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Consult the Reader Aids section at the end of this page for phone numbers, online resources, finding aids, reminders, and notice of recently enacted public laws.
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Food and Drug Administration, HHS.
Final rule; technical amendment.
The Food and Drug Administration (FDA) is amending its regulations to update the address for applicants to submit biologics license applications (BLAs) and BLA amendments and supplements regulated by the Center for Drug Evaluation and Research (CDER). This action is being taken to ensure accuracy and clarity in the Agency's regulations.
This rule is effective April 2, 2013.
Scott E. Zeiss, Center for Drug Evaluation and Research, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 22, rm. 1120, Silver Spring, MD 20993–0002, 301–796–0639.
FDA is amending 21 CFR 600.2(b) to update the address for applicants to submit BLAs and BLA amendments and supplements regulated by CDER. The new address for all these submissions is CDER Central Document Room, Center for Drug Evaluation and Research, Food and Drug Administration, 5901B Ammendale Rd., Beltsville, MD 20705. This action is being taken to ensure accuracy and clarity in the Agency's regulations.
Publication of this document constitutes final action on these changes under the Administrative Procedure Act (5 U.S.C. 553). FDA has determined that notice and public comment are unnecessary because this amendment to the regulations provides only technical changes to update an address for the submission of BLAs and BLA amendments and supplements.
Biologics, Reporting and recordkeeping requirements.
Therefore, under the Federal Food, Drug, and Cosmetic Act and under authority delegated to the Commissioner of Food and Drugs, 21 CFR part 600 is amended as follows:
21 U.S.C. 321, 351, 352, 353, 355, 360, 360i, 371, 374; 42 U.S.C. 216, 262, 263, 263a, 264, 300aa–25.
Coast Guard, DHS.
Notice of deviation from drawbridge regulation.
The Coast Guard has issued a temporary deviation from the operating schedule that governs the Third Street Drawbridge across the China Basin, mile 0.0, at San Francisco, CA. The deviation is necessary to allow the public to cross the bridge to participate in the scheduled CycleSF, a community event. This deviation allows the bridge to remain in the closed-to-navigation position during the deviation period.
This deviation is effective from 6 a.m. until 10 a.m. on April 28, 2013.
The docket for this deviation, [USCG–2013–0142], is available at
If you have questions on this temporary deviation, call or email David H. Sulouff, Chief, Bridge Section, Eleventh Coast Guard District; telephone 510–437–3516, email
The City of San Francisco requested a temporary change to the operation of the Third Street Drawbridge, mile 0.0, over China Basin, at San Francisco, CA. The Third Street Drawbridge navigation span provides a vertical clearance of 7 feet above Mean High Water in the closed-to-navigation position. The draw opens on signal if at least one hour notice is given as required by 33 CFR 117.149. Navigation on the waterway is recreational.
The drawspan will be secured in the closed-to-navigation position 6 a.m. until 10 a.m. on April 28, 2013, to allow participants in the CycleSF to cross the bridge during the event. This temporary deviation has been coordinated with the waterway users. No objections to the proposed temporary deviation were raised. The drawspan can be operated upon one hour advance notice for emergencies requiring the passage of waterway traffic.
Vessels that can transit the bridge, while in the closed-to-navigation position, may continue to do so at any time. In accordance with 33 CFR 117.35(e), the drawbridge must return to its regular operating schedule immediately at the end of the effective period of this temporary deviation. This deviation from the operating regulations is authorized under 33 CFR 117.35.
Department of Veterans Affairs.
Final rule.
The Department of Veterans Affairs (VA) amends its regulations to establish a new program to provide grants to eligible entities to assist veterans in highly rural areas through innovative transportation services to travel to VA medical centers, and to otherwise assist in providing transportation services in connection with the provision of VA medical care to these veterans, in compliance with section 307 of title III of the Caregivers and Veterans Omnibus Health Services Act of 2010. This final rule establishes procedures for evaluating grant applications under the new grant program, and otherwise administering the new grant program.
David Riley, Director, Veterans Transportation Service, Chief Business Office (10NB), Veterans Health Administration, Department of Veterans Affairs, 2957 Clairmont Road, Atlanta, GA 30329, (404) 828–5601. (This is not a toll-free number.)
On December 30, 2011, VA published in the
Interested persons were invited to submit comments to the proposed rule on or before February 28, 2012, and we received 17 comments. All of the issues raised by the commenters can be grouped together by similar topic, and we have organized our discussion of the comments accordingly. For the reasons set forth in the proposed rule and below, we are adopting the proposed rule as final, with changes to §§ 17.701, 17.703, 17.705, 17.715, and 17.725 and the authority citations following the regulations in this rulemaking.
Multiple commenters objected to the proposed rule's limitation that only VSOs and SVSAs may receive grants. These commenters contended that this limitation would block many existing transportation providers from receiving grants to expand current veterans' transportation services, to the detriment of veterans generally. Commenters asserted that making grants available to any existing transportation provider would ensure that grants would be used more effectively because VSOs and SVSAs that receive grants would only be duplicating transportation services already offered to veterans by existing providers, and because VSOs and SVSAs do not have the expertise of existing transportation providers to access a particular area or transport that area's veterans. We make no changes to the rule based on these comments, because grantees are limited by section 307 to VSOs and SVSAs. Subsection (a)(2) of section 307 identifies as eligible grant recipients “State veterans service agencies” and “Veterans service organizations.” Subsection (a)(3) of section 307 further states that “[a] State veterans service agency or veterans service organization” may use grant funds for specified purposes. We interpret this statutory language to bar VA from awarding grants to any entity other than a VSO or SVSA.
To more specifically address commenter concerns regarding duplicated services and lack of grantee expertise, we note that most commenters seemed to assume that VSOs and SVSAs that receive grants would not themselves be existing transportation providers. However, we know of several VSOs and SVSAs that provide transportation services. Moreover, the rule contains scoring criteria to reward coordination between grantees and other transportation providers (including existing providers that may not qualify to receive grants), and rewarding this type of coordination assists in addressing the general concerns of duplicated services and lack of grantee expertise. See § 17.705(a)(3). Discussion of these coordination criteria, as well as discussion of why VSOs and SVSAs would not merely be duplicating existing transportation services, are provided in greater detail in the next section of this document. Generally, grantees may use grants to expand or augment the transportation services offered by transportation providers that may not qualify as grantees under the rule, or otherwise may use such entities to provide the transportation assistance that is established in a grantee's program, as long as all other criteria of the rule are met.
One commenter specifically asserted that section 307 could be interpreted in an “innovative” manner to allow a grant award to an organization such as a county-level agency within a State that is delegated responsibilities to serve veterans by an SVSA, based on the following language from section 307: “The Secretary of Veterans Affairs shall establish a grant program to provide innovative transportation options to veterans in highly rural areas.” Public Law 111–163, sec. 307(a)(1). We interpret the term “innovative” in section 307(a)(1), however, only as a modifier to describe the types of transportation options that may be provided to veterans in highly rural areas. We do not interpret the term as having any effect regarding the two defined eligible entities that may receive grants under section 307. The plain meaning of a “State veterans service agency” considers only State-level entities, and not a county agency within a State. However, under the same rationale provided above, this rule does not prevent an SVSA from using grant funds to administer transportation assistance through a county-level agency to carry out the objectives of the SVSA's grant application.
One commenter additionally stated that the rule should specifically permit non-profit organizations to apply for and receive grants. We reiterate that only VSOs and SVSAs may apply for and receive grants under section 307, but note that a majority of VSOs function as non-profit entities.
In conjunction with the comments objecting to limiting the grant recipients to VSOs and SVSAs, several commenters stated that the rule should permit, or even mandate, grantee coordination with entities that are not eligible to receive grants, primarily coordination with existing community transportation providers. Commenters argued that such coordination would prevent duplication of transportation services and ensure that experienced existing providers would be utilized, thereby maximizing the efficient provision of transportation services to veterans. As discussed above, nothing in the rule prevents a grantee from coordinating services with entities that are not eligible to receive grants, including other transportation providers. Generally, grantees may use grants to expand or augment the transportation services offered by entities that do not qualify as grantees under the rule, or otherwise may use such entities to provide the transportation assistance that is established in a grantee's program, as long as all other criteria of the rule are met. In fact, scoring criteria in § 17.705(a)(3) encourage and reward coordination with existing transportation providers, by permitting up to 20 additional points to be awarded for an application that shows such coordination.
Although the proposed rule did not prohibit grantees from using grant funds to administer grant programs through other entity types, we recognize that several commenters seemed to misunderstand this point. Therefore, we make clarifying changes to §§ 17.701, 17.703, 17.705, and 17.715. First, we are adding to § 17.701 a definition of “subrecipient” to refer to “an entity that receives grant funds from a grantee to perform work for the grantee in the administration of all or part of the grantee's program.” We believe “subrecipient” clearly covers all entity types that are not eligible to receive grants but that nonetheless may receive grant funds from grantees to administer all or part of the grantees' programs. One commenter noted that this rule should permit “subcontracting” relationships to achieve this same end; the revision to include consideration of “subrecipient” relationships covers subcontracted relationships between grantees and other entities.
Second, §§ 17.703, 17.705, and 17.715 are revised to clarify that subrecipients as defined in § 17.701 may receive grant funds from grantees; to ensure that subrecipients are identified in grant applications and grant agreements as applicable for application scoring and grant award purposes; and to make any identified subrecipients subject to the same standards as a grantee under this rule. We note that under applicable regulations that control grant agreements between VA and other entities, subrecipients of grant funds may be subject to certain standards under 38 CFR parts 43 and 49. See 38 CFR 43.37 and 38 CFR 49.5. A new paragraph (d) is added to § 17.703 as proposed to permit grantees to provide grant funds to other entities, if such entities are identified as subrecipients in grant applications to perform work for grantees in the administration of all or part of grantees' programs. The language “or identified subrecipient” is added to paragraphs (a)(1)(i), (c)(1)(i), (c)(1)(ii), and (c)(2)(i) of § 17.705, related to grant application scoring and grant selection procedures. Paragraph (a)(2) of § 17.715 as proposed is redesignated to paragraph (a)(3), and a new paragraph (a)(2) is added to § 17.715 as proposed to ensure that if a subrecipient is identified in the grant application, such subrecipient must operate the program in accordance with the provisions of this section and the grant application. The language “or identified subrecipient” is added to § 17.715(a)(3)(i) and (ii), related to specific requirements when grant funds are used to procure or operate vehicles. The language “and identified subrecipients” is added to paragraphs (b), (b)(1), and (b)(2) of § 17.715 as proposed, related to additional requirements for VA grants.
