional energy savings realized from reducing the IEER differentials to the IEER values included in the ASRAC Working Group recommendations, as discussed in section III.B.2. As described in Section IV.C.2.b, the ASRAC Working Group recommendation included IEER values for the CUHP equipment classes based on IEER diffentials of 0.7 for all three CUHP equipment classes with electric resistance or no heating. At Efficiency Level 3, based on an approach of maintaining a constant energy savings differential with the CUAC equipment classes including electric resistance heating or no heating, the IEER differential would be 0.8, 0.9, and 1.1 for the small, large, and very large CUHP equipment classes with electric resistance or no heating, respectively. As a result, additional energy savings are realized from reducing the IEER differential to 0.7 for the CUHP equipment classes.
A more detailed description of the method and results for determining the additional energy associated with reducing the IEER differentials for both the CUAC equipment classes with all other types of heating and the CUHP equipment classes with electric resistance or no heating is given in appendix 10D of the direct final rule TSD.
In 2011, in response to the recommendations of a committee on “Point-of-Use and Full-Fuel-Cycle Measurement Approaches to Energy Efficiency Standards” appointed by the National Academy of Sciences, DOE announced its intention to use full-fuel-cycle (“FFC”) measures of energy use and GHGs and other emissions in the national impact analyses and emissions analyses included in future energy conservation standards rulemakings. 76 FR 51281 (August 18, 2011). After evaluating the approaches discussed in the August 18, 2011 notice, DOE published a statement of amended policy in which DOE explained its determination that EIA's NEMS is the most appropriate tool for its FFC analysis and its intention to use NEMS for that purpose. 77 FR 49701 (August 17, 2012). NEMS is a public domain, multi-sector, partial equilibrium model of the U.S. energy sector
The inputs for determining the NPV of the total costs and benefits experienced by consumers are: (1) Total annual installed cost; (2) total annual savings in operating costs; and (3) a discount factor to calculate the present value of costs and savings. DOE calculates net savings in each year as the difference between the no-new-standards case and each standards case in terms of total savings in operating costs versus total increases in installed costs. DOE calculates operating cost savings over the lifetime of the equipment shipped during the forecast period.
The total installed cost includes both the equipment price and the installation cost. DOE calculated equipment prices by efficiency level using manufacturer selling prices and weighted-average overall markup values (weights based on shares of the distribution channels used). Installation costs come from the LCC and PBP analysis.
For CUHPs, to estimate the cost at higher efficiency levels, DOE applied the same incremental equipment costs that were developed for the comparable CUAC efficiency levels for each equipment class).
As noted in section IV.F.1, DOE assumed no change in CUACs and CUHPs prices over the analysis period. For CWAFs, DOE derived a trend based on the PPI for “Warm air furnaces,” which shows a small rate of annual price decline. DOE applied the same trends to project prices for each CWAF equipment class at each considered efficiency level. DOE's projection of product prices is described in appendix 10C of the direct final rule TSDs.
To evaluate the effect of uncertainty regarding the price trend estimates, DOE investigated the impact of different equipment price trends on the consumer NPV for the considered TSLs. For CUACs and CUHPs, DOE conducted sensitivity analyses using one trend in which prices decline, and one in which prices rise. For CWAFs, DOE considered a high price decline case and a low price decline. The derivation of these price trends and the results of the sensitivity cases are described in appendix 10C of the direct final rule TSDs.
The NPV calculation includes the repair cost for units that are repaired rather than replaced.
Operating cost savings are estimated by comparing total energy expenditures and repair and maintenance costs for the base case and the standards cases. DOE calculates annual energy expenditures from annual energy consumption by incorporating forecasted energy prices. To calculate future energy prices, DOE applied the projected trend in national-average commercial energy prices from the
The aggregate difference each year between operating cost savings and increased equipment expenditures is the net savings or net costs. In calculating the NPV, DOE multiplies the net savings in future years by a discount factor to determine their present value. DOE estimates the NPV using both a 3-percent and a 7-percent real discount rate, in accordance with guidance provided by the Office of Management and Budget (“OMB”) to Federal agencies on the development of regulatory analysis.
In analyzing the potential impact of new or amended standards on commercial consumers, DOE evaluates the impact on identifiable subgroups of consumers that may be disproportionately affected by a new or amended national standard. DOE evaluates impacts on particular subgroups of consumers by analyzing the LCC impacts and PBP for those particular consumers from alternative standard levels. For CUACs/CUHPs and CWAFs, DOE evaluated impacts on a small business subgroup using the LCC spreadsheet model. Chapter 11 in the direct final rule TSDs describes the consumer subgroup analysis.
DOE analyzed manufacturer impacts (
DOE conducted the MIA for this rulemaking in three phases. In Phase 1 of the MIA, DOE prepared profiles of the CUAC/CUHP and CWAF manufacturers that included top-down analyses that DOE used to derive preliminary financial inputs for the GRIM (
In Phase 2 of the MIA, DOE prepared industry cash-flow analyses to quantify the potential impacts of an amended energy conservation standard. In general, new or more-stringent energy conservation standards can affect manufacturer cash flows in three distinct ways: (1) Create a need for increased investment; (2) raise production costs per unit; and (3) alter revenue due to higher per-unit prices and possible changes in sales volumes.
In Phase 3 of the MIA, DOE conducted structured, detailed interviews with a representative cross-section of manufacturers. During these interviews, DOE discussed engineering, manufacturing, procurement, and financial topics to validate assumptions used in the GRIM and to identify key issues or concerns. See sections IV.J.2.c in 79 FR 58948 (CUAC/CUHP NOPR) and 80 FR 6181 (CWAF NOPR) for a description of the key issues manufacturers raised during their respective interviews.
Additionally, in Phase 3, DOE evaluated subgroups of manufacturers that may be disproportionately impacted by new standards or that may not be accurately represented by the average cost assumptions used to develop the industry cash-flow analysis. For example, small manufacturers, niche players, or manufacturers exhibiting a cost structure that largely differs from the industry average could be more negatively affected. DOE identified one subgroup (
DOE applied the small business size standards published by the Small Business Administration (“SBA”) to determine whether a company is considered a small business. 65 FR 30836, 30848 (May 15, 2000), as amended by 65 FR 53533, 53544 (September 5, 2000) and codified at 13 CFR part 121. To be categorized as a small business under North American Industry Classification System (“NAICS”) code 333415, “Air-Conditioning and Warm Air Heating Equipment and Commercial and Industrial Refrigeration Equipment Manufacturing,” a CUAC/CUHP or CWAF manufacturer and its affiliates may employ a maximum of 750 employees. The 750-employee threshold includes all employees in a business's parent company and subsidiaries. Based on this classification, DOE identified three CUAC/CUHP manufacturers that qualify as small businesses under the SBA definition, and two CWAF manufacturers that qualify as small businesses. CUAC/CUHP and CWAF small manufacturer subgroups are discussed in sections V.B.2.d and VI.B of this document.
DOE uses the GRIM to quantify the changes in cash flow due to new standards that result in a higher or lower industry value. The GRIM analysis uses a standard annual, discounted cash-flow methodology that incorporates manufacturer costs, markups, shipments, and industry financial information as inputs. The GRIM models changes in costs, distribution of shipments, investments, and manufacturer margins that could result from an amended energy conservation standard. The GRIM spreadsheet uses the inputs to arrive at a series of annual cash flows, beginning in 2015 (the base year of the analysis) and continuing to 2048. DOE calculated INPVs by summing the stream of annual discounted cash flows during this period. For CUAC/CUHP manufacturers, DOE used a real discount rate of 6.2 percent, which was derived from industry financials and then modified according to feedback received during manufacturer interviews. Similarly, using this approach, DOE estimated a real discount rate of 8.9 percent for CWAF manufacturers. The variance in discount rate is due to a different mix of manufacturers, as not all CUAC/CUHP manufacturers also produce CWAFs (and vice-versa), and resulting variances in manufacturer feedback.
The GRIM calculates cash flows using standard accounting principles and compares changes in INPV between a no-new-standards case and each standards case. The difference in INPV between the no-new-standards case and a standards case represents the financial impact of the amended energy conservation standard on manufacturers. As discussed previously, DOE collected this information on the critical GRIM inputs from a number of sources, including publicly-available data and interviews with a number of manufacturers. The GRIM results are shown in section V.B.2. Additional details about the GRIM, the discount rate, and other financial parameters can be found in chapter 12 of the CUACs/CUHPs and CWAFs direct final rule TSDs.
Manufacturing higher-efficiency equipment is typically more expensive than manufacturing baseline equipment due to the use of more complex components, which are typically more costly than baseline components. The changes in the MPC of the analyzed equipment can affect the revenues, gross margins, and cash flow of the industry, making these equipment cost data key GRIM inputs for DOE's analysis.
In the MIA, DOE used the MPCs for each considered efficiency level calculated in the engineering analysis, as described in section IV.C and further detailed in chapter 5 of the direct final rule TSD. In addition, DOE used information from its teardown analysis, described in chapter 5 of the TSD, to disaggregate the MPCs into material, labor, and overhead costs. To calculate the MPCs for equipment above the baseline, DOE added the incremental material, labor, and overhead costs from the engineering cost-efficiency curves to the baseline MPCs. These cost breakdowns and equipment markups were validated and revised based on manufacturer comments received during MIA interviews.
The GRIM estimates manufacturer revenues based on total unit shipment forecasts and the distribution of these values by equipment class and efficiency level. Changes in sales volumes and efficiency mix over time can significantly affect manufacturer finances. For the CUAC/CUHP and CWAF analyses, the GRIM used the Shipments Analysis to estimate shipments from 2015 to 2048. See chapter 9 of the CUACs/CUHPs and CWAFs direct final rule TSDs for additional details.
An amended energy conservation standard would cause manufacturers to incur one-time conversion costs to bring their production facilities and equipment designs into compliance. DOE evaluated the level of conversion-related expenditures that would be needed to comply with each considered efficiency level in each equipment class. For the MIA, DOE classified these conversion costs into two major groups: (1) Product conversion costs; and (2) capital conversion costs. Product conversion costs are one-time investments in research, development, testing, marketing, and other non-capitalized costs necessary to make product designs comply with the amended energy conservation standard. Capital conversion costs are one-time investments in property, plant, and equipment necessary to adapt or change existing production facilities such that equipment with new, compliant designs can be fabricated and assembled.
To evaluate the level of capital conversion expenditures manufacturers would likely incur to comply with amended energy conservation standards for CUACs/CUHPs, DOE used manufacturer interviews to gather data on the anticipated level of capital investment that would be required at each efficiency level. DOE supplemented manufacturer comments with estimates of capital expenditure requirements derived from the product teardown analysis and engineering analysis.
DOE assessed the product conversion costs at each considered efficiency level by integrating data from quantitative and qualitative sources. DOE considered market-share-weighted feedback regarding the potential cost of each efficiency level from multiple manufacturers to estimate product conversion costs and validated those numbers against engineering estimates of redesign efforts. In general, DOE assumes that all conversion-related investments occur between the year of publication of the final rule and the year by which manufacturers must comply with the new standard. The conversion cost figures used in the GRIM can be found in section V.B.2.a of this document. For additional information on the estimated product and capital conversion costs, see chapter 12 of the CUACs/CUHPs direct final rule TSD.
To evaluate the level of capital conversion expenditures manufacturers would likely incur to comply with amended energy conservation standards for CWAFs, two methodologies were used to develop conversion cost estimates: (1) A Top-Down approach using feedback from manufacturer interviews to gather data on the level of costs expected at each efficiency level, and (2) a Bottom-Up approach using engineering analysis inputs derived from the equipment teardown analysis and engineering model described in chapter 5 of the CWAF direct final rule TSD to evaluate the investment required to design, manufacture, and sell equipment that meets a higher energy conservation standard.
For estimating capital conversion costs, the Top-Down approach took available feedback from manufacturers and marketshare-weighted the responses to arrive at an approximation representative of the industry as a whole. Responses from manufacturers with the greatest market share were given the greatest weight, while responses from manufacturers with the lowest market share were given the lowest weight. The Bottom-Up approach took capital conversion costs from the engineering analysis on a per-manufacturer basis to develop an industry-wide cost estimate. This analysis included the expected equipment, tooling, conveyor, and plant costs associated with CWAF production, as estimated by DOE based on product tear-downs and on manufacturer interviews. The results of the two methodologies were integrated to create high and low capital conversion cost scenarios.
Product conversion costs for CWAFs are primarily driven by re-development and testing expenses. As the standard increases, increasing levels of re-development effort would be required to meet the efficiency requirements, as more equipment models would require redesign. Additionally, expected product conversion costs would ramp up significantly where DOE expects condensing technology to be necessary to meet a revised energy conservation standard.
To estimate product R&D costs, the Top-Down approach developed average costs per product platform based on manufacturer feedback. This feedback focused on the human capital investments, such as engineering and lab technician time necessary to update designs. In the Bottom-Up approach, DOE used vendor quotes, industry product information, and engineering cost estimation analysis data to estimate the expenses associated with TE testing, heat limit testing, product safety testing, reliability testing, and engineering effort.
In general, because manufacturer expenses related to meeting the new standards must occur prior to the production of compliant equipment, DOE assumes that all conversion-related investments occur between the year of publication of the direct final rule and the year by which manufacturers must comply with the amended standard. The conversion cost figures used in the GRIM can be found in section V.B.2 of this document. For additional information on the estimated product and capital conversion costs, see chapter 12 of the CWAFs direct final rule TSD.
To calculate the MSPs in the GRIM, DOE applied manufacturer markups to the MPCs estimated in the engineering analysis for each equipment class and efficiency level. Modifying these manufacturer markups in the standards case yields different sets of manufacturer impacts. For the MIA, DOE modeled two standards-case manufacturer markup scenarios to represent the uncertainty regarding the potential impacts on prices and profitability for manufacturers following the implementation of amended energy conservation standards: (1) A preservation of gross margin percentage markup scenario; and (2) a preservation of per-unit operating profit markup scenario. These scenarios lead to different manufacturer markup values that, when applied to the inputted MPCs, result in varying revenue and cash flow impacts.
Under the preservation of gross margin percentage scenario, DOE applied a single uniform “gross margin percentage” markup across all efficiency levels, which assumes that manufacturers would be able to maintain the same amount of profit as a percentage of revenues at all efficiency levels within an equipment class. As production costs increase with efficiency, this scenario implies that the absolute dollar markup will increase as well. Based on publicly-available financial information for manufacturers of CUAC/CUHP and CWAF equipment, as well as comments from manufacturer interviews, DOE assumed the average non-production cost markup—which includes SG&A expenses, R&D expenses, interest, and profit—to be the following for each equipment class. The results are presented in Table IV–31 and Table IV–32.
This markup scenario assumes that manufacturers would be able to maintain their gross margin percentage markups as production costs increase in response to an amended energy conservation standard. Manufacturers stated that this scenario is optimistic and represents a high bound to industry profitability.
In the preservation of operating profit scenario, manufacturer markups are set so that operating profit one year after the compliance date of the amended energy conservation standard is the same as in the no-new-standards case. Under this scenario, as the costs of production increase under a standards case, manufacturers are generally required to reduce their markups to a level that maintains the no-new-standards case's operating profit. The implicit assumption behind this markup scenario is that the industry can only maintain its operating profit in absolute dollars after compliance with the new or amended standard is required. Therefore, operating margin in percentage terms is reduced between the no-new-standards case and standards case. DOE adjusted (
During the NOPR public meeting, interested parties commented on the assumptions and results of the NOPR analysis TSD. Oral and written comments addressed several topics, including employment impacts, conversion costs, and impacts on small businesses.
Nordyne expressed concern that DOE's NOPR CUAC/CUHP analysis indicates an increase in employment as a result of the rulemaking. (CUAC: Nordyne, No. 61 at p. 25) In response, DOE notes that the NOPR and Final Rule analyses present a range of potential employment impacts. These impacts are a function of the shipment forecasts and changes in production labor required to produce compliant products. At the NOPR stage, DOE presented direct employment impacts that ranged from a net loss of 94 production jobs to no change in production jobs at the proposed level.
For the final rule, DOE updated its employment analysis and continued to follow the same approach in light of the fact that, when presented with the details of DOE's analysis, manufacturers could not identify specific errors for DOE to correct. While manufacturers were unable to provide specific data regarding production employment numbers, either individually or for the industry as a whole, DOE accounted for the concerns that were raised regarding the initial projected employment impacts by incorporating the most recent data from the U.S. Census Bureau's 2013 Annual Survery of Manufacturers (ASM) and industry feedback from both written comments and the ASRAC Working Group meetings. The direct final rule analysis presents an updated set of direct employment impacts that range from a net loss of 829 jobs to no change in jobs at the adopted level.
In written comments, Lennox noted that DOE's direct employment estimates are too low. (CUAC: Lennox, No. 60 at pp. 5–6) Additionally, AHRI asked DOE to recalculate its employment forecast and methods to include all jobs associated within the equipment channel and not only the manufacturing portion. (CUAC: AHRI, No. 68 at p.41)
At the NOPR stage, DOE estimated production employment to be 1,085 workers in the no-new-standards case in 2019. For the final rule, DOE updated its analysis based on 2013 U.S. Census data, the updated engineering analysis, and the updated shipments analysis. DOE also revisited its assumption given the general feedback from industry that the initial employment figures were too low. DOE's revised direct final rule analysis forecasts that the industry will employ 2,643 production workers in the no-new-standards case in 2019.
DOE's employment analysis is based on three primary inputs: CUACs shipments in 2019, average labor content of the covered products, and an average production worker wage level. In the final rule analysis, DOE estimates there are 290,600 unit shipments in 2019. The engineering analysis shows that labor content can range from 8.2 percent to 17.5 percent of the MPC, depending on product class and model. The shipment-weighted average labor content of a unit is $342 per unit. Combining unit shipments and labor content, DOE estimates industry expenditures of $99.3 million on production labor. Using data from the ASM for NAICS code 333415, the average production worker's fully-burdened wage is $37,700 per year in the “Air-Conditioning and Warm Air Heating Equipment and Commercial and Industrial Refrigeration Equipment Manufacturing” industry. This value translates to 2,643 production workers supporting the industry in 2019.
When this figure was presented in ASRAC Working Group discussions, manufacturers stated that this figure was still too low. However, DOE did not receive any specific comments or suggestions on how it might modify this methodology to account for this issue. Furthermore, no manufacturer offered alternative estimates of company or industry employment data despite repeated requests in the NOPR and at the ASRAC Working Group meetings. The estimated number of production workers in DOE's analysis (
DOE notes that there were discrepancies between the NOPR Notice and NOPR TSD for CUAC/CUHP equipment with regard to the percentage of production labor that is domestically-based. For the final rule, DOE does not attempt to estimate the portion of foreign production of CUACs/CUHPs and CWAFs. Rather, the direct employment number captures the maximum number of domestic production workers based on the available data and DOE's methodology.
In response to AHRI's comments, DOE's manufacturer impact analysis focuses on the impacts to the regulated entities—the CUAC/CUHP manufacturers. The employment of component suppliers who manufacture components that may be used in a completed CUAC/CUHP system falls beyond the scope of the analysis. However, DOE does present the total employment impacts on the economy at large in the Indirect Employments Analysis in section IV.N of this document.
Responding to the CUAC/CUHP NOPR, stakeholders pointed out that high capital costs and intensive redesign efforts would be required by the proposed standards. Manufacturers noted that they are currently redesigning equipment to meet ASHRAE 90.1–2013 minimum efficiency levels. Adopting a standard above ASHRAE 90.1–2013 would require the redesign of most product offerings in a short time frame. (CUAC: Nordyne, No. 61 at p. 32; Trane, No. 95 at p. 11; AHRI, No. 107 at p. 46)
DOE acknowledges manufacturers' concerns regarding the product redesign process. To lessen the product redesign
Additionally, manufacturers stated that conversion costs of $12.7 million would not adequately cover all product conversion costs. (CUAC: Nordyne, No. 61 at p. 32; Trane, No. 95 at p. 11; AHRI, No. 107 at p. 45)
To clarify, in the CUAC/CUHP NOPR, DOE included an estimate of $12.7 million as a testing cost attributable to compliance, certification, and enforcement efforts that manufacturers would likely incur to re-rate all basic models using the IEER metric. However, this cost is only a small portion of the total conversion costs that DOE estimates that manufacturers are likely to incur. In the CUAC/CUHP NOPR, DOE expected the industry to incur $226.4 million in conversion costs at the proposed TSL. After evaluating further information gathered during additional interviews, as well as applying data from DOE's revised engineering analysis and shipments forecast, DOE estimates the industry would likely incur $520.8 million in conversion costs to comply with the CUAC/CUHP standard adopted in this direct final rule. This figure does not account for any cost savings that may result from aligning the CUACs/CUHPs and CWAFs standards' effective years. Conversion costs are discussed in detail in section V.B.2 of this document and in chapter 12 of the CUACs/CUHPs direct final rule TSD.
The SBA expressed concern about the impacts of the rulemaking on the one small manufacturer of CWAF equipment. Based on conversations with that small manufacturer, the SBA stated that the proposed standards are not economically feasible within the three-year period prescribed by DOE. (CWAF: SBA, No. 7 at p. 2)
For the direct final rule, DOE has adopted a later compliance date from the 2018 date proposed in the CWAF NOPR. For the direct final rule, DOE has extended the compliance year to 2023. This change will provide the small manufacturer with additional lead-time to comply with the amended standard level. In DOE's view, this additional lead-time, coupled with the more accommodating revised standards that are being adopted, will help this small manufacturer comply with the new efficiency levels in a timely manner.
The emissions analysis consists of two components. The first component estimates the effect of potential energy conservation standards on power sector and site (where applicable) combustion emissions of carbon dioxide (CO
For CWAFs, the adopted standards would reduce use of fuel at the site and slightly reduce electricity use, thereby reducing power sector emissions. However, the highest efficiency levels (
For the CUACs/CUHPs and CWAF NOPRs, DOE used marginal emissions factors for CO
Commenting on the CUAC/CUHP NOPR and the CWAF NOPR, AHRI stated that DOE should use the most recent AEO data available, which would significantly reduce the environmental benefits resulting from reductions of CO
For the direct final rule analysis, DOE used marginal emissions factors that were derived from data in
Combustion emissions of CH
The emissions intensity factors are expressed in terms of physical units per MWh or MMBtu of site energy savings. Total emissions reductions are estimated using the energy savings calculated in the national impact analysis.
For CH
Because the on-site operation of CWAFs requires use of fossil fuels and results in emissions of CO
The
SO
EIA was not able to incorporate CSAPR into
The attainment of emissions caps is typically flexible among EGUs and is enforced through the use of emissions allowances and tradable permits. Under existing EPA regulations, any excess SO
Beginning in 2016, however, SO
CAIR established a cap on NO
The MATS limit mercury emissions from power plants, but they do not include emissions caps and, as such, DOE's energy conservation standards would likely reduce Hg emissions. DOE estimated mercury emissions reduction using emissions factors based on
As part of the development of this rule, DOE considered the estimated monetary benefits from the reduced emissions of CO
For this final rule, DOE relied on a set of values for the social cost of carbon (SCC) that was developed by a Federal interagency process. The basis for these values is summarized in the next section, and a more detailed description of the methodologies used is provided as an appendix to chapter 14 of the direct final rule TSDs.
The SCC is an estimate of the monetized damages associated with an incremental increase in carbon emissions in a given year. It is intended to include (but is not limited to) climate-change-related changes in net agricultural productivity, human health, property damages from increased flood risk, and the value of ecosystem services. Estimates of the SCC are provided in dollars per metric ton of CO
Under section 1(b) of Executive Order 12866, “Regulatory Planning and Review,” 58 FR 51735 (Oct. 4, 1993), agencies must, to the extent permitted by law, “assess both the costs and the benefits of the intended regulation and, recognizing that some costs and benefits are difficult to quantify, propose or adopt a regulation only upon a reasoned determination that the benefits of the intended regulation justify its costs.” The purpose of the SCC estimates presented here is to allow agencies to incorporate the monetized social benefits of reducing CO
As part of the interagency process that developed these SCC estimates, technical experts from numerous agencies met on a regular basis to consider public comments, explore the technical literature in relevant fields, and discuss key model inputs and assumptions. The main objective of this process was to develop a range of SCC values using a defensible set of input assumptions grounded in the existing scientific and economic literatures. In this way, key uncertainties and model differences transparently and consistently inform the range of SCC estimates used in the rulemaking process.
When attempting to assess the incremental economic impacts of CO
Despite the limits of both quantification and monetization, SCC estimates can be useful in estimating the social benefits of reducing CO
It is important to emphasize that the interagency process is committed to updating these estimates as the science and economic understanding of climate change and its impacts on society improves over time. In the meantime, the interagency group will continue to explore the issues raised by this analysis and consider public comments as part of the ongoing interagency process.
In 2009, an interagency process was initiated to offer a preliminary assessment of how best to quantify the benefits from reducing carbon dioxide emissions. To ensure consistency in how benefits are evaluated across Federal agencies, the Administration sought to develop a transparent and defensible method, specifically designed for the rulemaking process, to quantify avoided climate change damages from reduced CO
After the release of the interim values, the interagency group reconvened on a regular basis to generate improved SCC estimates. Specially, the group considered public comments and further explored the technical literature in relevant fields. The interagency group relied on three integrated assessment models commonly used to estimate the SCC: The FUND, DICE, and PAGE models. These models are frequently cited in the peer-reviewed literature and were used in the last assessment of the Intergovernmental Panel on Climate Change (IPCC). Each model was given equal weight in the SCC values that were developed.
Each model takes a slightly different approach to model how changes in emissions result in changes in economic damages. A key objective of the interagency process was to enable a consistent exploration of the three models, while respecting the different approaches to quantifying damages taken by the key modelers in the field. An extensive review of the literature was conducted to select three sets of input parameters for these models: Climate sensitivity, socio-economic and emissions trajectories, and discount rates. A probability distribution for climate sensitivity was specified as an input into all three models. In addition, the interagency group used a range of scenarios for the socio-economic parameters and a range of values for the discount rate. All other model features were left unchanged, relying on the model developers' best estimates and judgments.
In 2010, the interagency group selected four sets of SCC values for use in regulatory analyses. Three sets of values are based on the average SCC from the three integrated assessment models, at discount rates of 2.5, 3, and 5 percent. The fourth set, which represents the 95th percentile SCC estimate across all three models at a 3-percent discount rate, was included to represent higher-than-expected impacts from climate change further out in the tails of the SCC distribution. The values grow in real terms over time. Additionally, the interagency group determined that a range of values from 7 percent to 23 percent should be used to adjust the global SCC to calculate domestic effects,
The SCC values used for this document were generated using the most recent versions of the three integrated assessment models that have been published in the peer-reviewed literature, as described in the 2013 update from the interagency Working Group (revised July 2015).
It is important to recognize that a number of key uncertainties remain, and that current SCC estimates should be treated as provisional and revisable because they will evolve with improved scientific and economic understanding. The interagency group also recognizes that the existing models are imperfect and incomplete. The National Research Council report mentioned previously points out that there is tension between the goal of producing quantified estimates of the economic damages from an incremental ton of carbon and the limits of existing efforts to model these effects. There are a number of analytical challenges that are being addressed by the research community, including research programs housed in many of the Federal agencies participating in the interagency process to estimate the SCC. The interagency group intends to periodically review and reconsider those estimates to reflect increasing knowledge of the science and economics of climate impacts, as well as improvements in modeling.
In summary, in considering the potential global benefits resulting from reduced CO
DOE multiplied the CO
In response to the CUAC/CUHP NOPR and the CWAF NOPR, DOE received a number of comments that were critical
A group of trade associations led by the U.S. Chamber of Commerce objected to DOE's continued use of the SCC in the cost-benefit analysis and stated that the SCC calculation should not be used in any rulemaking until it undergoes a more rigorous notice, review and comment process. (CUAC: U.S. Chamber of Commerce, No. 40 at pp. 3–4; CWAF: U.S. Chamber of Commerce, No. 21 at pp. 3–4) AHRI, Lennox and Nordyne criticized DOE's use of SCC estimates that are subject to considerable uncertainty. (CUAC: AHRI, No. 68 at p. 21; Lennox, No. 60 at p. 17; Nordyne, No. 61 at p. 18; CWAF: AHRI, No. 26 at p. 9) AHRI stated that the emissions reductions and global social cost of carbon do not meet the requirement of clear and convincing evidence that a standard more stringent than ASHRAE is justified. (CWAF: AHRI, No. 26 at p. 7) AHRI stated that the interagency process was not transparent and the estimates were not subjected to peer review. (CWAF: AHRI, No. 26 at p. 12)
In response, in conducting the interagency process that developed the SCC values, technical experts from numerous agencies met on a regular basis to consider public comments, explore the technical literature in relevant fields, and discuss key model inputs and assumptions. Key uncertainties and model differences transparently and consistently inform the range of SCC estimates. These uncertainties and model differences are discussed in the interagency Working Group's reports, which are reproduced in appendix 14A and 14B of the direct final rule TSD, as are the major assumptions. Specifically, uncertainties in the assumptions regarding climate sensitivity, as well as other model inputs such as economic growth and emissions trajectories, are discussed and the reasons for the specific input assumptions chosen are explained. However, the three integrated assessment models used to estimate the SCC are frequently cited in the peer-reviewed literature and were used in the last assessment of the IPCC. In addition, new versions of the models that were used in 2013 to estimate revised SCC values were published in the peer-reviewed literature (see appendix 14B of the direct final rule TSD for discussion). Although uncertainties remain, the revised estimates that were issued in November 2013 are based on the best available scientific information on the impacts of climate change. The current estimates of the SCC have been developed over many years, using the best science available, and with input from the public. In November 2013, OMB announced a new opportunity for public comment on the interagency technical support document underlying the revised SCC estimates. 78 FR 70586. In July 2015, OMB published a detailed summary and formal response to the many comments that were received.
AHRI stated that the use of SCC as determined on a global basis for the world population is outside of DOE's regulatory authority under EPCA. AHRI stated that EPCA authorizes DOE to conduct a national analysis of energy savings, but there are no references to global environmental impacts in the statute. (CUAC: AHRI, No. 68 at p. 21; CWAF: AHRI, No. 26 at pp. 9–11) Nordyne made similar comments. (CUAC: Nordyne, No. 61 at p. 18)
In response, DOE's analysis estimates both global and domestic benefits of CO
AHRI and Nordyne criticized DOE's inclusion of CO
AHRI and Nordyne stated that DOE wrongly assumes that SCC values will increase over time, contrary to historical experience and to economic development science. (CUACs and CUHPs: AHRI, No. 68 at p. 22; Nordyne, No. 61 at p. 19; CWAF: AHRI, No. 26 at p. 11) In response, the SCC increases over time because future emissions are expected to produce larger incremental damages as physical and economic systems become more stressed in response to greater climatic change (see appendix 14A of the direct final rule TSDs). The approach used by the interagency Working Group allowed estimation of the growth rate of the SCC directly using the three IAMs, which helps to ensure that the estimates are internally consistent with other modeling assumptions.
As noted previously, DOE has estimated how the considered energy conservation standards would reduce site NO
DOE estimated the monetized value of NO
DOE multiplied the emissions reduction (tons) in each year by the associated $/ton values, and then discounted each series using discount rates of 3 percent and 7 percent as appropriate. DOE will continue to evaluate the monetization of avoided NO
DOE is evaluating appropriate monetization of avoided SO
The utility impact analysis estimates several effects on the electric power industry that would result from the adoption of new or amended energy conservation standards. The utility impact analysis estimates the changes in installed electrical capacity and generation that would result for each TSL. The analysis for the direct final rule is based on published output from the NEMS associated with
The output of this analysis is a set of time-dependent coefficients capturing the change in electricity generation, primary fuel consumption, installed capacity and power sector emissions due to a unit reduction in demand for a given end use. These coefficients are multiplied by the stream of electricity use calculated in the NIA to provide estimates of selected utility impacts of new or amended energy conservation standards.
DOE considers employment impacts in the domestic economy as one factor in selecting a standard. Employment impacts from new or amended energy conservation standards include both direct and indirect impacts. Direct employment impacts are any changes in the number of employees of manufacturers of the products subject to standards, their suppliers, and related service firms. The MIA addresses those impacts. Indirect employment impacts are changes in national employment that occur due to the shift in expenditures and capital investment caused by the purchase and operation of more-efficient appliances. Indirect employment impacts from standards consist of the net jobs created or eliminated in the national economy, other than in the manufacturing sector being regulated, caused by: (1) Reduced spending by end users on energy; (2) reduced spending on new energy supply by the utility industry; (3) increased consumer spending on new products to which the new standards apply; and (4) the effects of those three factors throughout the economy.
One method for assessing the possible effects on the demand for labor of such shifts in economic activity is to compare sector employment statistics developed by the Labor Department's Bureau of Labor Statistics (“BLS”).
DOE estimated indirect national employment impacts for the standard levels considered in this direct final rule using an input/output model of the U.S. economy called Impact of Sector Energy Technologies version 3.1.1 (“ImSET”).
DOE notes that ImSET is not a general equilibrium forecasting model, and understands the uncertainties involved in projecting employment impacts, especially changes in the later years of the analysis. Because ImSET does not incorporate price changes, the employment effects predicted by ImSET may over-estimate actual job impacts over the long run for this rule. Therefore, DOE generated results for near-term timeframes, where these uncertainties are reduced. For more details on the employment impact analysis, see chapter 16 of the direct final rule TSDs.
The following section addresses the results from DOE's analyses with respect to the considered energy conservation standards for CUACs/CUHPs and CWAFs. It addresses the TSLs examined by DOE, the projected impacts of each of these levels if adopted as energy conservation standards for CUACs/CUHPs and CWAFs, and the standard levels that DOE is adopting in the direct final rule. Additional details regarding DOE's analyses are contained in the direct final rule TSDs supporting this document.
DOE analyzed the benefits and burdens of eight TSLs for CUACs and CUHPs that consisted of combinations of efficiency levels for each equipment class. Table V–1 presents the TSLs and the corresponding efficiency levels for CUACs and CUHPs. TSL 5 represents the maximum technologically feasible (“max-tech”) efficiency. The Recommended TSL corresponds to the standard levels recommended by the Working Group.
DOE also analyzed the benefits and burdens of five TSLs for CWAFs, which were developed by combining specific efficiency levels for each of the equipment classes analyzed. Table V–2 presents the TSLs and the corresponding efficiency levels for CWAFs. The results for all efficiency levels that DOE analyzed are in the direct final rule TSD. TSL 5 represents the max-tech efficiency levels, which rely on condensing technology. TSL 2 corresponds to the standard levels recommended by the Working Group.
DOE analyzed the economic impacts on CUAC and CWAF consumers by looking at the effects potential amended standards at each TSL would have on the LCC and PBP. DOE also examined the impacts of potential standards on commercial consumer subgroups. These analyses are discussed below.
In general, higher-efficiency products affect consumers in two ways: (1) Purchase prices increase, and (2) annual operating costs decrease. Inputs used for calculating the LCC and PBP include total installed costs (
Table V–3 through Table V–12 show the key LCC and PBP results for the TSL efficiency levels considered for each CUAC equipment class. DOE did not conduct LCC and PBP analyses for the CUHP equipment classes because energy modeling was performed only for CUAC equipment. However, the LCC and PBP results for CUACs are a close proxy for the likely consumer impacts for CUHPs because: (1) Over 98 percent of the energy savings for CUHP comes from the cooling side; (2) the per-unit savings for CUAC equipment and the cooling side of CUHP equipment are about the same; and (3) the cost of increasing efficiency for CUHPs is approximately the same as for CUACs.
In the first of each pair of tables, the simple payback is measured relative to the baseline product. In the second table, the impacts are measured relative to the efficiency distribution in the no-new-standards case in the compliance year (see section IV.F.8 of this document). The average savings reflect the fact that some consumers purchase products with higher efficiency in the no-new-standards case, and the savings
Table V–9 through Table V–12 show the key LCC and PBP results for the TSL efficiency levels considered for each CWAF equipment class. In Table V–9, the simple payback is measured relative to the baseline product. In Table V–10, the LCC savings are measured relative to the efficiency distribution in the no-new-standards case in the compliance year (see section IV.F.8 of this document).
In the consumer subgroup analysis, DOE estimated the impact of the considered TSLs on small businesses. Table V–13 and Table V–14 compare the average LCC savings and PBP at each efficiency level for the commercial consumer subgroup, along with the average LCC savings for the entire sample, for small and large CUACs, while Table V–15 shows similar results for gas-fired CWAFs. DOE did not conduct a consumer subgroup analysis for very large CUACs or for oil-fired CWAFs because the sample sizes available to DOE were very small.
In most cases, the average LCC savings and PBP for small businesses at the considered efficiency levels are not substantially different from the average
As discussed in section III.F.2, EPCA establishes a rebuttable presumption that an energy conservation standard is economically justified if the increased purchase cost for equipment that meets the standard is less than three times the value of the first-year energy savings resulting from the standard. Section IV.F describes the approach used to calculate the PBP for the rebuttable presumption. Table V–16 and Table V–17 shows the rebuttable presumption PBPs for the considered TSLs for CUACs/CUHPs and CWAFs, respectively. While DOE examined the rebuttable-presumption criterion, it also considered whether the standard levels considered for this rule are economically justified through a more detailed analysis of the economic impacts of those levels, pursuant to 42 U.S.C. 6313(a)(6)(B)(ii). The results of that analysis serve as the basis for DOE to definitively evaluate the economic justification of a potential standard level, thereby supporting or rebutting the results of any preliminary determination of economic justification.
As noted above, DOE performed an MIA to estimate the impact of new energy conservation standards on CUAC/CUHP and CWAF manufacturers. The following section describes the expected impacts on manufacturers at each considered TSL. Chapter 12 of the CUACs/CUHPs direct final rule TSD and chapter 12 of the CWAFs direct final rule TSD explains the analysis in further detail.
Table V–18 through Table V–21 depict the financial impacts (represented by changes in INPV) of new energy standards on CUAC/CUHP and CWAF manufacturers, as well as the conversion costs that DOE expects manufacturers would incur for all product classes at each TSL. To evaluate the range of cash flow impacts on the CUAC/CUHP and CWAF industries, DOE modeled two different markup scenarios using different assumptions that correspond to the range of anticipated market responses to potential new energy conservation standards: (1) The preservation of gross margin percentage; and (2) the preservation of per-unit operating profit. Each of these scenarios is discussed immediately below.
To assess the lower (less severe) end of the range of potential impacts, DOE modeled a preservation of gross margin percentage markup scenario, in which a uniform “gross margin percentage” markup is applied across all potential efficiency levels. In this scenario, DOE assumed that a manufacturer's absolute dollar markup would increase as production costs increase in the standards case.
To assess the higher (more severe) end of the range of potential impacts, DOE modeled the preservation of per-unit operating profit markup scenario, which assumes that manufacturers would be able to earn the same operating margin in absolute dollars per-unit in the standards case as in the no-new-standards case. In this scenario, while manufacturers make the necessary investments required to convert their facilities to produce new standards-compliant products, operating profit does not change in absolute dollars per unit and decreases as a percentage of revenue.
The results below show potential INPV impacts for CUAC/CUHP and CWAF manufacturers; Table V–18 and Table V–20 reflect the lower bound of impacts, and Table V–19 and Table V–21 represents the upper bound, respectively.
Each of the modeled scenarios results in a unique set of cash flows and corresponding industry values at each TSL. In the following discussion, the INPV results refer to the difference in industry value between the no-new-standards case and each standards case that results from the sum of discounted cash flows from the base year 2015 through 2048, the end of the analysis period for CUACs/CUHPs and CWAFs. To provide perspective on the short-run cash flow impact, DOE includes in the discussion of the results below a comparison of free cash flow between the no-new-standards case and the standards case at each TSL in the year before new standards would take effect. This figure provides an understanding of the magnitude of the required conversion costs relative to the cash flow generated by the industry in the no-new-standards case.
TSL 1 represents the most common efficiency levels in the current market for all product classes. At TSL 1, DOE estimates impacts on INPV for CUAC/CUHP manufacturers to range from −$107.0 million to $60.9 million, or a change in INPV of −6.5 percent to 3.7 percent. At this potential standard level, industry free cash flow is estimated to decrease by as much as 49.3 percent to $41.5 million, compared to the no-new-standards case value of $81.8 million in 2018, the year before the modeled compliance year. DOE anticipates that 31.5 percent of industry platforms would require redesign at a total industry conversion cost of $107.5 million at TSL 1.
TSL 2 represents EL 2 for all product classes. At TSL 2, DOE estimates impacts on INPV for CUAC/CUHP manufacturers to range from −$222.7 million to $114.0 million, or a change in INPV of −13.5 percent to 6.9 percent. At this potential standard level, industry free cash flow is estimated to decrease by as much as 85.7 percent to $11.7 million, compared to the no-new-standards case value of $81.8 million in 2018. DOE anticipates that 59.2 percent of industry platforms would require redesign at a total industry conversion cost of $186.8 million at TSL 2.
TSL 2.5 represents EL 2.5 for all product classes. At TSL 2.5, DOE estimates impacts on INPV for CUAC/CUHP manufacturers to range from −$344.0 million to $76.6 million, or a change in INPV of −20.9 percent to 4.7 percent. At this potential standard level, industry free cash flow is estimated to decrease by as much as 140.1 percent to −$32.8 million, compared to the no-new-standards case value of $81.8 million in 2018. DOE anticipates that 73.8 percent of industry platforms would require redesign at a total industry conversion cost of $302.5 million at TSL 2.5.
The recommended TSL represents adopting EL 1 for small, large and very large CUAC/CUHP equipment in 2018; and adopting EL 3 for small and large CUAC/CUHP equipment and EL 2.5 for very large CUAC/CUHP equipment in 2023. At the recommended TSL, DOE estimates impacts on INPV for CUAC/CUHP manufacturers to range from −$440.4 million to −$38.5 million, or a change in INPV of −26.8 percent to −2.3 percent. At this potential standard level, industry free cash flow is estimated to decrease by as much as 193.5 percent to −$76.5 million by 2022, compared to the no-new-standards case value of $81.8 million in 2018; and decrease by as much as 188.8 percent to −$76.5 million compared to the no-new-standards case value of $86.2 millon in 2022. DOE anticipates that 79.6 percent of industry platforms would require redesign at a total industry conversion cost of $520.8 million at the recommended TSL.
TSL 3 represents EL 3 for all product classes. At TSL 3, DOE estimates impacts on INPV for CUAC/CUHP manufacturers to range from −$447.2 million to $52.4 million, or a change in INPV of −27.2 percent to 3.2 percent. At this potential standard level, industry free cash flow is estimated to decrease by as much as 194.4 percent to −$77.2 million, compared to the no-new-standards case value of $81.8 million in the year before the compliance date (2019). DOE anticipates that 81.6 percent of industry platforms would require redesign at a total industry conversion cost of $418.1 million at TSL 3.
TSL 3.5 represents EL 3.5 for all product classes. At TSL 3, DOE estimates impacts on INPV for CUAC/CUHP manufacturers to range from −$506.4 million to $25.7 million, or a change in INPV of −30.8 percent to 1.6 percent. At this potential standard level, industry free cash flow is estimated to decrease by as much as 228.8 percent to −$105.3 million, compared to the no-new-standards case value of $81.8 million in 2018. DOE anticipates that 93.5 percent of industry platforms would require redesign at a total industry conversion cost of $489.2 million at TSL 3.5.
TSL 4 represents EL 4 for all product classes. At TSL 4, DOE estimates impacts on INPV for CUAC/CUHP manufacturers to range from −$619.6 million to $16.3 million, or a change in INPV of −37.7 percent to 1.0 percent. At this potential standard level, industry free cash flow is estimated to decrease by as much as 255.5 percent to −$127.2 million, compared to the no-new-standards case value of $81.8 million in 2018. DOE anticipates 96.0 percent of industry platforms would require redesign at a total industry conversion cost of $538.8 million at TSL 4.
TSL 5 represents max-tech across all equipment classes. At TSL 5, DOE estimates impacts on INPV CUAC/CUHP manufacturers to range from −$881.9 million to $93.1 million, or a change in INPV of −53.6 percent to 5.7 percent. At this potential standard level, industry free cash flow is estimated to decrease by as much as 283.8 percent to −$150.3 million, compared to the no-new-standards case value of $81.8 million in 2018. DOE anticipates that 98.7 percent of industry platforms would require redesign at a total industry conversion cost of $591.0 million at TSL 5.
Table V–20 and Table V–21 depict the estimated financial impacts (represented by changes in INPV) of amended energy standards on CWAFs, as well as conversion costs that DOE expects manufacturers would incur for all equipment classes at each TSL. To evaluate the range of cash flow impacts on the CWAF industry associated with potential amended energy conservation standards, DOE modeled two different markup scenarios and two different
In the following discussion, the INPV results refer to the difference in industry value between the no-new-standards case and each standards case that results from the sum of discounted cash flows from the base year 2015 through 2048, the end of the analysis period. To provide perspective on the short-run cash flow impact, DOE includes in the discussion of the results below a comparison of free cash flow between the no-new-standards case and the standards case at each TSL in the year before the standard takes effect. This figure provides an understanding of the magnitude of the required conversion costs relative to the cash flow generated by the industry in the no-new-standards case. The set of results below shows potential INPV impacts for CWAF manufacturers; Table V–20 represents the lower bound of impacts, and Table V–21 represents the upper bound.
In its analysis, DOE ran four scenarios based on combinations from two markup scenarios and two conversion cost scenarios. The results presented below represent the upper-bound and lower-bound of results from those scenarios only. Chapter 12 of the CWAF direct final rule TSD presents results for each markup and conversion cost scenario in further detail.
TSL 1 represents EL 1 (81 percent) for gas-fired CWAFs and baseline (81 percent) for oil-fired CWAFs. At this level, DOE estimates 55 percent of the industry platforms would require redesign at a total industry conversion cost of $6.9 million to $15.7 million. DOE estimates impacts on INPV for CWAF manufacturers to range from a change in INPV of −11.0 percent to −3.9 percent, or −$10.6 million to -$3.8 million. At this potential standard level, industry free cash flow is estimated to decrease by as much as 72.3 percent to $2.2 million, compared to the no-new-standards case value of $7.3 million in 2018, the year before the 2019 compliance year.
The recommended TSL represents an EL (81 percent for gas-fired and 82 percent for oil-fired) applicable across all equipment classes. At this level, DOE estimates 57.0 percent of the industry platforms would require redesign at at total industry conversion cost of $7.5 to $22.2 million. DOE estimates impacts on INPV for CWAF manufacturers to range from a change in INPV of −13.9 percent to −6.1 percent, or a change of −$13.4 million to −$5.9 million. At this potential standard level, industry free cash flow is estimated to decrease
TSL 3 represents EL 2 (82 percent) for gas-fired equipment and baseline (81 percent) for oil-fired equipment. At this level, DOE estimates 91 percent of the industry platforms would require redesign at a total industry conversion cost of $13.8 million to $41.0 million. DOE estimates impacts on INPV for CWAF manufacturers to range from a change in INPV of −32.0 percent to 29.9 percent, or −$30.9 million to $28.8 million. At this potential standard level, industry free cash flow is estimated to decrease by as much as 196.5 percent to −$7.5 million, compared to the no-new-standards case value of $7.3 million in 2018.
TSL 4 represents EL 2 (82 percent) for gas-fired equipment and EL 1 (82 percent) for oil-fired equipment. At this level, DOE estimates 94 percent of the industry platforms would require redesign at a total industry conversion cost of $14.4 million to $47.6 million. DOE estimates impacts on INPV for CWAF manufacturers to range from a change in INPV of −37.3 percent to 29.5 percent, or −$35.9 million to $28.4 million. At this potential standard level, industry free cash flow is estimated to decrease by as much as 233.4 percent to −$10.4 million, compared to the no-new-standards case value of $7.3 million in 2018.
TSL 5 represents max-tech across all equipment classes (
To quantitatively assess the impacts of energy conservation standards on direct employment in the collective CUAC/CUHP and CWAF industry, DOE used the GRIM to estimate the domestic labor expenditures and number of employees in the no-new-standards case and at each TSL from 2015 through 2048, the end of the analysis period. DOE used statistical data from the U.S. Census Bureau's 2013 Annual Survey of Manufacturers (ASM),
The total labor expenditures in the GRIM were then converted to domestic production employment levels by dividing production labor expenditures by the annual payment per production worker (production worker hours multiplied by the labor rate found in the U.S. Census Bureau's 2013 ASM). The estimates of production workers in this section cover workers, including line-supervisors who are directly involved in fabricating and assembling a product within the manufacturing facility. Workers performing services that are closely associated with production operations, such as materials handling tasks using forklifts, are also included as production labor. DOE's estimates only account for production workers who manufacture the specific products covered by this rulemaking.
The employment impacts shown in Table V–22 and Table V–23 represent the potential production employment changes that could result in 2019 for the collective CUAC/CUHP and CWAF industry, respectively. The upper end of the results in the table estimates the maximum increase in the number of production workers after the implementation of new energy conservation standards, and it assumes that manufacturers would continue to produce the same scope of covered products within the United States. The total direct employment impacts calculated in the GRIM are the changes in the number of production workers resulting from the amended energy conservation standards. In general, more efficient equipment is larger, more complex, and more labor intensive to build. Per unit labor requirements and production time requirements increase with a higher energy conservation standard. As a result, if shipments remain relatively steady, the model forecasts job growth at the upper bound on impact.
The lower bound assumes that, as the standard increases, manufacturers choose to retire sub-standard product lines rather than invest in manufacturing facility conversions and product redesigns. In this scenario, there is a loss of employment because manufacturers consolidate and operate fewer production lines. Since this is intended to be a worst-case scenario for employment, there is no consideration given to the fact that there may be employment growth in higher-efficiency lines. Additional detail can be found in chapter 12 of the TSDs.
DOE estimates that in the absence of amended energy conservation standards, there would be 2,643 domestic production workers for CUAC/CUHP equipment and 232 domestic production workers for CWAF equipment. For the final rule, DOE does not attempt to estimate the portion of production that occurs in other countries. Rather, as noted in section IV.J.3, the direct employment figure captures the maximum number of domestic production workers based on the available data and DOE's methodology. One noted constraint is that the production worker calculation methodology only takes into account the labor required for the most basic product that meets the appliance standard—it does not account for
DOE notes that the employment impacts discussed here are independent of the indirect employment impacts to the broader U.S. economy, which are documented in chapter 15 of the CUACs/CUHPs and CWAFs direct final rule TSDs.
CUAC/CUHP manufacturers noted during interviews that amended energy conservation standards could lead to higher fabrication labor hours. However, they also noted that industry shipments were down 40 percent from their peak in the 2007–2008 timeframe. Excess capacity in the industry today and any drop in shipments that result from higher prices could offset the additional production times. In the long-term, no manufacturers interviewed expected to have capacity constraints.
Manufacturers did, however, note concerns that engineering and testing capacity during the time period between the final rule's anticipated publication date and the 2019 compliance date initially proposed by DOE. Manufacturers were worried about the level of technical resources required to redesign and test all products at higher TSLs. The engineering analysis released with the NOPR showed that increasingly complex components and control strategies would be required as standards levels increase. Manufacturers noted in interviews that the industry would need to add electrical engineering and control systems, as well as engineering talent beyond current staffing, to meet the redesign requirements of higher TSLs. They also noted that additional training might be needed for manufacturing engineers, laboratory technicians, and service personnel if variable-speed components are broadly adopted. Furthermore, manufacturers indicated that as the stringency of standards increase, units tend to grow in size, requiring more lab resources and time to test. Some manufacturers were concerned that an amended standard would trigger the need for new test lab facilities, which would require significantly more lead time than what DOE had proposed to provide in its NOPR.
According to the CWAF manufacturers interviewed, amended energy conservation standards could lead to decreased production capacity. Most manufacturers indicated there would be little to no production capacity decrease at 81 percent and 82 percent efficiency levels, but at 91 percent and 92 percent, there would be significant capacity shortfalls. This feedback is consistent with the engineering analysis, which found there would be sufficient capacity at current levels to meet slightly higher efficiency standards, but that significant
Small manufacturers, niche equipment manufacturers, and manufacturers exhibiting a cost structure substantially different from the industry average could be affected disproportionately. As discussed in section IV.J, using average cost assumptions developed for an industry cash-flow estimate is inadequate to assess differential impacts among manufacturer subgroups.
For the collective CUAC/CUHP and CWAF industry, DOE identified and evaluated the impact of new energy conservation standards on one subgroup—small manufacturers. The SBA defines a “small business” as having 750 employees or less for NAICS 333415, “Air-Conditioning and Warm Air Heating Equipment and Commercial and Industrial Refrigeration Equipment Manufacturing.” Based on this definition, DOE identified three CUAC/CUHP manufacturers and two CWAF manufacturers that qualify as small businesses. For a discussion of the impacts on the small manufacturer subgroup, see the regulatory flexibility analysis in section VI.B of this document.
While any one regulation may not impose a significant burden on manufacturers, the combined effects of recent or impending regulations may have serious consequences for some manufacturers, groups of manufacturers, or an entire industry. Assessing the impact of a single regulation may overlook this cumulative regulatory burden. In addition to energy conservation standards, other regulations can significantly affect manufacturers' financial operations. Multiple regulations affecting the same manufacturer can strain profits and lead companies to abandon product lines or markets with lower expected future returns than competing products. For these reasons, DOE conducts an analysis of cumulative regulatory burden as part of its rulemakings pertaining to appliance efficiency.
During previous stages of this rulemaking, DOE identified a number of requirements in addition to new energy conservation standards for CUAC/CUHP and CWAF equipment. The following section briefly summarizes those identified regulatory requirements and addresses comments DOE received with respect to cumulative regulatory burden, as well as other key related concerns that manufacturers raised during interviews.
Companies that produce a wide range of regulated products and equipment may face more capital and product development expenditures than competitors with a narrower scope of products and equipment. Many CUAC/CUHP and CWAF manufacturers also produce other residential and commercial equipment. In addition to the amended energy conservation standard for CUAC/CUHP and CWAF equipment, these manufacturers contend with several other Federal regulations and pending regulations that apply to other products and equipment. DOE recognizes that each regulation can significantly affect a manufacturer's financial operations. Multiple regulations affecting the same manufacturer can quickly strain manufacturer profits and possibly cause an exit from the market. Table V–24 lists the other DOE energy conservation standards that could also affect CUAC/CUHP and CWAF manufacturers in the three years leading up to and after the compliance date of the new energy conservation standards for this equipment. Additionally, at the request of stakeholders, DOE has listed several pending DOE rulemakings in the table below.
In addition to Federal energy conservation standards, DOE identified other Federal regulatory burdens that would affect CUAC/CUHP and CWAF manufacturers:
The U.S. is obligated under the Montreal Protocol to limit the production and consumption of HCFCs through incremental reductions, culminating in a complete phase-out of HCFCs by 2030. On October 28, 2015, EPA published the “2015 HCFC Allocation Rule,” which allocates production and consumption allowances for HCFC–22, HCFC–123, and HCFC–124 for each year between 2015 and 2019. 79 FR 64253. Production and import of virgin HCFC–22 for servicing appliances will cease at the end of 2019, however reclaimed material and stocks of refrigerant produced prior to 2020 will be available to service existing appliances.
HCFC–22, which is also known as R–22, is a popular refrigerant that is commonly used in air-conditioning products. As of January 1, 2010, EPA effectively prohibited the installation in the field of new appliances containing virgin R–22. 74 FR 66412. Additionally, there is a prohibition on the manufacture of new appliances and appliance components pre-charged with R–22 as of the same date. However, manufacturers can still manufacture components for servicing existing appliances. 74 FR 66450. Under the Clean Air Act and EPA's implementing regulations at 40 CFR part 82, subpart A, starting January 1, 2020, it will be illegal to manufacture any appliance containing virgin HCFCs. Manufacturers of CUAC/CUHP and CWAF equipment must comply with the these prohibitions and the allowances established by the allocation rule, thereby facing a cumulative regulatory burden. As such, no covered manufacturers offer R–22 products today. The MPCs used for the baseline and higher efficiency design options account for the move away from R–22 and the changes in production costs that resulted from the shift to HFC refrigerants.
Any amended standard that DOE adopts would also require manufacturers to follow accompanying CC&E requirements. DOE conducted a rulemaking to expand the coverage of DOE's alternative efficiency determination method (“AEDM”) regulations to commercial HVAC, including the equipment covered by this rulemaking. See 78 FR 79579 (December 31, 2013). An AEDM is a computer modeling or mathematical tool that predicts the performance of non-tested basic models of a type of covered equipment or product. In that final rule, DOE permits manufacturers of small, large, and very large air-cooled commercial package air conditioning equipment to rate basic models using AEDMs for compliance certification purposes, reducing the need for sample units and the overall burden on manufacturers. The AEDM final rule established revised verification tolerances for small, large, and very large air-cooled commercial package air conditioning equipment manufacturers. More information can be found at
During interviews, some manufacturers stated that ENERGY STAR specifications for CUACs/CUHPs and CWAFs would be a source of cumulative regulatory burden.
DOE realizes that the cumulative effect of several regulations on an industry may significantly increase the burden faced by manufacturers that need to comply with multiple regulations and certification programs from different organizations and levels of government.
However, DOE notes that certain programs, such as ENERGY STAR, are optional for manufacturers. As these programs are voluntary in nature, they are not considered by DOE to be part of the manufacturers' cumulative regulatory burden since manufacturers are not legally required to meet the specifications prescribed by these voluntary programs.
DOE discusses these and other requirements (
DOE's analysis of the various national impacts flowing from amending the energy conservation standards for CUACs/CUHPs and CWAFs are summarized below and include a discussion of the energy savings and the related economic impacts that are projected to occur.
To estimate the energy savings attributable to potential standards for CUACs/CUHPs and CWAFs, DOE compared their energy consumption under the no-new-standards case to their anticipated energy consumption under each TSL. For most of the TSLs considered in this direct final rule, DOE forecasted the energy savings, operating cost savings, and equipment costs over the lifetime of CUACs/CUHPs and CWAFs sold from 2019 through 2048. For the TSLs that represent the consensus recommendations, DOE accounted for the lifetime impacts of CUACs and CUHPs sold from 2018 through 2047 and CWAFs sold from 2023 through 2048. Table V–25 and Table V–26 present DOE's projections of the national energy savings for each TSL considered for CUACs/CUHPs and CWAFs, respectively. The savings were calculated using the approach described in section IV.H of this document. Separate savings for each equipment class are presented in chapter 10 of the direct final rule TSDs.
OMB Circular A–4
DOE estimated the cumulative NPV of the total costs and savings for commercial consumers that would result from the TSLs considered for CUACs/CUHPs and CWAFs. In accordance with OMB's guidelines on regulatory analysis,
Table V–29 and Table V–30 show the commercial consumer NPV results with impacts counted over the lifetime of equipment purchased in the relevant analysis period for each TSL.
The results in Table V–29 reflect the use of a constant price trend for CUACs and CUHPs over the analysis period (see section IV.F.1). DOE also conducted a sensitivity analysis that considered one scenario with a lower rate of price decline than the reference case and one scenario with a higher rate of price decline than the reference case. The results of these alternative cases are presented in appendix 10C of the CUAC/CUHP direct final rule TSD.
The results in Table V–30 reflect the use of the historic trend in the inflation-adjusted PPI for “Warm air furnaces” to estimate the change in price for CWAFs over the analysis period (see section IV.F.1). The trend shows a small rate of annual price decline. DOE also conducted a sensitivity analysis that considered one scenario with a lower rate of price decline than the reference case and one scenario with a higher rate of price decline than the reference case. The results of these alternative cases are presented in appendix 10C of the CWAF direct final rule TSD.
The NPV results based on the aforementioned 9-year analytical period are presented in Table V–31 and Table V–32 for CUACs/CUHPs and CWAFs, respectively. As mentioned previously, such results are presented for informational purposes only and are not indicative of any change in DOE's analytical methodology or decision criteria.
DOE expects energy conservation standards for CUACs/CUHPs and CWAFs to reduce energy bills for consumers of those equipment, with the resulting net savings being redirected to other forms of economic activity. These expected shifts in spending and economic activity could affect the demand for labor. DOE used an input/output model of the U.S. economy to estimate indirect employment impacts of the TSLs that DOE considered in this rulemaking. DOE understands that there are uncertainties involved in projecting employment impacts, especially changes in the later years of the analysis. Therefore, DOE generated results for timeframes within five years of the compliance date, where these uncertainties are reduced.
The results suggest that the adopted standards are likely to have a negligible impact on the net demand for labor in the economy. The net change in jobs is so small that it would be imperceptible in national labor statistics and might be offset by other, unanticipated effects on employment. Chapter 16 of the direct final rule TSDs presents detailed results regarding anticipated indirect employment impacts.
DOE has concluded that the standards adopted in this final rule would not reduce the utility or performance of the CUACs/CUHPs and CWAFs under consideration in this rulemaking. Manufacturers of these equipment types currently offer units that meet or exceed the adopted standards.
EPCA directs DOE to consider any lessening of competition that is likely to result from standards. It also directs the Attorney General of the United States (Attorney General) to determine the impact, if any, of any lessening of competition likely to result from a proposed standard and to transmit such determination in writing to the Secretary within 60 days of the publication of a proposed rule, together with an analysis of the nature and extent of the impact.
To assist the Attorney General in making this determination, DOE provided the Department of Justice (DOJ) with copies of the NOPR and the TSD for review. In its assessment letter responding to DOE, DOJ concluded that the proposed energy conservation standards for CUACs/CUHPs and CWAFs are unlikely to have a significant adverse impact on competition. DOE is publishing the Attorney General's assessments for both proposals at the end of this direct final rule.
Enhanced energy efficiency, where economically justified, improves the Nation's energy security, strengthens the economy, and reduces the environmental impacts (costs) of energy production. Reduced electricity demand due to energy conservation standards is also likely to reduce the cost of maintaining the reliability of the electricity system, particularly during peak-load periods. As a measure of this reduced demand, chapter 15 in the direct final rule TSDs presents the estimated reduction in generating capacity, relative to the no-new-standards case, for the TSLs that DOE considered in this rulemaking.
Energy conservation resulting from amended standards for CUACs/CUHPs and CWAFs are expected to yield environmental benefits in the form of reduced emissions of air pollutants and GHGs. Table V–33 and Table V–34 provide DOE's estimate of cumulative emissions reductions expected to result from the TSLs considered for CUACs/CUHPs and CWAFs, respectively. The emissions were calculated using the multipliers discussed in section IV.K. DOE reports annual emissions reductions for each TSL in chapter 13 of the direct final rule TSDs.
As part of the analysis for this rule, DOE estimated monetary benefits likely to result from the reduced emissions of CO
Table V–35 and Table V–36 present the global value of CO
DOE is well aware that scientific and economic knowledge about the contribution of CO
DOE also estimated the cumulative monetary value of the economic benefits associated with NO
The Secretary of Energy, in determining whether a standard is economically justified, may consider any other factors that the Secretary deems to be relevant. (42 U.S.C. 6313(a)(6)(B)(ii)(VII)) No other factors were considered in this analysis.
The NPV of the monetized benefits associated with emissions reductions can be viewed as a complement to the NPV of the commercial consumer savings calculated for each TSL considered in this rulemaking. Table V–39 and Table V–40 present the NPV values that result from adding the estimates of the potential economic benefits resulting from reduced CO
In considering the above results, two issues are relevant. First, the national operating cost savings are domestic U.S. monetary savings that occur as a result of market transactions, while the value of CO
When considering new or amended energy conservation standards, the standards that DOE adopts for any type (or class) of covered product or equipment must be designed to achieve significant additional conservation of energy that the Secretary determines is technologically feasible and economically justified. (42 U.S.C. 6313(a)(6)(A)(ii)(II)) In determining whether a standard is economically justified, the Secretary must determine whether the benefits of the standard exceed its burdens by, to the greatest extent practicable, considering the seven statutory factors discussed previously. (42 U.S.C. 6313(a)(6)(B)(ii)(I)–(VII))
For this direct final rule, DOE considered the impacts from amended standards for CUACs/CUHPs and CWAFs at each TSL, beginning with the maximum technologically feasible level, to determine whether that level was economically justified. Where the max-tech level was not justified, DOE then considered the next most efficient level and undertook the same evaluation until it reached the highest efficiency level that is both technologically feasible and economically justified and saves a significant amount of energy.
To aid the reader as DOE discusses the benefits and/or burdens of each TSL, tables in this section present a summary of the results of DOE's quantitative analysis for each TSL. In addition to the quantitative results presented in the tables, DOE also considers other burdens and benefits that affect economic justification.
Table V–41 and Table V–42 summarize the quantitative impacts estimated for each TSL for CUACs and CUHPs. The national impacts are measured over the lifetime of CUACs and CUHPs purchased in the 2018–2048 period. The energy savings, emissions reductions, and value of emissions reductions refer to FFC results. The efficiency levels contained in each TSL are described in section V.A.
DOE first considered TSL 5, which represents the max-tech efficiency levels. TSL 5 would save 23.4 quads of energy, an amount DOE considers significant. Under TSL 5, the NPV of consumer benefit would be $18.8 billion using a 7-percent discount rate, and $68.2 billion using a 3-percent discount rate.
The cumulative emissions reductions at TSL 5 are 1,383 million Mt of CO
At TSL 5, the average LCC impact is a savings of $5,326 for small CUACs, $12,900 for large CUACs, and $18,338 for very large CUACs. The simple payback period is 4.6 years for small CUACs, 4.6 years for large CUACs, and 6.3 years for very large CUACs. The fraction of consumers experiencing a net LCC cost is 16 percent for small CUACs, 11 percent for large CUACs, and 6 percent for very large CUACs. Although DOE did not estimate consumer impacts for CUHPs, the results would be very similar to those for CUACs for the reasons stated in section V.B.1.
At TSL 5, the projected change in INPV ranges from a decrease of $881.9 million to an increase of $93.1 million, which correspond to a change of −53.7 percent and 5.7 percent, respectively. The industry is expected to incur $591.0 million in total conversion costs at this level. DOE projects that 98.7 percent of current equipment listings would require redesign at this level to meet this standard level today. At this level, DOE recognizes that manufacturers could face technical resource constraints. Manufacturers stated they would require additional engineering expertise and additional test laboratory capacity. It is unclear whether manufacturers could complete the hiring of the necessary technical expertise and construction of the necessary test facilities in time to allow for the redesign of all equipment to meet max-tech by 2019. Furthermore, DOE recognizes that a standard set at max-tech could greatly limit equipment differentiation in the small, large, and very large CUAC/CUHP market. By commoditizing a key differentiating feature, a standard set at max-tech would likely accelerate consolidaton in the industry.
The Secretary concludes that at TSL 5 for CUACs and CUHPs, the benefits of energy savings, positive NPV of consumer benefits, emission reductions, and the estimated monetary value of the emissions reductions would be outweighed by the economic burden on some consumers, and the impacts on manufacturers, including the conversion costs and profit margin impacts that could result in a large reduction in INPV. Consequently, the Secretary has concluded that TSL 5 is not economically justified.
DOE then considered TSL 4. TSL 4 would save 19.7 quads of energy, an amount DOE considers significant. Under TSL 4, the NPV of consumer benefit would be $19.2 billion using a 7-percent discount rate, and $64.1 billion using a 3-percent discount rate.
The cumulative emissions reductions at TSL 4 are 1,167 million Mt of CO
At TSL 4, the average LCC impact is a savings of $3,035 for small CUACs, $16,803 for large CUACs, and $18,386 for very large CUACs. The simple payback period is 2.5 years for small CUACs, 2.5 years for large CUACs, and 5.6 years for very large CUACs. The fraction of consumers experiencing a net LCC cost is 25 percent for small CUACs, 1 percent for large CUACs, and 3 percent for very large CUACs. Although DOE did not estimate consumer impacts for CUHPs, the results would be very similar to those for CUACs for the reasons stated in section V.B.1.
At TSL 4, the projected change in INPV ranges from a decrease of $619.6 million to an increase of $16.3 million, which corresponds to a change of −37.7 percent and 1.0 percent, respectively. The industry is expected to incur $538.8 million in total conversion costs at this level. DOE projects that 96.0 percent of current equipment listings would require redesign at this level to meet this standard level today.
The Secretary concludes that at TSL 4 for CUACs and CUHPs, the benefits of energy savings, positive NPV of consumer benefits, emission reductions, and the estimated monetary value of the emissions reductions would be outweighed by the economic burden on some consumers, and the impacts on manufacturers, including the conversion costs and profit margin impacts that could result in a reduction in INPV. Consequently, the Secretary has concluded that TSL 4 is not economically justified.
DOE then considered TSL 3.5. TSL 3.5 would save 16.4 quads of energy, an amount DOE considers significant. Under TSL 3.5, the NPV of consumer benefit would be $17.1 billion using a 7-percent discount rate, and $55.3 billion using a 3-percent discount rate.
The cumulative emissions reductions at TSL 3.5 are 973 million Mt of CO
At TSL 3.5, the average LCC impact is a savings of $3,517 for small CUACs, $12,266 for large CUACs, and $8,881 for very large CUACs. The simple payback period is 2.6 years for small CUACs, 2.6 years for large CUACs, and 7.2 years for very large CUACs. The fraction of consumers experiencing a net LCC cost is 13 percent for small CUACs, 1 percent
At TSL 3.5, the projected change in INPV ranges from a decrease of $506.4 million to an increase of $25.7 million, which corresponds to a change of −30.8 percent and 1.6 percent, respectively. The industry is expected to incur $489.2 million in total conversion costs at this level. DOE projects that 93.5 percent of current equipment listings would require redesign at this level to meet this standard level today.
The Secretary concludes that at TSL 3.5 for CUACs and CUHPs, the benefits of energy savings, positive NPV of consumer benefits, emission reductions, and the estimated monetary value of the emissions reductions would be outweighed by the economic burden on some consumers, and the impacts on manufacturers, including the conversion costs and profit margin impacts that could result in a reduction in INPV. Consequently, the Secretary has concluded that TSL 3.5 is not economically justified.
DOE then considered TSL 3. TSL 3 would save 15.9 quads of energy, an amount DOE considers significant. Under TSL 3, the NPV of consumer benefit would be $16.8 billion using a 7-percent discount rate, and $53.7 billion using a 3-percent discount rate.
The cumulative emissions reductions at TSL 3 are 943 million Mt of CO
At TSL 3, the average LCC impact is a savings of $4,233 for small CUACs, $10,135 for large CUACs, and $8,881 for very large CUACs. The simple payback period is 4.9 years for small CUACs, 2.6 years for large CUACs, and 7.2 years for very large CUACs. The fraction of consumers experiencing a net LCC cost is 5 percent for small CUACs, 2 percent for large CUACs, and 23 percent for very large CUACs. Although DOE did not estimate consumer impacts for CUHPs, the results would be very similar to those for CUACs for the reasons stated in section V.B.1.
At TSL 3, the projected change in INPV ranges from a decrease of $447.2 million to an increase of $52.4 million, which corresponds to a change of −27.2 percent and 3.2 percent, respectively. DOE projects that 81.6 percent of current equipment listings would require redesign at this level to meet this standard level today.
The Secretary concludes that at TSL 3 for CUACs and CUHPs, the benefits of energy savings, positive NPV of consumer benefits, emission reductions, and the estimated monetary value of the emissions reductions would be outweighed by the economic burden on some consumers, and the impacts on manufacturers, including the conversion costs and profit margin impacts that could result in a large reduction in INPV. Consequently, the Secretary has concluded that TSL 3 is not economically justified.
DOE then considered the Recommended TSL, which reflects the standard levels recommended by the ASRAC Working Group. The Recommended TSL would save 14.8 quads of energy, an amount DOE considers significant. Under the Recommended TSL, the NPV of consumer benefit would be $15.2 billion using a 7-percent discount rate, and $50.0 billion using a 3-percent discount rate.
The cumulative emissions reductions at the Recommended TSL are 873 million Mt of CO
At the Recommended TSL, the average LCC impact is a savings of $4,233 for small CUACs, $10,135 for large CUACs, and $8,610 for very large CUACs. The simple payback period is 4.9 years for small CUACs, 2.6 years for large CUACs, and 6.2 years for very large CUACs. The fraction of consumers experiencing a net LCC cost is 5 percent for small CUACs, 2 percent for large CUACs, and 7 percent for very large CUACs. Although DOE did not estimate consumer impacts for CUHPs, the results would be very similar to those for CUACs for the reasons stated in section V.B.1.
The Recommended TSL as developed by the Working Group and submitted to DOE by ASRAC, aligns the effective dates of the CUAC/CUHP and CWAF rulemakings. That recommended approach adopts the ASHRAE 90.1–2013 efficiency levels for this equipment for compliance starting in 2018 and will phase into a higher level starting in 2023 as recommended to ASRAC by the Working Group. DOE expects that aligning the effective dates reduces total conversion costs and cumulative regulatory burden, while also allowing industry to gain clarity on potential regulations that could affect refrigerant availability before the higher appliance standard takes effect in 2023. DOE projects that 31.5 percent of current equipment listings would require redesign at this level to meet the 2018 standard level, while 79.6 percent of current equipment listings would require redesign at this level to meet the 2023 standard level.
At the Recommended TSL, the projected change in INPV ranges from a decrease of $440.4 million to a decrease of $38.5 million, which corresponds to a change of −26.8 percent and −2.3 percent, respectively. The industry is expected to incur $520.8 million in total conversion costs at this level. However, the industry members of the Working Group noted that aligning the compliance dates for the CUAC/CUHP and CWAF standards in the manner recommended would allow manufacturers to coordinate their redesign and testing expenses for these equipment (CUAC: AHRI and ACEEE, No. 80 at p. 1). With this coordination, manufacturers explained that there would be a reduction in the total conversion costs associated with this direct final rule. These synergies resulting from the alignment of the CUAC/CUHP and CWAF compliance dates would yield INPV impacts that are less severe than the forecasted INPV range of −26.8 percent to −2.3 percent.
After considering the analysis and weighing the benefits and burdens, DOE has determined that the recommended standards are in accordance with 42 U.S.C. 6313(a)(6)(B), which contains provisions for adopting a uniform national standard more stringent than the amended ASHRAE Standard 90.1 for the equipment considered in this document. Specifically, the Secretary has determined, supported by clear and convincing evidence as described in this direct final rule and accompanying TSDs, that such adoption would result in the significant additional conservation of energy and is technologically feasible and economically justified. In determining whether the recommended standards are economically justified, the Secretary has determined that the benefits of the recommended standards exceed the burdens. Namely, the Secretary has concluded that under the recommended standards for CUACs and CUHPs, the benefits of energy savings, positive NPV of consumer benefits, emission reductions, the estimated monetary value of the emissions reductions, and positive average LCC savings would outweigh the negative impacts on some consumers and on manufacturers, including the conversion costs that
Under the authority provided by 42 U.S.C. 6295(p)(4) and 6316(b)(1), DOE is issuing this direct final rule that establishes amended energy conservation standards for CUACs and CUHPs at the Recommended TSL. The amended energy conservation standards for CUACs and CUHPs, which prescribe the minimum allowable IEER and, for commercial unitary heat pumps, COP, are shown in Table V–43.
The benefits and costs of the adopted standards can also be expressed in terms of annualized values. The annualized net benefit is the sum of: (1) The annualized national economic value (expressed in 2014$) of the benefits from operating equipment that meet the adopted standards (consisting primarily of operating cost savings from using less energy, minus increases in product purchase costs, and (2) the annualized monetary value of the benefits of CO
Table V–44 shows the annualized values for CUACs and CUHPs under the Recommended TSL, expressed in 2014$. The results under the primary estimate are as follows. Using a 7-percent discount rate for benefits and costs other than CO
Table V–45 and Table V–46 summarize the quantitative impacts estimated for each TSL for CWAFs. For TSL 2, the national impacts are projected over the lifetime of equipment sold in 2023–2048. For the other TSLs, the impacts are projected over the lifetime of equipment sold in 2019–2048. The energy savings, emissions reductions, and value of emissions reductions refer to FFC results. The efficiency levels contained in each TSL are described in section V.A.
DOE first considered TSL 5, which represents the max-tech efficiency levels. TSL 5 would save 2.4 quads of energy, an amount DOE considers significant. Under TSL 5, the NPV of consumer cost would be $0.4 billion using a 7-percent discount rate, and the NPV of consumer benefit would be $2.6 billion using a 3-percent discount rate.
The cumulative emissions reductions at TSL 5 are 126 Mt of CO
At TSL 5, the average LCC impact is a savings of $766 for gas-fired CWAFs and $1,817 for oil-fired CWAFs. The simple payback period is 11.3 years for gas-fired CWAFs and 7.5 years for oil-fired CWAFs. The fraction of consumers experiencing a net LCC cost is 58 percent for gas-fired CWAFs and 54 percent for oil-fired CWAFs.
At TSL 5, the projected change in INPV ranges from a decrease of $115.7 million to an increase of $47.2 million, which corresponds to a change of −120.1 percent and 49.0 percent, respectively. The industry is expected to incur $157.5 million in total conversion costs at this level. DOE projects that 99 percent of current equipment listings would require redesign at this level.
The Secretary concludes that at TSL 5 for CWAFs, the benefits of energy savings, positive NPV of consumer benefits using a discount rate of 3-percent, emission reductions, and the estimated monetary value of the emissions reductions would be outweighed by the economic burden on most consumers, the negative NPV of consumer benefits using a 7-percent discount rate, and the impacts on manufacturers, including the conversion costs and profit margin impacts that could result in a large reduction in INPV. Consequently, the Secretary has concluded that TSL 5 is not economically justified.
DOE then considered TSL 4. TSL 4 would save 0.41 quads of energy, an amount DOE considers significant. Under TSL 4, the NPV of consumer cost would be $0.4 billion using a 7-percent discount rate, and $0.1 billion using a 3-percent discount rate.
The cumulative emissions reductions at TSL 4 are 22 Mt of CO
At TSL 4, the average LCC impact is a savings of $75 for gas-fired CWAFs and $400 for oil-fired CWAFs. The simple payback period is 12.3 years for gas-fired CWAFs and 1.9 years for oil-fired CWAFs. The fraction of consumers experiencing a net LCC cost is 58 percent for gas-fired CWAFs, and 11 percent for oil-fired CWAFs.
At TSL 4, the projected change in INPV ranges from a decrease of $35.9 million to an increase of $28.4 million, which corresponds to a change of −37.3 percent and 29.5 percent, respectively. The industry is expected to incur $47.6 million in total conversion costs at this level; DOE projects that 94 percent of current product listings would require redesign at this level.
The Secretary concludes that at TSL 4 for CWAFs, the benefits of energy savings, emission reductions, and the estimated monetary value of the emissions reductions would be outweighed by the economic burden on many consumers, negative NPV of consumer benefits, and the impacts on manufacturers, including the conversion costs and profit margin impacts that could result in a large reduction in INPV. Consequently, the Secretary has concluded that TSL 4 is not economically justified.
DOE then considered TSL 3. TSL 3 would save 0.41 quads of energy, an amount DOE considers significant. Under TSL 3, the NPV of consumer cost would be $0.4 billion using a 7-percent discount rate, and $0.1 billion using a 3-percent discount rate.
The cumulative emissions reductions at TSL 3 are 22 Mt of CO
At TSL 3, the average LCC impact is a savings of $75 for gas-fired CWAFs. The simple payback period is 12.3 years for gas-fired CWAFs. The fraction of consumers experiencing a net LCC cost is 58 percent for gas-fired CWAFs. The EL at TSL 3 for oil-fired CWAFs is the baseline, so there are no LCC impacts for oil-fired CWAFs at TSL 3.
At TSL 3, the projected change in INPV ranges from a decrease of $30.9 million to an increase of $28.8 million, which corresponds to a change of −32.0 percent and 29.9 percent, respectively. The industry is expected to incur $41.0 million in total conversion costs at this level; DOE projects that 91 percent of current equipment listings would require redesign at this level.
The Secretary concludes that at TSL 3 for CWAFs, the benefits of energy savings, emission reductions, and the estimated monetary value of the emissions reductions would be outweighed by the economic burden on many consumers, negative NPV of consumer benefits, and the impacts on manufacturers, including the conversion costs and profit margin impacts that could result in a large reduction in INPV. Consequently, the Secretary has concluded that TSL 3 is not economically justified.
DOE then considered TSL 2. TSL 2 would save 0.23 quads of energy, an amount DOE considers significant. Under TSL 2, the NPV of consumer benefit would be $0.3 billion using a 7-percent discount rate, and $1.0 billion using a 3-percent discount rate.
The cumulative emissions reductions at TSL 2 are 12.4 Mt of CO
At TSL 2, the average LCC impact is a savings of $284 for gas-fired CWAFs and $400 for oil-fired CWAFs. The simple payback period is 1.4 years for gas-fired CWAFs and 1.9 years for oil-fired CWAFs. The fraction of consumers experiencing a net LCC cost is 6 percent for gas-fired CWAFs and 11 percent for oil-fired CWAFs.
At TSL 2, 57 percent of current equipment listings would require redesign at this level. The projected change in INPV ranges from a decrease of $13.4 million to a decrease of $5.9 million, which corresponds to a decrease of 13.9 percent and 6.1 percent, respectively. The CWAF industry is expected to incur $22.2 million in total conversion costs. However, the industry noted that aligning the compliance dates for the CUAC/CUHP and CWAF standards, as recommended by the Working Group, would allow manufacturers to coordinate their redesign and testing expenses for this equipment. If this occurs, there could be a reduction in the total conversion costs associated with this direct final rule. These synergies resulting from aligning the compliance dates of the CUAC/CUHP and CWAF standards would result in INPV impacts that are less severe than the forecasted INPV range of −13.9 percent to −6.1 percent.
After considering the analysis and weighing the benefits and burdens, DOE has determined that the recommended standards are in accordance with 42 U.S.C. 6313(a)(6)(B), which contains provisions for adopting a uniform national standard more stringent than the amended ASHRAE/IES Standard 90.1 for the equipment considered in this document. Specifically, the Secretary has determined, supported by clear and convincing evidence, that such adoption would result in significant additional conservation of energy and is technologically feasible and economically justified. In determining whether the recommended standards are economically justified, the
Under the authority provided by 42 U.S.C. 6295(p)(4) and 6316(b)(1), DOE is issuing this direct final rule that establishes amended energy conservation standards for CWAFs at TSL 2. The amended energy conservation standards for CWAFs, which are expressed in terms of TE, are shown in Table V–47.