We generally agree with commenters that asserted that coordination between grantees and other transportation providers may create more efficient programs. For instance, a grantee partnering with an existing transportation provider to augment or expand the services of that provider could allow for the relatively small amount of funds issued per grant to be used as effectively as possible. As an example, such partnering may preclude the need for a grantee to acquire a fleet of vehicles. Additionally, grantee coordination with existing transportation providers may assist grantees in developing relevant expertise in the provision of transportation services to a particular area and for that area's veterans, if grantees do not already have such experience. However, we do not believe the rule should mandate grantee coordination with any other transportation provider because such a mandate could also ultimately restrict grantees in the planning and administration of their own programs in accordance with the criteria of section 307. For instance, grantee programs under section 307 must be focused on the provision of transportation assistance to veterans in connection with the receipt of medical care, and forced coordination between a grantee and an existing transportation provider could divert grant resources to the transportation of non-veterans or for purposes other than the receipt of medical care. For example, some of the existing transportation providers described by commenters regularly provide transportation services in a broader context and to a broader population of participants than permitted under section 307.
A primary reason put forth by commenters in support of mandatory coordination was that VSOs and SVSAs might use grant funds to duplicate services that already exist, and mandatory coordination would maximize efficiency of such existing programs instead of creating new, potentially redundant programs. We believe this assertion as advanced by commenters assumes that all VSOs and SVSAs seeking grant funds would not themselves already be transportation providers. However, as stated above, we know of several VSOs and SVSAs that offer transportation services, so mandatory coordination with other transportation providers would not be necessary for these grantees. In addition, commenters' insistence on mandatory coordination could apply only in areas that already receive transportation services. The rule's very restrictive population requirement for “highly rural areas,” however, ensures that only the most sparsely populated areas may receive grants. By virtue of their lower population rate, these areas tend to have the least developed community resources, and therefore are not likely serviced by existing transportation providers. To this point, commenters who offered examples of existing
It should also not be assumed that VSOs and SVSAs will merely duplicate the services of existing transportation providers because VSOs and SVSAs will be required to provide transportation for the specific, restricted purpose of increasing veteran access to medical care, and not for the more general purpose of improving the access of a community at large to services that may include medical care. Indeed, commenters who asserted that existing transportation services would be duplicated by VSOs and SVSAs did not also assert that these existing services were only for veterans and only in connection with the provision of VA medical care; rather, these commenters provided examples of existing transportation providers that transported non-veterans as well as veterans, and for purposes other than to receive medical care.
Some commenters argued that grantee coordination with existing transportation groups should be mandatory because such coordination is required under Executive Order 13330, Human Service Transportation Coordination. Executive Order 13330 mandates coordination efforts between certain Federal agencies, including VA, and community transportation systems “to enhance access to transportation to improve mobility, employment opportunities, and access to community services for persons who are transportation-disadvantaged.” 69 FR 9185 (Feb. 26, 2004). One commenter provided a copy of a VA Information Letter 10–2007–006, dated March 2, 2007, which states that pursuant to Executive Order 13330, VA, as part of a Federal Interagency Transportation Coordinating Council on Access and Mobility, adopted a policy statement that resolved as follows:
Federally-assisted grantees that have significant involvement in providing resources and engage in transportation delivery should participate in a local coordinated human services transportation planning process and develop plans to achieve the objectives to reduce duplication, increase service efficiency and expand access for the transportation-disadvantaged populations as stated in Executive Order 13330.
Multiple commenters noted that grant funds would be best used if they were only permitted to supplement or augment the services offered by existing transportation providers, and that grant funds should not be used to create any new transportation services. We reiterate that while coordination with existing transportation providers is encouraged, grants may only be awarded to VSOs and SVSAs, and the rule will not restrict any grantee from using grant funds to initiate transportation services in accordance with the rule's criteria.
In particular, one commenter stated that grant funds would be best used to increase the use of technology to make existing transportation services more easily accessible for veterans, and to ensure these services were provided as efficiently as possible. One example of such technology as provided by the commenter was using grant funds to establish a “one call” center to centralize transportation requests and dispatch transportation services of existing providers. We make no changes based on this comment. Grants may be used to supplement or expand existing technology or create new technology that assists with the delivery of transportation services, versus actually transporting veterans. We reiterate from the proposed rule that section 307 supports awarding grants for programs that may not directly transport veterans, as subsections (a)(3)(A) and (a)(3)(B) of section 307 make clear that an eligible entity may use grant funds to “assist” veterans to travel to obtain VA medical care, or to otherwise “assist” in providing transportation in connection with the provision of care to a veteran. Accordingly, the rule defines “transportation services” to mean “the direct provision of transportation, or assistance with providing transportation, to travel to VA medical centers and other VA or non-VA facilities in connection with the provision of VA medical care.”
A few commenters asserted that the money that is authorized to be appropriated in subsection (d) of section 307 for VA to administer this grant program should be utilized instead to supplement or expand existing VA transportation programs. Specifically, one commenter stated that no data existed to support using funds for this grant program rather than supplementing other existing VA programs, and called on VA to use funds designated in subsection (d) of section 307 to increase fleet vehicles and staffing levels in the Veterans Transportation Service (VTS), and to supplement monetary benefits certain veterans may receive under the VA Beneficiary Travel Program. We make no changes based on these comments, as the grant program objectives have been defined by Congress and VA is not an authorized recipient of grant funds
One commenter stated that the rule should permit vehicles purchased with grant funds to be used to transport individuals, including non-veterans, in connection with activities other than receiving medical care, during the vehicle's idle time or when the vehicle has unused capacity. This commenter contended that such use of vehicles purchased with grant funds would maximize vehicle effectiveness for the benefit of a highly rural area's community at large, and further was required by Executive Order 13330.
As noted above, Executive Order 13330 does not—and should not—control our implementation of section 307. We also note, however, that under applicable regulations that govern grant agreements between VA and other entities, grantees may be required to make equipment procured with grant funds available for use on other projects. See 38 CFR 43.32(c)(2) and 38 CFR 49.34(d) (requiring grantees to make equipment acquired under a grant available for use on other projects or programs supported by the Federal government, provided such use will not interfere with the project or program for which the equipment was originally acquired). This rule already mandates this alternate use requirement for grantees, and subjects SVSAs and VSOs to all other applicable provisions in 38 CFR parts 43 and 49, in § 17.715(b)(1) and (b)(2). See § 17.715(b)(1)–(b)(2) (applying administrative grant requirements under 38 CFR part 43 to SVSAs, and requirements under 38 CFR part 49 to VSOs). The opportunity for grantees to use vehicles procured with grant funds for other programs, in line with these other controlling regulations regarding grant agreements, is therefore covered in the rule and no changes are necessary pursuant to this comment.
Although we note that other applicable regulations may permit the use of certain grantee vehicles for other programs, section 307 is clear that grant funds are to be used to “assist veterans in highly rural areas to travel to Department of Veterans Affairs medical centers” and “otherwise assist in providing transportation in connection with the provision of medical care to veterans in highly rural areas.” Public Law 111–163, sec. 307(a)(3). However, unlike Executive Order 13330, 38 CFR parts 43 and 49 are directly applicable to the grant program mandated by section 307, and as such the rule makes grantees subject to these applicable regulations.
In addition to the general comment concerning vehicles procured with grant funds, one commenter stated that the rule should specifically permit grant funds to be used to transport veterans in connection with employment activities (e.g., job seeking, commuting). We make no changes to the rule based on this comment, but reiterate that 38 CFR parts 43 and 49 permit certain equipment purchased with grants funds to be used to support other Federal programs, in line with the criteria in these other applicable regulations. To the extent such other Federal programs may be related to veteran employment activities, it is possible that vehicles procured with grants under this rule may be used as the commenter suggested, in accordance with 38 CFR parts 43 and 49.
In addition to comments that requested that grants be used to support existing transportation programs for the benefit of communities at large and comments related to the use of vehicles specifically for the community at large, one commenter specifically requested clarification on whether the rule permits a grantee to transport a non-veteran. We reiterate our discussion above that while we generally do not believe Congress intended these funds to be used to transport non-veterans, there may be instances where certain vehicles procured with grant funds could be used to support other Federal programs, potentially to transport non-veterans. This particular comment highlighted the fact that there is no definition of “veteran” in the rule. We therefore amend § 17.701 to include a definition of “veteran” to mean “a person who served in the active military, naval, or air service, and who was discharged or released therefrom under conditions other than dishonorable.” This definition is consistent with 38 U.S.C. 101(2) and other VA regulations, and we believe it is commonly understood among VSOs, SVSAs, and veterans who would be seeking transportation. We also amend § 17.701 to clarify that the definitions therein apply to all of the sections establishing this grant program.
Multiple commenters contended that the rule's criteria regarding a “highly rural area” failed to account for all areas in need of transportation services, or the extent to which such areas may need transportation services. Commenters asserted that these criteria should be revised, and we address below specific suggestions for revisions. Generally, we make no changes based on these comments, as many of the suggested revisions are contrary to section 307.
A majority of commenters argued that the definition of a “highly rural area” was too restrictive because factors other than population density can contribute to veterans' difficulty obtaining transportation, or can create a greater need for such transportation. The factors cited by commenters included areas in which there is widespread low economic status or financial need; high concentrations of residing veterans; older age or other characteristics, such as physical disabilities, which can make accessing transportation difficult; and geographic barriers to transportation such as land formations or bodies of water. Although we do not disagree that these factors may create a need for transportation services in an area that does not meet the highly rural definition in the rule, under section 307 Congress mandated that only areas that consist of a county or counties having a population of less than seven persons per square mile may be serviced by grantees. See Public Law 111–163, sec. 307(c)(1).