The benefits and costs of the adopted standards can also be expressed in terms of annualized values. The annualized net benefit is the sum of: (1) The annualized national economic value (expressed in 2014$) of the benefits from operating equipment that meet the adopted standards (consisting primarily of operating cost savings from using less energy, minus increases in equipment purchase costs), and (2) the annualized monetary value of the benefits of CO
Table V–48 shows the annualized values for CWAFs under TSL 2, expressed in 2014$. The results under the primary estimate are as follows. Using a 7-percent discount rate for benefits and costs other than CO
Using a 3-percent discount rate for all benefits and costs and the average SCC series corresponding to a value of $40.0/ton in 2015 (in 2014$), the estimated cost of the adopted standards for CWAFs is $4.38 million per year in increased equipment costs, while the estimated benefits are $71 million per year in reduced operating costs, $24 million per year in CO
Section 1(b)(1) of Executive Order 12866, “Regulatory Planning and Review,” 58 FR 51735 (Oct. 4, 1993), requires each agency to identify the problem that it intends to address, including, where applicable, the failures of private markets or public institutions that warrant new agency action, as well as to assess the significance of that problem. The problems that the adopted standards for CUACs/CUHPs and CWAFs are intended to address are as follows:
(1) Insufficient information and the high costs of gathering and analyzing relevant information lead some consumers to miss opportunities to make cost-effective investments in energy efficiency.
(2) In some cases, the benefits of more efficient equipment are not realized due to misaligned incentives between purchasers and users. An example of such a case is when the equipment purchase decision is made by a building contractor or building owner who does not pay the energy costs to operate that equipment.
(3) There are external benefits resulting from the improved energy efficiency of CWAFs that are not captured by the users of such equipment. These benefits include externalities related to public health, environmental protection and national energy security that are not reflected in energy prices, such as reduced emissions of air pollutants and greenhouse gases that impact human health and global warming. DOE attempts to qualify some of the external benefits through use of social cost of carbon values.
The Administrator of the Office of Information and Regulatory Affairs (“OIRA”) in the OMB has determined that the proposed regulatory action is a significant regulatory action under section (3)(f) of Executive Order 12866. Accordingly, pursuant to section 6(a)(3)(B) of the Order, DOE has provided to OIRA: (i) The text of the draft regulatory action, together with a reasonably detailed description of the need for the regulatory action and an explanation of how the regulatory action will meet that need; and (ii) An assessment of the potential costs and benefits of the regulatory action, including an explanation of the manner in which the regulatory action is consistent with a statutory mandate. DOE has included these documents in the rulemaking record.
In addition, the Administrator of OIRA has determined that the proposed regulatory action is an “economically” significant regulatory action under section (3)(f)(1) of Executive Order 12866. Accordingly, pursuant to section 6(a)(3)(C) of the Order, DOE has provided to OIRA an assessment, including the underlying analysis, of benefits and costs anticipated from the regulatory action, together with, to the extent feasible, a quantification of those costs; and an assessment, including the underlying analysis, of costs and benefits of potentially effective and reasonably feasible alternatives to the planned regulation, and an explanation why the planned regulatory action is preferable to the identified potential alternatives. These assessments can be found in the technical support documents for this rulemaking.
DOE has also reviewed this regulation pursuant to Executive Order 13563, issued on January 18, 2011. (76 FR 3281, Jan. 21, 2011) EO 13563 is supplemental to and explicitly reaffirms the principles, structures, and definitions governing regulatory review established in Executive Order 12866. To the extent permitted by law, agencies are required by Executive Order 13563 to: (1) Propose or adopt a regulation only upon a reasoned determination that its benefits justify its costs (recognizing that some benefits and costs are difficult to quantify); (2) tailor regulations to impose the least burden on society, consistent with obtaining regulatory objectives, taking into account, among other things, and to the extent practicable, the costs of cumulative regulations; (3) select, in choosing among alternative regulatory approaches, those approaches that maximize net benefits (including
DOE emphasizes as well that Executive Order 13563 requires agencies to use the best available techniques to quantify anticipated present and future benefits and costs as accurately as possible. In its guidance, OIRA has emphasized that such techniques may include identifying changing future compliance costs that might result from technological innovation or anticipated behavioral changes. For the reasons stated in the preamble, DOE believes that this direct final rule is consistent with these principles, including the requirement that, to the extent permitted by law, benefits justify costs and that net benefits are maximized.
The Regulatory Flexibility Act (5 U.S.C. 601
For manufacturers of CUAC/CUHP and CWAF equipment, the Small Business Administration (“SBA”) has set a size threshold, which defines those entities classified as “small businesses” for the purposes of the statute. DOE used the SBA's small business size standards to determine whether any small entities would be subject to the requirements of the rule. See 13 CFR part 121. The size standards are listed by North American Industry Classification System (“NAICS”) code and industry description and are available at
To better assess the potential impacts of this rulemaking on small entities, DOE conducted a focused inquiry of the companies that could be small business manufacturers of equipment covered by this rulemaking. DOE conducted a market survey using available public information to identify potential small manufacturers. DOE's research involved industry trade association membership directories (including AHRI
DOE identified 12 CUAC/CUHP manufacturers who sell covered equipment in the U.S market. DOE determined that nine of these manufacturers were large and three met the SBA's “small business” definition.
The first small manufacturer specialized in double-duct products. A review of its product literature and Web site showed that its only covered equipment were double-duct systems. Since this direct final rule does not amend the standards for double-duct equipment, this rule will not have an impact on this small manufacturer.
The second small manufacturer did not own any production assets for the covered equipment. The company outsourced the design and manufacture to a supplier. Thus, the small business would not face any capital conversion costs and very limited equipment conversion costs.
The third small manufacturer produced covered equipment that are subject to this direct final rule. Before issuing this final rule, DOE attempted to contact this small business manufacturer. However, the business chose not to participate in an MIA interview. Based on DOE's research, this third small manufacturer has three platforms with 11 models covered by the CUAC/CUHP rulemaking. However, it is difficult for DOE to discern the potential conversion costs required to comply with the direct final rule's standard since no IEER ratings were provided for these units.
Based on literature reviews, DOE believes this third small manufacturer specializes in custom and semi-custom products. This would suggest the manufacturer has less hard-tooling than their large competitors and their capital requirements would vary dramatically from the industy average. The company's capital conversion costs would likely be smaller in absolute dollars relative to large competitors. However, the small manufacturer would likely need to recover those costs over a lower volume of shipments.
To better assess the potential impacts of this rulemaking on small entities, DOE conducted a focused inquiry of the companies that could be small business manufacturers of equipment covered by this rulemaking. DOE conducted a market survey using available public information to identify potential small manufacturers. DOE's research involved industry trade association membership directories (including AHRI
DOE identified 14 manufacturers of CWAFs sold in the U.S. market. DOE determined that eleven manufacturers were large and three manufacturers met the SBA's definition of a “small business”.
Before issuing this document, DOE attempted to contact each small business CWAF equipment manufacturer it had identified. None of them, however, consented to formal interviews. DOE also attempted to obtain information about small business impacts while interviewing large manufacturers.
DOE identified one small gas-fired CWAF manufacturer and two small oil-fired CWAF manufacturers. The gas-fired CWAF manufacturer accounts for 17 of the 250 gas-fired CWAFs listings in the AHRI Directory,
With respect to oil-fired small business CWAF manufacturers, the first of these entities DOE examined accounts for 11 of the 16 oil-fired CWAFs listings in the AHRI Directory. This manufacturer produces some of the most efficient products on the market at 92-percent TE. Similarly, the second small oil-fired manufacturer produces the most efficient non-condensing equipment on the market at 84-percent TE. These two small oil-fired manufacturers would unlikely be at a technological disadvantage relative to its competitors at the recommended TSL. It is possible the small manufacturers would have a competitive advantage given its technological lead and experience in the niche market of high-efficiency commercial oil-fired warm air furnaces.
Since CWAFs have relatively low sales volumes, and because the industry as a whole generally produces equipment at the baseline, DOE believes the average impacts will be similar for large and small business manufacturers. DOE was unable to identify any publicly available information that would lead to a conclusion that small manufacturers would be differentially impacted by this direct final rule. Therefore, DOE assumed that small business manufacturers would face similar conversion costs as larger businesses. However, the small CWAF manufacturers may need to allocate a greater portion of their technical resources or may need to access outside capital to support the transition to the direct final rule's standard.
DOE is not aware of any rules or regulations that duplicate, overlap, or conflict with the rule being considered today.
The discussion above analyzes impacts on small businesses that would result from the direct final rule. In addition to the other TSLs being considered, the direct final rule TSDs analyzing the potential impacts from standards for CUACs/CUHPs and CWAFs include an analysis of the following policy alternatives: (1) No change in standard; (2) consumer rebates; (3) consumer tax credits; (4) manufacturer tax credits; (5) voluntary energy efficiency targets; and (6) bulk government purchases. While these alternatives may mitigate to some varying extent the economic impacts on small entities compared to the adopted standards, DOE does not intend to consider these alternatives further because in several cases, they would not be feasible to implement without authority and funding from Congress, and in all cases, DOE has determined that the energy savings of these alternatives are significantly smaller than those that are expected to result from adoption of the standards (0.2 percent to 2.4 percent of the energy savings from the adopted standards for CUACs/CUHPs, and less than 0.1 percent to 46 percent for CWAFs).
Further, EPCA provides that a manufacturer whose annual gross revenue from all of its operations does not exceed $8,000,000 may apply for an exemption from all or part of an energy conservation standard for a period not longer than 24 months after the effective date of a final rule establishing the standard. Additionally, Section 504 of the Department of Energy Organization Act, 42 U.S.C. 7194, authorizes the Secretary to adjust a rule issued under EPCA in order to prevent “special hardship, inequity, or unfair distribution of burdens” that may be imposed on that manufacturer as a result of such rule. See 10 CFR part 430, subpart E, and part 1003 for additional details.
Manufacturers of CUACs/CUHPs and CWAFs must certify to DOE that their equipment complies with any applicable energy conservation standards. In certifying compliance, manufacturers must test their equipment according to the DOE test procedures for CUACs/CUHPs and CWAFs, including any amendments adopted for those test procedures. DOE has established regulations for the certification and recordkeeping requirements for all covered consumer products and commercial equipment, including CUACs/CUHPs and CWAFs. 76 FR 12422 (March 7, 2011); 80 FR 5099 (Jan. 30, 2015). The collection-of-information requirement for certification and recordkeeping is subject to review and approval by OMB under the Paperwork Reduction Act (“PRA”). This requirement has been approved by OMB under OMB control number 1910–1400. The public
Notwithstanding any other provision of the law, no person is required to respond to, nor shall any person be subject to a penalty for failure to comply with, a collection of information subject to the requirements of the PRA, unless that collection of information displays a currently valid OMB Control Number.
Pursuant to the National Environmental Policy Act of 1969 (“NEPA”), DOE has determined that the rule fits within the category of actions included in Categorical Exclusion (“CX”) B5.1 and otherwise meets the requirements for application of a CX. See 10 CFR part 1021, app. B, B5.1(b); § 1021.410(b) and app. B, B(1)–(5). The rule fits within the category of actions because it is a rulemaking that establishes energy conservation standards for consumer products or industrial equipment, and for which none of the exceptions identified in CX B5.1(b) apply. Therefore, DOE has made a CX determination for this rulemaking, and DOE does not need to prepare an Environmental Assessment or Environmental Impact Statement for this rule. DOE's CX determination for this rule is available at
Executive Order 13132, “Federalism,” 64 FR 43255 (August 10, 1999) imposes certain requirements on Federal agencies formulating and implementing policies or regulations that preempt State law or that have Federalism implications. The Executive Order requires agencies to examine the constitutional and statutory authority supporting any action that would limit the policymaking discretion of the States and to carefully assess the necessity for such actions. The Executive Order also requires agencies to have an accountable process to ensure meaningful and timely input by State and local officials in the development of regulatory policies that have Federalism implications. On March 14, 2000, DOE published a statement of policy describing the intergovernmental consultation process it will follow in the development of such regulations. 65 FR 13735. DOE has examined this direct final rule and has determined that it would not have a substantial direct effect on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government. EPCA governs and prescribes Federal preemption of State regulations as to energy conservation for the equipment subject to this direct final rule. States can petition DOE for exemption from such preemption to the extent, and based on criteria, set forth in EPCA. (42 U.S.C. 6297) Therefore, no further action is required by Executive Order 13132.
With respect to the review of existing regulations and the promulgation of new regulations, section 3(a) of Executive Order 12988, “Civil Justice Reform,” imposes on Federal agencies the general duty to adhere to the following requirements: (1) Eliminate drafting errors and ambiguity; (2) write regulations to minimize litigation; (3) provide a clear legal standard for affected conduct rather than a general standard; and (4) promote simplification and burden reduction. 61 FR 4729 (Feb. 7, 1996). Regarding the review required by section 3(a), section 3(b) of Executive Order 12988 specifically requires that Executive agencies make every reasonable effort to ensure that the regulation: (1) Clearly specifies the preemptive effect, if any; (2) clearly specifies any effect on existing Federal law or regulation; (3) provides a clear legal standard for affected conduct while promoting simplification and burden reduction; (4) specifies the retroactive effect, if any; (5) adequately defines key terms; and (6) addresses other important issues affecting clarity and general draftsmanship under any guidelines issued by the Attorney General. Section 3(c) of Executive Order 12988 requires Executive agencies to review regulations in light of applicable standards in section 3(a) and section 3(b) to determine whether they are met or it is unreasonable to meet one or more of them. DOE has completed the required review and determined that, to the extent permitted by law, this direct final rule meets the relevant standards of Executive Order 12988.
Title II of the Unfunded Mandates Reform Act of 1995 (“UMRA”) requires each Federal agency to assess the effects of Federal regulatory actions on State, local, and Tribal governments and the private sector. Pub. L. 104–4, sec. 201 (codified at 2 U.S.C. 1531). For a regulatory action likely to result in a rule that may cause the expenditure by State, local, and Tribal governments, in the aggregate, or by the private sector of $100 million or more in any one year (adjusted annually for inflation), section 202 of UMRA requires a Federal agency to publish a written statement that estimates the resulting costs, benefits, and other effects on the national economy. (2 U.S.C. 1532(a), (b)) The UMRA also requires a Federal agency to develop an effective process to permit timely input by elected officers of State, local, and Tribal governments on a “significant intergovernmental mandate,” and requires an agency plan for giving notice and opportunity for timely input to potentially affected small governments before establishing any requirements that might significantly or uniquely affect them. On March 18, 1997, DOE published a statement of policy on its process for intergovernmental consultation under UMRA. 62 FR 12820. DOE's policy statement is also available at
DOE has concluded that this direct final rule may require expenditures of $100 million or more in any one year on the private sector. Such expenditures may include: (1) Investment in research and development and in capital expenditures by CUAC/CUHP and CWAF manufacturers in the years between the direct final rule and the compliance date for the new standards, and (2) incremental additional expenditures by consumers to purchase higher-efficiency CUACs/CUHPs and CWAFs.
Section 202 of UMRA authorizes a Federal agency to respond to the content requirements of UMRA in any other statement or analysis that accompanies the direct final rule. (2 U.S.C. 1532(c)) The content requirements of section 202(b) of UMRA relevant to a private sector mandate substantially overlap the economic analysis requirements that apply under section 325(o) of EPCA and Executive Order 12866. The
Under section 205 of UMRA, the Department is obligated to identify and consider a reasonable number of regulatory alternatives before promulgating a rule for which a written statement under section 202 is required. (2 U.S.C. 1535(a)) DOE is required to select from those alternatives the most cost-effective and least burdensome
Section 654 of the Treasury and General Government Appropriations Act, 1999 (Pub. L. 105–277) requires Federal agencies to issue a Family Policymaking Assessment for any rule that may affect family well-being. This direct final rule would not have any impact on the autonomy or integrity of the family as an institution. Accordingly, DOE has concluded that it is not necessary to prepare a Family Policymaking Assessment.
Pursuant to Executive Order 12630, “Governmental Actions and Interference with Constitutionally Protected Property Rights,” 53 FR 8859 (March 18, 1988), DOE has determined that this direct final rule would not result in any takings that might require compensation under the Fifth Amendment to the U.S. Constitution.
Section 515 of the Treasury and General Government Appropriations Act, 2001 (44 U.S.C. 3516, note) provides for Federal agencies to review most disseminations of information to the public under information quality guidelines established by each agency pursuant to general guidelines issued by OMB. OMB's guidelines were published at 67 FR 8452 (Feb. 22, 2002), and DOE's guidelines were published at 67 FR 62446 (Oct. 7, 2002). DOE has reviewed this direct final rule under the OMB and DOE guidelines and has concluded that it is consistent with applicable policies in those guidelines.
Executive Order 13211, “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use,” 66 FR 28355 (May 22, 2001), requires Federal agencies to prepare and submit to OIRA at OMB, a Statement of Energy Effects for any significant energy action. A “significant energy action” is defined as any action by an agency that promulgates or is expected to lead to promulgation of a final rule, and that: (1) Is a significant regulatory action under Executive Order 12866, or any successor order; and (2) is likely to have a significant adverse effect on the supply, distribution, or use of energy, or (3) is designated by the Administrator of OIRA as a significant energy action. For any significant energy action, the agency must give a detailed statement of any adverse effects on energy supply, distribution, or use should the proposal be implemented, and of reasonable alternatives to the action and their expected benefits on energy supply, distribution, and use.
DOE has concluded that this regulatory action, which sets forth amended energy conservation standards for CUACs/CUHPs and CWAFs, is not a significant energy action because the standards are not likely to have a significant adverse effect on the supply, distribution, or use of energy, nor has it been designated as such by the Administrator at OIRA. Accordingly, DOE has not prepared a Statement of Energy Effects on this direct final rule.
On December 16, 2004, OMB, in consultation with the Office of Science and Technology Policy (OSTP), issued its Final Information Quality Bulletin for Peer Review (the Bulletin). 70 FR 2664 (Jan. 14, 2005). The Bulletin establishes that certain scientific information shall be peer reviewed by qualified specialists before it is disseminated by the Federal Government, including influential scientific information related to agency regulatory actions. The purpose of the bulletin is to enhance the quality and credibility of the Government's scientific information. Under the Bulletin, the energy conservation standards rulemaking analyses are “influential scientific information,” which the Bulletin defines as “scientific information the agency reasonably can determine will have, or does have, a clear and substantial impact on important public policies or private sector decisions.”
In response to OMB's Bulletin, DOE conducted formal in-progress peer reviews of the energy conservation standards development process and analyses and has prepared a Peer Review Report pertaining to the energy conservation standards rulemaking analyses. Generation of this report involved a rigorous, formal, and documented evaluation using objective criteria and qualified and independent reviewers to make a judgment as to the technical/scientific/business merit, the actual or anticipated results, and the productivity and management effectiveness of programs and/or projects. The “Energy Conservation Standards Rulemaking Peer Review Report” dated February 2007 has been disseminated and is available at the following Web site:
As required by 5 U.S.C. 801, DOE will report to Congress on the promulgation of this direct final rule prior to its effective date. The report will state that it has been determined that the rule is a “major rule” as defined by 5 U.S.C. 804(2). DOE also will submit the supporting analyses to the Comproller General in the U.S. Government Accountability Office (“GAO”) and make them available to each House of Congress.
The Secretary of Energy has approved publication of this direct final rule.
Administrative practice and procedure, Confidential business information, Energy conservation, Household appliances, Imports, Intergovernmental relations, Reporting and recordkeeping requirements, Small businesses.
For the reasons set forth in the preamble, DOE amends part 431 of chapter II, subchapter D, of title 10 of the Code of Federal Regulations, as set forth below:
42 U.S.C. 6291–6317.
(a)
(1) For gas-fired commercial warm air furnaces manufactured starting on January 1, 1994, until January 1, 2023, the TE at the maximum rated capacity (rated maximum input) must be not less than 80 percent; and
(2) For gas-fired commercial warm air furnaces manufactured starting on January 1, 2023, the TE at the maximum rated capacity (rated maximum input) must be not less than 81 percent.
(b)
(1) For oil-fired commercial warm air furnaces manufactured starting on January 1, 1994, until January 1, 2023, the TE at the maximum rated capacity (rated maximum input) must be not less than 81 percent; and
(2) For oil-fired commercial warm air furnaces manufactured starting on January 1, 2023, the TE at the maximum rated capacity (rated maximum input) must be not less than 82 percent.
(1) Is either a horizontal single package or split-system unit; or a vertical unit that consists of two components that may be shipped or installed either connected or split;
(2) Is intended for indoor installation with ducting of outdoor air from the building exterior to and from the unit, as evidenced by the unit and/or all of its components being non-weatherized, including the absence of any marking (or listing) indicating compliance with UL 1995, “Heating and Cooling Equipment,” or any other equivalent requirements for outdoor use;
(3)(i) If it is a horizontal unit, a complete unit has a maximum height of 35 inches; (ii) If it is a vertical unit, a complete unit has a maximum depth of 35 inches; and
(4) Has a rated cooling capacity greater than or equal to 65,000 Btu/h and up to 300,000 Btu/h.
The revisions read as follows:
(b) Each commercial air conditioner or heat pump (not including single package vertical air conditioners and single package vertical heat pumps, packaged terminal air conditioners and packaged terminal heat pumps, computer room air conditioners, and variable refrigerant flow systems) manufactured starting on the compliance date listed in the corresponding table must meet the applicable minimum energy efficiency standard level(s) set forth in Tables 1 through 6 of this section.
(c) Each packaged terminal air conditioner (PTAC) and packaged terminal heat pump (PTHP) manufactured starting on January 1, 1994, but before October 8, 2012 (for standard size PTACs and PTHPs) and before October 7, 2010 (for non-standard size PTACs and PTHPs) must meet the applicable minimum energy efficiency standard level(s) set forth in Table 7 of this section. Each standard size PTAC and PTHP manufactured starting on October 8, 2012, and each non-standard size PTAC and PTHP manufactured starting on October 7, 2010, must meet the applicable minimum energy efficiency standard level(s) set forth in Table 6 of this section.
Environmental Protection Agency (EPA).
Proposed rule; grant of reconsideration.
The Environmental Protection Agency (EPA) is proposing to amend specific provisions in the Greenhouse Gas Reporting Rule to streamline and improve implementation of the rule, to improve the quality and consistency of the data collected under the rule, and to clarify or provide minor updates to certain provisions that have been the subject of questions from reporting entities. This action also proposes confidentiality determinations for the reporting of certain data elements to the program. This action also proposes action in response to a petition to reconsider specific aspects of the Greenhouse Gas Reporting Rule.
Comments must be received on or before February 29, 2016.
Submit your comments, identified by Docket ID No. EPA–HQ–OAR–2015–0526, to the Federal eRulemaking Portal:
Carole Cook, Climate Change Division, Office of Atmospheric Programs (MC–6207J), Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone number: (202) 343–9263; fax number: (202) 343–2342; email address:
Table 1 of this preamble is not intended to be exhaustive, but rather provides a guide for readers regarding facilities likely to be affected by this action. Other types of facilities than those listed in the table could also be subject to reporting requirements. To determine whether you are affected by this action, you should carefully examine the applicability criteria found in 40 CFR part 98, subpart A or the relevant criteria in the sections related to industrial gas suppliers and direct emitters of GHGs. If you have questions regarding the applicability of this action
The first section of this preamble contains background information regarding the origin of the proposed amendments. This section also discusses the EPA's legal authority under the CAA to promulgate (including subsequent amendments to) the Greenhouse Gas Reporting Rule, codified at 40 CFR part 98 (hereinafter referred to as “Part 98”) and the EPA's legal authority to make confidentiality determinations for new or revised data elements required by this amendment or for existing data elements for which a confidentiality determination has not previously been proposed. Section I of this preamble also discusses when the proposed amendments would apply and provides additional information regarding materials referenced in this rulemaking. Section II of this preamble describes the types of amendments included in this rulemaking, and includes the rationale for each type of proposed change. Section III of this preamble is organized by Part 98 subpart and contains detailed information on the proposed revisions to each subpart and the rationale for the proposed revisions in each section. Section IV of this preamble discusses the proposed confidentiality determinations for new or substantially
The GHGRP is a well-known, reliable source for high-quality, timely greenhouse gas emissions data that enables key stakeholders to understand greenhouse gas emissions, identify emission reduction opportunities, and take action. Since the first year of data collection through the GHGRP, the EPA has responded to tens of thousands of questions from reporters, engaged in stakeholder outreach through compliance assistance webinars, solicited feedback via a public testing process to help improve the EPA's electronic Greenhouse Gas Reporting Tool (e-GGRT), and learned about various site specific scenarios via interaction with reporters during the verification of submitted data. Through these extensive outreach efforts, the EPA has improved our understanding of the technical challenges and burden associated with implementation of the Part 98 provisions, as well as issues that may impact the quality of the data received. The proposed changes would amend specific provisions in the Greenhouse Gas Reporting Rule to streamline and improve implementation of the rule, improve the quality and consistency of the data collected under the rule, and clarify or provide minor updates to certain provisions that have been the subject of questions and feedback from reporting entities.
The EPA is proposing amendments that can be categorized as follows:
• Revisions to streamline implementation and reduce burden. These changes reduce or simplify requirements in a manner that would ease burden on reporters and the EPA. The changes would also improve the usefulness of data for the public. Such revisions include revising requirements to focus EPA and reporter resources on relevant data, removing reporting requirements for specific facilities that report little to no emissions, or removing reported data elements that are no longer necessary.
• Amendments to improve quality of data. These amendments are needed to ensure that accurate data are being collected under the rule and would expand monitoring or reporting requirements that are necessary to improve verification and improve the accuracy of data used to inform the Inventory of U.S. Greenhouse Gas Emissions and Sinks (hereafter referred to as the “U.S. GHG Inventory”).
• Minor amendments to better reflect industry processes and emissions. Such revisions include amendments to calculation, monitoring, or measurement methods that would address prior petitioner or commenter concerns (e.g., amendments that provide additional flexibility for facilities or that more accurately reflect industry processes and emissions).
• Minor clarifications and corrections to improve understanding of the rule. Such revisions include the following: Corrections to errors in terms and definitions in certain equations; clarifications that provide additional information for reporters to better or more fully understand compliance obligations; changes to correct cross references within and between subparts; and other editorial or harmonizing changes that would improve the public's understanding of the rule.
This action also proposes to establish confidentiality determinations for the reporting of certain data elements added or revised in these proposed amendments, and for certain existing data elements for which no confidentiality determination has been previously proposed.
The proposed revisions are anticipated to increase burden for Part 98 reporters in cases where they would expand current applicability, monitoring, or reporting, and are anticipated to decrease burden for reporters in cases where they would streamline Part 98 to remove notification or reporting requirements or simplify the data that must be reported. The estimated incremental change in burden from the proposed amendments to Part 98 includes burden associated with: (1) Changes to the reporting requirements by adding, revising, or removing existing reporting requirements; (2) revisions to the applicability of subparts such that additional facilities would be required to report; and (3) additional monitoring requirements for underground coal mines. Many of the amendments that the EPA is proposing in this action are not anticipated to have a significant impact on burden. As discussed in section I.E of this preamble, we are proposing to implement these changes over reporting years 2016, 2017, and 2018 in order to stagger the implementation of these changes over time. The burden has subsequently been determined based on when the proposed revisions would be implemented in each year (
The GHG Reporting Rule was published in the
The EPA subsequently proposed and finalized amendments to various subparts, including subparts in this action. The amendments generally did not change the basic requirements of Part 98, but were intended to improve clarity and ensure consistency across the calculation, monitoring, and data reporting requirements. The EPA issued additional rules in 2010 finalizing the requirements for subparts T, FF, II, and TT (75 FR 39736, July 12, 2010); subparts I, L, DD, QQ, and SS (75 FR 74774, December 1, 2010); and subparts RR and UU (75 FR 75060, December 1, 2010). Following the promulgation of these subparts, the EPA finalized several technical and clarifying amendments to these and other subparts under the GHGRP. A number of subparts have been revised since promulgation (75 FR 79092, December 17, 2010; 76 FR 73866, November 29, 2011; 77 FR 10373, February 22, 2012; 77 FR 29935, May 21, 2012; 77 FR 51477, August 24, 2012; 78 FR 68162, November 13, 2013; 78 FR 71904, November 29, 2013; 79 FR 63750, October 24, 2014; and 79 FR 73750, December 11, 2014). The amendments in this action are a continuation of the effort to improve the GHGRP and address issues identified during implementation.
The EPA is proposing these rule amendments under its existing CAA authority provided in CAA section 114. As stated in the preamble to the 2009 final GHG reporting rule (74 FR 56260), CAA section 114(a)(1) provides the EPA broad authority to require the information proposed to be gathered by this rule because such data would inform and are relevant to the EPA's carrying out a wide variety of CAA provisions. See the preambles to the proposed and final GHG reporting rule for further information.
In addition, the EPA is proposing confidentiality determinations for proposed new, revised, and existing data elements in Part 98 under its authorities provided in sections 114, 301, and 307 of the CAA. Section 114(c) of the CAA requires that the EPA make publicly available information obtained under CAA section 114, except for information (excluding emission data) that qualifies for confidential treatment. The Administrator has determined that this proposed rule is subject to the provisions of section 307(d) of the CAA. Generally section 307(d) contains a set of procedures relating to the issuance and review of certain enumerated CAA rules.
In this action, the EPA is proposing: (1) Numerous amendments to Part 98 including subpart-specific revisions that would streamline implementation of Part 98, improve the quality of the data collected under the rule, update certain provisions to more accurately reflect industry processes and emissions, and other corrections, as described in sections II and III of this preamble; and (2) new or revised confidentiality determinations for data elements that are added or revised in the proposed amendments or for certain existing data elements, as described in section IV of this preamble. The EPA is planning to phase in implementation of the proposed requirements depending on the nature of the revision. Some of the amendments would apply in RY2016, some in RY2017, and some in RY2018. This section describes when each of the proposed amendments would apply.
We are proposing that amendments to 40 CFR part 98, subparts I (Electronics Manufacturing) and HH (Municipal Solid Waste Landfills), with related revisions to subpart A (General Provisions), would apply to the RY2016 reports, which must be submitted by March 31, 2017. The remaining amendments proposed in this action would apply to annual reports submitted for RY2017, except for amendments to V (Nitric Acid Production), Y (Petroleum Refineries), FF (Underground Coal Mines) and OO (Suppliers of Industrial Greenhouse Gases) which would apply to reports for RY2018.
We are proposing to implement these revisions over reporting years 2016, 2017, and 2018 in order to stagger the implementation of these changes over time, in consideration of the types of changes being made and the associated revisions needed to implement them, including impacts to reporters and revisions to EPA's e-GGRT. Specifically, some of the proposed changes include revisions to software that would need to be updated in e-GGRT. The time phasing also allows sufficient lead time for reporters to implement the proposed changes following the promulgation of the final rule revisions. For example, where the proposed changes would require reporters to collect new data that are not readily available or that could not be determined from existing monitoring and recordkeeping, the EPA would not apply these changes to RY2016 reports. The proposed schedule also provides sufficient time for new reporters who would become subject to Part 98 as a result of the proposed amendments to acquire monitoring equipment and begin collecting data. The amendments that would apply to RY2016, RY2017, and RY2018 reports are discussed in sections I.E.1, I.E.2, and I.E.3 of this preamble.
Table 3 of this preamble lists the affected subparts and proposed changes that would apply to RY2016.
We are proposing that all changes to subparts I and HH, and minor revisions to subpart A, would apply to reports for RY2016, which must be submitted by March 31, 2017. For subpart I, we are proposing several revisions that would improve the quality of the data collected. For example, we are proposing to revise the requirements of the technology triennial report in 40 CFR 98.96(y), which applies to semiconductor manufacturing facilities with emissions from subpart I processes greater than 40,000 metric tons of carbon dioxide equivalent (mtCO2e) per year. Per the requirements of 40 CFR 98.96(y)(1), facilities are required to submit the first triennial report on March 31, 2017. The changes we are proposing to 40 CFR 98.96(y) would clarify the types of data and measurements to be submitted with the triennial report, but would not fundamentally alter the data reported or require additional data collection from reporters. Specifically, we are clarifying that where reporters provide any utilization and by-product formation rates and/or destruction or removal efficiency data in the triennial report, they must also include information on the methods and conditions under which the data were collected, where available (see section III.F of this preamble for additional information). We are proposing to implement the changes to subpart I in RY2016 in order to ensure that the data submitted in the triennial reports submitted on March 31, 2017 reflects these methods and conditions, which will help the EPA to more efficiently review the reported data. In addition to the proposed changes to 40 CFR 98.96(y), the EPA is proposing revisions to improve the methodology used to calculate the fraction of fluorinated-GHG and fluorinated-GHG byproduct destroyed or removed in a fab using the stack testing methodology.
Under subpart HH, we are proposing several revisions to improve the quality of the data collected, better align the rule requirements with industry operating practices, and streamline the reporting requirements. We are also proposing one related change to subpart A of Part 98 to update the definition of “gas collection system or landfill gas collection system” in 40 CFR 98.6. These revisions, which are described in section III.S of this preamble, are proposed to apply to RY2016 reports because they provide additional clarifications and flexibility regarding the existing regulatory requirements that address questions raised by reporters during implementation.
We have determined that it would be feasible for existing reporters to implement the proposed changes to subparts A, I, and HH for RY2016 because these changes are consistent with the data collection and calculation methodologies in the current rule. The proposed revisions would not add new monitoring requirements, and would not substantially affect the type of information that must be collected. The owners or operators are not required to actually submit RY2016 reports until March 31, 2017, which is three months or more after we expect the final rule amendments based on this proposal to be published, thus providing ample opportunity for reporters to adjust to the amendments.
Table 4 of this preamble lists the affected subparts and proposed changes that would apply to RY2017. For these revisions, reporters would submit an annual report on March 31, 2018.
The changes to subparts listed in Table 4 of this preamble would apply to the annual reports submitted for RY2017 on March 31, 2018; these changes are proposed to apply to the 2017 reporting year in order to allow for adequate time for the agency to integrate the revisions through e-GGRT and the Inputs Verification Tool (IVT), as well as prepare to incorporate the revisions into other GHGRP datasets and publications. The changes to subparts included in Table 4 of this preamble would be feasible for reporters to implement for RY2017 because these changes are consistent with the data collection and calculation methodologies in the current rule. In most cases, the proposed revisions include minor revisions such as editorial corrections, corrections to cross-references, and technical clarifications regarding the existing regulatory requirements. Where calculation equations are proposed to be modified, the changes generally clarify terms in the emission calculation equations and do not materially affect monitoring requirements or how emissions are calculated. In some cases, we are adding flexibility by providing alternative monitoring methods or missing data procedures that would reduce burden on reporters. For example, in subpart AA (Pulp and Paper Manufacturing), for missing measurements of the mass of spent liquor solids or spent pulping liquor flow rates, we are proposing to allow reporters to use the daily mass of spent liquor solids fired that are currently reported under 40 CFR 63, subpart MM (National Emission Standards for Hazardous Air Pollutants for Chemical Recovery Combustion Sources at Kraft, Soda, Sulfite, and Stand-Alone Semichemical Pulp Mills) as an alternative to maximum mass and flow rate values currently required in 40 CFR 98.275(b) (see section III.O of this preamble for additional information). Other proposed changes would reduce the type of information that must be collected;
We are proposing that the revisions to the subparts listed in Table 5 of this preamble would apply to annual reports submitted for RY2018, which must be submitted by March 31, 2019.
We are proposing that revisions to subparts V, Y, FF, and OO, and related changes to 40 CFR 98.7(l)(1) and Table A–5 of subpart A, would apply to RY2018, with reporters following the revised rule requirements beginning January 1, 2018. In several cases, the proposed changes would revise the applicability of a source category to certain facilities or significantly revise existing calculation or monitoring methodologies. For example, we are proposing to revise the definition of the industrial gas supplier source category in 40 CFR part 98, subpart OO to include facilities that destroy, but do not produce, fluorinated GHGs and fluorinated HTFs. These proposed changes could expand the applicability of Part 98 to additional facilities that were not previously required to report under the rule; these facilities would require more time to acquire and install monitoring equipment and begin collecting data under Part 98. Similarly, we are proposing to revise the calculation methodology for delayed coking units in 40 CFR part 98, subpart Y (Petroleum Refineries) to better reflect industry emissions (see section III.M of this preamble).
As discussed in section III.R of this preamble, we are proposing some methodological changes to subpart FF to clarify the type of facilities included in the source category and revise the monitoring and data collection requirements to improve the quality of the data collected. We are proposing a related revision to 40 CFR 98.7(l)(1) in
In past rulemakings, the EPA has typically required monitoring to begin a few months after finalization of revised rules, and has offered Best Available Monitoring Methods (BAMM) to be used temporarily to provide sufficient time for facilities to come into full compliance with the newly finalized monitoring methods. In this action, to avoid the need to offer the use of BAMM and to stagger the burden associated with making revisions to e-GGRT, we are proposing that the revisions to these subparts would apply to RY2018 reports. If finalized, subpart V, Y, FF, and OO reporters, including new reporters, would begin following the revised rule requirements on January 1, 2018 and submit the first annual reports using the revised monitoring and data collection methods on March 31, 2019. This schedule would allow at least one year for subpart V, Y, FF, and OO reporters to acquire, install, and calibrate any new monitoring equipment, as well as implement any changes to existing monitoring methods, for the 2018 reporting year. The proposed timeline also allows sufficient time for the agency to integrate any associated changes to reporting requirements in the affected subparts into e-GGRT and other GHGRP activities, such as verification.
The EPA is proposing one related change to subpart A that could apply to certain subpart FF reporters prior to January 1, 2018. In keeping with the proposed changes discussed in section III.A.1 of this preamble, we are proposing to revise 40 CFR 98.2(i) of subpart A to streamline the reporting requirements for closed coal mines. These proposed revisions would apply beginning January 1, 2017, consistent with the proposed revisions to 40 CFR 98.2 listed in Table 4 of this preamble, and could affect owners and operators of abandoned underground mines (see section III.A and III.R of this preamble for additional information). All other proposed revisions related to subpart FF would apply beginning January 1, 2018 for the reasons described above.
This preamble references several documents developed to support the proposed rulemaking. These documents provide additional information regarding the proposed changes to Part 98, and supplementary information which the EPA considered in the development of the proposed revisions. These documents are referenced in sections II through V of this preamble and are available in the docket to this rulemaking or other rulemaking dockets, as follows:
• “Table of 2015 Revisions to the Greenhouse Gas Reporting Rule.” EPA memorandum summarizing the less substantive minor corrections, clarifications, and harmonizing revisions in the proposed rule, as discussed in section II of this preamble. Available in the docket for this proposed rulemaking, Docket Id. No. EPA–HQ–OAR–2015–0526.
• “Re: Strong Nitric Acid Facilities in the U.S.” From Natalie Tang, EPA to Alexis McKittrick and Mausami Desai, EPA, dated January 29, 2015. Memorandum supporting proposed revisions to subpart V (Nitric Acid Production) as discussed in section III.K of this preamble. Available in the docket for this proposed rulemaking, Docket Id. No. EPA–HQ–OAR–2015–0526.
• “Request to Consider IPCC Balanced EDC/VCM Process Studies and Data for the Elimination of e-GGRT Validation Messages at VCM Production Facilities Reporting Under Subpart X.” Letter received from Occidental Chemical Company, July 10, 2015, as discussed in section III.L of this preamble. Available in the docket for this proposed rulemaking, Docket Id. No. EPA–HQ–OAR–2015–0526.
• “Proposed Changes to Flare Pilot Gas Reporting Requirements under the Greenhouse Gas Reporting Program (GHGRP).” From Jeff Coburn, Leslie Pearce and Kevin Bradley, RTI International (RTI) to Brian Cook, EPA, dated July 10, 2015. Memorandum supporting proposed revisions to subpart Y (Petroleum Refineries) as discussed in section III.M of this preamble. Available in the docket for this proposed rulemaking, Docket Id. No. EPA–HQ–OAR–2015–0526.
• “Revised Emission Methodology for Delayed Coking Units.” From Jeff Coburn, RTI to Brian Cook, EPA, dated June 4, 2015. Memorandum supporting proposed revisions to subpart Y (Petroleum Refineries) as discussed in section III.M of this preamble. Available in the docket for this proposed rulemaking, Docket Id. No. EPA–HQ–OAR–2015–0526.
• “Evaluating Possible VAM Emissions Estimation Errors Based on Different Sampling Intervals (Quarterly, Monthly, Weekly).” Ruby Canyon Engineering, dated June 10, 2015. Memorandum supporting revisions to subpart FF (Underground Coal Mines) as discussed in section III.R of this preamble. Available in the docket for this proposed rulemaking, Docket Id. No. EPA–HQ–OAR–2015–0526.
• “Use of Inspection Data from the Mine Safety Health Administration for Reporting Quarterly Methane Liberation from Mine Ventilation Shafts.” From Clark Talkington, Advanced Resources International, Inc. (ARI) to Cate Hight, EPA, dated November 13, 2015. Memorandum supporting revisions to subpart FF (Underground Coal Mines) as discussed in section III.R of this preamble. Available in the docket for this proposed rulemaking, Docket Id. No. EPA–HQ–OAR–2015–0526.
• “Review of Oxidation Studies and Associated Cover Depth in the Peer-Reviewed Literature.” From Kate Bronstein, Meaghan McGrath, and Jeff Coburn, RTI to Rachel Schmeltz, EPA, dated June 17, 2015, Memorandum supporting proposed revisions to subpart HH (Municipal Solid Waste Landfills) as discussed in section III.S of this preamble. Available in the docket for this proposed rulemaking, Docket Id. No. EPA–HQ–OAR–2015–0526.
• “Review of Site-Specific Industrial Waste Degradable Organic Content Data” from Jeff Coburn and Katherine Bronstein, RTI to Rachel Schmeltz, EPA, dated June 17, 2015. Memorandum supporting proposed revisions to subpart TT (Industrial Waste Landfills) as discussed in section III.Y of this preamble. Available in the docket for this proposed rulemaking, Docket Id. No. EPA–HQ–OAR–2015–0526.
• “Proposed Data Category Assignments and Confidentiality Determinations for Data Elements in the Proposed 2015 Revisions.” Memorandum listing all proposed new, substantially revised, and existing data elements with proposed category assignments and confidentiality determinations, as described in Section IV of this preamble. Available in the docket for this proposed rulemaking, Docket Id. No. EPA–HQ–OAR–2015–0526.
• “Final Evaluation of Competitive Harm from Disclosure of `Inputs to Equations' Data Elements Deferred to March 31, 2015.” Memorandum, September 2014. Available in Docket Id. No. EPA–HQ–OAR–2010–0929.
• “Summary of Evaluation of Greenhouse Gas Reporting Program (GHGRP) Part 98 `Inputs to Emission Equations' Data Elements Deferred Until 2013.” Memorandum, December 17, 2012. Available in the docket for this proposed rulemaking, Docket Id. No. EPA–HQ–OAR–2015–0526.
• “Final Data Category Assignments and Confidentiality Determinations for Part 98 Reporting Elements.” Memorandum, April 29, 2011. Available in Docket Id. No. EPA–HQ–OAR–2009–0924.
• “Assessment of Burden Impacts of 2015 Revisions to the Greenhouse Gas Reporting Rule.” Memorandum describing the costs of the proposed revisions to Part 98, as discussed in section V of this preamble. Available in the docket for this proposed rulemaking, Docket Id. No. EPA–HQ–OAR–2015–0526.
In this rulemaking, the EPA is proposing to include in a final EPA rule regulatory text for 40 CFR 98.7 that includes incorporation by reference. In accordance with requirements of 1 CFR 51.5, the EPA is proposing to incorporate by reference the following:
• Standard Test Methods for Determining the Biobased Content of Solid, Liquid, and Gaseous Samples using Radiocarbon Analysis (ASTM D6866–12), which would apply to subpart C reporters (see section III.B.2 of this preamble). These standards are available on the ASTM Web site (
• Inspection and sampling standards from the Coal Mine Safety and Health General Inspection Procedures Handbook Number: PH13–V–1 (February 2013) as published by the Mine Safety and Health Administration (MSHA), which would apply to subpart FF reporters (see section III.R.2 of this preamble). These standards are available free of charge through the MSHA Web site (
Because these standards do not present a significant financial burden to reporters, the EPA has determined that these methods are reasonably available. The EPA has also made, and will continue to make, these documents generally available in hard copy at the appropriate EPA office (see the
In this action, the EPA is proposing to revise specific provisions in Part 98 to simplify and streamline implementation of the rule, improve the quality and consistency of the data collected under the rule, and to clarify or provide minor updates to certain provisions that have been the subject of questions and feedback from reporting entities. The EPA has identified four categories of changes that we are proposing in this rulemaking, which include the following:
• Revisions to streamline implementation of the rule by reducing or simplifying requirements that would ease burden on reporters and the EPA, such as revising requirements to focus GHGRP and reporter resources on relevant data, removing reporting requirements for specific facilities which report little to no emissions, or removing reported data elements that are no longer necessary;
• Amendments that would expand monitoring, applicability, or reporting requirements that are necessary to enhance the quality of the data collected, improve verification of collected data under the GHGRP, and improve the accuracy of data included in the U.S. GHG Inventory;
• Other amendments, such as amendments to calculation, monitoring, or measurement methods that would address prior petitioner or commenter concerns (e.g., amendments that provide additional flexibility for facilities or that more accurately reflect industry processes and emissions).
• Minor clarifications and corrections, including: corrections to terms and definitions in certain equations; clarifications that provide additional information for reporters to better or more fully understand compliance obligations; changes to correct cross references within and between subparts; and other editorial or harmonizing changes that would improve the public's understanding of the rule.
Sections II.A through II.D of this preamble describe each of the above categories in more detail and provide rationale for the changes included in each category.
The proposed changes in this action would advance the EPA's goal of maximizing rule effectiveness. For example, these proposed changes would clarify existing rule provisions, thus enabling government, regulated entities, and the public to easily identify and understand rule requirements. In addition, specific changes such as increasing the flexibility given to reporting entities related to requesting extensions for revising annual reports would make compliance easier than non-compliance. The proposed changes also serve to clarify whether and when reporting requirements apply to a facility, and more specifically when a facility may discontinue reporting, thereby allowed a regulated entity to regularly assess their compliance and prevent noncompliance.
The proposed changes would also improve the EPA's ability to assess compliance by adding reporting elements that allow the EPA to more thoroughly verify GHG data and understand trends in emissions. For example, the proposed requirement to report the date of installation of any abatement equipment at Adipic Acid and Nitric Acid Production facilities will increase the EPA and public's understanding of the use of and trends in emissions reduction technologies. Lastly, the proposed changes further advance the ability of the Greenhouse Gas Reporting Program to provide access to quality data on greenhouse gas emissions by adding key data elements to improve the usefulness of the data. One example is the proposed addition of the reporting of emissions by state for Suppliers of Natural Gas (subpart NN reporters). This data will allow users of the GHGRP data to more easily identify the state within which the reporter operates, which will be useful for determining state level GHG totals associated with natural gas supply and increase transparency and usefulness of the data reported.
Additional details for the specific amendments proposed for each subpart are included in section III of this preamble. To reduce the length of this preamble, we have summarized the remaining less substantive minor corrections, clarifications, and harmonizing revisions in the memorandum, “Table of 2015 Revisions to the Greenhouse Gas Reporting Rule” (hereafter referred to as the “Table of Revisions”) available in the docket for this rulemaking (EPA–HQ–OAR–2015–0526). These changes include straightforward clarifications of
We are seeking public comment only on the issues specifically identified in this notice (including the changes listed in the Table of Revisions) for the identified subparts. We are not reopening other aspects of Part 98.
Following implementation of Part 98, the EPA has identified several areas of the rule which could be revised or simplified to improve the efficiency of the requirements or to reduce the burden on reporters and the EPA. We are consequently proposing several revisions that would streamline the requirements as well as improve implementation of the rule.
Several of the proposed revisions would clarify and revise the requirements of Part 98 in order to focus the GHGRP and reporter resources on the most relevant data. In some cases, we are proposing to revise requirements to reduce when facilities must report emissions, such as by clarifying requirements for facilities that may report very little or no emissions. The EPA does not anticipate a significant change in the overall reported emissions or a reduction in the quality of reported carbon dioxide equivalent (CO2e) emissions and supply. Removing these instances of reporting would also reduce burden on some reporters.
As an example, we are proposing to revise 40 CFR part 98, subpart FF to allow an underground coal mine to cease reporting after it has closed and its status is determined to be “abandoned” by MSHA. The CO
In addition, the EPA is proposing in this rulemaking that pilot gas, which is considered the gas used to maintain a pilot flame at the flare tip, may be excluded from the quantity of flare gas used to perform GHG emissions calculations for subparts Q (Iron and Steel Production), X (Petrochemical Production), and Y (Petroleum Refineries). The quantity of GHG emissions associated with pilot gas is very small relative to the total GHG emissions from a flare at petroleum refineries, petrochemical production facilities, and iron and steel production facilities. Eliminating the monitoring of this small quantity of emissions will not adversely impact the quality of the greenhouse gas data collected and may decrease the burden associated with monitoring the flare gas. We are proposing similar revisions to other subparts that simplify data collection for reporters and focus the provisions of the rule on the essential data that the EPA requires to review, assess, and verify reported emissions.
Other proposed revisions to the rule include changes that would streamline the rule, such as removing reported data elements that are no longer necessary. For example, for 40 CFR part 98, subpart LL (Suppliers of Coal-based Liquid Fuels), we are proposing to remove requirements of 40 CFR 98.386 that are no longer needed to support verification or other activities. In a prior notice, “2013 Revisions to the Greenhouse Gas Reporting Rule and Final Confidentiality Determinations for New or Substantially Revised Data Elements” (78 FR 71904, November 29, 2013, hereafter referred to as “2013 Revisions Rule”), we finalized amendments to subpart LL that removed requirements in 40 CFR 98.386 for suppliers to report the annual quantity of each product or natural gas liquid on the basis of the measurement method used. Subpart LL reporters are currently only required to report the total annual quantities of each product or natural gas liquid in metric tons or barrels supplied. In this action, we are proposing to remove the provisions of 40 CFR 98.386 that require suppliers to report the methods used to measure the quantities of each product reported. This change would harmonize with the previously finalized revisions which removed the requirement to report products by method and would reduce the burden on reporters.
We are also proposing certain revisions that would streamline the reporting and verification process. These proposed changes would ease the burden on reporters (e.g., by reducing the actions required of reporters) and improve agency implementation of the rule. For example, we are proposing to revise 40 CFR 98.2(i) to clarify the EPA's policies allowing reporters to cease reporting under Part 98. The existing provisions of 40 CFR 98.2(i) provide options for reporters to discontinue reporting when annual emissions are less than certain thresholds, or if process operations are permanently shut down. We are proposing to clarify when these requirements apply for suppliers, processes or operations that cease operation in the reporting year, and facilities where the operations are changed such that a process or operation no longer meets the “Definition of Source Category” for a subpart. These provisions are anticipated to streamline reporting by specifying when reporters are no longer required to report for a particular process or operation.
We are proposing similar changes to Part 98 which would improve the efficiency of the reporting process. The specific changes that we are proposing that are intended to streamline Part 98, as described in this section, are described for each subpart, as appropriate, in sections III.A through III.Y of this preamble.
The EPA is also proposing amendments in this action that would improve the existing applicability, monitoring, or reporting requirements of Part 98 in order to enhance the quality and accuracy of the data collected under the GHGRP, improve verification of collected data, and provide additional data to help improve estimates included in the U.S. GHG Inventory.
Several of the amendments in this action are being proposed to improve the quality of the data collected under the GHGRP. The data collected under Part 98 are used to inform the EPA's understanding of the relative emissions and distribution of emissions from specific industries, the factors that influence GHG emission rates, and to inform policy options and potential regulations. Following several years of implementation of the rule, the EPA has identified certain areas of the rule where clarifying amendments to source category definitions, revisions to calculation methodologies or monitoring methods, and revisions or additions to reporting requirements are needed to ensure that accurate data are being collected under the rule. For example, we are proposing revisions to subpart FF to revise the monitoring requirements for methane liberated from ventilation systems to remove the option to use quarterly testing by the MSHA. This change is being proposed because we have determined that the quarterly flowrate data gathered by
In another case, we are proposing to revise existing reporting requirements to collect more detailed facility data. For example, we are proposing to amend the reporting requirements of 40 CFR part 98, subpart O (HFC–22 Production and HFC–23 Destruction) to require reporting of the information under 40 CFR 98.156(a) at a process level. Currently, reporters are required to submit the annual mass of HCFC–22 produced, the annual mass of reactants fed into the process, the annual mass of HFC–23 emitted, and additional information under 40 CFR 98.156(a) at the facility level. Collecting this information on a process-level basis would further our understanding of emissions from HCFC–22 production processes and provide a more accurate emissions profile for this sector.
Some of the proposed amendments include revisions to existing reporting requirements to clarify the data that are currently reported or improve verification of reported data. For example, we are proposing amendments to 40 CFR part 98, subpart HH to add a requirement for landfills with gas collection systems to report the number of hours active gas flow was sent to each destruction device instead of the annual operating hours for each destruction device. This revision is needed in order for the EPA's reporting tool to accurately calculate a key variable in certain equations used to calculate emissions. Although the proposed change would require different data to be reported, it would improve verification of the existing data by reducing the number of reporters that override their equation results, resulting in fewer verification errors and follow-up messages to reporters.
We are also proposing several amendments to ensure data collected by the GHGRP adequately support the U.S. GHG Inventory. As described in the preamble of the proposed GHG Reporting Rule (74 FR 16448, April 10, 2009), the GHGRP is intended to supplement and complement the U.S. GHG Inventory by advancing the understanding of emission processes and monitoring methodologies for particular source categories or sectors. Specifically, the GHGRP complements the U.S. GHG Inventory by providing data from individual facilities and suppliers above certain thresholds to improve the assumptions and emissions values used in the U.S. GHG Inventory. The collected facility, unit, and process-level GHG data from the GHGRP provide and confirm the national statistics and emission estimates presented in the U.S. GHG Inventory, which are calculated using aggregated national data. These proposed amendments include clarifications to source category definitions, revisions to calculation methodologies, and revisions or additions to reporting requirements that will improve the accuracy of the data included in the U.S. GHG Inventory and improve our ability to inform the development of GHG policies and programs. For example, we are proposing revisions to 40 CFR part 98, subpart E (Adipic Acid Production) and 40 CFR part 98, subpart V (Nitric Acid Production) that would require reporting of the date of installation of any abatement systems (if applicable). The addition of these data elements would help improve the accuracy of trend estimates for these sectors in the U.S. GHG Inventory. Specifically, the proposed data elements would allow the agency to apply emission factors with and without abatement systems over the correct time periods using the reported dates.
The specific changes that we are proposing for each subpart, as appropriate, are described in sections III.A through III.Y of this preamble.
In addition to the amendments described in sections II.A and II.B of this preamble, the EPA is proposing other amendments to certain subparts of Part 98. Through outreach and communication with stakeholders, the EPA has identified certain aspects of the rule that may require substantive revision, such as amending calculation, monitoring, or measurement methods to provide flexibility for certain facilities, or to more accurately reflect industry processes and emissions. These changes would respond to comments raised by stakeholders in prior rulemakings and issues raised by petitioners for certain subparts, and would more closely align rule requirements with the processes conducted at specific facilities. For example, for 40 CFR part 98, subpart TT (Industrial Waste Landfills), we are proposing to add several waste types for pulp and paper, including associated degradable organic content (DOC) and k-values, to Table TT–1 of subpart TT to include common industrial waste subtypes. The EPA is proposing these revisions following comments on 2013 Revisions Rule, in which stakeholders requested the EPA add these common waste types to Table TT–1 of subpart TT. These proposed revisions would improve the accuracy of calculated emissions reported by these facilities.
Additional details for the amendments described in this section are discussed for each subpart, as appropriate, in sections III.A through III.Y of this preamble.
The EPA is proposing additional minor corrections, clarifications, and harmonizing revisions that would improve understanding of the rule. These revisions primarily include simple revisions of requirements to better reflect the EPA's intent, such as clarifying changes to definitions, calculation methodologies, monitoring and quality assurance requirements, missing data procedures, and reporting requirements. Some of these proposed changes result from questions raised by reporters through the GHGRP Help Desk or e-GGRT and are intended to resolve
In some cases, we are proposing minor amendments that would clarify general monitoring requirements, measurement methods, or reported data elements. These revisions include less substantive changes, such as simple corrections to calculation terms, revisions of cross-references, harmonizing changes (such as changes to terminology within a subpart for consistency), simple editorial corrections, and removal of redundant text. As discussed earlier in section II of this preamble, these less substantive revisions are summarized in the Table of Revisions available in the docket for this rulemaking (EPA–HQ–OAR–2015–0526).
This section summarizes the specific substantive amendments proposed for each Part 98 subpart, as generally described in section II of this preamble. Sections III.A through III.Z of this preamble also identify where additional minor corrections to a subpart are included in the Table of Revisions.
In this action, we are proposing several amendments, clarifications, and corrections to subpart A of Part 98. This section discusses the substantive changes to subpart A; additional minor amendments, corrections, and clarifications are summarized in the Table of Revisions available in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
For the reasons described in section II.A of this preamble, we are proposing several amendments that are intended to simplify and streamline the requirements of subpart A and increase the efficiency of the report submittal process. First, we are proposing to revise 40 CFR 98.2(i) to clarify the EPA's policies allowing reporters to cease reporting under Part 98. The existing provisions of 40 CFR 98.2(i)(1) and (2) provide options for reporters to discontinue reporting if annual emissions are less than 25,000 mtCO
The requirements of 40 CFR 98.2(i)(3) allow reporters to discontinue reporting if all processes or operations cease operation (e.g., plant closure). There has been confusion among reporters as to whether there is a similar provision to cease reporting for situations where a single process or operation ceases operation. The EPA is proposing to revise 40 CFR 98.2(i)(3) to specify that reporting is not required for any process or operation that ceases operation in the reporting years following the reporting year in which the process or operation ceased operation, provided the owner or operator submits a notification to the Administrator and explains the reasons for the cessation of operation. For example, if a facility previously reporting under 40 CFR part 98, subpart C (Stationary Fuel Combustion Sources) and 40 CFR part 98, subpart T (Magnesium Production) removes all of their combustion sources, but continues their magnesium casting operations under subpart T, the proposed revision to 40 CFR 98.2(i)(3) would clarify that this facility is exempt from the subpart C reporting of the combustion processes in the reporting years following the year in which the combustion sources ceased
In addition, there has been confusion regarding how Part 98 addresses situations where a facility no longer meets the “Definition of Source Category” specified in an applicable subpart. For example, subpart II of Part 98 (Industrial Wastewater Treatment) applies to anaerobic processes that treat wastewater from either meat processing operations (NAICS 3116) or fruit and vegetable processing (NAICS 3114). If a facility were subject to subpart II because it processes meat byproducts into human food, but switched its operations to producing animal food or to processing seafood rather than meat byproducts, then the processing plant would no longer meet the source category definition of “industrial wastewater treatment” in 40 CFR 98.350 because it no longer falls under the classification of NAICS 3116. The facility, therefore, would not be subject to reporting under subpart II. The EPA is proposing to add a new provision in 40 CFR 98.2(i)(5) to clarify that if the operations of a facility or supplier are changed such that a process or operation no longer meets the “Definition of Source Category” as specified in an applicable subpart, then the owner or operator is exempt from reporting under any such subpart for the reporting years following the year in which change occurs, provided that the owner or operator submits a notification to the Administrator that announces the cessation of reporting for the process or operation no later than March 31 of the year following such changes. For any future calendar year during which the process or operation meets the “Definition of Source Category” as specified in an applicable subpart, the owner or operator would be required to resume reporting for the process or operation.
Lastly, the EPA is proposing to limit resubmittal of reports to five years prior to the current reporting year. For example, in RY2016, resubmittal of reports from RY2011–2015 would be allowed, but a resubmittal of a RY2010 report would no longer be permitted. The EPA currently requires facilities to resubmit past year reports for the Greenhouse Gas Reporting Rule in which a substantive error is identified, and allows resubmittals going back to the first year of the program. Based on the resubmittals to the program to date, the EPA has determined that the number of reports that are resubmitted falls drastically after the active verification period of 6 months, and continues to fall over time. Because there is significant burden to the EPA for maintaining the reporting forms needed for facilities to resubmit reports for past years, the EPA is seeking comment on limiting the resubmittals to 5-years prior to the current reporting year. The EPA would set the limit at five years in part because there is a 5-year recordkeeping requirement in Part 98.
The EPA is proposing several amendments to subpart A that would improve the quality of the data collected under the GHGRP. For the reasons described in section II.B of this preamble, these proposed revisions are intended to collect data that would improve the EPA's understanding of sector GHG emissions, and are anticipated to generally result in only a slight increase in burden for reporters.
First we are proposing revisions to 40 CFR 98.3(c) to revise the content of the annual report to include three new data elements to uniquely identify individually reported fluorinated GHGs and fluorinated heat transfer fluids (HTF): Chemical name, CAS registry number, and the linear chemical formula. Currently, 40 CFR 98.3(c)(4)(iii)(E) and (F) require reporting of each fluorinated GHG and fluorinated HTF from applicable source categories, and 40 CFR 98.3(c)(5)(ii) requires the reporting of each fluorinated GHG from suppliers. The rule, however, does not specify how to identify each compound; instead, only the name of a GHG is required in a facility's annual report. Generally, reporters identify the GHGs in their annual report from Table A–1 of subpart A, which provides a list of fluorinated GHG along with the GWP of each gas, a registry number assigned by the Chemical Abstracts Service (CAS), and the chemical formula. When newly developed compounds are not listed in Table A–1 of subpart A, reporters classify the GHG as “other” and provide a chemical name. In these situations, different reporters sometimes refer to the “other” gas by different names (
To improve the usefulness of the emissions and supplier data reported, we are proposing to revise 40 CFR 98.3(c)(4) and (5) to include two additional identifiers of fluorinated
• Chemical name. If a chemical is not included in Table A–1 of subpart A (or not listed in the Web forms in the EPA's reporting tool), then facilities or suppliers would be required to report the name using the chemical naming convention provided by IUPAC.
• CAS Registry Number. If a CAS number is not assigned or if the CAS number is not associated with a single fluorinated GHG or fluorinated heat transfer fluid, then reporters would report an identification number assigned by the EPA's Substance Registry Services.
• Linear chemical formula.
Next, we are proposing to add a sentence to 40 CFR 98.3(c)(8) to clarify the missing data provisions. The proposed revision explains that missing data provisions apply not only to reported parameters, but to any parameter used to monitor or calculate emissions. Use of missing data procedures can affect the accuracy of an emission estimate regardless of whether that parameter is reported. It is the EPA's intention that the effect be documented, such that the accuracy of the reported emissions may be better understood.
We are proposing a change to 40 CFR 98.4(i) to update the content of the certificate of representation (COR). For each facility or supplier, all GHG reports and other communications are submitted by a “designated representative” of the owners and operators of the facility or supplier. The designated representative (DR) acts as a legal representative between the facility or supplier and the agency. The DR is appointed by submitting to the EPA a COR at least 60 days prior to the deadline for submission of the initial annual GHG report. Currently, 40 CFR 98.4(i) specifies that the COR must contain the following information:
• Identification of the facility or supplier;
• Name and contact information for the DR;
• A list of the owners and operators of the facility or supplier;
• Certification statements that the DR was appointed by a binding agreement with the owners and operators, that the DR has the necessary authority to carry out the duties and responsibilities on behalf of the owners and operators, and that the owners and operators are bound by the representations, actions, inactions, or submissions of the DR; and
• Signature of the DR.
We are proposing the addition of one item to the COR, which is a list of all the 40 CFR 98 subparts under which the facility or supplier intends to report. The information on the subparts anticipated to be reported is for the EPA's internal planning and management purposes, and would streamline the EPA's internal processes related to preparing for upcoming reporting seasons. This new COR requirement would impose no new burden on reporters. The revised content of the COR would apply only to newly submitted CORs for facilities that have not previously reported to the GHGRP. The DR would not be required to re-submit a previously submitted COR to add the new information. For example, the new information would not be required for a revised COR that is submitted to change the DR, address, or list of owners. The information submitted on anticipated subpart applicability would be based on whatever applicability analysis the facility or supplier has conducted on their own to determine that Part 98 applies, and on best engineering judgment as to the specific subparts that apply at the time that the COR is submitted. There would be no legal obligation to include GHG data for a particular subpart in the annual GHG report only because that subpart was included in the list of subparts submitted in the COR. Rather, the annual report must include all of the subparts that the DR determines meet the applicability requirements of 40 CFR 98.2 at any time during a reporting year. Also, the facility or supplier is not required to maintain any records to support the listing of subparts in the COR.
Finally, we are proposing to add provision 40 CFR 98.2(i)(6) to include a requirement that a facility must inform the EPA whenever the facility (or supplier) stops reporting under one e-GGRT identification number because the emissions (or quantity supplied) are being reported under another e-GGRT identification number. The EPA anticipates that this would occur when one facility purchases another facility (in its entirety) that is physically adjacent. The emissions from the purchased process equipment would automatically become part of the facility for the purchaser, and the facility previously reported by the seller would no longer exist. In general, the rule currently requires a facility reporting under an e-GGRT identification number to have a valid reason for discontinuing reporting under that e-GGRT identification number and to notify the EPA of that valid reason. The e-GGRT system is set up to collect such notification from the discontinuing reporter, and the EPA routinely follows up with all facilities that have discontinued reporting without providing a valid reason. On several occasions, a facility that was discontinuing reporting under its e-GGRT identification number contacted the GHGRP Help Desk in an attempt to notify the EPA that the emissions would be reported under another e-GGRT identification number. In those cases, the discontinuing reporter was looking for a formal way to transfer the reporting obligation to the other facility and confirm that the reporter was no longer responsible for reporting those emissions. The rule currently does not require reporting of any information from which the EPA could ascertain that the discontinuation of reporting was done for a valid reason or with which the discontinuing reporter could make a formal notification. To ensure that the EPA is aware of situations when an annual report for a facility or supplier
For more information on subpart A confidentiality determinations resulting from these proposed revisions, see section IV of this preamble.
For reasons described in section II.C of this preamble, we are also proposing to revise 40 CFR 98.3(h)(4) to simplify the process for requesting an extension for the reporter to respond to the EPA's questions on a submitted report or submit a revised report to correct a reporting error identified by the EPA during report verification. Currently, reporters are allowed a 45-day period to respond to the EPA's questions and may request an extension of 30 days, which is automatically granted, if needed. The Administrator may also grant an additional extension beyond the automatic 30-day extension, if the owner or operator submits a request for an additional extension at least 5 business days prior to the expiration of the automatic 30-day extension. We are proposing to remove the requirement that the request for an extension beyond the automatic 30 days must be submitted at least 5 days prior to the expiration of the automatic 30-day extension. Reporters would still be required to submit a request for the additional extension, but they may do so closer to (but not after) the expiration date of the automatic 30-day extension.
We are also proposing two amendments to subpart A of Part 98 to clarify a definition in 40 CFR 98.6. We are proposing to amend the definition of “gas collection system” to clarify that active venting systems that convey landfill gas to the surface of the landfill by mechanical convection, but the landfill gas is never recovered or thermally destroyed prior to release to the atmosphere, are not considered a landfill gas collection system. The requirements in subpart HH for gas collection systems are specific to landfill gas that is recovered or destroyed, but “active venting” systems appear to meet the definition of gas collection systems. The proposed revision clarifies that “active venting systems” are not subject to the monitoring and calculation requirements for landfills with gas collection systems.
The EPA is proposing to amend the definitions for “ventilation hole or shaft” in 40 CFR 98.6 to clarify that the term “vent hole or shaft” for mine ventilation systems includes mine portals, adits, and other mine entrances and exits used to move air from the ventilation system out of the mine. The proposed change is prompted by questions that we have received from reporters during the first four years of implementation, seeking guidance on whether these ventilation system components are considered part of the source category definition. Portal and adit are terms sometimes used to describe mine entries and shafts. The intent of the rule is to capture all points in the ventilation system where methane emissions may exhaust to the atmosphere. Adding these terms should provide clarity for reporters. We do not expect this rule change to result in an additional burden to reporters; it is a clarification to provide further guidance in applicability. However, the EPA does expect this proposed change to improve the accuracy of reporting.
For the reasons described in section II.D of this preamble, we are proposing several minor corrections and clarifications to subpart A of Part 98, including clarifications to definitions, editorial changes, and clarifications to reporting requirements. These minor revisions are summarized in the Table of Revisions available in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
In this action, we are proposing several amendments, clarifications, and corrections to subpart C of Part 98. This section discusses the substantive changes to subpart C; additional minor amendments, corrections, and clarifications are summarized in the Table of Revisions available in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
For the reasons described in section II.B of this preamble, we are proposing revisions that would allow the EPA to collect data that would improve the EPA's ability to verify data under Part 98, while generally resulting in only a slight increase in burden for reporters. First, the EPA is proposing to require reporting of the moisture content used to correct the default high heating value (HHV) for wood and wood residuals (dry basis) in Table C–1, in accordance with the procedures of footnote 5 in Table C–1. The Table C–1 default HHV for wood and wood residuals assumes that the wood and wood residuals are dry (
Facilities raised this concern through the GHGRP Help Desk and the EPA responded by adding footnote 5 to Table C–1 in the 2013 Revisions Rule, which allowed reporters to correct the default dry basis HHV to a wet basis. Currently e-GGRT and IVT require the use of the default dry basis HHV when reporting wood and wood residuals using Equations C–1 and C–8. For reporters that need to correct their HHV, the only option available is to override the e-GGRT or IVT calculated value, which is on a dry basis.
The EPA is proposing to add the moisture correction calculation as a reporting element, as well as a data element that would be entered into IVT for those reporters using IVT. This would allow the EPA to verify the accuracy of the moisture content and resultant emissions. Based on current reporting year data, approximately 132 facilities (167 units) would be affected by this new data element. The EPA anticipates that the impact of this new data element will be minimal, as moisture content is already determined by the facilities that correct the HHV of their wood products.
Because the new data element is an input to an emission equation, the EPA evaluated the data element to determine if its public release would cause disclosure concerns as was done for all inputs to equations through a previous action (79 FR 63750, October 24, 2014).
After considering whether disclosure concerns exist for those sources that meet the criteria in 40 CFR 98.36(f), the EPA has determined that the moisture content of the wood and wood residuals would not reveal any proprietary information about facility or process performance, design, and operation; cost to do business; raw material usage; or production. Site-specific fuel characteristics do not vary significantly from publicly-known average values. Additionally for the electric utilities, this sector has experienced a high level of transparency due to the practice of passing fuel costs through to paying customers. The EPA is proposing that, for sources that meet the criteria in 40 CFR 98.36(f), there are no disclosure concerns and the moisture content of the wood and wood residuals must be reported in e-GGRT.
For emissions reported using the aggregation of units (GP) and common pipe (CP) configurations, the EPA does not currently have the ability to compare emissions to the cumulative maximum rated heat input capacity for the units in the configuration. This information is important for verifying these emissions. The EPA is proposing to resolve this gap in verification by requiring reporting of the cumulative maximum rated heat input capacity for all units (within the configuration) that have a maximum rated heat input capacity greater than or equal to 10 (mmBtu/hr).
When originally promulgated, 40 CFR 98.36(c) required the cumulative heat input capacity for all units in GP and CP configurations. These requirements were removed in December 2010 amendments to the Greenhouse Gas Reporting Rule (75 FR 79092, December 17, 2010). The 2010 final rule noted that for verification purposes, “the only critical data element is the maximum rated heat input capacity of the largest unit in the group” (75 FR 79117). Although the highest maximum rated heat input capacity of any unit in these configurations is useful in verifying compliance with the rule requirements, it does not provide enough information to assess the quality of emissions reported under these configurations.
Currently over 50 percent non-biogenic CO
In the December 2010 amendments (75 FR 79117), commenters highlighted the burden associated with determining the maximum rated heat input capacity and maintaining an equipment count for small domestic combustion sources (
There were approximately 7,000 GP and CP configurations reported in 2014, out of the total 18,000 configurations reported in subpart C. Of these, approximately 2,250 reporting configurations reported that the highest maximum rated heat input capacity of
When reporting the cumulative maximum rated heat input capacity, reporters will not be required to account for units less than 10 mmBtu/hr. For GP configurations, this means that the cumulative maximum rated heat input capacity will be determined as the sum of the maximum rated heat input capacities for all units in the group that are greater than or equal to 10 (mmBtu/hr) and less than or equal to 250 (mmBtu/hr). Units with a maximum rated heat input capacity greater than 250 mmBtu/hr are not allowed to use the GP configuration. For CP configurations, the cumulative maximum rated heat input capacity will be determined as the sum of the maximum rated heat input capacities for all units served by the pipe that are greater than or equal to 10 (mmBtu/hr). Note that fuel use and corresponding emissions are still required to be reported for units with a maximum rated heat input capacity less than 10 (mmBtu/hr). Emissions reporting of GHGs for GP and CP configurations will remain unchanged.
Approximately 2,250 existing GP and CP reporting configurations will not be affected by this new requirement. Approximately 4,750 GP and CP reporting configurations will be required to determine and report cumulative maximum rated heat input capacity. This equates to approximately 3,540 affected facilities (out of the roughly 5,925 reporting in subpart C). However, many of these affected facilities will likely benefit from not having to account for units with a heat input capacity less than 10 (mmBtu/hr). The EPA believes that the burden associated with determining the cumulative maximum rated heat input capacity for GP and CP configurations will be minimal. Existing air permits and compliance records for other federal and state regulations likely contain heat input capacity data for many of the affected sources (
For more information on subpart C confidentiality determinations resulting from these proposed revisions, see section IV of this preamble.
For the reasons described in section II.C of this preamble, we are proposing revisions to the requirements of 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources) to (1) clarify the reporting requirements when the results of HHV sampling are received less frequently than monthly for certain sources; (2) streamline the conversion factors used to convert short tons to metric tons; and (3) revise Tables C–1 and C–2 to more clearly define emission factors for certain petroleum products.
First, we are proposing to amend 40 CFR 98.33(a)(2)(ii)(A) to clarify the definition of terms for Equation C–2b in cases where the results of HHV sampling are received less frequently than monthly. Reporters subject to 40 CFR 98.33(a)(2)(ii)(B) may use Equation C–2b, however the equation currently defines the frequency of HHV sampling as monthly. This proposed revision will replace the term “month” in the equation inputs “(HHV)
We are proposing changes to Tables C–1 and C–2 to remove duplication and to further classify several fuels to provide clarity. These changes are minor clarifications to existing rule requirements and, therefore, do not impact the burden on reporters. The first change that we are proposing to Table C–1 is to remove duplication of default HHV and CO
The second change to Table C–1 proposed is to move the fuel propane gas from the “Other fuels—gaseous” category into a new category entitled “Petroleum products—gaseous.” Propane is also included under the “Petroleum products” category, and we are not proposing to remove propane from this category as a majority of reporters use this fuel type when reporting use of propane. To help clarify that all fuels in the “Petroleum products” category are liquid fuels, we propose to rename this category to “Petroleum products—liquid.” In conjunction with the changes to Table C–1 for propane and petroleum coke, we are also proposing to change Table C–2 to further clarify that these fuels are considered petroleum products and their methane (CH
We are also proposing another change to Table C–2 to further streamline the CH
Finally, we are proposing to update the Standard Test Methods for Determining the Biobased Content of Solid, Liquid, and Gaseous Samples using Radiocarbon Analysis (ASTM D6866–08) to the current standard (ASTM D6866–12). The proposed change would revise references to the method in 40 CFR 98.34(d) and (e), 40 CFR 98.36(e)(2), and include a harmonizing change to 40 CFR 98.7(e)(33).
In addition to the substantive changes proposed, as described in section II.D of this preamble, we are proposing minor revisions that are intended to clarify specific provisions in subpart C. These minor revisions are summarized in the Table of Revisions available in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
In this action, we are proposing amendments to subpart E of Part 98 (Adipic Acid Production). This section discusses all of the proposed amendments to subpart E.
For the reasons described in section II.A of this preamble, we are proposing one amendment that is intended to simplify and streamline the requirements of subpart E and increase the efficiency of the report submittal process. We are proposing to revise 40 CFR 98.53(a)(2) to remove the annual approval for an alternative method for determining N
Reporters that are subject to subpart E are allowed to use an alternative method to calculate N
• The calculation method for determining annual N
• associated data collection procedures (parameters, how the parameters will be determined, frequency of data collection);
• initial and ongoing monitoring and quality assurance (QA)/quality control (QC) procedures;
• missing data procedures that will be applied in the event that quality-assured parameters are unavailable (
• any N
• any specific test methods or industry consensus standards that would be applied (ASTM, EPA, etc.) for data collection or monitoring; and
• any data reporting elements, in addition to the elements required in the rules, which would be provided to the EPA to verify the calculated emissions using the alternative method.
In this rulemaking, the EPA is proposing to allow additional flexibility in the use of alternative methods by removing the annual approval request. Unless there have been changes in the reporter's methodology. If a reporter received approval to use an alternative method in the previous reporting year and the methodology has not changed, the EPA is proposing that the request for use of the alternative method be automatically approved for subsequent reporting years. For most reporters, the alternative method is based on innovative methodologies that are already in practice at the facility, so the underlying monitoring, data collection, and QA/QC procedures used are unlikely to change from one reporting year to the next. The reporter would only need to notify the EPA that it is using an already approved alternative method. This notification would be included in the annual report submission. If, however, a reporter makes any changes to the previously-approved alternative method, then it must request permission to use the revised method as stated in 40 CFR 98.53(a)(2). Not only would this proposed change add flexibility to the reporters, it would also reduce the burden for reporters to comply with subpart E. By requiring requests only for new approvals or for methodologies that have changed since prior approval, the EPA burden required to review and approve the methodologies would also be reduced.
For the reasons described in section II.B of this preamble, we are proposing one amendment that is intended to improve the quality of data collected under subpart E while generally resulting in only a slight increase in burden for reporters. We are proposing to revise 40 CFR 98.56(f) to require reporting of the date of installation of any N
In this action, we are proposing several technical amendments to 40 CFR part 98, subpart F (Aluminum Production). This section discusses the substantive changes to subpart F; additional minor corrections and clarifications are summarized in the Table of Revisions available in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
For the reasons described in section II.B of this preamble, we are proposing several amendments to 40 CFR 98, subpart F to improve the quality of the data collected under Part 98 and improve the U.S. GHG Inventory. We are proposing to require reporting of two data elements that influence perfluorocarbon (PFC) emissions from aluminum production: annual average anode effect minutes per cell-day and annual smelter-specific slope coefficients. These proposed revisions are intended to collect more accurate and informative data. As discussed in section II.B of this preamble, these proposed revisions would allow the EPA to collect data that would improve the EPA's understanding of GHG emissions from aluminum production while generally resulting in only a slight increase in burden for reporters.
The annual average anode effect minutes per cell day is a measure of the fraction of the time during which aluminum electrolysis cells are operating that the cells are experiencing process disturbances known as anode effects. PFC emissions from aluminum production are closely associated with the frequency and duration of anode effects.
Both data elements were included in the 2009 Greenhouse Gas Reporting Rule. However, in the Final Deferral Notice published on August 25, 2011, we deferred reporting of the data elements because they were classified as inputs to emission equations (76 FR 53057).
IVT currently requires the entry of monthly anode effect minutes and smelter-specific slope coefficients (along with monthly metal production), allowing PFC emission estimates from smelters to be verified. However, our interest in anode effect minutes and slope coefficients goes beyond verification of emission estimates. Specifically, the annual average of anode effect minutes is of interest because it provides insight into one of the key drivers of PFC emissions from primary aluminum production at the facility and U.S. level. This data element helps us to understand why emissions have increased or decreased in a particular year or over longer periods. Thus, it is important for informing the development of future GHG policies and programs. In addition, it is important for explaining U.S. emission trends through the U.S. GHG Inventory. Before the GHGRP became effective, anode effect minutes (as well as smelter-specific slope coefficients) had been provided to the EPA by most U.S. smelters under the Voluntary Aluminum Industrial Partnership (VAIP), although anode effect minutes was reported as a company-wide (rather than smelter-specific) average by some companies in some years.
Smelter-specific slope coefficients also influence emissions. Because they are relatively stable over time (under subpart F, they are required to be re-measured every ten years), they do not drive trends in the same way that metal production and anode effect minutes do. However, they do contribute to differences in emission rates from different smelters and are therefore of interest for purposes of informing GHG policies and programs.
Smelter-specific slope coefficients are inputs to emission equations (i.e., to Equation F–2). In the analysis titled, “Final Evaluation of Competitive Harm from Disclosure of “Inputs to Equations” Data Elements Deferred to March 31, 2015” (September, 2014, available in docket EPA–HQ–OAR–2010–0929), we concluded that smelter-specific slope coefficients provided data related to process efficiency and also provided data that could be used to calculate the mass of aluminum produced if both the anode effect minutes and reported GHG emissions were also known. (The product of the slope coefficient, monthly metal produced, and monthly average anode effect minutes is the CF4 emissions from the smelter or potline.) However, we are now revisiting this conclusion in light of our proposed determination that the annual average of the anode effect minutes is CBI. Without data on anode effect minutes, data on smelter-specific slope coefficients pose few, if any, disclosure concerns. Most variability in process efficiency is driven by anode effect minutes, not smelter-specific slope coefficients, and it is not possible to back-calculate metal production without anode effect minutes.
In addition to the substantive changes proposed, as described in section II.D of this preamble, we are proposing minor revisions that are intended to clarify specific provisions in subpart F. These minor corrections are summarized in the Table of Revisions available in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
In this action, we are proposing multiple amendments to subpart G of Part 98 (Ammonia Manufacturing). This section discusses all of the proposed changes to subpart G.
For the reasons described in section II.B of this preamble, we are proposing revisions that would allow the EPA to collect data that would improve the EPA's understanding of GHG emissions from ammonia manufacturing while generally resulting in only a slight increase in burden for reporters. Specifically, we are proposing to add three data reporting elements. We are proposing to amend 40 CFR 98.76(a) to require reporting of annual ammonia production for facilities where a CEMS is used to measure CO2 emissions, 40 CFR 98.76(b)(2) to require reporting of annual feedstock consumption, and 40 CFR 98.76(b)(7) to require reporting of annual average carbon content. These data elements are readily available so these proposed changes would have no impact on burden for the reporters.
The addition of these data elements would improve the EPA's ability to verify reported GHGRP emissions, and enable the EPA to transparently apply more advanced calculation methods
For the reasons described in section II.C of this preamble, we are proposing multiple amendments to Subpart G to clarify the EPA's intentions related to the reporting of annual ammonia production and annual methanol production. We are proposing to amend 40 CFR 98.74(f) to read, “You may use company records or an engineering estimate to determine the annual ammonia production and the annual methanol production.” We are also proposing to clarify the requirement to report annual methanol production for each process unit in 40 CFR 98.76(b)(15) by adding that this information must be reported “regardless of whether the methanol is subsequently destroyed, vented, or sold as product.” These amendments will clarify the original intent of the requirements and reduce uncertainty from reporters by addressing multiple Help Desk questions, including questions related to the reporting of methanol that were raised during the RY2014 reporting period.
In this action, we are proposing several amendments, clarifications, and corrections to subpart I of Part 98 (Electronics Manufacturing). The reporting requirements for the electronics manufacturing sector were initially promulgated under subpart I on December 1, 2010 (75 FR 74774). Since the promulgation of that final rule, the EPA has published several rules to amend the calculation, monitoring, and reporting provisions of subpart I to respond to concerns raised by reporters and representatives from the semiconductor industry. Notably, the EPA finalized substantial amendments to provisions in subpart I on November 13, 2013 (78 FR 68162). These amendments included significant revisions to the methods for calculating GHG emissions, including revised default emission factors and the addition of a new stack test methodology, as well as substantial revisions to monitoring methodologies, data reporting and recordkeeping requirements, and clarifications to terms and definitions. These amendments became effective on January 1, 2014, and reporters used the revised requirements in the submittal of their annual reports for RY2014.
In this action, we are not proposing revisions that would include significant changes to the calculation methodologies, monitoring provisions, or data reporting and recordkeeping requirements of subpart I. Rather, we are proposing revisions that we have identified following implementation of the November 13, 2013 final rule and through discussions with industry stakeholders on how to improve the emissions estimates from the electronics manufacturing sector. These proposed changes are needed to improve the clarity of the calculation requirements and quality of the data collected under subpart I and to improve the EPA's understanding of GHG emissions from the electronics manufacturing sector.
This section discusses the substantive changes to subpart I; additional minor amendments, corrections, and clarifications are summarized in the Table of Revisions available in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
For the reasons described in section II.B of this preamble, the EPA is proposing several amendments to subpart I that would improve the quality of the data collected under the GHGRP. As discussed in section II.B of this preamble, we are proposing revisions that would allow the EPA to collect more accurate and detailed data which would improve the EPA's understanding of sector GHG emissions, while generally resulting in only a slight increase in burden for reporters.
First, the EPA is proposing to revise Equation I–24, including revising the name to Equation I–24A, which calculates the weighted-average fraction of a fluorinated GHG destroyed or removed in a fab using the stack testing methodology in 40 CFR 98.93(i), to incorporate two changes. First, instead of calculating the weighted-average fraction of gas destroyed or removed weighted by the consumption of that gas in different process types, the EPA is proposing to revise the equation so that the average fraction destroyed or removed is weighted by the estimated uncontrolled emissions of that gas from different process types. This change is needed to address the fact that the same gas can have different emissions when used in different process types, and these differences could potentially lead to errors in the calculation of the fraction of gas destroyed or removed, especially at facilities with a large percentage of tools fitted with abatement. To calculate the estimated uncontrolled emissions of each gas, the EPA is proposing to use the input gas emission factors from Tables I–3 to I–7 of subpart I and the consumption of each gas in each process type for each fab.
The second proposed change is to create a second equation (Equation I–24B) in 40 CFR 98.93(i) to calculate the weighted-average fraction of fluorinated GHG by-product gas “k” destroyed or removed in abatement systems in each fab using the stack testing methodology. This change is needed to clarify how the term d
Finally, for the triennial technology report required of certain facilities as specified in 40 CFR 98.96(y), the EPA is proposing to specify that reporters that are providing any utilization and by-product formation rates and/or destruction or removal efficiency data must also include information on the methods and conditions under which the data were collected, where such information is available. The triennial report would describe, for any utilization, by-product formation rate, and/or destruction or removal efficiency data submitted: the methods used for the measurements, the wafer size, film type being manufactured, substrate type, the linewidth or technology node, process type, process subtype for chamber clean processes, the input gases used and measured, the utilization rates measured, and the by-product formation rates measured, where this information is available. All of these data elements, with the exception of substrate type and linewidth, were submitted with the emission factor measurements provided to the EPA by semiconductor manufacturers during the development of the 2010 and 2013 final rules. This information is necessary to enable the EPA to better understand the data being submitted and to better apply it in the development of new or revised emission factors. Without collecting this data, the agency would not be able to effectively evaluate how emissions may vary by
For more information on subpart I confidentiality determinations resulting from these proposed revisions, see section IV of this preamble.
For the reasons described in section II.D of this preamble, we are proposing several minor corrections and clarification to subpart I of Part 98, including editorial changes, harmonizing changes, and clarifications to reporting requirements. These minor revisions are summarized in the Table of Revisions available in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
In this action, we are proposing amendments to subpart N of Part 98 (Glass Production). This section discusses the substantive changes to subpart N; additional minor corrections are summarized in the Table of Revisions available in the docket for this rulemaking (Docket ID No. EPA–HQ–OAR–2015–0526).
For the reasons described in section II.C of this preamble, we are proposing amendments that are intended to clarify the rule requirements in subpart N, while resulting in no impact on burden for reporters. Specifically, the changes clarify that a default value of 1.0 can be used for the fraction of calcination and the carbonate mass fraction for each carbonate type contained in the raw materials charged to the furnace. The current rule is unclear as to whether a reporter must perform a chemical analysis if they select to use a default value of 1.0. We are proposing to revise 40 CFR 98.144(b), 40 CFR 98.144(c), 40 CFR 98.144(d), 40 CFR 98.146(b)(5), and 40 CFR 98.146(b)(7) to clarify that no further chemical analysis is required if the default value of 1.0 is selected. These amendments will clarify the original intent of the requirements and address multiple Help Desk questions. Additional minor editorial corrections may be found in the Table of Revisions in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
In this action we are proposing several amendments to subpart O of Part 98 (HCFC–22 Production and HFC–23 Destruction). This section discusses all of the changes to subpart O.
For the reasons described in section II.A of this preamble, we are proposing several amendments to subpart O that are intended to simplify and streamline GHGRP requirements and increase the efficiency of the report submittal process, generally resulting in a decrease in burden on reporters. We are proposing to revise subpart O to remove three reporting requirements related to the revised destruction efficiency that facilities are required to calculate in the event that the HFC–23 concentration that they annually measure at the outlet of the destruction device exceeds the concentration measured during the performance test that is the basis for the current destruction efficiency. The reporting requirements are found at 40 CFR 98.156(d)(2), (3), and (4) and include, respectively, the concentration (mass fraction) of HFC–23 at the outlet of the destruction device, the flow rate at the outlet of the destruction device in kilograms per hour (kg/hr), and the emission rate (in kg/hr) calculated from these two parameters. These reporting requirements were originally intended to allow us to verify the calculation of a revised destruction efficiency. However, the requirements to report the revised destruction efficiency (the result of the calculation) and the flow rate of HFC–23 being fed into the destruction device (another input into the calculation) were removed by the Final Inputs Rule, and verification of HFC–23 emissions, including their destruction, is now conducted by the IVT. Thus, reporting these data elements to the EPA is no longer needed.
We are also proposing revisions to subpart O to (1) reinstate in 40 CFR 98.156(d) reporting of the method used to calculate the revised destruction efficiency, and (2) require facilities to report HCFC–22 production and HFC–23 emissions for each HCFC–22 production process rather than for the facility as a whole. As discussed in section II.B of this preamble, we are proposing revisions that would allow the EPA to collect data that would improve the EPA's understanding of GHG emissions from HCFC–22 production and HFC–23 destruction while generally resulting in only a slight increase in burden for reporters.
The requirement to report the method used to calculate the revised destruction efficiency (not an input to emission equation) was inadvertently removed by the Final Inputs Rule. We are proposing to reinstate this requirement because it is useful for understanding data quality, specifically, the rigor of the method used to revise the destruction efficiency.
Subpart O currently requires facilities to report production and emissions information at the facility level although these quantities are monitored and calculated at the process level. We are proposing to revise the reporting requirements in 40 CFR 98.156(a) to require that facilities report production and emissions information for each HCFC–22 production process. At the time the EPA finalized the subpart O requirements (74 FR 56260, October 30, 2009), we had intended to collect data on individual HCFC–22 processes, with the understanding that each facility had one HCFC–22 process. We have learned since that time that some facilities may have more than one HCFC–22 process and we are proposing to revise the rule to require reporting for each individual process. In the event that a facility has more than one HCFC–22 production process, this would provide more precise information that would allow us to better verify emissions and understand HFC–23 trends.
Reporters in this subpart already monitor, estimate, and record process and emissions data on a process basis per 40 CFR 98.153; therefore, these proposed rule revisions to report the production and emissions data on a process basis are not expected to significantly increase burden. For more information on subpart O confidentiality determinations resulting from these proposed revisions, see section IV of this preamble.
In this action we are proposing amendments to subpart Q of Part 98 (Iron and Steel Production). This section discusses one substantive change to subpart Q; additional minor amendments, corrections, and clarifications are summarized in the Table of Revisions available in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
A revision is being made to align with revisions being proposed for subpart Y
In this action, we are proposing amendments to subpart S of Part 98 (Lime Manufacturing). This section discusses all the proposed amendments to subpart S.
For the reasons described in section II.B of this preamble, the EPA is proposing several revisions to subpart S to improve the quality of data collected under Part 98. We are proposing to require reporting of three data elements that influence CO
Similar data elements were included in the 2009 Greenhouse Gas Reporting Rule; however, these data elements were monthly values, listed in 40 CFR 98.196(b)(2), 40 CFR 98.196(b)(3), and 40 CFR 98.196(b)(5). However, in a final rule published on August 25, 2011, we deferred reporting of the data elements because they were inputs to emission equations (76 FR 53057). In the Final Inputs Rule (79 FR 63750, October 24, 2014), we identified disclosure concerns with these data elements and therefore decided not to collect these monthly data elements and to include the inputs from Equations S–1 and S–2 in IVT.
IVT currently requires the entry of monthly calcium oxide and magnesium oxide content for Equation S–1, outputting the monthly emission factor for lime type; monthly calcium oxide and magnesium oxide content for Equation S–2, outputting the monthly emission factor for calcined lime byproduct/waste type sold; calcium oxide and magnesium oxide content, and annual weight or mass of calcined byproducts or wastes for lime type that is not sold for Equation S–3, outputting the annual CO
Collecting the annual emission factors for each lime product type produced, annual emission factors for each calcined byproduct/waste by lime type that is sold, and annual average results of chemical composition analysis of each type of lime product produced and calcined byproduct/waste sold would allow us to understand why emissions have increased or decreased in a particular year or over longer periods. Thus, they are important for informing the development of future GHG policies and programs. In addition, they are important for explaining U.S. emission trends through the U.S. GHG Inventory. These annual values are not inputs to equations; as described in section IV of this preamble, we are proposing that these data elements be eligible for confidential treatment.
For more information on subpart S confidentiality determinations resulting from these proposed revisions, see section IV of this preamble.
In this action, we are proposing three amendments to subpart V of Part 98 (Nitric Acid Production). This section discusses all of the proposed changes to subpart V.
For the reasons described in section II.A of this preamble, we are proposing one amendment that is intended to simplify and streamline the requirements of subpart V and increase the efficiency of the report submittal process. We are proposing to revise 40 CFR 98.223(a)(2) to conditionally remove the annual approval request by the reporter and the annual request approval by the EPA. As further discussed in section III.C of this preamble for subpart E, the EPA is proposing that the request for use of the alternative method be automatically approved for the next reporting year if the reporter received approval to use an alternative method in the previous reporting year and the method has not changed.
For the reasons described in section II.B of this preamble, we are proposing two amendments that are intended to improve the quality of data collected under subpart V that would result in a moderate increase in burden for reporters. First, we are proposing to revise 40 CFR 98.220 to change the definition of the source category to require reporting from all reporters that produce nitric acid, regardless of the nitric acid strength. The subpart V definition was based on the Standards of Performance for Nitric Acid Plants in 40 CFR part 60 (77 FR 48433, August 14, 2012) which covers the emissions of nitrogen oxides (NO
High-strength nitric acid is produced by two different methods. The first method begins with producing weak nitric acid and then uses extractive distillation to concentrate the nitric acid. Since N
When the Greenhouse Gas Reporting Rule was published in 2009, only one nitric acid plant in the United States produced nitric acid greater than 70 percent in strength. In the interim, further research has indicated the existence of three other nitric acid trains capable of producing high-strength nitric acid, including one existing plant and two potential plants becoming operational as early as the end of 2015. See the memorandum, “Re: Strong Nitric Acid Facilities in the U.S.” from
Because of increased usage of the high-strength nitric acid process in the United States, we are proposing that the definition of nitric acid be updated to apply to all nitric acid strengths to ensure that subpart V reporting captures all N
We are also proposing to revise 40 CFR 98.226(h) to require reporting of the date of installation of any N
In this action we are proposing several amendments to 40 CFR part 98, subpart X (Petrochemical Production). This section discusses the substantive changes to subpart X; additional minor amendments, corrections, and clarifications are summarized in the Table of Revisions available in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
For the reasons described in section II.A of this preamble, we are proposing amendments to subpart X that are intended to simplify, streamline, and align with other proposed GHGRP requirements, which would generally result in a decrease in burden for reporters. Under 40 CFR 98.243(c), facilities that report to subpart X are referred to provisions in subpart Y for reporting CO
The EPA is also proposing to amend 40 CFR 98.246(a)(5) to allow operators of an integrated ethylene dichloride (EDC) and vinyl chloride monomer (VCM) process to report either the measured quantity of EDC produced or both the measured quantity of VCM and an estimate of the amount of EDC produced as an intermediate in the process. We are also proposing to modify 40 CFR 98.240(a) to indicate that a reporter may elect to consider the entire integrated process (rather than just the EDC operations) to be the petrochemical process for the purposes of complying with the mass balance method.
Subpart X currently requires EDC manufacturers to perform the mass balance around operations involved in the production of the EDC, including situations where EDC is produced as an intermediate in the production of VCM. In a letter received from Occidental Chemical Company titled “Request to Consider IPCC Balanced EDC/VCM Process Studies and Data for the Elimination of e-GGRT Validation Messages at VCM Production Facilities Reporting Under Subpart X,” dated July 10, 2015, industry representatives indicated that an integrated EDC/VCM process is a continuous process with EDC produced as an intermediate that is not stored or measured. As an alternative to incurring the burden of modifying the process to enable measurement of the intermediate EDC stream, Occidental Chemical Company has requested that subpart X reporters be allowed to perform the mass balance over the entire integrated process and, for the quantity of petrochemical produced, report the quantity of VCM produced instead of the amount of EDC produced. Conducting the mass balance over the entire integrated process is acceptable to the EPA because the CO
Under the proposed optional method, carbon emitted in vent streams from VCM operations and carbon in liquid wastes that are combusted would be assumed to be converted to CO
In addition to conducting the mass balance over the entire integrated process, the EPA is proposing that facilities electing to use this optional method would report both the measured amount of VCM produced and an estimate of the amount of EDC produced as an intermediate. Reporting the amount of VCM would help the EPA to verify the estimate of EDC reported. Reporting the estimate of EDC produced would enable the EPA to determine if there is a statistically significant difference in average emissions per metric ton of EDC between results reported by facilities that use the option for integrated processes versus results for facilities that report only for EDC operations.
The proposed change to 40 CFR 98.240(a) would harmonize the proposed integrated EDC/VCM mass balance option with other requirements related to petrochemical processes (or process units) in subpart X. For example, the mass balance calculation requirements in 40 CFR 98.243(c) and reporting requirements in 40 CFR 98.246(a) are per petrochemical “process unit.” Thus, considering the entire integrated process to be the petrochemical process unit clarifies that these calculation and reporting requirements apply to the entire integrated process under the option, and
It is anticipated that the proposed amendments would reduce the compliance burden by not requiring monitoring equipment and/or sampling and analysis of an intermediate EDC stream just for the purpose of complying with subpart X. Instead, facilities would be allowed to measure the final product VCM, which is likely already being measured for other business reasons. A few facilities may have a liquid waste stream from the VCM operations that is not combusted. Such streams would need to be measured and included as products in the mass balance. The potential increase in burden for measurement of such streams is expected to be more than offset by the reduction for not measuring the intermediate EDC stream because not all facilities will have a liquid waste stream that is not combusted, and a waste stream is an output that would be more readily measured than an intermediate that is not stored.
For the reasons described in section II.B of this preamble, we are proposing to amend subpart X to collect additional data to help improve estimates included in the U.S. GHG Inventory. The EPA is proposing to add reporting requirements for facilities that use the mass balance approach to determine emissions under 40 CFR 98.243(c) to report the annual average of the measurements of the carbon content and molecular weight of each feedstock and product reported under subpart X. Much of these data are currently required to be determined and retained per the recordkeeping requirements in 40 CFR 98.247, so adding the reporting requirement to report annual averages adds very little burden to reporters. These additional data elements will be aggregated to the national level and used to improve national emission estimates in the U.S. GHG Inventory for several reasons.
First, these data points will be helpful for understanding non-energy uses of fossil fuels by the chemical industry, so they can more accurately be allocated between the industrial process and energy sectors of the U.S. GHG Inventory. As noted in the U.S. GHG Inventory, currently some degree of double-counting may occur between CO
Second, having annually averaged carbon content and molecular weight for products and feedstocks derived from facility-level GHGRP data would enable the EPA to transparently apply the IPCC mass balance method
For more information on subpart X confidentiality determinations resulting from these proposed revisions, see section IV of this preamble.
For the reasons described in section II.D of this preamble, we are proposing several minor corrections, and clarifications to subpart X of Part 98. These minor revisions are summarized in the Table of Revisions available in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
In this action we are proposing several amendments to 40 CFR part 98, subpart Y (Petroleum Refineries). This section discusses the substantive changes to subpart Y; additional minor amendments, corrections, and clarifications are summarized in the Table of Revisions available in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
For the reasons described in section II.A of this preamble, we are proposing several amendments that are intended to simplify and streamline the requirements of subpart Y. To reduce reporter burden, the EPA is proposing to clarify in this rulemaking that pilot gas, which is considered the gas used to maintain a pilot flame at the flare tip, may be excluded from the quantity of flare gas used to perform GHG emissions calculations. As described below, the quantity of GHG emissions associated with pilot gas is very small relative to the total GHG emissions from a flare at petroleum refineries, petrochemical production facilities, and iron and steel production facilities, and monitoring the quantity of pilot gas may impose additional burden on some facilities.
Generally flares combust waste gas (excess gas generated by the facility that needs disposal which the flare was designed to treat/destroy), purge/sweep gas (gas that must be added to the flare header system or to the base of the flare in order to prevent oxygen ingress during periods of low waste gas flow), and pilot gas (gas used to maintain a pilot flame at the flare tip). The majority of gas combusted by a flare is waste gas. The remaining gas combusted by the flare is comprised of purge/sweep and pilot gas. The amount of purge/sweep gas needed is dependent on the complexity of the flare gas header system and the flare diameter and tip design. As discussed in the memorandum “Proposed Changes to Flare Pilot Gas Reporting Requirements under the Greenhouse Gas Reporting Program (GHGRP)” from Jeff Coburn, Leslie Pearce and Kevin Bradley, RTI to Brian Cook, EPA, dated July 10, 2015 (see Docket Id. No. EPA–HQ–OAR–2015–0526), flares generally require at least 0.1 to 0.2 foot per second (ft/s) flow velocity at the tip to prevent oxygen ingress, but can be significantly higher for flares with complex header systems. For a 2 foot diameter flare, this translates to a minimum flow of 1,100 to 2,200 cubic feet per hour or 1 to 2 mmBtu/hr. Recommended heat rate for industrial flare pilots is approximately 0.05 mmBtu/hr, so GHG emissions from flare pilot gas are typically 10 percent or less of the emissions from the flare purge/sweep gas while the flare is on standby (i.e., no active waste gas flow). Therefore, we expect the resultant GHG emissions from pilot gas to be low, especially in the context of the broader flare emissions.
Further, it is difficult for facilities to estimate the quantities of pilot gas without the use of a meter. Facilities generally measure the flare gas, but do not always have unit-specific meters installed for the gas used for the pilot flame (typically natural gas). The EPA does not intend for facilities to install a separate meter to measure the pilot gas for the purposes of reporting under this
Finally, the EPA is proposing to amend the reporting requirements in 40 CFR 98.256(e) to add a requirement that facilities provide a yes/no indication as to whether a flare has a flare gas recovery system. Currently, 40 CFR 98.256(e) requires facilities to report general information as to the type of flare (e.g., air-assisted, steam-assisted, or non-assisted) and the flare service (e.g., general facility flare, unit flare, or emergency flare). Several offices within the EPA (as well as external researchers) use the GHGRP data on flares to characterize flare emissions, assess trends, and evaluate GHG emission reductions that could be achieved under various policies. In using the GHGRP data for flares for these purposes, we identified a key deficiency in the GHGRP data set is the lack of information regarding which flares have flare gas recovery systems. Flare gas recovery is a primary means by which owners and operators of flares may reduce flare emissions. The inclusion of information on which flares have flare gas recovery systems will provide useful information to characterize emission trends in key industries using flares and provide critical information needed by the EPA to make policy decisions. Only an indication of whether or not the flare is serviced by a flare gas recovery system is being proposed, so this amendment would add only a slight increase in burden to subpart Q, X, and Y reporters that have flares. For more information on subpart Y confidentiality determinations resulting from these proposed revisions, see section IV of this preamble.
For the reasons described in section II.B of this preamble, the EPA is proposing several amendments that would improve the quality of the data collected from subpart Y reporters while resulting in only a slight increase in burden for reporters.
The EPA originally promulgated rules for the reporting of GHG emissions from various source categories, including petroleum refineries, on October 30, 2009. Since the reporting requirements were developed, understanding of emissions from delayed coking units (DCU) has improved. The rule originally established a methodology to estimate methane emissions from a DCU based on a simple gas expansion model (i.e., Equation Y–18) which the EPA is proposing to replace with a new methodology that will more accurately determine emissions from DCU.
Recently, EPA's Office of Air Quality Planning and Standards (OAQPS) conducted a detailed information collection request (ICR) (OMB Control No. 2060–0657) of the petroleum refining industry that gathered information about DCU operations and the decoking process. Based on the information collected, the EPA determined that the simple gas expansion model did not accurately reflect the emissions source and significantly underestimated emissions from the DCU. First, there is less gaseous void space in the coke drum than previously thought because the coke drum is filled with water and the void (vapor) space in the coke drum is small. Second and more importantly, there is a significant quantity of steam generated and released from the coke drum during the depressurizing process because the boiling point of the water decreases as the pressure of the vessel decreases. That is, there is a phase change and gas generation that occurs during the venting process. Consequently, the total quantity of gas discharged during a venting event is actually much greater than predicted by the simple pressure expansion (no phase change) model previously used in Equation Y–18. Upon review of the test data collected in response to the ICR, the EPA determined that methane emissions are a function of steam generation, not the initial void volume in the delayed coking unit vessel. Based on these determinations, the EPA developed and used a steam generation model to estimate emissions from the DCU (see Docket Item No. EPA–HQ–OAR–2010–0682–0202) and revised and incorporated this methodology as part of the emissions factors update for petroleum refineries (see
The proposed methodology uses a heat balance on the DCU coke drum vessel contents to estimate the volume of steam produced during the DCU decoking operations (steam venting, draining, vessel deheading, and coke cutting). Methane emissions per venting cycle is proportional to the quantity of steam generated. Key inputs to the heat balance include the mass of water and coke in the coke drum vessel and the average temperature of the coke drum contents when venting first occurs. We are proposing to allow reporters to determine the mass of coke in the coke drum based on company records or to estimate the mass of coke in the coke drum based on drum dimensions and drum outage (parameters already required to be recorded under the current rule) and a new equation provided in the rule (Equation Y–18a). We are proposing to require reporters to determine the mass of water in the coke drum based on the height of water in the coke drum and the mass of coke in the coke drum. We are proposing to allow either one of two methods to estimate the average temperature of the coke bed contents: (1) A method based on the measured overhead temperature of the drum, and (2) a method based on the overhead pressure using a temperature-pressure correlation equation provided in the rule.
While the EPA generally considers the temperature method to be the most accurate means to determine the average temperature of the coke bed contents, the EPA understands that there are concerns that the temperature measurements in the overhead line may be erroneously high due to additional steam purges in the overhead line to prevent coke build-up on the monitoring equipment, so we have provided the temperature-pressure correlation equation as well to provide reporters additional flexibility. Additionally, the EPA has not previously required temperature monitoring for the DCU in subpart Y of Part 98, but the previous methodology for delayed coking units in subpart Y required the vessel pressure prior to venting to be monitored and used as an input to the previous equation. Consequently, the EPA is providing the use of the temperature-pressure correlation to allow reporters to use current pressure monitoring and recordkeeping practices to obtain the information needed to implement the new methodology. As such, the new methodology will not require the installation or use of new monitoring systems.
Finally, we are proposing to allow facilities that have DCU vent gas measurements to use these measurements to develop a unit-specific methane emissions factor for the DCU. This allows reporters that have previously used the combined Equation Y–18/Y–19 method (as well as other reporters) to use the measurement data available to provide an improved, site-specific emissions estimate. If a unit-specific methane emissions factor is not available, we are proposing that reporters use the default methane emissions factor for DCU of 7.9 kg methane per metric ton of steam generated. Additional background on this change is available in the memo “Revised Emission Methodology for Delayed Coking Units” from Jeff Coburn, RTI International to Brian Cook, EPA, dated June 4, 2015 (see Docket Id. No. EPA–HQ–OAR–2015–0526).
The EPA is proposing that the new methodology be used to estimate the emissions for each DCU and the EPA is proposing to amend the reporting requirements for DCU to only require reporting at the unit level. This change is being proposed for several reasons. Currently, DCU emissions are reported at the facility level. The decision was originally made to require reporting at the facility level to allow facilities that have two identical DCU (with same sized drums) to apply Equation Y–18 to the set of drums one time to reduce burden. However, the rule contains several required reporting elements be submitted on a DCU unit-specific basis, so the burden reduction associated with this simplification is very small, and facility-level data hindered the EPA's ability to verify the reported data.
Facilities currently have the option to use a combination of Equation Y–18 and Y–19 (process vent method) for estimating the emissions from the DCU. This further splits certain reporting elements between the DCU process unit and the process vents inputs. This split in the DCU reporting elements has caused confusion among reporters and made verification of the reported data challenging. For example, facilities that did not have a DCU were required to actively report a zero for their emissions from this source. Also, because emissions were to be reported at the facility level, the emissions from process vents added for DCU vents needed to be reported as zero for the DCU vent at the process vent level. However, many reporters reported emissions at the process vent level and may or may not have fully reported the DCU emissions at the facility level.
Due to the difficulties associated with the split reporting requirements, we are proposing that the new methodology be implemented to estimate the emissions for each delayed coking unit separately. This will simplify the reporting requirements for facilities and allow the EPA to simplify and streamline recordkeeping and reporting requirements for most reporters. Additionally, in the proposed approach, DCU vent measurements may be used to develop a unit-specific methane emissions factor so the available measurement data can be used within the context of the proposed DCU methodology, rather than splitting the emissions estimates between two different methodologies (i.e., Equations Y–18 and Y–19). For these reasons, the EPA anticipates the burden on reporters would be reduced by streamlining the DCU reporting requirements so that DCU-related reporting elements are only required to be reported at the DCU unit level.
In related revisions, we are proposing to revise 40 CFR 98.253(j) to delete “CH4 emissions if you elected to use the method in paragraph (i)(1) of this section,” because the DCU methodology no longer includes an option to use a combination of techniques to determine the CH4 emissions from DCU decoking operations. We are also including “coke produced per cycle” in the list of quantities of petroleum process streams that are determined using company records in 40 CFR 98.254(j), and adding a requirement that temperature and pressure measurements associated with the DCU are to be determined “using process instrumentation operated, maintained, and calibrated according to manufacturer's instructions.” These revisions are included to clarify monitoring requirements associated with the new DCU methodology. Additionally, we are proposing to revise the recordkeeping requirements in 40 CFR 98.257 associated with the DCU to harmonize the recordkeeping requirements with the new DCU methodology equations.
The EPA is also proposing to amend 40 CFR 98.253(h)(1) and (h)(2) to clarify the appropriate equations to be used for reporters with an asphalt blowing unit with a control device other than a vapor scrubber, thermal oxidizer, or flare (classified as “other (specify)” in e-GGRT). The current rule language in 40 CFR 98.253(h)(1) and (h)(2) only specifies the methodology to use for these three control systems and for uncontrolled asphalt blowing. In the proposed amendments, we are revising 40 CFR 98.253(h)(1) to clarify that reporters with “asphalt blowing operations controlled either by vapor scrubbing or by another non-combustion control device” must use Equations Y–14 and Y–15 to calculate their GHG emissions. We are also revising 40 CFR 98.253(h)(2) to clarify that reporters with “asphalt blowing operations controlled by either a thermal oxidizer, a flare, or other vapor combustion control device” must use Equations Y–16a/Y–16b and Y–17 to calculate their GHG emissions. These amendments will yield more accurate emissions values as reporters will now be required to use the most appropriate equations for “other” control systems used for asphalt blowing operations. For more information on subpart Y confidentiality determinations resulting from these proposed revisions, see section IV of this preamble.
For the reasons described in section II.D of this preamble, we are proposing several minor corrections, and clarifications to subpart Y of Part 98. These minor revisions are summarized in the Table of Revisions available in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
In this action, we are proposing amendments to subpart Z of Part 98 (Phosphoric Acid Production). This section discusses all the proposed amendments to subpart Z. For the reasons described in section II.B of this preamble, we are proposing to revise subpart Z of Part 98 (Phosphoric Acid Production) to allow the EPA to collect data that would improve the EPA's understanding of GHG emissions from phosphoric acid production while generally resulting in only a slight increase in burden for reporters.
We are proposing to revise 40 CFR 98.266(f)(3) to require that the annual report must include the annual phosphoric acid production capacity (tons) for each wet-process phosphoric acid line, rather than the annual permitted phosphoric acid production capacity. In a prior technical correction to the rule (78 FR 19823, April 2, 2013) we acknowledged that not all phosphoric acid production facilities have a permitted production capacity, and additionally, not all facilities produce to the permitted capacity. During that action, we removed the word “permitted” from the requirement at 40 CFR 98.266(b) to report the facility-level production capacity. We are proposing a similar revision in this action to remove the word “permitted” from the requirement to report the process-level production capacity,
In this action, we are proposing several amendments, clarifications, and corrections to subpart AA of Part 98 (Pulp and Paper Manufacturing). This section discusses all of the proposed changes to subpart AA.
For the reasons described in section II.A of this preamble, we are proposing one amendment to subpart AA that would streamline the requirements of the rule and improve implementation, while generally reducing burden. We are proposing to clarify that Tier 4 CEMS are not used to report emissions under subpart AA. Subpart AA currently requires that fossil-fuel based CO
As described in section II.C of this preamble, through communication with stakeholders, we have identified certain aspects of the rule that may require revision, including those we are proposing in response to comments submitted by stakeholders on prior rulemakings. Subpart AA requires pulp mill reporters to determine the annual mass of spent liquor solids fired in chemical recovery furnaces and chemical recovery combustion units by either measuring the mass of spent liquor solids annually (or more frequently) with a Technical Association of the Pulp and Paper Industry (TAPPI) method, or using records of measurements made with an online measurement system. Missing measurements are currently required to be populated with either the maximum spent liquor mass or fuel flow rate for the combustion unit, or the maximum mass or flow rate that the fuel meter can measure. Representatives of the forest products industry requested revisions to the missing data requirements for spent liquor solids in 40 CFR 98.275(b).
The EPA has reviewed the industry representatives' request and agrees that use of the daily value recorded under 40 CFR 63.866(c)(1) of subpart MM results in an acceptable missing data estimate for the combustion unit. Thus, the EPA is proposing to amend 40 CFR 98.275(b) to allow use of the daily mass of spent liquor solids fired reported under 40 CFR 63.866(c)(1) as an alternative to maximum values. The provisions of 40 CFR 63.866(c)(1) require pulp mills to retain records of the mass of spent liquor solids fired in megagrams (Mg) or tons per day. This proposed amendment acknowledges that the daily value recorded under 40 CFR 63.866(c)(1) may need to be adjusted to match the duration of missing data under subpart AA. For example, the daily measurement may need to be adjusted to represent only a few hours of monitor downtime. We are proposing to retain the original requirements of 40 CFR 98.275(b) in addition to proposing the alternative to use the value recorded under 40 CFR 63.866(c)(1) to avoid requiring reconfiguration of data systems in mills that may have configured their data reporting systems to supply maximum values for subpart AA.
We are proposing one additional revision to subpart AA that is a minor clarification and that would improve the understanding of the rule. We are proposing a clarification to column labels in Table AA–2. Table AA–2 contains CH
In this action, we are proposing amendments to subpart CC of Part 98 (Soda Ash Manufacturing). This section discusses the substantive changes to subpart CC; additional minor amendments, corrections, and clarifications are summarized in the Table of Revisions available in the
We are proposing two revisions that are intended to improve the quality of data collected under subpart CC, while only resulting in a slight increase in burden for reporters. We are proposing to revise 40 CFR 98.296(a) and (b) to require reporting of the facility-level annual consumption of trona or liquid alkaline feedstock. For the reasons described in section II.B of this preamble, we are proposing the addition of this data element to help improve the quality of the U.S. GHG Inventory by using aggregated facility level data. These data are already required to be reported on the manufacturing-line basis for subpart CC reporters that report using CEMS. For non-CEMS subpart CC reporters, the requirements to report consumption data for each manufacturing line, previously required per 40 CFR 98.269(b)(5), was removed in the Final Inputs Rule. This action would propose to streamline the reporting of facility-level consumption data from both CEMS and non-CEMS reporters on a more aggregate level. Currently, the U.S. Inventory estimates CO
For the reasons described in section II.D of this preamble, we are proposing one minor correction to subpart CC of Part 98. This minor revision is summarized in the Table of Revisions available in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
In this action, we are proposing several amendments, clarifications, and corrections to subpart DD of Part 98 (Use of Electric Transmission and Distribution Equipment). This section discusses all of the proposed changes to subpart DD.
For the reasons described in section II.B of this preamble, the EPA is proposing several changes to subpart DD that will improve the quality and usefulness of the data received by the GHGRP, while generally resulting in only a slight increase in burden for reporters.
A facility is defined under subpart DD at 40 CFR 98.308 as an electric power system, comprised of all electric transmission and distribution equipment insulated with or containing SF
Given the nature of electric power systems, subpart DD facilities generally span a geographic area, and in some cases, may cross state boundaries. Currently, subpart DD reporters provide the EPA with the facility address on their certificate of representation. However, this address does not provide complete information on where the electric power system actually lies. The EPA is proposing to add new reporting requirements at 40 CFR 98.306(m) to make data collected under subpart DD more useful to the public. The new data elements would require the electric power system to provide the name of the U.S. state, states, or territory in which the electric power system lies and the total miles of transmission and distribution lines that lie in each state or territory. These data elements would allow users of GHGRP data to more easily identify the state, states, or territory within which the electric power system lies. Users of GHGRP data would also be able to compare the miles of transmission and distribution lines in each state or territory to the total miles of transmission and distribution lines for the facility and then approximate the percentage of emissions that occur within each state or territory. (As discussed in the U.S. GHG Inventory, SF
We are also proposing to add reporting elements to subpart DD that are related to the nameplate capacities and numbers of pieces of new and retiring equipment. Currently, electric transmission and distribution facilities are required to include the nameplate capacities of new and retiring hermetically sealed-pressure equipment, along with the corresponding quantities for other electrical equipment, in their emission calculations. They are also required to report the total nameplate capacity of new equipment, including hermetically sealed-pressure equipment, and the total nameplate capacity of retiring equipment, including hermetically sealed-pressure equipment. However, they are not required to distinguish between hermetically sealed-pressure and other equipment in these reports.
In lieu of reporting the total nameplate capacity for all hermetically sealed-pressure equipment and other equipment, we are proposing to require facilities to separately report the nameplate capacities of hermetically
The proposed amendments would add reporting of the nameplate capacities of new hermetically sealed-pressure switchgear (proposed 40 CFR 98.306(a)(2)), new SF
Because we recognize that the range of charge sizes can be large (
While this approach would require more effort than providing the total numbers of pieces of equipment newly installed and retired for hermetically sealed-pressure equipment and for all other equipment, it would provide more precise data. For example, it would enable us to distinguish between situations in which most newly installed, hermetically sealed-pressure equipment had a charge size of 1 or 2 pounds, and situations in which most such equipment had a charge size of one or two ounces, but the average charge size was inflated by a few outliers with charge sizes of ten pounds or more.
For more information on subpart DD confidentiality determinations resulting from these proposed revisions, see section IV of this preamble.
In this action, we are proposing several amendments, clarifications, and corrections to subpart FF of Part 98 (Underground Coal Mines). This section discusses the substantive changes to subpart FF; additional minor amendments, corrections, and clarifications are summarized in the Table of Revisions available in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
For the reasons described in section II.A of this preamble, the EPA is proposing three changes to subpart FF that will streamline reporting of GHG emissions under subpart FF.
First, for the reasons described in section III.A.1 of this preamble, the EPA is proposing to amend 40 CFR 98.2(i)(3), which provides that an owner or operator of a facility that has reported to the GHGRP can stop reporting to the program if all applicable GHG-emitting processes and operations permanently cease to operate. Facilities may take advantage of this provision beginning in the year after the cessation of operations. However, paragraph (i)(3) expressly precludes owners and operators of underground coal mines from using this off-ramp even after a mine is closed and abandoned. Underground coal mines may only cease reporting after meeting the other criteria in 40 CFR 98.2(i): (1) If GHG emissions fall below 25,000 mtCO
In proposing this change, the EPA recognizes that non-flooded underground coal mines continue to liberate methane even after the mining operations cease. However, methane liberation from closed mines occurs on a rapidly declining basis until the mine is sealed and declared abandoned by MSHA, and sealed shafts emit virtually no methane to the atmosphere. This is supported by the EPA's work in developing a methodology for calculating emissions from abandoned underground mines.
The proposed change will streamline reporting under subpart FF by limiting reporting to facilities actively emitting measurable volumes of methane. Reports submitted by closed and abandoned mines during the first four years of the GHGRP show that abandoned and sealed mines produce quantities of GHG emissions far below the reporting threshold, and the data are of limited value for the GHGRP and U.S. GHG Inventory while resulting in additional reporting burden for facilities.
With respect to defining when a mine is considered abandoned, the EPA is proposing to rely on the MSHA determination of a mine's operational status as “abandoned,” because it is a transparent, publicly available indicator of mine operational activity. The operational status of any mine can be found using MSHA's on-line Mine Data Retrieval System (MDRS)
Furthermore, the EPA believes that this proposed change has the added benefit of removing a perceived conflict with 40 CFR 98.320(c), “Definition of the source category”, in subpart FF. This provision exempts abandoned and closed underground coal mines as source categories required to report to the GHGRP. Some reporters are uncertain which provision, 40 CFR 98.2(i) or 40 CFR 98.320(c), takes precedence when formerly operating and reporting mines change status to abandoned and sealed mines. The EPA believes the proposed modification would remove any ambiguity and uncertainty, clarifying when underground coal mines may cease reporting to the GHGRP and streamlining implementation of the GHGRP.
Second, the EPA is proposing several amendments to clarify when moisture content is to be reported. The first several amendments apply to 40 CFR 98.326, which lists the data reporting requirements for subpart FF. The EPA is proposing to amend 40 CFR 98.326(o) to require reporting of moisture content only in those cases where the volumetric flow rate and CH
Third, the EPA is proposing several amendments related to moisture content in 40 CFR 98.323 and 40 CFR 98.324, which lists the requirements for calculating GHG emissions. The EPA is proposing to amend 40 CFR 98.323(a)(2) to read, “Values of V, C, T, P, and, if applicable, (f
For the reasons described in section II.B of this preamble, the EPA is proposing two changes to subpart FF that will improve the quality of data received by the GHGRP and seeking comment on a third. First, the EPA is proposing to amend 40 CFR 98.324(b) to no longer allow MSHA quarterly inspection reports to be used as a source of data for monitoring methane liberated from ventilation systems. Instead, the facility will be required to use either of the two other methods set forth in the rule to monitor methane released from mine ventilation systems: CEMS or independently collected grab samples. Second, the EPA is proposing to add annual coal production to the list of data reporting requirements outlined in 40 CFR 98.326. Third, the EPA is seeking comment on increasing the frequency with which grab samples must be taken, from quarterly to monthly.
Under 40 CFR 98.324(b)(1) through (3), reporters may choose to monitor methane liberated from mine ventilation systems using any one or a combination of three approved methods: 40 CFR 98.324(b)(1)—quarterly grab samples; 40 CFR 98.324(b)(2)—data from MSHA quarterly inspection reports; or 40 CFR 98.324(b)(3)—use of a CEMS. MSHA conducts health and safety inspections at all operating mines at least once every quarter. Each inspection includes a methane survey of the ventilation system to ensure that the mines are operating within prescribed safety limits. To obtain methane measurements, an MSHA inspector takes grab samples using sealed test tubes. The samples are analyzed at an MSHA laboratory. A handheld anemometer is used to determine ventilation air flow. Approximately 50 percent of the 125 mines reporting to the GHGRP use MSHA quarterly reports as the basis for reporting methane liberation from ventilation.
The EPA is proposing to remove the option of using MSHA quarterly inspection reports as an accepted methodology for monitoring methane liberation in mine ventilation systems. Reporters would be required to collect grab samples or use a CEMS to monitor mine ventilation systems. This change will remove 40 CFR 98.324(b)(2). We are
The second proposal to improve data quality under subpart FF adds a new provision 40 CFR 98.326(u). The EPA is proposing to require reporters to report the total volume of coal produced, in short tons, during the reporting period. An important approach for verifying the accuracy of subpart FF annual reports is a comparison of year to year changes in methane liberation and methane emissions for each facility. To support report verification, the EPA is proposing to add coal production to the list of required data to be reported under subpart FF. In many instances, an increase or decrease in coal production is a reasonable explanation for a corresponding increase or decrease in methane liberation. Obtaining annual coal production data with the annual subpart FF report would allow the EPA to review year-to-year changes in methane emissions in light of changes in coal production. These data are expected to reduce the burden on reporters and the EPA in verifying the annual reports. This change will not result in additional reporting burden for the mine because coal companies closely track coal production and report quarterly production totals to MSHA. MSHA makes quarterly and annual coal production publicly available through MSHA's Mine Data Retrieval System (MDRS) at
Third, the EPA is seeking comment on increasing the sampling frequency for reporters using grab samples from quarterly to monthly in order to provide more accurate and reliable data. Currently, mines that monitor methane liberation from grab samples must take at least one grab sample per quarter for each ventilation monitoring point (40 CFR 98.324(b)(1)), and report methane liberation on a quarterly basis. Mine-specific daily and weekly data sets show that significant day-to-day and week-to-week variation in methane emissions can occur depending on operating and geologic conditions at a mine. According to the IPCC Guidelines, frequent measurements of underground coal mine emissions can account for such variability and also reduce the intrinsic errors in the measurement techniques. As emissions vary over the course of a year due to variations in coal production rate and associated drainage, good practice is to collect measurement data as frequently as practical, preferably biweekly or monthly to smooth out variations.
Using VAM emissions data recorded daily and weekly from the three underground coal mines (one with daily sampling and two with weekly sampling), the EPA analyzed the average daily VAM emissions rate by randomly selecting the sampling day or week during a 12 month reporting period. Mine A had daily CH
To assess the variability in emissions, each case was run for a weekly, monthly, and quarterly sampling frequency over a 12 month reporting period. For Mine A, the results showed that weekly sampling produced a small standard deviation of 1.6% compared to daily sampling. For all three mines, the results showed the standard deviations increased to 4.3–5.2% when sampling frequency decreased from weekly to monthly sampling. Finally, the results showed the standard deviations increased to 12.1–13.4% when sampling frequency decreased from monthly sampling to quarterly sampling. Due to the day-to-day variability in VAM emissions, ranges of maximum possible errors are also greater with decreased sampling frequency. Deviations from the actual value for monthly sampling ranged from 8.8–10.7%, while deviations for quarterly sampling ranged from 20.6–35.1%.
This analysis demonstrates that uncertainty decreases as sampling frequency increases, most noticeably when the frequency decreases from quarterly to monthly. Although the EPA considered requiring weekly sampling, it appears that monthly sampling strikes the most appropriate balance between improving data quality while limiting the additional burden on reporters for more frequent sampling. The EPA also notes that a number of mines reporting to the GHGRP already take grab samples on a more frequent basis than the quarterly MSHA sampling requirements.
For additional information regarding the EPA's preliminary analysis for increasing monitoring frequency, see the memorandum entitled “Evaluating Possible VAM Emissions Estimation Errors Based on Different Sampling Intervals (Quarterly, Monthly, Weekly),” Ruby Canyon Engineering, dated June 10, 2015, in Docket Id. No. EPA–HQ–OAR–2015–0526. The EPA encourages commenters to submit studies, data, and background information demonstrating multi-year VAM monitoring on a basis that is more frequent than quarterly. This information will help determine the appropriate frequency of monitoring for ventilation emissions that is needed to ensure accurate and reliable measurements.
Finally, we are also proposing a change to 40 CFR 98.324(b)(1) to require use of the most recent edition of the MSHA Handbook for inspections and sampling procedures entitled, Coal Mine Safety and Health General Inspection Procedures Handbook Number: PH13–V–1, February 2013.
In addition to improving the quality of data reported to the GHGRP, and, in turn, the quality of emissions data aggregated and reported to the public by the GHGRP, the proposed changes to monitoring methods for mine ventilation systems, as well as the addition of annual coal production to the data reporting requirement, would improve the emissions estimates for coal mines reported in the U.S. GHG Inventory. For more information on subpart FF confidentiality determinations resulting from these proposed revisions, see section IV of this preamble.
As described in section II.C of this preamble, we are proposing revisions to Part 98 to respond to issues raised by reporters and to more closely align rule requirements with the processes conducted at specific facilities. The following proposed revisions to subpart FF are in response to comments and questions we have received since reporting under subpart FF began in 2011.
In 40 CFR 98.323(a) and (b), we are proposing to clarify for Equations FF–1 and FF–3 the method for determining the number of days in a month or week (n) where active ventilation and degasification are taking place. In both equations, the definition of Number of Days (n) is being clarified to note that (n) is determined by taking the number of hours in the monitoring period and dividing by 24 hours per day.
In 40 CFR 98.323(a)(3) and 40 CFR 98.323(b)(2), the text is being amended to state that the quarterly sum of CH4 liberated from ventilation and degasification systems, respectively, “must be” rather than “should be” determined as the sum of the CH4 liberated at each monitoring point during that quarter. This change is being proposed because calculating the quarterly sum of CH4 liberated is required rather than being optional.
The EPA is proposing to remove “If applicable” in 40 CFR 98.324(h) to clarify that the provision requiring the owner or operator to document the procedures used to ensure the accuracy of gas flow rate, gas composition, temperature, pressure, and moisture content measurements is a requirement for all reporters, because grab samples and CEMS would be the only acceptable monitoring methods if the amendments to 40 CFR 98.324(b) are finalized as proposed.
In 40 CFR 98.326(r)(2), we are proposing to clarify the start date and end date for a well, shaft, or vent hole. This requirement has caused confusion for some reporters. The start date of a well, shaft, or vent hole is the date of actual initiation of operations and may begin in a year prior to the reporting year. For purposes of reporting, we are amending paragraph (r)(2) to state that the end date of a well, shaft, or vent hole is the last day of the reporting year if the well, shaft, or vent hole is operating on that date.
In 40 CFR 98.326(r)(3), we are proposing to add language clarifying the method for determining and reporting the number of days a well, shaft, or vent hole was in operation during the reporting year. The number of days is determined by dividing the total operating hours in the reporting year by 24 hours per day. This change is consistent with similar changes to the method for determining number of days in Equations FF–1 and FF–3, discussed earlier in this section.
In addition to the substantive changes proposed, for the reasons described in section II.D of this preamble, we are proposing minor revisions that are intended to clarify specific provisions in subpart FF. These minor revisions are summarized in the Table of Revisions available in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
In this action, we are proposing several amendments, clarifications, and corrections to subpart HH of Part 98. This section discusses the substantive changes to subpart HH; additional minor amendments, corrections, and clarifications are summarized in the Table of Revisions available in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
For the reasons described in section II.A of this preamble, we are proposing one amendment that is intended to simplify and streamline the requirements of subpart HH and focus the provisions of the rule on the essential data that the EPA requires to review, assess, and verify reported emissions. We are proposing to revise 40 CFR 98.346(f) to remove the requirement to report the surface area for each type of cover material used at the facility. The surface area for each cover material used has not been useful in assessing or verifying reported emissions and therefore, the EPA is proposing to remove the requirement to report this data. The proposed amendment will still require the reporting of the total surface area of the landfill containing waste (in square meters) and an identification of the type(s) of cover material used. This information is used during verification to check the consistency of the collection efficiency reported by the landfill. However, when multiple cover types are used, reporters will no longer be required to report the surface area of the landfill containing waste associated with each cover type. The proposed change would reduce the burden to reporters and the agency as described in section II.A of this preamble.
For the reasons described in section II.B of this preamble, the EPA is proposing several amendments to
First, we are seeking comment on whether revisions should be made to Table HH–3 to allow landfill owners or operators to determine the weighted average collection efficiency for their landfill using either an area-based weighting approach, as has been required in previous reporting years, or a volume-based weighting approach. We are also seeking comment on whether reporters should be given the option to use either approach, or if one approach should be required if reporters meet certain landfill characteristics and if so, what those landfill characteristics should be. We have received comments from reporters stating that the area weighted average does not accurately reflect the overall efficiency of the gas collection system due to differences in the waste depth or age in different portions of their landfill. We considered allowing reporters to define subareas of the landfill and perform all of the subpart HH calculations and report the equation inputs for each subarea. This approach would consider the effects of waste age, composition, and quantity for the different landfill subareas, but it would essentially double or triple the number of reporting elements, depending on the number of subareas defined. We next considered providing a volume-based weighting approach for calculating collection efficiency. This approach only considers some of the variables that influence methane generation rate, but these are variables already reported, namely the depths for each waste area defined in Table HH–3. If the option to use the area weighted approach or the volume-based weighting approach is finalized, no new reporting elements beyond an indication of which weighting approach is used would be required. This revision would allow us to use the data previously reported to develop a consistent time line, if necessary, without requiring reporters to revise previously submitted reports. If a requirement to use one approach over another for reporters with certain landfill characteristics is finalized, one or more new reporting elements may be required depending on what the certain landfill characteristics are.
Consequently, we are seeking comment on (1) whether reporters should be given the option to calculate the collection efficiency; (2) whether reporters should be allowed to use and report the option of either the area weighted average or the volume weighted average approach; (3) whether reporters should be required to use one approach over the other depending on specific landfill characteristics (e.g., reporters with drastically different wastes depths in portions of their landfill should be required to use the volume weighted approach); and (4) what those specific landfill characteristics should be. We expect that the many landfills that have similar waste depths in different areas of their landfill (or a single area) will maintain their existing data collection and calculation procedures by using the area weighted average. In contrast, we expect reporters with different waste depths in portions of their landfill to use the volume weighted average approach, thereby improving the accuracy of the data reported for those landfills. If finalized, these changes would be effective beginning with the 2016 reporting year and are not retroactive.
We are proposing to broaden the description of area type A5 in Table HH–3 to include alternative final covers. Currently, facilities with landfill gas collection and approved alternative final covers are not allowed to use the 95 percent collection efficiency in their emissions calculations because an alternative final cover does not fit the exact language in the definition for area type A5 in Table HH–3. This proposed revision would allow facilities with alternative final covers to use a collection efficiency greater than 75 percent. Alternative final covers may include, but are not limited to, evapotranspiration covers, capillary barrier covers, asphalt covers, or concrete covers. The state, local, or other agency responsible for permitting the landfill determines whether an alternative final cover meets the applicable regulatory requirements and has been shown to adequately protect human health and the environment. This rule does not intend to provide details of the design or implementation of alternative final covers and solely relies on the agency responsible for permitting the landfill to approve an alternative final cover at the facility. For clarity, we are also proposing a definition for alternative final covers to this effect in 40 CFR 98.348.
We are also proposing to revise 40 CFR 98.346(i)(5) to require reporting of the annual hours that active gas flow was sent to each destruction device instead of reporting the annual operating hours for each destruction device associated with a given measurement location. The proposed revision refers to the fraction of hours the destruction device was operating (f
Finally, landfills with active gas collection systems must calculate and report their GHG emissions in two ways. Equation HH–6 is designed to be driven by the modeled methane generation (
We allowed the term G
For more information on subpart HH confidentiality determinations resulting from these proposed revisions, see section IV of this preamble.
We are proposing two amendments for subpart HH for the reasons described in section II.C of this preamble. These proposed amendments are anticipated to have minimal or no impact on burden for reporters. On April 2, 2013, the EPA proposed flux-dependent oxidation fractions based on data provided by industry representatives (78 FR 19802). While we proposed the use of these oxidation fractions with no minimum soil cover requirement, we received comments on the proposed soil oxidation fractions noting that soil oxidation only occurs with soil of adequate depth, porosity, temperature and microbes. To respond to this comment, we reviewed the soil depths present in the peer-reviewed studies upon which the data were based and determined that the studies supporting the higher flux-dependent oxidation fractions were performed on soils with an average depth across all of the studies reviewed of 24 inches or more of soil cover. We finalized the proposed flux dependent soil oxidation fractions, and also included a requirement that these flux dependent soil oxidation fractions could only be used if the majority of the landfill area that contains waste has a soil cover of at least 24 inches (78 FR 71971, November 29, 2013). We subsequently received an administrative petition for reconsideration from Waste Management, Inc. (hereafter referred to as “Petitioner”) on January 28, 2014 regarding the inclusion of this minimum soil cover requirement in order to use the flux-dependent soil oxidation fractions, titled “Waste Management's Petition for Reconsideration of 2013 Revisions to Greenhouse Gas Reporting Rule and Final Confidentiality Determinations for New or Substantially Revised Data Elements Docket I.D. EPA–HQ–OAR–2012–0934” (hereafter referred to as the “Petition for Reconsideration,” available in the docket for this rulemaking). This section of this preamble discusses the specific issue raised in the Petition for Reconsideration that is addressed in this action, the review and analysis that was undertaken since the Petition for Reconsideration was received, and the changes the EPA is proposing in response to the petition. The EPA intends to complete its response to the Petition for Reconsideration through this rulemaking.
In response to the Petition for Reconsideration, the EPA re-evaluated the available peer-reviewed literature (27 studies) at the time of proposal regarding soil oxidation fractions. This review found that 85 percent of the data points in the literature where both methane oxidized and cover depth were reported had a cover depth of 24 inches or more. This investigation confirmed that the vast majority of the soil oxidation studies were performed on landfills with cover depths of 24 inches or more, which was the basis for the 24 inch soil depth requirement in the final rule (78 FR 71927, November 29, 2013). However, several of these studies investigated the oxidation profile within the cover soil and several of these studies indicated that the majority of soil oxidation occurs in the top 12 to 15 inches of the soil cover. While some of the data support the idea that the bulk of the oxidation may occur in the top 12 to 15 inches of the soil, it is unclear whether these soils would have had similar oxidation rates if only 12 or 15 inches of soil cover were present. For further details on the review of the soil oxidation literature, see the memorandum entitled “Review of Oxidation Studies and Associated Cover Depth in the Peer-Reviewed Literature” from Kate Bronstein, Meaghan McGrath, and Jeff Coburn, RTI International to Rachel Schmeltz, EPA, dated June 17, 2015, in Docket Id. Number EPA–HQ–OAR–2015–0526.
We also reviewed the codified state standards from all 50 states for requirements regarding intermediate or interim cover depth and found that the depth requirements are not consistent from state to state, and for some states depth requirements are not specified (
After reviewing the literature on the soil oxidation studies and the codified state standards for intermediate soil cover, we determined that while the literature studies are not conclusive regarding the minimum soil cover necessary for oxidation to occur, they do show that oxidation generally occurs with at least 12 inches of soil cover. Further, most states require at least 12 inches of intermediate soil cover. As a result, we are proposing to revise and clarify the soil cover requirements as follows. First, we are proposing to revise the phrase “. . . for a majority of the landfill area containing waste . . .” to read “. . . for at least 50 percent of the landfill area containing waste . . .” to clarify that we intended the majority of the landfill to mean 50 percent or more. Second, we are proposing to revise the requirement for “. . . a soil cover of at least 24 inches . . .” to read “. . . intermediate or interim soil cover . . .” Third, we propose to define intermediate or interim soil cover in 40 CFR 98.348 to mean “the placement of material over waste in a landfill for a period of time prior to disposal of additional waste and/or final closure as defined by state regulation, permit, guidance or written plan, or state accepted best management practice.” In the case where a landfill is located in a state that does not have an intermediate
Lastly, in our review of the oxidation studies, we noted that some investigators observed that soil methane flux near passive vent locations was low. Most of the landfills where methane flux and soil oxidation were measured occurred at landfills with active gas collection systems. For landfills with passive gas collection, a significant portion of the generated methane can be released via these passive vents and bypass diffusion through the cover soil. That is, landfill gas that is lost through the passive vents would not undergo any soil oxidation. The GHGRP does not currently require, nor are we proposing to require, direct measurement of passive vent flows; thus, a facility is unable to determine the fraction of the generated landfill gas that bypasses the soil cover and it is therefore not possible to estimate a weighted average soil oxidation fraction for landfills with passive vents. It is important to note that the Intergovernmental Panel on Climate Change 2006 Guidelines
While we are proposing to lower the minimum amount of soil cover required to use certain oxidation fractions, we are proposing to require the use of a 10 percent oxidation fraction for landfills with passive or active venting, or for landfills with less than 12 inches of soil cover (that do not also have a geomembrane cover) because application of higher soil oxidation fractions would be inappropriate at landfills with limited cover soils or passive vent systems because a significant portion of the landfill gas may be released through channels or vents with little to no soil oxidation occurring.
We are also proposing to add definitions of “passive vent” and “active venting” to further clarify the rule requirements as they pertain to landfill gas collection system flow and composition monitoring and the use of soil oxidation fractions. Specifically, we are proposing “
For the reasons described in section II.D of this preamble, we are proposing several minor corrections and clarifications to subpart HH of Part 98, including editorial changes and clarifications to reporting requirements. These minor revisions are summarized in the Table of Revisions available in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
We are proposing amendments to subpart II of Part 98 (Industrial Wastewater). This section discusses the substantive changes to subpart II; additional minor amendments, corrections, and clarifications are summarized in the Table of Revisions available in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
For the reasons described in section II.B of this preamble, the EPA is proposing amendments to subpart II reporting requirements that would provide additional data to support estimates included in the U.S. GHG Inventory, while generally resulting in only a slight increase in burden for reporters.
We are proposing an amendment to 40 CFR 98.356 to require facilities that perform ethanol production to indicate if their facility uses a wet milling process or a dry milling process. To clarify this requirement, we are proposing amendments to 40 CFR 98.358 to add definitions of “wet milling” and “dry milling.” The EPA intends to use the data on the numbers of facilities with wet versus dry milling processes and their respective wastewater characteristics to update assumptions used in the U.S. GHG Inventory and thereby improve the estimates of U.S. emissions from wastewater treatment at ethanol production facilities. In addition, the EPA intends to update the U.S. GHG Inventory using data on the level of biogas recovery in use at wet milling facilities and at dry milling facilities. For more information on subpart II confidentiality determinations resulting from these proposed revisions, see section IV of this preamble.
For the reasons described in section II.C of this preamble, the EPA is proposing several clarifying amendments to subpart II; these proposed changes would have no impact on burden for reporters. In order to resolve uncertainties in the reporting requirements in 40 CFR 98.356(b)(1) and 40 CFR 98.356(d)(3) through (d)(6) regarding how to calculate weekly averages for chemical oxygen demand (COD) and 5-day biochemical oxygen demand (BOD
For the reasons described in section II.D of this preamble, we are proposing several minor clarifications to subpart II of Part 98. These minor revisions are summarized in the Table of Revisions available in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
In this action, we are proposing several amendments to subpart LL of Part 98 (Suppliers of Coal-based Liquid Fuels). This section discusses the substantive changes to subpart LL; additional minor amendments, corrections, and clarifications are summarized in the Table of Revisions available in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
For the reasons described in section II.A of this preamble, we are proposing several revisions to 40 CFR part 98, subpart LL (Suppliers of Coal-based Liquid Fuels) to clarify requirements and amend data reporting requirements, resulting in a decrease in burden for reporters.
As described in section II.A of this preamble, we are proposing to remove the requirements of 40 CFR 98.386(a)(4), (a)(8), (a)(15), (b)(4), and (c)(4) for each facility, importer, and exporter to report the annual quantity of each coal-based liquid fuel on the basis of the measurement method used. Reporters would continue to report the annual quantities of each coal-based liquid fuel in metric tons or barrels at 40 CFR 98.386(a)(2), (a)(6), (a)(14), (b)(2), and (c)(2). We are also proposing to clarify that the quantity of bulk natural gas liquids (NGLs) reported under 40 CFR 98.386(a)(20) should not include NGLs already reported as individual products under 40 CFR 98.386(a)(2). These changes not only clarify the reporting requirements, but also harmonize subpart LL requirements with those of subpart MM.
For the reasons described in section II.D of this preamble, we are proposing several minor clarifications to subpart LL of Part 98. These minor revisions are summarized in the Table of Revisions available in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
In this action, we are proposing several amendments, clarifications, and corrections to subpart NN of Part 98 (Suppliers of Natural Gas and Natural Gas Liquids). This section discusses the substantive changes to subpart NN; additional minor amendments, corrections, and clarifications are summarized in the Table of Revisions available in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
For the reasons described in section II.B of this preamble, we are proposing one amendment to subpart NN that would improve the quality of the data collected under Part 98 while generally resulting in only a slight increase in burden for reporters. Each local distribution company (LDC) reporting under subpart NN is defined in 40 CFR 98.400(b) as a company that owns or operates distribution pipelines that physically deliver natural gas to end users that are within a single state. LDCs provide the EPA with a corporate address on their certificate of representation which may or may not be within the state where the LDC operates.
The EPA is proposing to add a new reporting requirement at 40 CFR 98.406(b)(14) to support data verification and make the data more useful to the public. The new data element would require LDCs to provide the name of the U.S. state or territory covered in the report. This data element will improve the EPA's ability to compare reported data to information contained in outside data sets (such as those from the EIA). Adding this requirement will enable the EPA to identify a larger portion of LDCs in the EIA data set which will lead to improved data quality in both the EPA and the EIA data sets. This data element will also allow users of GHGRP data to more easily identify the state within which the LDC operates, which will be useful for determining state level GHG totals associated with natural gas supply.
For more information on subpart NN confidentiality determinations resulting from these proposed revisions, see section IV of this preamble.
For the reasons described in section II.D of this preamble, the EPA is proposing several changes to subpart NN that are corrections, editorial changes, and minor clarifications to improve understanding of the rule. These additional minor corrections to subpart NN are discussed in the Table of Revisions available in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
In this action, we are proposing several amendments to subpart OO of Part 98 (Suppliers of Industrial Greenhouse Gases). This section discusses all of the proposed changes to subpart OO.
As discussed in section II.B of this preamble, we are proposing revisions that would allow the EPA to collect data that would improve the EPA's understanding of industrial GHG supplies while generally resulting in only a slight increase in burden for reporters. We are proposing three amendments to subpart OO of Part 98 (Suppliers of Industrial Greenhouse Gases) that would improve the quality of the data collection under Part 98 and improve the U.S. GHG Inventory.
We are proposing two revisions to the definition of the source category to include facilities that (1) destroy 25,000 mtCO
By requiring facilities that destroy fluorinated GHGs to report that destruction, we would capture such destruction and thereby eliminate a potential overestimate of the U.S. supply of fluorinated GHGs. To avoid covering the destruction of very small quantities of fluorinated GHGs that do not have a material impact on the CO
This expansion of the definition of the subpart OO source category would apply to facilities that destroy previously produced fluorinated GHGs and that are not already required to report any residual emissions of the destroyed fluorinated GHGs under another subpart. For example, cement kilns that annually accept and destroy a total of 25,000 mtCO
We estimate that five to ten destruction facilities would be newly covered by subpart OO under this amendment. This estimate is based on the number of facilities that report destruction of ozone-depleting substances (ODSs) to the EPA under the Stratospheric Protection Program. Because fluorinated GHGs are chemically similar to ODSs, are manufactured and imported by many of the same facilities and companies that manufacture and import ODSs, and are used in many of the same applications as ODSs, the set of facilities destroying fluorinated GHGs is likely to be similar to the set of facilities destroying ODSs. These facilities include hazardous waste treatment facilities that use a variety of different destruction technologies such as plasma arc and combustion. Facilities destroying very small quantities of ODSs were excluded from the total because similar quantities of fluorinated GHGs appeared unlikely to equal or exceed the proposed 25,000 mtCO
The same rationale applies to destruction of fluorinated HTFs; reporting by suppliers of fluorinated HTFs is discussed below.
Collecting information on the U.S. supply of fluorinated HTFs would enable us to compare reported supplies to the demand for fluorinated HTFs that we calculate based on the emissions (1) reported under subpart I, and (2) estimated for electronics facilities that do not report under subpart I (
Suppliers of fluorinated HTFs would be subject to the same thresholds as suppliers of fluorinated GHGs. That is, there would be no threshold for producers of fluorinated HTFs, but the threshold for importers, exporters, and destroyers of fluorinated HTFs would be 25,000 mtCO
For more information on subpart OO confidentiality determinations resulting from these proposed revisions, see section IV of this preamble.
In this action, we are proposing amendments to subpart RR of Part 98 (Geologic Sequestration of Carbon Dioxide). This section discusses all of the proposed changes to subpart RR.
As discussed in section II.B of this preamble, we are proposing revisions that would allow the EPA to collect data that would improve the EPA's understanding of GHG emissions from geologic sequestration, while generally resulting in a minimal increase in burden for reporters. The EPA is proposing to add a data reporting element to 40 CFR 98.446 to indicate whether the facility is injecting a CO
In this action, we are proposing amendments to subpart TT of Part 98 (Industrial Waste Landfills). This section discusses the substantive changes to subpart TT; one additional correction is summarized in the Table of Revisions available in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
For the reasons described in section II.B of this preamble, the EPA is proposing several amendments to Table TT–1 to subpart TT of Part 98 that would improve the quality of the data collected under the GHGRP and improve the EPA's understanding of sector GHG emissions, and are anticipated to either have no impact on the burden for reporters or may reduce burden for some facilities currently using site-specific factors. During the development of subpart TT, we received several comments regarding the need to provide more default DOC values for specific industrial waste streams, particularly from the pulp and paper industry. Additionally, on May 17, 2013, we received written comments from the American Forest and Paper Association and the American Wood Council, with input from the National Council for Air and Stream Improvement, on the proposed 2013 Revisions to the Greenhouse Gas Reporting Rule and Proposed Confidentiality Determination for New or Substantially Revised Data Elements (78 FR 19802, April 2, 2013). These comments stated that the current DOC values in Table TT–1 overstate substantially the GHG emissions from landfills at pulp and paper mills. (See Docket Id. No. EPA–HQ–OAR–2012–0934). One suggested resolution was for the EPA to create separate categories of wastes that would include largely inorganic waste streams and assign a lower DOC value in Table TT–1. At that time, the information provided in the comments was considered new, the comments contained only limited data on which to base any changes, and they did not address items that were not part of the proposal. The EPA also did not have data to develop more waste specific DOC values for any of the industrial waste categories. Instead, we provided methods in the rule that allowed reporters to develop site-specific DOC values for wastes that may not be well-characterized by the default values provided in Table TT–1. While we still maintain that site-specific DOC values are preferable to the Table TT–1 defaults, we reviewed the site-specific DOC values reported under subpart TT from 2011 to 2013 to determine if we had adequate data to develop more specific industry default DOC values for inclusion in Table TT–1. For most industries, we did not have enough data from site-specific DOC estimates to establish new or revise default DOC values for inclusion in Table TT–1. However, we had site-specific DOC data for over 100 waste streams at pulp and paper manufacturing facilities. We note that the pulp and paper industry accounts for approximately 55 percent of the subpart TT reporters and accounts for 62 percent of the emissions reported during the 2013 reporting year. Within the data, we found four general pulp and paper waste types for which reporters commonly developed site-specific DOC values. These are: Boiler ash, kraft recovery (causticizing) wastes, wastewater treatment sludges, and other (which included hydropulper rejects, bark wastes, and digester knots). We found that our general pulp and paper waste (other than industrial sludge) default DOC value was reasonable for the “other” waste category, but overestimated DOC content for other pulp and paper waste streams. Boiler ash and kraft recovery wastes had very low DOC values, but not low enough to be considered “inerts.” We also found that wastewater treatment sludges for the pulp and paper industry had, on average, a slightly higher DOC content than the default for “industrial sludge.” See memorandum, “Review of Site-Specific Industrial Waste Degradable Organic Content Data” from Jeff Coburn and Katherine Bronstein, RTI International to Rachel Schmeltz, EPA, dated June 17, 2015 in Docket Id. EPA–HQ–OAR–2015–0526.
Based on the available site-specific DOC values for these different pulp and paper industry wastes, we consider it appropriate to provide additional default DOC values for the pulp and paper industry for the purposes of improving the accuracy of the methane emissions estimates reported under subpart TT. Specifically, we are proposing to provide default DOC values for the four specific pulp and paper industry waste types previously listed. The proposed default DOC value for boiler ash is 0.06; the proposed default DOC value for kraft recovery wastes is 0.025. As proposed, these values, rather than the previous “pulp and paper waste (other than industrial sludge)” default value of 0.20 or the “Inert Waste [
While we are proposing to provide these specific defaults for different types of waste in the pulp and paper industry, we do not intend to prevent the pulp and paper industry from using the other default values in Table TT–1 that may apply. For example, if construction and demolition wastes are disposed of in a landfill at a pulp and paper manufacturing facility, the reporter may still use the construction and demolition waste default DOC value for these waste streams. However, to clarify, we intend to require the pulp and paper industry to use the industry-specific wastewater sludge default DOC value, and are therefore proposing to revise the “Industrial Sludge” category to be “Industrial Sludge (other than pulp and paper industry sludge).”
For the reasons described in section II.D of this preamble, we are proposing one minor correction to subpart TT of Part 98 that is an editorial change. This minor revision is summarized in the Table of Revisions available in the docket for this rulemaking (Docket Id. No. EPA–HQ–OAR–2015–0526).
In addition to the substantive amendments proposed in sections III.A through III.Y of this preamble, for the reasons described in section II.D of this preamble, we are proposing minor revisions, clarifications, and corrections to subparts P, U, MM, PP, and UU of Part 98. The proposed changes to these subparts are provided in the Table of Revisions for this rulemaking, available in Docket Id. No. EPA–HQ–OAR–2015–0526, and include clarifying requirements to better reflect the EPA's intent, corrections to calculation terms or cross-references that do not revise the output of calculations, harmonizing changes within a subpart (such as changes to terminology), simple typographical errors, and other minor corrections (
In this notice we are proposing confidentiality determinations for new or substantially revised reporting data elements (
In this action, we are proposing confidentiality determinations for 117 new or substantially revised data reporting requirements in 21 subparts. We are not proposing new confidentially determinations for data reporting elements where the change does not require an additional or different data element to be reported. The final confidentiality determinations the EPA has previously made for these minimally revised data elements are unaffected by this proposed amendment and continue to apply.
We are also proposing confidentiality determinations for 27 existing data elements in subparts I, Z, MM, NN, PP, and RR that are not revised in the proposed amendments. These include 22 data elements in subparts I, Z, MM, and RR for which the EPA had not made previous confidentiality determinations under Part 98, as well as two data elements in subpart NN for which a previous confidentiality determination is proposed to be revised because of new information indicating the data element is not entitled to confidential treatment under the provisions in 40 CFR 2.208. We are also proposing confidentiality determinations for three data elements in subpart PP that were included in the finalized “Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units” (EGU NSPS) (Docket Id. No. EPA–HQ–OAR–2013–0495).
These proposed confidentiality determinations would be finalized before the end of 2016 based on public comment. The confidentiality determinations for new and substantially revised data elements would apply at the same time as the proposed rule amendments described in sections II and III of this preamble, as described in section I.E of this preamble. The confidentiality determinations for the existing Part 98 data elements would apply to reports submitted in RY2016 as well as all prior reporting years in which the data elements applied. This proposal is one of a series of rulemakings dealing with confidentiality determinations for data reported under Part 98. For more information on previous confidentiality determinations for Part 98 data elements, see the following notices:
• 75 FR 39094, July 7, 2010; hereafter referred to as the “July 7, 2010 CBI proposal.” Describes the data categories and category-based determinations the EPA developed for the Part 98 data elements.
• 76 FR 30782, May 26, 2011; hereafter referred to as the “2011 Final CBI Rule.” Assigned data elements to data categories and published the final CBI determinations for the data elements in 34 Part 98 subparts, except for those data elements that were assigned to the “Inputs to Emission Equations” data category.
• 77 FR 48072, August 13, 2012, hereafter referred to as “2012 Final CBI Determinations Rule.” Finalized confidentiality determinations for data elements reported under nine subparts I, W, DD, QQ, RR, SS, UU; except for those data elements that are inputs to emission equations. Also finalized confidentiality determinations for new data elements added to subparts II and TT in the November 29, 2011 Technical Corrections Notice (76 FR 73886).
• 78 FR 68162; November 13, 2013; hereafter referred to as the “2013 Amendments and Confidentiality Determinations for Electronics Manufacturing.” Finalized confidentiality determinations for new data elements added to subpart I.
• 78 FR 69337, November 29, 2013; hereafter referred to as the “2013 Revisions Rule.” Finalized determinations for new and revised data elements in 15 subparts, except for those data elements assigned to the “Inputs to Emission Equations” data category.
• 79 FR 63750, October 24, 2014; Final Inputs Rule. Revised recordkeeping and reporting requirements for 23 subparts and finalized confidentiality determinations for new data elements in 11 subparts.
To make the determinations proposed in this notice, we applied the same approach as previously used for making confidentiality determinations for data elements reported under the GHGRP, which consisted of assigning data elements to an appropriate data category and then either assigning the previously determined category-based confidentiality determination or making an individual determination if the data element is assigned to a category for which no category-based determination was previously made. The data categories used were those finalized in the 2011 Final CBI Rule.
In the 2011 Final CBI Rule, the EPA made categorical confidentiality determinations for data elements assigned to eight direct emitter data categories and eight supplier data categories. For two direct emitter data categories (“Unit/Process `Static' Characteristics that Are Not Inputs to Emission Equations” and “Unit/Process Operating Characteristics that Are Not Inputs to Emission Equations,”) and three supplier data categories (“GHGs Reported,” “Production/Throughput Quantities and Composition,” and “Unit/Process Operating Characteristics”), the EPA did not make categorical CBI determinations; instead the EPA determined that none of the data elements were emissions data (as defined in 40 CFR 2.301(a)(2)(i)) and made CBI determinations for each individual data elements based on the criteria in 40 CFR 2.208. In subsequent amendments to Part 98,
In this action, we are proposing to assign new and substantially revised data elements in the proposed amendments, as well as certain existing data elements in subparts I, Z, II, MM, NN, PP, and RR, to the appropriate direct emitter or supplier data category.
Although the EPA grouped similar data into categories and made categorical confidentiality determinations for a number of data categories, the EPA also recognized in previous rulemakings that similar data elements may not always have the same confidentiality status
Please see the memorandum titled “Proposed Data Category Assignments and Confidentiality Determinations for Data Elements in the Proposed 2015 Revisions” in Docket Id. No. EPA–HQ–OAR–2015–0526 for a list of the proposed new, substantially revised, and existing data elements, their proposed category assignments, and their proposed confidentiality determinations (whether categorical or individual).
In this action, the EPA is proposing to assign each of the 117 new or substantially revised data reporting requirements to the appropriate direct emitter or supplier data category. New and substantially revised data elements assigned to categories with categorical confidentiality determinations are summarized in the memorandum “Proposed Data Category Assignments and Confidentiality Determinations for Data Elements in the Proposed 2015 Revisions,” available in Docket Id. No. EPA–HQ–OAR–2015–0526. For new and substantially revised reporting elements assigned to direct emitter or supplier data categories without a categorical determination, we are proposing that these data elements are not emission data and are making individual CBI determinations for each data element. We are proposing individual CBI determinations for 48 data elements assigned to the “Unit/Process ‘Static' Characteristics that Are Not Inputs to Emission Equations” and “Unit/Process ‘Operating' Characteristics that Are Not Inputs to Emission Equations” direct emitter data categories and the “Production/Throughput Quantities and Composition” and “Unit/Process Operating Characteristics” supplier data categories. These data elements consist of 17 new data elements in the direct emitter subparts C, E, F, I, S, V, X, Y, DD, II, and subpart RR, and 27 new data elements in the supplier subpart OO. We are also proposing individual CBI determinations for four substantially revised data elements in subparts Y, DD, HH, and II. Table 7 of this preamble provides the category assignment and proposed rationale for the proposed determinations.
We are proposing to assign one revised data element in subpart Z (Phosphoric Acid Production) to the “Unit/Process `Static' Characteristics that are Not Inputs to Emissions Equation Category” but are not making a confidentiality determination for this data element. The provision 40 CFR 98.266(f)(3) requires reporting the annual phosphoric acid production capacity (tons) for each wet-process phosphoric acid process line (metric tons). The EPA reviewed the available capacity information and determined that the situation may vary for individual facilities. While the production capacity data elements are generally publicly available through construction and Title V permits, there may be facilities where these data are not public. Further, the information publicly available for facilities may not necessarily be the same as the data elements required under Part 98. For example, capacity data available in the Title V permit may be a plant-wide throughput capacity rather than the capacity of the individual process line reported under Part 98. For this reason, we have decided not to make a confidentiality determination for this revised data element, but instead determinations for this data element will be made on a case-by-case basis. This decision not to propose a determination for this data element is consistent with our treatment of other capacity data (
We are also proposing to make an individual confidentiality determination for one data element in subpart FF without assigning it to a data category. While our general approach for making confidentiality determination is to assign each data element to a data category and apply the categorical confidentiality determination where one has been made, we are not doing so here for the following reason. The data element at issue is in provision 40 CR 98.326(u), which requires the annual coal production in short tons for the reporting year. The proposed data element shares characteristics with data elements previously assigned to the
We are proposing categorical determinations for 22 data elements currently in subparts I, Z, MM, and RR for which no determination has been previously proposed or finalized under Part 98, as well as for three data elements that were proposed to be included in subpart PP in the finalized EGU NSPS. For subpart I, the affected data element was revised in final subpart I rule amendments on November 13, 2013 (78 FR 68162) following public comment. In this case, the EPA had not proposed a confidentiality determination for the revised data element and therefore did not finalize a determination in the final rule. For subpart Z, we are proposing to clarify the original determination for a data element in which it is unclear how to apply the final determination assigned in the 2011 Final CBI Rule. For subpart MM, we are proposing a determination for one data element where the EPA inadvertently failed to finalize a determination in the 2013 Revisions Rule. We are proposing confidentiality determinations for three data elements in subpart PP which were added to Part 98 in the EGU NSPS. Finally, we are proposing confidentiality determinations for 16 data elements in subpart RR. In the 2012 Final CBI Determinations Rule (77 FR 48072, August 13, 2012), we did not finalize a confidentiality determination for these data elements, which relate to facility-level and flow meter-level quantities of CO2 received onsite, because the sensitivity of these data elements was dependent on whether the reporter conducted enhanced oil and gas recovery (ER) activities or non-ER activities. In this action, we are proposing to require that facilities report whether they are conducting ER activities. As such, the proposed amendments would allow the submitted reports to indicate that the facility is conducting ER activities and therefore would allow for categorical confidentiality determinations for these data elements.
Of these data elements, we are proposing to assign one data element in subpart MM to the “Amount and Composition of Materials Received” supplier data category, which has a categorical confidentiality determination of CBI. We are proposing to assign the remaining data elements in subparts I, Z, PP, and RR to the “Unit/Process `Operating' Characteristics that Are Not Inputs to Emission Equations” and “Unit/Process `Static' Characteristics that Are Not Inputs to Emission Equations” direct emitter data categories and the “Production/Throughput Quantities and Composition” supplier data categories, and are proposing individual confidentiality determinations for these data elements. For 16 data elements in subpart RR, we are proposing separate determinations for each data element for facilities conducting ER operations and facilities conducting non-ER operations.
Table 8 of this preamble provides the category assignment and proposed rationale for the proposed determinations for the existing data elements in subparts I, Z, MM, PP, and RR.