Other commenters did not necessarily contend that the rule should permit VA to award grants to service areas that do not meet the definition of “highly rural,” but maintained that the rule's criteria did not assess the need for transportation services even among communities that meet the regulatory definition of a highly rural area. These commenters urged that certain factors such as the number of veterans in any given highly rural area, and such veterans' actual need for VA medical care, should be determinative for purposes of application scoring and awarding of grants. We interpret these comments to argue that greater weight should be given to these factors so that grants could be maximized for only those areas where the most veterans actually reside, and for those areas where the most medical need exists. We make no changes based on these comments. First, nothing in the plain language or legislative history of section 307 compels VA to prioritize awarding grants in this manner. Although it may
One commenter argued that the rule should consider the relative difficulty of establishing transportation services or transportation programs in certain highly rural areas, and factor such difficulty into the scoring criteria and the amount of grant funds awarded. The commenter stated that the current scoring criteria favored those areas where transportation services can be planned and delivered more “easily,” and that certain highly rural areas that are more remote or more difficult to access should be given additional scoring considerations and should receive greater funding. To the extent that the commenter believes that any highly rural area as defined in the rule is easily accessible for purposes of planning or establishing transportation services, we disagree. We believe the narrow definition of a highly rural area creates a presumption that no such qualified area is necessarily easily accessible, because the extremely sparse population requirement likely means that such an area does not have well-developed community resources, to include transportation services. In essence, we believe many of these highly rural areas will be in equivalent standing with regards to accessibility, because many of these areas do not have well-developed transportation services, and in turn are generally not easily accessible by transportation thoroughfares.
However, if certain highly rural areas may be more remote or more difficult to access than others, we believe that the rule considers such relative difficulty with planning and delivering transportation services in § 17.705(a)(4). For instance, § 17.705(a)(4) provides for up to 10 points to be awarded on a grantee application based on the innovative aspects of a program, such as the grantee's use of alternative transportation resources. This particular scoring criterion would be advantageous to any grantee that may in fact need to use non-conventional and alternative transportation methods, specifically because of an area's remoteness or difficulty to access. For instance, taking from examples provided by this commenter, if certain highly rural areas could only be accessed by planes or boats, the need for these non-conventional transportation methods (non-conventional in the context of public transportation), as stated in the application, would allow the grantee to actually score additional points over those areas that may be considered more “easily” accessible (i.e., already accessible by transportation thoroughfares).
The current scoring criteria do not give an undue advantage to any highly rural area over another, because any program that is well planned and proposes to provide transportation services effectively will score well. To address the portion of the comment related to the amount of grant funding an area should receive relative to how “easily” transportation services may be established, we assume that grantees will be requesting varying amounts up to and including the maximum $50,000 amount based on their individual program's needs. VA will not be administering $50,000 as a blanket amount for all grants. The grant application requests a detailed explanation of the program's budget and how the requested amount of funds will be sufficient to completely implement the program, as required under § 17.705(a)(1)(ii) in this rule. We do not make any changes based on this comment.
A few commenters stated that the rule should not limit transportation services only to or from VA facilities, but should permit transportation to and from non-VA facilities that provide care for which VA contracts. We agree with commenters that necessary and preapproved care that is furnished in non-VA facilities may be essential for some veterans in certain rural areas where the nearest VA facility is inaccessible. The definition of “transportation services” in the rule does not limit transportation only to VA facilities, but rather indicates that the care to be received must be VA medical care. See § 17.701. However, we only referred to “VA facilities” in the explanatory portion of the proposed rulemaking, and we understand how this could lead the public to conclude that transportation services may be provided only to VA facilities. To clarify, our intent is to include medical care that is authorized by VA, regardless of whether it is furnished in a VA facility. Accordingly, we clarify the definition of “transportation services” in § 17.701 to mean “the direct provision of transportation, or assistance with providing transportation, to travel to VA medical centers and other VA or non-VA facilities in connection with the provision of VA medical care.” We additionally clarify that under the rule, transportation may be provided to and from any VA health care facility (such as a VA Community Based Outpatient Clinic) and is not limited to VA medical centers. Further, such facilities need not be within the same state that a veteran resides, as there is nothing in section 307 that could be interpreted to restrict transportation in this way.
We agree with the commenter that the rule can more clearly state that for purposes of this rule “VA” medical care includes not only that which VA provides directly but also that which VA authorizes to be furnished in non-VA facilities. Therefore, we revise the definition of the phrase “[p]rovision of VA medical care” in § 17.701 to include reference to sections 1703 and 8153 of title 38, United States Code, which are the statutes that permit VA to contract to furnish specified care to eligible veterans at non-VA facilities. The revision will read as follows: “[p]rovision of VA medical care means the provision of hospital or medical services authorized under sections 1710, 1703, and 8153 of title 38, United States Code.”
One commenter requested clarification on whether grantees may provide vouchers for veterans to travel to the “nearest health care center,” and provided examples of VA and non-VA facilities as the nearest health care centers. We interpret this comment to be asking both about the types of facilities to which veterans may be transported, and also whether grants may be used to
Section 307 instead bases transportation assistance on the relative remoteness of a geographic area, and consequently assumes due to this remoteness that veterans will need assistance accessing medical care. Finally, we note that VA already assists eligible veterans with the cost of transportation associated with their obtaining VA care under VA's Beneficiary Travel Program. See 38 CFR part 70. We recognize that not all veterans are eligible for beneficiary travel benefits. However, we still make no changes to the rule because the use of grant funds for monetary travel assistance would be duplicative of existing VA programs.
We also received a comment regarding whether transportation assistance under this rule is only available to “low-income people.” We clarify that transportation assistance is not limited to veterans with a low income. Although we note that this rule specifically prevents a veteran from being charged for transportation assistance provided by grantees, the prohibition on veterans being charged is not based on a veteran's relative ability to pay for transportation, but rather ensures that veterans can have as much access to services provided by grantees as feasible regardless of their ability to pay. We make no changes based on this comment.
Multiple commenters expressed concern that the rule must provide a means to monitor the use of grant funds and allow recoupment of such funds, as well as a means to monitor the efficacy of grantee programs, to ensure that funds are used appropriately and that veterans have adequate access to transportation services. We agree, and the rule prescribes multiple oversight mechanisms to ensure grant funds are used effectively to transport veterans in accordance with section 307. Section 17.725 as proposed required grantees to provide VA with quarterly fiscal reports on grant funds usage, and annual reports on program efficiency. These reports would provide VA with information necessary to analyze the performance of a grantee's program, and to ensure that grant funds are used appropriately and as specified in the grant agreement. VA's receipt of this and other information required to be reported in § 17.725 would indicate deficient and ineffective use of grant funds. Section 17.725(d) allows VA to request additional information, which would allow VA to conduct additional monitoring as necessary.
In response to commenters' concerns regarding the insufficiency of the monitoring criteria, however, we have revised § 17.725 to require quarterly, in addition to annual, reports to VA related to program efficacy to ensure more stringent monitoring of program efficacy and appropriate use of grant funds. We also revise the heading in § 17.725(a) so that it clearly refers to “program efficacy reports,” versus only an “annual report.” These revisions will assist VA in monitoring program effectiveness more consistently to ensure the efficient and effective use of grant funds so that veterans have access to and are satisfied with transportation services provided under this rule.
In the event that grant funds are not used in accordance with the requirements of the rule and as stated in grant agreements, § 17.730 allows VA to recover grant funds, and further prevents a grantee that misused funds from being issued a grant in the future. We believe the reporting requirements in § 17.725, in conjunction with VA's authority to recover grant funds and prevent the future awards of grants in § 17.730, create a means of monitoring grantees that ensures grant funds will be used effectively to provide veterans with access to transportation services.
One commenter objected that the proposed rule did not set forth the yearly funding limitations for this grant program as indicated in subsection (d) of section 307, and expressed concern that this lack of information in the rule was suspect, and created a risk of excess expenditures to the detriment of the program. The omission of funding limitations from the regulation text was intentional. These restrictions have no bearing on the actual amounts that are authorized to be appropriated for this program under subsection (d) of section 307. See Public Law 111–163, sec. 307(d). As stated in the proposed rule, not including the funding limitation or the limited funding years prevents this rule from appearing to be restricted or ceased beyond fiscal year 2014. Section 307 is not designated by Congress to be a pilot program, and the law does not otherwise contain a provision that it will cease to have effect after a specific date unless extended. If funding is not available to extend the program beyond 2014, we will not publish a subsequent Notice of Fund Availability in the
One commenter objected to the criterion in § 17.702(a) that only one grant may be awarded per highly rural area to be serviced by a grantee. This commenter stated that allowing only one grantee to service a highly rural area essentially permits a grantee to monopolize the transportation services for veterans in that area, and that this creates the potential for the delivery of substandard services. We disagree, as we believe the reporting requirements and ability to recover grant funds that are authorized by §§ 17.725 and 17.730 would prevent any grantee from continuously providing poor service. We reiterate from the proposed rule that we instituted the limitation to one grant per highly rural area to ensure that as many areas are serviced as possible, for the benefit of all veterans that live in these areas across the country.
One commenter contended that grants should be awarded for more than one
One commenter noted that the rule failed to articulate the responsibilities of grantees under the Americans with Disabilities Act (ADA) and implementing Department of Transportation (DOT) regulations. We recognize that grantees and subrecipients may be subject to DOT regulations that implement certain transit requirements under the ADA, and agree with the commenter that this rule should articulate the applicability of these requirements. We revise § 17.715(a)(3), which addresses the specific responsibilities of grantees who procure or operate vehicles with grant funds, to add a new clause (v) to mandate that such vehicles be operated in accordance with applicable DOT regulations concerning transit requirements under the ADA. We note that although VA has no authority to enforce compliance with these other laws and regulations, this revision will permit VA to take action against a grantee for noncompliance with a grant agreement.