We are proposing revised confidentiality determinations for two existing data elements in subpart NN. Under subpart NN, local distribution companies report the volume of natural gas withdrawn from on-system storage and the annual volume of liquefied natural gas (LNG) withdrawn from storage and vaporized for delivery on the distribution system (40 CFR 98.406(b)(3)). The EPA previously assigned these data elements to the “Amount and Composition of Materials Received” category, which has a confidentiality determination of CBI. The EPA is proposing to change these data elements' status from CBI to non-CBI. These data elements are reported to the EPA by LDCs subject to subpart W of Part 98 (Petroleum and Natural Gas Systems) in addition to subpart NN. In support of a recent subpart W rulemaking (79 FR 70352, November 25, 2014), review of publicly available data found that gas withdrawals from underground storage are reported to the EIA on form EIA–176 (Annual Report of Natural and Supplemental Gas Supply and Disposition). As we noted in the proposed version of that rule, the EIA considers all information submitted on EIA–176 to be non-proprietary information and publishes the quantity of natural gas withdrawn from storage on their Web site. Data that are already in the public domain are not entitled to confidential treatment under the provisions in 40 CFR 2.208. Since the quantity of natural gas withdrawn from storage is publicly available, the EPA proposes to assign the confidentiality determination for 40 CFR 98.406(b)(3) to “not CBI.”
For the CBI component of this rulemaking, we are soliciting comment on the following specific issues. We
If you believe that the EPA has improperly assigned certain new, substantially revised, or existing data elements in these subparts to any of the data categories established in the 2011 Final CBI Rule, please provide specific comments identifying which of the data elements may be wrongly assigned along with a detailed explanation of why you believe them to be incorrectly assigned and in which data category you believe they belong. In addition, if you believe that a data element should be assigned to one of the five categories that do not have a categorical confidentiality determination, please also provide specific comment along with detailed rationale and supporting information on whether such data element does or does not qualify as CBI. We also seek comment on the proposed confidentiality status of the new, substantially revised, or existing data elements in the direct emitter data categories “Unit/Process `Operating' Characteristics that Are Not Inputs to Emission Equations” and “Unit/Process `Static' Characteristics that Are Not Inputs to Emission Equations” and the supplier data categories “Production/Throughput Quantities and Composition” and “Unit/Process Operating Characteristics.”
By proposing confidentiality determinations prior to data reporting through this proposal and rulemaking process, we provide potential reporters an opportunity to submit comments, particularly comments identifying data they consider sensitive and their rationales and supporting documentation. This opportunity to submit comments is the same opportunity that is afforded to submitters of information in case-by-case confidentiality determinations. In addition, it provides an opportunity to rebut the agency's proposed determinations prior to finalization. We will evaluate the comments on our proposed determinations, including claims of confidentiality and information substantiating such claims, before finalizing the confidentiality determinations. Please note that this will be reporters' only opportunity to substantiate a confidentiality claim. Upon finalizing the confidentiality determinations of the data elements identified in this rule, the EPA will release or withhold these data in accordance with 40 CFR 2.301, which contains special provisions governing the treatment of Part 98 data for which confidentiality determinations have been made through rulemaking.
When submitting comments regarding the confidentiality determinations we are proposing in this action, please identify each individual proposed new, revised, or existing data element you do or do not consider to be CBI or emission data in your comments. Please explain specifically how the public release of that particular data element would or would not cause a competitive disadvantage to a facility. Discuss how this data element may be different from or similar to data that are already publicly available. Please submit information identifying any publicly available sources of information containing the specific data elements in question. Data that are already available through other sources would likely be found not to qualify for CBI protection. In your comments, please identify the manner and location in which each specific data element you identify is publicly available, including a citation. If the data are physically published, such as in a book, industry trade publication, or federal agency publication, provide the title, volume number (if applicable), author(s), publisher, publication date, and International Standard Book Number (ISBN) or other identifier. For data published on a Web site, provide the address of the Web site, the date you last visited the Web site and identify the Web site publisher and content author.
If your concern is that competitors could use a particular data element to discern sensitive information, specifically describe the pathway by which this could occur and explain how the discerned information would negatively affect your competitive position. Describe any unique process or aspect of your facility that would be revealed if the particular proposed new or revised data element you consider sensitive were made publicly available. If the data element you identify would cause harm only when used in combination with other publicly available data, then describe the other data, identify the public source(s) of these data, and explain how the combination of data could be used to cause competitive harm. Describe the measures currently taken to keep the data confidential. Avoid conclusory and unsubstantiated statements, or general assertions regarding potential harm. Please be as specific as possible and include all information necessary for the EPA to evaluate your comments.
The EPA is proposing amendments to Part 98 that would streamline and improve implementation of the rule, improve the quality and consistency of the data collected under the rule, and clarify certain provisions. The proposed revisions are anticipated to increase burden in cases where the proposed amendments would expand current applicability, monitoring, or reporting, and are anticipated to decrease burden in cases where the proposed amendments would streamline Part 98 to remove notification or reporting requirements or simplify the data that must be reported. For most subparts, we are proposing both revisions that would result in an increase in burden and revisions that would result in a decrease in burden. In several cases, we are proposing changes where we anticipate a decrease in burden, but are unable to quantify this decrease. This conservative approach means that the impacts for this proposed rule generally reflect an increase in burden for most subparts. For example, as discussed in section II.C and II.K of this preamble, we are proposing amendments to add new reporting requirements to subpart E and subpart V to improve the quality of the data collected under the rule, as well as amendments that would streamline the rule by conditionally removing the annual approval request for an alternative method for determining N
As discussed in section I.E of this preamble, we are proposing to implement these changes over reporting years 2016, 2017, and 2018 in order to stagger the implementation of these changes over time and provide time for needed software revisions. The burden has subsequently been determined
A full discussion of the impacts may be found in the memorandum, “Assessment of Burden Impacts of 2015 Revisions to the Greenhouse Gas Reporting Rule,” available in Docket Id. No. EPA–HQ–OAR–2015–0526.
The estimated incremental change in burden from the proposed amendments to Part 98 include burden associated with: (1) Changes to the reporting requirements by adding, revising, or removing existing reporting requirements (21 subparts); (2) revisions to the applicability of subparts such that additional facilities would be required to report under Part 98 (subparts V and OO); and (3) additional monitoring requirements (subpart FF).
Section III of this preamble describes proposed amendments to each subpart of Part 98 that improve the quality and accuracy of the data collected under the GHGRP, improve verification of collected data, and provide additional data to help improve estimates included in the U.S. GHG Inventory. In general, these proposed amendments would add reporting requirements or revise existing reporting requirements to collect more detailed facility data. The proposed amendments would collectively add or revise data elements in 21 subparts of Part 98, including 97 data elements that were not previously required to be collected. With the exception of revisions to subpart FF (Underground Coal Mines), the collection of these new and revised data elements would not add new monitoring requirements, and would not substantially affect the type of information that must be collected. For all of these additional data elements, the EPA has estimated a nominal additional cost to report the data element and fulfill the recordkeeping requirements. The EPA is also proposing to remove 18 data elements in subparts O, Y, DD, HH, and LL. For these data elements, the EPA has estimated a nominal reduction in cost, since reporters would no longer be required to report the data element. The total incremental costs from the addition, revision, and removal of these reporting requirements are anticipated at $39,234 annually ($2011). This includes $9,359 from revisions implemented in RY2016, $25,650 from revisions first implemented in RY2017, and $4,225 from revisions first implemented in RY2018. For subpart I, the new data elements in the proposed rule pertain to the triennial technology report required under 40 CFR 98.96(y), which must first be submitted with RY2016 reports on or before March 31, 2017 and every three years thereafter. For the purposes of estimating burden, the annual costs associated with these data elements ($1,226) would apply in RY2016 only. For RY2017 and RY2018, the estimated incremental cost associated with reporting the new, revised, and removed data elements for all affected source categories is $33,782 and $38,007, respectively.
All costs to the regulated industry resulting from changes to the reporting requirements for the GHGRP are labor costs (
The EPA is proposing revisions that would affect the applicability of two subparts of Part 98: Subpart V (Nitric Acid Production) and subpart OO
To estimate the cost impacts for additional reporters, the recent information collection request for the GHG reporting program
As discussed in section III.R.2 of this preamble, we are proposing changes to the monitoring requirements of subpart FF of Part 98 to remove the option to allow MSHA quarterly inspection reports to be used as a source of data for monitoring methane liberated from ventilation systems. Instead, facilities would be required to independently collect their own grab samples or to use CEMS. The incremental increase in costs for subpart FF reporters who would no longer have the option to use MSHA data (and would need to collect monthly grab samples) are $28,440 per facility in the first year and $14,609 per facility in subsequent years ($2011); these revisions would affect approximately 65 reporters anticipated to use MSHA data annually. The proposed revisions would have an industry-wide incremental cost of $1,848,571 in the first year and $949,582 in subsequent years. The proposed changes would apply beginning in RY2018.
The incremental costs to the regulated industry resulting from changes to the monitoring requirements for Underground Coal Mines are based on the collection of independent grab samples in ventilation air. Currently, about 50 percent of subpart FF reporters collect quarterly gas samples. For mines that currently use MSHA data, the annual incremental costs for taking grab samples was estimated as the cost of taking the samples, less the avoided cost of obtaining, interpreting and reporting MSHA data. We assumed that facilities would not install a CEMS as a result of the monitoring changes.
The costs resulting from removing the use of MSHA quarterly data and requiring facilities to collect quarterly grab samples include additional labor costs (
In addition to amendments that would revise the existing applicability, monitoring, or reporting requirements of Part 98, the EPA is proposing additional technical revisions and other clarifications to several subparts in Part 98 that are not anticipated to have a significant impact on burden. These include revisions discussed in section III of this preamble that are intended to streamline the rule requirements, including proposed revisions to clarify and revise the requirements of Part 98 in order to focus GHGRP and reporter resources on relevant data, to expand and clarify the conditions under which a facility can cease reporting, or to clarify requirements for facilities that report very little or no emissions, and revisions that would improve the efficiency of the reporting and verification process. These changes are anticipated to minimally reduce burden for reporters.
The EPA is also proposing revisions that are intended to improve the quality of the rule but that would not impact burden, such as amending calculation methods to improve the accuracy of the emissions estimate (
We are proposing, for certain subparts, to amend monitoring or measurement methods to more closely align rule requirements with different operating scenarios in the industry. Other proposed amendments would provide flexibility for reporters and clarify reporting requirements, as described in section II.C of this preamble. These proposed amendments are anticipated to have no impact or minimally decrease burden for reporters.
The proposed revisions also include minor amendments, corrections, and clarifications, including simple revisions of requirements such as clarifying changes to definitions, calculation methodologies, monitoring and quality assurance requirements, missing data procedures, and reporting requirements. These proposed changes clarify Part 98 to better reflect the EPA's intent, and would not present any additional burden on reporters.
A full discussion of the burden associated with the proposed revisions for each subpart may be found in the memorandum, “Assessment of Burden Impacts of 2015 Revisions to the Greenhouse Gas Reporting Rule,” available in Docket Id. No. EPA–HQ–OAR–2015–0526.
This action is a significant regulatory action that was submitted to the Office of Management and Budget (OMB) for review because the proposed amendments raise novel legal or policy issues. Any changes made in response to OMB recommendations have been documented in the docket. The EPA prepared an economic analysis of the potential costs and benefits associated with this action. A copy of the analysis is available in Docket Id. No. EPA–HQ–
The information collection activities in this proposed rule have been submitted for approval to the OMB under the PRA. The Information Collection Request (ICR) document that the EPA prepared has been assigned EPA ICR number 2300.18. You can find a copy of the ICR in the docket for this rule, and it is briefly summarized here.
This action is proposing to amend specific provisions in the Greenhouse Gas Reporting Rule to streamline and improve implementation of the rule, improve the quality and consistency of the data collected under the rule, and to clarify or propose minor updates to certain provisions that have been the subject of questions from reporting entities. These proposed amendments would improve the quality and consistency of the data collected, as well as improve the efficiency of the reporting process for both the EPA and reporters. The proposed amendments are anticipated to increase burden in cases where the proposed amendments would expand current applicability, monitoring, or reporting, and are anticipated to decrease burden in cases where the proposed amendments would streamline Part 98 to remove notification or reporting requirements or simplify the data that must be reported.
Specifically, this action proposes to amend the reporting requirements to add or revise 118 data elements in 21 subparts of Part 98. These revisions are necessary to improve the quality of the data collected under the GHGRP. The EPA is also proposing to remove 18 data elements in five subparts, which would streamline rule requirements. This action also proposes amendments that would affect the applicability of two subparts of Part 98: subparts V (Nitric Acid Production) and OO (Suppliers of Industrial Greenhouse Gases). These amendments could increase the number of facilities required to report under Part 98. Finally, this action proposes to revise the monitoring requirements of subpart FF of Part 98 (Underground Coal Mines). The proposed amendments would remove the option to allow Mine Safety and Health Administration (MSHA) quarterly inspection reports to be used as a source of data for monitoring methane liberated from ventilation systems, and require facilities to independently collect their own grab samples or to use continuous emissions monitoring. Impacts associated with the proposed changes to the applicability, monitoring, and reporting requirements are detailed in the memorandum “Assessment of Burden Impacts of 2015 Revisions to the Greenhouse Gas Reporting Rule” (see Docket Id. No. EPA–HQ–OAR–2015–0526). Burden is defined at 5 CFR 1320.3(b).
The total estimated incremental burden and cost associated with the proposed revisions is 23,456 hours and $2,049,478 over the 3 years covered by the information collection. These costs include $9,359 in RY2016, $33,782 in RY2017, and $2,006,337 in RY2018, averaging $683,159 per year over the three years. The total estimated number of reporters affected by the proposed amendments is 8,240. The proposed frequency of response for these changes is once annually, with the exception of certain data elements for subpart I which would be submitted once every three years.
The estimated incremental costs and hour burden associated with the addition and revision of 118 data elements and the removal of 18 data elements in 21 subparts is 682 hours and $39,234 annually ($2011), including $9,359 from revisions first implemented in RY2016, $25,650 from revisions first implemented in RY2017, and $4,225 from revisions first implemented in RY2018. For subpart I, the new data elements in the proposed rule pertain to the triennial technology report required under 40 CFR 98.96(y), which must first be submitted with RY2016 reports on or before March 31, 2017 and every three years thereafter. For the purposes of estimating burden for the three years covered by the information collection, the annual burden and costs associated with these data elements (21 hours and $1,226) would apply for RY2016 only. Therefore, the estimated incremental burden and cost associated with reporting the new, revised, and removed data elements for all affected source categories is 588 hours and $33,782 in RY2017, and 661 hours and $38,007 for RY2018. The annual reporting burden associated with these changes is estimated to average 0.17 hour per response, and the estimated number of reporters affected is 7,127.
The estimated incremental cost burden associated with additional reporters to subparts V and OO is $119,759 in the first year (RY2018) and $93,015 in subsequent years. The incremental burden for the additional reporters for subpart V includes first-year costs of $83,544 and subsequent year costs of $66,403. The incremental burden for the additional reporters for subpart OO includes first-year costs of $36,215 and subsequent year costs of $26,612. The estimated number of likely new respondents that would result from these amendments is 12, including four additional reporters under subpart V, and an average of eight additional reporters for subpart OO. The annual hourly burden for these additional reporters is based on the annual average hourly burden for existing reporters under subparts V and OO, which is 191 hours and 55 hours per reporter, respectively.
The incremental increase in costs for subpart FF reporters from the revised monitoring requirements are $28,440 per facility in the first year (RY2018) and $14,609 in subsequent years ($2011). The proposed revisions are estimated to affect 65 respondents and would have an industry incremental cost of $1,848,571 in the first year (RY2018) and $949,582 in subsequent years. The annual hourly burden associated with these monitoring costs are 320 hours per reporter in the first year and 165 hours in subsequent years.
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for the EPA's regulations in 40 CFR are listed in 40 CFR part 9.
Submit your comments on the agency's need for this information, the accuracy of the provided burden estimates and any suggested methods for minimizing respondent burden to the EPA using the docket identified at the beginning of this rule. You may also send your ICR-related comments to OMB's Office of Information and Regulatory Affairs via email to
I certify that this action will not have a significant economic impact on a substantial number of small entities under the RFA. In making this determination, the impact of concern is any significant adverse economic impact on small entities. An agency may certify that a rule will not have a significant economic impact on a substantial number of small entities if the rule relieves regulatory burden, has no net burden or otherwise has a positive economic effect on the small entities subject to the rule. The impacts to small entities due to the revisions was evaluated for each subpart. The EPA conducted a screening assessment
Although there are no small entity impacts associated with these proposed revisions, in the development of Part 98, the EPA took several steps to reduce the impact on small entities. For example, the EPA determined appropriate thresholds that reduced the number of small businesses reporting. In addition, the EPA conducted several meetings with industry associations to discuss regulatory options and the corresponding burden on industry, such as recordkeeping and reporting. The proposed rule amendments are minor technical corrections, clarifying, and other amendments that will not impose any new requirement on small entities that are not currently required by the regulation of Part 98. We have therefore concluded that this action will have no net regulatory burden for all directly regulated small entities. The EPA continues to conduct significant outreach on the GHGRP and maintains an “open door” policy for stakeholders to help inform the EPA's understanding of key issues for the industries. We continue to be interested in the potential impacts of the proposed rule amendments on small entities and welcome comments on issues related to such impacts.
This action does not contain an unfunded mandate of $100 million or more as described in UMRA, 2 U.S.C. 1531–1538, and does not significantly or uniquely affect small governments.
The action implements mandate(s) specifically and explicitly set forth in CAA section 114(a)(1) without the exercise of any policy discretion by the EPA.
This action does not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government.
This action does not have tribal implications as specified in Executive Order 13175. The proposed rule amendments would not result in any changes to the requirements that are not currently required for 40 CFR part 98. Thus, Executive Order 13175 does not apply to this action. Consistent with the EPA Policy on Consultation and Coordination with Indian Tribes, the EPA consulted with tribal officials during the development of the rules for Part 98. A summary of that consultation is provided in sections VIII.E and VIII.F of the preamble to the October 30, 2009 final GHG reporting rule.
The EPA interprets Executive Order 13045 as applying only to those regulatory actions that concern environmental health or safety risks that the EPA has reason to believe may disproportionately affect children, per the definition of “covered regulatory action” in section 2–202 of the Executive Order. This action is not subject to Executive Order 13045 because it does not concern an environmental health risk or safety risk.
This action is not a “significant energy action” because it is not likely to have a significant adverse effect on the supply, distribution or use of energy. Part 98 relates to monitoring, reporting, and recordkeeping and does not impact energy supply, distribution, or use. This final rule amends monitoring, calculation, and reporting requirements for the GHGRP. In addition, the EPA is proposing confidentiality determinations for new and revised data elements proposed in this rulemaking and for certain existing data elements for which a confidentiality determination has not previously been proposed, or where the EPA has determined that the current determination is no longer appropriate. These proposed amendments and confidentiality determinations do not make any changes to the existing monitoring, calculation, and reporting requirements under Part 98 that affect the supply, distribution, or use of energy.
This rulemaking does not involve technical standards.
The EPA believes the human health or environmental risk addressed by this action will not have potential disproportionately high and adverse human health or environmental effects on minority, low-income or indigenous populations because it does not affect the level of protection provided to human health or the environment because it is a rule addressing information collection and reporting procedures.
Environmental protection, Administrative practice and procedure, Greenhouse gases, Incorporation by reference, Reporting and recordkeeping requirements, Suppliers.
For the reasons stated in the preamble, the Environmental Protection Agency proposes to amend title 40, chapter I, of the Code of Federal Regulations as follows:
42 U.S.C. 7401–7671q.
The revisions and additions read as follows:
(a) * * *
(1)
(i) * * *
(1) If reported emissions are less than 25,000 metric tons CO
(2) If reported emissions are less than 15,000 metric tons CO
(3) If the operations of a facility or supplier are changed such that all applicable processes and operations subject to paragraphs (a)(1) through (4) of this section cease to operate, then the owner or operator may discontinue complying with this part for the reporting years following the year in which cessation of such operations occurs, provided that the owner or operator submits a notification to the Administrator that announces the cessation of reporting and certifies to the closure of all applicable processes and operations no later than March 31 of the year following such changes. If one or more processes or operations subject to paragraphs (a)(1) through (4) of this section at a facility or supplier cease to operate, but not all applicable processes or operations cease to operate, then the owner or operator is exempt from reporting for any such processes or operations in the reporting years following the reporting year in which cessation of the process or operation occurs, provided that the owner or operator submits a notification to the Administrator that announces the cessation of reporting for the process or operation no later than March 31 of the year following such changes. This paragraph (i)(3) does not apply to seasonal or other temporary cessation of operations. This paragraph (i)(3) does not apply to facilities with municipal solid waste landfills or industrial waste landfills, or to underground coal mines except those with abandoned status as determined by the U.S. Mine Safety & Health Administration. The owner or operator must resume reporting for any future calendar year during which any of the GHG-emitting processes or operations resume operation.
(4) The provisions of paragraphs (i)(1) and (2) of this section apply to suppliers subject to subparts LL through QQ of this part by substituting the term “quantity of GHG supplied” for “emissions.” For suppliers, the provisions of paragraphs (i)(1) and (2) of this section apply individually to each importer and exporter and individually to each petroleum refinery, fractionator of natural gas liquids, local natural gas distribution company, and producer of CO
(5) If the operations of a facility or supplier are changed such that a process or operation no longer meets the “Definition of Source Category” as specified in an applicable subpart, then the owner or operator may discontinue complying with any such subpart for the reporting years following the year in which change occurs, provided that the owner or operator submits a notification to the Administrator that announces the cessation of reporting for the process or operation no later than March 31 of the year following such changes. The owner or operator must resume complying with this part for the process or operation starting in any future calendar year during which the process or operation meets the “Definition of Source Category” as specified in an applicable subpart.
(6) If an entire facility or supplier is merged into another facility or supplier that is already reporting GHG data under this part, then the owner or operator may discontinue complying with this part for the facility or supplier, provided that the owner or operator submits a notification to the Administrator that announces the discontinuation of reporting and the e-GGRT identification number of the reconstituted facility no later than March 31 of the year following such changes.
The revisions and additions read as follows:
(c) * * *
(4) * * *
(iii) Annual emissions from each applicable source category, expressed in metric tons of each applicable GHG
(G) For each reported fluorinated GHG and fluorinated heat transfer fluid, report the following identifying information:
(
(
(
(5) * * *
(ii) Quantity of each GHG from each applicable supply category in Table A–5 to this subpart, expressed in metric tons of each GHG. For each reported fluorinated GHG, report the following identifying information:
(A) Chemical name. If the chemical is not listed in Table A–1 of this subpart, then use the method of naming organic chemical compounds as recommended by the International Union of Pure and Applied Chemistry (IUPAC).
(B) The CAS registry number assigned by the Chemical Abstracts Registry Service. If a CAS registry number is not assigned or is not associated with a single fluorinated GHG, then report an identification number assigned by EPA's Substance Registry Services.
(C) Linear chemical formula.
(8) Each parameter for which a missing data procedure was used according to the procedures of an applicable subpart and the total number of hours in the year that a missing data procedure was used for each parameter. Parameters include not only reported data elements, but any data element required for monitoring and calculating emissions.
(d) * * *
(1) * * *
(i) Monitoring methods currently used by the facility that do not meet the specifications of a relevant subpart.
(h) * * *
(4) Notwithstanding paragraphs (h)(1) and (2) of this section, upon request by the owner or operator, the Administrator may provide reasonable extensions of the 45-day period for submission of the revised report or information under paragraphs (h)(1) and (2) of this section. If the Administrator receives a request for extension of the 45-day period, by email to an address prescribed by the Administrator prior to the expiration of the 45-day period, the extension request is deemed to be automatically granted for 30 days. The Administrator may grant an additional extension beyond the automatic 30-day extension if the owner or operator submits a request for an additional extension and the request is received by the Administrator prior to the expiration of the automatic 30-day extension, provided the request demonstrates that it is not practicable to submit a revised report or information under paragraphs (h)(1) and (2) of this section within 75 days. The Administrator will approve the extension request if the request demonstrates to the Administrator's satisfaction that it is not practicable to collect and process the data needed to resolve potential reporting errors identified pursuant to paragraphs (h)(1) or (2) of this section within 75 days.
(i) * * *
(6) A list of the subparts that the owners and operators anticipate will be included in the annual GHG report. The list of potentially applicable subparts is required only for an initial certificate of representation that is submitted after [date of publication of the final rule in the
(e) * * *
(33) ASTM D6866–12 Standard Test Methods for Determining the Biobased Content of Solid, Liquid, and Gaseous Samples Using Radiocarbon Analysis, IBR approved for §§ 98.34(d), 98.34(e), and 98.36(e).
(l) * * *
(1) Coal Mine Safety and Health General Inspection Procedures Handbook, Handbook Number: PH13–V–1, February 2013, IBR approved for § 98.324(b).
The revisions read as follows:
(a) * * *
(2) * * *
(ii) * * *
(A) * * *
(5) * * *
(i) * * *
(C) Divide the cumulative annual CO
(ii) * * *
(C) Divide the cumulative annual CO
(iii) * * *
(C) Divide the cumulative annual CO
(d) Except as otherwise provided in § 98.33(b)(1)(vi) and (vii), when municipal solid waste (MSW) is either the primary fuel combusted in a unit or the only fuel with a biogenic component combusted in the unit, determine the biogenic portion of the CO
(e) For other units that combust combinations of biomass fuel(s) (or heterogeneous fuels that have a biomass component,
(c) * * *
(1) * * *
(iii) Cumulative maximum rated heat input capacity of the group (mmBtu/hr). The cumulative maximum rated heat input capacity shall be determined as the sum of the maximum rated heat input capacities for all units in the group, excluding units less than 10 (mmBtu/hr).
(3) * * *
(ii) Cumulative maximum rated heat input capacity of the units served by the common pipe (mmBtu/hr). The cumulative maximum rated heat input capacity shall be determined as the sum of the maximum rated heat input capacities for all units served by the common pipe, excluding units less than 10 (mmBtu/hr).
(e) * * *
(2) * * *
(i) For the Tier 1 Calculation Methodology, report:
(A) The total quantity of each type of fuel combusted in the unit or group of aggregated units (as applicable) during the reporting year, in short tons for solid fuels, gallons for liquid fuels and standard cubic feet for gaseous fuels, or, if applicable, therms or mmBtu for natural gas.
(B) If applicable, the moisture content used to calculate the wood and wood residuals wet basis HHV for use in Equations C–1 and C–8, in percent.
(x) When ASTM methods D7459–08 (incorporated by reference, see § 98.7) and D6866–12 (incorporated by reference, see § 98.7) are used to determine the biogenic portion of the annual CO
(xi) When ASTM methods D7459–08 (incorporated by reference, see § 98.7) and D6866–12 (incorporated by reference, see § 98.7) are used in accordance with § 98.34(e) to determine the biogenic portion of the annual CO
(a) The applicable records specified in §§ 98.34(f), 98.35(b), and 98.36(e).
(b) * * *
(37) Moisture content used to calculate the wood and wood residuals wet basis HHV (percent), if applicable (Equations C–1 and C–8).
The revisions, and additions read as follows:
The additions read as follows:
(a) * * *
(2) Request Administrator approval for an alternative method of determining N
(i) If you received Administrator approval for an alternative method of determining N
(ii) You must notify the EPA of your use of a previously approved alternative method in your annual report.
(iii) Otherwise, you must submit the request within 45 days following promulgation of this subpart or within the first 30 days of each subsequent reporting year.
(iv) If the Administrator does not approve your requested alternative method within 150 days of the end of the reporting year, you must determine the N
(f) Types of abatement technologies used and date of installation for each (if applicable).
(a) Where anode or paste consumption data are missing, CO
(c) * * *
(2) Anode effect minutes per cell-day (AE-mins/cell-day), anode effect frequency (AE/cell-day), anode effect duration (minutes). (Or anode effect overvoltage factor ((kg CF4/metric ton Al)/(mV/cell day)), potline overvoltage (mV/cell day), current efficiency (%).)
(3) Smelter-specific slope coefficients (or overvoltage emission factors) and the last date when the smelter-specific slope coefficients (or overvoltage emission factors) were measured.
(f) You may use company records or an engineering estimate to determine the annual ammonia production and the annual methanol production.
The revisions and additions read as follows:
(a) If a CEMS is used to measure CO
(3) Annual ammonia production (metric tons, sum of all process units reported within subpart G of this part).
(b) * * *
(2) Annual quantity of each type of feedstock consumed for ammonia manufacturing (scf of feedstock or gallons of feedstock or kg of feedstock).
(7) Annual average carbon content of each type of feedstock consumed.
(15) Annual methanol production for each process unit (metric tons), regardless of whether the methanol is subsequently destroyed, vented, or sold as product.
The revisions read as follows:
(a) * * *
(1) If you manufacture semiconductors, you must adhere to the procedures in paragraphs (a)(1)(i) through (iii) of this section. You must calculate annual emissions of each input gas and of each by-product gas using Equations I–6 and I–7 of this subpart, respectively. If your fab uses less than 50 kg of a fluorinated GHG in one reporting year, you may calculate emissions as equal to your fab's annual consumption for that specific gas as calculated in Equation I–11 of this subpart, plus any by-product emissions of that gas calculated under paragraph (a) of this section.
(d) * * *
N
F
(i) * * *
(1) * * *
(ii) You must use representative data from the previous reporting year to estimate the consumption of input gas i as calculated in Equation I–13 of this subpart and the fraction of input gas i and by-product gas k destroyed in abatement systems for each stack system as calculated by Equations I–24A and I–24B of this subpart. If you were not required to submit an annual report under subpart I for the previous reporting year and data from the previous reporting year are not available, you may estimate the consumption of input gas i and the fraction of input gas i destroyed in abatement systems based on representative operating data from a period of at least 30 days in the current reporting year. When calculating the consumption of input gas i using Equation I–13 of this subpart, the term “f
(iv) If you anticipate an increase or decrease in annual consumption or emissions of any fluorinated GHG, or the number of tools connected to abatement systems greater than 10 percent for the current reporting year compared to the previous reporting year, you must account for the anticipated change in your preliminary estimate. You may account for such a change using a quantifiable metric (
(3) * * *
(ii) * * *
(iii) * * *
d
(iv) * * *
d
(v) * * *
d
(vi) * * *
dk
(viii) When using the stack testing option described in paragraph (i) of this section, you must calculate the weighted-average fraction of each fluorinated input gas i and each fluorinated by-product gas k destroyed or removed in abatement systems for each fab f, as applicable, by using Equation I–24A (for input gases) and Equation I–24B (for by-product gases) of this subpart.
Where:
d
d
C
(1—U
B
DRE
DRE
f = fab.
i = Fluorinated GHG input gas.
j = Process type.
(4)
(f) If your fab employs abatement systems and you elect to reflect emission reductions due to these systems, or if your fab employs abatement systems designed for fluorinated GHG abatement and you elect to calculate fluorinated GHG emissions using the stack test method under § 98.93(i), you must comply with the requirements of paragraphs (f)(1) through (3) of this section. If you use an average of properly measured destruction or removal efficiencies for a gas and process sub-type or process type combination, as applicable, in your emission calculations under § 98.93(a), (b), and/or (i), you must also adhere to procedures in paragraph (f)(4) of this section.
(j) * * *
(5) * * *
(ii)
The revisions read as follows:
(c) * * *
(2) When you use the procedures specified in § 98.93(a), each fluorinated GHG emitted from each process type or process sub-type as calculated in Equations I–8 and I–9 of this subpart, as applicable.
(d) The method of emissions calculation used in § 98.93 for each fab.
(e) Annual production in terms of substrate surface area (e.g., silicon, PV-cell, glass) for each fab, including specification of the substrate.
(r) * * *
(2) * * *
(y) * * *
(2) * * *
(iv) It must provide any utilization and by-product formation rates and/or destruction or removal efficiency data that have been collected in the previous 3 years that support the changes in semiconductor manufacturing processes described in the report. For any utilization, by-product formation rate, and/or destruction or removal efficiency data submitted, the report must describe, where available: methods used for the measurements, wafer size, film type being manufactured, substrate type, the linewidth or technology node, process type, process subtype for chamber clean processes, the input gases used and measured, the utilization rates measured, and the by-product formation rates measured.
(d) * * *
(5) In addition to the inventory specified in § 98.96(p), the information in paragraphs (d)(5)(i) through (iii) of this section:
(7) Records of all inputs and results of calculations made to determine the average weighted fraction of each gas destroyed or removed in the abatement systems for each stack system using Equations I–24A and I–24B of this subpart, if applicable. The inputs should include an indication of whether each value for destruction or removal efficiency is a default value or a measured site-specific value.
(b) Unless you use the default value of 1.0, you must measure carbonate-based mineral mass fractions at least annually to verify the mass fraction data provided by the supplier of the raw material; such measurements shall be based on sampling and chemical analysis using consensus standards that specify X-ray fluorescence. For measurements made in years prior to the emissions reporting year 2014, you may also use ASTM D3682–01 (Reapproved 2006) Standard Test Method for Major and Minor Elements in Combustion Residues from Coal Utilization Processes (incorporated by reference,
(c) Unless you use the default value of 1.0, you must determine the annual average mass fraction for the carbonate-based mineral in each carbonate-based raw material by calculating an arithmetic average of the monthly data obtained from raw material suppliers or sampling and chemical analysis.
(d) Unless you use the default value of 1.0, you must determine on an annual basis the calcination fraction for each carbonate consumed based on sampling and chemical analysis using an industry consensus standard. If performed, this chemical analysis must be conducted using an x-ray fluorescence test or other enhanced testing method published by an industry consensus standards organization (
(b) * * *
(5) Results of all tests, if applicable, used to verify the carbonate-based mineral mass fraction for each carbonate-based raw material charged to a continuous glass melting furnace, as specified in paragraphs (b)(5)(i) through (iii) of this section.
(7) Method used to determine decimal fraction of calcination, unless you used the default value of 1.0.
(b) * * *
(3) Data on carbonate-based mineral mass fractions provided by the raw material supplier for all raw materials consumed annually and included in calculating process emissions in Equation N–1 of this subpart, if applicable.
(4) Results of all tests, if applicable, used to verify the carbonate-based mineral mass fraction for each carbonate-based raw material charged to a continuous glass melting furnace, including the data specified in paragraphs (b)(4)(i) through (v) of this section.
(d) * * *
(2) Annual amount of each carbonate-based raw material charged to each continuous glass melting furnace (tons) (Equation N–1 of this subpart).
(3) Decimal fraction of calcination achieved for each carbonate-based raw material for each continuous glass melting furnace (specify the default value, if used, or the value determined according to § 98.144) (percentage, expressed as a decimal) (Equation N–1 of this subpart).
(a) In addition to the information required by § 98.3(c), the HCFC–22 production facility shall report the following information for each HCFC–22 production process:
(d) If the HFC–23 concentration measured pursuant to § 98.154(l) is greater than that measured during the performance test that is the basis for the destruction efficiency (DE), the facility shall report the method used to calculate the revised destruction efficiency, specifying whether
(b) * * *
(3) * * *
(b) * * *
(1) Calibrate all oil and gas flow meters that are used to measure liquid and gaseous fuel and feedstock volumes (except for gas billing meters) according to the monitoring and QA/QC requirements for the Tier 3 methodology in § 98.34(b)(1). Perform oil tank drop measurements (if used to quantify liquid fuel or feedstock consumption) according to § 98.34(b)(2). Calibrate all solids weighing equipment according to the procedures in § 98.3(i).
(b) * * *
(4) Annual quantity of ammonia intentionally produced as a desired product, if applicable (metric tons).
(d) Annual quantity of carbon other than CO
(e) Annual quantity of methanol intentionally produced as a desired product, if applicable, (metric tons) for each process unit.
(b) * * *
(1) * * *
(v) * * *
(e) * * *
(6) * * *
(ii) * * *
(iii) * * *
(iv) * * *
(b) If a CEMS is not used to measure CO
(19) Annual emission factors for each lime product type produced.
(20) Annual emission factors for each calcined byproduct/waste by lime type that is sold.
(21) Annual average results of chemical composition analysis of each type of lime product produced and calcined byproduct/waste sold.
(e) If you followed the calculation method of § 98.213(a), you must report the information in paragraphs (e)(1) through (3) of this section.
A nitric acid production facility uses one or more trains to produce nitric acid. A nitric acid train produces nitric acid through the catalytic oxidation of ammonia.
(a) * * *
(2) Request Administrator approval for an alternative method of determining N
(i) If you received Administrator approval for an alternative method of determining N
(ii) You must notify the EPA of your use of a previously approved alternative method in your annual report.
(iii) Otherwise, if you have not received Administrator approval for an alternative method of determining N
(iv) If the Administrator does not approve your requested alternative method within 150 days of the end of the reporting year, you must determine the N
(h) Abatement technologies used (if applicable) and date of installation of abatement technology.
(a) The petrochemical production source category consists of processes as described in paragraphs (a)(1) through (3) of this section.
(1) The petrochemical production source category consists of all processes that produce acrylonitrile, carbon black, ethylene, ethylene dichloride, ethylene oxide, or methanol, except as specified in paragraphs (b) through (g) of this section.
(2) The petrochemical production source category includes processes that produce the petrochemical as an intermediate in the on-site production of other chemicals as well as processes that produce the petrochemical as an end product for sale or shipment off site.
(3) When ethylene dichloride and vinyl chloride monomer are produced in an integrated process, you may consider the entire integrated process to be the petrochemical process for the purpose of complying with the mass balance option in § 98.243(c). If you elect to consider the integrated process to be the petrochemical process, then the mass balance must be performed over the entire integrated process.
(c) * * *
(3) Collect a sample of each feedstock and product at least once per month and determine the molecular weight (for gaseous materials when the quantity is measured in scf) and carbon content of each sample according to the procedures of § 98.244(b)(4). If multiple valid molecular weight or carbon content measurements are made during the monthly measurement period, average them arithmetically. However, if a particular liquid or solid feedstock is delivered in lots, and if multiple deliveries of the same feedstock are received from the same supply source in a given calendar month, only one representative sample is required. Alternatively, you may use the results of analyses conducted by a feedstock supplier, or product customer, provided the sampling and analysis is conducted at least once per month using any of the procedures specified in § 98.244(b)(4).
(4) If you determine that the monthly average concentration of a specific compound in a feedstock or product is greater than 99.5 percent by volume or mass, then as an alternative to the sampling and analysis specified in paragraph (c)(3) of this section, you may determine molecular weight and carbon content in accordance with paragraphs (c)(4)(i) through (iii) of this section.
(i) Calculate the molecular weight and carbon content assuming 100 percent of that feedstock or product is the specific compound.
The revisions and additions read as follows:
(a) * * *
(5) Annual quantity of each type of petrochemical produced from each process unit (metric tons). If your petrochemical process is an integrated ethylene dichloride and vinyl chloride monomer process, report either the measured ethylene dichloride production (metric tons) or both the measured quantity of vinyl chloride monomer production (metric tons) and an estimate of the ethylene dichloride production (metric tons).
(6) * * *
(ii) Description of each type of measurement device (
(iii) Identification of each method (
(14) Annual average of the measurements of the carbon content of each feedstock and product.
(i) For feedstocks and products that are gaseous or solid, report this quantity in kg carbon per kg of feedstock or product.
(ii) For liquid feedstocks and products, report this quantity either in units of kg carbon per kg of feedstock or production, or kg C per gallon of feedstock or product.
(15) For each gaseous feedstock and product, the annual average of the measurements of molecular weight in units of kg per kg mole.
(b) * * *
(2) For CEMS used on stacks that include emissions from stationary combustion units that burn any amount of off-gas from the petrochemical process, report the relevant information required under § 98.36(c)(2) and (e)(2)(vi) for the Tier 4 calculation methodology. Section 98.36(c)(2)(ii), (ix) and (x) does not apply for the purposes of this subpart.
(3) For CEMS used on stacks that do not include emissions from stationary combustion units, report the information required under § 98.36(b)(6), (b)(7), (b)(9)(i), (b)(9)(ii) and (e)(2)(vi).
(8) Annual quantity of each type of petrochemical produced from each process unit (metric tons). If your petrochemical process is an integrated ethylene dichloride and vinyl chloride monomer process, report either the measured ethylene dichloride production (metric tons) or both the measured quantity of vinyl chloride monomer production (metric tons) and an estimate of the ethylene dichloride product (metric tons).
(a) If you comply with the CEMS measurement methodology in § 98.243(b), then you must retain under this subpart the records required for the Tier 4 Calculation Methodology in § 98.37, records of the procedures used to develop estimates of the fraction of total emissions attributable to petrochemical processing and combustion of petrochemical process off-gas as required in § 98.246(b), and records of any annual average HHV calculations.
The revisions read as follows:
(b) For flares, calculate GHG emissions according to the requirements in paragraphs (b)(1) through (3) of this section. All gas discharged through the flare stack must be considered for the flare GHG emissions calculations with the exception of gas used for the flare pilots, which may be excluded.
(1) * * *
(iii) * * *
(B) For periods of normal operation, use the average higher heating value measured for the fuel gas used as flare sweep or purge gas for the higher heating value of the flare gas. If higher heating value of the fuel gas is not measured, the higher heating value of the flare gas under normal operations may be estimated from historic data or engineering calculations.
(h) * * *
(1) For uncontrolled asphalt blowing operations or asphalt blowing operations controlled either by vapor scrubbing or by another non-combustion control device, calculate CO
(2) For asphalt blowing operations controlled by either a thermal oxidizer, a flare, or other vapor combustion control device, calculate CO
(i) For each delayed coking unit, calculate the CH
(1) Determine the typical dry mass of coke produced per cycle from company records of the mass of coke produced by the delayed coking unit. Alternatively, you may estimate the typical dry mass of coke produced per cycle based on the delayed coking unit vessel (coke drum) dimensions and typical coke drum outage at the end of the coking cycle using Equation Y–18a of this section.
(2) Determine the typical mass of water in the delayed coking unit vessel at the end of the cooling cycle prior to venting to the atmosphere using Equation Y–18b of this section.
(3) Determine the average temperature of the delayed coking unit vessel when the drum is first vented to the atmosphere using either Equation Y–18c or Y–18d of this section, as appropriate, based on the measurement system available.
(j) For each process vent not covered in paragraphs (a) through (i) of this section that can reasonably be expected to contain greater than 2 percent by volume CO
(j) Determine the quantity of petroleum process streams using company records. These quantities include the quantity of coke produced per cycle, asphalt blown, quantity of crude oil plus the quantity of intermediate products received from off site, and the quantity of unstabilized crude oil received at the facility.
(k) Determine temperature or pressure of delayed coking unit vessel using process instrumentation operated, maintained, and calibrated according to the manufacturer's instructions.
(e) * * *
(3) A description of the flare service (general facility flare, unit flare, emergency only or back-up flare) and an indication of whether or not the flare is serviced by a flare gas recovery system.
(6) If you use Equation Y–1a in § 98.253, an indication of whether daily or weekly measurement periods are used, annual average carbon content of the flare gas (in kg carbon per kg flare gas), and, either the annual volume of flare gas combusted (in scf/year) and the annual average molecular weight (in kg/kg-mole), or, the annual mass of flare gas combusted (in kg/yr).
(h) * * *
(5) * * *
(ii) * * *
(A) The annual volume of recycled tail gas (in scf/year).
(k) For each delayed coking unit, the owner or operator shall report:
(1) The unit ID number (if applicable).
(2) Maximum rated throughput of the unit, in bbl/stream day.
(3) Annual quantity of coke produced in the unit during the reporting year, in metric tons.
(4) The calculated annual CH
(5) The total number of delayed coking vessels (or coke drums) associated with the delayed coking unit.
(6) The basis for the typical dry mass of coke in the delayed coking unit vessel at the end of the coking cycle (mass measurements from company records or calculated using Equation Y–18a of this subpart).
(7) An indication of the method used to estimate the average temperature of the coke bed, T
(8) An indication of whether a unit-specific methane emissions factor or the default methane emission factor was used for the delayed coking unit.
The revisions and additions read as follows:
(b)
(41) Typical dry mass of coke in the delayed coking unit vessel at the end of the coking cycle (metric tons/cycle) from company records or calculated using Equation Y–18a of this subpart (Equations Y–18a, Y–18b and Y–18e in § 98.253) for each delayed coking unit.
(42) Internal height of delayed coking unit vessel (feet) (Equation Y–18a in § 98.253) for each delayed coking unit.
(43) Typical distance from the top of the delayed coking unit vessel to the top of the coke bed (
(44) Diameter of delayed coking unit vessel (feet) (Equations Y–18a and Y–18b in § 98.253) for each delayed coking unit.
(45) Mass of water in the delayed coking unit vessel at the end of the cooling cycle prior to atmospheric venting (metric ton/cycle) (Equations Y–18b and Y–18e in § 98.253) for each delayed coking unit.
(46) Typical distance from the bottom of the coking unit vessel to the top of the water level at the end of the cooling cycle just prior to atmospheric venting (feet) from company records or engineering estimates (Equation Y–18b in § 98.253) for each delayed coking unit.
(47) Mass of steam generated and released per decoking cycle (metric tons/cycle) (Equations Y–18e and Y–18f in § 98.253) for each delayed coking unit.
(48) Average temperature of the delayed coking unit vessel when the drum is first vented to the atmosphere (°F) (Equations Y–18c, Y–18d, and Y–18e in § 98.253) for each delayed coking unit.
(49) Temperature of the delayed coking unit vessel overhead line measured as near the coking unit vessel as practical just prior to venting the atmosphere (Equation Y–18c in § 98.253) for each delayed coking unit.
(50) Pressure of the delayed coking unit vessel just prior to opening the atmospheric vent (psig) (Equation Y–18d in § 98.253) for each delayed coking unit.
(51) Methane emission factor for delayed coking unit (kilograms CH
(52) Cumulative number of decoking cycles (or coke-cutting cycles) for all delayed coking unit vessels associated with the delayed coking unit during the year (Equation Y–18f in § 98.253) for each delayed coking unit.
(65) Specify whether the calculated or default loading factor L specified in § 98.253(n) is entered, for each liquid loaded to each vessel (methods specified in § 98.253(n)).
(f) * * *
(3) Annual phosphoric acid production capacity (tons) for each wet-process phosphoric acid process line.
(a) * * *
(1) Calculate fossil fuel-based CO
(b) * * *
(1) Calculate fossil CO
(c) * * *
(1) Calculate CO
(b) For missing measurements of the mass of spent liquor solids or spent pulping liquor flow rates, use the lesser value of either the maximum mass or fuel flow rate for the combustion unit, or the maximum mass or flow rate that the fuel meter can measure. Alternatively, records of the daily spent liquor solids firing rate obtained to comply with § 63.866(c)(1) of this chapter may be used, adjusting for the duration of the missing measurements, as appropriate.
The revisions read as follows:
(a) * * *
(2) Measure the mass of trona input to each soda ash manufacturing line on a monthly basis using belt scales or methods used for accounting purposes.
(a) * * *
(1) Annual consumption of trona or liquid alkaline feedstock at the facility level (tons).
(b) * * *
(5) Annual consumption of trona or liquid alkaline feedstock at the facility level (tons).
(a) * * *
(2) New hermetically sealed-pressure switchgear during the year.
(3) New SF
(4) Retired hermetically sealed-pressure switchgear during the year.
(5) Retired SF
(m) State(s) or territory in which the facility lies and total miles of transmission and distribution lines located within each state or territory.
(n) The following numbers of pieces of equipment:
(1) New hermetically sealed-pressure switchgear during the year.
(2) New SF
(3) Retired hermetically sealed-pressure switchgear during the year.
(4) Retired SF
The revisions and additions read as follows:
(a) * * *
(1) The quarterly periods are:
(2) Values of V, C, T, P, and, if applicable, (f
(b) * * *
(1) Values for V, C, T, P, and, if applicable, (f
(2) Quarterly total CH
The revisions read as follows:
(b) * * *
(1) Collect quarterly or more frequent grab samples (with no fewer than 6 weeks between measurements) for methane concentration and make quarterly measurements of flow rate, temperature, pressure, and, if applicable, moisture content. The sampling and measurements must be made at the same locations as Mine Safety and Health Administration (MSHA) inspection samples are taken, and should be taken when the mine is operating under normal conditions. You must follow MSHA sampling procedures as set forth in the MSHA Handbook entitled, Coal Mine Safety and Health General Inspection Procedures Handbook Number: PH13–V–1, February 2013 (incorporated by reference, see § 98.7). You must record the date of sampling, flow, temperature, pressure, and moisture measurements, the methane concentration (percent), the bottle number of samples collected, and the location of the measurement or collection.
(h) The owner or operator shall document the procedures used to ensure the accuracy of gas flow rate, gas composition, temperature, pressure, and moisture content measurements. These procedures include, but are not limited to, calibration of flow meters, and other measurement devices. The estimated accuracy of measurements and the technical basis for the estimated accuracy shall be recorded.
(f) Quarterly volumetric flow rate for each ventilation monitoring point and units of measure (scfm or acfm), date and location of each measurement, and method of measurement (quarterly sampling or continuous monitoring), used in Equation FF–1 of this subpart. Specify whether the volumetric flow rate measurement at each ventilation monitoring point is on dry basis or wet basis; or, if a flow meter is used, indicate whether or not the flow meter automatically corrects for moisture content.
(g) Quarterly CH
(h) Weekly volumetric flow rate used to calculate CH
(i) Quarterly CH
(o) Temperature (°R), pressure (atm), moisture content (if applicable), and the moisture correction factor (if applicable) used in Equations FF–1 and FF–3 of this subpart; and the gaseous organic concentration correction factor, if Equation FF–9 of this subpart was required. Moisture content is required to be reported only if CH
(r) * * *
(2) Start date and close date of each well, shaft, and vent hole. If the well, shaft, or vent hole is operating through the end of the reporting year, December 31st of the reporting year shall be the close date for purposes of reporting.
(3) Number of days the well, shaft, or vent hole was in operation during the reporting year. To obtain the number of days in the reporting year, divide the total number of hours that the system was in operation by 24 hours per day.
(u) Annual coal production in short tons for the reporting year.
(f) The surface area of the landfill containing waste (in square meters), identification of the type(s) of cover material used (as either organic cover, clay cover, sand cover, or other soil mixtures).
(i) * * *
(5) An indication of whether destruction occurs at the landfill facility, off-site, or both. If destruction occurs at the landfill facility, also report for each measurement location:
(i) The number of destruction devices associated with the measurement location.
(ii) The annual operating hours of the gas collection system associated with the measurement location,
(iii) For each destruction device associated with the measurement location, report:
(A) The destruction efficiency (decimal).
(B) The annual operating hours where active gas flow was sent to the destruction device.
(7) A description of the gas collection system (manufacturer, capacity, and number of wells), the surface area (square meters) and estimated waste depth (meters) for each area specified in Table HH–3 to this subpart, the estimated gas collection system efficiency for landfills with this gas collection system and an indication of whether the gas collection efficiency was determined on an area-weighted average basis (Option 1) or a volume-weighted average basis (Option 2), and an indication of whether passive vents and/or passive flares (vents or flares that are not considered part of the gas collection system as defined in § 98.6) are present at the landfill.
(13) Methane emissions for the landfill (
The revision and additions read as follows:
The revisions and additions read as follows:
(a) Identify the anaerobic processes used in the industrial wastewater treatment system to treat industrial wastewater and industrial wastewater treatment sludge, provide a unique identifier for each anaerobic process, indicate the average depth in meters of each anaerobic lagoon, and indicate whether biogas generated by each anaerobic process is recovered. Provide a description or diagram of the industrial wastewater treatment system, identifying the processes used, indicating how the processes are related to each other, and providing a unique identifier for each anaerobic process. Each anaerobic processes must be identified as one of the following:
(b) * * *
(6) If the facility performs an ethanol production processing operation as defined in § 98.358, you must indicate if the facility uses a wet milling process or a dry milling process.
Suppliers of coal-based liquid fuels must report the CO
Suppliers of coal-based liquid fuels must follow the calculation methods of § 98.393 as if they applied to the appropriate coal-to-liquid product supplier (
(a) In calculation methods in § 98.393 for petroleum products or petroleum-based products, suppliers of coal-to-liquid products shall also include coal-to-liquid products.
(b) In calculation methods in § 98.393 for non-crude feedstocks or non-crude petroleum feedstocks, producers of coal-to-liquid products shall also include coal-to-liquid products that enter the facility to be further processed or otherwise used on site.
(c) In calculation methods in § 98.393 for petroleum feedstocks, suppliers of coal-to-liquid products shall also include coal and coal-to-liquid products that enter the facility to be further processed or otherwise used on site.
Suppliers of coal-based liquid fuels must follow the monitoring and QA/QC requirements in § 98.394 as if they applied to the appropriate coal-to-liquid product supplier. Any monitoring and QA/QC requirement for petroleum products in § 98.394 also applies to coal-to-liquid products.
Suppliers of coal-based liquid fuels must follow the procedures for estimating missing data in § 98.395 as if they applied to the appropriate coal-to-liquid product supplier. Any procedure for estimating missing data for petroleum products in § 98.395 also applies to coal-to-liquid products.
The revisions read as follows:
(a) * * *
(9) For every feedstock reported in paragraph (a)(2) of this section for which Calculation Method 2 in
(10) For every non-solid feedstock reported in paragraph (a)(2) of this section for which Calculation Method 2 in § 98.393(f)(2) was used to determine an emissions factor, report:
(11) For every product reported in paragraph (a)(6) of this section for which Calculation Method 2 in § 98.393(f)(2) was used to determine an emissions factor, report:
(20) Annual quantity of bulk NGLs in metric tons or barrels received for processing during the reporting year. Report only quantities of bulk NGLs not reported in paragraph (a)(2) of this section.
(b) * * *
(5) For each product reported in paragraph (b)(2) of this section for which Calculation Method 2 in § 98.393(f)(2) used was used to determine an emissions factor, report:
(6) For each non-solid product reported in paragraph (b)(2) of this section for which Calculation Method 2 in § 98.393(f)(2) was used to determine an emissions factor, report:
(c) * * *
(5) For each product reported in paragraph (c)(2) of this section for which Calculation Method 2 in § 98.393(f)(2) was used to determine an emissions factor, report:
(6) For each non-solid product reported in paragraph (c)(2) of this section for which Calculation Method 2 in § 98.393(f)(2) used was used to determine an emissions factor, report:
Suppliers of coal-based liquid fuels must retain records according to the requirements in § 98.397 as if they applied to the appropriate coal-to-liquid product supplier (
Any supplier of natural gas and natural gas liquids that meets the requirements of § 98.2(a)(4) must report GHG emissions associated with the products they supply.
The revisions read as follows:
(a) * * *
(1)
(2)
(b) * * *
(1) * * *
(2) * * *
(ii) * * *
(3) * * *
(i) * * *
(ii) * * *
(4) * * *
(c) * * *
(1) * * *
(ii) * * *
(2) * * *
(a) * * *
(1) NGL fractionators and LDCs shall determine the quantity of NGLs and natural gas using methods in common use in the industry for billing purposes as audited under existing Sarbanes Oxley regulation.
(3) NGL fractionators shall use measurement for NGLs at custody transfer meters or at such meters that are used to determine the NGL product slate delivered from the fractionation facility.
(4) If a NGL fractionator supplies a product that is a mixture or blend of two or more products listed in Tables NN–1 and NN–2 of this subpart, the NGL fractionator shall report the quantities of the constituents of the mixtures or blends separately.
The revisions read as follows:
(a) * * *
(1) Annual quantity (in barrels) of each NGL product supplied (including fractionated NGL products received from other NGL fractionators) in the following product categories: Ethane, propane, normal butane, isobutane, and pentanes plus (Fuel
(2) Annual quantity (in barrels) of each NGL product received from other NGL fractionators in the following product categories: Ethane, propane, normal butane, isobutane, and pentanes plus (Fuel
(b) * * *
(1) Annual volume in Mscf of natural gas received by the LDC at its city gate stations for redelivery on the LDC's distribution system, including for use by the LDC (Fuelh in Equations NN–1 and NN–2 of this subpart).
(6) Annual volume in Mscf of natural gas delivered to downstream gas transmission pipelines and other local distribution companies (Fuel in Equation NN–3 of this subpart).
(12) For each large end-user reported in paragraph (b)(7) of this section, report:
(i) The customer name, address, and meter number(s).
(ii) Whether the quantity of natural gas reported in paragraph (b)(7) of this section is the total quantity delivered to a large end-user's facility, or the quantity delivered to a specific meter located at the facility.
(iii) If known, report the EIA identification number of each LDC customer.
(13) The annual volume in Mscf of natural gas delivered by the LDC (including natural gas that is not owned by the LDC) to each of the following end-use categories. For definitions of these categories, refer to EIA Form 176 (Annual Report of Natural Gas and Supplemental Gas Supply & Disposition) and Instructions.
(14) The name of the U.S. state or territory covered in this report submission.
(a) The industrial gas supplier source category consists of any facility that produces fluorinated GHGs, fluorinated HTFs, or nitrous oxide; any bulk importer of fluorinated GHGs, fluorinated HTFs, or nitrous oxide; any bulk exporter of fluorinated GHGs, fluorinated HTFs, or nitrous oxide; and any facility that destroys fluorinated GHGs or fluorinated HTFs.
(d) To produce a fluorinated HTF means to manufacture, from any raw material or feedstock chemical, a fluorinated GHG used for temperature control, device testing, cleaning substrate surfaces and other parts, and soldering in processes including but not limited to certain types of electronics manufacturing production processes. Fluorinated heat transfer fluids do not include fluorinated GHGs used as lubricants or surfactants. For fluorinated heat transfer fluids under this subpart, the lower vapor pressure limit of 1 mm Hg in absolute at 25 °C in the definition of fluorinated greenhouse gas in § 98.6 shall not apply. Fluorinated heat transfer fluids include, but are not limited to, perfluoropolyethers, perfluoroalkanes, perfluoroethers, tertiary perfluoroamines, and perfluorocyclic ethers. Producing a fluorinated HTF does not include the reuse or recycling of a fluorinated HTF, the creation of intermediates, or the creation of fluorinated HTFs that are released or destroyed at the production facility before the production measurement at § 98.414(a).
(e) For purposes of this subpart, to destroy fluorinated GHGs or fluorinated HTFs means to cause the expiration of a previously produced (as defined at § 98.410(b) and (d)) fluorinated GHG or fluorinated HTF to the destruction efficiency actually achieved. Such destruction does not result in a commercially useful end product. For purposes of this subpart, such destruction does not include HFC–23 destruction as defined at § 98.150 or the dissociation of fluorinated GHGs that occurs during electronics manufacturing as defined at § 98.90. For example, such destruction does not include the dissociation of fluorinated GHGs that occurs during etch or chamber cleaning processes or during use of abatement systems that treat the fluorinated GHGs vented from such processes at electronics manufacturing facilities.
You must report the GHG emissions that would result from the release of the nitrous oxide and each fluorinated GHG or fluorinated HTF that you produce, import, export, transform, or destroy during the calendar year.
The revisions read as follows:
(a) Calculate the total mass of each fluorinated GHG, fluorinated HTF, or nitrous oxide produced annually, except for amounts that are captured solely to be shipped off site for destruction, by using Equation OO–1 of this section:
(b) Calculate the total mass of each fluorinated GHG, fluorinated HTF, or nitrous oxide produced over the period “p” by using Equation OO–2 of this section:
(c) Calculate the total mass of each fluorinated GHG, fluorinated HTF, or nitrous oxide transformed by using Equation OO–3 of this section:
(d) Calculate the total mass of each fluorinated GHG or fluorinated HTF destroyed by using Equation OO–4 of this section:
(a) The mass of fluorinated GHGs, fluorinated HTFs, or nitrous oxide coming out of the production process shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. If the measured mass includes more than one fluorinated GHG or fluorinated HTF, the concentrations of each of the fluorinated GHGs or fluorinated HTFs, other than low-concentration constituents, shall be measured as set forth in paragraph (n) of this section. For each fluorinated GHG or fluorinated HTF, the mean of the concentrations of that fluorinated GHG (mass fraction) measured under paragraph (n) of this section shall be multiplied by the mass measurement to obtain the mass of that fluorinated GHG or fluorinated HTF coming out of the production process.
(b) The mass of any used fluorinated GHGs, fluorinated HTFs, or used nitrous oxide added back into the production process upstream of the output measurement in paragraph (a) of this section shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. If the mass in paragraph (a) of this section is measured by weighing containers that include returned heels as well as newly produced fluorinated GHGs or fluorinated HTFs, the returned heels shall be considered used fluorinated GHGs or fluorinated HTFs for purposes of this paragraph (b) of this section and § 98.413(b).
(c) The mass of fluorinated GHGs, fluorinated HTFs, or nitrous oxide fed into the transformation process shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better.
(d) The fraction of the fluorinated GHGs, fluorinated HTFs, or nitrous oxide fed into the transformation process that is actually transformed shall be estimated considering yield calculations or quantities of unreacted fluorinated GHGs, fluorinated HTFs, or nitrous oxide permanently removed from the process and recovered, destroyed, or emitted.
(e) The mass of fluorinated GHGs, fluorinated HTFs, or nitrous oxide sent to another facility for transformation shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better.
(f) The mass of fluorinated GHGs or fluorinated HTFs sent to another facility for destruction shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than the fluorinated GHG or fluorinated HTF, the concentration of the fluorinated GHG or fluorinated HTF shall be estimated considering current or previous representative concentration measurements and other relevant process information. This concentration (mass fraction) shall be multiplied by the mass measurement to obtain the mass of the fluorinated GHG or fluorinated HTF sent to another facility for destruction.
(g) You must estimate the share of the mass of fluorinated GHGs or fluorinated HTFs in paragraph (f) of this section that is comprised of fluorinated GHGs or fluorinated HTFs that are not included in the mass produced in § 98.413(a) because they are removed from the production process as by-products or other wastes.
(h) You must measure the mass of each fluorinated GHG or fluorinated HTF that is fed into the destruction device and that was previously produced as defined at § 98.410(b). Such fluorinated GHGs or fluorinated HTFs include but are not limited to quantities that are shipped to the facility by another facility for destruction and quantities that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore destroyed. You must use flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than the fluorinated GHG or fluorinated HTF being destroyed, you must estimate the concentrations of the fluorinated GHG or fluorinated HTF being destroyed considering current or previous representative concentration measurements and other relevant process information. You must multiply this concentration (mass fraction) by the mass measurement to obtain the mass of the fluorinated GHG or fluorinated HTF fed into the destruction device.
(i) Very small quantities of fluorinated GHGs or fluorinated HTFs that are difficult to measure because they are entrained in other media such as destroyed filters and destroyed sample containers are exempt from paragraphs (f) and (h) of this section.
(l) In their estimates of the mass of fluorinated GHGs or fluorinated HTFs destroyed, facilities that destroy fluorinated GHGs or fluorinated HTFs shall account for any temporary reductions in the destruction efficiency that result from any startups, shutdowns, or malfunctions of the destruction device, including departures from the operating conditions defined in state or local permitting requirements and/or oxidizer manufacturer specifications.
(n) If the mass coming out of the production process includes more than one fluorinated GHG or fluorinated HTF, you shall measure the concentrations of all of the fluorinated GHGs or fluorinated HTFs, other than low-concentration constituents, as follows:
(3)
(4)
(5)
(o) All analytical equipment used to determine the concentration of fluorinated GHGs or fluorinated HTFs, including but not limited to gas chromatographs and associated detectors, IR, FTIR and NMR devices, shall be calibrated at a frequency needed to support the type of analysis specified in the site GHG Monitoring Plan as required under §§ 98.414(n) and 98.3(g)(5) of this part. Quality assurance samples at the concentrations of concern shall be used for the calibration. Such quality assurance samples shall consist of or be prepared from certified standards of the analytes of concern where available; if not available, calibration shall be performed
The revisions and additions read as follows:
(a) Each fluorinated GHG, fluorinated HTF, or nitrous oxide production facility shall report the following information:
(1) Mass in metric tons of each fluorinated GHG, fluorinated HTF, or nitrous oxide produced at that facility by process, except for amounts that are captured solely to be shipped off site for destruction.
(2) Mass in metric tons of each fluorinated GHG, fluorinated HTF, or nitrous oxide transformed at that facility, by process.
(3) Mass in metric tons of each fluorinated GHG or fluorinated HTF that is destroyed at that facility and that was previously produced as defined at § 98.410(b). Quantities to be reported under paragraph (a)(3) of this section include but are not limited to quantities that are shipped to the facility by another facility for destruction and quantities that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore destroyed.
(4) [Reserved]
(5) Total mass in metric tons of each fluorinated GHG, fluorinated HTF, or nitrous oxide sent to another facility for transformation.
(6) Total mass in metric tons of each fluorinated GHG or fluorinated HTF sent to another facility for destruction, except fluorinated GHGs and fluorinated HTFs that are not included in the mass produced in § 98.413(a) because they are removed from the production process as by-products or other wastes. Quantities to be reported under paragraph (a)(6) of this section could include, for example, fluorinated GHGs that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore sent to another facility for destruction.
(7) Total mass in metric tons of each fluorinated GHG or fluorinated HTF that is sent to another facility for destruction and that is not included in the mass produced in § 98.413(a) because it is removed from the production process as a byproduct or other waste.
(8)–(9) [Reserved]
(10) Mass in metric tons of any fluorinated GHG, fluorinated HTF, or nitrous oxide fed into the transformation process, by process.
(11) Mass in metric tons of each fluorinated GHG or fluorinated HTF that is fed into the destruction device and that was previously produced as defined at § 98.410(b). Quantities to be reported under paragraph (a)(11) of this section include but are not limited to quantities that are shipped to the facility by another facility for destruction and quantities that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore destroyed.
(12) Mass in metric tons of each fluorinated GHG, fluorinated HTF, or nitrous oxide that is measured coming out of the production process, by process.
(13) Mass in metric tons of each used fluorinated GHGs, fluorinated HTFs, or nitrous oxide added back into the production process (
(14) Names and addresses of facilities to which any nitrous oxide, fluorinated GHGs, or fluorinated HTFs were sent for transformation, and the quantities (metric tons) of nitrous oxide and of each fluorinated GHG or fluorinated HTF that were sent to each for transformation.
(15) Names and addresses of facilities to which any fluorinated GHGs or fluorinated HTFs were sent for destruction, and the quantities (metric tons) of each fluorinated GHG or fluorinated HTF that were sent to each for destruction.
(16) Where missing data have been estimated pursuant to § 98.415, the reason the data were missing, the length of time the data were missing, the method used to estimate the missing data, and the estimates of those data.
(b) By March 31, 2017 or within 60 days of commencing fluorinated GHG or fluorinated HTF destruction, whichever is later, any facility that destroys fluorinated GHGs or fluorinated HTFs shall submit a one-time report containing the information in paragraphs (b)(1) through (6) of this section for each destruction process. Facilities that previously submitted a one-time report under this paragraph are exempt from this requirement unless they meet the conditions in paragraph (b)(6) of this section.
(3) Methods used to record the mass of fluorinated GHG or fluorinated HTF destroyed.
(6) If any process changes affect unit destruction efficiency or the methods used to record mass of fluorinated GHG or fluorinated HTF destroyed, then a revised report must be submitted to reflect the changes. The revised report must be submitted to EPA within 60 days of the change.
(c) Each bulk importer of fluorinated GHGs, fluorinated HTFs, or nitrous oxide shall submit an annual report that summarizes its imports at the corporate level, except for shipments including less than twenty-five kilograms of fluorinated GHGs, fluorinated HTFs, or nitrous oxide, transshipments, and heels that meet the conditions set forth at § 98.417(e). The report shall contain the following information for each import:
(1) Total mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF imported in bulk, including each fluorinated GHG or fluorinated HTF constituent of the fluorinated GHG or fluorinated HTF product that makes up between 0.5 percent and 100 percent of the product by mass.
(2) Total mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF imported in bulk and sold or transferred to persons other than the importer for use in processes resulting in the transformation or destruction of the chemical.
(3) Date on which the fluorinated GHGs, fluorinated HTFs, or nitrous oxide were imported.
(4) Port of entry through which the fluorinated GHGs, fluorinated HTFs, or nitrous oxide passed.
(5) Country from which the imported fluorinated GHGs, fluorinated HTFs, or nitrous oxide were imported.
(6) Commodity code of the fluorinated GHGs, fluorinated HTFs, or nitrous oxide shipped.
(8) Total mass in metric tons of each fluorinated GHG or fluorinated HTF destroyed by the importer.
(9) If applicable, the names and addresses of the persons and facilities to which the nitrous oxide, fluorinated GHGs, or fluorinated HTFs were sold or transferred for transformation, and the quantities (metric tons) of nitrous oxide and of each fluorinated GHG or fluorinated HTF that were sold or transferred to each facility for transformation.
(10) If applicable, the names and addresses of the persons and facilities to which the fluorinated GHGs or fluorinated HTFs were sold or transferred for destruction, and the quantities (metric tons) of each fluorinated GHG or fluorinated HTF that were sold or transferred to each facility for destruction.
(d) Each bulk exporter of fluorinated GHGs, fluorinated HTFs, or nitrous oxide shall submit an annual report that summarizes its exports at the corporate level, except for shipments including less than twenty-five kilograms of fluorinated GHGs, fluorinated HTFs, or nitrous oxide, transshipments, and heels. The report shall contain the following information for each export:
(1) Total mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF exported in bulk.
(4) Commodity code of the fluorinated GHGs, fluorinated HTFs, or nitrous oxide shipped.
(5) Date on which, and the port from which, the fluorinated GHGs, fluorinated HTFs, or nitrous oxide were exported from the United States or its territories.
(6) Country to which the fluorinated GHGs, fluorinated HTFs, or nitrous oxide were exported.
(i) Each facility that destroys fluorinated GHGs or fluorinated HTFs but does not otherwise report under this section shall report the mass in metric tons of each fluorinated GHG or fluorinated HTF that is destroyed at that facility and that was previously produced as defined at § 98.410(b) or (d), as applicable. Quantities to be reported under this paragraph include but are not limited to quantities that are shipped to the facility by another facility for destruction and quantities that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore destroyed.
(j) By March 31, 2017, all fluorinated HTF production facilities shall submit a one-time report that includes the concentration of each fluorinated HTF or fluorinated GHG constituent in each fluorinated HTF product as measured under § 98.414(n). If the facility commences production of a fluorinated HTF product that was not included in the initial report or performs a repeat measurement under § 98.414(n) that shows that the identities or concentrations of the fluorinated HTF or fluorinated GHG constituents of a fluorinated HTF product have changed, then the new or changed concentrations, as well as the date of the change, must be provided in a revised report. The revised report must be submitted to EPA by the March 31st that immediately follows the new or repeat measurement under § 98.414(n).
(b) Whenever the quality assurance procedures in § 98.424(b) cannot be followed to determine concentration of the CO
(g) Whether the CO
The revisions and additions read as follows:
(c) * * *
(2) You must convert all measured volumes of CO2 to the following standard industry temperature and pressure conditions for use in Equation UU–2 of this subpart: Standard cubic meters at a temperature of 60 degrees Fahrenheit and at an absolute pressure of 1 atmosphere.
Office of Energy Efficiency and Renewable Energy, Department of Energy.
Final rule.
The U.S. Department of Energy (DOE) amends its test procedure for residential furnaces and boilers established under the Energy Policy and Conservation Act. This rulemaking will fulfill DOE's obligation to review its test procedures for covered products at least once every seven years. The revisions include: Clarifying the components included in the burner electrical power input term (PE); adopting a method for determining whether a minimum draft factor can be applied, and how the conditions are to be verified; allowing optional measurement of condensate collection during establishment of steady state; updating references to the applicable installation and operating manual and providing clarifications when the installation and operation (I&O) manual does not specify test setup; clarifying the testing of units intended to be installed without a return duct; adopting a provision clarifying the testing of multi-position units; revising the required reporting precision for annual fuel utilization efficiency (AFUE); and adopting a verification method for determining whether a boiler incorporates an automatic means for adjusting water temperature and whether this design requirement functions as required.
The effective date of this rule is February 16, 2016. The final rule changes will be mandatory for representations made on or after July 13, 2016. The incorporation by reference of certain material listed in this rule is approved by the Director of the Federal Register as of February 16, 2016.
The docket, which includes
A link to the docket Web page can be found at:
For further information on how to review the docket, contact Ms. Brenda Edwards at (202) 586–2945 or by email:
Ms. Ashley Armstrong, U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Building Technologies Office, EE–5B, 1000 Independence Avenue SW., Washington, DC 20585–0121. Telephone: (202) 586–6590. Email:
Mr. Pete Cochran, U.S. Department of Energy, Office of the General Counsel, GC–33, 1000 Independence Avenue SW., Washington, DC 20585–0121. Telephone: (202) 586–9496. Email:
This final rule incorporates by reference into part 430 the following industry standard:
ASTM D2156–09 (Reapproved 2013) (“ASTM D2156R13”),
Copies of ASTM D2156R13 can be obtained from ASTM. American Society of Testing and Materials, ASTM Headquarters, 100 Barr Harbor Drive, P.O. Box C700, West Conshohocken, PA 19428–2959, (877) 909–2786 or (610) 832–9585, or by going to
Title III, Part B
Under EPCA, DOE's energy conservation program generally consists of four parts: (1) Testing; (2) labeling; (3) Federal energy conservation standards; and (4) certification and enforcement procedures. The testing requirements consist of test procedures that manufacturers of covered products must
EPCA sets forth the criteria and procedures that DOE must follow when prescribing or amending test procedures for covered products. EPCA provides, in relevant part, that any test procedures prescribed or amended under this section shall be reasonably designed to produce test results which measure energy efficiency, energy use, or estimated annual operating cost of a covered product during a representative average use cycle or period of use, and shall not be unduly burdensome to conduct. (42 U.S.C. 6293(b)(3))
In addition, if DOE determines that a test procedure amendment is warranted, it must publish proposed test procedures and offer the public an opportunity to present oral and written comments on them. (42 U.S.C. 6293(b)(2)) Finally, in any rulemaking to amend a test procedure, DOE must determine to what extent, if any, the proposed test procedure would alter the product's measured energy efficiency as determined under the existing test procedure. (42 U.S.C. 6293(e)(1))
EISA 2007 amended EPCA to require that, at least once every 7 years, DOE must review test procedures for all covered products and either amend the test procedures (if the Secretary determines that amended test procedures would more accurately or fully comply with the requirements of 42 U.S.C. 6293(b)(3)) or publish a notice in the
DOE's current energy conservation standards for residential furnaces and boilers are expressed as minimum annual fuel utilization efficiency (AFUE). AFUE is an annualized fuel efficiency metric that accounts for fuel consumption in active, standby, and off modes. The following discussion provides a brief history of the rulemakings underlying the existing test procedure for residential furnaces and boilers.
The existing DOE test procedure for determining the AFUE of residential furnaces and boilers is located at 10 CFR part 430, subpart B, appendix N,
On October 20, 2010, DOE amended its test procedure for furnaces and boilers to establish a method for measuring the electrical energy use in standby mode and off mode for gas- fired and oil-fired furnaces and boilers, as required by EISA 2007. 75 FR 64621. These test procedure amendments incorporated by reference, and were based primarily on, provisions of the International Electrotechnical Commission (IEC) Standard 62301 (First Edition),
On January 4, 2013, DOE initiated this rulemaking to examine all aspects of the DOE test procedure by publishing a request for information (RFI) (January 2013 RFI) in the
DOE also proposed to amend the test procedure to: (1) Allow the measurement of condensate during the establishment of steady-state rather than require an additional 30 minutes of testing after steady-state conditions are established; (2) revise annual electricity consumption equations to account for additional electrical components; (3) revise test procedure references to “manufacturer recommendations” or “manufacturer's instructions” that do not explicitly identify the source of the recommendations or instructions; (4) include a test protocol for determining the functionality of the automatic means for adjusting water temperature; (5) include a test method to indicate the absence or presence of air flow to determine whether the minimum default draft factor may be used; (6) revise the required reporting precision for AFUE; (7) specify testing requirements for units that are installed without a return duct; and (8) specify testing requirements for units with multi-position configurations. 80 FR 12876.
The final rule amends the existing DOE test procedure for residential furnaces and boilers to improve the consistency and accuracy of test results generated using the DOE test procedure and to reduce test burden. In particular, these modifications include: (1) Clarifying the definition of the electrical power term PE; (2) adopting a smoke stick test for determining use of minimum default draft factors; (3) allowing for the measurement of condensate under steady-state
DOE has withdrawn or modified all test procedure amendment proposals in the March 2015 NOPR for which stakeholders expressed concern regarding the effect of the proposed amendments on the measured energy efficiency of residential furnaces and boilers when compared to the current test procedure. In particular, as discussed in section III.C, DOE has withdrawn its proposal to incorporate by reference ASHRAE 103–2007.
The following sections discuss the products within the scope of this rulemaking, the test procedure amendments, other test procedure considerations, test burden, measured energy use, and changes to certification and enforcement provisions.
In response to the March 2015 NOPR, the following twelve interested parties submitted written comments: The American Gas Association (AGA); the Air-Conditioning, Heating and Refrigeration Institute (AHRI); Burnham Holdings, Inc. (Burnham); Carrier Corporation (Carrier); John Cockerill (Cockerill); Goodman Global, Inc. (Goodman); Lennox Industries Inc. (Lennox); Lochinvar, LLC (Lochinvar); Rheem Manufacturing Company (Rheem); Ingersoll Rand Residential Solutions (Ingersoll Rand); Laclede Group; and Weil-McLain. Interested parties provided comments on a range of issues, including those DOE identified in the March 2015 NOPR, as well as issues related to the proposed test procedure changes. The issues on which DOE received comments, as well as DOE's responses to those comments and the resulting changes to the test procedure proposals presented in the NOPR, are discussed in the subsequent sections. A parenthetical reference at the end of a comment quotation or paraphrase provides the location of the item in the public record.
The test procedure amendments apply to products that meet the definitions for residential furnaces and boilers (see DOE's regulations at 10 CFR 430.2). A “furnace” is defined as a product that: (1) Utilizes only single-phase electric current, or single-phase electric current or direct current (DC) in conjunction with natural gas, propane, or home heating oil; (2) is designed to be the principal heating source for the living space of a residence; (3) is not contained within the same cabinet with a central air conditioner whose rated cooling capacity is above 65,000 Btu per hour; (4) is an electric central furnace, electric boiler, forced-air central furnace, gravity central furnace, or low pressure steam or hot water boiler; and (5) has a heat input rate of less than 300,000 Btu per hour for electric boilers and low pressure steam or hot water boilers and less than 225,000 Btu per hour for forced-air central furnaces, gravity central furnaces, and electric central furnaces.
The individual products within the scope of this test procedure and the definition of each (see DOE's regulations at 10 CFR 430.2) are listed below:
(1) Electric boiler means an electrically powered furnace designed to supply low pressure steam or hot water for space heating application. A low pressure steam boiler operates at or below 15 pounds per square inch gauge (psig) steam pressure; a hot water boiler operates at or below 160 psig water pressure and 250 °F water temperature.
(2) Electric central furnace means a furnace that is designed to supply heat through a system of ducts with air as the heating medium, in which heat generated by one or more electric resistance heating elements is circulated by means of a fan or blower.
(3) Forced-air central furnace means a furnace that burns gas or oil and is designed to supply heat through a system of ducts with air as the heating medium. The heat generated by combustion of gas or oil is transferred to the air within a casing by conduction through heat exchange surfaces and is circulated through the duct system by means of a fan or blower.
(4) Gravity central furnace means a gas-fueled furnace which depends primarily on natural convection for circulation of heated air and which is designed to be used in conjunction with a system of ducts.
(5) Low pressure steam or hot water boiler is an electric, gas, or oil-burning furnace designed to supply low pressure steam or hot water for space heating applications. A low pressure steam boiler operates at or below 15 psig steam pressure; a hot water boiler operates at or below 160 psig water pressure and 250 °F water temperature.
(6) Mobile home furnace means a direct vent furnace that is designed for use only in mobile homes.
(7) Outdoor furnace or boiler is a furnace or boiler normally intended for installation out-of-doors or in an unheated space (such as an attic or a crawl space).
(8) Weatherized warm air furnace or boiler means a furnace or boiler designed for installation outdoors, approved for resistance to wind, rain, and snow, and supplied with its own venting system.
Stakeholders submitted general comments regarding the test procedure and parallel energy conservation standards rulemaking timeline and the availability of data related to this proceeding. DOE discusses and responds to these comments in the following subsections.
As noted in section I, EISA 2007 requires that DOE must review test procedures for all covered products and amend the test procedures or publish a notice in the
AHRI asserted that the start date for the obligation to review efficiency test procedures at least once every seven years has been reset by the July 2013 Final Rule. And, therefore, by its estimation, DOE has approximately five more years to review and amend, as needed, the test procedures for residential furnaces and boilers. AHRI added that this would be ample time to manage DOE's rulemaking activities such that proposed revisions to efficiency standards and test procedures are not considered concurrently. (AHRI, No. 36 at p. 2)
DOE notes that the July 2013 Final Rule was limited in scope and only intended to remedy a specific concern articulated by stakeholders. Specifically, the July 2013 Final Rule adopted needed equations to allow manufacturers the option to omit the heat up and cool down tests and still generate a valid AFUE measurement for certain condensing products. 78 FR 41265, 41266. DOE considers the seven year look back provision to include a comprehensive review of the entire test procedure. (42 U.S.C. 6293(b)(1)(A)) DOE did not conduct a comprehensive review for the July 2013 Final Rule. Furthermore, DOE stated in the July 2013 Final Rule that it was initiating a separate rulemaking that was broader in scope to examine all aspects of the DOE test procedure for residential furnaces and boilers. 78 FR 41265, 41266. Therefore, DOE maintains that the July 2013 final rule did not meet the requirements outlined in 42 U.S.C. 6293(b)(1)(A). In contrast, DOE has conducted a comprehensive review as part of the current rulemaking, which satisfies the requirements of 42 U.S.C. 6293(b)(1)(A).