Paragraph (a)(2) in § 17.715 as proposed was designated by the heading “[p]rocurement and operation of vehicles.” A descriptive heading such as this may be used in paragraphs within regulations to emphasize or organize information, but should be used consistently to ensure clarity for the reader. However, paragraph (a)(1) of § 17.715 as proposed did not contain such a heading. Therefore, to ensure consistent use of paragraph headings in § 17.715(a), we amend § 17.715(a)(2) as proposed to remove the heading “[p]rocurement and operation of vehicles.” We restate that § 17.715(a)(2) as proposed is also redesignated as paragraph (a)(3) because we have added a new paragraph (a)(2) to address subrecipients. Removing the heading from § 17.715(a)(2) as proposed does not substantively affect the obligation of grantees to ensure certain conditions are met if funds are used to procure or operate vehicles. Additionally, because redesigated paragraph (a)(3) retains the phrase “procure or operate vehicles,” it remains very clear what type of information is contained in the paragraph.
Paragraphs (a), (b), and (c) of § 17.725 as proposed were all designated by headings; however, paragraph (d) was not so designated. Under the same rationale expressed above, we amend § 17.725(d) as proposed to add the heading “Additional reporting.”
In order to establish a parallel structure between paragraphs (a)(1), (a)(2), and (a)(3) in § 17.715, we have removed the phrase “the grantee agrees to” in the last sentence of paragraph (a) which leads into paragraphs (a)(1), (a)(2), and (a)(3). The removal of the phrase “the grantee agrees to” in § 17.715(a) will have no substantive effect on any of the further obligations under the proceeding paragraphs under § 17.715(a). We also revise the beginning of paragraph (a)(1) in § 17.715 as proposed to add the phrase “[t]he grantee must,” so that the subject of § 17.715(a)(1) remains the grantee.
Paragraphs (a)(1) through (a)(2) of § 17.715 as proposed were intended to be items in a series, in the same part of speech or the same type of phrase, and therefore should have been drafted in parallel structure. To reiterate, proposed § 17.715(a)(2) is redesignated in this rule as § 17.715(a)(3). To maintain parallel structure in the rule, we revise redesignated § 17.715(a)(3) to make sense with revised § 17.715(a), and to be parallel with new § 17.715(a)(2), so that it is clear that each paragraph under § 17.715(a) consistently and clearly refers to obligations of a grantee or subrecipient. Redesignated § 17.715(a)(3) will require that “[i]f a grantee's application identified that funds will be used to procure or operate vehicles to directly provide transportation services,” certain specified requirements must be met. The listed requirements are set forth in § 17.715(a)(3)(i) through (v). To maintain parallel structure, we also revise paragraphs (ii) and (iv) of redesignated § 17.715(a)(3) to consistently use the word “must” instead of the words “shall” and “will,” respectively.
Section 17.700 as proposed stated that “[t]his section establishes the Grants for Veterans Service Organizations for Transportation of Veterans in Highly Rural Areas program,” which misidentified VSOs as the only entities for which grants would be administered. We revise § 17.700 to remove the phrase “for Veterans Service Organizations.” This is not a significant change because the proposed rule was clear that grants could be administered to both VSOs and SVSAs in accordance with section 307.
Sections 17.701 and 17.703 mistakenly pluralized VSOs and SVSAs when describing them within the meaning of the singular subject “eligible entity.” We revise §§ 17.701 and 17.703 to refer to “[a] Veterans Service Organization” and “[a] State veterans service agency” with no substantive change. We note that more than one single VSO and one single SVSA may receive a grant under this program per year, as contemplated in and consistent with the proposed rule.
We also clarified the authority citations for the regulations in this rulemaking by specifying section 307 of Public Law 111–163.
For all the reasons noted above, VA is adopting the rule as final with changes as noted to §§ 17.701, 17.703, 17.705, 17.715, and 17.725.
Title 38 of the Code of Federal Regulations, as revised by this final rulemaking, represents VA's implementation of its legal authority on this subject. Other than future amendments to this regulation or governing statutes, no contrary guidance or procedures are authorized. All existing or subsequent VA guidance must be read to conform with this rulemaking if possible or, if not possible, such guidance is superseded by this rulemaking.
The Paperwork Reduction Act of 1995 (44 U.S.C. 3507) requires that VA consider the impact of paperwork and other information collection burdens imposed on the public. According to the 1995 amendments to the Paperwork Reduction Act, an agency may not collect or sponsor the collection of information, nor may it impose an information collection requirement unless it displays a currently valid Office of Management and Budget (OMB) control number.
This final rule will impose new information collection requirements in the form of an application to receive grant funds, and reporting requirements to retain grant funds to include surveys for completion by veteran participants. On December 30, 2011, in a proposed rule published in the
The Secretary hereby certifies that this final rule will not have a significant economic impact on a substantial number of small entities as they are defined in the Regulatory Flexibility Act, 5 U.S.C. 601–612. We do not believe that many small entities such as independently owned taxi cab services or other small transportation businesses frequently or routinely access highly rural areas as defined in the rule, or that such access is often for the express purpose of transporting veterans to VA medical centers or transporting veterans in connection with receiving VA medical care. We believe that veterans in these highly rural areas who must pay for transportation services to receive medical care would seek more conveniently located non-VA care, versus VA care that may require traveling greater distances. There will be no economic impact on any of the eligible entities, as they are not required to provide matching funds to obtain a grant as stated in section 307. Therefore, pursuant to 5 U.S.C. 605(b), this rulemaking is exempt from the initial and final regulatory flexibility analysis requirements of sections 603 and 604.
Executive Orders 12866 and 13563 direct agencies to assess the costs and benefits of available regulatory alternatives and, when regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, and other advantages; distributive impacts; and equity). Executive Order 13563 (Improving Regulation and Regulatory Review) emphasizes the importance of quantifying both costs and benefits, reducing costs, harmonizing rules, and promoting flexibility. Executive Order 12866 (Regulatory Planning and Review) defines a “significant regulatory action” requiring review by OMB as “any regulatory action that is likely to result in a rule that may: (1) Have an annual effect on the economy of $100 million or more or 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; (2) Create a serious inconsistency or otherwise interfere with an action taken or planned by another agency; (3) Materially alter the budgetary impact of entitlements, grants, user fees, or loan programs or the rights and obligations of recipients thereof; or (4) Raise novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles set forth in this Executive Order.”
The economic, interagency, budgetary, legal, and policy implications of this regulatory action have been examined, and it has been determined not to be a significant regulatory action under Executive Order 12866.
The Unfunded Mandates Reform Act of 1995 requires, at 2 U.S.C. 1532, that agencies prepare an assessment of anticipated costs and benefits before issuing any rule that may result in the expenditure by State, local, and tribal governments, in the aggregate, or by the private sector, of $100 million or more (adjusted annually for inflation) in any one year. This final rule will have no such effect on State, local, and tribal governments, or on the private sector.
The Catalog of Federal Domestic Assistance numbers and titles for the programs affected by this document are 64.009, Veterans Medical Care Benefits; 64.011, Veterans Dental Care; 64.012, Veterans Prescription Service; 64.013, Veterans Prosthetic Appliances; 64.014, Veterans State Domiciliary Care; and 64.035, Veterans Transportation Program.
The Secretary of Veterans Affairs, or designee, approved this document and authorized the undersigned to sign and submit the document to the Office of the Federal Register for publication electronically as an official document of the Department of Veterans Affairs. John R. Gingrich, Chief of Staff, Department of Veterans Affairs, approved this document on January 28, 2013, for publication.
Administrative practice and procedure, Grant programs-health, Grant programs-veterans, Health care, Health facilities, Medical devices, Mental health programs, Reporting and recordkeeping requirements, Travel and transportation expenses, Veterans.
For the reasons stated in the preamble, VA amends 38 CFR part 17 as follows:
38 U.S.C. 501, and as noted in specific sections.
This section establishes the Grants for Transportation of Veterans in Highly Rural Areas program. Under this program, the Department of Veterans Affairs (VA) provides grants to eligible entities to assist veterans in highly rural areas through innovative transportation services to travel to VA medical centers,
For the purposes of §§ 17.700–17.730 and any Notice of Fund Availability issued pursuant to such sections:
(1) A Veterans Service Organization, or
(2) A State veterans service agency.
(a)
(b)
(c)
(d)
(a)
(1) A Veterans Service Organization.
(2) A State veterans service agency.
(b)
(c)
(d)
(a)
(1) VA will award up to 40 points based on the program's plan for successful implementation, as demonstrated by the following:
(i) Program scope is defined, and applicant has specifically indicated the mode(s) or method(s) of transportation services to be provided by the applicant or identified subrecipient.
(ii) Program budget is defined, and applicant has indicated that grant funds will be sufficient to completely implement the program.
(iii) Program staffing plan is defined, and applicant has indicated that there will be adequate staffing for delivery of transportation services according to the program's scope.
(iv) Program timeframe for implementation is defined, and applicant has indicated that the delivery of transportation services will be timely.
(2) VA will award up to 30 points based on the program's evaluation plan, as demonstrated by the following:
(i) Measurable goals for determining the success of delivery of transportation services.
(ii) Ongoing assessment of paragraph (a)(2)(i), with a means of adjusting the program as required.
(3) VA will award up to 20 points based on the applicant's community relationships in the areas to receive transportation services, as demonstrated by the following:
(i) Applicant has existing relationships with state or local agencies or private entities, or will develop such relationships, and has shown these relationships will enhance the program's effectiveness.
(ii) Applicant has established past working relationships with state or local agencies or private entities which have provided transportation services similar to those offered by the program.
(4) VA will award up to 10 points based on the innovative aspects of the program, as demonstrated by the following:
(i) How program will identify and serve veterans who otherwise would be unable to obtain VA medical care through conventional transportation resources.
(ii) How program will use new or alternative transportation resources.
(b)
(1) VA will rank those applications that receive at least the minimum amount of total points and points per category set forth in the Notice of Fund Availability. The applications will be ranked in order from highest to lowest scores.
(2) VA will use the applications' ranking as the basis for awarding grants. VA will award grants for the highest ranked applications for which funding is available.
(c)
(1) VA will award up to 55 points based on the success of the grantee's program, as demonstrated by the following:
(i) Application shows that the grantee or identified subrecipient provided transportation services which allowed participants to be provided medical care timely and as scheduled.
(ii) Application shows that participants were satisfied with the transportation services provided by the grantee or identified subrecipient, as described in the Notice of Fund Availability.