Several stakeholders cited legal and practical concerns regarding the timing of proposed revisions to the test procedures and standards for residential furnaces and boilers. Stakeholders requested that DOE delay any further work on the rulemakings to amend efficiency standards for these products until after the finalization of the test procedure. (AHRI, No. 36 at p. 1; Weil-McLain, No. 31 at p. 2; Ingersoll Rand, No. 37 at p. 5)
AHRI stated that it believes the non-final status of the test procedure inhibits stakeholders' fair evaluation of the standard. AHRI stressed the importance of having a known efficiency test procedure. AHRI noted that when a test procedure is in flux, manufacturers must spend resources collecting potentially unusable data which undermines their ability to provide input on the proposed efficiency standards. Similarly, AHRI added that when a test procedure is not finalized, a manufacturer has no way of determining whether the test procedure will affect its ability to comply with a proposed revised standard. AHRI noted that DOE is required to give stakeholders the opportunity to provide meaningful comments and asserted that the joint proposal of test procedures and standards diminishes that opportunity (see 42 U.S.C. 6295(p)(2), 6306(a)). (AHRI, No. 36 at p. 1)
In response to AHRI, DOE does not believe that the timing of the test procedure and standards rulemakings has negatively impacted stakeholders' ability to provide meaningful comment on this test procedure rulemaking. DOE allowed four months for public comment on the test procedure NOPR. Additionally, DOE's original proposal included an update to the latest industry standard (
AHRI and Goodman stated that by publishing the March 2015 NOPR within weeks of the proposed efficiency standard, DOE has failed to abide by the procedures located at 10 CFR part 430, subpart C, appendix A (7)(b). (AHRI, No. 36 at p. 2; Goodman, No. 33 at p. 2) AHRI stated that the Administrative Procedure Act (APA) requires agencies to abide by their policies and procedures, especially where those rules have a substantive effect. AHRI asserted that the non-final test procedure has the substantive effect of increasing costs to stakeholders and diminishing their ability to comment on the efficiency standards. (AHRI, No. 36 at p. 2; Weil-McLain, No. 31 at p. 7)
In response to the comments from AHRI and Goodman asserting that DOE has failed to abide by its procedures at 10 CFR 430, subpart C, appendix A (7)(b), DOE notes that appendix A establishes procedures, interpretations, and policies to guide DOE in the consideration and promulgation of new or revised appliance efficiency standards under EPCA. (See section 1 of 10 CFR part 430, subpart C, appendix A) Those procedures are a general guide to the steps DOE typically follows in promulgating energy conservation standards. The guidance recognizes that DOE can and will, on occasion, deviate from the typical process. Accordingly, DOE has concluded that there is no basis to either: (1) Delay the final rules adopting standards for residential furnaces and boilers; or (2) suspend the test procedure rulemaking until the standards rulemaking has been completed.
Ingersoll Rand and Goodman stated their concern that two-stage, condensing furnaces that would meet the March 12, 2015 furnace proposed rule of 92-percent AFUE under the current test procedure would not meet the 92-percent AFUE standard under the proposed DOE test procedure. Ingersoll Rand noted that the two test procedures were assumed to be identical in the March 12, 2015 residential furnace standard NOPR technical support document. (Ingersoll Rand, No. 37 at p. 2; Goodman, No. 33 at p. 1) Similarly, Weil-McLain suggested that the uncertainty caused by the simultaneous test procedure rulemaking amplifies venting issues present in the residential boiler standards NOPR. (Weil-McLain, No. 31 at p. 3)
In response to Ingersoll Rand and Goodman, as discussed in section III.C, DOE declines to adopt the latest industry standard of ASHRAE 103–2007, which is the only amendment proposed in the March 2015 NOPR that manufacturers claimed could alter the AFUE for two-stage and modulating condensing products. In response to Weil-McLain, DOE notes that none of the proposed test procedure provisions that had the potential to result in a change in measured AFUE are adopted in this test procedure final rule, as discussed in section III.G.
In response the March 2015 NOPR, interested parties submitted comments regarding lack of data availability. For example, the March 2015 NOPR included several references to a testing report. 80 FR 12876, 12878. Burnham stated that in spite of requests from commenters, the testing report was not available in the public docket as of July 8, 2015. Burnham added that the lack of access to the testing report has made it impossible to properly review the impact of ambient conditions on AFUE during the public comment period. Burnham requested that the comment period be extended to allow comment on this document which should be disclosed immediately. (Burnham, No. 35 at p. 7)
DOE made the test results available during the test procedure public meeting.
In the March 2015 NOPR, DOE proposed amendments to reduce variability, eliminate ambiguity, and address discrepancies between the test procedure and actual field conditions, and DOE requested comment on its proposals. 80 FR 12876, 12902. One of these proposals was to update its incorporation by reference of the industry test standard ASHRAE 103–1993 to ASHRAE 103–2007.
DOE received several comments in response to its proposal to update the incorporation by reference in the DOE test procedure to ASHRAE 103–2007. Lochinvar and AGA responded to the NOPR in favor of adopting ASHRAE 103–2007 provided that DOE make adequate allowances for the resulting test burden and the impact that the change would have on existing efficiency claims. (Lochinvar, No. 29 at p. 1; AGA, No. 27 at p. 4) Similarly, Burnham stated that they are not opposed to the update provided test burden is reduced. (Burnham, No. 35 at p. 3)
Ingersoll Rand and Rheem stated their support only for certain provisions of ASHRAE 103–2007. Specifically, Ingersoll Rand supported requiring only reduced fire testing (and not high-fire testing) when the calculated balance point temperature is less than or equal to five degrees. (Ingersoll Rand, No. 37 at p. 4) Rheem stated their support for the elimination of table 8 and the average design heating requirements in ASHRAE 103–1993. (Rheem, No. 30 at p. 2)
Lennox and Weil-McLain suggested DOE not update to ASHRAE 103–2007 at this time. (Lennox, No. 32 at p. 2; Weil-McLain, No. 31 at p. 7) AHRI and Weil-McLain suggested that DOE wait to modify the test procedure until ASHRAE 103–2016 is issued. (AHRI, No. 36 at p. 8; Weil-McLain, No. 31 at p. 7) Carrier suggested that DOE not update to ASHRAE 103–2007, but change the AFUE metric for forced-air furnaces to be based on the steady-state operation, as discussed in section III.E.4. (Carrier, No. 34 at p. 2)
Several commenters suggested that that the updating to ASHRAE 103–2007 would result in more significant changes to AFUE ratings than suggested by DOE in the March 2015 NOPR. (Burnham, No. 35 at p. 3; Lennox, No. 32 at p. 2; AGA, No. 27 at p. 4; AHRI, No. 36 at p. 4; Ingersoll Rand, No. 37 at p. 2) Of these commenters, only AHRI provided test data, which indicated small changes in AFUE as a result of changes to the cyclical condensate test for modulating condensing boilers. (AHRI, No. 36 at p. 17)
Burnham and Ingersoll Rand suggested that the impact to AFUE resulting from the changes in cycle times is still uncertain. Therefore, it is not possible to conclude that the effect of this proposed change to the procedure is insignificant. (Burnham, No. 35 at p. 3; Ingersoll Rand, No. 37 at p. 2) Ingersoll Rand noted that as a result of adopting ASHRAE 103–2007, two-stage and modulating non-condensing furnaces will have a higher AFUE rating, and condensing furnaces will have lower AFUE ratings. Ingersoll Rand noted that the changes in AFUE are higher than the uncertainty of the test procedure reported by DOE and therefore this change to the test procedure cannot be considered
Similarly, Ingersoll Rand suggested the calculation to account for post purge times longer than three minutes not be adopted without test data indicating the adjustment to AFUE that would result from this update. Ingersoll Rand stated that without test data they cannot determine if the new readings would be representative of a unit's performance. (Ingersoll Rand, No. 37 at p. 4)
In response to the March 2015 NOPR, Ingersoll Rand requested that DOE not adopt the proposed changes to the calculation of annual auxiliary electrical energy consumption (E
Several commenters stated that the changes to AFUE caused by updating to ASHRAE 103–2007 would lead to additional testing burden. (Burnham, No. 35 at p. 3; Lennox, No. 32 at p. 2; AHRI, No. 36 at p. 4) AHRI stated that the change to use calculated values for t
Given this expected test burden, Lochinvar argued that if DOE is to adopt ASHRAE 103–2007, DOE must declare in writing that products certified according to ASHRAE 103–1993 that were on the market prior to updating the test procedure are not required to be retested and recertified unless the design is changed in a way that affects efficiency. Lochinvar suggested that future audit tests of pre-existing products could still be conducted according to ASHRAE 103–2007 but that manufacturers should not be required to do new tests on existing models for certification reporting to DOE's Compliance Certification Management System (CCMS). (Lochinvar, No. 29 at p. 1)
Burnham also commented that their efforts to explore the impact of adoption of ASHRAE 103–2007 have been hampered by the lack of generally available, National Institute of Standards and Technology (NIST) validated software tools for calculating AFUE (and intermediate values) based on ASHRAE 103–2007. Burnham argued that the lack of software is a significant departure from past practice during comparable rulemakings. Burnham also asserted that this constituted a lack of transparency that would violate basic administrative law precepts and would be arbitrary and capricious. (Burnham, No. 35 at p. 3)
After considering these comments, DOE agrees that further evaluation is
DOE does not agree with Burnham's assertion that the lack of an automated software program implementing the equations presented in DOE's proposal hampered stakeholder's ability to comment on the practicability and the impact of the adoption of ASHRAE 103–2007. DOE does not endorse specific calculations tools commonly developed by industry or third-party test laboratories that automate the equations provided in DOE's regulations. Furthermore, DOE does not need to provide software for interested parties to be able to perform the calculations in proposed test procedure amendments and believes the simplified equations provided in the proposed rule can be easily implemented through a desktop-software calculation tool such as a commonly available spreadsheet application. Lastly, DOE disagrees with Burnham's assertion that the proposed rule was not sufficiently clear to provide an opportunity for interested parties to understand the proposal and provide meaningful comment because each of the equations utilized was presented in the regulatory text within the proposed rule in a step-by-step fashion.
In response to the March 2015 NOPR, DOE received input on a variety of test procedure issues beyond incorporation of ASHRAE 103–2007, including: (1) Electrical power of additional components; (2) smoke stick test for determining use of minimum default draft factors; (3) measurement of condensate under steady-state conditions; (4) I&O manual reference and proposed clarifications when the I&O manual does not specify test setup; (5) specifying ductwork requirements for units that are installed without a return duct; (6) specifying testing requirements for units with multi-position configurations; (7) AFUE reporting precision; (8) room ambient temperature and humidity ranges; (9) full-fuel-cycle (FFC) energy metrics in the AFUE test; (10) oversize factor values; (11) alternative methods for furnace and boiler efficiency determination; and (12) test method for combination appliances. DOE amends the test procedure for residential furnaces and boilers regarding issues (1)–(7), which are addressed in further detail below. Issues (8)–(12), for which DOE does not amend the test procedure in this final rule, are discussed in section III.E. DOE also received comments on the verification test for automatic means for adjusting water temperature, which are discussed in section III.H.1.
In the January 2013 RFI and March 2015 NOPR, DOE noted that the specific method of electrical measurement prescribed in the existing DOE test procedure does not explicitly capture the electrical power associated with all auxiliary components. The method identifies PE as the electrical power used to operate the burner but only explicitly mentions measurements of the power supplied to the power burner motor, the ignition device, and the circulation water pump, but does not explicitly identify other devices that use power during the active mode, such as the gas valve, safety and operating controls, and a secondary pump for boilers (
AHRI expressed the view that the proposed changes over-complicate this issue and that the proposed measurements will change the measurement of E
Burnham supported DOE's proposal to measure all electrical consumption associated with operating the burner (PE), which should include the power consumption of any additional pump which is needed to provide adequate flow through the boiler itself without also providing significant flow through the heating system. (Burnham, No. 35 at p. 4)
Lochinvar stated that, in its experience, all electrical power consumption measurements made during an AFUE test are made at the power supply connection to the boiler and account for all auxiliary components. (Lochinvar, No. 29 at p. 2) Lochinvar stated that while the proposed change in the measurement of electrical consumption seems unnecessary, it does not object to the revision.
After reviewing the comments on the March 2015 NOPR, DOE agrees with the alternative approach suggested by AHRI to make explicit that all of the electrical energy provided to the burner is captured in the E
The revised section 2 of appendix N defines the individual components that are measured as part of PE:
• Control means a device used to regulate the operation of a piece of equipment and the supply of fuel, electricity, air, or water.
• Draft inducer means a fan incorporated in the furnace or boiler that either draws or forces air into the combustion chamber.
• Gas valve means an automatic or semi-automatic device consisting essentially of a valve and operator that controls the gas supply to the burner(s) during normal operation of an appliance. The operator may be actuated by application of gas pressure on a flexible diaphragm, by electrical means, by mechanical means or by other means.
• Oil control valve means an automatically or manually operated device consisting of an oil valve for controlling the fuel supply to a burner to regulate burner input.
• Boiler pump means a pump installed on a boiler that maintains adequate water flow through the boiler heat exchanger and that is separate from the circulating water pump.
Although these definitions were not explicitly proposed in the NOPR, they provide additional clarity about the definition of PE, consistent with the proposal in the NOPR to improve the regulatory text to reflect that PE includes the electrical power of all auxiliary components.
Carrier noted that DOE in the past had held to the policy of not making changes that will negatively impact present ratings. The electrically-efficient furnaces ratio, known as “e”, will increase with the additional requirement, making some products lose their ENERGY STAR® qualification. Carrier stated that including additional electrical components along with the blower electrical consumption is equivalent to changing the ENERGY STAR qualifying standard without justifying the value. (Carrier, No. 34 at p. 4)
In response to Carrier's concerns, DOE notes that the definition of PE has always been the electrical energy input to the burner and that the amendments adopted in this rule merely make explicit additional components that are commonly incorporated into burners. Further, as noted in many other stakeholder comments, most manufacturers already measure the electrical power of all the auxiliary components that are listed in the revised definition of PE. Therefore, clarifying the additional components in the definition of PE will not affect ENERGY STAR ratings for most furnaces. Furthermore, the clarification of the definition of PE ensures more accurate and consistent reporting of energy consumption in the residential furnaces and boilers market.
Weil-McLain stated that the new electrical testing requirements would not allow the manufacturer to interpolate results from tests because the electrical load will not scale in the same manner as other aspects of a boiler. This means hundreds of new tests will need to be run, imposing substantial cost and burden. (Weil-McLain, No. 31 at p. 6)
In response to Weil-McLain's comment, DOE notes that only cast iron sectional boilers may be certified based on linear interpolation, as specified in 10 CFR 429.18(b)(3). As stated previously, the amendment of the definition of PE will not impose additional burden because it does not change the definition but merely clarifies the components included in measurement of PE. In addition, DOE's understanding is that cast iron sectional boilers are typically non-condensing models that do not have boiler pumps.
Burnham recommended that DOE provide regulatory provisions to ensure that electrical consumption is measured with the controls normally shipped with the boiler. Such provisions are required because in many cases it is impossible to perform the AFUE test using controls having an automatic means of adjusting water temperature, making replacement of the standard controls during the AFUE test mandatory. (Burnham, No. 35 at p. 4) DOE notes that the electrical power measurement during the steady-state test does not account for electrical power outside of normal steady-state operation. Therefore, any controls operation outside of the steady-state test, such as automatic means for adjusting water temperature, are not included in the electrical power measurement.
In the March 2015 NOPR, DOE proposed to leave the default draft factor values for furnaces and boilers unchanged from the existing text procedure. 80 FR 12876, 12885. DOE did not receive any comments on this issue, and does not amend the default draft factor values for this final rule.
In addition, to determine if a unit has no measureable airflow through the heat exchanger such that manufacturers may use the minimum default draft factors, DOE proposed in the March 2015 NOPR to incorporate a test based on the use of a smoke stick to establish the absence of flow through the heat exchanger. DOE requested input on whether, in addition to the proposed smoke stick test, other options exist for indicating the absence of flow through the heat exchanger. 80 FR 12876, 12902.
Lochinvar stated that it appreciates and supports the DOE's affirmation of the use of smoke for visual determination of no-flow conditions in the vent. (Lochinvar, No. 29 at p. 4) Similarly, Rheem stated that although the proposed procedure is not quantitative, it is more definitive than “absolutely no chance of airflow through the combustion chamber and heat exchanger when the burner is off.” (Rheem, No. 30 at p. 3)
Ingersoll Rand and Carrier stated that the proposed procedure requires a detailed definition of the “smoke stick device” and test method to be created and made available. (Ingersoll Rand, No. 37 at p. 5; Carrier, No. 34 at p. 5) Ingersoll Rand stated that the test method and materials to be used need to be explicitly documented to ensure that all test labs generate repeatable and reproducible test results. (Ingersoll Rand, No. 37 at p. 5) Carrier also requested additional information as to where smoke sticks can be obtained commercially. (Carrier, No. 34 at p. 5)
DOE agrees with Rheem that the test procedure is not quantitative; however, the purpose of the test is to provide a visual assessment of no airflow, not a quantitative measure of airflow. Regarding the Ingersoll Rand and Carrier request to provide a detailed definition of the smoke stick device, DOE notes that smoke sticks are commercially available and routinely used for visualization purposes, and DOE does not endorse a specific type of smoke stick device. In addition, DOE believes that the exact amount of smoke produced by the smoke stick is not essential to the reproducibility of the results.
Ingersoll Rand expressed concern about air flow in the lab and if manufacturers can fix their venting such that air does not flow through it. (Ingersoll Rand, Public Meeting Transcript, No. 23 at p. 117) Similarly, Carrier requested DOE to add clarification to the procedure to ensure that the smoke stick is not affected by
In response to Ingersoll Rand, DOE already specified that all air currents and drafts be minimized for the smoke stick test in the March 2015 NOPR. For this final rule, DOE explicitly states that ventilation should be turned off if the test area is mechanically ventilated, and to minimize air currents if there is no mechanical ventilation. To address Carrier's safety concerns, DOE clarifies that the smoke produced by the smoke stick must be non-toxic to the test personnel. DOE is confident that the smoke stick test as proposed in the NOPR and modified based on the clarifications recommended by stakeholders will ensure repeatable and reproducible test results. Therefore, DOE adopts the modified optional smoke stick test to determine the absence of flow through the heat exchanger.
In the March 2015 NOPR, DOE also proposed to include revisions to the requirements of sections 8.8.3 and 9.10 of ASHRAE 103–2007 to accommodate the use of the smoke stick test, and, to reduce redundancy, to eliminate use of the term “absolutely” from “absolutely no chance of airflow” in sections 8.8.3 and 9.7.4 of ASHRAE 103–2007. 80 FR 12876, 12902. DOE received no comment on these proposals. Even though DOE has decided not to adopt ASHRAE 103–2007 and instead retain reference to ASHRAE 103–1993, the relevant sections do not differ between the two versions. Therefore, DOE is adding sections 7.10 and 8.10 to appendix N and revising sections 10.2 and 10.3 of appendix N to accommodate the use of the smoke stick test and is eliminating the use of the term “absolutely” from “absolutely no chance of airflow” in sections 8.8.3 and 9.7.4 of ASHRAE 103–1993 (included as sections 7.10 and 8.9 of appendix N) for determining the use of the minimum default draft factors.
In the March 2015 NOPR, DOE proposed to allow for the condensate mass to be measured during the establishment of steady-state conditions, rather than after steady-state has been achieved. 80 FR 12876, 12881. Section 9.2 of ASHRAE 103–1993 requires that the measurement of condensate shall be conducted during the 30-minute period after steady-state conditions have been established. For the March 2015 NOPR, DOE investigated the difference in condensate mass collected and the rate of condensate production during the two separate periods (
In response to the March 2015 NOPR, Lennox, Lochinvar and AHRI stated their support for the allowance to measure condensate during the establishment of steady‐state conditions. (Lochinvar, No. 29 at p. 2; Lennox, No. 32 at p. 3; AHRI, No. 36 at p.5; Ingersoll Rand, No. 37 at p. 5) However, Lennox, AHRI and Ingersoll Rand each noted that to avoid an unintended consequence of causing manufacturers to retest existing models, this change should be clearly identified as an option to the current procedure. (Lennox, No. 32 at p. 3 Lennox, No. 32 at p. 3; AHRI, No. 36 at p.5; Ingersoll Rand, No. 37 at p. 5) Carrier also agreed that the condensate collection can be done during the steady state period, so long as clarification is added to prevent testing with dry heat exchangers. (Carrier, No. 34 at p. 4)
On the other hand, Rheem did not support allowing the measurement of condensate during the establishment of steady state conditions. (Rheem, No. 30 at p.1) Rheem argued that condensate measurements have a significant impact on the final calculated AFUE value and that additional variation in the condensate measurement procedure will add variation to the test procedure. Rheem believes that the time spent to establish steady-state conditions is worthwhile and should not be eliminated. (Rheem, No. 30 at p.1)
DOE understands commenters' concerns regarding the test burden associated with the need to retest existing models to the new test procedure. Therefore, DOE has made the ability to measure condensate during the establishment of steady-state conditions an option, not a requirement. This change is incorporated in section 8.4 of appendix N.
In response to Rheem, DOE notes that test data indicate a similar rate of condensate mass production in both the establishment of steady-state, and measurement of condensate test intervals. Therefore, DOE does not expect any impact on AFUE to result from the allowance of this optional procedure.
The existing DOE test procedure language, which refers in some locations to “manufacturer recommendations” or “manufacturer instructions”, can lead to the use of ad hoc instructions derived solely for testing purposes. To clarify the test procedure language, DOE proposed in the March 2015 NOPR that testing recommendations should be drawn from each product's I&O manual. DOE also provided alternate instructions if the I&O manual did not contain the necessary testing recommendations. 80 FR 12876, 12883. Lastly, in the March 2015 NOPR, DOE proposed to require manufacturers to request a test procedure waiver from DOE when the DOE test procedure provisions and I&O manuals are not sufficient for testing a furnace or boiler.
DOE did not receive any comments objecting to reference the manufacturer's I&O manuals instead of “manufacturer's instructions” or “manufacturer's recommendations.” Therefore, DOE replaces all references to “manufacturer's instructions” or “manufacturer's recommendations” in ASHRAE 103–1993 with “I&O manual” in appendix N.
In the NOPR, DOE proposed specific instructions for adjusting combustion airflow to achieve an excess air ratio, flue O
Lennox, AHRI, and Burnham noted that the proposed adjustment of the CO
Carrier, Ingersoll Rand, and Rheem stated that most modern furnaces do not have the capability to make combustion air adjustments because the practice of including primary air shutters is no longer widely used on modern gas furnaces with fan-assisted or power burners. (Carrier, No. 34 at pp. 3–4; Ingersoll Rand, No. 37 at p. 6; Rheem No. 30 at p. 3) AHRI and Burnham also stated that for many gas furnaces and boilers that use atmospheric burners or other equipment with no means of adjusting CO
Burnham stated that some type of tolerance is needed for adjusting CO
After reviewing stakeholders' comments on the specific instructions for adjusting combustion airflow, DOE concurs that further study is needed to determine the impact on AFUE of the CO
In response to DOE's proposal that manufacturers request a test procedure waiver from DOE when the DOE test procedure provisions and I&O manuals are not sufficient for testing a furnace or boiler, Burnham stated that the proposed waiver process is unduly burdensome, given the use of increasingly complex control and burner systems. To reduce the frequency with which waivers are required, Burnham suggested that DOE adopt a repository for “special test instructions” similar to that which DOE currently has in place for commercial boilers. (Burnham, No. 35 at p. 5) Lennox and AHRI similarly stated that if DOE is concerned about the situation where the manufacturer does not provide any recommended settings in the I&O manual, DOE should allow manufacturer to provide information on unit setup for testing as part of the certification report as is done for commercial and industrial equipment. (Lennox, No. 32 at p. 3; AHRI, No. 36 at pp. 4, 6)
In response to stakeholders' comments, DOE notes that manufacturers have control over what information is specified in the I&O manual. Furthermore, the test procedure provides defaults for most requirements that are based on the I&O manual. As such, DOE believes the instructions given in the test procedure and I&O manuals should be sufficient for testing in most cases. Therefore, DOE is not amending its certification provisions to permit manufacturers to report test-specific instructions as supplemental information in cases where the I&O manual does not provide instructions, and is implementing the requirement to request a waiver in section 6.1.a of appendix N. DOE also notes that the waiver procedure provides a feedback loop by which DOE learns of issues manufacturers are encountering with the test procedure and yields amendments to the test procedure through rulemaking to address those issues.
In the March 2015 NOPR, DOE proposed to add a provision in the test procedure clarifying that the return (inlet) duct is not required during testing for units that, according to the I&O manual, are intended to be installed without a return duct. 80 FR 12876, 12902–12903.
In response, Rheem, Carrier, and Ingersoll Rand agreed that a unit that is intended to be installed without a return duct should be tested without a return duct. (Rheem, No. 30 at p. 3; Carrier, No. 34 at p. 6; Ingersoll Rand, No. 37 at p. 5) In addition, Carrier recommended that DOE adopt figure 2 in exhibit 1 of Carrier's comment, which clarifies the use of a return duct for gas furnaces. (Carrier, No. 34 at p. 6)
DOE agrees with stakeholders and adopts the amendment clarifying that units intended to be installed without a return duct are not required to use the return (inlet) duct during testing. After reviewing the figure provided by Carrier, DOE believes that the language is sufficient and an additional figure is unnecessary.
In the March 2015 NOPR, DOE proposed to require that multi-position furnaces be tested using the least-efficient position.
In response, AHRI stated that they believe that manufacturers already test in the least-efficient configuration. (AHRI, Public Meeting Transcript, No. 23 at p. 123)
Carrier stated that in the past, it has tested and displayed the AFUE by orientation of installation; however, it no longer does so because the multiple ratings by position did not give customers any benefit. Because the setup requirements of the DOE test procedure already cause furnaces to operate at the lowest efficiency, thus making AFUE ratings conservative for the average installation, Carrier recommended that DOE drop the requirement to test in all positions and simplify the testing to be in the most commonly installed position of the furnace. If DOE were to require testing in all positions, Carrier proposed an alternative to allow single rating that is weighted based on percent of applications by configuration and installation location to reduce sample testing burden and not confuse consumers with excess information. (Carrier, No. 34 at pp. 6–8)
Lennox disagreed with the testing requirements in multiple configurations because of the increased test burden and lack of improved test accuracy. (Lennox, No. 32 at pp. 3–4)
In response to Carrier's and Lennox's concerns about increased test burden if required to test in all configurations, DOE clarifies that in the March 2015 NOPR, DOE did not propose to require manufacturers to test in all positions, but rather to require testing only in the least efficient configuration while explicitly allowing manufacturers to test in multiple configurations if they wish. DOE notes that, as stated by AHRI, it is already common industry practice to test in the least efficient configuration; accordingly, DOE anticipates that there will be no additional test burden from the clarification to require testing in the least efficient configuration. Regarding Carrier's suggestion to test in the dominant installed position, DOE believes that testing in the least efficient position will provide ratings that are more comparable between different models because the dominant position may not be the least efficient configuration and may vary among models and among manufacturers. DOE believes that Carrier's suggestion of a weighted rating is not practicable because DOE is not requiring manufacturers to test in all configurations, only the least efficient one. Therefore, in section 6.1.b of appendix N and in 10 CFR 429.18, DOE amends its regulations to require testing and rating only in the least efficient configuration, while still allowing manufacturers the ability to test and rate in multiple configurations. In addition, DOE includes a definition for multi-position furnace in section 2 of appendix N.
In the March 2015 NOPR, DOE also proposed to allow testing of units configured for multiple position installations to use the blower access door as an option instead of one of the inlet openings. 80 FR 12876, 12886 (March 11, 2015). In response, Rheem stated that a furnace should not be tested in a configuration that is prohibited by the installation manual. For example, Rheem stated that its furnace installation manuals allow only bottom and side returns. A rear return and a return in place of the blower access door are not allowed. (Rheem, No. 30 at p. 4) Ingersoll Rand stated that testing of multi-position units using the blower access door may not be feasible option for some furnaces, and the manufacturer should state whether this is an acceptable test method for the furnace model. (Ingersoll Rand, No. 37 at p. 6)
DOE agrees with Rheem and Ingersoll Rand that units should not be required to be tested using the blower access door if not allowed in the I&O manual or if not feasible. In an effort to ensure consistent and appropriate testing, DOE withdraws its proposal that would have explicitly allowed the use of the blower access door for testing of multi-position furnaces and boilers that are not shipped with an open inlet.
DOE's existing furnaces and boilers test procedure specifies that the AFUE rating be rounded to the nearest whole percentage point. 10 CFR 430.23(n)(2). In the March 2015 NOPR, DOE sought comment on its proposal to report AFUE to the nearest tenth of a percentage point. 80 FR 12876, 12902.
AHRI, Lochinvar, Lennox, and Burnham support reporting of AFUE to the nearest tenth of a percentage point and noted that it reflects the current practice. (AHRI, No. 36 at p. 6; Lochinvar, No. 29 at p. 4; Lennox, No. 32 at p. 3; Burnham, No. 35 at p. 6) However, Burnham does not agree with the proposal to round to the nearest 0.1 percent, stating that it would be a direct violation of 10 CFR 429.18(a)(2)(i)(B) requiring any representative value of AFUE for which consumers would favor higher values to be less than or equal to the lower of the mean of the sample or the lower 97.5 percent confidence limit (LCL) of the true mean divided by 0.95. Burnham stated that rounding up would allow the representative value to potentially be higher than allowed by calculation mentioned. Burnham urged DOE to prescribe the current industry practice of truncating to 0.1 percent. (Burnham, No. 35 at pp. 6–7)
In contrast, Rheem stated that rating furnaces to the nearest tenth of a percentage point will give consumers the impression that one furnace is more efficient than another, while in actuality, the test procedure tolerances do not result in the proposed level of precision that should be required to support reporting AFUE to the nearest tenth of a percentage point. (Rheem, No. 30 at p. 3)
Ingersoll Rand stated that while DOE's CCMS can accommodate reporting AFUE to this level, any manufacturer that reports AFUE to the whole percentage point will have to submit new certification reports and
AHRI stated that it reports to the nearest tenth to DOE for furnaces but not for boilers due to Environmental Protection Agency (EPA) and ENERGY STAR requirements. (AHRI, Public Meeting Transcript, No. 19 at p. 89) Burnham urged DOE to work with the EPA to simultaneously update the ENERGY STAR requirement of rounding to the nearest whole percentage point to avoid conflicting values on the DOE and ENERGY STAR Web sites. (Burnham, No. 35 at p. 7)
DOE understands that reporting AFUE values to the nearest tenth of a percentage point is currently industry practice. Based on 10 CFR 429.18(a)(2)(i)(B), DOE agrees with Burnham that AFUE should be truncated to the tenth of a percentage point. In response to Rheem's comment about the test procedure tolerances, DOE notes that in response to the January 2013 RFI, Rheem stated that this level of precision has been demonstrated to be statistically possible. (Rheem, No. 12 at p. 9). DOE also observes that Rheem, as well as many other manufacturers, reports AFUE to the tenth of a percentage point in DOE's Compliance Certification Database and the AHRI directory for some models. In response to Ingersoll Rand's comments, DOE notes that AHRI's certification directories for both furnaces and boilers as well as DOE's Compliance Certification Database already allow manufacturers to report AFUE to the nearest tenth of a percentage point. Therefore, DOE anticipates this clarification will not require changing the reported efficiency in manufacturer literature, nor will it cause significant manufacturer burden. Furthermore, in response to AHRI and Burnham, DOE notes that EPA must use the method of test, sampling plan, and representation requirements adopted by DOE. DOE will work with EPA to make sure the language in its specification is harmonized with federal regulations. Accordingly, DOE updates the existing requirement for residential furnaces and boilers in 10 CFR 430.23(n)(2) to truncate AFUE to the tenth of a percentage point. DOE also clarifies in 10 CFR 429.18 that the represented value of AFUE based on the tested sample must be truncated to the tenth of a percentage point.
In this final rule, DOE revises the term “seasonal off switch” to “off switch” and revises the definitions of “off mode” and “standby mode” in section 2 of appendix N to reflect the updated definitions found in the second edition of IEC 62301, which was incorporated by reference in the December 2012 final rule. DOE also revises sections 8.1, 8.2, and 8.4 of the existing appendix N (sections 8.3, 8.5, and 8.7 of the amended appendix N) to clarify and improve the test instructions. DOE also revises sections 10.4, 10.5, 10.6, 10.7.3, 10.9, 10.9.1, and 10.11 of appendix N to improve grammar and consistency in formatting throughout the test procedure, and to include missing variable definitions. In addition, DOE incorporates the previously excluded section 9.7.l of ASHRAE 103–1993 to include instructions on the setup of the tracer gas test. DOE updates the definition of “isolated combustion system” in section 2.5 of the existing appendix N (2.8 of the amended appendix N) to reflect the updated definition in ASHRAE 103–2007. Finally, DOE modifies section 8.3 of the existing appendix N (8.6 of the amended appendix N) to clarify that the referenced time delay is the blower delay t
In the March 2015 NOPR, DOE proposed not to change the test procedure regarding room ambient temperature and humidity conditions, neither by mathematical correction nor by limiting the existing ambient condition range, and requested input on this approach. 80 FR 12876, 12889.
Lochinvar and Lennox stated their support for DOE's proposal not to further restrict the ambient conditions due to the additional test burden it would cause. (Lochinvar, No. 29 at p. 4; Lennox, No. 32 at p. 4) Rheem stated that they believe that the ambient conditions range requires further study. Rheem noted that the room ambient air temperature and humidity ranges were developed based on 30-year-old laboratory conditions and that laboratory conditions may be more carefully controlled today compared to the long past. (Rheem, No. 30 at p.1) AHRI noted that the new edition of ASHRAE–103–2016 will be issued for public review and one of the proposed amendments is to include changes to the definition of room ambient air operating conditions. (AHRI, No. 36 at p. 5)
Burnham stated that they disagree with DOE's assertion in the March 2015 NOPR that relative humidity (RH) has a minimal impact on the AFUE of condensing boilers and stated that the issue should be revisited. Burnham provided test data of a condensing boiler which shows a swing in AFUE of approximately 1.3 percent when the RH was changed from approximately 30 percent to 70 percent. Burnham stated that they expect the variation in AFUE as a function of RH to be at least as large for boilers as it is for furnaces. Burnham noted that the flue temperature of boilers is closely linked to the return water temperature during the test (120 °F), which is close to the typical dew point of natural gas flue products. Changes in RH may therefore have a large impact on where the temperature of the flue products falls below the dew point as they pass through the heat exchanger. Burnham stated that if ambient conditions have a significant impact on AFUE, DOE should tighten the tolerance for RH to conditions likely to be seen in the field, even if this results in an increased burden for manufacturers in the form of requiring conditioned lab facilities. (Burnham, No. 35 at p. 7)
DOE agrees with Rheem and Burnham that the impact of ambient conditions on AFUE warrants further study. However, at this time DOE does not have adequate data to justify the testing burden associated with the narrowing of ambient conditions. Therefore, DOE maintains the ambient conditions specified in the current test procedure.
In the March 2015 NOPR, DOE stated that the test procedure rulemaking was not the appropriate vehicle for deriving an FFC energy descriptor for furnaces (and other products). Specifically, DOE noted that if a secondary FFC energy descriptor were included as part of the furnace and boiler test procedure, DOE would need to update the test procedure annually. DOE indicated its intent to estimate FFC energy savings in future energy conservation standards rulemakings for furnaces, and to take those savings into account in proposing and selecting amended standards. 80 FR 12876, 12896.
In response to the NOPR, AGA expressed their disagreement with
DOE maintains its position outlined in the NOPR that it does not believe that a mathematical adjustment to the test procedure to account for FFC is appropriate. As noted in the March 2015 NOPR, the mathematical adjustment to the site-based energy descriptor relies on information that is updated annually. If DOE were to include such an adjustment to the test procedure, DOE would be required to update the test procedure annually.
In the March 2015 NOPR, DOE proposed to maintain the existing oversize factor of 0.7 and sought comment on the appropriateness of this strategy.
Rheem stated that replacement furnaces are more likely to be oversized than a new construction furnace because the unit may not be resized when it is replaced with a more efficient unit. Rheem also noted that it is more likely for a furnace to be oversized in a climate with high variation in outdoor temperature, or if it is installed in an area with high airflow requirements for the cooling load. (Rheem, No. 30 at p. 4)
DOE agrees with Rheem that a variety of factors, including construction type and climate, may influence the magnitude of oversizing that occurs in a given installation. DOE did not receive any data supporting a change to the existing oversize factor of 0.7. DOE has determined the existing value of 0.7 continues to be representative of the oversized factor applicable to the average U.S. household and therefore maintains that value.
In response to the March 2015 NOPR, Carrier questioned the need for a test method as precise as ASHRAE 103 due to the advances that have been made in reducing cyclical losses. Carrier noted that the difference between steady state efficiency and cyclical AFUE is less than 1 percent across all model types. Carrier suggested that DOE change the AFUE metric for forced-air furnaces to be based on the steady-state operation. (Carrier, No. 34 at p. 2) Carrier stated that this would simplify the test procedure and relieve significant burden from manufacturers. Carrier stated that the lab setup of gas furnaces during AFUE testing—including vent length, isolated combustion system (ICS) installation, off cycle times, and blower off delay time—rarely replicates the actual installation of condensing gas furnaces. (Carrier, No. 34 at p. 2)
DOE agrees that there have been significant advances in the minimization of cyclical losses since the inception of the AFUE metric. However, including cyclical losses, which are captured in the AFUE metric, still provides market differentiation for models that would yield the same steady-state values. Furthermore, DOE believes that the inclusion of cyclical losses in the AFUE metric has contributed to the increases in efficiency noted by Carrier. For these reasons, DOE declines to limit the calculation of AFUE to steady-state operation. DOE would be willing to work with industry to investigate this further to see if moving to a steady-state methodology has merit and meets the requirements of the statute.
In the March 2015 NOPR, DOE discussed the possibility of creating a test procedure for determining the efficiency of combination products. Ultimately DOE did not propose to amend the test procedure to include a method of test for combination appliances choosing not to complicate the test procedure rulemaking. 80 FR 12876, 12894.
In response to the NOPR, Ingersoll Rand believes that EPCA anticipated products being capable of serving more than one function and expects DOE to set separate energy efficiency metrics for each major function. Ingersoll Rand noted that EPCA authorizes DOE to “set more than 1 energy conservation standard for each major function.” (42 U.S.C. 6295(o)(5)) Ingersoll Rand suggested that establishing a combination metric and setting a standard for a combination unit is contrary to EPCA. (Ingersoll Rand, No. 37 at p. 6)
DOE did not propose a combination metric in the NOPR, and does not amend the test procedure to include such a metric in this final rule.
EPCA requires that the test procedures DOE prescribes or amends be reasonably designed to produce test results that measure the energy efficiency, energy use, water use (in the case of showerheads, faucets, water closets, and urinals) or estimated annual operating cost of a covered product during a representative average use cycle or period of use. These procedures must also not be unduly burdensome to conduct. (42 U.S.C. 6293(b)(3))
In response to the March 2015 NOPR, Ingersoll Rand stated that the testing and reporting burden from the proposals would be far greater than the average 20 hours per response that DOE estimates. (Ingersoll Rand, No. 37 at p. 9) Weil-McLain expressed concerns that the cost of the proposed test is grossly underestimated and that cost analysis for all of the testing is fundamentally flawed and incomplete. Weil-McLain stated that a more appropriate estimate for the cost to re-test all models in DOE's example of average small boiler business with 70 basic models would be more than twenty times the estimate shown for various reasons, such as the cost of set up for each test, test re-runs if parameters are not met, test recording, and analysis time. In addition, Weil-McLain stated that: (1) Only the incremental cost related to the changes in procedure have been captured when in all likelihood all products will have to be retested through the entire test procedure; (2) at least two tests per model are required for data submittal; (3) initial certification and annual audits require an additional witness test by a third-party lab; (4) engineering, facility, or other charges were not captured; (5) third-party test agency fees were not considered; and (6) the time required to test the number of models for the manufacturer and third-party test agency capacity were not considered. Weil-McLain also stated that retesting and re-rating would take substantially longer than 180 days. (Weil-McLain, No. 31 at pp. 6–7) Ingersoll Rand stated that to retest all of its current models will require more than six months of lab time with a cost of over $400,000. (Ingersoll Rand, No. 37 at p. 9)
Weil-McLain questioned why DOE would impose the burden of conducting all of the new tests on manufacturers
Several stakeholders requested more time to conduct re-testing after the issuance of the final rule. Weil-McLain stated that the process of conducting all the tests, analyzing information, and conducting re-certification through the certified labs for hundreds of models cannot be completed within 180 days of when the final rule is issued. (Weil-McLain, No. 31 at p. 7) Similarly, Burnham expressed concern that it has found it impossible to thoroughly evaluate the impact of this NOPR, as it asserted that DOE provided only a short amount of time and inadequate information and resources during the rulemaking process. (Burnham, No. 35 at p. 8) Goodman stated that the industry needs at least 6 months to assess the impact of the new test procedure on existing basic models. (Goodman, No. 33 at p. 2)
Ingersoll Rand argued that the fact that many of the current models may be removed from the market as a result of the separate energy conservation standards rulemakings, Fan Energy Rating (FER) standard effective in 2019 and AFUE proposed standard effective in 2021, makes this retesting effort even more burdensome, unnecessary and wasteful. (Ingersoll Rand, No. 37 at p. 9) Carrier also stated that recent rulemakings, such as the standby power ruling and the recent legislation for furnace fans, have increased the test burden for gas furnace compliance compared to when the complicated AFUE procedure was formulated and first implemented. (Carrier, No. 34 at p. 3)
The many comments from manufacturers regarding re-testing of all models currently in distribution were responding to DOE's proposals to incorporate by reference ASHRAE 103–2007 and adjust the CO
DOE believes that the clarification of the electrical power term PE will not add any additional burden on manufacturers, since this is what has been required under the existing test procedure. In terms of the boiler pump, DOE included a default value in case manufacturers are not currently capturing this component, which will minimize test burden.
Many manufacturers currently perform the tracer gas test to determine whether the minimum default draft factor of 0.05 may be used. DOE expects that, when establishing the absence of flow through the heat exchanger, the use of the smoke stick test will reduce the test burden to manufacturers by eliminating, in some cases, the need for the tracer gas test.
The optional provision allowing for the measurement of condensate during the establishment of steady-state conditions will provide manufacturers of condensing furnaces and boilers time and labor savings.
The inclusion of references to the I&O manual will provide additional guidance and clarity to the test procedure. It does not impose additional test burden since the information is already available in the manufacturers' literature.
The amendment of the duct work setup for units that are installed without a return duct and the requirement to test multi-position units in the least efficient position only clarify the testing requirements. The duct work setup change reflect current industry practice and does not introduce new testing requirements. With respect to the multi-position unit testing, most manufacturers indicated that the change reflects their understanding and current practice. DOE notes that, although the test method did not describe the position for testing as the “least efficient position,” in practice, if following the existing method for setup, manufacturers should have tested the least efficient position or all testing configurations. DOE also notes that AHRI commented that this reflects the common practice of its members, which is to test in the least efficient position. (AHRI, Public Meeting Transcript, No. 23 at p. 123) Therefore, DOE expects that there would be no additional test burden associated with these revisions.
The requirement to report AFUE to be truncated to the tenth of a percentage point and the requirement to report whether a boiler uses a burner delay automatic means control strategy will not introduce any additional test burden because they do not require retesting; however, they may impose a cost on either boiler manufacturers or manufacturers who do not currently report AFUE to a tenth of a percentage point, who must submit new certification reports and relabel their products. DOE discusses this burden in section IV.B.
For these reasons, DOE concludes that the amended test procedure will not be unduly burdensome to conduct.
When DOE modifies test procedures, it must determine to what extent, if any, the new test procedure would alter the measured energy efficiency or energy use of any covered product. (42 U.S.C. 6293(e)(1)) In the NOPR, DOE stated that the one amendment that might alter the AFUE of covered products is the incorporation by reference of ASHRAE 103–2007. 80 FR 12876, 12897.
As discussed in section III.C, based on stakeholder comments, DOE has declined to incorporate by reference ASHRAE 103–2007 in this final rule. Therefore, the amended test procedure will not alter measured AFUE ratings.
As discussed in section III.D.1, certain stakeholders commented that the proposed revision in the NOPR regarding the method for determining the electrical power consumption would change the power measurements. In response to comments, for the Final Rule, DOE decided not to change the method for calculating the electrical consumption and only clarified the definition of the PE term. This clarification will not alter measured AFUE ratings.
As discussed in section III.D.3, certain stakeholders expressed concern that allowing the measurement of condensate during the establishment of steady state conditions would have an impact on the final calculated AFUE value. In response to comments, DOE clarified for the final rule that this is an option rather than a requirement. DOE has found through its testing as shown in the test data presented at the NOPR public meeting indicating both options produce a similar rate of condensate mass production and therefore would have a
As discussed in section III.D.4.b, certain stakeholders expressed concern that the proposed adjustment of the CO
DOE received no comment regarding the impact of measured energy use on the remaining test procedure amendments, including the smoke stick test, duct work for units that are installed without a return duct, and testing requirements for multi-position configurations. The smoke stick test serves to verify a condition and does not
For these reasons, DOE has determined that none of the adopted test procedure amendments would alter the projected measured energy efficiency or energy use of the covered products that are the subject of this rulemaking.
In 2008, DOE published a technical amendment to the 2007 energy conservation standards final rule for residential furnaces and boilers that added design requirements for boilers consistent with the provisions of EISA 2007, including mandating, starting September 1, 2012, that all gas, oil, and electric hot water boilers (excluding those equipped with a tankless domestic water heating coil) be equipped with automatic means for adjusting the boiler water temperature (“automatic means”) to ensure that an incremental change in inferred heat load produces a corresponding incremental change in the temperature of water supplied (codified at 42 U.S.C. 6295(f)(3)).
The existing DOE residential furnace and boiler test procedure does not include any method of test for determining compliance with these design requirements. In the March 2015 NOPR, DOE proposed the introduction of a new test method for the verification of the automatic means for adjusting the water temperature in boilers. DOE proposed the use of two test methods—one for single-stage boilers and one for two-stage/modulating boilers—for verification of the functionality of the automatic means for adjusting the water temperature supplied by a boiler. The proposed test methods were based on draft testing methodologies provided by Natural Resources Canada (NRCan), as well as the California mechanical codes section for non-residential boilers.
Several stakeholders commented on the lack of compliance criteria for the automatic means test. Burnham asserted that it is legally unacceptable for DOE to not specify any objective criteria for demonstrating compliance and that DOE does not have authority to unilaterally create criteria to determine compliance with the automatic means test without notice and comment. (Burnham, No. 35 at p. 6) Weil-McLain stated that it is not clear what this required test criteria or procedure would be, but that, once defined, this test will require more time and resources to complete. Weil-McLain also asserted that the new requirement is arbitrary and capricious because it is so indefinite. (Weil-McLain, No. 31 p. 8)
DOE's automatic means design requirement does not specify how a manufacturer must implement the automatic means and does not provide compliance criteria for the automatic means testing. DOE interprets the design requirement established by EISA 2007 as intending to allow manufacturers flexibility when designing control strategies to meet the design requirement. DOE believes that the requirement of an incremental change in inferred heat load that produces a corresponding incremental change in the temperature of water supplied is a sufficient metric for evaluation of the functionality of an automatic means for adjusting water temperature. DOE designed the tests, as noted in the March 2015 NOPR, to confirm whether the boiler supply water temperature responds to a change in inferred heat load without specifying to what degree the temperature must change or for how long that change is present because such detail is not required for meeting the design requirement. DOE also designed the test methods to accommodate technological advancements in controls and designs. For these reasons, DOE does not agree with Burnham and Weil-McLain that establishing further criteria or thresholds is required beyond the general requirements set forth in the 2008 technical amendment to the furnace and boiler final rule.
Lochinvar stated that while it supports the use of automatic means as an effective method of energy conservation, it opposes testing controls for compliance for the following reasons: (1) The lack of compliance threshold; (2) no guarantee of repeatability or consistency in test method or results; (3) difficulty in reasonably measuring the effectiveness of different designs; (4) test method may be biased for or against certain control methods; and (5) a published simulation-type test will lead to manufacturers designing automatic means for the test compliance. (Lochinvar, No. 29 at p. 3) AHRI stated that the criterion to confirm the functioning of the means is too vague to be meaningful, and that DOE should not finalize this proposed procedure and not pursue further the concept of adding a test to verify the functioning of the automatic means. (AHRI, No. 36 at p. 6)
Several stakeholders commented on technical issues regarding the proposed test method. Lochinvar and Burnham stated that single-stage products may use options other than “thermal purge.” (Lochinvar, No. 29 at p. 3; Burnham, No. 35 at p. 6) Lochinvar stated that if DOE chooses to require automatic means testing, single-stage boilers must be allowed to comply by meeting either the proposed test method in § 429.134(e)(1) or (e)(2). (Lochinvar, No. 29 at p. 3)
Lochinvar also stated that DOE incorrectly states that the automatic means will change the heat output of a boiler in response to the inferred heat load. Responding to DOE's proposal in the March 31, 2015 notice of proposed rulemaking for energy conservation standards for boilers (“March 2015 ECS Boiler NOPR”), Lochinvar asserted that the automatic means would change the temperature of the water supplied, not necessarily the heat output. (Lochinvar, No. 29 at p. 4)
Burnham argued that the water temperatures specified are too low to necessarily cause a burner delay. Also responding to the March 2015 ECS Boiler NOPR, Burnham suggested that the proposed 10 CFR
Burnham stated that the proposed 10 CFR 429.134(e)(2)(ii)(B)(
Burnham stated that some of the control strategies currently in use require multiple burner cycles to determine the inferred heat load, which does not seem to be taken into account by DOE's proposed verification method. (Burnham, No. 35 at p. 6)
DOE makes several changes to the proposed verification of automatic means tests to address the technical comments received from Lochinvar and Burnham. DOE revised the two tests for the verification of automatic means presented in the NOPR such that the test previously identified as the two-stage/modulating boilers test will apply to all boilers, with the exception of single-stage boilers that employ a burner delay control strategy. The test for all boiler products monitors water temperature settings from the inferential load controller and/or monitors supply water temperature to determine whether the supply water temperature changes in response to changes in the inferred load. This test method allows for establishing the necessary conditions that may lead to a change in inferred load, for example, a change in outdoor air temperature, a change in thermostat patterns, and/or a change in boiler cycling.
DOE is adopting the test previously identified as the single-stage boilers test as the test method for single-stage boilers that employ a burner delay control strategy to fulfill the automatic means design requirement as specified in 42 U.S.C. 6295(f)(3)(B)(ii). The test for single-stage boilers that employ a burner delay control strategy captures the delayed burner reaction following a call for heating when residual heat is present within the boiler.
DOE agrees with Burnham and Lochinvar's comments that help to clarify the test method and allow for accommodating variations in the control strategies. Therefore, DOE adopts revisions that include removing the minimum supply water temperature tolerance requirement to allow variations in temperature when burner cycling occurs; increasing the inlet water temperature from 120 °F (±2 °F) to 140 °F (±2 °F) for the test method for single-stage boilers that employ a burner delay control strategy so that it is high enough to cause burner delay; and making terminology related to inlet water consistent throughout the test method. However, DOE disagrees with Burnham's comment that the tolerance range for determining a stabilized supply water temperature could not be met under a specific control strategy, such as the boost mode where an extended call for heating occurs until the heat demand is satisfied. In such a case, DOE's test method would be implemented when either the heat demand is satisfied or the high boiler water temperature limit is reached.
As discussed in the March 2015 NOPR, DOE also adds a definition for “controlling parameter.” DOE has placed this definition in 10 CFR 430.2 rather than appendix N as it applies to DOE enforcement regulations rather than manufacturer testing. Controlling parameter is defined as a measurable quantity for a residential boiler (such as temperature or usage pattern) used for inferring heating load, which would then result in incremental changes in supply water temperature.
This document amends 10 CFR 429.18, 10 CFR 429.134, 10 CFR 430.2, 10 CFR 430.3, 10 CFR 430.23, and 10 CFR part 430, subpart B, appendix N. When DOE modifies test procedures, it must determine to what extent, if any, the new test procedure would alter the measured energy efficiency or energy use of any covered product. (42 U.S.C. 6293(e)(1)) For the reasons described previously, DOE has determined that none of the test procedure amendments would alter the measured energy efficiency or energy use of the covered products that are the subject of this rulemaking. The changes made to appendix N through this final rule, as listed in section III.D, clarify the manner in which the test is conducted, or otherwise represent minor changes or additions to the test or reporting requirements that do not affect measured energy use. Therefore, these amendments become effective 30 days after publication of this final rule in the
The Office of Management and Budget (OMB) has determined that test procedure rulemakings do not constitute “significant regulatory actions” under section 3(f) of Executive Order 12866, “Regulatory Planning and Review,” 58 FR 51735 (Oct. 4, 1993). Accordingly, this action was not subject to review under the Executive Order by the Office of Information and Regulatory Affairs (OIRA) in OMB.
The Regulatory Flexibility Act (5 U.S.C. 601
DOE reviewed this final rule under the provisions of the Regulatory Flexibility Act and the procedures and policies published on February 19, 2003. 68 FR 7990. This final rule amends DOE's test procedure by providing clarifications regarding relevant test procedure provisions and revising the definitions of some terms. DOE has concluded that this final rule will not have a significant impact on a substantial number of small entities. The factual basis for this certification is as follows:
The Small Business Administration (SBA) considers a business entity to be a small business if, together with its affiliates, it employs less than a threshold number of workers specified in 13 CFR part 121. These size standards and codes are established by the North American Industry Classification System (NAICS) and are available at
After DOE identified manufacturers of residential furnaces and consumer boilers, DOE then consulted publically-available data and contacted companies, as necessary, to determine if they both meet the SBA's definition of a “small business” manufacturer and have their manufacturing facilities located within the United States. DOE screened out companies that did not offer products covered by this rulemaking, did not meet the definition of a “small business,” or are foreign-owned and operated. Based on this analysis, DOE identified 9 small businesses that manufacture residential furnaces and 9 small businesses that manufacture residential boilers (two of which also manufacture residential furnaces), for a total of 16 small businesses potentially impacted by this rulemaking.
This document amends DOE's test procedure by incorporating several changes that modify the existing test procedure or reporting requirements for furnaces and boilers. This includes the following changes that could potentially impact manufacturers: (1) Clarified definition of electrical power term PE; (2) a smoke stick method for determining whether the minimum default draft factor may be used; (3) a provision to allow for the measurement of condensate under steady-state conditions; (4) reference to manufacturers' I&O manuals; (5) specification of ductwork for units that are installed without a return duct; (6) specification of testing requirements for multi-position units; (7) revised reporting precision for AFUE to the nearest tenth of a percentage point; and (8) requirement to report the use of a burner delay automatic means control strategy in certification reports. The estimated costs of testing/rating and potential impact to manufacturer burden resulting from use of the amended test procedure are discussed subsequently. The estimated costs and potential impacts apply to all manufacturers, including the manufacturers identified as small businesses.
DOE believes that explicitly listing the components encompassed in the definition of PE does not change the definition of the electrical power term PE but rather only clarifies it, and will not impose any additional test burden.
The adoption of the smoke stick method for determining whether the minimum default draft factor may be used is intended to reduce the test burden to manufacturers. DOE estimated that the smoke stick method for determining the minimum default draft factor would reduce the overall duration of the test by about 15 minutes for units designed to have no flow through the heat exchanger. However, DOE does not have sufficient information to support estimating the fraction of units that have been designed such that there is no flow through the heat exchanger. Therefore, DOE has not included the cost savings associated with the smoke stick.
The addition of the optional provision to allow for the measurement of condensate prior to the establishment of steady state conditions will result in a lowering of test burden for manufacturers of condensing furnaces and boilers. Manufacturers of condensing furnaces and boilers will benefit from the time and labor savings attributed to the measurement of condensate during the establishment of steady-state conditions. However, DOE does not have sufficient information to support estimating the fraction of units that would be tested under the optional provision. Therefore, DOE has not included the cost savings associated with the optional provision to allow for the measurement of condensate prior to the establishment of steady state conditions.
The clarification of duct work requirements for units that are installed without a return duct and clarification of the test requirements for multi-position units do not present any additional test burden to manufacturers, as the two amendments do not change the existing testing requirements or conflict with current industry practice.
Revision of AFUE reporting precision and the requirement to report the use of a burner delay automatic means control strategy in the certification report do not present any additional test burden to manufacturers, as the two amendments do not change testing requirements. However, both amendments may require some manufacturers to submit new certification reports and relabel their products. DOE estimates that for affected parties, submitting new certification reports and relabeling products will take 30 minutes per unit. At an assumed cost of $40 per hour, the cost to recertify and relabel is $20 per unit.
To determine the potential cost of the test procedure amendments on small furnace and boiler manufacturers, DOE estimated the cost of recertifying and relabeling per basic model and the savings from the optional provision to measure condensate during the establishment of steady state conditions, as described above. DOE estimated that on average, each furnace small business would have 51 basic models, and each boiler small business would have 70 basic models. Based on residential furnace and boiler model data, DOE assumed that approximately 70 percent of all furnace and 60 percent of all boiler manufacturers will need to recertify and relabel due to the revision of the AFUE reporting precision. Based on residential boiler model data, DOE assumed that about 75 percent of boilers are single-stage boilers; furthermore, DOE assumed that about two-thirds of single-stage boilers employ a burner delay automatic means control strategy. Thus, DOE assumed that half of all boiler models will employ a burner delay automatic means control strategy. The additional recertification and relabeling cost associated with the test procedure amendments was multiplied by the estimated fraction of affected basic models produced by a small manufacturer. DOE has estimated a total added cost from the test procedure amendments of $714 per furnace
For the reasons stated previously, DOE certifies that this rule will not have a significant economic impact on a substantial number of small entities.
Manufacturers of residential furnaces and boilers must certify to DOE that their products comply with all applicable energy conservation standards. In certifying compliance with applicable performance standards, manufacturers must test their products according to the DOE test procedures for residential furnaces and boilers, including any amendments adopted for those test procedures. Manufacturers must also ensure their products comply with applicable design standards. DOE has established regulations for the certification and recordkeeping requirements for all covered consumer products and commercial equipment, including residential furnaces and boilers.
Notwithstanding any other provision of the law, no person is required to respond to, nor shall any person be subject to a penalty for failure to comply with, a collection of information subject to the requirements of the PRA, unless that collection of information displays a currently valid OMB Control Number.
In this final rule, DOE amends its test procedure for residential furnaces and boilers. DOE has determined that this rule falls into a class of actions that are categorically excluded from review under the National Environmental Policy Act of 1969 (42 U.S.C. 4321
Executive Order 13132, “Federalism,” 64 FR 43255 (August 10, 1999) imposes certain requirements on agencies formulating and implementing policies or regulations that preempt State law or that have Federalism implications. The Executive Order requires agencies to examine the constitutional and statutory authority supporting any action that would limit the policymaking discretion of the States, and to carefully assess the necessity for such actions. The Executive Order also requires agencies to have an accountable process to ensure meaningful and timely input by State and local officials in the development of regulatory policies that have Federalism implications. On March 14, 2000, DOE published a statement of policy describing the intergovernmental consultation process it will follow in the development of such regulations. 65 FR 13735. DOE examined this final rule and determined that it will not have a substantial direct effect on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government. EPCA governs and prescribes Federal preemption of State regulations as to energy conservation for the products that are the subject of this final rule. States can petition DOE for exemption from such preemption to the extent, and based on criteria, set forth in EPCA. (42 U.S.C. 6297(d)) No further action is required by Executive Order 13132.
Regarding the review of existing regulations and the promulgation of new regulations, section 3(a) of Executive Order 12988, “Civil Justice Reform,” 61 FR 4729 (Feb. 7, 1996), imposes on Federal agencies the general duty to adhere to the following requirements: (1) Eliminate drafting errors and ambiguity; (2) write regulations to minimize litigation; (3) provide a clear legal standard for affected conduct rather than a general standard; and (4) promote simplification and burden reduction. Section 3(b) of Executive Order 12988 specifically requires that Executive agencies make every reasonable effort to ensure that the regulation: (1) Clearly specifies the preemptive effect, if any; (2) clearly specifies any effect on existing Federal law or regulation; (3) provides a clear legal standard for affected conduct while promoting simplification and burden reduction; (4) specifies the retroactive effect, if any; (5) adequately defines key terms; and (6) addresses other important issues affecting clarity and general draftsmanship under any guidelines issued by the Attorney General. Section 3(c) of Executive Order 12988 requires Executive agencies to review regulations in light of applicable standards in sections 3(a) and 3(b) to determine whether they are met or it is unreasonable to meet one or more of them. DOE has completed the required review and determined that, to the extent permitted by law, this final rule meets the relevant standards of Executive Order 12988.
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA) requires each Federal agency to assess the effects of Federal regulatory actions on State, local, and Tribal governments and the private sector. Public Law 104–4, sec. 201 (codified at 2 U.S.C. 1531). For a regulatory action resulting in a rule that may cause the expenditure by State, local, and Tribal governments, in the aggregate, or by the private sector of $100 million or more in any one year (adjusted annually for inflation), section 202 of UMRA requires a Federal agency to publish a written statement that estimates the resulting costs, benefits, and other effects on the national economy. (2 U.S.C. 1532(a), (b)) The UMRA also requires a Federal agency to develop an effective process to permit timely input by elected officers of State, local, and Tribal governments on a proposed “significant intergovernmental mandate,” and requires an agency plan for giving notice and opportunity for timely input to potentially affected small governments before establishing any requirements that might significantly or uniquely affect small governments. On March 18, 1997, DOE published a statement of policy on its process for intergovernmental consultation under UMRA. 62 FR 12820. (This policy is also available at
Section 654 of the Treasury and General Government Appropriations Act, 1999 (Pub. L. 105–277) requires Federal agencies to issue a Family Policymaking Assessment for any rule that may affect family well-being. This rule will not have any impact on the autonomy or integrity of the family as an institution. Accordingly, DOE has concluded that it is not necessary to prepare a Family Policymaking Assessment.
Pursuant to Executive Order 12630, “Governmental Actions and Interference with Constitutionally Protected Property Rights,” 53 FR 8859 (March 18, 1988), DOE has determined that this regulation will not result in any takings that might require compensation under the Fifth Amendment to the U.S. Constitution.
Section 515 of the Treasury and General Government Appropriations Act, 2001 (44 U.S.C. 3516 note) provides for agencies to review most disseminations of information to the public under guidelines established by each agency pursuant to general guidelines issued by OMB. OMB's guidelines were published at 67 FR 8452 (Feb. 22, 2002), and DOE's guidelines were published at 67 FR 62446 (Oct. 7, 2002). DOE has reviewed this final rule under the OMB and DOE guidelines and has concluded that it is consistent with applicable policies in those guidelines.
Executive Order 13211, “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use,” 66 FR 28355 (May 22, 2001), requires Federal agencies to prepare and submit to OMB, a Statement of Energy Effects for any significant energy action. A “significant energy action” is defined as any action by an agency that promulgated or is expected to lead to promulgation of a final rule, and that: (1) Is a significant regulatory action under Executive Order 12866, or any successor order; and (2) is likely to have a significant adverse effect on the supply, distribution, or use of energy; or (3) is designated by the Administrator of OIRA as a significant energy action. For any significant energy action, the agency must give a detailed statement of any adverse effects on energy supply, distribution, or use if the regulation is implemented, and of reasonable alternatives to the action and their expected benefits on energy supply, distribution, and use.
This regulatory action is not a significant regulatory action under Executive Order 12866. Moreover, it would not have a significant adverse effect on the supply, distribution, or use of energy, nor has it been designated as a significant energy action by the Administrator of OIRA. Therefore, it is not a significant energy action, and, accordingly, DOE has not prepared a Statement of Energy Effects.
Under section 301 of the Department of Energy Organization Act (Pub. L. 95–91; 42 U.S.C. 7101), DOE must comply with section 32 of the Federal Energy Administration Act of 1974, as amended by the Federal Energy Administration Authorization Act of 1977 (Pub. L. 95–70). (15 U.S.C. 788; FEAA) Section 32 essentially provides in relevant part that, where a proposed rule authorizes or requires use of commercial standards, the notice of proposed rulemaking must inform the public of the use and background of such standards. In addition, section 32(c) requires DOE to consult with the Attorney General and the Chairman of the Federal Trade Commission (FTC) concerning the impact of the commercial or industry standards on competition.
This final rule incorporates testing methods contained in the following commercial standard: ASTM D2156–09 (Reapproved 2013). While this test procedure is not exclusively based on this standard, the DOE test procedure adopts several provisions from this standard without amendment. DOE has evaluated this standard and is unable to conclude whether it fully complies with the requirements of section 32(b) of the FEAA (
In this final rule, DOE incorporates by reference the ASTM test standard “Standard Test Method for Smoke Density in Flue Gases from Burning Distillate Fuels,” ASTM D2156–09 (Reapproved 2013). ASTM D2156 is an industry accepted test procedure that establishes uniform test methods for the evaluation of smoke density in the flue gases from burning distillate fuels. The test procedure established in this final rule references ASTM D2156 in its entirety, which includes terminology, methods of testing, materials, apparatus, procedures, reporting, and precision and bias, to determine the allowable smoke in the flue of oil furnaces and boilers. ASTM D2156–09 is available on ASTM's Web site at
As required by 5 U.S.C. 801, DOE will report to Congress on the promulgation of this rule prior to its effective date. The report will state that it has been determined that the rule is not a “major rule” as defined by 5 U.S.C. 804(2).
The Secretary of Energy has approved publication of this final rule.
Confidential business information, Energy conservation, Household appliances, Imports, Reporting and recordkeeping requirements.
Administrative practice and procedure, Confidential business information, Energy conservation, Household appliances, Imports, Incorporation by reference, Intergovernmental relations, Small businesses.
For the reasons stated in the preamble, DOE amends parts 429 and 430 of chapter II, subchapter D of title 10, Code of Federal Regulations, as set forth below:
42 U.S.C. 6291–6317.
(a) * * *
(2) * * *
(vii)
(b) * * *
(4) For multi-position furnaces, the annual fuel utilization efficiency (AFUE) reported for each basic model must be based on testing in the least efficient configuration. Manufacturers may also report and make representations of additional AFUE values based on testing in other configurations.
(h)
(1)
(i)
(B)
(C)
(D)
(
(ii)
(
(B)
(
(iii)
(B)
(
(
(iv) [Reserved]
(2)
(i)
(B)
(C)
(ii)
(B)
(C)
(D)
(iii)
(B)
(C)
(iv) [Reserved]
42 U.S.C. 6291–6309; 28 U.S.C. 2461 note.
(1) Is designed to be the principal heating source for the living space of a residence;
(2) Is not contained within the same cabinet with a central air conditioner whose rated cooling capacity is above 65,000 Btu per hour;
(3) Is an electric central furnace, electric boiler, forced-air central furnace, gravity central furnace, or low-pressure steam or hot water boiler; and
(4) Has a heat input rate of less than 300,000 Btu per hour for electric boilers and low-pressure steam or hot water boilers and less than 225,000 Btu per hour for forced-air central furnaces, gravity central furnaces, and electric central furnaces.
(g) * * *
(11) ANSI/ASHRAE Standard 103–1993, (“ASHRAE 103–1993”), Methods of Testing for Annual Fuel Utilization Efficiency of Residential Central Furnaces and Boilers, (with Errata of October 24, 1996), except for sections 7.1, 7.2.2.2, 7.2.2.5, 7.2.3.1, 7.8, 8.2.1.3, 8.3.3.1, 8.4.1.1, 8.4.1.1.2, 8.4.1.2, 8.4.2.1.4, 8.4.2.1.6, 8.6.1.1, 8.7.2, 8.8.3, 9.1.2.2.1, 9.1.2.2.2, 9.5.1.1, 9.5.1.2.1, 9.5.1.2.2, 9.5.2.1, 9.7.1, 9.7.4, 9.7.6, 9.10, 11.5.11.1, 11.5.11.2 and appendices B and C, approved October 4, 1993, IBR approved for § 430.23 and appendix N to subpart B.
(j) * * *
(2) ASTM D2156–09 (Reapproved 2013) (“ASTM D2156R13”), Standard Test Method for Smoke Density in Flue Gases from Burning Distillate Fuels, approved October 1, 2013, IBR approved for appendix N to subpart B.
(n) * * *
(2) The annual fuel utilization efficiency for furnaces, expressed in percent, is the ratio of the annual fuel output of useful energy delivered to the heated space to the annual fuel energy input to the furnace determined according to section 10.1 of appendix N of this subpart for gas and oil furnaces and determined in accordance with section 11.1 of the American National Standards Institute/American Society of Heating, Refrigerating, and Air-Conditioning Engineers (ANSI/ASHRAE) Standard 103–1993 (incorporated by reference, see § 430.3) for electric furnaces. Truncate the annual fuel utilization efficiency to one-tenth of a percentage point.
After July 13, 2016, representations with respect to energy use or efficiency of residential furnaces and boilers, including compliance certifications, must be based on testing conducted in accordance with this appendix.
1.0
For purposes of this appendix, the Department of Energy incorporates by reference several industry standards, either in whole or in part, as listed in § 430.3. In cases where there is a conflict, the language of the test procedure in this appendix takes precedence over the incorporated standards.
2.0
2.1
2.2
2.3
2.4
2.5
2.6
2.7
2.8
2.9
2.10
2.11
2.12
a. To facilitate the activation of other modes (including activation or deactivation of active mode) by remote switch (including thermostat or remote control), internal or external sensors, or timer;
b. Continuous functions, including information or status displays or sensor based functions.
2.13
3.0
4.0
5.0
6.0
6.1
a. Install the furnace or boiler in the test room in accordance with the I&O manual, as defined in section 2.6 of this appendix, except that if provisions within this appendix are specified, then the provisions herein drafted and prescribed by DOE govern. If the I&O manual and any additional provisions of this appendix are not sufficient for testing a furnace or boiler, the manufacturer must request a waiver from the test procedure pursuant to 10 CFR 430.27.
b. If the I&O manual indicates the unit should not be installed with a return duct, then the return (inlet) duct specified in section 7.2.1 of ASHRAE 103–1993 (incorporated by reference, see § 430.3) is not required.
c. Test multi-position furnaces in the least efficient configuration. Testing of multi-position furnaces in other configurations is permitted if energy use or efficiency is represented pursuant to the requirements in 10 CFR part 429.
d. The apparatuses described in section 6 of this appendix are used in conjunction with the furnace or boiler during testing. Each piece of apparatus shall conform to material and construction specifications listed in this appendix and in ASHRAE 103–1993 (incorporated by reference, see § 430.3), and the reference standards cited in this appendix and in ASHRAE 103–1993.
e. Test rooms containing equipment must have suitable facilities for providing the utilities (including but not limited to environmental controls, sufficient fluid source(s), applicable measurement equipment, and any other technology or tools) necessary for performance of the test and must be able to maintain conditions within the limits specified in section 6 of this appendix.
6.2
a. Units not equipped with a draft hood or draft diverter must be provided with the minimum-length vent configuration recommended in the I&O manual or a 5-ft flue pipe if there is no recommendation provided in the I&O manual (see Figure 4 of ASHRAE 103–1993 (incorporated by reference, see § 430.3)). For a direct exhaust system, insulate the minimum-length vent configuration or the 5-ft flue pipe with insulation having an R-value not less than 7 and an outer layer of aluminum foil. For a direct vent system, see section 7.5 of ASHRAE 103–1993 for insulation requirements.
b. For units with power burners, cover the flue collection box with insulation having an R-value of not less than 7 and an outer layer of aluminum foil before the cool-down and heat-up tests described in sections 9.5 and 9.6 of ASHRAE 103–1993 (incorporated by reference, see § 430.3), respectively. However, do not apply the insulation for the jacket loss test (if conducted) described in section 8.6 of ASHRAE 103–1993 or the steady-state test described in section 9.1 of ASHRAE 103–1993.
c. For power-vented units, insulate the shroud surrounding the blower impeller with insulation having an R-value of not less than 7 and an outer layer of aluminum foil before the cool-down and heat-up tests described in sections 9.5 and 9.6, respectively, of ASHRAE 103–1993 (incorporated by reference, see § 430.3). Do not apply the insulation for the jacket loss test (if conducted) described in section 8.6 of ASHRAE 103–1993 or the steady-state test described in section 9.1 of ASHRAE 103–1993. Do not insulate the blower motor or block the airflow openings that facilitate the cooling of the combustion blower motor or bearings.
6.3
6.4
a. For units with an integral draft diverter, cover the 5-ft stack with insulation having an R-value of not less than 7 and an outer layer of aluminum foil.
b. For units with draft hoods, insulate the flue pipe between the outlet of the furnace and the draft hood with insulation having an R-value of not less than 7 and an outer layer of aluminum foil.
c. For units with integral draft diverters that are mounted in an exposed position (not inside the overall unit cabinet), cover the diverter boxes (excluding any openings through which draft relief air flows) before the beginning of any test (including jacket loss test) with insulation having an R-value of not less than 7 and an outer layer of aluminum foil.
d. For units equipped with integral draft diverters that are enclosed within the overall unit cabinet, insulate the draft diverter box with insulation as described in section 6.4.c before the cool-down and heat-up tests described in sections 9.5 and 9.6, respectively, of ASHRAE 103–1993 (incorporated by reference, see § 430.3). Do not apply the insulation for the jacket loss test (if conducted) described in section 8.6 of ASHRAE 103–1993 or the steady-state test described in section 9.1 of ASHRAE 103–1993.
6.5
7.0
7.1
7.2
7.3
7.4
7.5
7.6 Adjust air throughputs to achieve a temperature rise that is the higher of a and b, below, unless c applies. A tolerance of ±2 °F is permitted.
a. 15 °F less than the nameplate maximum temperature rise or
b. 15 °F higher than the minimum temperature rise specified in the I&O manual.
c. A furnace with a non-adjustable air temperature rise range and an automatically controlled airflow that does not permit a temperature rise range of 30°F or more must be tested at the midpoint of the rise range.
7.7 Establish the temperature rise specified in section 7.6 of this appendix by adjusting the circulating airflow. This adjustment must be accomplished by symmetrically restricting the outlet air duct and varying blower speed selection to obtain the desired temperature rise and minimum external static pressure, as specified in Table 4 of ASHRAE 103–1993 (incorporated by reference, see § 430.3). If the required temperature rise cannot be obtained at the minimum specified external static pressure by adjusting blower speed selection and duct outlet restriction, then the following applies.
a. If the resultant temperature rise is less than the required temperature rise, vary the blower speed by gradually adjusting the blower voltage so as to maintain the minimum external static pressure listed in Table 4 of ASHRAE 103–1993 (incorporated by reference, see § 430.3). The airflow restrictions shall then remain unchanged. If static pressure must be varied to prevent unstable blower operation, then increase the static pressure until blower operation is stabilized, except that the static pressure must not exceed the maximum external static pressure as specified by the manufacturer in the I&O manual.
b. If the resultant temperature rise is greater than the required temperature rise, then the unit can be tested at a higher temperature rise value, but one not greater than nameplate maximum temperature rise. In order not to exceed the maximum temperature rise, the speed of a direct-driven blower may be increased by increasing the circulating air blower motor voltage.
7.8
7.9
7.10
7.10.1
7.10.1.1
7.10.1.2
7.10.1.3
7.10.1.4
7.10.1.5
If absolutely no smoke is drawn into the combustion air intake, the furnace or boiler meets the requirements to allow use of the minimum default draft factor pursuant to section 8.8.3 and/or section 9.10 of ASHRAE 103–1993 (incorporated by reference, see § 430.3).
If there is any smoke drawn into the intake, proceed with the methods of testing as prescribed in section 8.8 of ASHRAE 103–1993.
8.0
8.1
8.2
For furnaces, during the steady-state test, perform a single measurement of the electrical power to the circulating air blower (BE). For hot water boilers, use the circulating water pump nameplate power for BE, or if the pump nameplate power is not available, use 0.13 kW.
8.3
8.4
8.5
For furnaces that employ post-purge, measure the length of the post-purge period with a stopwatch. Record the time from burner “OFF” to combustion blower “OFF” (electrically de-energized) as t
8.6
8.7
a. During this off-period, for units that do not have pump delay after shut-off, do not allow any water to circulate through the hot water boilers.
b. For units that have pump delay on shut-off, except those having pump controls sensing water temperature, the unit control must stop the pump. Measure and record the time between burner shut-off and pump shut-off (t
c. For units having pump delay controls that sense water temperature, operate the pump for 15 minutes and record t
d. For boilers that employ post-purge, measure the length of the post-purge period with a stopwatch. Record the time from burner “OFF” to combustion blower “OFF” (electrically de-energized) as t
8.8
8.9
8.10
8.11
8.11.1
8.11.2
9.0
10.0
10.1
10.2
If the option in section 8.10 of this appendix is employed, calculate
10.3
If the option in section 8.10 of this appendix is employed, calculate Effy
10.4
10.4.1
10.4.1.1 For furnaces and boilers equipped with two stage or step modulating controls the average annual energy used during the heating season, E
10.4.1.2 For furnaces and boilers equipped with two-stage or step-modulating controls, the national average number of burner operating hours at the reduced operating mode (BOH
10.4.1.3 For furnaces and boilers equipped with two-stage controls, the national average number of burner operating hours at the maximum operating mode (BOH
10.4.1.4 For furnaces and boilers equipped with step-modulating controls, the national average number of burner operating hours at the modulating operating mode (BOH
10.4.2
10.4.2.1 For furnaces or boilers equipped with either two-stage or step modulating controls, E
10.4.3
10.4.3.1 For furnaces or boilers equipped with two-stage controls, E
10.4.3.2 For furnaces or boilers equipped with step-modulating controls, E
10.5
10.6
10.6.1
10.6.2
10.7
10.7.1
10.7.2
10.7.3
10.8
10.8.1
10.8.2
10.8.3
10.9
10.9.1 For mobile home furnaces, the sales weighted average annual fossil fuel energy consumption is expressed in Btu per year and defined as:
10.9.2 For mobile home furnaces, the sales-weighted-average annual auxiliary electrical energy consumption is expressed in kilowatt-hours and defined as:
10.10
10.11
Bureau of Alcohol, Tobacco, Firearms, and Explosives, Department of Justice.
Final rule.
The Department of Justice is amending the regulations of the Bureau of Alcohol, Tobacco, Firearms, and Explosives (ATF) regarding the making or transferring of a firearm under the National Firearms Act (NFA). This final rule defines the term “responsible person,” as used in reference to a trust, partnership, association, company, or corporation; requires responsible persons of such trusts or legal entities to complete a specified form and to submit photographs and fingerprints when the trust or legal entity files an application to make an NFA firearm or is listed as the transferee on an application to transfer an NFA firearm; requires that a copy of all applications to make or transfer a firearm, and the specified form for responsible persons, as applicable, be forwarded to the chief law enforcement officer (CLEO) of the locality in which the applicant/transferee or responsible person is located; and eliminates the requirement for a certification signed by the CLEO. These provisions provide a public safety benefit as they ensure that responsible persons undergo background checks. In addition, this final rule adds a new section to ATF's regulations to address the possession and transfer of firearms registered to a decedent. The new section clarifies that the executor, administrator, personal representative, or other person authorized under State law to dispose of property in an estate may possess a firearm registered to a decedent during the term of probate without such possession being treated as a “transfer” under the NFA. It also specifies that the transfer of the firearm to any beneficiary of the estate may be made on a tax-exempt basis.
This rule is effective July 13, 2016.
Brenda Raffath Friend, Office of Regulatory Affairs, Enforcement Programs and Services, Bureau of Alcohol, Tobacco, Firearms, and Explosives, U.S. Department of Justice, 99 New York Avenue NE., Washington, DC 20226; telephone: (202) 648–7070.
The current regulations at 27 CFR 479.63 and 479.85, which require fingerprints, photographs, and a law enforcement certification for individual applicants to make or transfer National Firearms Act (NFA) firearms, do not apply to trusts or legal entities. On September 9, 2013, the Department of Justice (“the Department” or DOJ) published in the
The goal of this final rule is to ensure that the identification and background check requirements apply equally to individuals, trusts, and legal entities. To lessen potential compliance burdens for the public and law enforcement, DOJ has revised the final rule to eliminate the requirement for a certification signed by a chief law enforcement officer (CLEO) and instead require CLEO notification. DOJ has also clarified that the term “responsible person” for a trust or legal entity includes those persons who have the power and authority to direct the management and policies of the trust or legal entity to receive, possess, ship, transport, deliver, transfer, or otherwise dispose of a firearm for, or on behalf of, the trust or entity. In the case of a trust, those with the power or authority to direct the management and policies of the trust include any person who has the capability to exercise such power and possesses, directly or indirectly, the power or authority under any trust instrument, or under State law, to receive, possess, ship, transport, deliver, transfer, or otherwise dispose of a firearm for or on behalf of the trust.
With respect to trusts, partnerships, associations, companies, or corporations, this final rule defines the term “responsible person” as an individual in the organization that has the power and authority to direct the management and policies of the entity insofar as they pertain to firearms. This final rule requires that each responsible person complete a specified form and submit photographs and fingerprints when the trust or legal entity either files an application to make an NFA firearm, or is listed as the transferee on an application to transfer an NFA firearm.
This rule requires that trusts and legal entities (
This final rule also requires that all those who apply to make or receive an NFA firearm, as well as all responsible persons for each trust or legal entity applicant or transferee, notify their local CLEO that an application has been filed with ATF before the applicant or transferee is permitted to make or receive an NFA firearm. Current regulations require individuals, but not trusts or legal entities, to obtain CLEO certification before making or receiving an NFA firearm. ATF estimates that the total cost of the CLEO notification requirement will be approximately $5.8 million annually ($0.5 million for individuals; $5.3 million for legal entities). The current cost of CLEO certification for individuals is approximately $2.26 million annually. Consequently, the final rule's estimated net cost increase is approximately $3.6 million annually. This increase, however, primarily involves costs to responsible persons for trusts and legal entities that had not previously been required to register, and will be offset by cost savings to individuals. ATF estimates the change in the final rule to a notice requirement will save individuals approximately $1.8 million annually. This rule is not an “economically significant” rulemaking under Executive Order 12866.
The Attorney General is responsible for enforcing the provisions of the NFA, 26 U.S.C. Chapter 53.