(2) VA will award up to 35 points based on the cost effectiveness of the program, as demonstrated by the following:
(i) The grantee or identified subrecipient administered the program on budget.
(ii) Grant funds were utilized in a sensible manner, as interpreted by information provided by the grantee to VA under § 17.725(a)(1) through (a)(7).
(3) VA will award up to 15 points based on the extent to which the program complied with:
(i) The grant agreement.
(ii) Applicable laws and regulations.
(d)
(1) VA will rank those applications that receive at least the minimum amount of total points and points per category set forth in the Notice of Fund Availability. The applications will be ranked in order from highest to lowest scores.
(2) VA will use the applications' ranking as the basis for awarding grants. VA will award grants for the highest ranked applications for which funding is available.
When funds are available for grants, VA will publish a Notice of Fund Availability in the
(a) The location for obtaining grant applications;
(b) The date, time, and place for submitting completed grant applications;
(c) The estimated amount and type of grant funding available;
(d) The length of term for the grant award;
(e) The minimum number of total points and points per category that an applicant or grantee must receive in order for a supportive grant to be funded;
(f) The timeframes and manner for payments under the grant; and
(g) Those areas identified by VA to be the “highly rural areas” in which grantees may provide transportation services funded under this rule.
(a)
(1) The grantee must operate the program in accordance with the provisions of this section and the grant application.
(2) If a grantee's application identified a subrecipient, such subrecipient must operate the program in accordance with the provisions of this section and the grant application.
(3) If a grantee's application identified that funds will be used to procure or operate vehicles to directly provide transportation services, the following requirements must be met:
(i) Title to the vehicles must vest solely in the grantee or identified subrecipient, or with leased vehicles in an identified lender.
(ii) The grantee or identified subrecipient must, at a minimum, provide motor vehicle liability insurance for the vehicles to the same extent they would insure vehicles procured with their own funds.
(iii) All vehicle operators must be licensed in a U.S. State or Territory to operate such vehicles.
(iv) Vehicles must be safe and maintained in accordance with the manufacturer's recommendations.
(v) Vehicles must be operated in accordance with applicable Department of Transportation regulations concerning transit requirements under the Americans with Disabilities Act.
(b)
(1) State veterans service agencies and identified subrecipients in the grant agreement are subject to the Uniform Administrative Requirements for Grants and Cooperative Agreements to State and Local Governments under 38 CFR part 43, as well as to OMB Circular A–87, Cost Principles for State, Local, and Indian Tribal Governments, and 2 CFR parts 25 and 170, if applicable.
(2) Veterans Service Organizations and identified subrecipients in the grant agreement are subject to the Uniform Administrative Requirements for Grants and Agreements With Institutions of Higher Education, Hospitals, and Other Non-Profit Organizations under 38 CFR part 49, as well as to OMB Circular A–122, Cost Principles for Non-Profit Organizations, codified at 2 CFR part 230, and 2 CFR parts 25 and 170, if applicable.
Grantees are to be paid in accordance with the timeframes and manner set forth in the Notice of Fund Availability.
(a)
(1) Record of time expended assisting with the provision of transportation services.
(2) Record of grant funds expended assisting with the provision of transportation services.
(3) Trips completed.
(4) Total distance covered.
(5) Veterans served.
(6) Locations which received transportation services.
(7) Results of veteran satisfaction survey.
(b)
(c)
(d)
(a)
(b)
Environmental Protection Agency (EPA).
Final rule.
The EPA is taking final action to approve two revisions to the Arkansas State Implementation Plan (SIP) submitted by the Arkansas Department of Environmental Quality (ADEQ) to EPA on February 17, 2010, and November 6, 2012. The February 17, 2010, SIP revision to the Arkansas New Source Review (NSR) Prevention of Significant Deterioration (PSD) program updates the Arkansas SIP to incorporate by reference (IBR) requirements for the federal PSD permitting program under EPA's November 29, 2005 Phase 2 8-hour Ozone Implementation rule. The November 6, 2012, SIP revision to the Arkansas NSR PSD program provides the state of Arkansas with the authority to issue PSD permits governing greenhouse gas (GHG) emissions and establishes appropriate emission thresholds for determining which new stationary sources and modifications to existing stationary sources become subject to Arkansas's PSD permitting requirements for their GHG emissions. The November 6, 2012 SIP revision also defers until July 21, 2014, application of the PSD permitting requirements to biogenic carbon dioxide emissions from bioenergy and other biogenic stationary sources. EPA is approving the February 17, 2010, and November 6, 2012, SIP revisions to the Arkansas NSR PSD permitting program as consistent with federal requirements for PSD permitting. As a result of this approval, EPA is rescinding the GHG PSD Federal Implementation Plan (FIP) for Arkansas that was put in place on December 30, 2010, to ensure the availability of a permitting authority for GHG permitting in Arkansas. EPA is finalizing this action under section 110 and part C of the Act.
This final rule will be effective May 2, 2013.
EPA has established a docket for this action under Docket ID No. EPA–R06–OAR–2012–0639. All documents in the docket are listed in the
The State submittals related to this SIP revision, and which are part of the EPA docket, are also available for public inspection at the Local Air Agency listed below during official business hours by appointment: Arkansas Department of Environmental Quality, 5301 Northshore Drive, North Little Rock, Arkansas 72118–5317.
Mr. Mike Miller (6PD–R), Air Permits Section, Environmental Protection Agency, Region 6, 1445 Ross Avenue (6PD–R), Suite 1200, Dallas, TX 75202–2733. The telephone number is (214) 665–7550. Mr. Miller can also be reached via electronic mail at
Throughout this document whenever “we,” “us,” or “our” is used, we mean EPA.
The background for today's final rule and the EPA's national actions pertaining to GHGs is discussed in detail in our January 11, 2013 proposal (see 78 FR 2354). The comment period was open for thirty days and no comments were received.
We are approving Arkansas's February 17, 2010 SIP submittal, which updates the Arkansas SIP to incorporate by reference (IBR) requirements for the federal PSD permitting program under EPA's November 29, 2005 Phase 2 8-hour Ozone Implementation rule.
We are also approving Arkansas's November 6, 2012, SIP submittal, relating to PSD permitting requirements for GHG-emitting sources in Arkansas. Specifically, the SIP revision provides the state of Arkansas with the authority to issue PSD permits governing greenhouse gas (GHG) emissions and establishes appropriate emission thresholds for determining which new stationary sources and modifications to existing stationary sources become subject to Arkansas's PSD permitting requirements for their GHG emissions. The November 6, 2012, SIP revision also defers until July 21, 2014, application of the PSD permitting requirements to biogenic carbon dioxide emissions from bioenergy and other biogenic stationary sources.
EPA has made the determination that the February 17, 2010, and November 6, 2012, revisions to the Arkansas SIP for PSD permitting are approvable because the revisions were adopted and submitted as SIP revisions in accordance with the CAA and EPA regulations regarding PSD permitting for 8-hour ozone and GHGs. We are taking this final action today under section 110 and part C of the Act.
As explained in our January 11, 2013 proposal (see 78 FR 2354), as a result of today's action we are also rescinding the GHG PSD FIP for Arkansas at 40 CFR 52.37(b)(2). Therefore, as of the effective date of this final rule, the EPA will no longer be the PSD permitting authority for GHG-emitting sources in Arkansas.
This action is not a “significant regulatory action” under the terms of
This action does not impose an information collection burden under the provisions of the
The Regulatory Flexibility Act (RFA) generally 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. Small entities include small businesses, small not-for-profit enterprises, and small governmental jurisdictions.
For purposes of assessing the impacts of today's rule on small entities, small entity is defined as: (1) A small business as defined by the Small Business Administration's (SBA) regulations at 13 CFR 121.201; (2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) a small organization that is any not-for-profit enterprise which is independently owned and operated and is not dominant in its field.
This rule will transfer the permitting responsibility of GHG emissions from EPA to the State of Arkansas. This final rule will lead to permitting requirements for certain sources of GHG emissions; however these sources are large emitters of GHGs and tend to be large sources. Further, this rule will not have a significant impact on a substantial number of small entities because SIP approvals under section 110 and part C of the Clean Air Act do not create any new requirements but simply approve requirements that the States are already imposing. After considering the economic impacts of this rule on small entities, I certify that this action will not have a significant economic impact on a substantial number of small entities. This final rule will not impose any requirements on small entities.
This action contains no Federal mandates under the provisions of Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 1531–1538 for State, local, or tribal governments or the private sector. This action imposes no enforceable duty on any State, local or tribal governments or the private sector. Therefore, this action is not subject to the requirements of sections 202 or 205 of the UMRA.
This action is also not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments. This action transfers permitting responsibility of GHG emissions from EPA to the State of Arkansas. Small governments are not impacted.
This action does not have federalism implications. It will not have substantial direct effects on Arkansas, on the relationship between the national government and the State of Arkansas, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. The CAA specifies conditions under which states may request, and EPA may approve state implementation of CAA requirements. This rulemaking approves PSD permitting provisions in the state of Arkansas for GHG emissions, and as a consequence of the SIP approval, simultaneously rescinds federal PSD permitting responsibility for GHG emissions in Arkansas. This rulemaking is pursuant to the SIP approval and requirements of the CAA. As such, this final rule does not change the balance of power between Arkansas and EPA as provided for in the CAA. Thus, Executive Order 13132 does not apply to this action.
In the spirit of Executive Order 13132, and consistent with EPA policy to promote communications between EPA and State and local governments, EPA specifically solicited comment on the proposed action from State and local officials. EPA received no comments from state or local governments on this rulemaking.
This action does not have tribal implications, as specified in Executive Order 13175 (65 FR 67249, November 9, 2000). In this action, EPA is not addressing any Tribal Implementation Plans. This action is limited to Arkansas's PSD SIP. Thus, Executive Order 13175 does not apply to this action.
EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying only to those regulatory actions that concern health or safety risks, such that the analysis required under section 5–501 of the EO has the potential to influence the regulation. This action is not subject to EO 13045 because EPA is approving revisions to the Arkansas PSD SIP for permitting of GHG emissions, as authorized by the CAA.
This action is not subject to Executive Order 13211 (66 FR 28355 (May 22, 2001)), because it is not a significant regulatory action under Executive Order 12866.
Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (“NTTAA”), Public Law 104–113, 12(d) (15 U.S.C. 272 note) directs EPA to use voluntary consensus standards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by voluntary consensus standards bodies. NTTAA directs EPA to provide Congress, through OMB, explanations when the Agency decides not to use available and applicable voluntary consensus standards. This action does not involved technical standards. Therefore, EPA did not consider the use of any voluntary consensus standards.
Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high
EPA has determined that this final rule will not have disproportionately high and adverse human health or environmental effects on minority or low-income populations because it increases the level of environmental protection for all affected populations without having any disproportionately high and adverse human health or environmental effects on any population, including any minority or low-income population. This rule requires the State of Arkansas to assume the responibiity for permitting GHG emissions subject to PSD requirements. This final rule approves the Arkansas SIP as meeting Federal requirements for GHG PSD permitting and imposes no additional requirements beyond those imposed by Arkansas law.
The Congressional Review Act, 5 U.S.C. 801
Under section 307(b)(1) of the Clean Air Act, petitions for judicial review of this action must be filed in the United States Court of Appeals for the appropriate circuit by June 3, 2013. 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, Incorporation by reference, Intergovernmental relations, Reporting and recordkeeping requirements.
40 CFR part 52 is amended as follows:
42 U.S.C. 7401
The revisions read as follows:
(c) * * *
Environmental Protection Agency (EPA).
Final rule.
The EPA is finalizing its proposal to approve revisions to the Texas State Implementation Plan (SIP) for the Houston/Galveston/Brazoria (HGB) 1997 8-Hour ozone nonattainment Area (Area). The HGB Area consists of Brazoria, Chambers, Fort Bend, Galveston, Harris, Liberty, Montgomery and Waller counties. Specifically, we are finalizing our proposed approval of portions of two revisions to the Texas SIP submitted by the Texas Commission on Environmental Quality (TCEQ) as meeting certain Reasonably Available Control Technology (RACT) requirements for Volatile Organic Compounds (VOC), and Oxides of Nitrogen (NO
This rule will be effective on May 2, 2013.
The EPA has established a docket for this action under Docket ID No. EPA–R06–OAR–2012–0100. All documents in the docket are listed on the
Mr. Alan Shar, Air Planning Section (6PD–L), Environmental Protection Agency, Region 6, 1445 Ross Avenue, Suite 700, Dallas, Texas 75202–2733, telephone (214) 665–6691, fax (214) 665–7263, email address
Throughout this document “we,” “us,” and “our” refer to EPA.
In EPA's September 19, 2012 (77 FR 58063) rulemaking action we proposed to approve portions of revisions to the Texas SIP submitted to EPA in two separate letters dated June 13, 2007 and April 6, 2010 from TCEQ. We are finalizing our proposed approval as described below.
We are finalizing our proposal to approve the June 13, 2007 submittal, sent to EPA from TCEQ, which in part, included the Voluntary Mobile Emission Reduction Program (VMEP) commitments as strategies to complement existing regulatory programs through voluntary, non-regulatory changes in local transportation activities or changes in in-use vehicle and engine composition. Economic incentive provisions are also available in sections 182 and 108 of the Act. Credits generated through VMEP can be counted toward attainment and maintenance of the NAAQS. Due to the voluntary nature of this program, only up to 3% of the total future year emissions reductions required to attain an appropriate NAAQS may be claimed under the VMEP policy guidance.
In addition, the June 13, 2007 submittal included an analysis intended to demonstrate RACT was being implemented in the HGB Area as required by the CAA (Appendix D of the submittal).
Texas supplemented the RACT analysis contained in the June 13, 2007 submittal as a part of the April 6, 2010 revision to the Texas SIP. We are finalizing the proposal to find, based on the analysis in Appendix D of the April 6, 2010 submittal, in conjunction with the June 13, 2007 submission, that Texas has met certain RACT requirements under section 182(b). Appendix D of the April 6, 2010 submittal is titled “Reasonably Available Control Technology Analysis.” See section B of the September 19, 2012 (77 FR 58063) proposal for more information on RACT evaluation for the HGB Area.
The public comment period for the 77 FR 58063 proposed approval ended on October 19, 2012, and we received relevant comments from TCEQ and the 8-Hour Ozone SIP Coalition (the Coalition) on this rulemaking action during its comment period. See section II below.
This concludes our response to the comments received on the September 19, 2012 (77 FR 58063) proposal during comment period. As a result of comments received no changes were made to the proposed approval action.
Under sections 182(b)(2)(A) and (B), states must insure RACT is in place for each source category for which EPA issued a CTG. As a part of its June 13, 2007 submittal TCEQ conducted a RACT analysis to demonstrate that the RACT requirements for CTG sources in the HGB 8-Hour ozone nonattainment Area have been fulfilled. The TCEQ revised and supplemented this analysis in the April 6, 2010 submittal. For information on how TCEQ conducted its RACT analysis see section E of the September 19, 2012 (77 FR 58065) proposal. We are finalizing our proposal finding that TCEQ has properly conducted its analysis, and their approach to control requirements are in agreement with the CAA RACT requirements for VOC sources in the HGB Area listed in Table 1 below.
Table 1 below contains a list of VOC CTG source categories, and their corresponding sections of 30 TAC Chapter 115 that fulfill the applicable RACT requirements.
In addition, Texas declared that there are no existing major sources of rubber tire manufacturing, identified with the Standard Industrial Classification (SIC) 3011, in the HGB Area. As such, TCEQ does not have to adopt VOC regulations for this source category at this time for the HGB Area. We are also finalizing our proposed approval of Texas' negative declaration for this source category.
On March 29, 2010 (75 FR 15348) we approved revisions to 30 TAC, Chapter 115 Control of Air Pollution from Volatile Organic Compounds. On September 19, 2012 (77 FR 58063), we proposed approval of these revisions as satisfying RACT requirements for liquid storage sources in the HGB Area. We are now finalizing our proposed approval of these revisions and finding that by implementing these measures Texas is meeting the VOC RACT for liquid storage sources in the HGB Area.
Under section 182(b)(2)(C), states must assure that major sources not covered by a CTG have RACT in place. Texas has identified a list, in its Appendix D of the April 6, 2010 submittal, of major VOC sources in the HGB Area to determine if any do not have RACT level controls in place and do not fall into the identified sectors for which EPA has issued a CTG. For information on how TCEQ reviewed the point source emissions inventory and title V databases to identify all major sources of VOC emissions see section I of the September 19, 2012 (77 FR 58063). As a part of our approval of the 1-Hour ozone attainment demonstration plan for the HGB Area at 70 FR 58136, October 5, 2005, and 71 FR 52676, September 6, 2006, we stated that Texas has met RACT for VOC and NO
As a part of our action on the 1-Hour ozone attainment demonstration plan for the HGB Area at 70 FR 58136, October 5, 2005; and 71 FR 52676, September 6, 2006, we stated that Texas has met RACT for VOC and NO
As a part of our approval of the 1-Hour ozone attainment demonstration plan for the HGB Area at 70 FR 58136, October 5, 2005; and 71 FR 52676, September 6, 2006, we stated that Texas has met RACT for VOC and NO
The purpose of 30 TAC Chapter 115 and 117 rules for the HGB Area is to establish reasonable controls on the emissions of ozone precursors. Texas reviewed its VOC and NO
Today, we are finalizing our proposal to find that for VOC CTG categories identified in Table 1 and all major Non-CTG VOC sources, and for NO
Under the Clean Air Act, 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 Clean Air Act. 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 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 Clean Air Act;
• 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); and
• Does not have tribal implications as specified by Executive Order 13175 (65 FR 67249, November 9, 2000), because the SIP is not approved to apply in Indian country located in the state, and EPA notes that it will not impose substantial direct costs on tribal governments or preempt tribal law.
The Congressional Review Act, 5 U.S.C. 801
Under section 307(b)(1) of the Clean Air Act, petitions for judicial review of this action must be filed in the United States Court of Appeals for the appropriate circuit by June 3, 2013. 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, Hydrocarbons, Incorporation by reference, Intergovernmental relations, Reporting and recordkeeping requirements, Volatile organic compounds.
Part 52, chapter I, title 40 of the Code of Federal Regulations is amended as follows:
42 U.S.C. 7401
(e) * * *
Environmental Protection Agency (EPA).
Direct final rule.
EPA is taking direct final action to approve a revision to the State Implementation Plan (SIP) and Operating Permits Program to amend the definitions provisions of the rules. This SIP revision and revision to the Missouri operating permits program add the compounds propylene carbonate and dimethyl carbonate to the list of compounds which are excluded from the definition of Volatile Organic Compound (VOC) for consistency with the Federal definition of VOC. The SIP revision also corrects two asbestos method subpart references. This revision also approves Missouri's request to amend the SIP to meet the 2008 fine particulate matter (PM
This direct final rule will be effective June 3, 2013, without further notice, unless EPA receives adverse comment by May 2, 2013. If adverse comment is received, EPA will publish a timely withdrawal of the direct final rule in the
Submit your comments, identified by Docket ID No. EPA–R07–OAR–2012–0749, by one of the following methods:
1.
2.
3.
Craig Bernstein at (913) 551–7688, or by email at
Throughout this document “we,” “us,” or “our” refer to EPA. This section provides additional information by addressing the following questions:
EPA is publishing this rule without a prior proposed rule because we view this as a noncontroversial action and anticipate no adverse comment because the revisions are largely administrative and consistent with Federal regulations. The revisions will improve the clarity of the rule and do not have an adverse affect on air quality or the stringency of the SIP and operating permits program. However, in the “Proposed Rules” section of today's
If EPA receives adverse comment, we will publish a timely withdrawal in the
EPA is approving revisions to the Missouri SIP and operating permits program. The first revision adds the compounds propylene carbonate and dimethyl carbonate to the list of compounds which are excluded from the definition of Volatile Organic Compound (VOC) in 10 CSR 10–6.020(v). This action is consistent with the EPA definition of VOC. These compounds can be found in the EPA definition of VOC at 40 CFR 52.100 (s)(1).
Revisions were made to the Table of compounds not considered VOCs because of their known lack of participation in the atmospheric reactions to produce ozone. Revisions include deletions, corrections and additions which are consistent with EPA regulations and do not adversely affect the stringency of the SIP or the operating permits program.
Next, definitions in 40 CSR 10–6.020(c) for Category I nonfriable asbestos containing material (ACM), and Category II nonfriable ACM are being updated to correct the method subpart reference. The correct method subpart references are consistent with the EPA rules found at 40 CFR part 763, subpart E, appendix E, section 1. The state has incorporated the EPA method subpart references in 10 CSR 10–6.020 Definitions and Common Reference Tables (2)(C)3 and (2)(C)4 dated November 30, 2010. Although asbestos is not regulated under the SIP, the EPA asbestos regulations (NESHAPS) are applicable requirements for purposes of Missouri's operating permit program and are approved for this purpose.
Finally, the de minimis emissions table is being updated for consistency with 40 CFR 52.21, specifically related to a portion of the NSR implementation rule for PM
The state submittal has met the public notice requirements for SIP submissions in accordance with 40 CFR 51.102. The submittal also satisfied the completeness criteria of 40 CFR part 51, appendix V. The substantive requirements of Title V of the 1990 CAA Amendments and 40 CFR part 70 have been met as well.
We are taking direct final action to approve the amendments to the Missouri SIP and operating permits program. This revision will amend the definitions provisions of the rules as described above for VOCs and asbestos, as well as update the de minimis emissions table found in Missouri's rule “Definitions and Common Reference Tables” to be consistent with 40 CFR part 52.21.
Under Executive Order 12866 (58 FR 51735, October 4, 1993), this action is not a “significant regulatory action” and therefore is not subject to review under Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011). This action is also not subject to Executive Order 13211, “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use” (66 FR 28355, May 22, 2001). This action merely approves state law as meeting Federal requirements and imposes no additional requirements beyond those imposed by state law. Accordingly, the Administrator certifies that this rule will not have a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601
This rule also does not have tribal implications because it will not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes, as specified by Executive Order 13175 (65 FR 67249, November 9, 2000). This action also does not have Federalism implications because it does 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, as specified in Executive Order 13132 (64 FR 43255, August 10, 1999). Thus Executive Order 13132 does not apply to this action. This action merely approves a state rule implementing a Federal standard, and does not alter the relationship or the distribution of power and responsibilities established in the CAA. This rule also is not subject to Executive Order 13045, “Protection of Children from Environmental Health Risks and Safety Risks” (62 FR 19885, April 23, 1997) because it approves a state rule implementing a Federal standard.
In reviewing SIP submissions, EPA's role is to approve state choices, provided that they meet the criteria of the CAA. In this context, in the absence of a prior existing requirement for the State to use voluntary consensus standards (VCS), EPA has no authority to disapprove a state submission for failure to use VCS. It would thus be inconsistent with applicable law for EPA when it reviews a state submission, to use VCS in place of a state submission that otherwise satisfies the provisions of the CAA. Thus, the requirements of section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) do not apply. This action does not impose an information collection burden under the provisions of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
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 June 3, 2013. Filing a petition for reconsideration by the Administrator of this final rule does not affect the finality of this rule 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. Parties with objections to this direct final rule are encouraged to file a comment in response to the parallel notice of proposed rulemaking for this action published in the proposed rules section of today's
Environmental protection, Air pollution control, Carbon monoxide, Incorporation by reference, Intergovernmental relations, 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.
Chapter I, title 40 of the Code of Federal Regulations is amended as follows:
42 U.S.C. 7401 et seq.
(c) * * *
42 U.S.C. 7401
(aa) The Missouri Department of Natural Resources submitted revisions to Missouri rule 10 CSR 10–6.020, “Definitions and Common Reference Tables” on December 15, 2010. The state effective date is December 30, 2010. This revision is effective June 3, 2013.
Environmental Protection Agency (EPA).
Withdrawal of direct final rule.
EPA published a direct final rule,
Effective April 2, 2013, the EPA withdraws the direct final rule published at 78 FR 11585 on February 19, 2013.
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:
Because EPA received potentially adverse comments, EPA is withdrawing the direct final rule,
Environmental Protection, Administrative practice and procedures, Air pollution control, Greenhouse gases, Monitoring, Reporting and recordkeeping requirements.
Accordingly, the amendments to the rule published on February 19, 2013 (78 FR 11585) are withdrawn as of April 2, 2013.
Office of Energy Efficiency and Renewable Energy, Department of Energy.
Supplemental notice of proposed rulemaking.
The U.S. Department of Energy (DOE) proposes to establish test procedures for electrically-powered devices used in residential heating, ventilation, and air-conditioning (HVAC) products to circulate air through ductwork, hereafter referred to as “furnace fans.” DOE proposes a test procedure that would be applicable to furnace fans that are used in weatherized and non-weatherized gas, oil and electric furnaces and modular blowers, even though DOE interprets its authority as encompassing more than just circulation fans used in furnaces. This notice proposes to establish a test method for measuring the electrical consumption of the furnace fans used in these products. Concurrently, DOE is undertaking an energy conservation standards rulemaking to address the electrical energy used by these products for circulating air. Once these energy conservation standards are promulgated, the adopted test procedures would be used to determine compliance with the standards. DOE is also requesting written comments on issues presented in this test procedure rulemaking. DOE does not plan to hold a public meeting to discuss the modified proposals of this supplemental notice.
Any comments submitted must identify the SNOPR on Test Procedures for Residential Furnace Fans, and provide docket number EERE–2010–BT–TP–0010 and/or regulatory information number (RIN) number 1904–AC21. Comments may be submitted using any of the following methods:
1.
2.
3.
4.
No telefacsimilies (faxes) will be accepted. See section V, “Public Participation,” for detailed instructions on submitting comments and additional information on the rulemaking process.
A link to the docket Web page can be found at:
For further information on how to submit a comment, review other public comments and the docket, or participate in the public meeting, contact Ms. Brenda Edwards at (202) 586–2945 or by email:
The residential furnace fans rulemaking electronic mailbox, Email:
Mr. Ari Altman, U.S. Department of Energy, Office of the General Counsel, GC–71, 1000 Independence Avenue SW., Washington, DC 20585–0121. Telephone: (202) 287–6307. Email:
For information on how to submit or review public comments, contact Ms. Brenda Edwards, U.S. Department of Energy, Building Technologies Program, EE–2J, 1000 Independence Avenue SW., Washington, DC 20585–0121. Telephone: (202) 586–2945. Email:
Title III, Part B
Under the Act, this energy conservation program consists essentially 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 use as the basis for certifying to DOE that their products comply with the applicable energy conservation standards adopted pursuant to EPCA and for making representations about the efficiency of those products. (42 U.S.C. 6293(c); 42 U.S.C. 6295(s)) Any representation made after September 30, 2013 for energy consumption of residential furnace fans must be based upon results generated under this test procedure. Upon the compliance date(s) of any energy conservation standard(s) for residential furnace fans, use of the applicable provisions of this test procedure to demonstrate compliance with the energy conservation standard will also be required. Similarly, DOE must use these test procedures in any enforcement action to determine whether covered products comply with these energy conservation standards. (42 U.S.C. 6295(s))
Under 42 U.S.C. 6293, EPCA sets forth the criteria and procedures DOE must follow when prescribing or amending test procedures for covered products. Under EPCA, “[a]ny 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)) In any rulemaking to amend a test procedure, DOE must determine to what extent, if any, the proposed test procedure would alter the measured energy efficiency of a covered product as determined under the existing test procedure. (42 U.S.C. 6293(e)(1)) If DOE determines that the amended test procedure would alter the measured efficiency of a covered product, DOE must amend the applicable energy conservation standard accordingly. (42 U.S.C. 6293(e)(2))
Pursuant to EPCA under 42 U.S.C. 6295(f)(4)(D), DOE is currently conducting a rulemaking to consider new energy conservation standards for furnace fans. EPCA directs DOE to establish test procedures in conjunction with new energy conservation standards, including furnace fans. (42 U.S.C. 6295(o)(3)(A)) DOE does not currently have a test procedure for furnace fans. Hence, to fulfill the statutory requirements, DOE initiated a test procedure rulemaking for furnace fans simultaneously to the energy conservation standards rulemaking for furnace fans. DOE intends for the test procedure to include an energy consumption metric and the methods necessary to measure the energy performance of the covered products. The proposed energy consumption metric does not account for the electrical energy consumption in standby mode and off mode because consumption in those modes is already accounted for in the DOE rulemakings for furnaces and central air conditioners (CAC) and heat pumps. 77 FR 76831, December 31, 2012; 76 FR 65616 (Oct. 24, 2011). Manufacturers would be required to use the proposed energy consumption metric, sampling plans, and testing methods developed during this rulemaking to verify compliance with the new energy conservation standards when they take effect and for making representations about the energy consumption of furnace fans.
On June 3, 2010, DOE published a Notice of Public Meeting and Availability of the Framework Document (the June 2010 Framework Document) to initiate the energy conservation standard rulemaking for furnace fans. 75 FR 31323. In the June 2010 Framework Document, DOE requested feedback from interested parties on many issues related to test methods for evaluating the electrical energy consumption of furnace fans. DOE held the framework public meeting on June 18, 2010. DOE originally scheduled the framework comment period to close on July 6, 2010. However, due to the large number and broad scope of questions and issues raised regarding the June 2010 Framework Document in writing and during the public meeting, DOE published a notice in the
On May 15, 2012, DOE published a notice of proposed rulemaking in the
In response to the NOPR, many interested parties commented that the proposed test procedure was unduly burdensome. The Air-Conditioning, Heating and Refrigeration Institute (AHRI), with support from Goodman Global, Inc. (“Goodman”), Ingersoll Rand, Lennox International, Inc. (“Lennox”), and Morrison Products, Inc. (“Morrison”), proposed an alternative
DOE agrees that the key concept embodied in the alternative method suggested by AHRI and manufacturers (using the AFUE test set up and temperature rise to determine airflow) may provide accurate and repeatable FER values at a significantly reduced burden to manufacturers. In this supplemental notice of proposed rulemaking (SNOPR), DOE proposes to adopt a modified version of the test method presented by AHRI as the furnace fan test procedure. DOE also explains the changes reflected in the test procedure proposed herein compared to the test procedure proposed in the NOPR. This notice also provides interested parties with an opportunity to comment on the revised proposed test method.