Section 5822 of the NFA, 26 U.S.C. 5822, provides that no person shall make a firearm unless the person has: (1) Filed with the Attorney General a written application, in duplicate, to make and register the firearm; (2) paid any tax payable on the making and evidenced such payment by affixing the proper stamp to the original application form; (3) identified the firearm to be made in the application form in such manner as prescribed by regulation; (4) identified the applicant in the application form, in such manner as prescribed by regulation, except that, if such person is an individual, the identification must include the individual's fingerprints and photograph; and (5) obtained the approval of the Attorney General to make and register the firearm and shows such approval on the application form. Applications shall be denied if the making or possession of the firearm would place the person making the firearm in violation of law. For purposes of title 26, United States Code, the term “person” means “an individual, a trust, estate, partnership, association, company or corporation.” 26 U.S.C. 7701(a)(1).
Regulations implementing section 5822 are set forth in 27 CFR part 479, subpart E. Section 479.62 provides, in pertinent part, that no person may make a firearm unless the person has filed with the Director a written application on ATF Form 1 (5320.1),
Section 479.63 states that if the applicant is an individual, such person must securely attach to each copy of the Form 1, in the space provided on the form, a 2 x 2-inch photograph of the applicant taken within 1 year prior to the date of the application. The regulation also provides that a completed Federal Bureau of Investigation (FBI) Form FD–258 (Fingerprint Card), containing the fingerprints of the applicant, must be submitted in duplicate with the application.
In addition, § 479.63 provides that the law enforcement certification located on Form 1 must be completed and signed by the local chief of police or county
Under the current regulations, the requirements for fingerprints, photographs, and law enforcement certification specified in § 479.63 are not applicable to an applicant who is not an individual,
Section 479.64 sets forth the procedure for approval of an application to make a firearm. As specified, the Form 1 application must be forwarded, in duplicate, by the maker of the firearm to the Director, in accordance with the instructions on the form. If the application is approved, the Director will return the original to the maker of the firearm and retain the duplicate. Upon receipt of the approved application, the maker is authorized to make the firearm described therein. The maker of the firearm may not, under any circumstances, make the firearm until the application has been forwarded to the Director and has been approved and returned by the Director with the NFA stamp affixed. If the application is disapproved, the original Form 1 and the remittance submitted by the applicant for the purchase of the stamp will be returned to the applicant with the reason for disapproval stated on the form.
Section 5812(a) of the NFA, 26 U.S.C. 5812(a), which applies to applications to transfer a firearm, is substantively similar to NFA section 5822 (described above in section II.A of this final rule). Regulations implementing section 5812 are set forth in 27 CFR part 479, subpart F. In general, § 479.84 provides that no firearm may be transferred in the United States unless an application, ATF Form 4 (5320.4),
Section 479.85 states that if the transferee is an individual, such person must securely attach to each copy of the Form 4, in the space provided on the form, a 2 x 2-inch photograph of the transferee taken within 1 year prior to the date of the application. The transferee must also attach to the application two properly completed FBI Forms FD–258 (Fingerprint Card). In addition, a certification by the local chief of police, county sheriff, head of the State police, State or local district attorney or prosecutor, or such other person whose certification may in a particular case be acceptable to the Director, must be completed on each copy of the Form 4. The certifying official must state,
Under the current regulations, the requirements for fingerprints, photographs, and law enforcement certification specified in § 479.85 do not apply to individuals qualified as a manufacturer, importer, dealer, or Special (Occupational) Taxpayer (SOT) under part 479; nor do they apply to a transferee who is not an individual,
Section 5852(e) of the NFA, 26 U.S.C. 5852(e), provides that an unserviceable firearm may be transferred as a curio or ornament without payment of the transfer tax imposed by section 5811, under such requirements as the Attorney General may by regulations prescribe.
Section 5853(a) of the NFA, 26 U.S.C. 5853(a), provides that a firearm may be transferred without the payment of the transfer tax imposed by section 5811 to any State, possession of the United States, any political subdivision thereof, or any official police organization of such a government entity engaged in criminal investigations.
Regulations implementing sections 5852(e) and 5853(a) are set forth in 27 CFR 479.90 and 479.91. These sections provide, in pertinent part, that the exemption from the transfer tax for the transfer of an unserviceable firearm as a curio or ornament or for a transfer to or from certain government entities may be obtained by the transferor of the firearm by filing with the Director an application, ATF Form 5 (5320.5),
On September 9, 2013, ATF published in the
The proposed regulations were in response to a petition for rulemaking, dated December 3, 2009, filed on behalf of the National Firearms Act Trade and Collectors Association (NFATCA). The petitioner requested that the Department amend §§ 479.63 and 479.85, as well as corresponding ATF Forms 1 and 4. 78 FR at 55016–55017. The petition requested amendments as numbered and discussed below.
The NFATCA expressed concern that persons who are prohibited by law from possessing or receiving firearms may acquire NFA firearms without undergoing a background check by establishing a trust or legal entity such as a corporation or partnership. It contended that the number of applications to acquire NFA firearms via a trust or corporation, partnership, and other legal entity had increased significantly over the years, increasing the potential for NFA firearms to be accessible to those prohibited by law from having them. Therefore, for cases in which a trust, corporation, partnership, or other legal entity applies to make or receive an NFA firearm, the petitioner requested amendments to §§ 479.63 and 479.85 requiring photographs and fingerprint cards for individuals who are responsible for directing the management and policies of the entity so that a background check of those individuals may be conducted.
The proposed rule set forth ATF's finding that the number of Forms 1, 4, and 5 it received from legal entities that are neither individuals nor Federal Firearms Licensees (FFLs) increased from approximately 840 in 2000 to 12,600 in 2009 and to 40,700 in 2012, resulting in a substantial increase in the number of individuals who have access to NFA firearms but who have not undergone a background check in connection with obtaining that access. The proposed rule stated that the Department agreed with the concerns underlying petitioner's requests, and believed that responsible persons for a trust or legal entity should not be excluded from background checks and other requirements of the regulations that seek to ensure that prohibited persons do not gain access to NFA firearms. The proposed rule also discussed an application ATF had recently denied after recognizing that the trust name and firearm were the same as those on a prohibited individual's recently denied application. The proposed rule noted that the application might have been approved if the trust name had been different from that of the prior transferee or if the application had included a different firearm.
When filing an ATF Form 1, 4, or 5, the applicant also must submit ATF Form 5330.20,
The proposed rule accommodated the petitioner's request that the information required on Form 5330.20 be incorporated into the requirements of 27 CFR 479.63 and 479.85 and the corresponding forms. According to the petitioner, “[e]limination of the ATF Form 5330.20 by adding a citizenship statement to the transfer [and making] forms would reduce human effort for both the public and ATF while reducing funds expenditures for printing, copying, and handling the form.”
The proposed rule stated that the Department supports the elimination of unnecessary forms and is committed to reducing the paperwork burden for individuals and businesses. Accordingly, the Department proposed amending 27 CFR 479.62 and 479.84 and the corresponding forms to incorporate information currently required in Form 5330.20.
The proposed rule also accommodated the petitioner's request that the instructions on applications to make or transfer a firearm be revised so that they are consistent with those on ATF Form 7 (5310.12),
The proposed rule stated that the Department agreed that proposed changes to the regulations would require modifications to corresponding Forms 1, 4, and 5, including changes to the instructions on the forms, and proposed to go forward with those changes.
Finally, the proposed rule accepted in part petitioner's request that the law enforcement certification requirement be eliminated and that ATF “adopt a CLEO [chief law enforcement officer] process that will include a full NICS [National Instant Criminal Background Check System] check for principal officers of a trust or corporation receiving such firearms for the trust or corporation.” The petitioner articulated several reasons in support of its request. In addition, the petitioner stated that “[s]ome CLEOs express a concern of perceived liability; that signing an NFA transfer application will link them to any inappropriate use of the firearm.” See 78 FR at 55016–55017 for full discussion.
The Department agreed in principle with some of petitioner's assertions (for example, that ATF independently verifies whether receipt or possession of an NFA firearm would place the applicant or transferee in violation of State or local law).
In addition to the issues raised in NFATCA's 2009 petition, the Department proposed amending 27 CFR 479.11 to add a definition for the term “responsible person.” The proposed term included specific definitions in the case of a trust, partnership, association, company (including a Limited Liability Company (LLC)), or corporation. Depending on the context, the proposed term included any individual, including any grantor, trustee, beneficiary, partner, member, officer, director, board
To ensure that responsible persons, as so defined, were subject to penalties under 26 U.S.C. 5871 for committing unlawful acts under the NFA (
Although the definition of “person” in § 479.11 includes the word “estate,” ATF traditionally has treated estates differently from business entities. Therefore, the Department did not propose defining the term “responsible person” to include estates. The Department explained that estates are temporary legal entities created to dispose of property previously possessed by a decedent with the estate's term typically defined by the law of the State in which the decedent resided, whereas partnerships, trusts, associations, companies, and corporations are formed for a specific purpose and remain in existence until action is taken to dissolve them. The Department further explained that, historically, ATF has treated the transfer of a registered NFA firearm held by an estate differently from other transfers under the NFA. ATF has allowed the executor—or other person authorized under State law to dispose of property in an estate—to convey firearms registered to the decedent without being treated as a voluntary transfer under the NFA. ATF has also allowed such transfers to be made on a tax-exempt basis when an ATF Form 5 is submitted and approved in accordance with 27 CFR 479.90. When the transfer of the firearm is to persons who are not lawful heirs, however, the executor is required to file an ATF Form 4 and to pay any transfer tax in accordance with 27 CFR 479.84.
With respect to an application to make a firearm, the Department proposed several amendments to 27 CFR 479.62 (“Application to make”) and 479.63 (“Identification of applicant”).
Amendments to § 479.62 proposed to:
1. Provide that if the applicant is a partnership, company, association, trust, or corporation, all information on the Form 1 application must be furnished for each responsible person of the applicant;
2. Specify that if the applicant is a partnership, company, association, trust, or corporation, each responsible person must comply with the identification requirements prescribed in the proposed § 479.63(b); and
3. Require the applicant (including, if other than an individual, any responsible person), if an alien admitted under a nonimmigrant visa, to provide applicable documentation demonstrating that the applicant falls within an exception to 18 U.S.C. 922(g)(5)(B) or has obtained a waiver of that provision.
Amendments to § 479.63, where the applicant is an individual, proposed to maintain the CLEO certification but omit the requirement for a statement about the use of a firearm for other than lawful purposes. This section proposed to require, instead, that the certification state that the official is satisfied that the fingerprints and photograph accompanying the application are those of the applicant and that the official has no information indicating that possession of the firearm by the maker would be in violation of State or local law.
The Department stated that the CLEO's certification that the CLEO “is satisfied that the fingerprints and photograph accompanying the application are those of the applicant,” is an existing requirement for an individual applicant (
Additionally, amendments to § 479.63, where the applicant is a partnership, company, association, trust, or corporation, proposed to:
1. Provide that the applicant must be identified on the Form 1 application by the name and exact location of the place of business, including the name of the county in which the business is located or, in the case of a trust, the address where the firearm is located. In the case of two or more locations, the address shown must be the principal place of business (or principal office, in the case of a corporation) or, in the case of a trust, the principal address at which the firearm is located;
2. Require the applicant to attach to the application:
• Documentation evidencing the existence and validity of the entity, which includes complete and unredacted copies of partnership agreements, articles of incorporation, corporate registration, declarations of trust, with any trust schedules, attachments, exhibits, and enclosures; however, if the entity had an application approved as a maker or transferee within the preceding 24 months, and there had been no change to the documentation previously provided, the entity may provide a certification that the information has not changed since the prior approval and must identify the application for which the documentation had been submitted by form number, serial number, and date approved;
• A completed ATF Form 5320.23 for each responsible person. Form 5320.23 would require certain identifying information for each responsible person, including each responsible person's full name, position, Social Security number (optional), home address, date and place of birth, and country of citizenship;
• In accordance with the instructions provided on Form 5320.23, a 2 x 2-inch photograph of each responsible person, clearly showing a full front view of the features of the responsible person with head bare, with the distance from the top of the head to the point of the chin approximately 1
• Two properly completed FBI Forms FD–258 (Fingerprint Card) for each responsible person. The fingerprints must be clear for accurate classification and should be taken by someone properly equipped to take them; and
• In accordance with the instructions provided on Form 5320.23, a certification for each responsible person completed by the local chief of police, sheriff of the county, head of the State police, State or local district attorney or prosecutor, or such other person whose certification may in a particular case be acceptable to the Director. The certification for each responsible person must be completed by the CLEO who has jurisdiction over the area in which the responsible person resides. The certification must state that the official is satisfied that the fingerprints and photograph accompanying the application are those of the responsible person and that the certifying official has no information indicating that possession of the firearm by the
ATF also sought public comments regarding the feasibility of asking CLEOs to certify that they are satisfied that the photographs and fingerprints match those of the responsible person and whether changes were needed to this proposal.
With respect to an application to transfer a firearm, the Department proposed several amendments to 27 CFR 479.84 (“Application to transfer”) and 479.85 (“Identification of transferee”).
Amendments to § 479.84 proposed to provide that:
1. The Form 4 application, in duplicate, must be filed by the transferor. If the transferee is a partnership, company, association, trust, or corporation, all information on the Form 4 application must be furnished for each responsible person of the transferee; and
2. The type of firearm being transferred must be noted on the Form 4. If the firearm is other than one classified as “any other weapon,” the applicant must submit a remittance in the amount of $200 with the application in accordance with the instructions on the form. If the firearm is classified as “any other weapon,” the applicant must submit a remittance in the amount of $5.
Where the transferee is an individual, the proposed amendments to § 479.85 retained the certification requirement but eliminated the requirement for a CLEO statement about the use of a firearm for other than lawful purposes. In addition, the proposal required the certification to state that the official is satisfied that the fingerprints and photograph accompanying the application are those of the applicant and that the certifying official has no information indicating that receipt or possession of the firearm by the transferee would be in violation of State or local law.
The Department stated that the CLEO's certification that the CLEO “is satisfied that the fingerprints and photograph accompanying the application are those of the applicant,” if an individual applicant, is an existing requirement (
Amendments to § 479.85, where the transferee is a partnership, company, association, trust, or corporation, proposed to:
1. Provide that the transferee must be identified on the Form 4 application by the name and exact location of the place of business, including the name of the county in which the business is located or, in the case of a trust, the address where the firearm is to be located. In the case of two or more locations, the address shown must be the principal place of business (or principal office, in the case of a corporation) or, in the case of a trust, the principal address at which the firearm is to be located;
2. Require the transferee to attach to the application:
• Documentation evidencing the existence and validity of the entity, which includes complete and unredacted copies of partnership agreements, articles of incorporation, corporate registration, declarations of trust, with any trust schedules, attachments, exhibits, and enclosures; however, if the entity has had an application approved as a maker or transferee within the preceding 24 months, and there had been no change to the documentation previously provided, including the responsible person information, the entity may provide a certification that the information has not changed since the prior approval and must identify the application for which the documentation had been submitted by form number, serial number, and date approved;
• A completed ATF Form 5320.23 for each responsible person. Form 5320.23 would require certain identifying information, including the responsible person's full name, position, Social Security number (optional), home address, date and place of birth, and country of citizenship;
• In accordance with the instructions provided on Form 5320.23, a 2 x 2-inch photograph of each responsible person, clearly showing a full front view of the features of the responsible person with head bare, with the distance from the top of the head to the point of the chin approximately 1
• Two properly completed FBI Forms FD–258 (Fingerprint Card) for each responsible person. The fingerprints must be clear for accurate classification and should be taken by someone properly equipped to take them; and
• In accordance with the instructions provided on Form 5320.23, a certification for each responsible person completed by the local chief of police, sheriff of the county, head of the State police, State or local district attorney or prosecutor, or such other person whose certification may in a particular case be acceptable to the Director. The certification for each responsible person must be completed by the CLEO who has jurisdiction over the area in which the responsible person resides. The certification must state that the official is satisfied that the fingerprints and photograph accompanying the application are those of the responsible person and that the certifying official has no information indicating that receipt or possession of the firearm by the responsible person would be in violation of State or local law.
ATF also sought public comments concerning the feasibility of asking CLEOs to certify that they are satisfied that the photographs and fingerprints match those of the responsible person, or whether changes were needed to this proposal.
Section 5853(a) of the NFA, 26 U.S.C. 5853(a), provides that a firearm may be transferred to any State, possession of the United States, any political subdivision thereof, or any official police organization of such a government entity engaged in criminal investigations, without the payment of the transfer tax. Regulations implementing section 5853(a) are set forth in 27 CFR 479.90. That section provides, in pertinent part, that the transfer tax exemption may be obtained by the transferor of the firearm by filing with the Director an application on ATF Form 5 (5320.5),
The Department proposed amending § 479.90(b) to remove the word “natural.” Removing the word “natural” leaves the term “person,” which was defined in proposed § 479.11 to include a partnership, company, association, trust, or corporation (including each responsible person of such entity), an estate, or an individual. Under this proposal, each transferee (including all responsible persons) would be subject to the requirements prescribed in proposed § 479.85 when a governmental entity transfers a firearm to a partnership,
The Department also proposed adding a new section to part 479 to address the possession and transfer of firearms registered to a decedent.
Section 479.91 provides that an unserviceable firearm, defined in § 479.11 as a firearm that is incapable of discharging a shot by means of an explosive and incapable of being readily restored to a firing condition, may be transferred as a curio or ornament without payment of the transfer tax. This section also provides that the procedures set forth in § 479.90 must be followed for the transfer of an unserviceable firearm, with the exception that a statement must be entered on the application that the transferor is entitled to the exemption because the firearm is unserviceable and is being transferred as a curio or ornament. The Department proposed no changes to this section. However, the Department noted that § 479.91 references the procedures in § 479.90, which in turn references § 479.85, thereby providing notice that changes to § 479.85 would apply to transfers governed by § 479.91.
In the proposed rule, ATF recognized that the composition of the responsible persons associated with a trust, partnership, association, company, or corporation may change over time. As a result, ATF stated that it was considering a requirement that new responsible persons submit Form 5320.23 within 30 days of such a change. ATF sought comments on this option and solicited recommendations for other approaches.
The comment period for the proposed rule closed on December 9, 2013.
In response to the proposed rule, ATF received over 9,500 comments. Comments were submitted by citizens; individuals associated with trusts, corporations, and other legal entities; individuals associated with estates; FFLs; SOTs; silencer manufacturers; nonprofit and other organizations; trade associations; lawyers; collectors; hunters; and others.
Several commenters supported the entire proposed rule, while the majority opposed the entire proposed rule. The majority of commenters also opposed the proposed expansion of the CLEO certification requirement and the new definition for a “responsible person” for a trust or legal entity. Some of the commenters who opposed the proposed expansion of the CLEO certification requirement and the new “responsible person” definition, however, supported other portions of the proposed rule. The commenters' support and opposition, along with specific concerns and suggestions, are discussed below.
More than a dozen commenters stated that they supported the proposed rule in its entirety. This support was based on a variety of reasons, including that: (1) The current regulations create a “loophole,” through which prohibited persons can use a trust to circumvent the background check and CLEO certification requirements; (2) the benefit of ensuring felons and others could no longer circumvent background checks by submitting applications as representatives of a corporation or trust outweighed the “small inconvenience” the proposed rule would involve; (3) the current system of background checks only for individuals is inadequate to do the job of keeping guns out of the wrong hands; and (4) identification of and background checks on responsible persons would increase accountability for firearms regulated under the NFA.
The Department acknowledges the commenters' support for the proposed rule, which generally focuses on the importance of conducting background checks, particularly for individuals acquiring NFA firearms. This rule will require all responsible persons to provide the necessary information, including fingerprints, to allow ATF to conduct background checks through the various criminal record databases. In addition, individuals, as well as any responsible person associated with a trust or legal entity, will be required to provide notification to the local CLEO of the intent of the individual, trust, or legal entity with which the responsible person is associated, to make or acquire the NFA firearm identified on the form. This notification will provide the CLEO an opportunity to conduct any inquiries required by State law, and provide ATF with appropriate input regarding the lawfulness of the individual's or responsible person's acquisition or possession of a firearm.
Regarding the commenters who desired greater accountability for NFA weapons, the Department notes that the NFA requires inclusion of those weapons in the National Firearms Registration and Transfer Record (NFRTR), and that the NFRTR includes firearm identification information, as well as the name and address of the registrant. Moreover, by allowing for background checks on individuals who will possess and control firearms on behalf of trusts or legal entities, the rule will deter persons who are prohibited from possessing firearms from attempting to use such trusts or legal entities to unlawfully acquire firearms.
Two commenters stated that the proposal to incorporate the information currently required on ATF Form 5330.20 into Forms 1, 4, and 5 is beneficial, will reduce unnecessary paperwork, and increase efficiency. Another two commenters, including an FFL who is an SOT, supported the proposed changes eliminating the Form 5330.20 and incorporating the information from that form into Forms 1, 4, and 5. One of these commenters based his support on guidance provided by Executive Order 13610 of May 10, 2012 (“Identifying and Reducing Regulatory Burden”). Another commenter, a member of the NFATCA, stated that he supports the part of the proposed rule that would incorporate the certification of an applicant's status as a U.S. citizen, immigrant alien, or
The Department acknowledges the commenters' support for incorporating the certificate of compliance required to obtain the exemption provided by 18 U.S.C. 922(g)(5)(B) into ATF Forms 1, 4, and 5. This change will reduce the burden on the applicant by reducing the number of forms the applicant must complete to acquire an NFA firearm. The change will also reduce the cost burden on the Department as the Form 5330.20 will no longer have to be printed and separately processed by ATF.
Several commenters agreed with the addition of a new section in ATF's regulations addressing firearm transfers by estates, and supported the provisions regarding when a transfer occurs, and when a transfer tax must be paid. These commenters supported the additions because they increase clarity and provide specific direction for transfers through estates.
Other commenters supported the proposed changes related to estates and transfers, but suggested that the proposed rule did not go far enough. One commenter recommended expanding regulations to cover all involuntary transfers, including transfers at the dissolution of a corporation or other entity, liquidation in bankruptcy, and forced transfers during divorce proceedings, not just those involving the death of the owner. Other commenters argued that although they supported the treatment of estates, the proposal ran afoul of the Department's stated purpose to require the same identification and background checks of individuals and legal entities, and created a “fundamental internal inconsistency.” Similarly, another commenter suggested that trusts should be treated the same as estates, and not subject to the same requirements as apply to individuals. That commenter further stated that § 479.90a should expressly address the role of attorneys, because issues may arise that require an attorney to take possession of a firearm to effectuate distribution to beneficiaries. This commenter also stated that a copy of the obituary in a recognized newspaper should be an acceptable alternative to the death certificate.
The Department acknowledges supporters' comments regarding the addition of § 479.90a to address the possession and transfer of firearms registered to a decedent. The addition of this section clarifies that an executor, administrator, personal representative, or others recognized under State law may possess the firearm during the term of probate, which is often a concern for individuals dealing with the NFA firearms as part of an estate. Additionally, the rule provides clarification as to when a transfer tax must be paid.
The Department does not agree that its positions with regard to estates should be expanded to include other types of involuntary transfers as part of this rulemaking. Other types of involuntary transfers were not addressed in the proposed rule. The Department has exercised its discretion to decline to expand the scope of the rulemaking to encompass involuntary transfers not addressed in the proposed rule. Should the Department determine that its position with regard to estates should be extended to other involuntary transfers, it will do so in a separate rulemaking.
Transfers of NFA firearms from an estate to a lawful heir are necessary because the deceased registrant can no longer possess the firearm. For this reason, ATF has long considered any transfer necessitated because of death to be involuntary and tax-free when the transfer is made to a lawful heir as designated by the decedent or State law. However, when an NFA firearm is transferred from an estate to a person other than a lawful heir, it is considered a voluntary transfer because the decision has been made to transfer the firearm to a person who would not take possession as a matter of law. Such transfers cannot be considered involuntary and should not be exempt from the transfer tax. Other tax-exempt transfers—including those made by operation of law—may be effected by submitting Form 5. Instructions are provided on the form.
The Department disagrees that § 479.90a should expressly address the role of attorneys to effectuate distribution to beneficiaries. Clear rules are provided that establish who can make the necessary distributions and how those distributions should occur. The Department also disagrees with the assertion that a copy of an obituary in a “recognized newspaper” should be recognized as equivalent to a death certificate for purposes of the new section addressing estate transfers, as anyone can pay to have an obituary published in a newspaper. However, a death certificate is an official document issued by a government agency; a newspaper obituary has no equivalent guarantee of authenticity.
When an individual heir is named in a will, the executor of the estate would file a Form 5 to effect the transfer. The heir would be listed on the Form 5 as the transferee and an individual heir would be required to submit photographs and fingerprints and be subject to a background check. Similarly, if the trust expires upon the death of the grantor, then the trustee, as the administrator of the trust, would file Form 5 to transfer the firearm to the individual named as the beneficiary. Like the heir, the beneficiary would be required to submit photographs and fingerprints and be subject to a background check. Transfers to trusts and legal entities from estates will require that responsible persons at those trusts and legal entities identify themselves in the same manner as they would in circumstances involving a taxable transfer. If there is no beneficiary or the beneficiary does not wish to possess the registered firearm, the trustee would dispose of the property to a person other than a trust beneficiary on an ATF Form 4. If, however, the trust remains a valid trust after the death of the grantor, the trustee would continue to administer the trust property according to the terms of the trust as there would be no transfer under the NFA.
Seventy-two commenters, including members of a trade organization, stated in a form letter that they agree that requiring fingerprint cards and photographs of all adult applicants or responsible persons of a trust or LLC acquiring NFA firearms would ensure that NFA firearms are not acquired by prohibited persons. These same commenters stated that they oppose any expansion of the CLEO requirement. Thirty-six other commenters stated in a form letter that by eliminating the CLEO signoff and narrowing the definition of responsible persons, ATF could still require fingerprints and background checks on the person primarily
The Department acknowledges support regarding the requirement for responsible persons of trusts or legal entities to submit fingerprints and photographs and undergo background checks. The Department agrees that responsible persons of trusts or legal entities should be subject to the same requirements as individuals acquiring an NFA firearm.
The Department acknowledges comments regarding expansion of the CLEO certification requirement. The Department has changed the CLEO certification in the proposed rule to a CLEO notification requirement in the final rule for all transferees, whether individuals, trusts, or legal entities.
A few commenters disagreed with all proposed changes without providing any specifics. The majority of commenters who were opposed to the proposed rule provided specific reasons as discussed below.
Many commenters stated that there are already stringent Federal regulations in place for the firearms covered by the proposed rule; for example, prohibited persons who receive or possess an NFA firearm through a legal entity are already violating current laws. A few commenters stated that these existing laws work, as shown by ATF's examples in the proposed rule. A few commenters objected to any additional firearm regulations.
Many commenters stated that this rule only creates more “red tape” for lawful citizens. Another commenter believed that the “filings” for corporations, trusts, and legal entities already identify a legally responsible person, and, as a result, maintained that the burdens of the proposed rule outweighed its benefits. Another commenter argued that a corporation or a trust was not a person, and should not be treated as one.
The Department acknowledges that there are existing Federal laws and regulations that pertain to NFA firearms and firearms more generally. Requiring background checks for responsible persons of trusts and legal entities helps to enforce those laws by keeping firearms out of the hands of persons who are prohibited from possessing them. The efficacy of background checks is evident in the statistics. The most recent statistics released by the Department of Justice, Bureau of Justice Statistics, reflect that through the end of December 2012, background checks run through the NICS by either the FBI or State point-of-contact agencies resulted in about 2.4 million denials.
In addition, requiring background checks for responsible persons of trusts and legal entities conforms the requirements applicable to those entities to those that apply to individuals. It also maintains consistency with the way ATF processes applications for Federal firearms licenses, where responsible persons for legal entities are subject to background checks.
Many commenters stated their view that this rulemaking is motivated by politics and not driven by legitimate concerns. Some argued that the proposal was an executive “overreach,” represented an “end run” around Congress, and was beyond the scope of ATF's regulatory authority. Some commenters expressed concern that the proposed regulation was intended to disarm law abiding citizens.
The Department acknowledges that the regulation of firearms provokes strong feelings on all sides and that any form of firearm regulation is often a topic of substantial debate. The Department initiated this rulemaking after ATF received a petition from the NFATCA, a non-profit association. ATF agreed with the petitioner that by not requiring background checks for trusts and legal entities, the existing regulations created the potential for abuse. The goal—as stated in both the proposed rule and here—is to ensure that the rules regarding NFA applications that apply to individuals apply equally to trusts and corporate entities. By ensuring background checks are run on certain persons who may have access to NFA weapons, the rule is intended to help enhance public safety. Put simply, this rule will not prevent a person who can lawfully possess firearms from receiving or possessing NFA firearms; it was designed to prevent persons who are prohibited from receiving or possessing firearms from obtaining them through the use of trusts or legal entities not currently subject to the same procedures applicable to individuals. The rule will not disarm law abiding citizens. However, it will help ensure that persons who are prohibited by law from
The Department also does not agree that the rule is outside of ATF's authority. ATF has regulated the circumstances under which NFA firearms are manufactured, transferred, and acquired for decades. This authority is based upon the authority to implement the law that Congress has both expressly and implicitly delegated to the Department. Specifically, the authority to implement the regulations requiring a CLEO certification have withstood challenge.
Many commenters stated that it is not necessary for the Department to add additional rules and that the current rules are sufficient to ensure NFA firearms are not acquired by unauthorized individuals. Many commenters felt that the proposed rule fails to address crime, and instead simply makes it more difficult for law-abiding citizens to legally obtain NFA registered firearms. Many commenters stated that someone who wishes to obtain a firearm for criminal purposes would not go through the NFA application process for a legal entity, a process that entails expense and efforts to register such firearms with the Federal Government.
One commenter noted that the proposed rule would alter the timing of the background check, and asserted that the timing would have a negative effect on safety. Currently, background checks are performed at the time the weapon is physically transferred; the proposed change would require the background check be performed at the beginning of the application process. This commenter stated that it currently takes transfer applications a year for approval, and with the proposed change, any arrests, convictions, or restraining orders that occur during this year would not be discovered and restricted persons could potentially obtain possession of the NFA items. Several commenters questioned why it takes ATF months to approve NFA applications if it does not currently run checks on trusts and legal entities.
Many commenters stated that there is no “loophole” to close, arguing that nothing in the current system allows felons or otherwise prohibited persons to possess NFA items through trusts, corporations, or individually. Several commenters further added that their trust was constructed in a manner such that prohibited persons may not have a role in the trust. Other commenters noted existing requirements that the person picking up the NFA item must still fill out ATF Form 4473,
Many commenters noted that ATF's three examples provided in the proposed rule fail to illustrate that there is a problem to be solved (
Many commenters requested ATF to leave the current regulations in place. Instead of proposing new rules and regulations, many commenters asked ATF to enforce the rules, laws, and penalties already on the books, and noted the small number of prosecutions resulting from NICS denials. A few of these commenters also requested that ATF give longer sentences and harsher penalties to those who break the rules. Another commenter noted that the current regulations are unenforceable due to an already “over-taxed and under-funded and under-staffed system.” Another commenter stated that ATF makes so many “gun laws” that the public cannot possibly understand them, and asked how ATF proposes to enforce them.
While the Department acknowledges that most individuals who apply to register and transfer an NFA firearm are not prohibited from possessing or receiving firearms, there have been a significant number of instances in which prohibited persons have submitted NFA applications. Information received from the ATF NFA Branch disclosed that from 2010 to 2014 there were approximately 270 NFA applications by individuals, out of 115,842 applications, that were disapproved due to background check denials. The NFA Branch also tracked the number of applications received from trusts and legal entities during the same period. The Department believes that the disapprovals would have been higher if background checks would have been conducted on responsible persons associated with the 217,996 applications received from trusts or legal entities during this time. This belief is based on the FBI's denial rate on NICS background checks between November 30, 1998, and December 31, 2014, which is approximately 1.24 percent. Additionally, the Department believes that the background check requirement has an important deterrent effect as a prohibited person would be less likely to try and acquire an NFA firearm knowing that the person would be subject to a background check.
As a result of the increased use of trusts or legal entities to acquire NFA
The Department does not agree that the proposed regulations are unnecessary. Background checks required under the Brady Act (18 U.S.C. 922(t) and 27 CFR 478.102), as part of the licensing process (18 U.S.C. 923(d)(1)(B) and 27 CFR 478.47(b)(2)), and the application process for individuals submitting applications to make or receive an NFA firearm (26 U.S.C. 5812 and 5822, 27 CFR 479.63 and 479.85) are in place to prevent prohibited persons from unlawfully acquiring firearms. The proposed rule is similarly intended to prevent prohibited persons from acquiring firearms by closing down an avenue that can be exploited.
The Department acknowledges that there is a backlog of NFA applications, and notes that the backlog has decreased over the last year. ATF processes applications as quickly as its resources allow.
The Department agrees with the commenters that the existing laws should be enforced, and the Department is committed to focusing its limited prosecutorial resources on the most significant violent crime problems facing our communities. That said, enforcement must be paired with common-sense regulatory efforts to help limit access to firearms by persons prohibited from possessing them. This rule is intended to do just that.
The Department acknowledges that the person picking up the NFA item must still fill out ATF Form 4473,
The Department does not regard time-of-transfer background checks as sufficient to comply with the transfer provision of the NFA. The Department interprets that provision to require that background checks precede the transfer of NFA firearms. Specifically, the statute provides that a firearm “shall not be transferred unless” the Secretary has approved the application, and that an application “shall be denied if the transfer, receipt, or possession of the firearm would place the transferee in violation of law.” 26 U.S.C. 5812(a). The Department construes that language to mean that background checks for individuals and responsible persons must be conducted before the application is approved. Additionally, this provision requires that an individual's “identification must include his fingerprints and his photograph.”
The Department does not agree that the proposed rule would alter the timing of the background check. Background checks under the statute's transfer provision are not currently performed at the time the weapon is physically transferred, as the commenter suggested. Rather, background checks are currently performed before an application is approved and will continue to be performed in the same manner. With respect to the commenter's concern that delay in processing applications might mean that an individual will become a prohibited person while awaiting a background check, the agency has two responses. First, because nothing about the Department's method of processing applications will change because of this rule, the Department believes the commenter's concern is outside the scope of this rulemaking. Second, processing times for applications reflect the delay between the time the application is received by the NFA Branch and the time the application is entered into the NFRTR and processed. As the background check is not conducted until after the information is entered into the NFRTR, any prohibitions that may have occurred after the applicant mailed the application will be disclosed when the background check is conducted.
Many commenters stated that these restrictions will not reduce crime and questioned whether violent crimes have been committed with registered NFA items, or by responsible persons of a trust or legal entity. Several commenters asked if ATF could provide the statistics demonstrating the need for the regulations and direct link between the proposed rule and enhanced public safety.
Many other commenters observed that NFA items are expensive, already heavily regulated, and “virtually unheard of” in the hands of criminals. Although commenters disagreed on the number of crimes they believe have been committed with registered NFA weapons, those addressing the subject agreed that the number was small, and argued that the proposed rule would accordingly have little to no effect on public safety.
The Department disagrees that it must show a direct link between the proposed rule and enhanced public safety. Congress has directed the Department to ensure that individuals who are prohibited from possessing NFA firearms do not obtain them, even if those individuals have no intention of using them in an unlawful manner.
Additionally, the Department notes that some individuals who own NFA firearms do in fact commit crimes. A review of trace data and criminal records from 2006 to 2014 disclosed twelve incidents in which owners of NFA firearms were convicted of crimes; however, there is no evidence that these crimes were committed with NFA firearms. Convictions include attempted homicide, conspiracy to commit felony offenses of firearms laws, operating a drug involved premises, possession of unlawful firearms, possession of marijuana, intent to distribute methamphetamine, possession of a firearm during commission of drug trafficking, domestic violence, theft, dealing firearms without a license, and possession of an unregistered NFA firearm.
In one instance the purchaser was arrested 9 days after the purchase of the firearm. In another instance the purchaser was arrested within 3 months of the purchase of the firearm. Both purchasers were convicted of drug related charges.
The Department acknowledges that the majority of firearms traced are handguns. However, between 2006 and 2013, local or Federal law enforcement recovered and ATF traced 5,916 NFA firearms. ATF is authorized to trace a firearm for a law enforcement agency involved in a bona fide criminal investigation. There were also at least seven instances in which the possessor of the firearm at the time it was traced was not the person it was registered to in the NFRTR. Under Federal law, possession of an NFA firearm by a person to whom it is not registered is unlawful (26 U.S.C. 5861(d)).
The Department also emphasizes that NFA weapons are dangerous weapons that can empower a single individual to take many lives in a single incident. Therefore, a low incidence of the use of NFA firearms in crimes does not reflect the threat to public safety that they pose. A low usage of NFA firearms in crime may also bespeak the success of the NFA in preventing such weapons from reaching the hands of prohibited persons in the past. The large increase in transfers in which no background check takes place, however, increases the risk that NFA firearms will reach prohibited persons. The Department does not believe it is reasonable to wait for an NFA firearm to be used in a significant criminal incident before crafting procedures reasonably calculated to carry out its regulatory mandate to prevent prohibited persons from obtaining NFA firearms.
Many commenters stated that the proposed rule is misleading because it suggests that there are no background checks currently required for trusts or legal entities when, in fact, the person who picks up an NFA item from a licensed dealer on behalf of a trust or legal entity must complete a Form 4473 and undergo an individual NICS background check prior to taking possession of the NFA item. Some of these commenters provided specific language from ATF's NFA Handbook as support for their point.
The Department acknowledges that ATF procedures currently require that FFLs run a background check on any person picking up a firearm on behalf of a trust or legal entity. However, this ensures only that the direct recipient from the FFL is not a prohibited person. It does not verify the status of the other responsible persons associated with a trust or legal entity who will have access to the firearm. Thus, this rule will help ensure that many persons with access to the firearm are neither prohibited possessors nor otherwise ineligible for such access. With the implementation of the rule, responsible persons for trusts and legal entities will undergo a background check as part of the application process. Therefore, a responsible person will not have to undergo a background check at the time of the transfer from the FFL.
Many commenters stated that the proposed rule mistakenly contends that individuals create trusts or legal entities solely to avoid background checks when acquiring NFA items. These commenters offered other valid reasons (
The Department is unable to assess the reason(s) for the recent exponential growth in the use of trusts, in particular, to acquire NFA firearms, and the proposed rule made no claim about the extent to which such trusts are being used predominantly to circumvent the background check requirement for individuals, as opposed to for other reasons. But the use of trusts has grown exponentially, and as a result so have the number of persons gaining access to NFA firearms without undergoing a background check. Regardless of their motive, the Department does not believe that responsible persons of trusts or legal entities should be excluded from the background check and other requirements that seek to ensure prohibited persons do not gain access to NFA firearms.
Additionally, the Department notes that it believes that even if individuals are not frequently exploiting the potential loophole in the statute, the existence of the loophole invites future exploitation. The Department regards it as wise to close the loophole to eliminate the opportunity for future evasion of the individual background check requirement, even if the tactic has not yet come into common use.
Some commenters noted that NFATCA's petition asked ATF to amend §§ 479.63 and 479.85 to, among other things, require photographs and fingerprints of persons responsible for directing the legal entity, eliminate the requirement for CLEO approval of Forms 1 and 4 for natural persons, and require notification to CLEOs for all Form 1 and Form 4 applicants. One commenter noted that the proposed rule differed from the petitioner's request by adding CLEO certification requirements, not removing them. Another commenter observed that the proposed rule did largely what the petitioner requested by expanding requirements for all responsible persons involved with corporations and trusts; however, the proposed rule lessened—but did not entirely eliminate—CLEO certification requirements. Several commenters referenced NFATCA's letter, dated August 31, 2013, in which NFATCA said that it supports the elimination of the CLEO certification requirement, but does not support the proposed rule in its current form. The NFATCA letter states, in part, that “[t]he Executive Branch proposals unduly burden the law-abiding public, will restrain lawful commerce and bury an already overwhelmed agency with an administrative infrastructure that will not serve the public safety interest.”
NFATCA also submitted a public comment to the rulemaking, stating that the proposed rule bears little resemblance to its petition, or to changes that NFATCA discussed with ATF and that were published in “ATF's Unified Agenda repeatedly over the past several years”
The Department acknowledges that in proposing to extend CLEO certification rather than notification requirements, and not eliminating all CLEO involvement, the proposed rule differed not only from material contained in the published abstracts of RIN 1140–AA43 in the 2011 and 2012 Unified Agendas, but also from what the petition
The Department agrees that a change from a CLEO certification to CLEO notification will require a change to the Forms 1, 4, and 5. See section IV.C.1 for further discussion.
Hundreds of commenters stated that the proposed rule violated and infringed their Second Amendment rights. Many commenters stated the proposed rule further eroded and encroached on such rights as they believe that the NFA—with some also adding the GCA—is unconstitutional and already unconstitutionally infringes the rights protected by the Second Amendment. Many commenters referenced the Supreme Court's decision in
Numerous commenters specifically connected the perceived Second Amendment infringement to the CLEO certification requirement, as some CLEOs are represented as being unwilling to sign off on applications, regardless of the applicant's background, or the legality of the NFA item in the applicant's jurisdiction.
A commenter focused particularly on silencers, which are included in the definition of firearm under the NFA. 26 U.S.C. 5845(a). This commenter provided data showing the benefits of silencers (
The Department notes that the NFA regulates weapons such as machineguns, short-barreled rifles, short-barreled shotguns, silencers, destructive devices, which include such items as grenade launchers, as well as firearms meeting the definition of “any other weapon,” which include disguised devices such as penguns, cigarette lighter guns, knife guns, cane guns and umbrella guns.
The Department does not believe that the proposed regulation violates, erodes, or otherwise infringes any rights protected by the Second Amendment. The Supreme Court and several Courts of Appeal have recognized, “the right to keep and bear arms has never been unlimited.”
The Department's position is that the Second Amendment, properly construed, allows for reasonable regulation of firearms.
In addition, although the Court did not purport to define the full scope of the Second Amendment right in
In the absence of any evidence tending to show that the possession or use of a [short-barreled shotgun] at this time has some reasonable relationship to the preservation or efficiency of a well-regulated militia, we cannot say that the Second Amendment guarantees the right to keep and bear
We may as well consider at this point (for we will have to consider eventually) what types of weapons
In
Like the restrictions on machineguns, the Department believes that other longstanding Federal restrictions on making and transferring SBSs, SBRs, silencers, and AOWs are “firmly historically rooted” and will not burden Second Amendment rights given the Court's holding in
Finally, even if a court were to conclude that the NFA and its implementing regulations are not “presumptively lawful,” they would nevertheless pass constitutional muster under existing Second Amendment jurisprudence. The NFA and this final rule are not a ban on NFA items, as some commenters suggest. Rather they are reasonable regulations on the possession of such weapons that the Department believes are consistent with the Second Amendment.
In response to those commenters who seek the repeal of the NFA and a different treatment for certain NFA weapons, like silencers, the Department cannot repeal the NFA, nor can it choose to ignore provisions of the act for certain weapons, or minimize the burden of the statutory language for certain weapons, such as, silencers, SBSs, SBRs, and AOWs. The statute neither requires nor is best read as permitting disparate treatments of NFA firearms in the manner suggested by the comments.
Assuming,
Although the CLEO certification process has been upheld by courts as a reasonable regulation (
One commenter stated that the wait time for ATF to approve NFA transfers is excessive, and that the proposed rule imposes additional restrictions. The commenter stated that these restrictions deprive him of the use of his legally obtained property, and violate the Fourth Amendment as they are a “de facto seizure.” Another commenter provided an example in which a county sheriff publicly stated that he would possibly provide CLEO certification, on the condition that the applicant “pass a background check” and “allow the Sheriffs (sic) Department to inspect the home where the weapon will be stored.” This commenter stated that this “safety inspection” blatantly violated the Fourth Amendment protection against unreasonable searches.
The Department believes that the law provides that applicants do not have a property interest in the NFA firearm sought during the application period. Therefore, an NFA firearm is not the property of a transferee until the transferor receives a properly approved NFA Form 4.
The Department takes the view that individuals, trusts, and legal entities do not obtain a property interest in an NFA firearm until the Department has approved an application to make or transfer one. A “protected property interest simply `cannot arise in an area voluntarily entered into . . . which, from the start, is subject to pervasive Government control.' ”
The Department therefore disagrees that delaying or preventing the transfer of an NFA firearm constitutes a “seizure” under the Fourth Amendment. As explained above, individuals, trusts, and legal entities do not have a property interest in an NFA firearm until a properly approved Form 1 or 4 is issued. They therefore lack standing to assert a Fourth Amendment claim because they cannot assert “an interest in the property seized.”
As to the comment regarding the home inspection that one CLEO purportedly required of citizens before granting a CLEO certification, the Department notes that the final rule will not include a CLEO certification requirement so there will be no further need to consent to such home inspections. Instead, the final rule will contain a CLEO notification provision, which should ease commenters' concerns.
Several commenters expressed a concern that local CLEOs would refuse to certify applications for little or no reason, amounting to a violation of due process under the Fifth Amendment. Several commenters also stated that applicants primarily use “gun trusts” due to their CLEOs' arbitrary and capricious refusal to provide certification, and expressed concern that the proposal essentially removes this option.
In addition, a few commenters noted that Federal appellate courts have recognized the validity of trusts established with a prohibited person as the settlor, which allows the prohibited person to maintain the prohibited person's “ownership” interest in the property while surrendering the prohibited person's right to the “possessory” interest to a trustee,
The Department believes that most of the commenters' concerns are addressed with the change from CLEO certification to CLEO notification. Moreover, this rule does not eliminate or significantly burden the use of trusts or legal entities by persons who may wish to employ them as part of the NFA firearm acquisition process.
The Department disagrees with commenters asserting that the proposed regulations would lead to a violation of an applicant's due process rights under the Fifth Amendment. Recently, at least two courts considered whether a denied NFA applicant had a property interest in the denied Form 1 application or in the NFA weapons he sought to make. Both district courts ruled that the applicant had no property interest in the ATF Form 1 or firearm at issue.
Procedural due process challenges must demonstrate that the “ `state has deprived a person of a liberty or property interest.' ”
Moreover, most, if not all, NFA applicants who will be impacted by the proposed change in the definition of a “person,” which requires “responsible persons” for a trust or legal entity to undergo a background check, will have no legally cognizable property interest in either the NFA firearm sought or the NFA application form. Several courts have held that a property interest is lacking where the alleged property is not accompanied by the “crucial indicia of property rights,” such as the right to assign, sell, or transfer the property at issue.
As for the comments expressing concerns about protecting the property interest of minors, the proposed regulation will allow trusts to possess the NFA weapon until the minor comes of age. Once the minor is of age, the minor can then complete the transfer application and background check and, if not otherwise prohibited from possessing an NFA firearm, take possession of the NFA weapon. The only change the rule makes is that it requires that responsible persons in trusts undergo background checks and not be prohibited persons. If anything, therefore, the rule will provide trust beneficiaries with an added measure of protection by ensuring that trust property is held in the hands of a law-abiding person who is not prohibited from possessing firearms under Federal or State law.
Moreover, to the extent that courts have recognized a felon's ability to employ a trust or other device to maintain an ownership interest, so long as there is no ability to physically possess or control the firearm, those cases have no application here. Trust beneficiaries who cannot physically possess or control firearms held in trust for them will not typically be responsible persons under the rule. Additionally, this rule pertains to the acquisition of a firearm, not the disposition of a firearm already owned by someone who later becomes prohibited.
The Fifth Amendment provides a right against self-incrimination, which
This comment has no relevance to the rule.
Commenters should be aware that
In response to
The 14th Amendment provides that “[n]o state shall . . . deprive any person of life, liberty, or property, without due process of law; nor deny to any person within its jurisdiction the equal protection of the laws.” Many commenters stated that CLEOs categorically or arbitrarily refuse to sign any ATF forms, even though the NFA firearm is completely legal in their jurisdiction. Further, according to other commenters some CLEOs impose additional burdensome and arbitrary conditions not consistent with the law, or even common sense, to obtain their signature. A few commenters believed that, as written, the proposed rule allows CLEOs to exercise an “administrative veto” in a selective and arbitrary, and not uniform, manner across the United States, thereby violating the 14th Amendment's Equal Protection Clause, as well as the Due Process Clause.
As previously stated, the final rule will not require CLEO certification or approval, but will instead require CLEO notification. This change moots the concerns—whether valid or not—that a CLEO's refusal to grant an individual a certification would violate the 14th Amendment.
A few commenters argued that the proposed rule unnecessarily interferes with State law in several ways, including by: (1) Undermining State law by granting CLEOs de facto arbitrary power to establish policies directly contrary to State law; (2) intruding on State law governing corporations, trusts, and LLCs by defining “responsible persons” of such entities; (3) undermining State laws limiting disclosure of information regarding ownership of firearms by mandating that an applicant share such information with a CLEO to obtain CLEO certification; and (4) imposing an unfunded mandate on CLEOs by expanding the CLEO certification requirement.
Given that the final rule will not require CLEO certification but rather only CLEO notification, the Department believes that any Federalism concerns raised by this rule are moot.
Moreover, this rule defines “responsible person” for purposes of NFA registration, and for no other purpose. Nor does this rule purport to impose any dissemination obligations or restrictions upon CLEOs with respect to the notifications they receive. Accordingly, this rule does not infringe upon legitimate State prerogatives in those areas.
A few commenters asserted that the original purpose of the NFA was to use the tax code solely to provide a basis for prosecuting “gangsters” who possessed untaxed, unregistered firearms, and not to prohibit NFA firearms, or eliminate the ability to transfer them to law-abiding citizens who paid the tax and followed the registration procedures. One of these commenters further asserted that by passing the Firearm Owners' Protection Act (FOPA), Public Law 99–308, 110 Stat. 449 (1986), Congress made clear that “ATF's regulations and enforcement activities of
Another commenter, citing the Supreme Court's decision in
Another commenter stated that ATF lacked statutory authority to promulgate a regulation creating a new class of persons (
The Department does not agree with comments that this rulemaking exceeds its authority to issue regulations for administration of the NFA. Congress granted the Attorney General
To the extent commenters assert that the proposed rule is inconsistent with the purpose underlying the NFA, the Department respectfully disagrees. The history of the NFA makes clear that Congress intended to use its tax authority to ensure the transfer of certain firearms was subject to a transfer tax and registration requirement to help prevent violent criminals from obtaining those firearms.
During the Great Depression, the Nation faced the difficulty of controlling violence by gangsters. Representative Robert L. Doughton noted that “for some time this country has been at the mercy of the gangsters, racketeers, and professional criminals.” 78 Cong. Rec. 11,400 (1934). The Attorney General, Homer Cummings, warned Congress that “there are more people in the underworld today armed with deadly weapons, in fact, twice as many, as there are in the Army and the Navy of the United States combined.”
The proposed rule's definition of “responsible person,” and its requirement that such persons undergo a background check prior to making or receiving an NFA firearm, are fully consistent with this legislative history and with the intended purpose of the NFA. The proposed rule serves Congress's intent in passing the NFA because it further denies criminals the ability to obtain NFA firearms. The proposed rule does not meaningfully limit the availability of firearms to the law-abiding public.
A similar response applies to the comments asserting that the proposed rule's requirement that responsible persons undergo a background check is inconsistent with Congressional intent underlying FOPA. The Department is certainly aware that, in passing FOPA, Congress expressed that it was not its intent to place undue or unnecessary restrictions or burdens on law abiding citizens with respect to the lawful private possession of firearms for lawful purposes. FOPA, Public Law 99–308, 100 Stat 449 (1986). However, this expression of intent was set out in a section of FOPA amending the GCA, not the NFA. In the context of the dangerous class of weapons regulated by the NFA, the Department's assessment is that the background check requirement is within its statutory authority, and the regulatory burden is proportionate and appropriate.
In any event, the rule in no way places undue or unnecessary Federal restrictions or burdens on law abiding citizens, but rather imposes regulations reasonably designed to fulfill the purposes of the NFA. The proposed rule is crafted to ensure consistent application of the law and effectuate Congress's preference that criminal background checks be conducted on unlicensed persons to whom firearms are transferred, including those who exert control over NFA firearms on behalf of trusts and legal entities. By defining many individuals affiliated with trust and legal entities who exert control over NFA firearms as “responsible persons” and requiring them to undergo background checks, the proposed rule helps achieve the Congressional objective of preventing the transfer of firearms to those who are prohibited or otherwise ineligible to possess or receive them.
One commenter challenged the adequacy of the industry impact disclosures in the proposed rule, asserting they were inaccurate and incomplete. Another commenter generally asserted that the proposed rule violated the constitutional rights of corporations.
The Department has undertaken its best efforts to accurately calculate the rule's benefits and costs. The Department believes the financial impact information contained in the NPRM refutes the commenter's challenge to the adequacy of the financial impact disclosures. The Department fully and accurately assessed the financial impact of the cost
The NPRM included the required statutory and executive order review, which fully addressed the financial impact of the proposed rule. These reviews concluded that the annual effect of the proposed rule on the economy will not exceed $100 million and that the proposed rule would not adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or tribal governments or communities. Accordingly, the proposed rule did not reach the threshold of an economically significant rulemaking under Executive Order 12866.
Moreover, because the statutory and executive order reviews in the NPRM included the costs of CLEO certification in their assessments, the cost estimates included in each of those reviews significantly overstate the cost that will be associated with the final rule. As noted, the final rule has eliminated the CLEO certification requirement and replaced that requirement with a less burdensome notice requirement. Thousands of commenters agreed that CLEO certification was the most expensive and cumbersome aspect of the proposed rule, and asserted that the elimination of the CLEO certification provision would result in substantial cost savings to the public and law enforcement. Examples of savings suggested in the comments included: (1) would-be applicants intended to create trust entities solely for the purpose of avoiding the CLEO certification process will now save the cost of that trust creation; (2) applicants who opt not to create a trust or cannot afford a trust will no longer have to expend time and resources obtaining CLEO certification; and (3) State and local law enforcement will not be required to expend the time and resources needed to complete certifications.
The Department does not agree that requiring responsible persons of trusts and legal entities to provide identification information and submit to a background check violates the constitutional rights of those entities. Background checks are lawful as applied to individuals, and the Department believes they are similarly lawful when applied to the responsible persons behind corporate entities. In fact, responsible persons of FFLs are subject to a background check, as are responsible persons of corporate entities that wish to obtain explosives permits or licenses. There is no reason to believe that because NFA weapons are involved, that same approach violates the Constitution in this context.
Many commenters stated that the CLEO certification requirement makes the proposed rule “unworkable” and demonstrates the need to eliminate this requirement for individuals as well. A few other commenters foresaw the proposed rule exposing ATF to potential lawsuits filed by law-abiding citizens who could not obtain NFA weapons because some CLEOs refuse to certify NFA applications, and protested that the proposed rule would eliminate the option of obtaining NFA items without a CLEO certification through a trust. See section IV.C.4.c, on general applicability, for additional information. Others added that that the certification requirement was an unworkable burden on both NFA applicants and State law enforcement agencies and that nothing in the proposed rule suggests that ATF has any intention to expand the size or funding of the NFA Branch to handle the increased workload as the number of individuals and Forms to check would drastically expand.
Several commenters stated generally that the proposed rule would cause “unintended consequences” and have “negative repercussions.” Many commenters stated that the proposed rule has the potential to dramatically increase the processing times and further burden what they regard as ATF's already overwhelmed NFA Branch, which they assert presently takes 8 to 10 months—with some commenters stating even longer times, (
Several commenters expressed concern that the proposed rule would impact an applicant's ability to file applications electronically.
As previously stated, in response to the concerns expressed by commenters, the final rule will no longer include a CLEO certification provision; instead, the final rule will include a CLEO notification provision that will require applicants simply to notify the CLEO in writing of the application in accordance with the language of the final regulation. Thus, the many concerns expressed by commenters regarding the CLEO certification are moot. The Department also believes that with the shift to CLEO notification, there will be cost and time-saving benefits for all applicants.
Likewise, concerns about the Department's reliance on CLEO certification to complete background checks on NFA applicants are moot. The Department will continue to conduct background checks in accordance with established procedures.
The Department believes it has considered all reasonably foreseeable consequences and possible repercussions arising from the rule. As with most meaningful changes to regulations or laws, the new rule may cause some operational or procedural changes, and may alter the workload and costs for industry members and Government workers. The Department acknowledges that this final rule may increase the time required to process applications received from trusts and legal entities, as well as for individuals, as an increased number of applications undergo more complete checks. The Department estimates that this final rule initially will increase processing times of these applications from the current four months processing time to six to eight months for processing. The Department anticipates that this time will be reduced once the NFA Branch adjusts to the new process. In addition, ATF will work to increase its resources and staffing to process the applications. Of course, continued increases in the number of applications submitted may correspondingly continue to place pressure on processing times. The Department has done its best to consider all possible consequences arising out of the final rule and has considered, among other things, the increased operational cost for the Government and industry members; the increased cost associated with additional fingerprint cards and photographs for responsible persons; and the increased labor cost associated with the time it takes for applicants and industry members to complete the required forms. Having considered all of the reasonably foreseeable costs and benefits, the Department has determined that the benefits of ensuring NFA weapons are less easily obtained by persons prohibited from possessing them outweigh the cost of implementing the rule.
In response to commenters who believe that this rulemaking may “goad” States into passing firearm laws that attempt to “nullify ATF's authority” in this area, the Department has two responses. First, the Department does not believe that State efforts to interfere with the rule's effectiveness lessen the need for it. The Department believes that the rule will help to fulfill the purposes of the NFA and help to ensure public safety even if State efforts might make it somewhat less effective than it would otherwise be.
Second, the Department believes that, to be valid, State firearms laws must be consistent with Federal law. The Supremacy Clause of the United States Constitution provides that the laws of the United States “shall be the supreme Law of the Land; . . . any Thing in the Constitution or Laws of any state to the Contrary notwithstanding.” U.S. Const. art. VI, cl. 2. Since
Many commenters stated the proposed rule failed to consider more cost effective and practical alternatives that would enhance public safety and enable ATF to better meet administrative obligations under the NFA, and suggested other mechanisms that ATF should consider. The majority of commenters suggested that ATF eliminate the CLEO certification requirement for all NFA transactions, for reasons discussed in section IV.C.1. Many commenters also proposed general alternatives. These proposed alternatives included eliminating the NFA altogether; removing some categories of items subject to NFA regulation (such as silencers); varying the regulatory requirements depending on the nature of the NFA item; amending NFA transaction forms to more strongly emphasize criminal liability for possession by a prohibited person; developing and improving enforcement efforts; and improving the administrative process.
Several commenters suggested that the NFA transfer procedures be repealed. Some of these commenters suggested replacing NFA transfer procedures with the issuance of “NFA cards,” that would allow the card-holder to purchase any NFA weapon. One of these commenters recommended that card applicants be required to undergo background checks and submit fingerprints and photographs.
Several commenters, including FFLs, who urged repeal of the NFA, suggested that transfer of NFA firearms should be handled in the same manner as GCA transfers, with either the $200 tax and registration requirements being abolished or having the tax collected at the point of sale by the FFL. One of these commenters asserted that a simple and effective background check by the FBI's National Crime Information Center would serve the same function as the current NFA procedure at greatly reduced cost. Another commenter characterized NFA regulations as “archaic” and argued that they should be repealed and changed in light of “advances in technology and linked NICS databases.” Another commenter urged that ATF abolish the requirements for fingerprints, photographs, and CLEO certification for all NFA transfers and add a requirement that the NFA Branch process and return all new applications in no more than 10 business days from date of receipt.
The Department does not have the authority to repeal the NFA or any of its provisions; the NFA is a statute that only Congress may repeal or alter. Only Congress can remove a weapon from the purview of the NFA, or alter, increase or decrease, the making or transfer tax on a NFA weapon. ATF does not have the authority to change any of the requirements mandated in the statute. The NFA provides very limited authority to permit exemptions from the transfer tax, and commenters' requested exemptions do not fall within that authority.
Specifically, the NFA provision governing the making of an NFA firearm, 26 U.S.C. 5822, requires that a person who seeks to make an NFA firearm (a) apply to make and register “the firearm,” (b) pay applicable taxes on such firearm, (c) identify the firearm to be made, (d) identify himself, and if an individual, “include his fingerprints and his photograph” and (e) obtain “approval of the Secretary to make and register the firearm.” 26 U.S.C. 5822. The statutory provision governing the transfer of NFA weapons, 26 U.S.C. 5812(a), is substantively similar to section 5822, requiring (a) an application for the specific firearm, (b) the payment of relevant taxes, (c) identification of the firearm, (d) identification of the applicant (with fingerprints and a photograph required for individuals), and (e) approval of the transfer of the firearm. The Department therefore cannot abolish the fingerprint and photograph identification requirements, nor issue blanket permits to individuals to make or transfer NFA firearms.
To the extent commenters would like the Department to change how it conducts its background checks, or not require fingerprints and photographs for applicants that are not individuals, the
Many commenters suggested that certain categories of NFA-regulated items should be removed. A few commenters stated that silencers, short-barreled rifles, short-barreled shotguns, and weapons falling within the NFA's “any other weapon” (AOW) definition should be regulated in the same manner as non-NFA firearms—requiring only a NICS background check when transferred from an FFL. Another commenter suggested that there be a more nuanced approach to regulating NFA items—not a one-size-fits-all approach—and that some could have fewer regulatory requirements than others. The suggestions for treatment of the particular categories are separately addressed.
Many commenters argued that SBRs and SBSs are functionally no different than handguns. The same commenters noted that a criminal could easily make an SBR or SBS by cutting down a long gun, and stated that SBRs and SBSs should be treated the same as handguns. Several commenters argued that SBRs and SBSs are less accurate than handguns. These commenters asked how SBRs and SBSs are more deadly or more dangerous than AR–15-style pistols and other handguns that are more readily concealable.
A few commenters stated that ATF should deregulate SBRs and SBSs and remove them from the NFA. These commenters suggested that ATF allow FFLs to sell SBRs and SBSs in over-the-counter transactions, in the same manner as GCA long guns (rifles and shotguns). A few commenters stated that there is no reason to regulate SBRs and SBSs when these items are not normally used in crimes. A few other commenters stated that continuing to regulate these items will have no impact on crime.
Many commenters also believed that AOWs do not warrant NFA classification, and should also be handled under GCA transfer standards. These commenters noted that AOWs generally pique the interest of collectors—not criminals—and are therefore owned by law-abiding citizens for lawful purposes. Another commenter suggested that ATF increase taxes on machineguns, and remove SBRs and SBSs from NFA regulations. Another commenter suggested that ATF direct its investigative energies toward AOW and machinegun applications, and apply lesser treatment for SBRs and silencers (
As noted, only Congress can bring a weapon under the purview of the NFA, and only Congress can repeal or remove a weapon from the purview of the NFA. All of the weapons referenced in these comments (SBSs, SBRs, silencers, AOWs, and machineguns) have been designated NFA weapons since the statute was enacted in 1934. With the exception of the reduced transfer tax on AOWs, no statutory provision in the NFA specifically provides for differing treatment of NFA firearms. While ATF has the authority to remove some firearms from the purview of the NFA due to certain factors that make them primarily a collector's item and not likely to be used as a weapon, ATF does not have the authority to change the definition of “firearm” under 26 U.S.C. 5845(a). To the extent that commenters would like the agency to take a more flexible approach to regulating NFA firearms, for example, by reducing or eliminating background checks, the Department takes the position that uniform measures best fulfill the NFA's statutory purposes and benefit public safety.
The Department received a number of comments concerning silencers (commonly known as “suppressors,”
The NFA defines silencers as firearms. 26 U.S.C. 5845(a)(7). The NFA defines the word “silencer” by reference to section 921 of title 18,
As noted, only Congress can remove a class of weapons from the purview of the NFA. ATF does not have the authority to remove silencers from the NFA and does not believe it would be prudent to make different types of firearms subject to different background check requirements. The NFA provides very limited authority to permit exemptions from the transfer tax, and
A commenter suggested that ATF amend all forms associated with NFA transactions to add warnings indicating that any individual or any member of a legal entity that permits a prohibited person access to any NFA item has committed a criminal act. The added language should also state that for a legal entity, the criminal responsibility for permitting such access rests with the legal entity and all of its individual members. The commenter further asserted that legal entities are not widely used by prohibited persons to acquire or possess NFA items because the NFA forms submitted to ATF identify all members of the legal entity involved in the transfer, and a prohibited person would likely fear being identified from the form and prosecuted. The commenter asserted that no evidence exists that ATF actually uses these names to identify, investigate, and prosecute criminal acts, and he suggested that ATF should do more to develop efforts to identify, investigate, and prosecute possession of NFA items by prohibited persons. If ATF were to institute such efforts, ATF could establish an information baseline to show the extent of any illegal practices, which could support any necessary regulatory or legislative changes.
The Department believes that current NFA transfer forms (ATF Forms 1, 4, and 5) adequately convey information about the penalties for unlawful possession of an NFA weapon. With respect to the assertion that legal entities are not widely used by prohibited persons to circumvent background checks, the absence of background checks for transfers involving trusts or legal entities renders it extremely difficult to assess how often prohibited persons have obtained NFA firearms through such transfers. Finally, ATF enforces the criminal laws within its jurisdiction, and if it becomes aware of any firearm—including NFA firearms—in the possession of persons prohibited from having it, it will take appropriate actions.
A few commenters requested that ATF reopen the NFRTR to permit the legal ownership of machineguns manufactured after 1986 (post-1986 machineguns). A few other commenters suggested revising the requirements by simply eliminating the “cut off” date in the NFA to allow for newly manufactured NFA weapons (
A commenter stated that ATF needs to rewrite the proposed rule to comply with the Plain Language Act of 2010. Another commenter suggested that, prior to drafting regulations, ATF should start a dialogue to enable “sound and rational” regulations to promote safety without the “animosity and conflict” that has divided the country on so many issues. Another commenter expressed his willingness to work with ATF to conduct geographic information system research to help devise a common sense approach to crime reduction. One commenter suggested that ATF delay the final rule's effective date to allow ATF to process its backlog of NFA applications.
A few commenters asked general questions and for additional information about other terms used in the proposed rule. For example, a commenter requested that ATF define the term “make” and asked if the proposed rule applied to all firearms or only to fully automatic weapons. Another commenter stated that the term “certain other firearms” was so vague that most semi-auto cartridge firing mechanisms would be considered illegal. Another commenter asked about a “destructive device.” This commenter asked what “constitutes” a destructive device, and for guidance to ensure that this term is not open-ended.
ATF does not have the authority to remove the general prohibition on the transfer and possession of machineguns that were not lawfully possessed on May 19, 1986. This is a statutory prohibition and therefore only Congress has the authority to remove this prohibition. 18 U.S.C. 922(o). Further, the statute requires that any machinegun be lawfully possessed by May 19, 1986. ATF does not have the authority to permit nongovernmental entities the ability to possess machineguns or other NFA firearms that are not lawfully registered in the NFRTR.
With respect to commenters who believe that the Department should engage in additional dialogue or gather more data before issuing this rule, the Department disagrees. The Department has complied with the notice and comment procedures in the Administrative Procedure Act, other requirements imposed by statute, and relevant procedures required by the President for the promulgation of rules. The Department invited public comment to improve and refine the proposed rule and it has used public comments to do so. But the Department is not persuaded that further delay in promulgating the rule is likely to improve it or is otherwise in the public interest.
The Department does not agree with the comment asserting that the final rule's effective date should be delayed until the backlog of NFA applications has been cleared. ATF's capacity to process NFA applications during a given timeframe is limited by resource constraints; absent a dramatic reduction in the number of applications ATF receives, it will likely continue to have some number of applications that await processing (
The terms in the proposed rule about which the commenters sought clarification, such as “make” and “destructive device,” are defined by the NFA and in its supporting regulations. The definitions may be found in 26 U.S.C. 5845 and 27 CFR 479.11.
Several commenters stated that ATF's access to NICS and other databases provides a more accurate background check than a CLEO certification. These commenters stated the CLEO signoff is “worthless,” as the CLEO's signing or refusing to sign is in most cases based on the CLEO's personal political preferences; the CLEO signature has potential for abuse with the signature given for political support or other compensation; and that even on the limited occasions CLEOs perform background checks, they use NICS or the State equivalent for this type of check. Many commenters, noting that the CLEO certification requirement predated NICS, asserted that the CLEO certification no longer serves its original purpose. One commenter described the certification as “antiquated and a gross waste of resources.” Another described it as “outdated, redundant, and superfluous,” and urged ATF to eliminate it under the guidance provided in Executive Order 13610 of May 10, 2012, “Identifying and Reducing Regulatory Burdens.”
Several other commenters noted that ATF acknowledged in the proposed rule that even without CLEO certification, ATF already has a “fuller picture of any individual than was possible in 1934.” Many commenters also generally noted that technological and societal changes have made it less likely that a CLEO is the best source for information indicating an individual may be prohibited from firearm possession. One commenter observed that many applicants never previously interacted with their local CLEOs, and, consequently, CLEOs do not serve the function they once did to assess the character or potential of an individual to misuse an NFA item. Many commenters agreed with this assessment as they personally never had any interactions with their local CLEOs.
Many commenters asserted that the sign-off creates an insurmountable challenge and an unreasonable burden on applicants and CLEOs. Hundreds of commenters agreed that the consequence of retaining CLEO certifications for individuals and extending this requirement to responsible persons associated with legal entities would result in a
Several commenters raised privacy concerns with the CLEO certification requirement, and asserted it should be completely eliminated in the interest of protecting personal tax information. These commenters considered the $5 or $200 tax paid to manufacture or transfer a NFA firearm or device to be “protected” or “confidential” tax information, and stated that the mere application before paying the tax should not be reported to or involve any local CLEO or other government official. Another commenter questioned why his private tax information must be subject to law enforcement inspection and approval. This commenter worried that his personal, nonpublic information might become public record if the local law enforcement agency received a Freedom of Information Act request. The commenter stated that ATF has a “well structured system for protecting [his] applications;” however, he did not know of any Federal or State guidelines applicable to local law enforcement protecting his personal tax information. A few other commenters also raised concerns with some CLEOs retaining copies of the forms they sign. These commenters stated that they cannot object to such retention or they would never receive signoff from the CLEOs. A few commenters believed that sharing Federal tax information involuntarily with local agencies was against the law. Another commenter expressed concern that his personal privacy was also invaded by permitting local government officials to know what firearms are in his home.
In addition, several commenters asked general questions about why CLEO certification was needed at all or why CLEO certifications are not required on all firearm transfers. Another commenter noted that there is no CLEO certification requirement for SOT-licensed manufacturers of NFA items to obtain their licenses, and such manufacturers merely need to send an “intent letter” informing local police agencies of their intent to manufacture NFA items in their local areas. This commenter asked how ATF determines SOT manufacturers are “trusted” persons with no CLEO certification. Further, this commenter opined that manufacturers of NFA items “pose greater risk” and should have “considerably more scrutiny” than an individual or legal entity desiring to possess a few items.
The Department acknowledges that some trusts and legal entities would be unable to obtain a CLEO certification, for reasons other than a responsible person being prohibited or local ordinances prohibiting such firearms, which would result in those trusts and legal entities being unable to obtain an NFA firearm. As the proposed rule was not intended to deny those trusts and legal entities the opportunity to acquire such firearms where permitted by law, the Department has changed the CLEO certification to a CLEO notification. Additionally, the Department believes that with the shift to CLEO notification, there will be cost and time-saving benefits for all applicants, including those who find the current CLEO certification process daunting.
The Department disagrees with the concern that providing the application to make or transfer NFA items to local law enforcement as part of CLEO notification is an unlawful release of tax information. Since the application has not been received by ATF at the time of CLEO notification, it does not constitute “return information.”
The Department does not agree with commenters that ATF does not have the authority to formulate regulations enforcing the provisions of the NFA. Congress expressly delegated authority to the Attorney General in section 5812 and 5822, among other sections. Congress provided the Attorney General with the authority to require certain identification procedures for transferors and transferees.
Finally, the Department has the authority to require CLEO notification for the same reason that it has the authority to require CLEO certification. Sections 5812 and 5822 give the Department broad authority to promulgate regulations governing application forms, including regulations pertaining to the identification of a firearm and its maker or, in the case of a transfer, its transferee and transferor.
Many commenters stated that the proposed extension of the CLEO certification requirement exceeds ATF's statutory authority. A few commenters noted that ATF cites to 26 U.S.C. 5812 and 5822 of the NFA as the statutory authority for the proposed rule, but disputed that these statutory provisions provided ATF with authority to impose a CLEO certification requirement on individuals, much less a responsible person of a legal entity. These commenters argued that section 5812 authorizes ATF to prescribe the form of NFA applications with the limited purpose of identifying the transferor, transferee and firearm, and that seeking opinions from local CLEOs goes beyond establishing the actual identity of the applicant.
One commenter asserted that the Attorney General cannot delegate the duties of the office to a CLEO—a non-Federal agency—as a CLEO's arbitrary or capricious actions, or failure to act, are not subject to review under the Administrative Procedure Act (5 U.S.C. 551–559). Other commenters stated that ATF cannot delegate this authority arbitrarily to itself or to a third party without authorization from Congress and that requiring CLEO certification gives “absolute and unchecked discretion” to local CLEOs. Another commenter stated that no provision in the NFA provides ATF the authority to refuse to issue a “stamped application form” when the applicant can be identified by a method other than CLEO certification. This commenter stated that section 5812(a)(3) only requires that an individual be identified by fingerprints and photographs, not by CLEO certification. All these commenters contended that the local CLEO certification should be eliminated not expanded.
Although the Department does not agree with the assertions that ATF lacks statutory authority to require CLEO certifications, for other reasons described herein at section IV.C.1.a–d, the Department has removed the CLEO certification requirement from the final rule. Since removal of the CLEO certification requirement is the ultimate result advocated by these commenters, in-depth discussion of their assertions is not necessary to the final rule.
In addressing the comments, it must be noted that Congress provided the Attorney General with the authority to require certain identification procedures for transferors and transferees.
Under the proposed regulation, ATF would not have delegated the application process to the CLEO. ATF merely proposed to extend to the responsible persons of trusts and legal entities the CLEO certification requirement, which was the same process that had been in place for many years with individuals. A certification was just one step involved in the process of determining if an application could be approved. These issues are moot, however, as ATF will adopt a CLEO notification process instead.
Numerous commenters, including trade associations and individuals, discussed the reasons some CLEOs refused to approve NFA applications. These commenters disputed ATF's statement in the proposed rule that liability concerns are a primary reason some CLEOs refuse to approve NFA applications. A commenter stated that ATF was wrong to rely on this “false premise,” and requested that ATF perform a “systematic study and survey of CLEOs to develop a solution to the actual problem at hand rather than disrupt established procedures for entities developed over the past 80 years.” Many commenters stated that CLEOs often refuse to sign based on personal or political concerns, not civil liability concerns. Some of the stated political reasons include that the transferee did not donate to their political campaigns; general political liability—as opposed to civil liability— concerns; and the CLEO's personal disagreement with the policy choices of the CLEO's States and Congress to permit private ownership of NFA firearms. Another commenter stated that there are jurisdictions where CLEOs collectively refuse to sign, exercising their “personal fiat.” Many commenters related personal experiences purporting to show that CLEOs in certain regions and jurisdictions refuse to sign due to political party affiliation and ideological beliefs. Several commenters urged ATF to place time limits within which CLEOs would be required to act on certifications requests; if the CLEO failed to act on the certification request within the time limit, ATF would be required to proceed as if the certification had been approved. Many commenters referenced newspaper articles and other sources that provide quoted statements from local CLEOs regarding their reasons for refusal and their publicly announced policies to no longer consider applications for silencers, short-barreled shotguns, explosives, etc. Another commenter asked if ATF has proposed guidelines that CLEOs must follow to ensure no discrimination. This commenter also asked if ATF will establish a system to prosecute and reprimand CLEOs who refuse to provide certification when there are no issues preventing such certification.
NFATCA's comment noted that in the NPRM ATF had accurately cited a quote from NFATCA's 2009 petition regarding CLEO concerns over liability (“[s]ome CLEOs express a concern of perceived liability; that signing an NFA transfer application will link them to any inappropriate use of the firearm”), but asserted that this point was secondary to its primary concern that the CLEO certification requirement was unlawful. NFATCA further asserted that in focusing on liability, ATF had failed to acknowledge that many CLEOs would not sign NFA certifications for reasons other than liability, such as budgetary concerns and opposition to private ownership of NFA firearms, or firearms in general.
NFATCA, the American Silencer Association (ASA),
The Department acknowledges that there are many reasons why a CLEO may not sign an NFA application. Taking these concerns and other factors into consideration, the Department has removed the CLEO certification requirement from the final rule.
The Department notes, however, that its decision to remove the certification requirement from the final rule does not reflect agreement with assertions, such as those put forward by NFATCA in the comments, that the CLEO certification requirement is unlawful.
The majority of commenters were opposed to the expanded CLEO certification requirement, and many suggested alternatives to this requirement. The most commonly cited alternative was to completely eliminate the requirement for all NFA transfers. Many commenters suggested that instead of CLEO certification, ATF could require notification whereby the individual or the responsible person executing the form in the name of the legal entity must provide the local CLEO with a copy of Form 1, 4, or 5 submitted to ATF, and provide the CLEO a reasonable time for review. If, by the end of that time period, the CLEO has not provided ATF with information showing cause for denial, ATF should consider the application cleared at the CLEO level and proceed with the application. The commenters believed this alternative would meet the statutory requirements of sections 5812 and 5822 of the NFA without allowing CLEOs to arbitrarily deny applications. The time period that commenters considered “reasonable” varied, with suggestions for periods of 7, 15, 30, and 60 business days. A commenter noted that a similar process is already used with Form 7. Several commenters noted that NFATCA had recommended this alternative in its petition (
A few commenters suggested ways to amend §§ 479.63 and 479.85, as well as Forms 1, 4, and 5, to provide for a notification process similar to the one the Department has chosen to adopt. One commenter provided specific language to replace the CLEO certification on Form 1. Another commenter suggested replacing the CLEO certification language on Form 4 with a certified statement—under penalty of perjury or falsification of an official government form—by the individual or the responsible person of the legal entity executing the form. This statement would indicate that such individual or responsible person has “conferred with their attorney and/or the local law enforcement officials and that the individual or the entity and each `responsible person' in the entity are not prohibited by local or state law from owning or possessing the items being transferred to them on the form and that they are not a prohibited `alien' who cannot own or possess the items.”
Many commenters supported eliminating CLEO certification and instead requiring all members of a trust, once the application is returned “approved” from ATF, to undergo a NICS check prior to the transfer of the NFA firearm. One commenter suggested that ATF keep the NICS check requirement for the individual or responsible person completing Form 4473 to obtain the transferred item. This commenter also suggested that ATF keep the current process where only the individual or one of the responsible party(s) of a legal entity complete and sign the transfer form.
Many commenters suggested that if the objective is to prevent restricted persons from owning NFA items, a simpler solution would be to substitute fingerprinting and background checks for the CLEO certification requirement for all NFA transfers. Many other commenters concurred with eliminating CLEO certification and making NFA weapons point-of-sale items as they saw no difference between the background checks performed by ATF's NFA Branch and those performed by FFLs.
A commenter stated that the best alternative is to either keep the status quo—requiring CLEO certification for individual applicants—or eliminate the CLEO certification requirement for trusts while retaining the need for a standard “NFA-style” background check for each individual. Other commenters requested that ATF consider either no change to ATF's stance on trusts and legal entities regarding CLEO certification or remove the CLEO certification requirement for all NFA items. Other commenters urged ATF to eliminate the CLEO certification requirement for all transfers, replacing it with various forms of automated background checks. Another commenter suggested an “equitable solution” would be to have an applicant's local police department provide a “letter of good conduct,” which states that “you are who you say you are and provides a list of any criminal offenses you may have had.” This commenter named a local police department that issued these letters quite regularly.
Many commenters questioned the intention of CLEO certification. If the objective is to verify the applicant's identity (
Many other commenters suggested alternatives under which ATF could require individual applicants and responsible persons to provide various forms of government-issued identification with photographs to verify identity. One commenter suggested revising the application forms to include a page for individuals and all responsible persons of legal entities to attach photograph(s) showing the front and back of a currently valid State-issued identification or driver's license. Another commenter stated that ATF only needs a full name, date of birth,
Another commenter suggested that ATF reform the process to have the $200 tax either be an “excise tax” payable at the point of sale or, with the advances in technology, have the retailer print out a tax stamp at the point of sale. This would enable the purchaser to complete a Form 4473, enable a NICS check to be performed, and enable remittance of the taxes through the retailer.
Although many commenters preferred that the CLEO certification requirement be completely eliminated, they also provided compromise positions if ATF were set on keeping and expanding the CLEO certification requirement. These commenters suggested that ATF make the CLEO certification a “shall issue” and require CLEOs to decide based on legal restrictions and obligations, and sign off on the certification, if the background check is “clean” unless there is a valid reason not to sign (
If ATF were to maintain the certification, a few commenters suggested changing the sequence of CLEO review by requiring ATF to provide the application information to the CLEO only after conducting a review. Many commenters suggested that ATF provide for judicial review of instances where CLEOs would not sign off on the certification; others requested that the CLEO be required to state the reason for the denial and provide “real tangible evidence” and state “specific, objective and legally relevant reasons” for the non-concurrence or denial.
Several commenters suggested that Forms 1, 4, and 5 be revised to provide an area indicating that the local CLEO would not sign off on the form, and in such instances ATF could require more information or perform a more extensive background check. For example, one commenter suggested adding three signature lines on the forms: (1) First line—for the CLEO to sign and state “no disqualifying information;” (2) second line—for the CLEO to sign and state “information indicating disqualification” and for the CLEO to explain the disqualification; and (3) third line—for the applicant to certify “I certify I submitted this to this CLEO (name address) over 30 days ago and received no response.”
Many commenters recommended that ATF broaden the list of officials who could provide certifications, to include local district attorneys, judges, officials in local ATF offices, or a designated official in each State, among others.
Many commenters suggested that individual applicants and responsible persons of legal entities who hold a concealed carry permit or license in the State where they reside—authorizing them to purchase, obtain, or carry weapons—should be exempt from the CLEO certification requirement, as well as the photograph and fingerprint requirements, since State and Federal background checks have already been performed and verified.
One commenter requested that ATF consider not requiring CLEO certification for active and retired law enforcement officers, active and retired military officers, including Guard and Reserve officers, and any government employee with a security clearance, as well as FFLs. Other commenters suggested that the CLEO certification requirement be removed for silencer ownership. Another commenter recommended requiring CLEOs to sign off on forms in States where SBRs, machineguns, and silencers were legal. Another commenter recommended that ATF require differing levels of CLEO certification per NFA item, and that silencers and “any other weapons”should not be subject to CLEO certification.
Another commenter suggested simply that a large red “F” be placed on the driver's license of a convicted felon to ensure that criminals do not obtain or use firearms, and proprietors of gun ranges and sellers of ammunition could easily ascertain who is permitted to do business with them and who is not.
Although the Department does not agree with all of the concerns expressed or suggestions made in the above-summarized comments, it does concur with the conclusion of many commenters that the benefits of CLEO certification do not outweigh the costs of the CLEO certification requirement, and that alternate procedures will satisfy the statutory requirements of section 5812 and 5822. Consequently, as previously noted, the Department has removed the CLEO certification requirement from the final rule. As an alternative to certification, the final rule adopts a CLEO notification requirement that is similar to that suggested by many commenters. In conjunction with the mandatory background check required of all applicants, including responsible persons of trusts and legal entities, the requirement of CLEO notice fulfills the primary objectives that have supported the certification requirement: It provides the CLEO awareness that a resident of the CLEO's jurisdiction has applied to make or obtain an NFA weapon and affords the CLEO an opportunity to provide input to the ATF of any information that may not be available during a Federal background check indicating the applicant is prohibited from possessing firearms. As noted in the NPRM, although the NICS provides access to a substantial number of records to verify if an individual is prohibited from possessing firearms, CLEOs often have access to records or information that has not been made available to NICS. Providing notice to the CLEO of a prospective NFA transfer with instructions on how to relay relevant information to ATF will help fill possible information gaps in NICS by affording the CLEO a reasonable opportunity to provide relevant information to ATF.
To effectuate the CLEO notice requirement, the Department is revising the regulations in §§ 479.63 and 479.85 to require the applicant or transferee, and all responsible persons, to provide a notice to the appropriate State or local official that an application is being submitted to ATF, and conforming changes will be made to ATF Forms 1, 4, and 5. In addition, responsible persons for trusts or legal entities will be required to provide CLEO notification on ATF Form 5320.23,
Consistent with the recommendation of many commenters, the changes to Forms 1, 4, and 5 will also include a certification requirement by the applicant or transferee under penalty of perjury, that the applicant or transferee has provided notification to the CLEO; a corresponding change will be made to Form 5320.23 for certification by responsible persons of trusts and legal entities. Applicants will also be required to provide the name and location of the CLEO to whom the form was sent, and date the form was sent. Removal of the CLEO certification requirement also means that CLEOs will no longer need to attest to the authenticity of the applicant's or transferee's photographs and fingerprints. To ensure verification of identity, however, the official taking the applicant/transferee's fingerprints must sign the fingerprint card to certify the official has verified identity of the applicant/transferee. In reaching the decision to substitute CLEO notification for certification, the Department
The Department recognizes comments received suggesting that the Department (1) require that CLEOs certify forms, (2) require that CLEOs provide reason for not certifying forms, (3) make judicial review available when a CLEO does not certify a form, and (4) expand the number and types of officials who may provide certifications. As the certification has been replaced with a notification, the suggested changes are no longer a necessary part of the process. Additionally, the Department rejects comments proposing that ATF, rather than the applicant, provide a copy of the application to the CLEO; ATF is prohibited from releasing an individual's tax return information.
The Department rejects the suggestion of collecting the “excise tax” and printing out the tax stamp at the point of sale. The Department believes that allowing nongovernmental entities to issue tax stamps could lead to fraud and abuse.
The Department has not adopted suggestions that the fingerprints and photograph requirement be replaced by State permitting or licensing because such State-issued documents may not meet the biometric fingerprint check requirements of 26 U.S.C. 5812 and because the background check process for each State-issued concealed carry permit or license is different and not all permits or licenses qualify as an exception to a background check. Additionally, it is unclear to what extent the Department has the legal authority to require local and State officials to aid it in implementing Federal firearms regulations.
The Department recognizes comments regarding exempting certain categories of persons and certain types of NFA firearms from CLEO certification. While CLEO certification has been replaced with a CLEO notification, all applicants, including active and retired law enforcement, active and retired military officers, and government employees with security clearances, and all types of NFA firearms, including silencers, will be subject to the notification requirement.
The Department does not adopt the suggestion of special markings on a driver's license for convicted felons. The Department does not have the authority to require this information on State-issued identification documents.
Many commenters stated that the proposed rule exceeds ATF's statutory authority to require photographs or fingerprints of responsible persons. One of these commenters, NFATCA, acknowledged that its 2009 petition requested a requirement that responsible persons of legal entities submit photographs and fingerprints, but advised that it has changed its conclusion as to the statutory authority of ATF to impose this requirement, and was withdrawing its 2009 recommendation. A few commenters argued that the provision of the NFA that ATF cited as authority for extending the photograph and fingerprint requirement to responsible persons of legal entities, section 5812, does not support ATF's position because the text of that section extends the photograph and fingerprint requirement only to individuals, and not to legal entities.
The Department does not agree with comments that this rulemaking exceeds its authority by requiring photographs or fingerprints of responsible persons. Information that the Attorney General can seek is not limited to fingerprints and photographs for individuals. The inclusion of individual transfers as a specific category that requires the submission of fingerprints and photographs in 26 U.S.C. 5812 does not equate to a limitation on the authority of ATF to extend that requirement to transfers involving trusts or legal entities.
The Department believes it may require trusts and legal entities to submit identifying information regarding their responsible persons as a component of the identifying information it requires a trust or legal entity to submit prior to obtaining authorization to receive or make an NFA firearm. Sections 5812 and 5822 provide broad authority for the Department to require the identifying information of any applicant to make or transfer an NFA firearm. Section 5812 prohibits the transfer of a firearm “unless . . . the transferee is identified in the application form in such manner as ATF may by regulations prescribe.” Similarly, section 5822 prohibits the making of any firearm unless the maker has “identified himself in the application form in such manner as ATF may prescribe.” The Department views the identities of responsible persons associated with trusts and legal entities as a vital aspect of the identities of those entities themselves. The very purpose of the NFA would be undermined if a criminal could use a trust or legal entity the criminal controls to obtain an NFA firearm without submitting any personally identifying information to the Department.
Many commenters asserted that all NFA applicants, including legal entities, should be required to undergo background checks and submit fingerprints and photographs. Some of these commenters differed, however, as to which individuals associated with a legal entity should be subject to these requirements. Several commenters supported background checks for trustees only. A few commenters asserted that successor trustees and other members of trusts (other than the original trustee) should be excluded. Many commenters stated that beneficiaries do not have actual possession and should also be excluded. Another commenter suggested requiring all responsible persons to submit a background check annually to the “head of the trust” to be maintained on file, and to make that head person responsible for all law enforcement approvals. A few commenters supported background checks on the “main person” in the trust or legal entity. Other commenters supported background checks on a single responsible person only. Several
A few commenters suggested requiring a one-time fingerprinting and background check of responsible persons associated with a trust at the creation of the trust, not on every transfer of regulated items contained in the trust. Another commenter suggested requiring only the executor to provide fingerprints and photographs and undergo a background check one time, and that this process be repeated whenever the executor dies or forfeits the executor's position to the next person appointed as executor or owner of the corporation. Another commenter suggested only requiring fingerprints and photographs from trustees once, or perhaps once every ten years upon a new NFA item form. This commenter urged that ATF also adopt the “once every ten years rule” for individuals, too.
In addition to recommendations specific to trusts and legal entities, several commenters suggested that ATF devise alternative methods to identify individuals. Some commenters recommended the use of digital technology to submit photographs and fingerprints, citing as examples other Federal agencies such as the Securities and Exchange Commission (which uses a digital fingerprinting service) and the Transportation Security Agency (which uses a digital service to perform background checks on its employees).
The Department agrees with comments that beneficiaries should not generally be included in the definition of responsible person and has removed beneficiaries from the definition in the final rule. The Department does not agree with comments that background checks should only be conducted on the “main person” in the trust or legal entity, a single responsible person for the trust or legal entity, or only the person picking up the firearm. These recommendations fail to account for multiple individuals within a trust or legal entity that will exercise control over NFA firearms. The “responsible person” definition in the final rule accounts for such individuals, and requires them to meet the same requirements that apply to all other individuals who apply to make or possess an NFA firearm.
The Department concludes that proposals involving one-time or periodic background checks and submission of fingerprints and photographs—for example at the creation of a trust or legal entity or only once every ten years—do not meet the NFA's requirement that each NFA transaction must be accompanied by an individual application and registration.
Many commenters stated that the proposed rule ignored or misunderstood the common circumstances surrounding the creation of an NFA trust, and did not account for the “myriad of innocuous and legitimate” reasons why a trust would own an NFA item, for example to pass the NFA item to one's heirs. Several commenters stated that the proposed rule, by naming a beneficiary as a “responsible person,” deprived individuals from common estate planning techniques (
Many commenters stated that trust use is on the increase as many people live in areas where the CLEO simply will not sign an NFA certification, causing law-abiding citizens to use trusts and corporations to bypass the CLEO certification requirement in order to lawfully make or obtain an NFA weapon. One of these commenters added, “[t]he simple truth is, corporations and trusts are formed NOT to circumvent background checks, but to take power away from an antiquated unfair system of CLEO signoff.”
Many commenters stated that a trust's main purpose is to hold assets, property, and expensive collector investments for inheritance, and as such is a critical estate planning and management tool. Other commenters stated that trusts are being used to lawfully permit multiple people and families to share access to, and use, legally owned and registered NFA items. These commenters noted that without a trust, only the person who directly purchased the NFA item can lawfully possess it. Another commenter asserted that absent ownership by a trust the NFA item must always be in the registered individual's possession when it is out of the safe. Several commenters noted that the NFA makes it unlawful for any person “to possess a firearm that is not registered to him in the National Firearms Registration and Transfer Record.” 26 U.S.C. 5861(d). Hence, if the item is registered only to an individual, and not a trust or legal entity, then family members of the registrant who possess or use the NFA item are exposing themselves to serious criminal charges.
Many commenters stated that a trust eases the burden of transferring NFA items upon the death of the grantor/settlor. Other commenters stated that a trust prevents the need to pay a $200 transfer tax, amounting to a “double tax,” and file another Form 4 to transfer and retain the property, should one of the family members die before the other family member. Other commenters stated that trusts are used to ensure that remaining family members could not be prosecuted for being in possession of an illegal firearm upon death of the person who obtained the NFA tax stamp. Several other commenters stated that another benefit to a trust is that a settlor can list the settlor's children as beneficiaries, and after the settlor's death, a trustee will continue to oversee the items until the children are of legal age to possess the items. Many commenters also stated that these beneficiaries should not have to submit to their civil liberties being violated simply because they inherited private property.
Two commenters stated that most (NFA) trusts are being used to lawfully obtain silencers. These commenters stated that if ATF really desired to reduce the use of trusts, it should remove silencers from the NFA “list.” Several commenters noted that trusts are established in a variety of contexts (
A commenter noted that the Seventh Circuit Court of Appeals held that a trust is a proper legal entity for holding a firearm where the settlor was prohibited, provided that the trust included proper safeguards to ensure that a prohibited person did not possess the firearm.
Another commenter stated that, if necessary, ATF could add additional language to the transferee's certification, similar to that already found in Forms 1, 4, and 5, to ensure that the responsible person understands that it is unlawful to make the firearms available to prohibited persons, and could add a definition of “prohibited person” consistent with 18 U.S.C. 922(g) in the “Definitions” section of the application. This commenter proposed specific language for this purpose.
The Department is aware of the legitimate reasons individuals may choose to utilize a trust or legal entity to acquire an NFA item. These include facilitating the transfer of an NFA item to a decedent's heirs and providing a mechanism that allows several individuals to lawfully possess the same NFA item. To the extent that courts have recognized a felon's ability to employ a trust or other device to maintain an ownership interest, so long as there is no ability to physically possess or control the firearm, trusts have been employed. The Department also recognizes that some trusts created to hold NFA assets contain provisions seeking to ensure that Federal, State, and local laws regarding possession and transfer of NFA firearms are not violated.
The final rule that the Department is promulgating is not designed or intended to reduce the use of trusts for estate planning or other lawful purposes. Instead, provisions of the final rule are intended to facilitate the ability of trusts and legal entities to comply with the statutory requirements of the NFA through the establishment of tailored mechanisms that help ensure prohibited persons are not able to misuse such entities to illegally obtain NFA firearms. The final rule accomplishes this objective by defining as responsible persons those individuals associated with a trust or legal entity who are able to control firearms, and requiring those individuals to undergo the background checks and submit fingerprints and photographs required by statute and ATF's regulations.
With respect to the concerns voiced by many commenters regarding the impact a new rule may have on estate planning, the provisions of the final rule do not materially alter long-existing procedures ATF has established to facilitate the registration of NFA firearms to legal heirs. Those procedures take into account that a decedent's registered NFA firearm(s) must be managed by the executor or administrator of the estate, and provide for a reasonable amount of time to arrange for the transfer of the firearms to the lawful heir. They further provide that a decedent's registered NFA firearm(s) may be conveyed tax-exempt to lawful heirs as an “involuntary transfer” resulting from the death of the registrant.
In promulgating the final rule, the Department has also evaluated the assertions by several commenters that:
• New Federal regulations are not necessary because many trusts designed to hold NFA assets contain voluntary, self-imposed, provisions designed to preclude prohibited persons from acquiring NFA weapons through the trust
• ATF should set requirements mandating provisions in trust agreements for trusts that acquire NFA weapons
Finally, the Department does not agree with commenters' assertions that additional language needs to be added to the certification in ATF Forms 1, 4, and 5 regarding firearm possession by prohibited persons. The instructions on these Forms already include specific information on who is considered a prohibited person.
A commenter desired more information and clarification concerning the number of legal entities that file Form 1, 4, and 5 applications. This commenter stated that the NFATCA petition—as described by the NPRM, section II. Petition—contends that the number of applications to acquire NFA firearms via a legal entity has increased significantly. This commenter noted that this same section of the NPRM also provided ATF research data showing that the number of Form 1, 4, and 5 applications submitted to ATF by legal entities that are not FFLs have increased from “approximately 840 in 2000 to 12,000 in 2009 and to 40,700 in 2012.” This commenter could not determine ATF's statistical methodologies, as they were “neither stated nor explained” in the NPRM, and ATF's analyses did not seem to allow for the same legal entity filing multiple Form 1, 4, and 5 applications during the reporting periods CY 2000, CY 2009, and CY 2012. The commenter contended that it was not uncommon for a legal entity (or an individual) to file multiple Form 1, 4, and 5 applications during a single calendar year. In addition, this commenter noted that ATF did not provide corresponding data to show how many non-legal entities or natural persons submitted to ATF Form 1, 4, and 5 applications during the same reporting periods (
(1) What are the actual number of separate and distinct Legal Entities that submitted ATF Form 1, 4, and 5 applications during these same reporting periods, including CY 2000, CY 2009, and CY 2012?
(2) What are the actual number of separate and distinct non-Legal Entities or natural
(3) What is the increase (or decrease) in the actual number of separate and distinct Legal Entities that submitted ATF Form 1, 4, and 5 applications during these same reporting periods, including CY 2000, CY 2009, and CY 2012?
(4) What is the increase (or decrease) in the actual number of separate and distinct non-Legal Entities or natural persons that submitted ATF Form 1, 4, and 5 applications during these same reporting periods, including CY 2000, CY 2009, and CY 2012?
(5) How does the increase (or decrease) in the actual number of separate and distinct Legal Entities that submitted ATF Form 1, 4, and 5 applications compare with the increase (or decrease) in the actual number of separate and distinct non-Legal Entities or natural persons that submitted ATF Form 1, 4, and 5 applications during these same reporting periods, including CY 2000, CY 2009, and CY 2012?
Another commenter stated that there was an “unexplained discrepancy” between the numbers that ATF used in Table A of the NPRM for the number of applications for legal entities received in 2012 and the numbers ATF used in its “Firearms Commerce in the United States Annual Statistical Update 2013” (ATF's 2013 Statistical Update), available at
The Department has carefully considered all commenters' concerns relating to the number of legal entities that file Form 1, 4, and 5 applications. For purposes of the NPRM, ATF conducted an analysis of all applications actually received in the NFA Branch in CY 2012.
The total number of transfers to trusts, corporations, governmental entities, and individuals cited in the NPRM were taken from the total number of all applications received. When an application is received in the NFA Branch it is counted one time. Additionally, each application covers the transfer of a separate firearm with a separate and unique serial number. Thus, the transfer or making of an NFA firearm is counted each and every time an application is submitted. There is no system in place that counts the number of applications received at different times from the same applicant. However, such a system would have been irrelevant for purposes of the NPRM. The key fact is the number of transfers made by legal entities without a background check. The fact that legal entities may have made more than one transfer does not lessen the concern. Also, for purposes of the final rule, new numbers for CY 2014 have been compiled. Those new numbers will cover only those applications that have been processed with a final determination, as opposed to all applications received regardless of a final determination.
The Department did not prepare an analytical impact statement concerning non-legal entities as the definition of “Person” in section 479.11 does not use the term. Applicants who submit Forms 1, 4, and 5 are identified as trusts, legal entities, governmental entities, FFLs and individuals. Further, as some commenters noted, the NPRM did not reflect any increase or decrease in the number of individuals (natural persons), government entities, or FFLs who submitted Form 1, 4, or 5 applications for CY 2000 or 2009 because the NPRM in part was a response to inquiries on legal entities as identified in the petition from NFATCA. The NPRM in Table A does reflect a breakdown of the type of forms received by corresponding categories in order to compare the costs to those applicants who are currently required to submit fingerprints, photographs, and CLEO certifications with the costs reflected in the final rule that will require each responsible persons of a trust or legal entity to submit the same personal information to ATF before a trust or legal entity is allowed to make or have transferred to it an NFA firearm.
Some comments noted a possible discrepancy between ATF's 2013 Statistical Update and Table A of the 2012 NPRM. The difference appears to be attributable to the fact that the NPRM counted the number of applications received in CY 2012, whereas the Statistical Update counted the number of firearms processed in CY 2012. ATF processed fewer Forms 1 and 4 than it received in CY 2012, which is why there are fewer firearms processed than applications received in those categories. The 170,561 number used in relation to Form 5 in ATF's 2013 Statistical Update reflects the total number of firearms processed on Form 5 applications for CY 2012 from all applicants to make or transfer firearms,
Several commenters stated that ATF's “one-size-fits-all solution” failed to consider that trusts and legal entities vary widely and differ in purposes and structure. These commenters asserted that ATF should engage in a proactive assessment of each trust and legal entity, first reviewing the
Another commenter recommended excluding specific trust roles from the “responsible person” definition, including successor trustees, beneficiaries, and contingent beneficiaries and that successor trustees should be expressly excluded until they become a trustee. Another commenter described the types of individuals who are generally trust beneficiaries (
Some commenters recommended exemptions or clarifications for trust members and executors. For instance, a commenter suggested exempting members of the trust that are related by lawful marriage and adoption, and through the commonplace definitions of family. Another commenter suggested that if ATF removes the option for a trust that ATF “amend the classification of individual to include immediate family” as he would “love to pass down [his] NFA items to [his] children.” Another commenter suggested clarifying wording to allow the executor or an estate temporary possession and that would not be considered a transfer, which according to the commenter is much needed for those with trusts.
Another commenter suggested requiring that trust members include their Social Security numbers when submitting a Form 1 or Form 4. In addition, when a new member is added to a trust, the trust must include that new member's Social Security number when a new Form 1 or Form 4 is submitted.
Another commenter believes that only the main person in the trust should be held responsible for the others named in the trust. This same commenter also supported doing a background check on the main person in the trust when the trust is formed but was against having to recheck background checks every single time they get an NFA item. Another commenter suggested only requiring photographs and fingerprints for the settlor/grantor of the trust. This commenter stated that the settlor/grantor is the person who completes the Form 4473, undergoes the background check at the time of transfer, and is ultimately responsible for how the trust items are disposed of and used.
A few commenters suggested other alternative processes for legal entities. A commenter suggested that ATF automate Form 1 and Form 4 transactions to tie them into the Form 4473 background check process, and that all listed trustees or legal entities be included in this process. Another commenter suggested that if the issue is with trusts and having all trust members submit their information to ATF, that ATF create a new FFL classification and follow the “well established and functioning process” of the FFL system. Another commenter suggested that ATF could achieve its goals through establishing an NFA equivalent of U.S. Customs and Border Protection's Global Entry System. Such a system would enable ATF to perform a “single extensive” background check on each trust member and would simplify background checks for future trust purchases.
Another commenter suggested that ATF allow corporations or trusts to file the necessary information separately, and not be included in the Form 1 or Form 4 submission. The legal entity could then electronically file (e-file) the tax stamp request. Another commenter suggested that, for any NFA item that a trust or legal entity purchases, the transaction include either a NICS check or the presentation of a State-issued carry permit to complete a Form 4473.
Another commenter recommended that for trust applications, ATF accept the Affidavit of Trust instead of requiring the full trust document be submitted. This commenter contended that the full trust document is not relevant for firearm approval, and would lessen the paperwork for the applicant and improve the processing times and reduce the burden for ATF. Another commenter asked that ATF consider requiring members of trusts to be issued a license similar to the process for a concealed carry weapon license.
Another commenter suggested that ATF permit trusts, partnerships, and other corporate entities to transfer any NFA items to an individual on a tax-free basis for a one year period.
The Department is aware that there are differences in purpose and structure among various trusts and legal entities; these differences, however, do not provide an appropriate basis to apply different standards when applying the provisions of the NFA.
The Department rejects the suggestion that it review the documentation establishing each trust or legal entity and determine whether the creators and operators of that trust or legal entity took appropriate safeguards to prevent prohibited persons from using the trust or legal entity to acquire NFA firearms. The Department believes that it is more efficient and effective to ensure, at a minimum, that all trusts and legal entities do not have any responsible persons who are prohibited from possessing NFA firearms. The Department believes that it is the responsibility of those trusts and legal entities to take all other appropriate measures to ensure that they comply with State and Federal law. Additionally, requiring that the Department determine whether trusts and legal entities had sufficient safeguards in place to prevent NFA firearms from coming into the possession of prohibited persons would be costly and time consuming.
The Department does not agree with the suggestion that it should require only the acting trustee to submit fingerprints and photographs and receive a CLEO signature. Depending on the terms of the trust, additional people beyond the acting trustee may have the power and authority, directly or indirectly, to direct the management and policies of the entity insofar as they pertain to firearms.
The Department also does not agree with performing the background check at the time of the NFA transfer, as this would necessarily take place after the application is approved. Such a process is not consistent with the statutory requirements of section 5812(a) (providing that applications shall be denied if the transfer, receipt, or possession of the firearm would place the transferee in violation of the law) and section 5822 (providing that applications shall be denied if the making or possession of the firearm would place the person making the firearm in violation of law). Prior to approving the application, ATF must verify that the person is not prohibited from making, receiving, or possessing the firearm. This cannot be accomplished by having the FFL conduct the background check at the time of the transfer. See section IV.C.4 for responses relating to the definition of “responsible persons.”
The Department rejects the suggestion that it exempt family members from the definition of “responsible persons” as these are the individuals most likely to be named as grantors, trustees, or
The Department has chosen not to require Social Security numbers on the Form 5320.23 for responsible persons, nor on Forms 1, 4, and 5. The Department believes such information is not necessary to be included on these forms because the information is already requested on the FBI Form FD–258 (fingerprint card) used for conducting the necessary background checks.
The Department rejects the suggestion that it only require the Affidavit of Trust to verify that an applicant is a genuine trust. That document does not contain all the information necessary to verify that it is a valid trust and may not contain all the information necessary to verify who is a responsible person for the trust.
Regarding alternate means of conducting background checks, the Department believes that using NICS in conjunction with a fingerprint-based background check provides the best option. The NICS has access to several Federal databases that contain information relevant to determining whether a person is prohibited from possessing a firearm, and since its inception has identified over two million prohibited persons attempting to purchase firearms and denied transfers to those individuals. Additionally, the fingerprint-based background check may identify a disqualifying criminal record under another name.
The transfer tax is fixed by statute,
A few commenters stated that the interpretation of the definition of responsible person could mean that any person who has possession of a firearm could be required to get CLEO certification. The commenters also stated that “nowhere in the law is every member of an organization held accountable for every action of the organization.” A few other commenters stated that every employee of an FFL is not required to be listed as a responsible person on the license, so there is no reason to require everyone associated with a legal entity to be designated as a responsible person. Two other commenters stated that by requiring fingerprints, photographs, and CLEO signature for each responsible person, it increases the burden to both applicants and CLEOs, and could become an administrative nightmare. One of the two commenters also asked, since ATF anticipates a requirement for notification in changes of responsible persons, “[w]ill trustees be aware of such a requirement and practically be able to comply?” Another commenter, an attorney, stated that every corporation has shareholders and that extending the definition of responsible person to include all shareholders defeats the purpose of the corporation and “overrides well developed statutory case law relating to corporate governance and property ownership rights.” The commenter also stated that the proposed rule eliminates the advantages of corporations and their ability to exercise their right to own property. Another commenter asked whether beneficiaries who are under the age of 21 years old, who may live in different States, and who do not have any authority to possess, transport, or acquire NFA firearms, would be required to obtain photographs, fingerprints, and the CLEO signature. Another commenter, a licensed NFA dealer, stated that given the broad definition of responsible person as related to trusts, and the possible criminal consequence of non-compliance, entities have no choice but to err on the side of over-inclusion, which places a burden on both the entity and ATF. The commenter suggested that there might be hundreds or thousands of responsible persons for a single entity, and gave the example of a corporation with headquarters in Maryland with over 4000 employees located in 38 States. A few commenters, including a licensed manufacturer, stated that the definition is too broad and exceeds both what is reasonable and the definition of responsible person currently used for FFLs.
Other commenters noted that the definition for responsible person appears to extend to beneficiaries of a trust holding NFA firearms, and even to successor trustees, remainder beneficiaries, and trust protectors. The commenter noted, however, that in a typical trust document, the trustee is the only person with legal title to any items in such a trust, and that the “beneficial interest” of the beneficiary does not vest until the time specified in the trust.
Another commenter stated that the proposed definition for responsible person exceeds the definition of responsible person used for handling explosives. This commenter asked if ATF intended to extend the CLEO's “veto” to explosives workers. Another commenter stated that the proposed definition was very vague on which “entity” could decide who would be a responsible person. This commenter expressed concern that any government agency could be capable of making that decision. Another commenter recognized the need to define responsible person; however, this commenter expressed concern that if the government alone defined the term that it might allow them more power over which persons could exercise their right to bear arms.
The Department has reviewed the definition in the proposed rule and amended it to address concerns about its breadth while maintaining the important objective of ensuring background checks for relevant parties associated with a trust or legal entity. As in the definition of “responsible person” in the NPRM, the definition of “responsible person” in this final rule applies to those who possess the power or authority to direct the management and policies of an entity insofar as they pertain to firearms. This addresses commenters' concerns that shareholders and others who are associated with an entity are not always in a position to possess the entity's firearms. It should be noted that if an individual has the power or authority to direct the management and policies for a legal entity, that individual would fall within the definition of “responsible person.” Trusts differ from legal entities in that those possessing the trust property—trustees—are also the individuals who possess the power and authority to direct the management and policies of the trust insofar as they pertain to trust property, including firearms.
The Department believes that the definition of “responsible person” in this final rule appropriately addresses concerns that the necessary individuals receive background checks before receiving NFA firearms, and that the potentially large number of individuals who are merely associated with the trust or legal entity, but will not possess firearms, are not required to submit applications. Further, the Department notes that under 18 U.S.C. 922(g), it remains unlawful for a prohibited person to possess firearms. Similarly, under section 922(d) it remains unlawful for any person to sell or deliver a firearm to any prohibited person if that person knows or has reasonable cause to believe the person is prohibited. For responses to comments on CLEO certification see section IV.C.1. As noted previously, ATF Forms 1, 4, and 5 will be updated to reflect the definition of responsible persons in the final rule.
The Department does not agree that including shareholders in the definition of “responsible person” defeats the purpose of a corporation, as a shareholder will only be a responsible person if the shareholder possesses, directly or indirectly, the power or authority to direct the management and policies of the entity insofar as they pertain to firearms.
Many commenters stated in a form letter that the proposed rule interferes with the lawful use of trusts for estate planning. These same commenters stated that the overly broad definition of a responsible person means contemplating the “absurd possibility of fingerprinting, photographing, and securing CLEO sign-offs for unborn children.” Another commenter, who holds a trust, stated that the proposed rule places a hardship on his family and trust by possibly requiring fingerprints of his elderly grandmother and his two-year-old and five-year-old children. Another commenter, a trust holder, asked how the definition of responsible persons applies to minor beneficiaries in a trust, and asked if ATF is proposing the fingerprinting and photographing of minor children who lawfully cannot possess a firearm. Other commenters also asked about the need for CLEO certification, as well as fingerprints and photographs, for children and minors. At least one commenter specifically argued that his CLEO would not provide a certification for beneficiaries. Many commenters questioned the practicality of requiring fingerprints and photographs for minors, and wondered how this would be done, in particular on babies and young children. Many commenters stated that a background check for beneficiaries is more appropriately conducted at the time an item in the NFA trust is actually transferred to them from the trust. Another commenter questioned whether doing a background check on a minor beneficiary would have any benefit, and asked if a background check would show the chances of committing a felony or domestic violence in the future. Another commenter asked if the requirements for photographs, fingerprints, and CLEO certification do not apply to minors, would the minor upon turning 18 need to submit these required items?
As noted, the Department agrees that beneficiaries should not generally be included in the definition of responsible person. The definition of responsible person has been amended and no longer includes beneficiaries as a typical example of a “responsible person.”
Many commenters, most of whom have trusts, and an FFL, noted in a form letter that the Department's definition of responsible persons is different for different types of entities. They stated that based on the Department's general definition of a responsible person, and the complexity of trust laws, they would need to speak to a lawyer to determine who in their trust would be considered a responsible person. Ninety-eight of the same commenters, all of whom have trusts, also stated that their trust includes beneficiaries who are under 18 years old and that they would need to speak to a lawyer to get a clear answer about whether they fall under the responsible person definition.
Other commenters asked various questions concerning companies that own NFA firearms and how they are to determine who counts as responsible persons. A commenter asked if such companies would have to “photograph, fingerprint, and complete a favorable background check” on each individual before accepting that individual as an employee or partner. This commenter also asked if a stockholder would be viewed as having ownership of the corporate assets such that they would need to be fingerprinted. Another commenter stated that the proposed rule left many unanswered questions concerning its definition of a responsible person, including whether and when minor trust beneficiaries would qualify.
The final rule incorporates a new definition of “responsible person” that addresses many of the questions and concerns raised by these comments, including the concerns about trust beneficiaries who are minors. That said, the Department agrees that in some cases persons may need to seek legal counsel to determine who is a responsible person for purposes of this rule. The Department notes, however, that many of the trust applications it currently reviews were prepared with the advice or assistance of a lawyer. As a result, it is not clear whether the overall need for legal counsel will increase or decrease because of this rule. The Department anticipates, for example, that persons who have used a trust in the past to avoid the CLEO certification requirement may well choose to acquire future NFA firearms as individuals once the CLEO certification requirement has been modified to a notification requirement,
Several hundred commenters objected to the proposed requirement that any responsible person of a legal entity prove citizenship as part of submitting an application to transfer or possess NFA items. The bases for this objection varied from an ideological opposition to ever having to prove citizenship to an observation that not all aliens are prohibited from possessing firearms under Federal law. Other commenters approved of the requirement to demonstrate citizenship, even though they were otherwise opposed to the rule.
Under Federal law (18 U.S.C. 922(g)(5)(B)) it is generally unlawful for any alien admitted to the United States under a nonimmigrant visa to ship or transport in interstate or foreign commerce, or possess in or affecting commerce, any firearm or ammunition, or to receive any firearm or ammunition that has been shipped or transported in interstate or foreign commerce. This prohibition extends to NFA firearms. Federal law (18 U.S.C. 922(y)(2)) also provides certain exceptions to this prohibition. As a result, before ATF can approve an NFA registration request it must determine if the applicant or transferee is a U.S. citizen, and if the applicant or transferee is not a citizen, whether the applicant or transferee falls within the prohibition or exceptions described above. This requirement is not unique to NFA transfers. For example, the ATF Form 4473 requires the transferee or buyer to respond to questions to determine if the transferee or buyer is an alien admitted under a nonimmigrant visa, and if so, whether the transferee or buyer qualifies for an exception to the section 922(g)(5)(B) prohibition. On the ATF Form 7 (5310.12),
Many commenters stated that the proposed rule gave rise to many unanswered questions, especially about the operation of the CLEO certification requirement in jurisdictions where CLEOs were reluctant or refused to provide the certification, regardless of the applicant's background. Another commenter asked how the rule would apply when, following the transfer, some or all of the responsible persons are replaced, and whether the answer would be different based upon the type of legal entity involved.
As indicated in section IV.C.1 the Department has replaced the CLEO certification requirement with a CLEO notification requirement. This change renders moot many of the hypothetical questions submitted by commenters, including those that focus on jurisdictions in which obtaining CLEO certification is hindered for “political” reasons.
With respect to issues raised by the prospect of a post-transfer change in responsible parties, this rule does not require that ATF be notified of such changes. In the NPRM, the Department indicated that it was considering a requirement that new responsible persons submit Form 5320.23 within 30 days of a change in responsible persons at a trust or legal entity. After receiving several public comments on this issue, the Department is not requiring in this final rule that new responsible persons submit a Form 5320.23 within 30 days of any change in responsible persons.
A number of commenters took issue with the proposed definition of “responsible person.” Some found it vague and overly broad. Others argued for a more finite definition, with some suggesting specific alternative definitions. Quite a few argued that, depending on the nature of the trust or legal entity, and the roles performed by persons associated with the trust or legal entity, ATF should permit designation of a sole or primary responsible person, thereby minimizing the burden associated with processing the application.
The Department acknowledges that whether an individual meets the definition of a responsible person will depend on the structure of the trust or legal entity acquiring the firearm and who within that structure has the power and authority to direct the management or policy of the trust or legal entity pertaining to firearms. The final rule provides guidance to persons seeking to acquire an NFA firearm for a trust or legal entity about who qualifies as a responsible person under most routine circumstances. For example, under the terms of a trust, if a minor child does not have the power and authority to direct the management and policy of the trust, and is not authorized under any trust instrument, or under State law, to receive, possess, ship, transport, deliver, transfer, or otherwise dispose of a firearm for, or on behalf of, the trust, the minor child would not meet the definition of a responsible person. Additionally, beneficiaries do not appear in the non-exclusive list of possible “responsible persons” in the definition and will not be considered responsible persons unless they meet the definition set out in the final rule.
The Department agrees that trusts and legal entities may have complex structures. However it is the responsibility of each trust, association, partnership, LLC, or corporation to determine which individuals within its structure are responsible persons under this rule. The Department does not agree with comments limiting the responsible person to only one individual per trust or legal entity because multiple individuals may have the power and authority to make decisions for the trust or legal entity, or otherwise meet the definition of “responsible person.” This includes co-trustees, members of the board of directors, or controlling members of an LLC.
The Department has amended the originally proposed definition of “responsible person,”
The Department further believes that it is the duty of individuals having the power or authority to direct the management and policies of the trust or legal entity to ensure that prohibited persons do not have access to firearms.
Several commenters argued that the proposed rule violated or failed to comply with Executive Order 12866, an order which a few of these commenters noted was “revived by” Executive Order 13497. In general, these commenters took issue with ATF's cost-benefit
In addition, a few commenters argued that, in particular, the rule's extension of the CLEO certification requirement violated sections 1(b)(9) and (11) of Executive Order 12866 by failing to adopt the least burdensome effective alternative.
A commenter supported the estimates in the proposed rule, and concluded that the public safety benefits—expanding background checks to legal entities and ensuring fewer firearms would be possessed by prohibited persons—were “massive” and far outweighed any minor monetary or time costs to potential makers or acquirers of NFA firearms.
Another commenter stated that the proposed regulations extending the CLEO certification requirements would increase the processing workload for the NFA Branch by nine times, and that this would further add to the NFA Branch's backlog of one year. The commenter thus concluded that wait times would approach a decade.
The Department believes it has thoroughly considered the costs and benefits of the rule. Commenters have not provided the Department with data or information that would alter or refine the Department's estimates of the rule's costs and benefits. The Department has done its best to consider all relevant costs and benefits traceable to the rule, including, among other things, the benefits to public safety that will stem from the rule; the increased operational cost for the Government and industry members; the increased cost associated with additional fingerprint cards and photographs for responsible persons; and the increased labor cost associated with the time it takes for applicants and industry members to complete the required forms. Having considered all of the reasonably foreseeable costs and benefits, the Department has determined that the benefits of ensuring NFA weapons are less easily obtained by persons prohibited from possessing them outweighs the cost of implementing the rule.
The Department acknowledges the commenters' concerns with the Department's assessment of costs and benefits of the proposed rule in the NPRM. The final rule reflects that after careful consideration of all comments, the Department has elected to eliminate the CLEO certification and replace it with a CLEO notification that will lessen the burden to CLEOs and applicants for registration. See section IV.C.1 for the in-depth discussion of the Department's decision to adopt a CLEO notification requirement in lieu of CLEO certification.
This final rule also identifies important benefits to public safety and security that will be achieved by the rule. For example, by conducting background checks on persons who meet the new definition of a “responsible person,” ATF will be better able to ensure that responsible persons within trusts and legal entities are not prohibited from possessing NFA firearms. Presently, only individuals are required to submit fingerprint cards and undergo background checks to ensure that they are allowed to possess and receive an NFA firearm.
Further, the CLEO notification will ensure that CLEOs are aware of NFA firearm acquisitions in their jurisdictions and have an opportunity to provide input to ATF, but will reduce costs because they will no longer be responsible for signing certifications or conducting background checks for individual applicants. This final rule will require all applicants and responsible persons within trusts and legal entities to notify their local CLEO by either forwarding a completed copy of Form 1, 4, or 5, or a completed copy of Form 5320.23, if applicable. ATF estimates that the time for a CLEO to review the notification is 15 minutes per applicant/responsible person. Because not all responsible persons within a trust or legal entity may live in the same location as the applicant trust or legal entity, a different CLEO may review the ATF Form 1, 4, or 5 from the CLEO that reviews a Form 5320.23 for each responsible person. However, if a CLEO determines that there is any reason why an applicant or transferee should not have an NFA firearm, the CLEO should notify ATF. While there will be additional costs to ATF, the Department has determined that the benefits will significantly outweigh any costs.
The NPRM identified a few instances when a prohibited person nearly erroneously acquired an NFA firearm; however, the transaction did not occur because the responsible person within the particular trust or legal entity had undergone a background check. Those examples show that there is a tangible risk of a prohibited person acquiring an NFA firearm through a trust or legal entity. The Department has not relied on those instances to conclude that there are presently a large number of erroneous transfers. However, the fact that some individuals have been prevented from obtaining firearms supports the Department's position that a risk exists that should be addressed.
The Department stands by its determination that this rule will neither have a significant annual effect on the economy of $100 million or more, nor adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or tribal governments or communities.
The Department recognizes that the final rule will affect processing times and is implementing processes to keep the impact to a minimum.
A commenter quoted text that ATF used in section IV.B of the NPRM (78 FR at 55023), from which the Attorney General concluded that the NRPM did not have sufficient federalism implications to warrant ATF's preparing a federalism summary impact statement, and accordingly complied with section 6 of Executive Order 13132 (Federalism). This commenter noted that ATF acknowledged that the proposed expansion of the CLEO certification requirement to all responsible persons of a legal entity had the potential for increased utilization of State and local agencies' resources for processing CLEO certifications. This commenter questioned ATF's statement that such utilization would be “voluntary” and was “expected to be minimal.” This commenter stated ATF needs to further clarify this “voluntary” utilization, and perform proper cost-benefit analyses to clarify its “claim” of minimal impact, or else abandon its proposal to extend the CLEO certification requirement to responsible persons of a legal entity.
After considering the objections of numerous commenters concerning the extension of the CLEO certification
The Department continues to maintain that the proposed rule did not have sufficient federalism implications to warrant a federalism summary impact statement. The Department noted in the proposed rule that the impact on resources used by State and local agencies would be “voluntary” and was “expected to be minimal.” As many commenters have observed, CLEOs voluntarily decide to sign or not to sign off on any particular application, and would have continued to be able to do so under the proposed rule.
Numerous commenters stated that ATF did not comply with the Regulatory Flexibility Act (RFA), 5 U.S.C. 601–612. According to most of these commenters, there was no indication in the proposed rule that ATF adequately considered the needs of small businesses and the costs that were likely to be associated with the rule, especially the costs imposed on small businesses directly and indirectly associated with the manufacture, distribution, purchase, and use of NFA firearms. Numerous commenters suggested that the proposed rule would dramatically increase the cost of acquiring NFA firearms, especially silencers. They also suggested that the proposed rule would likely force a number of small businesses out of business, resulting in job loss and economic turmoil. Many of these commenters focused on the proposed requirement that CLEO certification be obtained for all acquisitions, regardless of the nature of the trust or legal entity, but some also identified the burden that would be imposed by requiring responsible persons for trusts and legal entities to have background checks run as part of the acquisition process. In addition, many commenters argued that ATF's estimated increased costs to legal entities were too low, as ATF estimated the number of responsible persons as two, a figure commenters regarded as an underestimate. Further, a commenter requested that ATF clarify the research and methodology it used to determine that the proposed rule complied with the RFA and perform further research, analyses, and clarification before implementing the final rule.
A few commenters explained that under the RFA and (as amended by) SBREFA, when “promulgating a rule, an agency must perform an analysis of the impact of the rule on small businesses, or certify, with support, that the regulation will not have a significant economic impact on them.”
Another commenter stated that ATF should clarify the research and methodology it used to determine that the NPRM complied with RFA, and that further research, analyses, and clarification is required regarding the proposed rule's economic impact. Another commenter disagreed with ATF's estimated cost increase per legal entity being only $293.93, and believed this was far too low. The commenter attributed that result to ATF underestimating the average number of responsible persons as two.
The Department believes it has thoroughly considered whether the rule will have a significant impact on small businesses and has reasonably concluded that it will not have such an impact. Commenters have pointed to no flaws in the Department's analysis that would call into question the reasonableness of its conclusion that the rule will minimally impact small businesses. Commenters have identified only two specific issues with the Department's analysis—namely, (1) that the Department underestimated the average number of responsible persons for trusts and legal entities, and (2) that the Department failed to consider potential secondary market impacts on small businesses that sell NFA firearms to trusts and legal entities covered by the rule. As to the first objection, the Department disagrees that its estimate of two responsible persons per entity was unreasonable. As to the second, the Department believes that any secondary market impacts will be negligible. The Department thus rejects the suggestion that it failed to give careful consideration to the full effect the proposed rule would have had on small businesses. In any event, this final rule has been revised to eliminate or ameliorate many of the concerns reflected in the comments about the RFA, and the rule remains fully compliant with that Act.
This final rule primarily affects trusts and legal entities that seek to make or acquire NFA firearms and are not making or acquiring them as qualified FFLs. The Department believes that the increased cost of implementing the regulations will not be significant on trusts or legal entities. ATF has estimated that the cost of implementing the regulation will increase the cost for 115,829 trusts and legal entities with an average of two responsible persons by $25,333,317 (identification costs for background checks: $23,846,679; CLEO notification costs: $1,487,244) per year.
In reaching this estimate the Department was quite specific in the proposed rule in allowing 10 minutes for each responsible person to complete Form 5320.23 and considered this a reasonable amount of time for
By developing Table B(1)—Cost Estimates of the Time to Comply with the Proposed Rule's Requirements and Table B(2)—Cost Estimates of Procuring Photographs, Fingerprints, and Documentation, the Department complied with the requirement that it analyze the impact of the rule on small businesses and documented the anticipated effect of the regulation.
In section IV.A.2 of the proposed rule, ATF reported that “[i]n calendar year (CY) 2012, ATF received 84,435 applications that were either ATF Forms 1, 4, or 5. Of these, 40,700 applications were for unlicensed trusts or legal entities (
The Department disagrees with the comments indicating that the proposed rule would impose substantial recordkeeping obligations and increase the costs to ensure regulatory compliance, thereby resulting in small businesses being driven from the field. This final rule incorporates information required on ATF Form 5330.20 into the existing Forms 1, 4, and 5 that will reduce the burden upon the applicant or transferee by eliminating an additional form to be completed and filed. The current estimated time to complete the form is 3 minutes. Because the information requested on the forms is the same, savings will result from the applicant not having to attach a separate form. Further, these forms are not kept by the FFL and therefore will result in no increase in small business recordkeeping obligations.
Several commenters argued that ATF's RFA statement considered only the NFA purchasers and their estimated additional costs of compliance, but ignored the proposed rule's significant effect on manufacturers and distributors/sellers, and the fact that business' customers would have a difficult time obtaining certification via a CLEO, therefore hurting sales. The Department notes again that it has changed the certification requirement to a notification requirement.
Finally, the Department emphasizes that this rule will primarily affect trusts and legal entities that are seeking to make or acquire NFA firearms and are not making or acquiring them as qualified FFLs. Many commenters have observed that the increased use of trusts during the last decade has been in response to increased CLEO refusals to provide the certification required for individual NFA acquisition applications. If that is true, the Department's revision of that requirement can be expected to dramatically decrease the use of trusts to acquire NFA firearms in the future, meaning that the rule's impact on small businesses may be even less than it estimates. In any event, the increased cost of implementing the rule will not be significant on trusts or legal entities, even if the number of trusts and legal entities remains the same. The Department has estimated that the cost of implementing the regulation will increase the cost for 115,829 entities with an average of 2 responsible persons by $25,333,317 per year (identification costs: $23,846,679; notification costs: $1,487,244).
Although the proposed rule stated that it did not constitute a “major rule” as defined by section 251 of the Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 U.S.C. 804, several commenters disagreed. In addition, while the proposal stated that it would not result in “an annual effect on the economy of $100 million or more; a major increase in costs or prices; or significant adverse effect on . . . employment . . .,” 78 FR at 55024, several commenters disagreed with these assertions as well. One commenter requested that ATF clarify the research and methodology it used to determine that the proposed rule complied with SBREFA.
One commenter asserted that extending the CLEO certification requirement to responsible persons of trusts and legal entities would effectively destroy the market for NFA firearms because “99% of `legal entity' transfers” stemmed from the CLEO's refusal to sign an individual application. According to the commenter, the proposed rule would thus eliminate “approximately $54 million dollars of tax generating commerce,” with a corresponding impact on jobs, with zero value gained in terms of public safety, and, thus would constitute a “major rule” under SBREFA. Other commenters made similar points concerning the proposed rule's impact under the assumption that CLEO certification would be a larger hindrance to conducting commerce in NFA firearms. Several commenters noted that this would also collaterally impact the Federal fiscal budget through a decreased payment of the Special Occupational Tax. Another commenter proposed that the economic impact of the proposed rule would have a “chilling” effect on NFA items' sales (especially lower-cost sound suppressors) due to the cost increase incurred by transferees under the proposed rule.
The Department maintains that it complied with the SBREFA in the proposed rule. Nonetheless, for this final rule, the Department has reassessed burdens and costs to
In preparing this final rule, the Department looked at the additional impact on licensed manufacturers, dealers, legal entities, applicants, and responsible persons and determined that the changes would not exceed a threshold greater than $100 million or more on the economy. The impact on small businesses should remain minimal.
Based upon concerns from commenters that the Department underestimated the number of responsible persons in the NPRM, the Department revisited the definition of “responsible person” and has amended it in this final rule.
As discussed in section IV.C.1, the Department is eliminating the CLEO certification requirement and implementing a CLEO notification requirement; this will lessen the burden to CLEOs. The CLEOs will have the discretion and flexibility to review, manage, and maintain this information in the manner that they believe is most appropriate to the public safety concerns in their respective jurisdictions.
In addressing commenters' concerns that the CLEO extension requirement could force many FFLs out of business, ATF did not assess the indirect costs to FFLs, such as manufacturers or dealers, but concentrated on the direct costs to applicants, responsible persons and CLEOs, who have the greatest investment in the making or transfer process. However, as stated, CLEO notification will diminish, if not eliminate, the economic impact on small businesses, including FFLs, that CLEO certification may have imposed.
A few commenters expressed concerns that the proposed rule did not comply with the Unfunded Mandates Reform Act of 1995 (UMRA), with two commenters identifying certain areas that they contended called for additional study and justification by ATF to ensure compliance with UMRA. One commenter stated that the proposal to extend the CLEO certification requirement shifts a “significant regulatory burden” onto State and local agencies, causing them to have to undertake additional expenditures, hire new staff, and engage in additional training. This commenter stated that UMRA (2 U.S.C. 1532) requires that an analysis be performed to determine whether additional government funding is needed for State and local agencies to comply with the mandate. Many other commenters questioned or disagreed with ATF's statement that the proposed rule did not impose any “unfunded mandates,” again focusing on the proposal to extend the CLEO certification requirement to responsible persons of trusts and legal entities, which, they noted, would significantly burden CLEOs and divert local law enforcement resources from other criminal justice priorities. Numerous commenters referenced the U.S. Supreme Court case,
The Department acknowledges commenters' concerns that the proposed extension of the CLEO certification would place additional burdens on CLEOs for processing and reviewing additional responsible persons' forms, and for taking and reviewing fingerprints. The Department, however, complied with UMRA in the proposed rule. In any event, for this final rule, the Department reexamined the burdens and costs to CLEOs.
In preparing this final rule, the Department based the costs and expenditures upon direct costs to State and local agencies, licensees, and ATF. While it acknowledges that there may be several indirect costs or resources that may be associated with complying with the rule, the Department believes that the amount would still not be greater than $100 million or more.
For this final rule, the Department prepared an additional analysis of approved applications in response to several comments that it provided a “low estimate” of the number of responsible persons per applicant, and the number of pages of chartering documents at those entities, which directly affects the time and resources required by the CLEO to review applications. As discussed in section IV.C.1, the Department is eliminating the CLEO certification requirement and replacing it with a CLEO notification requirement that will significantly lessen the burden to CLEOs. The CLEOs will have the flexibility and discretion to review and maintain the information they obtain as a result of this rule in the manner that best enhances public safety in their respective jurisdictions.
Regarding the commenters who referenced
As a result of ATF's review of public comments received in response to the proposed rule, the Department will remove the CLEO certification and replace it with a notification obligation upon the applicant/transferee, including
Because CLEO notifications will require only those resources that the CLEOs themselves decide to devote to notification management, additional funding to assist State, local, and tribal governments in complying with this rule is unnecessary.
The Department has determined that this rule is not an unfunded mandate because it does not meet the criteria under UMRA. Specifically, it does not result in the expenditure of funds by State, local, and tribal governments, in the aggregate, or by the private sector of $100 million or more in any one year. See section VI.A.3 for additional details about the Department's estimate of costs to State and local entities.
Many commenters stated that the proposed rule, with its proposal to expand the CLEO certification requirement to responsible persons, imposed an increased information collection burden (
One commenter suggested further ways to decrease paperwork and reduce the redundancy in ATF's processing system associated with multiple applications submitted by the same person or legal entity. This commenter suggested that ATF consolidate applications from repeat applicants, maintain and use a database of approved applicants, and perform background checks on new applications from the date of the last approval. In this way, the commenter contended, the process would be shortened but maintain its integrity.
The Department acknowledges the commenters' concerns that the proposed expansion of the CLEO certification requirement, as well as the CLEO certification requirement for individuals, imposed paperwork burdens on the public and on ATF. The Department also acknowledges that the proposed expansion may have limited the use of the ATF eForms system for many NFA applications because of the manual submission of fingerprint cards, etc. As discussed in section IV.C.1, the Department is removing the CLEO certification requirement for individuals, and replacing it with a notification requirement for both individuals and trusts or legal entities. This change will help reduce paperwork and increase efficiency for the public and ATF. Section VI.G of this rule fully discusses the paperwork burdens.
Regarding commenters' other suggestions for streamlining the process (
In the proposed rule, ATF estimated an average of two responsible persons associated with a legal entity. Many commenters stated that ATF grossly underestimated this number and that having more than two responsible persons was not calculated into the cost. A number of objections were raised as to the sample size ATF used to obtain its estimate, which commenters argued was too small and not determined through statistically rigorous analysis. One of these commenters stated that if ATF's estimate of two responsible persons was inaccurate, it should propose another comment period with a revised number of responsible persons and associated costs.
Numerous commenters also noted that given the breadth of the definition of “responsible person” in the proposed rule, it was likely that the average number per legal entity was much higher than two. Commenters, including persons with experience preparing NFA trusts, opined that two was more likely to be the minimum number per legal entity, not the average. For corporations or LLCs, in particular, commenters observed that the number could be higher still, potentially in the “hundreds to thousands.”
Commenters noted that if, as they believed, ATF's estimated average number of responsible persons was unreasonably low, its cost estimate was equally unreliable. One commenter opined that the total annual direct implementation costs to citizens involved in NFA transactions should be at least three times higher than ATF's estimate (
For this final rule, the Department reviewed a random sampling of 454 forms to determine the average number of responsible persons per legal entity. The random sample was pulled from the 115,825 Forms 1, 4, and 5 processed in CY 2014. The forms to be reviewed were generated using established sampling methods based on ATF criteria of a 95 percent confidence level with a 2 percent sampling error, and represented a mixture of legal entities including trusts, corporations, and LLCs. The random sample showed that the average number of responsible persons was approximately two. Additionally, the random sample showed that the most frequent number of responsible persons was one (with 226 instances), followed by two (with 124 instances). This represents 78 percent of the forms reviewed. The highest number of responsible persons in the sample was 11. Based on its random sample, the Department continues to estimate that each trust or legal entity has an average of two responsible persons. Moreover, the criteria used for determining who would be a responsible person in the most recent random sample review was based on a definition of “responsible person” materially similar to the revised definition of responsible person in this rule.
To be considered a responsible person, the individual must possess, directly or indirectly, the power or authority to direct the management and policies of the entity insofar as they pertain to firearms. This power or authority will be limited by the terms of the trust or the structure of a legal entity. Therefore, not every individual named in a trust document will be considered a responsible person, but any person who has the capability to exercise such power and possesses, directly or indirectly, the power or authority under any trust instrument, or under State law, to receive, possess, ship, transport, deliver, transfer, or otherwise dispose of a firearm for, or on behalf of, the trust, will be considered a responsible person of the trust.
With respect to the definition of responsible person that was used to determine the average number of responsible persons at trusts and legal entities, the definition used was materially similar to the definition that appears in this final rule. The Department has thus concluded that, under the definition of responsible person that appears in this final rule, the best estimate of the average number of responsible persons at trusts and legal entities is two. The Department notes that none of the trust documents reviewed in the sampling gave beneficiaries the power or authority to direct the management and policies of the trust, including the capability to exercise such power and possess, directly or indirectly, the power or authority under any trust instrument, or under State law, to receive, possess, ship, transport, deliver, transfer, or otherwise dispose of a firearm for, or on behalf of, the trust.
A few commentators questioned the sampling methodology ATF used to determine that the documents chartering a legal entity averaged 15 pages in length and thought it was “highly suspect.” These commenters noted that ATF reviewed a different sample size to determine the average length of documentation than it used to compute the average number of responsible persons per legal entity (
Another commenter stated that his own experiences as the owner and founder of Gun Trust Lawyer®, a nationwide network of lawyers, confirm what many other commenters observed, namely, that ATF underestimated the document length and other costs associated with the proposed rule. This commenter and several other commenters stated that the document length of a sample revocable trust used by Gun Trust Lawyer®, including exhibits and attachments, is almost double the length that ATF estimated when the trust has four to six trustees, a typical number of trustees. These commenters stated that the sample revocable trust, used by this network includes a 19-page trust document, with additional pages for assignment of property and recording contributions, witnessed statements from each trustee and the settlor, and the signed “Trustee Declaration” and notarized signature page. Another commenter stated that documents associated with sophisticated estate plans or complicated trusts can be quite lengthy with trust instruments and entity formation documents ranging from a few pages to hundreds of pages when their schedules, exhibits, and attachments—all of which must be filed with ATF—are included. Another commenter stated that the gun trusts he creates are at least 65 pages long, and that he knows a substantial number of other attorneys who also create trusts of this length. Another commenter stated that his trust comprises 18 articles and over 70 pages. This commenter stated that ATF needed to reevaluate the sample and revise the cost assumptions.
Another commenter stated that ATF did not consider corporations and LLCs when estimating the average document length, and asked about the average length of document pages that a corporate entity and its shareholders would submit. Another commenter stated that the type of documents needed to evidence the existence and validity of partnerships, companies, associations, corporations, and trusts is governed by “formation and continuation” rules, which vary among the 50 States and are “complex, state-specific, and diverse in purpose.” This commenter stated that it is highly unlikely that ATF will be able to examine “hundreds or perhaps thousands of pages of trust or entity documents” due to lack of time and expertise.
For this final rule, the Department reviewed a random sampling of 454 applications to determine the average number of pages in the corporate or trust documents. The random sample was derived from 115,825 Forms 1, 4, and 5 processed in CY 2014. The forms
The Department acknowledges that each State is specific in the documentation required for partnerships, companies, associations, corporations, and trusts. ATF examines all submitted documents when trusts and legal entities apply for a Federal firearms license.
ATF estimated that photographs would cost $8.00 and take an average of 50 minutes to obtain, and that fingerprints would cost $24.00 and take 60 minutes to obtain. Many commenters stated that ATF's estimates for photographs and fingerprints were unrealistically low, and, in their experiences, the costs and times were “higher” and even “significantly higher.” The costs and times provided by the commenters for photographs ranged from $8.00 to $125 and 5 minutes to two weeks, respectively. The costs and times provided by the commenters for fingerprints ranged from no cost—complimentary service—to $120, and from 10 minutes to three weeks. A commenter stated that since ATF did not provide any supporting documentation for the estimated costs and times, it was not clear whether ATF surveyed only service providers in “highly-competitive, urban markets.” This commenter referenced the experiences of another commenter, who lived in a rural area and had to contact six police departments, taking several hours, before finding someone willing to fingerprint him. Other commenters mentioned additional costs in obtaining photographs and fingerprints that they believed ATF did not take into consideration such as work time missed, drive time, “fuel, wear and tear on my personal vehicle,” and “value of my time.” Another commenter stated that the stores offering in-house photography are dwindling and that applicants will spend 15 minutes locating a store, an average of at least 40 minutes for travel to and from the store, 20 minutes waiting for copy machines to warm up at the store, and additional time getting pictures taken and printed, totaling 75 minutes. This commenter referenced a nationwide chain's price for passport photographs at $11.99 plus tax, totaling $12.71, plus an $11.30 cost of driving to the store, computed by estimating an average roundtrip of 20 miles at the Federal mileage rate. This commenter summed up costs and time at $24.01 and 75 minutes, respectively, to obtain photographs. This commenter accepted ATF's estimate of $24.00 to obtain fingerprints but considered ATF's estimate of the associated time as 60 minutes to be low. This commenter estimated the time at 100 minutes (70 minutes total travel time plus 30 minutes on site to obtain fingerprints) plus an average round trip of 40 miles costing $22.60, determined at the Federal mileage rate. This commenter tallied the fingerprint costs and time at $46.60 ($24.00 + 22.60 = 46.60) and 100 minutes, equating to $97.93 per responsible person. As support for his position that ATF underestimated the fingerprint costs, another commenter provided a link to the Department of Homeland Security's Transportation Security Administration Web page
Fingerprints may be taken by anyone who is properly equipped to take them (see instructions on ATF Form 1, Form 4, Form 5, and Form 5320.23). Therefore, applicants may utilize the service of any business or government agency that is properly equipped to take fingerprints. Depending on where the fingerprints are taken, the service may require an appointment, and appointment availability may be limited. Some businesses provide evening and weekend appointments and a number of private companies provide mobile fingerprinting services at a location chosen by the customer to be fingerprinted. Additionally, some mobile fingerprinting services offer special pricing to groups of individuals who need to be fingerprinted.
ATF reviewed 254 Web sites that published the cost of fingerprint service. Information was obtained from businesses and government agencies located throughout the United States, in both urban and rural areas. The review disclosed a cost from zero to $75.00 for two fingerprint cards. One hundred thirty-eight of the Web sites listed a cost between $10.00 and $20.00. Based on its review, ATF estimates the average cost to be $18.66.
The estimated time to obtain fingerprints set forth in the proposed rule was 60 minutes. This estimate was derived from information ATF submitted to OMB as part of the renewal approval process for ATF Forms 1, 4, and 5. The time estimate has been accepted by OMB as an appropriate estimate of the time needed to obtain fingerprints. A review of twenty-two Web sites that published an approximate amount of time to obtain fingerprints disclosed time estimates ranging from 5 minutes to 120 minutes, with the average time being 22 minutes. As not all the Web site estimates include wait time to obtain fingerprints, the Department believes the estimate of 60 minutes is a reasonable time approximation. The Department recognizes that individual experiences may vary from the estimated time.
Photographs must be a size of 2 inches x 2 inches of a frontal view taken within one year of the date of the application (see 27 CFR 479.63 and 479.85). There is no requirement that the applicant/transferee use a professional photographer to acquire the photographs, provided that they meet the stated requirements. The photographs may be taken at home with a digital camera and printed out in the required size using a color printer or the applicant/transferee may use a Web site that provides this service. In addition, the applicant/transferee may choose to obtain passport photographs, which meet the required specifications.
Numerous businesses offer passport photograph services including national chain stores. Generally, there is no appointment necessary to obtain passport photographs from these types of businesses.
ATF reviewed 57 Web sites that published the cost of passport photographs. Information was obtained from businesses located throughout the United States, in both urban and rural areas. The review disclosed a cost for two passport photographs that ranged from zero to $25.00. Thirty-five of the Web sites listed a cost between $10.00 and $15.00. Based on its review, ATF estimates the average cost is $11.32. The Department recognizes that the costs associated with individual experiences may vary from the estimated cost.
The estimated time of 50 minutes to obtain photographs was obtained from information ATF submitted to the OMB as part of the renewal approval process for ATF Forms 1, 4, and 5. The time estimate has been accepted by OMB as an appropriate estimate of time to obtain photographs. A review of fifteen Web sites that published an approximate amount of time to obtain photographs disclosed time estimates ranging from 5 to 15 minutes with the average time being 10 minutes. As the Web site estimates include only the time necessary to have the photograph taken and printed, ATF believes the estimate of 50 minutes (accounting for travel time and possible wait time) is a more accurate time approximation. The Department recognizes that individual experiences may vary from the estimated time.
ATF estimated that the time needed for a responsible person to procure the CLEO certification was 100 minutes (70 minutes travel time and 30 minutes review time with the CLEO). Several commentators stated that in their experiences, ATF's estimate was inaccurate, too low, “way off-base,” and did not include additional associated costs. A few of those commenters stated that ATF did not consider the large number of instances where multiple CLEOs were unwilling to sign and an applicant needed additional time to “hunt” for a CLEO willing to sign the certification, which may have included visiting several different government offices, making appointments with multiple CLEOs, and educating and persuading the CLEO to sign the certification. A commenter stated that his CLEO would not review the form with him, and instead advised the commenter to mail in the form with an estimated wait of over 30 days for the CLEO to decide whether to sign the form. Another commenter expressed knowledge of many CLEOs who require that the applicant leave the form with their offices, and return later to pick it up, doubling ATF's estimated travel time of 70 minutes to 140 minutes. This commenter also stated that a typical process is for the CLEO's assistant to first review the form—taking 30 minutes—and then for the CLEO to review the form—taking 15 minutes—so that the total CLEO review time is 45 minutes. This commenter also estimated applicants' drive time to average 40 miles, twice, to obtain the CLEO certification with a total mileage cost of $45.20 at the Federal mileage rate. This commenter tallied the costs at $140.17 per responsible person. Another commenter estimated that he spent over 240 minutes calling and writing letters to try and obtain CLEO certification to no avail, far exceeding ATF's estimated 100 minutes.
Another commenter stated that ATF did not justify or substantiate its estimate of 100 minutes. This commenter requested that ATF sample a statistically relevant number of NFA item owners to determine how long it actually takes to obtain CLEO certification. This commenter also requested that ATF consider the additional costs that some CLEOs arbitrarily impose on applicants as a condition to providing certification. According to the commenter, these conditions may include acquisition of an FFL03 Curio and Relic license or Concealed Weapons Permit, attendance at police fundraisers, volunteer service with the CLEO's department, or contributions to political campaigns.
The Department acknowledges that individual experiences to obtain CLEO certification have varied from the time estimate. However, the time estimate is no longer relevant as the CLEO certification has been replaced with a CLEO notification requirement.
A trade organization commenter stated that by basing all of its time valuations on $30.80—the current average hourly compensation for all civilian workers in the United States—ATF failed to consider that NFA firearms are often very costly, and that even the least expensive ones are discretionary purchases and unlikely to be made by low-income individuals. This commenter also noted that these items typically have a $200 making or transfer tax, and that people using legal entities to make or acquire NFA firearms will already have incurred other expenses to create the legal entities, such as legal fees and corporate filing fees. This commenter suggested that ATF base its cost burden estimates on the actual characteristics of those who would be considered responsible persons. Other commenters stated that an individual purchasing NFA firearms would have higher than average disposable income and is not an average civilian worker.
The Department does not have access to confidential information such as the salary or disposable income for individuals purchasing NFA firearms. Commenters have not suggested a methodology or dataset that would permit the Department to more accurately estimate the time-value of responsible persons than the one it has adopted. The Department thus continues to believe that it is appropriate to base the time valuations for individuals and responsible persons of trusts and legal entities on the civilian hourly rate, as determined by the U.S. Department of Labor, Bureau of Labor Statistics. In June 2015, the hourly earnings for civilians was $33.19. See section VI.A.1 of this rule for further discussion and the U.S. Department of Labor, Bureau of Labor, Web site at
A commenter stated that ATF's time estimate of 10 minutes for a responsible person to complete Form 5320.23 was too optimistic. This commenter thought that ten minutes might be reasonable if the person completing it was familiar with the form, but that additional costs would be incurred to learn how to complete the form. This commenter asserted 15 minutes would be a more accurate estimate, equating to $7.70 per responsible person. Another commenter asked how ATF could accurately estimate a “mere” 10 minutes, on average, per responsible person to complete Form 5320.23, when the form had not yet been created. This commenter disagreed with ATF's statement that there would be no increased costs associated with mailing the application package to ATF, and called such a statement “either willfully false, or woefully ignorant.” This commenter argued that the proposed rule would add weight and increased cost to mail an application, which now must contain a “significant” number of paper pages (
Another commenter considered ATF's estimate of cost to copy documents, associated with a legal entity, at $0.10 per page, a fair estimate; however, this commenter stated that the average trust, if properly drafted, would have 20 pages, not the estimated 15 pages. Additionally, this commenter stated that ATF's time estimate of 5 minutes to make copies was low. This commenter stated that many legal entities do not have a copy machine on site and would need to travel to a commercial facility to make copies. This commenter estimated such a round trip to be 30 minutes and cover 15 miles on average, costing the applicant $8.48 (using the Federal mileage rate). This commenter stated that making copies and paying for those copies would take 10 minutes. Tallying the total times and costs, this commenter estimated that the entity would spend “$16.95 to travel, $2.00 on copies, and 40 minutes to travel and acquire the copies. In dollars, this equates to $39.48 per entity.”
A commenter questioned ATF's estimated cost of $14.50 to process fingerprints. This commenter stated that $14.50 is the cost ATF pays but may not be the actual cost to the FBI. This commenter expressed interest in hearing from the FBI on the “true” cost transfer from ATF to the FBI.
The Department agrees with the suggestion that allowing 15 minutes to complete Form 5320.23, 5 minutes more than the estimate in the proposed rule (78 FR at 55022), is a fair estimate. With respect to mailing costs, the addition of a CLEO notification requirement will result in the mailing of an additional form to the CLEO (if the applicant/transferee or responsible person(s) opts to use mail delivery) but the associated costs are minimal. Moreover, any additional mailing costs will be offset by cost and time savings resulting from the elimination of the CLEO certification requirement. Further, postage costs are already included in the costs of completing and mailing Forms 1, 4, or 5 to ATF. As discussed in the proposed rule (78 FR at 55022), individuals, trusts, and legal entities must complete and mail Forms 1, 4, or 5 to ATF. This final rule should not change the costs associated with that process. Even if there are multiple responsible persons associated with a trust or legal entity, the trust or legal entity still will be completing and mailing one Form 1, 4, or 5. Similarly, because CLEO notifications have replaced CLEO certifications, ATF's internal costs will remain as discussed in the proposed rule (78 FR at 55022).
The Department agrees with the commenter who referenced ATF's estimate of cost to copy documents “at $0.10 per page a fair estimate.” Further, a more recent analysis of 454 random samples available to ATF suggests that 16 pages approximates the mean length for properly drafted trust documentation. In addition, the Department concurs with the estimate of ten minutes to make and pay for copies. Current data indicates that ATF pays the FBI $12.75 to process fingerprints, which is the appropriate cost for inclusion in this final rule.
Many commenters stated that ATF failed to account for the significant loss of tax revenue by ATF from fewer NFA transfers, and on the income tax lost on the sale of NFA firearms by manufacturers, distributors, and dealers. Several of these commenters noted that ATF estimated 40,565 ATF Forms 1 or 4 were submitted in 2012 for non-FFL legal entities (78 FR at 55021). Several commenters stated that the proposed rule would “discourage” or “scare off” individuals from purchasing or making NFA firearms because the rule will make the application process for legal entities more difficult. These commenters stated that for every Form 1 and Form 4 that is not submitted to ATF, a $200 tax payment loss will result (unless the application is submitted for an “Any Other Weapons” weapon, in which case the tax payment loss would only be $5). Several commenters provided estimates of the decreased volume in NFA applications that they asserted would result from implementation of the proposed rule, and corresponding losses in NFA tax stamp revenue. These estimates of reduced applications ranged from a 50 percent reduction (attributed primarily to predicted refusal of CLEOs to sign certifications for legal entity responsible persons) to a 75 percent reduction (attributed primarily to a decrease in legal entity applications), with corresponding estimated losses in NFA tax stamp revenue of $6.1 to $8.1 million. Several commenters stated that the proposed rule would make it harder for people to legally purchase silencers, and asked, “is ATF trying to eliminate $12,000,000+ in annual tax revenue?” Several commenters asserted tax revenue losses would occur in addition to lost NFA tax stamp revenue. They stated that if the business of selling NFA firearms declined and caused small FFL dealers and custom manufacturers to cease dealing in NFA firearms, such dealers and manufacturers would surrender their SOT status and stop paying at least $500 annually to the U.S. Treasury. If small custom manufacturers determined it was no longer profitable to stay in business and were forced to shut their doors, such manufacturers would stop annual payments of at least $2,400 to the U.S. Treasury under the International Traffic in Arms Regulations.
As noted, the final rule eliminates the CLEO certification requirement. Consequently, comments asserting tax revenue losses resulting from the refusal of CLEOs to sign certifications for legal entities are now moot. Moreover, the Department does not anticipate a decline in Form 4 applications. The Department has not observed, and does not anticipate, reduced demand for NFA firearms or a decline in the filing of applications (Forms 1 and 4). Applications have generally increased each year and the Department expects this trend to continue as more States loosen restrictions on the use, in particular, of silencers for hunting or target shooting.
Moreover, because the CLEO notification requirement and the requirements for fingerprint and photograph submission will be the same under the final rule for individual applicants and trusts and legal entities, applicants may choose to forgo the formation of a trust or legal entity and acquire firearms as individuals. A number of commenters have observed that the proliferation of NFA trusts is a direct result of the CLEO certification requirement for individual applicants. It is therefore fair to predict that eliminating the certification requirement will reverse that trend. Applications submitted by an individual are less complex because they do not require documentation evidencing the existence and validity of a trust or legal entity, such as articles of incorporation.
Contrary to the assertions of several commenters, the Department does not anticipate that implementation of the final rule will result in an increase in the number of FFLs or FFL/SOTs going out of business. The number of FFLs that also paid SOT to manufacture, import, or deal in NFA firearms increased 117 percent between 2009 and 2014. The Department estimates that the
Many commenters stated that the proposed rule completely overlooked the cost of hearing loss due to the unavailability of silencers. Many commenters stated that many citizens desire to make or acquire silencers to protect their hearing while engaged in lawful, recreational shooting, as well as in self-defense situations. These commenters stated that the proposed rule imposed obstacles to making and acquiring silencers, and a significant number of shooters who desire to use silencers will be unable to do so. Several commenters provided data and statistics showing: The level of impulse noise generated from unsuppressed firearm discharge; that firearm discharge is a leading cause of noise induced hearing loss; the efficacy of silencers at protecting hearing; and the impracticality of using means other than silencers in certain situations (
The Department recognizes that the use of a silencer while shooting a firearm may help to reduce hearing loss. Neither the proposed rule nor the final rule prohibit the manufacture or sale of silencers; the primary premise of the comments is that silencers will become less available as a result of the proposed rule, thereby increasing societal costs from shooting related hearing loss. The Department disagrees that the final rule will significantly reduce the availability of silencers. The final rule no longer requires CLEO certification, the aspect of the proposed rule most commonly cited by commenters as an impediment to consumers obtaining silencers and other NFA weapons (from either retailers or private transfers). With the elimination of the CLEO certification requirement for all NFA applications, including individuals, the process for individuals who wish to purchase a silencer to protect from hearing loss becomes less, not more, burdensome. Moreover, as is noted in several sections of this final rule, the silencer industry has experienced significant growth largely as the result of several States legalizing the ownership of silencers for hunting and other purposes under State law. This legalization trend among the States is likely to continue, strengthening demand for silencers, thus driving additional industry growth and increased product availability. Finally, with respect to assessing the societal costs of firearms-related hearing loss, the Department is unaware of any peer reviewed study calculating an average value for hearing loss attributable only to the use of firearms without silencers.
Many commenters stated that ATF failed to consider the costs that individuals associated with trusts or legal entities would incur to consult with attorneys to accurately determine the number of individuals associated with their trusts or legal entities that would fall under the proposed “responsible person” definition. Another commenter stated that the proposed rule did not address the interstate nature of corporations, and that an individual would need to consult an attorney—at $150 per hour—to determine what jurisdiction the CLEO certification would be required to be obtained in. A few commenters provided their total attorney fees to consult with lawyers specializing in NFA legal matters and to form an NFA trust that complied with all the relevant laws; these fees ranged from $200 to over $1,500. Another commenter stated that if the proposed rule were implemented, applicants would need to obtain revised trust documents from a licensed attorney. This commenter, a licensed attorney, conservatively estimated the average cost and time at $200 per trust and at least two hours of the applicant's time, respectively. After assuming that 20 percent of the approximately 100,000 NFA related trusts or other entities would require revision, this commenter estimated the costs to trusts for legal fees to be $4,000,000 plus 40,000 client hours.
This same commenter stated that ATF did not estimate the costs for attorneys to revise forms, attend continuing legal education, and perform other uncompensated work needed to comply with the proposed changes. This commenter estimated five hours for each attorney to perform these activities. After assuming 1000 attorneys are involved nationwide in NFA matters and a conservative hourly rate of $200, this commenter estimated the total cost at $1 million.
Another commenter stated that ATF did not estimate the cost to ATF for a State licensed attorney to review the submitted trust documentation to ensure the trust's validity and that all responsible persons are included. This commenter estimated the annual cost to ATF at $1,628,000 after assuming 40,700 trust documents, half an hour of the attorney's time to review each trust, and an $80 hourly rate.
There is no requirement to form a trust or legal entity to acquire an NFA firearm. In fact, all of the legal fees included in the comments may be avoided if the NFA firearm is acquired by an individual. Therefore, when an applicant voluntarily decides to register a firearm to a trust or legal entity, the applicant assumes all responsibilities for determining the responsible persons—including legal fees associated with making that determination. Additionally, as noted, the final rule no longer requires CLEO certification; the final rule requires only CLEO notification. Moreover, both the text of the final rule (when incorporated into a regulation) and instructions on revised ATF forms will provide specific directions as to who must provide notification to the CLEO. Therefore, it may not be necessary to consult an attorney to determine this information.
As the attorney-commenter did not specify why trust documents would need to be revised, the Department cannot directly address this concern. There is no requirement, existing or proposed, to form a trust or legal entity to acquire an NFA firearm or to satisfy any CLE requirement. The cost of CLE is therefore outside the scope of the cost of this final rule.
A commenter stated that ATF did not estimate the costs to revise various publications, informational brochures, industry Web pages, and other miscellaneous resources relied upon by NFA applicants and potential applicants for NFA information such as those published by hobbyists, industry, retailers, local law enforcement, and Federal agencies. The commenter could not estimate such costs but imagined that such costs could easily be $1,000,000 or more nationally.
Another commenter stated that ATF's cost analysis did not address the cost of implementing the forms and applications in the NFA Branch that have a “pending” status when the rule changes are implemented.
ATF updates its publications, Web site, and forms on an ongoing basis and will continue to do so each time there are changes to Federal firearms laws or regulations. FFLs, other law enforcement agencies, trade associations, and other entities are not required under Federal law or regulation to provide information on the NFA or on how to acquire an NFA firearm. Therefore, these comments are outside the scope of this rulemaking. Additionally, such costs are difficult to estimate, and informational resources provided by other entities are routinely updated as a matter of course, making it difficult to trace what update costs are specifically attributable to ATF's new rule. The commenter did not suggest a methodology by which ATF could readily quantify such costs, and ATF believes any such costs directly traceable to the promulgation of this final rule will be negligible.
With regard to the comment regarding applications that have a “pending” status when the rule is implemented, all applications postmarked prior to the effective date of the rule will be processed under the current regulations. The same is the case for any applications that have a pending status at the time the rule is implemented. Consequently, no additional costs will be incurred by ATF to process pending applications.
Several commenters stated that ATF omitted the costs to ATF, DOJ, and local law enforcement of litigation that could potentially arise if the proposed rule were implemented. These commenters stated that ATF must expect significant judicial challenges to the proposed CLEO certification requirements for responsible persons as many law abiding citizens will no longer have a “work-around” or mechanism to avoid CLEO certification, will consequently face arbitrary refusal by CLEOs, and will be unable to own or possess otherwise legal NFA items. A few of these commenters stated that citizens who live in jurisdictions where every local CLEO refuses to sign off on the NFA paperwork would have no recourse other than to sue ATF or DOJ. Another commenter referenced
Another commenter expressed the opinion that the rule was too vague to withstand legal scrutiny and would result in expensive litigation. Another commenter stated that DOJ will spend millions of taxpayer dollars “in vain” trying to defend this rule in various courts. Another commenter agreed that taxpayers would “foot the bill” for the litigation that citizens allegedly denied their constitutional rights would bring against local and State governments, and the Federal Government, and that this would place a huge burden on local departments and agencies.
The change from CLEO certification to notification addresses the substance of the concerns expressed in these comments and will reduce the likelihood of litigation.
Additionally, the Department regards the possible costs of potential future legal challenges as difficult to quantify. Commenters did not suggest a methodology by which the Department could accurately measure such costs. Moreover, the Department already must maintain a legal staff to defend its rules that it must fund whether or not any particular legal challenge is brought. It would thus be difficult to determine the extent to which litigation about the rule would add to the Department's legal costs.
Finally, the Department does not regard the potential cost of defending the lawfulness of its rule as appropriate to include in an assessment of the costs and benefits of the rule. Such costs are imposed by third parties that choose to file suit regardless of the potential legal merit of their claims. If the costs of defending suits formed part of the cost of a rule, opponents could claim that they would file suit, regardless of the merits of their claims, and thereby drive up the estimated cost of the rule. If an agency were required to factor litigation threats into the cost of a rule, opponents threatening litigation could exercise a sort of veto over agency rulemaking by artificially increasing the rule's costs.
A commenter stated that ATF severely underestimated the time and costs to trust participants arising from the rule. This commenter stated that the proposed rule would take trust participants an additional 30 days to properly coordinate and submit the required documentation for each NFA item requiring approval by the NFA Branch.
Another commenter stated that neither ATF nor any other component within DOJ provided “credible information, studies, or analysis” showing details of the estimated annual fiscal costs and the feasibility of implementing the proposed rule. This commenter asked that the Government Accountability Office (GAO) perform an “independent, non-partisan review” of the proposed rule and its current and potential fiscal impact, as well as its feasibility, and submit the findings to Congress so Congress could review to determine if the proposed rule complied with the “policies, rules, and standards” governing ATF.
One commenter noted that ATF calculated the costs of the proposed rule based on the number of legal entity applications from previous years, and further noted that ATF listed a large increase in legal entity applications from 2000 to 2012 as evidence, in the commenter's words, that these applications “are serving as a mask for individuals who otherwise would be prohibited from owning guns.” This commenter stated that if the proposed rule's purpose is to target and reduce such activity, then ATF's cost calculations should reflect a reduction in the number of applications by legal entities.
The Department does not agree with the commenter that the proposed rule would add an additional 30 days to the process of acquiring an NFA firearm. The commenter provided no empirical evidence or analysis supporting this
Proposed changes to ATF regulations, including the proposals set forth in the NPRM and this final rule, undergo a rigorous review process by both the Department and the Office of Management and Budget. These reviews include close scrutiny of the estimated annual fiscal costs associated with the proposed and final rules. Finally, the proposed rule and this final rule have been published for public comment and scrutiny. In light of all these review procedures, the Department does not believe additional review of this rule by the GAO, as requested by a commenter, is necessary or warranted.
The Department also does not agree with the commenter who asserts that the purpose of the proposed rule is to target and reduce NFA applications filed by trusts. The objective of the final rule is instead to ensure all applicants, regardless of whether they are an individual applying in an individual capacity or applying in a representative capacity on behalf of a trust or legal entity, are subject to the same approval process to help ensure that prohibited persons do not obtain NFA firearms.
Moreover, the Department's decision to base its estimate of the costs of the rule on the number of trusts and legal entities that currently apply to make and transfer NFA firearms is appropriate because it likely accurately estimates the overall number of background checks and information submissions that will need to be undertaken as a result of the rule. To the extent individuals presently create single-person trusts and legal entities to circumvent background check requirements, they may now choose simply to submit individual applications. To be sure, that would result in a decrease in the number of applications from trusts and legal entities. But it would be accompanied by a concomitant increase in the average number of responsible persons at the trusts and legal entities that remain. The overall number of information submissions and background checks is therefore likely to remain roughly equivalent to the Department's estimate. Commenters have not suggested a method of estimating the costs of the final rule that is superior to the methodology the Department has chosen.
A large percentage of commenters asserted that the proposed rule will negatively impact NFA industry participants (including manufacturers, dealers, and employees) as well as related businesses such as suppliers. The commenters characterized their assessments of the financial impact on business in a number of different ways: The impact on NFA manufactures; the impact on specific NFA manufacturers such as silencer manufacturers; the impact on firearm dealers; the impact on related industries such as suppliers to manufacturers; the impact on general lawful commerce in firearms; the impact on “small businesses;” the impact on employees of various businesses in the form of lost jobs and wages; and general claims of “reduced revenue” for industry and affiliated business.
Most of the commenters focused their assessment of the proposed rule's negative impact on the provision in the proposed rule extending the CLEO certification requirement to trusts and legal entities. These commenters emphasized that, for numerous reasons, some CLEOs will not sign the NFA certifications even if the applicant is not prohibited by law from acquiring a firearm, freezing the application approval process. Because no process exists to override a CLEO's refusal to sign a certification, the refusal to sign functions as a denial of the application, preventing the applicant from purchasing the NFA item, and thereby depriving NFA manufacturers and dealers of law-abiding customers. A second recurring theme in the comments was that the proposed rule would decrease demand for NFA firearms, and thereby negatively impact businesses, because the rule will require a greater number of NFA applicants to undergo background checks (
Examples of comments from the various categories of characterization used by the commenters include the following:
Several commenters reasoned that the proposed rule would make it more difficult to obtain NFA items and as a result would drive manufacturers out of business; one such commenter characterized the impact as jeopardizing the entire, booming “cottage industry” of NFA manufacturers. Similarly, an employee of a silencer manufacturer, that has been in business for more than 20 years, commented that the proposed rule would “cripple” his employer's business. One commenter listed multiple negative impacts he predicted the proposed rule would have on NFA manufacturers: (1) Lost investment in machines; (2) lost investment in unsellable inventory; (3) lay-offs of manufacturing and sales staff; and (4) no market for their product. Several commenters argued that the proposed regulation would make wait times for customers to obtain ATF approval even longer, resulting in frustrated customers and reduced sales.
Many commenters directly linked predictions that the proposed rule would negatively impact NFA manufacturers and dealers to the CLEO certification requirement. They asserted that extending the certification requirement to legal entities will drastically inhibit sales of NFA items, particularly silencers, causing reductions in business, business closure, and loss of employees. Several FFL commenters asserted that the proposed rule would “destroy” their businesses because CLEO certification was difficult or impossible to obtain in their counties. One of these FFLs stated he had researched the impact of CLEO certification in his State, Texas, and determined that approximately “70% of Texans” will not be able to obtain a CLEO signature; therefore, he predicted, “70% of his customer base” would be eliminated by the proposed rule. Another FFL asserted that he anticipated a 75 percent loss in sales due to the CLEO requirement, and two other FFLs stated that they anticipated a 20 percent loss in revenue due to the CLEO certification requirement.
Several commenters opined that the proposed rule would place significant financial burdens on firearm dealers by prolonging the transfer process for trusts and legal entities because under the responsible person definition the trust or legal entity will need to obtain the fingerprints and photographs of all members of the trust or legal entity.
Many commenters stated generally that the proposed rule will hurt, hinder, or make it harder for small business owners, particularly firearm related businesses, by increasing transaction costs and transaction times. Several commenters emphasized that small firearms related businesses are engaged in lawful commerce, and expressed the view the government was seeking to unfairly target such businesses with regulations increasing the cost of doing business. Other commenters hypothesized that the proposed rule will destroy small businesses because it would limit or prevent law-abiding citizens from acquiring NFA items.
Several commenters focused on the proposed rule's negative effect on specific NFA market segments such as the markets for silencers, short-barreled rifles, machineguns, and military surplus firearms. A large number of commenters claimed the proposed rule would significantly reduce the sale of silencers, driving silencer manufacturers out of business and potentially causing the entire silencer industry segment to collapse. Another commenter predicted the proposed rule would cause the collapse of the military surplus firearms market. Some commenters expressed concerns that the proposed rule could harm technical innovations for silencers, with one commenter asserting that advancements in silencer technology will grind to a halt, affecting the military firearms supplied to “our troops overseas who deserve and require the best we have to offer.” One commenter reasoned that the proposed rule will limit the availability of NFA items, thus making the value of silencers, machineguns, and short-barreled rifles increase for those who own them. This commenter anticipated that this effect would make current owners “happy.”
Several commenters expressed concerns that the proposed rule will negatively impact firearms related-industries, not only those businesses directly involved in the sale and manufacture of firearms. Many of these commenters asserted that the proposed rule's CLEO certification requirement will have the effect of halting the sale of all NFA items in many areas (because, they assert, certain CLEOs will not sign certifications), which, they assert, will have a cascading effect: Reduced sales will result in substantial losses for NFA manufacturers and dealers (particularly those involved in the silencer market), which, in turn, will negatively impact businesses that contribute to the manufacturing process or derive business from firearms dealers and manufacturers. One commenter stated that the proposed regulation will cause well paying, American jobs to be lost in machining, manufacturing, marketing, and retail sales. Examples provided of related businesses that commenters believe would be negatively impacted also included: Ranges, materials suppliers, computer numerical control and milling operations and manufacturers, third party processors (such as Cerakote coating, powder-coating, anodizing, black oxide, metal sales, tooling, laser marking, and engraving), office supply stores, trade shows, and various NFA shooting events (such as machinegun shoots).
Other commenters asserted that the proposed rule will negatively impact law firms that handle trust matters involving NFA items because demand for creation of trusts solely used to obtain and hold NFA firearms will decrease as a result of the proposed rule's provision defining responsible persons for legal entities and requiring such persons to undergo background checks. These commenters asserted that the decreased demand for firearm trusts will cause a loss of revenue to law firms and layoffs of law firm employees.
The Department acknowledges that this rulemaking will have some modest impact on the firearms industry; the Department does not agree, however, with the assessment of the many commenters who assert that this rulemaking will have a substantial negative economic impact on NFA industry participants (including manufacturers, dealers, and employees), and on related businesses such as suppliers. The comments asserting that the proposed rule will have substantial negative (and even catastrophic) impacts on the industry are primarily premised on two conclusions, neither of which, in the Department's view, are supported by the facts and circumstances underlying this final rule. The first conclusion is that the CLEO certification requirement in the proposed rule will deter potential purchasers who previously would have chosen to obtain an NFA firearm through a trust or legal entity because they could do so without the need for CLEO certification. This conclusion is largely based on assertions that many CLEOs (1) refuse to sign NFA certifications even when the applicant is not prohibited from possessing a firearm; (2) too slowly process certification requests due to resource constraints; or (3) seek to extract political or economic favors from applicants in exchange for signing a certification. As a result of the impediments posed by CLEO certification, the commenters assert, the proposed rule would have resulted in a drastic reduction in the sale of NFA weapons (particularly silencers), thus decimating the NFA industry and greatly harming related industries. The second conclusion is that the demand for NFA firearms will dramatically decrease if a greater number of NFA applicants are required to undergo background checks and to submit fingerprints and photographs. This conclusion is directly linked to the rule's definition of “responsible persons” affiliated with trusts and legal entities; persons meeting that definition will be required under this final rule to undergo background checks and submit fingerprints and photographs when the trust or legal entity they are affiliated with files an NFA application or is a transferee.
The conclusion regarding the impact of CLEO certification has been rendered moot by this final rule. In response to the concerns expressed by commenters relating to CLEO certification, the Department has eliminated that requirement, and replaced it with a less burdensome CLEO notification requirement. Hence, obtaining CLEO certification is no longer a hurdle for individuals, trusts, or legal entities acquiring an NFA firearm, and therefore the problems identified by the commenters with respect to the CLEO certification process are no longer a factor threatening the economic health
With respect to the commenters' conclusion regarding background checks, the Department believes the reality of the firearms marketplace refutes the conclusion that background checks will deter individuals from acquiring NFA firearms. Background checks, a vital law enforcement tool that ensures prohibited persons will not unlawfully obtain firearms, are already conducted on virtually all non-licensed individual persons who purchase either a GCA or NFA firearm from an FFL or FFL/SOTs. Notwithstanding these checks, both the GCA and NFA firearms markets are flourishing. Background checks do not significantly deter non-prohibited individuals from purchasing firearms from licensed dealers, including NFA dealers and manufacturers.
Other market conditions also refute the concerns about the proposed or final rule threatening the viability of NFA dealers and manufactures. Many States have been relaxing prohibitions on ownership of silencers, SBRs, and SBSs, thus expanding the market for these NFA firearms. In addition, the firearms industry is constantly introducing new and improved models. As evidence of this, the Shooting, Hunting and Outdoor Trade (SHOT) Show is attended annually by more than 62,000 industry professionals from the United States and many foreign countries, seeking information on new firearms and shooting products. This is a clear market signal that demand for innovation and development of new firearms and shooting products, including NFA products, is strong, and will continue to support NFA manufacturers and dealers regardless of whether or when the final rule is implemented. Additionally, demand for silencers has continued to increase as several States have recently legalized ownership of silencers for hunting and self-defense; the trend of States legalizing silencer ownership appears likely to continue. Consequently, the Department anticipates demand for silencers will continue to rise. Finally, some States have recently relaxed laws restricting the possession of SBRs and SBSs, thereby increasing the potential market and demand for these NFA items.
The Department also disagrees with comments that FFLs will be hurt because they reserve inventory without payment during the application process. An FFL may choose, as part of its business practice, to require payment in full on an NFA firearm before an application may be submitted. Additionally, ATF posts the processing time for NFA items on its Web site so a purchaser may determine the approximate time necessary to process the application. Due to the nature of the application process, some risk that a new model will be introduced prior to the approval of a customer's purchase is inherent; the new rule, however, does not materially increase that risk.
The Department also rejects comments asserting that this rulemaking is intended to limit or prevent ownership of NFA items by persons who are not prohibited from receiving or possessing them. This final rule is intended to ensure only that persons acquiring and having access to NFA firearms are not prohibited from receiving or possessing them. Furthermore, in response to commenters who asserted that the decreased demand for firearm trusts will cause a loss of revenue to law firms and layoffs of law firm employees, a formation of a trust or other legal entity is not required to acquire an NFA firearm. Therefore, comments on the loss of income for attorneys who draft these documents is outside the scope of this rulemaking.
Several commenters took issue with ATF's assertion that the proposed rule would cause only a minimal burden to industry. In sum, these commenters explained that the proposed rule will be more than minimally financially burdensome to the industry because it will cause customers to stop buying NFA items due to the extended wait times and increased regulatory burdens created by the rule, thus making it less profitable for licensees to hold their SOT status.
According to some commenters, as a result of the proposed regulation, some retailers are facing shutdowns, others face employee lay-offs, and all licensees and related-industries are bracing for revenue reduction. Some commenters stated the proposed rule unreasonably burdens commerce because of the cost of fingerprinting and passport photographs for every purchase. A commenter stated the proposed rule will make it more difficult for local businesses to sell items that are already difficult to obtain. Finally, a commenter argued that the proposed rule is so burdensome it will deter citizens from acquiring NFA items through the approved government process, and encourage the rise of a black market in NFA items. Several commenters claimed it will take about two or three additional hours of customer service assistance per transaction to handle the additional fingerprint cards, photographs, and application paperwork should the NPRM be implemented. One commenter estimated three additional customer service hours would be needed while others estimated two hours would be needed.
Applicants who purchase NFA firearms in an individual capacity have long paid the costs of fingerprints and photographs; the final rule equitably extends these costs to trust and legal entity applicants, and reasonably limits the photograph and fingerprint requirements to responsible persons of the trust and legal entity applicants. The Office of Management and Budget, when granting the renewal of the ATF Forms 1, 4, and 5, has determined that the cost of fingerprints and photographs is not an unreasonable burden. To the extent commenters have asserted that requiring responsible persons to submit fingerprints and photographs is more burdensome than the requirement for individuals because a trust or legal entity may have multiple responsible persons, the option exists for the applicants who have formed trusts or legal entities for the express purpose of acquiring NFA firearms to forego use of a trust or legal entity and acquire the NFA firearm in an individual capacity. The formation of a trust or legal entity is not required to purchase an NFA firearm. For corporate applicants, the costs associated with submitting fingerprints and photographs for responsible persons is a reasonable cost of doing business; for trusts or legal entities that acquire NFA firearms to allow multiple individuals to possess and use the same firearm (each of whom will therefore be a responsible person), the cost of submitting fingerprints and photographs for each of those persons is directly related to the statutory goal of ensuring prohibited persons do not possess and use NFA firearms.
The Department also notes that, as has been explained elsewhere, the Department predicts that the rule's impacts on demand for NFA firearms will be minimal and the costs to trusts and legal entities will be low.
The final rule also simplifies the process of acquiring an NFA firearm by eliminating the CLEO certification requirement for all applicants or transferees and replacing it with a less burdensome notification requirement. Similarly, the final rule has clarified the “responsible person” definition to ensure it does not extend to all members of a trust or legal entity (
A commenter observed that the proposed rule will be expensive to implement for the firearms industry. Another commenter warned that ATF failed to take into account the fact that the proposed rule will also have an adverse financial impact on those who manufacture and sell or transfer NFA firearms. At least one commenter stated ATF failed to consider the significant revenue losses the proposed rule would impose on small businesses. Another commenter disagreed with ATF's assertion that the proposed rule will not affect small businesses. A commenter who works for a firearms business stated, “[I] manage a small business that holds an FFL and deals in NFA devices. . . . All (100%) of our customers utilize legal entities to lawfully obtain NFA firearms. Since the proposed rule change our business in selling NFA firearms has dropped to zero as our customers do not want to spend money with the risk that they may not be able to take delivery of the NFA item. That drop translates into loss of revenue for my small business, distributors I buy from, manufacturers of the devices and manufacturers of related equipment.” A commenter who is an employee of a silencer manufacturer stated that the proposed regulation will “surely cripple if not disable our business.” Finally, another commenter asked the question, “what about the manufacturers and vendor of these controlled items who would inevitably lose a substantial amount of business?” That commenter argued that it is foreseeable that businesses involved in the manufacturing and selling of NFA items will suffer from the implementation of the proposed regulation.
The Department believes that any impact on the firearms industry arising from the proposed rule will be insignificant. As noted, the CLEO certification requirement has been changed to a notification requirement, and the definition of responsible person has been clarified. These changes will ensure that the impact on the firearms industry is minimal. Applications postmarked prior to the implementation of the final rule will be processed under the current regulations. Only those applications postmarked on or after the implementation of the final rule will be subject to the new regulations. Therefore, individuals who refuse to purchase NFA items on the basis of their belief that the rule will interfere with their ability to complete the transfer process are mistaken.
A commenter challenged ATF's assessment of the implementation cost of the proposed regulation, saying that ATF failed to assess the loss of revenue from several sources; this commenter continued that ATF failed to consider all of the monetary loss manufacturers, wholesalers, dealers, individuals, and “corporate/trust” entities will incur as a result of the proposed rule. This commenter argued that there will be “perceptional monetary loss” as well. According to this commenter, when law abiding buyers perceive that the transaction will require CLEO certification that cannot be obtained in their area, the potential buyers will not attempt to buy the NFA items because they will believe the CLEO will not approve the sale. The commenter continued that this perception will ultimately lower the number of purchasers, thus creating a monetary loss for the NFA industry.
A commenter stated that the proposed regulation does not adequately address the economic impact to small and medium businesses. This commenter stated that no assessment of this type could be valid without conservative assumptions on the number of lost sales due to these increased restrictions; these restrictions will have a significant and material impact on the number of silencers and other NFA items sold in the United States. This commenter stated that this is likely to cause many businesses (including large, medium, and small businesses) to close and would have a “downstream ripple effect to their suppliers and local communities.” At least one commenter asked the following questions: “can you imagine the damage this will cause to the NFA market? What happens to the value of our items when you indirectly prohibit 90 percent of potential customers from obtaining the item? What happens to the R&D budget for our arms manufacturers when they don't sell anywhere near the volume to their most abundant customer base?”
Another commenter noted that ATF failed to identity the cost associated with lost time from the backlog of applications for both existing and future employees of any company. Another commenter stated the proposed rule will have a considerable and obvious negative impact on the industry by stifling sales and adding significant burdens relating to long term secure storage of pending NFA items. Another commenter stated that the proposed rule will decimate the industry that makes these NFA products for the military and the police because the NPRM will put these companies out of business, making product warranties that the military and police rely on invalid.
The Department agrees that CLEO certification for all responsible persons of trusts or legal entities is not necessary; consequently that requirement has been eliminated in this final rule and replaced with a less burdensome notification requirement. The change from certification to notification will reduce the impact on the firearms industry. The Department believes that the impact on demand for NFA firearms arising from the rule will be slight. Please see section IV.E.2.a above for additional detail regarding the Department's response to claims this rule will negatively impact NFA manufacturers, dealers, and related businesses.
The Department does not agree with the commenters who assert that the proposed rule would have a negative effect on NFA firearms suppliers to the military and police. Government entities are exempt from the requirements in the rule and therefore neither the NPRM nor the final rule affects this industry. Moreover, because the impact of the rule on the market for NFA firearms will be slight, the Department does not anticipate that military and police suppliers will go out of business as a result of the rule.
The Department recognizes that the final rule will affect processing times and is implementing processes to keep the impact to a minimum. However, processing times do not appear to reduce the demand for NFA firearms. ATF received more than ninety thousand applications in 2014 when processing times were approximately nine months.
Several commenters noted that the proposed rule provided only three “anecdotal” examples occurring over the 80-year life of the NFA to support the need for the proposed rule; they asserted that these examples failed to quantify any expected benefits, raised many questions, and could just as
Other commenters stated that the problems with the proposed rule far outweigh any perceived benefits. One commenter acknowledged the benefit of increasing public safety by preventing prohibited persons from obtaining firearms, but requested that ATF expand its explanation of the benefits the proposed revisions would deliver. This commenter stated that this additional information on benefits would be useful when considering and offsetting the increase in costs from the proposed rule.
Several commenters stated that ATF's assumptions lacked statistical validity. Other commenters stated that the proposed rule lacked evidence to support the proposition that the proposed changes were needed to enhance safety by preventing criminal use of highly regulated NFA items. A commenter asked ATF to provide statistical evidence that the proposed rule would reduce violent crime, and to provide a list of all violent crimes committed with registered NFA weapons by the actual owner of the firearm where these proposed changes would have deterred the crime. Another commenter similarly asked for current statistics on crimes committed by NFA weapons, and how the proposed rule would make citizens safer. This commenter also asked for the studies that ATF did “in conjunction with this legislation,” and asked ATF to provide the studies and specific statistics that support the proposed regulations. Another commenter asked if ATF's three provided examples represent the only examples that ATF has identified since the origin of the NFA in 1934. This commenter requested that ATF clarify its analyses used to support a public safety benefit for the proposed rule since this commenter, and many others, contend that there is no documented violent criminal activity associated with NFA firearms. These commenters noted that the proposed rule would not have applied to the few rare occurrences of violent crime with legally owned NFA registered firearms, as those activities were committed by a non-prohibited person in possession of a properly registered NFA item. Another commenter asked ATF to have “an unbiased third party” show a real risk to public safety through past harms from the use of NFA items acquired via a living trust or legal entity, as well as project future risk trends from the use of such items.
Another commenter referenced a 2001 survey of inmates that showed that less than two percent of inmates used semi-automatic or fully automatic rifles to commit their crimes. This commenter contended that the proposed rule's effect of “tightening restrictions on law abiding citizens” would not reduce this rate, and that ATF did not need to “pass greater legislation to reduce the access of law abiding citizens to weapons and accessories which are registered, carefully monitored, and taxed.”
Between 2006 and 2014, there were over 260,000 NFA firearms acquired by trusts or legal entities where no individual associated with the trust or legal entity was subject to a NFA background check as part of the application process. NFA firearms have been singled out for special regulation by Congress because they are particularly dangerous weapons that can be used by a single individual to inflict mass harm. The Department does not agree that a mass shooting involving an NFA firearm obtained by a prohibited person through a legal entity must occur before these persons must be subject to a background check.
The GCA, at 18 U.S.C. 922(t)(1), requires FFLs to run a NICS check “before the completion of the transfer” of a firearm, and verify the identity of the transferee. There is a limited exception under 18 U.S.C. 922(t)(3)(B) when a firearm is transferred “between a licensee and another person . . . if the Attorney General has approved the transfer under section 5812 of the Internal Revenue Code of 1986.” The purpose of this exception is to avoid multiple background checks on the same individual by exempting a person from a NICS check at the point of transfer when that same person has already been the subject of a background check during the NFA registration process. Congress did not intend for NFA firearms to be transferred to individuals who avoided the background check process altogether. Between November 30, 1998, and August 31, 2015, the FBI's Criminal Justice Information Services Division conducted 216,349,007 background checks using NICS. Of the background checks conducted during this time period, 1,229,653 resulted in a denial. The 99.4 percent “proceed” rate does not negate the public safety associated with the 0.6 percent denied. While the number of NFA applications that are denied due to the background check is small, because even one prohibited individual with an NFA firearm poses an enormous risk to the lives of others, that small number does not negate the public safety associated with denying a prohibited person access to an NFA firearm. Furthermore, requiring a background check on responsible persons of trusts and legal entities during the application process is consistent with Congressional intent for these individuals to undergo a background check to be eligible for the limited exception under 18 U.S.C. 922(t)(3)(B).
Additionally, even though 70 percent of all crime gun traces are on handguns, Federal law (18 U.S.C. 922(t)) requires FFLs to conduct background checks prior to the transfer of long guns (rifles and shotguns) as well as handguns (pistols and revolvers) to unlicensed persons. Thus, Congress did not intend to exclude certain types of firearms from background checks simply because those firearms may be less frequently involved in criminal activity. The Department does not agree that further research is needed to show that a responsible person for a legal entity purchasing a machinegun should be subject to a background check. There is a tangible risk to public safety whenever
See sections IV.E.1.a and E.1.b for responses to comments on the methodology for determining the number of responsible persons and number of pages of supporting documents. See section IV.D.1 regarding responses to comments on Executive Order 12866.
A commenter stated that ATF did not make the NFATCA petition available for public inspection at any time before or during the public comment period for ATF 41P. This commenter noted that ATF cited the NFATCA petition as its basis for the NPRM, and that the petition formed the “central and critical foundation” of ATF's argument for the proposed changes. Noting that ATF did not explain why it withheld this vital information, this commenter called ATF's lack of transparency inexcusable, and stated this inaction warrants further investigation and clarification by ATF.
Another commenter stated that the NPRM indicated that the proposal rested on certain studies and other underlying information, but that such underlying documents (seven categories, including the rulemaking petition; alleged “numerous statements” from CLEOs that ATF received regarding “purported reasons” for denying CLEO certifications, details regarding the instances that prompted the decision that the regulation was needed; and the methodology employed in random samples to estimate the number of responsible persons and the documentation pages) were not placed in the rulemaking docket and, thus, the commenter had requested such documents (and any other documents that ATF replied upon when preparing the NPRM) “[i]n order to ensure an adequate opportunity to comment on the ATF proposal.” The commenter asserted that ATF declined to make public the requested information, and that ATF neither posted materials to the eRulemaking site, nor made them available in ATF's reading room. The commenter also requested the documents via a Freedom of Information Act (FOIA) request without receiving such documents. The commenter stated its concern that omitting these items raised the question of what other pertinent materials may have been excluded. The commenter quoted several legal cases explaining that interested parties should be able to participate in a meaningful way in the final formulation of rules, which would require an accurate picture of the agency's reasoning, which should be done with the agency providing the data used and the methodology of tests and surveys relied upon to develop the NPRM. The commenter continued that case law provides that an agency commits serious procedural error when it fails to reveal the basis for a proposed rule in time to allow for meaningful commentary. Thus, the commenter reasoned that providing access to materials like those it requested has long been recognized as essential to a meaningful opportunity to participate in the rulemaking process. The commenter concluded that the lack of access to the requested materials hindered the ability of interested persons to address the assertions in the NPRM, and that if ATF intends to revise part 479 in the manner proposed, ATF should first lay the foundation for a proposal and then expose that foundation to meaningful critique.
In response to the assertion that the Department withheld the NFATCA petition, the Department references section II of the NPRM that details each of NFATCA's four categories of concern—amending §§ 479.63 and 479.85; certifying citizenship; providing instructions for ATF Forms, 1, 4, and 5; and eliminating the CLEO certification requirement. 78 FR at 55016–55017.
The NPRM explained those aspects of the NFATCA petition that were relevant to the rulemaking. The Department provides the following excerpt from section II.A of the NPRM:
The NFATCA expressed concern that persons who are prohibited by law from possessing or receiving firearms may acquire NFA firearms through the establishment of a legal entity such as a corporation, trust, or partnership. It contends that the number of applications to acquire NFA firearms via a corporation, partnership, trust, or other legal entity has increased significantly over the years. ATF has researched the issue and has determined that the number of Forms 1, 4, and 5 involving legal entities that are not Federal firearms licensees increased from approximately 840 in 2000 to 12,600 in 2009 and to 40,700 in 2012.
In response to the commenter who indicated that ATF did not provide certain documents related to seven categories of information that the commenter deemed essential to meaningfully commenting on the rule, the Department acknowledges that ATF received requests for disclosure of the information from the commenter. Those requests were processed by ATF's Disclosure Division and a copy of the NPRM was provided to the commenter in response to the commenter's request. The response did not include the requested seven categories of information. The Department believes, however, that all of the requested information was discussed and addressed in the NPRM to a degree sufficient to provide the commenter with the opportunity to participate in a meaningful way in the discussion and final formulation of the final rule. The Department did not rely on any data, methodologies, predictions, or analysis that it did not clearly explain in the NPRM. The Department provided commenters “an accurate picture of the reasoning that . . . led the agency to the proposed rule” and “identif[ied] and ma[de] available technical studies and data that it . . . employed in reaching” its decisions.
For example, the Department explained the source and number of samples it used to determine the average number of constitutive documents and responsible persons at trusts and legal entities. The Department cited and relied upon the NFATCA petition that prompted the rulemaking. The Department gave examples of instances in which background check requirements were nearly evaded to show that a risk of circumvention existed. The Department openly discussed the benefits and drawbacks of the CLEO certification requirement and its proposed expansion. Further, specific details about public safety concerns, including specific instances, were included in the NPRM. The Department believes that the details provided in the NPRM were sufficient and, as such, no additional information needed to be placed in the docket.
With respect to CLEO certification specifically, the Department believes that the NPRM amply conveyed ATF's
Finally, the Department emphasizes that it remained open to persuasion throughout the rulemaking. In response to comments critical of the CLEO certification requirement, the Department adopted a CLEO notification requirement. In response to comments critical of various aspects of its statutory and regulatory review and its cost-benefit analysis, the Department expanded and strengthened its analysis and revised its estimates where appropriate. The Department believes that the analysis and responses to comments in this preamble conclusively show that commenters were provided a meaningful opportunity to support, challenge, and critique the proposed rule and help to shape the Department's decision.
A commenter noted that ATF posted an unrelated final rule in the docket for this NPRM at
The Department is unaware of any “extraneous material” in the docket. A Department review of the
A commenter stated that “ATF has a statutory duty to provide public access to members of the public and where . . . access is denied during the very period when the public are supposed to be able to investigate matters as a basis for submitting comments on a proposed rule, ATF has denied a meaningful opportunity to participate in the notice and comment rulemaking process.” The commenter expressed concern regarding the closure of the reading room from November 8, 2013, until November 15, 2013, while ATF was open. The commenter questioned how such a closing was consistent with ATF's duty under FOIA. The commenter also expressed concern that ATF mandated that counsel for commenter submit documentation regarding race, ethnicity, employment history, and other matters before ATF would permit access to its reading room.
This same commenter stated that it physically inspected the docket at ATF's reading room, but that it appeared that only the public comments were available for review. The commenter expressed concern that the physical inspection of the docket also revealed that ATF had “selectively excluded correspondence clearly related to the rulemaking proceeding.” The commenter stated that it identified six items that had not been entered into the docket and requested that all pertinent material be placed in the docket. One such item was posted, but the other five referenced items were not added to the docket prior to commenter's second physical inspection of the docket. The commenter stressed concern that ATF either delayed posting items or ignored its requests.
The Department notes that on September 12, 2013, ATF posted the first comment relative to this NPRM on
Regarding the commenter's portrayal of ATF's reading room being closed November 8, 2013, until November 15, 2013, this is not accurate. The Department acknowledges that a few days elapsed between the commenter's request and his counsel gaining access to ATF's reading room. Regarding the commenter's concern that ATF requested that his counsel provide certain documentation before gaining access to the reading room, ATF notes that this documentation is part of its standard procedures that have been implemented to address public safety concerns and does not meaningfully interfere with access to all of the materials available in the ATF reading room.
A commenter pointed out problems inhibiting access to public to public comments through, for example, (1) the reading room being unavailable, (2) the
The Department determined that an extension of the 90-day comment period was not warranted because it had received a large volume of diverse comments and additional time was unlikely to result in the submission of comments identifying new concerns. Many of the comments ATF received were a repetition or duplication of previous comments. Further, using all resources available, ATF followed the guidelines for public participation that appeared in the NPRM and posted “All comments [that referenced] the docket
A commenter noted ATF's delays in posting comments and that the delays were not uniform. This commenter contended that ATF “conveniently” delayed the posting of the comment the commenter prepared for another individual, which critiqued flaws in the NPRM, while ATF simultaneously “apparently seeded the docket with submissions from proxies.” The commenter stated that once the comment it prepared for another individual was posted, the cause for delays in posting comments, in general, was ameliorated and that comments were continually posted. This commenter also expressed concern that ATF continued to exclude its submissions or delayed posting them to the docket while processing correspondence and comments from other interested persons, which raised a question regarding “what other material submitted for the docket by other interested persons was not properly posted.” The commenter stated that its communications to ATF regarding the rulemaking only occasionally received a reply, only sometimes were placed in the docket, and only sometimes were posted promptly. Despite commenter's inquiries, ATF declined to provide any explanation for the “seemingly arbitrary management of the docket.”
Another commenter stated that ATF repeatedly delayed posting comments, and that this significantly impacted his ability to meaningfully participate in the comment process. This commenter observed that well past the government shutdown, 25–50 percent of the comments received had not been posted; during other periods when the government was not shutdown, four or five days passed without ATF posting any comments even though the total comments received increased every day.
The Department stresses that it posted all comments that followed the public participation guidelines in the NPRM. ATF followed its processes for reviewing and posting comments.
A commenter stated that ATF had proxies submit comments “in an effort to bolster the suggestion of prior misuse of legal entities” and listed examples of comments from ATF Special Agent Gregory Alvarez and John Brown, President of NFATCA. This commenter stated that ATF did not disclose its relationship with John Brown or reveal that the only information John Brown offered in his public comment is “what ATF leaked to him.”
Neither the Department nor ATF uses or recruits “proxies.” Both the Department and ATF are committed to a robust, candid rulemaking process and have an interest only in authentic public comments.
A commenter stated that ATF has a well-documented record of “spinning” facts and engaging in outright deception of the courts, Congress, and the public. As a result, this commenter believes there is even more reason for ATF to provide the documentation showing its basis for characterizing the issues in the NPRM, that it fairly considered alternatives, that it only inadvertently provided potentially misleading information or omitted pertinent information from the docket, that it only accidentally failed to consider requests for extension of the comment period, and that it had no knowledge that commenters with a connection to ATF would act to bolster “ATF's unsupported assertions.”
The commenter purported to provide instances where: (1) ATF committed blatant “institutional perjury” in the context of criminal prosecutions and in support of probable cause showings for search warrants; (2) ATF delayed answering questions or provided deceptive answers to congressional inquiries about NFRTR inaccuracies and the “Fast and Furious” gun-walking operation, for example, and published proposed rules in flagrant disregard to limitations on appropriations; and (3) ATF misled the public about the accuracy of the NFRTR.
The Department notes that ATF has committed available resources to develop this NPRM and respond to comments as part of the rulemaking process. In developing this rulemaking and responding to comments, ATF has followed all established regulatory procedures and complied with all relevant policies and requirements.
A commenter identified prior communications with ATF employees in August 2013, prior to the proposed rule's publication in September 2013, regarding whether a rule finalizing the proposed changes in the NPRM would only apply to applications submitted after the effective date of the regulation, and stated that these communications indicated that such would be the case. However, this commenter stated that the text of the proposed rule was not clear on this matter and ATF had “needlessly confused the public” and potentially falsely reassured persons interested in filing comments. This commenter noted that several commenters expressed concern with the “grandfathering” or transition issues. A few commenters specifically asked whether ATF would grandfather any trusts or legal entities where the applications have been sent in, the $200 tax stamp check has been cashed, and the application is “pending” prior to the effective date of the final rule. A few commenters asked what would happen to pending or “in limbo” applications, and if the applications would be sent back to the applicants. Several commenters suggested—or would want to ensure—that ATF “grandfather in” (
A few commenters asked if existing legal entities and trusts holding NFA items must submit to ATF fingerprints, photographs, and CLEO certifications for each responsible person or if they would be grandfathered. Another commenter pointed out that the proposed rule did not provide a cost estimate to bring the “many thousands” of existing trusts and corporations into compliance with the new rule, and therefore surmised that past transfers would be grandfathered. If this is not the case, this commenter suggested that ATF publicly disclose such a cost estimate. This commenter stated that it could take months for a large corporation, which routinely purchases and sells NFA weapons, to establish policies and bring the entire workforce into compliance. This commenter asked whether employees who have been approved as responsible persons could continue conducting business while other employees were pending approval as responsible persons, and presumed that ATF would answer affirmatively. Finally, this commenter asked if ATF has estimated, even internally, the ATF staffing level and expansion of staff required to implement these new rules considering that the current wait time for Form 4 transfers and Form 3 (dealer to dealer) transfers is six to nine months, and three months, respectively, and the proposed rule, if finalized, would result in a “likely substantial” additional workload for ATF.
The final rule is not retroactive and therefore the final rule will not apply to applications that are in “pending” status, or to previously approved applications for existing legal entities and trusts holding NFA items. The Department has considered the additional costs to ATF as a result of this rule, which are detailed in section VI.A below.
Several trade association commenters, as well as individuals, encouraged ATF to withdraw the proposal. One of these commenters, a trade association, suggested that ATF work with makers, sellers, and users of NFA firearms to develop a rule that is more realistic and addresses the real needs of all those concerned. Another trade association urged ATF to withdraw or substantially rewrite the rule. Both trade associations requested that ATF hold a public hearing to ensure that all views and comments are fully heard. An individual commenter requested a hearing, or series of hearings around the country. In addition, another of these commenters advised ATF to focus on streamlining the NFA application process and reducing the stress on local law enforcement.
The Department does not believe that soliciting additional information and views from the public, either through informal meetings to further refine the scope of the rulemaking, or through public hearings, are necessary or appropriate.
The Department notes that the proposed rule included four direct, clear objectives:
1. Defining the term “responsible person,” as used in reference to a trust, partnership, association, company, or corporation;
2. Requiring responsible persons of such legal entities to submit,
3. Modifying the information required in a law enforcement certification to relieve the certifying official from certifying that the official has no information indicating that the maker or transferee of the NFA firearm will use the firearm for other than lawful purposes; and
4. Adding a new section to ATF's regulations stipulating that the executor, administrator, personal representative, or other person authorized under State law to dispose of property in an estate may possess a firearm registered to a decedent during the term of probate without such possession being treated as a “transfer” under the NFA, and specifying that the transfer of the firearm to any estate beneficiary may be made on a tax-exempt basis.
ATF received nearly 9,500 responses from diverse public commenters, including professional associations, lobbying groups, and individuals, and the Department has afforded full consideration to these comments in formulating this final rule. Further, the Department's receipt and review of this volume of comments provides the Department with a complete array of comments likely to arise in a public hearing, making additional public events redundant. A public hearing, or even a series of them, will only serve to provide the Department information it has already collected without delivering new insights.
Many commenters stated that there is nothing wrong with the current system, and believed that the only change needed is to speed up the NFA approval process. Many remarked on the huge backlog of pending NFA applications and that it takes months to well over a year for the NFA Branch to process Form 1 and Form 4 applications. A commenter thought that speeding up the process was especially essential for a person trying to register a second item. Several commenters stated that if ATF and the Department really wanted to improve the NFA process, they should modernize the current process and upgrade their systems to permit electronic forms that need to be filled out only once, and “upgrade systems” and utilize technology so that after the initial NFA approval, ATF could access and use “data” and “background checks” already on file to further speed up the process for subsequent transfer requests.
Several commenters stated that ATF needed to hire more people (
Another commenter stated that the process should only take a few days at most to process instead of the current “months” processing time. Another commenter suggested that ATF implement a maximum approval time of 30 days, and that if ATF has taken no action in that time, the application should be automatically approved. Another commenter suggested that the process be no longer than three months by default.
In addition to their suggestions on speeding up the process, a few commenters suggested that ATF decrease the tax stamp costs. A commenter asked, “if I have an individual tax stamp why do I have to pay again to move it to a trust that I set up?” Another commenter suggested that ATF draft new regulations to change the tax stamp costs for all NFA items from $200 to $5. Another commenter suggested that ATF either reduce the $200 tax stamp cost to $50 or eliminate it altogether. Another commenter added that a reduction of the tax stamp cost would increase ATF's revenues and the “tax basis” of the firearms industry.
The Department and ATF are committed to processing NFA forms as efficiently and expediently as possible considering that an ever-increasing number of forms are submitted. In FY 2010, ATF's NFA Branch processed almost 92,000 forms (Forms 1, 2, 3, 4, 5, 9, 10, and 5320.20). In FY 2014, the number of forms processed increased to over 236,000, an increase of 250 percent. As a result of this increase, ATF has dedicated more staffing to the NFA Branch, increasing the number of legal instruments examiners from 9 to 27. Research assistants were provided to the examiners to research and resolve problems. Data entry staffing has been increased. Similarly, customer service representative staffing has been increased so that examiners are not pulled away from their tasks, and can respond quickly to the public and industry.
ATF has approved overtime in an effort to increase the forms processing rate and has brought in staffing on detail to process forms. In February 2014, the forms backlog was over 81,000 forms. As of October 7, 2015, the backlog has been reduced to just over 51,000. The time frame for the processing of each type of form has also decreased (note: since each form has a different purpose, the processing times vary). Processing times for Forms 1 and 4, for example, have been reduced from nine months to approximately five months.
ATF has used technology to help make the process quicker and more efficient. In 2013, ATF introduced an electronic filing system (eForms) designed to allow forms to be filed more accurately, and more quickly, with immediate submission into the NFA system for processing. This reduces data entry demands otherwise required with paper forms. The eForms system, however, was not designed to allow the filing of forms where fingerprints, photographs, and the law enforcement certification were required. However, it did allow the filing of forms by trusts or legal entities, such as LLCs. After several months of operation, the system encountered complications. It was taken out of service for a brief period and then brought back up over a period of time. To preclude further complications, the highest volume forms submitted, Forms 3 and 4, have been kept out of service while ATF seeks to implement a new system with a more robust platform to process these forms and others in the existing eForms system. This process continues at the present time.
Some commenters stated that ATF should modernize the process and utilize technology so that data and background checks can be used for subsequent transfer requests. The Department agrees and, resources permitting, will look to design systems that will utilize information on file.
Budget allowing, the Department and ATF anticipate a staffing increase for the NFA Branch in FY 2016. As stated above, over the past two years, ATF has committed additional resources to address the increase in applications submitted to the NFA Branch. The legal instrument examiner staffing has been tripled to 27 positions. However, the rate of submission continues to increase from almost 164,000 forms in CY 2013, to 236,000 in CY 2014 and a projected total of 322,000 in CY 2015.
Because the tax rate is set by statute, ATF has no authority to change it. The NFA provides very limited authority to permit exemptions from the transfer tax, but commenters' requested exemptions do not fall within that authority. ATF is also precluded by law from utilizing the taxes generated, as the making, transfer, and special (occupational) tax revenues are deposited into a general Treasury fund. In regard to a transfer between an individual and a trust, the NFA imposes a tax on the transfer of an NFA firearm. A trust is a separate “person” and, thus, the transfer from the individual to a trust is a taxable “transfer” under the statute and is subject to tax.
The majority of commenters thought that the proposed rule would do nothing to lessen crime and gun violence and suggested that ATF first focus its efforts in other directions. A few commenters stressed educating children about gun safety, and stated that this could be done by parents and not on a Federal level. A few commenters urged the reduction or elimination of gun-free zones. A few commenters suggested that gangs are a problem for gun violence and crime, and that more time be spent addressing the causes of gang violence. Other commenters mentioned “Operation Fast and Furious” and suggested that ATF focus on “clean[ing] up [its] own house before attacking lawful gun owners.”
Several commenters believed that mental health issues greatly needed more attention, including more accessible and affordable resources and better screening, with commenters calling the mental health system “crippled” and a “failure.” A few commenters noted that the problem in the most recent mass gun murders has been mental health, and that the focus of prevention efforts should be on the “unrestricted mental capacity” of citizens who cannot understand and obey laws, not the tool (firearms) used in the crime. A commenter suggested that the Department devote time and efforts to enact regulations for mental health; another commenter suggested working on the “mental health aspect” of people obtaining firearms. Another commenter suggested that gun purchasers take a mental exam. Another commenter suggested spending money to educate people about the signs of severe mental illness. Another commenter desired a national database, consisting of criminal offenders and mental health patients, released to each State's police force and the FBI.
Many commenters also stated that the administration, the Department, and ATF should better enforce the laws already on the books, modify the current NICS instant check system to include mental health mandatory reporting, stiffen penalties, and stop handing out plea deals to people who violate the laws. Another commenter noted the items listed in the NFA constitute less than one percent of all firearm felonies, and questioned why ATF would go after the “smallest portion of a problem.” This commenter suggested that ATF go after the criminals and not law-abiding citizens. Another commenter suggested that ATF focus on repeated felonies.
Another commenter suggested that an NFA passport book be issued to each individual or trust that has completed an NFA background check. This passport book would be presented after paying the tax, at the time of the item's purchase. A stamp would immediately be placed in the passport book and the customer could leave with the purchased item. This commenter added that the check would then be mailed to ATF, and ATF could conduct yearly audits to regulate the passport books.
The Department's ultimate objective in the promulgation of this final rule is to enhance public safety by ensuring prohibited persons do not possess and use NFA weapons— the primary statutory goal of the NFA. Contrary to the comments submitted suggesting otherwise, the objective of this final rule complements, rather than detracts from, the numerous other public safety efforts that the Department and ATF engage in every day.
With the numbers of transactions involving trusts or legal entities increasing, the Department believes the possibility of a prohibited person obtaining an NFA firearm also increases. For example, currently, it is possible that one or more responsible persons at a trust or legal entity are prohibited persons, yet that person could obtain access to an NFA firearm by having someone at the trust or legal entity who is not a prohibited person serve as the subject of the point-of-transfer background check. As noted above, the costs to ATF are detailed in section VI.A, below. ATF is dedicating resources to the processing of the forms currently submitted, and will continue to apply resources to ensure improvements in the process.
The Department considered alternatives, such as the implementation of “passport books” or similar systems, but determined that implementing them would require a statutory change.
In the NPRM, ATF stated that it was considering a requirement that new responsible persons submit Form 5320.23 within 30 days of a change in responsible persons at the trust or legal entity, and sought opinions and recommendations.
This commenter further stated that a continuing obligation to obtain approval from ATF to add each new responsible person would magnify the burdens related to the proposed CLEO certification requirement and the “responsible person” definition, particularly because legal entities have less control over managerial structure changes than they do over a decision about whether and when to acquire or make a new NFA firearm. This commenter believes that non-firearm related factors overwhelmingly dictate changes in personnel and managerial structure, and that complications relating to ensuring compliance with an ongoing designation obligation under the implementing regulations should not impact the personnel and managerial structure of a legal entity.
A few commenters did not recognize that ATF was only considering this change, and thought that this change was being proposed; they included their comments on the issue with comments on the proposed change to CLEO certification for responsible persons. For example, a few commenters stated that the NPRM would impact trustees' abilities to manage trusts because of the proposed requirement that new responsible persons submit a Form 5320.23 and obtain a CLEO sign-off within 30 days of their appointment. A few other commenters stated that, by proposing that any new responsible person submit a Form 5320.23 and obtain a CLEO signoff within 30 days of the new responsible person's appointment, the proposed rule intruded upon the traditional uses of trusts and upon the rights of settlors to manage their estate plans.
Another commenter, noting ATF's long-held position that certain activities, such as the sale of a company, hiring new employees, or adding new trustees are not “transfers” of firearms, stated that the rule change would improperly extend ATF's authority. This commenter stated that ATF and DOJ incorrectly relied on their authority under 26 U.S.C. 5812(a) for the proposed change, because that section only authorizes ATF to collect information on the transferee during a transfer, not to continue collecting information on the transferee (or persons who act on behalf of the transferee) after the application is approved. This commenter asserted that the 30-day rule requirement would enable CLEOs and ATF to veto private decisions that are not the business of the government, and that Congress has not authorized such veto rights. This commenter asked ATF to consider the negative unintended consequences of the 30-day rule requirement, because its imposition would effectively mean a CLEO has to approve the sale of a company where buyers reside, the addition of trustees where trustees reside, the hiring of employees where employees reside, and the membership of an association. Further, this commenter stated that if ATF implemented this change, ATF would be violating First and Second Amendment rights, as well as rights of privacy, when ATF's objective could be achieved by any licensed FFL performing a “discreet, confidential NICS check.” Further, this commenter stated that requiring a legal entity to request and receive permission for all personnel changes would be cumbersome, impacting personnel decisions and greatly increasing hiring costs.
Another commenter stated that a requirement for all responsible persons to submit Form 5320.23 and comply with the CLEO certification within 30 days would be a “radical” departure from trust law and estate planning. As a result, this commenter cautioned ATF to expect long and costly court battles, that ATF would lose, as the proposed requirements would infringe property rights and the ability to pass trust property to legal heirs.
The Department notes that it did not propose to make any changes on this issue in the proposed rule. Rather the Department requested input and guidance relative to identification of
The Department further notes that nothing in this rulemaking has altered the requirement for trusts and legal entities to submit new applications to make or transfer (as applicable) if the trust or legal entity intends to possess additional NFA items, or if there is a sufficient change in control or ownership of the trust or legal entity such that it is considered a new or different entity under relevant law. In either case, at the time of such application, the trust or legal entity will need to identify current responsible persons, who will submit photographs and fingerprints, and undergo a background check.
Refer to section IV.C.1 in this document to review ATF's shift from CLEO certification to CLEO notification—a process that alleviates the potential for administrative backlogs as a result of personnel changes, and any concerns that a CLEO may dictate the operation of an entity.
For the reasons discussed above, this final rule has been revised from the proposed rule to eliminate the requirement for a certification signed by a CLEO and instead add a CLEO notification requirement. The final rule also clarifies that the term “responsible person” for a trust or legal entity includes those persons who possess the power or authority to direct the management and policies of an entity to receive, possess, ship, transport, deliver, transfer, or otherwise dispose of a firearm for, or on behalf of, the trust or entity. In the case of a trust, those with the power or authority to direct the management and policies of the trust includes any person who has the capability to exercise such power and possesses, directly or indirectly, the power or authority under any trust instrument, or under State law, to receive, possess, ship, transport, deliver, transfer, or otherwise dispose of a firearm for, or on behalf of, the trust. The Department has removed “beneficiaries” from the final non-exclusive list in the definition of “responsible person.” However, a beneficiary or any other individual actually meeting the definition of a “responsible person” in the final rule shall be considered one.
Accordingly, because the law enforcement certification will no longer be required, the regulations in §§ 479.63 and 479.85 are being revised to require the applicant maker or transferee, as well as each responsible person, to provide a notice to the appropriate State or local official that an application is being submitted to ATF. The Department also agrees that a change from a CLEO certification to CLEO notification will require a change to the Forms 1, 4, and 5.
This final rule clarifies proposed § 479.62(b)(2) to denote that the required employer identification number for an applicant, other than an individual, may be “if any.” This final rule makes a minor change to proposed §§ 479.63(b)(2)(ii) and 479.85(b)(2)(ii) by removing “Social Security number (optional)” and “place of birth” from the “certain identifying information” required to be submitted on the Form 5320.23 in both of these sections, and clarifying that the “country of citizenship” must only be provided if other than the United States. In addition, this final rule removes “place of birth” from proposed § 479.62(b)(2) for the required Form 1 applicant identity information. This final rule adopts all other proposed changes in the NPRM.
This regulation has been drafted and reviewed in accordance with section 1(b) of Executive Order 12866 (“Regulatory Planning and Review”) and with section 1(b) of Executive Order 13563 (“Improving Regulation and Regulatory Review”). The Department of Justice has determined that this final rule is a significant regulatory action under section 3(f) of Executive Order 12866, and, accordingly, this final rule has been reviewed by the Office of Management and Budget.
This final rule will not have an annual effect on the economy of $100 million or more; nor will it adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or tribal governments or communities. Accordingly, the final rule is not an economically significant rulemaking under Executive Order 12866. The estimated costs and benefits of the final rule are discussed below.
This rule requires certain trusts and legal entities (partnerships, companies, associations, and corporations) applying to make or receive an NFA firearm to submit information for each of its responsible persons to ATF in order for ATF to ensure that such persons are not prohibited from possessing or receiving firearms. ATF estimates a total additional cost of approximately $29.4 million annually for trusts and legal entities to gather, procure, and submit such information to ATF and for ATF to process the information and conduct a background check on responsible persons. These provisions have public safety benefits in that they will enable ATF to ensure that the estimated 231,658 responsible persons within trusts or legal entities that request to make or receive NFA firearms each year are not prohibited from possessing such firearms.
The Department acknowledges that this final rule may increase the time required to process applications received from trusts and legal entities, as well as for individuals, as an increased number of applications undergo more complete checks. The Department estimates that this final rule initially will increase processing times of these applications from four months to six to eight months. However, the Department anticipates that this time will be reduced once the NFA Branch adjusts to the new process. In addition, ATF will work to increase its resources and staffing to process the applications. Of course, continued increases in the numbers of applications submitted may correspondingly continue to place pressure on processing times.
This final rule eliminates the current requirement that all individual applicants obtain a certification from the CLEO for the locality. Instead, under the final rule, applicants seeking to make or receive an NFA firearm are required to notify their local CLEO before they submit the ATF application to make or receive an NFA firearm. Similarly, the final rule does not adopt a requirement that responsible persons obtain a CLEO certification, as was discussed in the proposed rule; instead, the final rule extends the same notification requirement to all responsible persons for each trust and legal entity applicant. ATF estimates the total cost of the CLEO notification requirement in this final rule to be approximately $5.8 million annually ($0.5 million for individuals; $5.3 million for legal entities), as compared to the approximate costs of $2.26 million annually for the current
ATF estimated the cost of the provisions to ensure responsible persons within trusts and legal entities are not prohibited from possessing NFA firearms by: (1) Estimating the time and other resources that would be expended by legal entities to complete paperwork, obtain photographs and fingerprints, and send this information to ATF; and (2) estimating the time and other resources that would be expended by ATF to process and review the materials provided by the trusts and legal entities and to conduct background checks of responsible persons.
ATF estimated the cost of the time for trusts and legal entities to complete these tasks using employee compensation data for June 2015 as determined by the U.S. Department of Labor, Bureau of Labor Statistics (BLS).
ATF used data from CY 2014 to estimate the number of trusts, legal entities, and individuals that would be affected by the final rule. In CY 2014, ATF processed 159,646 applications that were either ATF Forms 1, 4, or 5. Of these, 115,829 applications were for unlicensed trusts or legal entities (
ATF estimated the cost of complying with the final rule's requirements by estimating the cost of undertaking each of the steps necessary to complete an application. Under this final rule, a trust or legal entity is required to complete the following steps in addition to completing the applicable Form 1, 4, or 5 before it is permitted to make or receive an NFA firearm:
1. Complete and submit Form 5320.23 for each responsible person;
2. Submit fingerprints and photographs for each responsible person; and
3. Submit a copy of the documentation that establishes the legal existence of the legal entity.
In addition, under the final rule, information required on the existing ATF Form 5330.20 would be incorporated into the ATF Forms 1, 4, and 5.
The final rule requires trusts and legal entities to complete and submit to ATF a new form (Form 5320.23), photographs, and fingerprint cards for each responsible person before the trust or legal entity is permitted to make or receive an NFA firearm. The information required on Form 5320.23 includes the responsible person's name, position, home address, and date of birth. The identifying information for each responsible person is necessary for ATF to conduct a background check on each individual to ensure the individual is not prohibited from possessing an NFA firearm under Federal, State, or local law.
ATF estimates the time for each responsible person to complete Form 5320.23 to be 15 minutes. Based on an estimate of 2 responsible persons per trust or legal entity and 115,829 entities, the estimated time cost to complete Form 5320.23 is $1,922,182 (15 minutes at $33.19 per hour × 115,829 × 2).
ATF estimates that:
• The cost of the photographs is $11.32 (based on the average of the costs determined for 60 Web sites); and
• The time needed to procure photographs is 50 minutes.
Currently, only individuals must obtain and submit photographs to ATF. Based on an estimate of 29,191 individuals, the current estimated cost is $1,137,816 (Cost of Photographs = $11.32 × 29,191 = $330,442; Cost to Procure Photographs = 50 minutes at $33.19 per hour × 29,191 = $807,374). Under the final rule, costs for individuals would remain the same, but trusts and legal entities would incur new costs. Each responsible person of a trust or legal entity would be required to obtain and submit photographs. Based on an estimate of 2 responsible persons per entity and 115,829 entities, the estimated cost for trusts and legal entities to obtain and submit photographs is $9,029,642 (Cost of Photographs = $11.32 × 115,829 × 2 = $2,622,368; Cost to Procure Photographs = 50 minutes at $33.19 per hour × 115,829 × 2 = $6,407,274).
ATF has reviewed various fingerprinting services. At the present time, ATF is only able to accept
• The estimated cost of the fingerprints is $18.66 (cost based on the average of the costs determined for 275 Web sites); and
• The estimated time needed to procure the fingerprints is 60 minutes.
Currently, only individuals must obtain and submit fingerprints. Based on an estimate of 29,191 individuals, the current estimated cost is $1,513,553 (Cost of Fingerprints = $18.66 × 29,191 = $544,704; Cost to Procure Fingerprints = 60 minutes at $33.19 per hour × 29,191 = $968,849). Under the final rule, costs for individuals would remain the same, but trusts and legal entities would incur new costs. Each responsible person of a trust or legal entity would be required to obtain and submit fingerprints to ATF. Based on an estimate of 2 responsible persons per entity and 115,829 entities, the estimated cost for trusts and legal entities to obtain and submit fingerprints is $12,011,467 (Cost of Fingerprints = $18.66 × 115,829 × 2 = $4,322,738; Cost to Procure Fingerprints = 60 minutes at $33.19 per hour × 115,829 × 2 = $7,688,729).
A trust or legal entity that is applying to make or receive an NFA firearm must provide to ATF documentation evidencing the existence and validity of the entity—
ATF estimates that:
• The cost of the copied documentation is $1.60 ($.10 per page at 16 pages); and
• The time needed to copy attachments is 10 minutes.
Assuming 115,829 entities would provide ATF this documentation each year, the estimated annual cost to submit the documentation is $826,053 (Cost of documentation = $1.60 × 115,829 = $185,326; Cost to copy attachments = 10 minutes at $33.19 per hour × 115,829 = $640,727). This cost is not dependent on the number of responsible persons associated with a legal entity. ATF notes that the estimated cost is likely to be lower if the entity has already filed the documents with ATF as part of a recent making or transfer application and the information previously provided has not changed. Under these circumstances, the entity can certify to ATF that the documentation is on file and is unchanged.
Currently, individuals, trusts, and legal entities must complete and mail Form 1, 4, or 5. This final rule should not change the costs to individuals, trusts, or legal entities to complete such forms. Even if there are multiple responsible persons associated with a trust or legal entity, the trust or legal entity still will be completing and mailing one Form 1, 4, or 5. However, ATF estimates that trusts and legal entities will incur increased postage costs to mail Forms 1, 4, and 5 applications to ATF. Currently, for trusts and legal entities, these applications only contain the completed form itself; ATF estimates postage costs at $56,756 (115,829 × $.49). However, under the final rule, trusts and legal entities must also include Form 5320.23, photographs, and fingerprint cards for each responsible person, as well as documentation evidencing the existence and validity of the trust or entity. ATF estimates postage costs for this complete application package at $113,512 ($115,829 × $.98). Therefore, ATF estimates the new mailing costs for trusts and legal entities, under this final rule, to be $56,756 ($113,512−$56,756).
The estimated costs to legal entities that are discussed above are summarized in Tables B(1) and B(2). The total estimated new cost of the final rule for legal entities to provide to ATF identification information for each of its responsible persons is $23,846,679 annually.
ATF incurs costs to process forms, fingerprint cards, photographs, and to conduct and review background checks. Currently, ATF incurs these costs for the 29,191 applications for individuals to make or receive NFA firearms. Under the final rule, ATF would incur these costs for applications for trusts and legal entities to make or receive NFA firearms. ATF estimates that:
• ATF's cost for the FBI to process a set of fingerprints is $12.75. (The cost is based on the FBI's current fee, which is set by statute on a cost recovery basis.)
• The estimated cost for an examiner at ATF's NFA Branch to conduct and review the results of a background check is $11.06 (15 minutes at $44.22 per hour); and
• The estimated cost to print the new 5320.23 forms is $.0747 per form.
Based on an estimate of 2 responsible persons per legal entity and 115,829 entities, the estimated cost for ATF to process forms, fingerprint cards, photographs, and to conduct and review background checks for applications for legal entities to make or receive firearms is $5,533,082 annually (Cost for processing fingerprints = $12.75 × 115,829 × 2= $2,953,640; Cost for background checks = $11.06 × 115,829 × 2 = $2,562,137; Cost to print forms = $.0747 × 115,829 × 2 = $17,305).
The estimated total additional cost of the final rule for trusts and legal entities to gather, procure, and submit to ATF responsible person forms, fingerprints, photographs, documents to establish existence of trust or legal entity, and Form 1, 4, or 5, and for ATF to process the information and conduct a background check on responsible persons is $29,379,155 annually (Sum of tables B(1), B(2), and C: $16,658,885 + $7,187,188 + $5,533,082 = $29,379,761).
The background check requirement for responsible persons provides at least two important benefits. First, it provides important public safety and security benefits by helping ATF to prevent individuals who are prohibited from possessing firearms from obtaining them. Second, by requiring responsible persons to submit the same information and meet same requirements as individuals who seek permission to make or transfer a firearm, the final rule closes a potential loophole that might otherwise allow individuals to form trusts or legal entities for the purpose of obtaining a firearm they are prohibited from possessing.
This final rule provides important public safety and security benefits by enabling ATF to ensure that individuals who are prohibited from possessing firearms do not obtain them. Existing regulations do not require the identification of responsible persons of a trust or legal entity. Therefore, ATF lacks the necessary information to perform a background check on a person who meets the rule's definition of “responsible person” to determine if that person is prohibited from possessing an NFA firearm. This final rule provides important public safety and security benefits by enabling ATF to identify and perform background checks on such persons.
For example, there may be a number of responsible persons associated with a corporation, LLC, or trust. As noted above, based on a recent review of applications for corporations, LLCs, and trusts, ATF estimates that there are 2 responsible persons associated with such legal entities. One or more of these persons could be a prohibited person,
Under current regulations, the maker or transferee of an NFA firearm typically will bring a Form 1, 4, or 5 to the maker or transferee's local CLEO to obtain the CLEO certification as required on the form and therefore may need to meet with the CLEO. The maker or transferee may need to return to pick up the certified form. ATF estimates that the time needed for the maker or transferee to procure the CLEO certification is 100 minutes (70 minutes travel time and 30 minutes review time with the CLEO).
For CY 2014, of the 159,646 Form 1, Form 4, and Form 5 applications processed by ATF, 115,829 were for trusts or legal entities to make or receive NFA firearms. Trusts and legal entities
The final rule replaces the existing requirement to obtain certification by the local CLEO before submitting an application to make or receive an NFA firearm with a requirement to notify the local CLEO before submitting an application to make or receive an NFA firearm. The notification requirement requires the maker or transferee to mail a copy of the application to the CLEO with jurisdiction over the area of the applicant's residence or, in the case of a trust or legal entity, the CLEO with jurisdiction over the business or trust. In addition, the notification requirement requires all responsible persons for trusts and legal entities to mail a copy of Form 5320.23 to the CLEO for their area of residence, principal office, or business. The effect of this provision is that trusts and legal entities, as well as their responsible persons, are required to provide notification of the proposed making or transfer to their local CLEOs, whereas currently trusts and legal entities and their responsible persons are not required to notify or obtain certification from their local CLEOs. Individuals must only notify their local CLEOs under the final rule, whereas currently they are required to obtain certification from their local CLEOs.
In CY 2014, ATF processed 115,829 applications from trusts and legal entities and 29,191 application from individuals. Under the final rule, each of these applications require CLEO notification. For individuals, the CLEO notification will include a copy of the Form 1, 4, or 5 application, which contains 3 pages for each application. For trusts and legal entities, the CLEO notification will include: (1) For the applicant, a copy of the Form 1, 4, or 5 application, which contains 3 pages for each application; (2) for responsible persons, a copy of Form 5320.23, which contains 2 pages. Form 5320.23 will contain a “copy 1” page for ATF and a “copy 2” page for the CLEO. This means that trusts and legal entities will not need to make copies of Form 5320.23 when mailing Form 5320.23 to the CLEO. All applicants will need to make copies of the application to mail the application to the CLEO.
ATF estimates the cost of CLEO notification for individuals as follows:
• The estimated cost to copy an application to send as a notification to the CLEO is $.30 for each Form 1, Form 4, and Form 5 ($.10 per page for 3 pages). Cost is $8,757 ($.30 × 29,191).
• The estimated cost to mail an application to the CLEO is $.49 (current postage cost). Cost is $14,304 ($.49 × 29,191).
• The estimated cost of the time to copy and mail the application to the CLEO is $5.53 (10 minutes at $33.19 per hour). Cost is $161,426 ($5.53 × 29,191).
• The estimated cost of the time for the CLEO to review the notification is $11.06 (15 minutes at $44.22 per hour). Cost is $322,852 ($11.06 × 29,191).
ATF estimates the cost of CLEO notification for trusts and legal entities as follows:
• The estimated cost to copy an application to send as a notification to the CLEO is $.30 for each Form 1, Form 4, and Form 5 ($.10 per page for 3 pages). Cost is $34,749 ($.30 × 115,829).
• The estimated cost to mail an application to the CLEO is $.49 (current postage cost). Cost is $56,756 ($.49 × 115,829).
• The estimated cost of the time to copy and mail the application to the CLEO is $5.53 (10 minutes at $33.19 per hour). Cost is $640,534 ($5.53 × 115,829).
• The estimated cost of the time for the CLEO to review the notification is $11.06 (15 minutes at $44.22 per hour). Cost is $1,281,069 ($11.06 × 115,829).
• The estimated cost to mail Form 5320.23 to the CLEO is $113,512 ($.49 × 115,829 × 2 (number of responsible persons)).
• The estimated cost of the time to mail Form 5320.23 to the CLEO is $2.77 (5 minutes at $33.19 per hour). Cost is $641,693 ($2.77 × 115,829 × 2 (number of responsible persons)).
• The estimated cost of the time for the CLEO to review the notification is $11.06 (15 minutes at $44.22 per hour). Cost is $2,562,137 ($11.06 × 115,829 × 2 (number of responsible persons) = $2,562,137).
The estimated total cost of the final rule to require notification to the CLEO is $5,837,789 annually (sum of Tables E1, E2, and E3). As shown in Table D, the estimated cost of the current requirement to obtain CLEO certification is $2,260,162. Therefore, the final rule notification requirement results in an estimated cost increase of approximately $3.6 million per year. However, for individuals, the final rule notification requirement results in an estimated reduction of approximately $1.8 million per year ($2,260,162−$507,339 = $1,752,823).
The new law enforcement notification requirement provides at least two important benefits. First, by changing the certification requirement to a notification requirement, the final rule reduces the burdens on individuals and entities who seek to possess firearms in jurisdictions whose chief law enforcement officers either process certifications slowly or refuse to process them at all. Second, by making the same notification requirement applicable to individuals and responsible persons of trusts and legal entities the rule closes a loophole that incentivized individuals to form trusts and legal entities to circumvent the certification requirement.
Under current regulations, individuals must obtain a certification from a CLEO in their jurisdiction stating, inter alia, that the certifying official has no information indicating that possession of the firearm by the individual would be in violation of State or local law, or no information that the individual will use the firearm for other than lawful purposes. Some applicants have found the process of obtaining a CLEO certification burdensome. Additionally, local and State officials have the option of participating or not, and some CLEOs have refused to issue certifications, thereby making it more difficult for applicants and transferees to obtain the needed certification. Requiring only notice, rather than a certification, will benefit applicants and transferees by removing a potentially burdensome impediment to furnishing ATF with a completed application.
Under the current rule, the certification requirement does not apply to trusts and legal entities. Some individuals have therefore created trusts and legal entities to circumvent the certification requirement. This final rule makes the requirements for background checks the same for trusts and legal entities as they now are for individuals. The Department believes the incentive for makers and transferees to create corporations and trusts solely to avoid the CLEO certification requirement will decrease once the certification is no longer required. As noted in the comments above, some CLEOs are reluctant to issue certifications for a variety of reasons. As a result, an individual may decide to establish a trust or legal entity because trusts and legal entities are not required to provide CLEO certifications under current regulations. By eliminating the CLEO certification requirement, this rulemaking will reduce the burden imposed on such individuals. Certainly, there are legal reasons to create a corporation or a trust unrelated to the desire to avoid the certification. The Department therefore believes creation of these trusts and legal entities will continue.
The incorporation of the information required on ATF Form 5330.20 into the existing Forms 1, 4, and 5 reduces the burden upon the applicant or transferee by eliminating an additional form to be completed and filed. The current estimated time to complete the form is 3 minutes. Because the information requested on the forms is the same, any savings result from the applicant not having to attach a separate form. ATF estimates the elimination of the form will reduce the industry costs by $240,661 (145,020 transactions for individuals, trusts, and legal entities × 3 minutes per form saved x $33.19 per
This regulation will not have substantial direct effects on the States, on the relationship between the Federal Government and the States, or on the distribution of power and responsibilities among the various levels of government. The elimination of the CLEO certification reduces the burden on State and local agencies, and its replacement with the notification of the pending application still provides the agency with knowledge of a controlled firearm in its area of jurisdiction. As noted in the benefits section, ATF estimates that the cost of the notification to the agencies will be less than the cost to the agencies of completing the certification. ATF discussed this change with State and local agencies. While agencies will no longer be able to “deny” an application by not completing the law enforcement certification, the agencies will receive a notification and can contact ATF with any issues.
While there would be an increase in the paperwork filed with ATF and an increase in ATF's processing workload, that is balanced by ATF being able to conduct background checks on persons who do not receive background checks under the current regulations. The overall impact on the States will be positive. Therefore, in accordance with section 6 of Executive Order 13132 (“Federalism”), the Attorney General has determined that this regulation does not have sufficient federalism implications to warrant the preparation of a federalism summary impact statement.
This regulation meets the applicable standards set forth in sections 3(a) and 3(b)(2) of Executive Order 12988 (“Civil Justice Reform”).
The Regulatory Flexibility Act requires an agency to conduct a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities.
This rule primarily affects trusts and legal entities that seek to make or acquire NFA firearms and are not making or acquiring them as a qualified FFL. This rule requires responsible persons of trusts or legal entities to undergo background checks and comply with CLEO notification requirements. For CY 2014, ATF processed 115,829 applications from trusts and legal entities that were not qualified FFLs. ATF estimates the cost of implementing the rule will increase the cost for 115,829 trusts and legal entities with an average of 2 responsible persons by $25,333,317 (identification costs for background checks: $23,846,073; CLEO notification costs: $1,487,244) per year.
This rule is not a major rule as defined by section 251 of the Small Business Regulatory Enforcement Fairness Act of 1996.
This rule will not result in the expenditure by State, local, and tribal governments, in the aggregate, or by the private sector, of $100 million or more in any one year, and it will not significantly or uniquely affect small governments. Therefore, no actions are deemed necessary under the provisions of the Unfunded Mandates Reform Act of 1995.
Under the Paperwork Reduction Act, a Federal agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a valid control number assigned by OMB. This final rule revises several existing information collections and creates a new information collection. The existing information collections that are revised are in 27 CFR 479.62, 479.63, 479.84, 479.85, 479.90, 479.90a, and 479.91, which are associated with ATF Forms 1, 4, and 5. Forms 1, 4, and 5 have been approved by the OMB under control numbers 1140–0011, 1140–0014, and 1140–0015, respectively. The new information collection that is being created is associated with ATF Form 5320.23, and is currently in review for approval by OMB prior to the effective date of this final rule. Form 5320.23 requires certain identifying information for each responsible person within a trust or legal entity requesting to make or receive an NFA firearm, including the responsible person's full name, position, home address, date of birth, and country of citizenship if other than the United States. Form 5320.23 also requires a proper photograph of each responsible person, and two properly completed FBI Forms FD–258 (Fingerprint Card) for each responsible person. In addition, Form 5320.23 requires each responsible person to list the full name and complete address of the chief law enforcement officer in the responsible person's locality to whom the responsible person has forwarded the responsible person's completed copy of Form 5320.23.
The estimated total annual burden hours and related information (number of respondents, frequency of responses, costs, etc.) for the revisions to Forms 1, 4, and 5, as well as the new Form 5320.23, appear below.
The current estimated total annual burden hours and related information for Forms 1, 4, and 5 are based upon the current CLEO certification requirements, and the number of applications processed in CY 2012. As this final rule eliminates CLEO certification and adds CLEO notification, the estimated submission times for Forms 1, 4, and 5 for individuals, trusts, legal entities, and Gov/FFL have changed. For example, the revised estimated submission times associated with Form 1 are:
The above estimated times do not reflect that a trust or legal entity must also submit to ATF, as part of each Form 1, Form 4, or Form 5 application, a completed Form 5320.23 for each responsible person, and must provide a copy of completed Form 5320.23 to the CLEO of the jurisdiction for each responsible person. Those times are separately reflected in the estimated submission time of 40 minutes for submission to or by a trust or legal entity of Form 5320.23 (for 2 responsible persons) (30 minutes to complete and include “copy 1” of Form 5320.23 in the Form 1, Form 4, or Form 5 application, and 10 minutes to mail “copy 2” of Form 5320.23 for notification.
With respect to ATF Form 1:
$1,412,597 (fingerprints and photographs ($29.98 × 3,360 (individuals) = $100,732; $29.98 × 43,758 (2 responsible persons) = $1,311,865))
$35,006 (copies of legal entity documents ($1.60 × 21,879))
$24,967.95 (mailing ($.98 each for 25,239 respondents = $24,734.22; $.49 for 477 respondents = $233.73) (current estimated total costs from OMB Information Collection Number 1140–0011: $146,766).
With respect to ATF Form 4:
$6,380,373 (fingerprints and photographs ($29.98 × 25,343 (individuals) = $759,783; $29.98 × 187,478 (2 responsible persons) = $5,620,590))
$149,982 (copies of trust or legal entity documents ($1.60 × 93,739))
$118,786.29 (mailing ($.98 each for 119,082 respondents = $116,700.36; $.49 for 4,257 respondents = $2,085.93) (current estimated total costs from OMB Information Collection Number 1140–0014: $979,645).
With respect to ATF Form 5:
$27,282 (fingerprints and photographs ($29.98 × 488 (individuals) = $14,630; $29.98 × 422 (2 responsible persons) = $12,652))
$338 (copies of trust or legal entity documents ($1.60 × 211))
$5,532.10 (mailing ($.98 each for 699 respondents = $685.02; $.49 for 9,892 respondents = $4,847.08)) (current estimated total costs from OMB Information Collection Number 1140–0015: $25,844).
With respect to ATF Form 5320.23:
Comments concerning the accuracy of these burden estimates for Form 5320.23 and suggestions for reducing the burden should be directed to the Chief, Materiel Management Branch, Bureau of Alcohol, Tobacco, Firearms, and Explosives, 99 New York Avenue NE., Washington, DC 20226, and to the Office of Management and Budget, Attention: Desk Officer for the Department of Justice, Bureau of Alcohol, Tobacco, Firearms, and Explosives, Office of Information and Regulatory Affairs, Washington, DC 20503.
The current estimated costs provided above for Forms 1, 4, and 5 are being revised. ATF has provided OMB with
Copies of the final rule, proposed rule, and all comments received in response to the proposed rule will be available for public inspection through the Federal eGovernment portal,
The author of this document is Brenda Raffath Friend, Office of Regulatory Affairs, Enforcement Programs and Services, Bureau of Alcohol, Tobacco, Firearms, and Explosives.
Administrative practice and procedure, Arms and munitions, Excise taxes, Exports, Imports, Military personnel, Penalties, Reporting and recordkeeping requirements, Seizures and forfeitures, and Transportation.
Accordingly, for the reasons discussed in the preamble, 27 CFR part 479 is amended as follows:
26 U.S.C. 5812; 26 U.S.C. 5822; 26 U.S.C. 7801; 26 U.S.C. 7805.
(a)
(b)
(1) The type of application,
(2) The identity of the applicant. If an individual, the applicant shall provide the applicant's name, address, and date of birth, and also comply with the identification requirements prescribed in § 479.63(a). If other than an individual, the applicant shall provide its name, address, and employer identification number, if any, as well as the name and address of each responsible person. Each responsible person of the applicant also shall comply with the identification requirements prescribed in § 479.63(b);
(3) A description of the firearm to be made by type; caliber, gauge, or size; model; length of barrel; serial number; other marks of identification; and the name and address of the original manufacturer (if the applicant is not the original manufacturer);
(4) The applicant's Federal firearms license number (if any);
(5) The applicant's special (occupational) tax stamp (if applicable); and
(6) If the applicant (including, if other than an individual, any responsible person) is an alien admitted under a nonimmigrant visa, applicable documentation demonstrating that the nonimmigrant alien falls within an exception to 18 U.S.C. 922(g)(5)(B) under 18 U.S.C. 922(y)(2), or has obtained a waiver of that provision under 18 U.S.C. 922(y)(3).
(c)
(d)
(a) If the applicant is an individual, the applicant shall:
(1) Securely attach to each copy of the Form 1, in the space provided on the form, a 2 x 2-inch photograph of the applicant, clearly showing a full front view of the features of the applicant with head bare, with the distance from the top of the head to the point of the chin approximately 1
(2) Attach to the application two properly completed FBI Forms FD–258 (Fingerprint Card). The fingerprints must be clear for accurate classification and should be taken by someone properly equipped to take them.
(b) If the applicant is not a licensed manufacturer, importer, or dealer qualified under this part and is a partnership, company (including a Limited Liability Company (LLC)), association, trust, or corporation, the applicant shall:
(1) Be identified on the Form 1 by the name and exact location of the place of business, including the name and number of the building and street, and the name of the county in which the business is located or, in the case of a trust, the primary location at which the firearm will be maintained. In the case of two or more locations, the address shown shall be the principal place of business (or principal office, in the case of a corporation) or, in the case of a trust, the primary location at which the firearm will be maintained;
(2) Except as provided in paragraph (c) of this section, attach to the application—
(i) Documentation evidencing the existence and validity of the entity, which includes complete and unredacted copies of partnership agreements, articles of incorporation, corporate registration, and declarations of trust, with any trust schedules, attachments, exhibits, and enclosures;
(ii) A completed ATF Form 5320.23 for each responsible person. Form 5320.23 requires certain identifying information, including each responsible person's full name, position, home address, date of birth, and country of citizenship if other than the United States;
(iii) In the space provided on Form 5320.23, a 2 x 2-inch photograph of each responsible person, clearly showing a full front view of the features of the responsible person with head bare, with the distance from the top of the head to the point of the chin approximately 1
(iv) Two properly completed FBI Forms FD–258 (Fingerprint Card) for each responsible person. The fingerprints must be clear for accurate classification and should be taken by someone properly equipped to take them.
(c) If the applicant entity has had an application approved as a maker or transferee within the preceding 24 months, and there has been no change to the documentation previously provided, the entity may provide a certification that the information has not been changed since the prior approval and shall identify the application for which the documentation had been submitted by form number, serial number, and date approved.
(a)
(b)
(1) The type of firearm being transferred. If the firearm is other than one classified as “any other weapon,” the applicant shall submit a remittance in the amount of $200 with the application in accordance with the instructions on the form. If the firearm is classified as “any other weapon,” the applicant shall submit a remittance in the amount of $5;
(2) The identity of the transferor by name and address and, if the transferor is other than a natural person, the title or legal status of the person executing the application in relation to the transferor;
(3) The transferor's Federal firearms license number (if any);
(4) The transferor's special (occupational) tax stamp (if any);
(5) The identity of the transferee by name and address and, if the transferee is a person not qualified as a manufacturer, importer, or dealer under this part, the transferee shall be further identified in the manner prescribed in § 479.85;
(6) The transferee's Federal firearms license number (if any);
(7) The transferee's special (occupational) tax stamp (if applicable); and
(8) A description of the firearm to be transferred by name and address of the manufacturer or importer (if known); caliber, gauge, or size; model; serial number; in the case of a short-barreled shotgun or a short-barreled rifle, the length of the barrel; in the case of a weapon made from a rifle or shotgun, the overall length of the weapon and the length of the barrel; and any other identifying marks on the firearm. In the event the firearm does not bear a serial number, the applicant shall obtain a serial number from ATF and shall stamp (impress) or otherwise conspicuously place such serial number on the firearm in a manner not susceptible of being readily obliterated, altered, or removed.
(9) If the transferee (including, if other than an individual, any responsible person) is an alien admitted under a nonimmigrant visa, applicable documentation demonstrating that the nonimmigrant alien falls within an exception to 18 U.S.C. 922(g)(5)(B) under 18 U.S.C. 922(y)(2), or has obtained a waiver of that provision under 18 U.S.C. 922(y)(3).
(c)
(d)
(a) If the transferee is an individual, such person shall:
(1) Securely attach to each copy of the Form 4, in the space provided on the form, a 2 x 2-inch photograph of the applicant, clearly showing a full front view of the features of the applicant with head bare, with the distance from the top of the head to the point of the chin approximately 1
(2) Attach to the application two properly completed FBI Forms FD–258 (Fingerprint Card). The fingerprints must be clear for accurate classification and should be taken by someone properly equipped to take them.
(b) If the transferee is not a licensed manufacturer, importer, or dealer qualified under this part and is a partnership, company, association, trust, or corporation, such person shall:
(1) Be identified on the Form 4 by the name and exact location of the place of business, including the name and number of the building and street, and the name of the county in which the business is located or, in the case of a trust, the primary location at which the firearm will be maintained. In the case of two or more locations, the address shown shall be the principal place of business (or principal office, in the case of a corporation) or, in the case of a trust, the primary location at which the firearm will be maintained;
(2) Except as provided in paragraph (c) of this section, attach to the application—
(i) Documentation evidencing the existence and validity of the entity, which includes complete and unredacted copies of partnership agreements, articles of incorporation, corporate registration, and declarations of trust, with any trust schedules, attachments, exhibits, and enclosures;
(ii) A completed ATF Form 5320.23 for each responsible person. Form 5320.23 requires certain identifying information, including the responsible person's full name, position, home address, date of birth, and country of citizenship if other than the United States;
(iii) In the space provided on Form 5320.23, a 2 x 2-inch photograph of each responsible person, clearly showing a full front view of the features of the responsible person with head bare, with the distance from the top of the head to the point of the chin approximately 1
(iv) Two properly completed FBI Forms FD–258 (Fingerprint Card) for each responsible person. The fingerprints must be clear for accurate classification and should be taken by someone properly equipped to take them.
(c) If the applicant entity has had an application approved as a maker or transferee within the preceding 24 months, and there has been no change to the documentation previously provided, the entity may provide a certification that the information has not been changed since the prior approval and shall identify the application for which the documentation had been submitted by form number, serial number, and date approved.
(a) The executor, administrator, personal representative, or other person authorized under State law to dispose of property in an estate (collectively “executor”) may possess a firearm registered to a decedent during the term of probate without such possession being treated as a “transfer” as defined in § 479.11. No later than the close of probate, the executor must submit an application to transfer the firearm to beneficiaries or other transferees in accordance with this section. If the transfer is to a beneficiary, the executor shall file an ATF Form 5 (5320.5), Application for Tax Exempt Transfer and Registration of Firearm, to register a firearm to any beneficiary of an estate in accordance with § 479.90. The executor will identify the estate as the transferor, and will sign the form on behalf of the decedent, showing the executor's title (
(b) If there are no beneficiaries of the estate or the beneficiaries do not wish to possess the registered firearm, the executor will dispose of the property outside the estate (
(c) The executor, administrator, personal representative, or other person authorized under State law to dispose of property in an estate shall submit with the transfer application documentation of the person's appointment as executor, administrator, personal representative, or as an authorized person, a copy of the decedent's death certificate, a copy of the will (if any), any other evidence of the person's authority to dispose of property, and any other document relating to, or affecting the disposition of firearms from the estate.