In this SNOPR, DOE addresses only the changes to the test procedure it proposed in the NOPR and those comments received on the NOPR that are relevant to the proposed changes. All other comments received on the test procedure NOPR will be addressed in the test procedure final rule.
Pursuant to EPCA, DOE is required to establish these test procedures in order to allow for the development of energy conservation standards to address the electrical consumption of the products covered under this rulemaking. (42 U.S.C. 6295(o)(3)(A)) The proposed test procedure would be applicable to electrically-powered devices used in central HVAC systems for the purposes of circulating air through ductwork (
DOE proposes to adopt a modified version of the alternative test method recommended by AHRI and other furnace fan manufacturers to rate the electrical consumption of furnace fans. The AHRI-proposed method provides a framework for accurate and repeatable determinations of FER that is comparable to the test method previously proposed by DOE, but at a significantly reduced test burden. In general, the AHRI proposal reduces the test burden because it: (1) Does not require airflow to be measured directly; (2) avoids the need to make multiple determinations in each airflow-control setting because outlet restrictions to achieve the specified reference system external static pressure (ESP) would be set in the maximum airflow-control setting and maintained for measurements in subsequent airflow-control settings; and (3) can be conducted using the test set up currently required to rate furnace AFUE for compliance with furnace standards.
DOE proposes to align the proposed furnace fan test procedure with the DOE test procedure for furnaces by incorporating by reference specific provisions from an industry standard incorporated by reference in its test procedure for furnaces. DOE's test procedure for furnaces is codified in appendix N of subpart B of part 430 of the code of federal regulations (CFR). The DOE furnace test procedure incorporates by reference American National Standards Institute (ANSI)/American Society of Heating, Refrigerating and Air Conditioning Engineers (ASHRAE) 103–1993,
DOE proposes to use the same definition for the fan efficiency rating (FER) metric as proposed in the NOPR, but to modify the title and calculation. In the NOPR, DOE proposed to define FER as the estimated annual electrical energy consumption of the furnace fan normalized by: (a) The estimated total number of annual fan operating hours (1,870); and (b) the airflow in the maximum airflow-control setting. DOE is aware that referring to the FER rating metric as the “fan efficiency rating,” as was done in the NOPR, is a misnomer because it is not a function of the output energy of the furnace fan, which is typical of an efficiency metric. FER is a function of fan energy consumption and as a result, DOE believes it is more appropriately categorized as an energy consumption metric. Thus DOE proposes to refer to FER as the “fan energy rating.” The estimated annual electrical energy consumption, as proposed, is a weighted average of the furnace fan electrical input power (in Watts) measured separately for multiple airflow-control settings at different external static pressures (ESPs). These ESPs are determined by a reference system that represents national average ductwork system characteristics. Table II.1 includes the proposed reference system ESP values by installation type. The reference system ESP values proposed in the NOPR included a value for “heating-only” installation types. Interested parties recommended that DOE eliminate this installation type because they are unaware of products that could be categorized as such. DOE agrees with interested parties and proposes to eliminate the heating-only designation for this SNOPR. Section III.F provides a detailed discussion of this issue.
The
As shown in Table II.2., for products with single-stage heating, the three proposed rating airflow-control settings are the default constant-circulation setting, the default heating setting, and the absolute maximum setting. For products with multi-stage heating or modulating heating, the proposed rating airflow-control settings are the default constant-circulation setting, the default low heating setting, and the absolute maximum setting. The absolute lowest default airflow-control setting is used to represent constant circulation if a default constant-circulation setting is not specified. DOE's proposes to define “default airflow-control settings” as the airflow-control settings specified for installed use by the manufacturer in the product literature shipped with the product in which the furnace fan is integrated. Manufacturers typically provide detailed instructions for setting the default heating airflow control-setting to ensure that the product in which the furnace fan is integrated operates safely. Manufacturer installation guides also provide detailed instructions regarding compatible thermostats and how to wire them to achieve the specified default settings.
DOE proposes to weight the Watt measurements using designated annual operating hours for each function (
The specified operating hours for the heating mode for multi-stage heating or modulating heating products are divided by the heat capacity ratio (HCR) to account for variation in time spent in this mode associated with turndown of heating output. The HCR is the ratio of the reduced heat output capacity to maximum heat output capacity. In the NOPR, DOE proposed to incorporate HCR to adjust the heating operating hours in both the numerator (
EPCA grants DOE authority to “consider and prescribe energy conservation standards or energy use standards for electricity used for purposes of circulating air through ductwork.” (42 U.S.C. 6295(f)(4)(D)) In the June 2010 Framework Document, DOE tentatively interpreted this EPCA language to allow DOE to cover any electrically-powered device used in a central HVAC system for the purpose of circulating air through ductwork. DOE sought comment on including the air circulation fans used in gas furnaces, oil furnaces, electric furnaces, CAC air handlers, and modular blowers in the scope of coverage. DOE also sought comment on excluding draft inducer fans, exhaust fans, heat recovery ventilators (HRV), and energy recovery ventilators (ERV) from the scope of coverage. DOE also requested comment on whether other products, such as small-duct, high-velocity (SDHV) and through-the-wall systems should be included in the scope of coverage of this rulemaking.
In the test procedure NOPR, DOE proposed a scope of applicability for the test procedure that was sufficiently broad to cover the products under consideration for the scope of coverage for the energy conservation standards. The NOPR test procedure's proposed scope of applicability included single-phase, electrically-powered devices that circulate air through ductwork in HVAC systems with heating input capacities less than 225,000 Btu per hour, cooling capacities less than 65,000 Btu per hour, and airflow capacities less than 3,000 cfm. These heating and cooling capacity limits are identical to those in the DOE definitions for residential “furnace” and “central air conditioner” (10 CFR
In their comments on the test procedure NOPR, many interested parties commented that the scope of coverage should be limited to circulation fans used in residential furnaces. AHRI stated its view that DOE had misinterpreted the relevant provision of EPCA. According to AHRI, the heading of 42 U.S.C. 6295(f) entitled, “standards for furnaces and boilers” and subsections 1 through 4 under that section apply only to residential furnaces and boilers, as defined by EPCA. 10 CFR 430.2 AHRI suggested that this clear, consistent format strongly indicates that the scope of this requirement includes only the motor and blower combinations provided in residential warm air furnaces. AHRI added that there is nothing within section 42 U.S.C. 6295(f) that suggests that the provisions of that section apply to any other products that may be used to heat a residence. AHRI contended that if the intent of this change had been to include circulation fans used in residential air conditioners and heat pumps, then Congress would have added a corresponding paragraph to 42 U S C. 6295(d)—the section covering central air conditioners and heat pumps. (AHRI, No. 16 at pp. 1–2.) First Company (“First Co.”), Morrison, and Lennox echoed AHRI's arguments. (First Co., No. 9 at p. 1; Morrison, Public Meeting Transcript, No. 23 at p. 26; Lennox, No. 12 at p. 2.)
First Co. added that, although subsection (f)(4)(D) refers in more general terms to “standards for electricity used for purposes of circulating air through ductwork,” it is a well-established rule of statutory construction that, “[w]here general words follow specific words in a statutory enumeration, the general words are construed to embrace only objects similar in nature to those objects enumerated by the preceding specific words.”
AHRI, First Co., Ingersoll Rand, Morrison, Mortex Products, Inc., Goodman, and Lennox commented that CAC and heat pump products like split-system packaged central air conditioners and heat pump air handlers should be excluded because the electrical consumption of their circulation fans is already addressed in the seasonal energy efficiency ratio (SEER) and heating seasonal performance factor (HSPF) descriptors. (AHRI, Public Meeting Transcript, No. 23 at p. 74; First Co., No. 10 at p. 2; Ingersoll Rand, Public Meeting Transcript, No. 23 at p. 98; Morrison, No. 21 at p. 2; Mortex, No. 18 at p. 1; Goodman, No. 17 at p. 1; Lennox, No. 12 at p. 2). First Co. points out that in the NOPR, DOE proposed not to adopt additional test procedure provisions for standby and off mode electrical energy consumption of furnace fans used in furnaces and CAC and heat pumps given that consumption in these modes either has been or is in the process of being fully addressed in other rulemakings. Applying the same principle, First Co. states that there is no need for DOE to adopt additional test procedures for furnace fans in central air conditioners in this rulemaking because their energy usage is addressed by the SEER descriptor under the standard.
First Co. also commented that EPCA allows for the development of more than one standard for products that serve more than one major function, but limits DOE's authority to setting one standard for each major function. 42 U.S.C. 6295(o)(5) According to First Co., to the extent that DOE has the authority to regulate the energy efficiency of “furnace fans,” it does not have authority to require manufacturers of central air conditioners to meet a separate standard for a component of the system already tested and rated under the SEER standard. (First Co., No. 10 at p.2.) Ingersoll Rand echoed First Co.'s sentiments, stating that further testing of air handlers would be redundant and add regulatory burden with no benefit because all air handlers are currently tested as part of a CAC or HP system with the fan power included in the SEER, EER, and HSPF descriptors. Ingersoll Rand added that consumer confusion is a likely unintended consequence. (Ingersoll Rand, No. 14 at p. 2.) Goodman submitted that cooling hours and energy consumption should be removed from the metric for all covered products to eliminate duplicate regulations. (Goodman, No. 17 at p. 4.)
AHRI, Ingersoll Rand, and Morrison commented that modular blowers and hydronic air handlers should not be covered in this test procedure because they are beyond the authority provided by EPCA and are not currently regulated product classes. (AHRI, No. 16 at p. 2; Ingersoll Rand, No. 14 at p. 2; Morrison, Public Meeting Transcript, No. 23 at p. 88.)
Several interested parties commented that the test procedure should address operation of furnace fans as installed in the products in which they are sold rather than separately. DOE acknowledges that its NOPR may not have been clear in indicating that the test procedure proposal would apply to operation of fans while installed in these products. Consequently, some interested parties recommend that DOE consider the air handler (
During the comment period of the test procedure NOPR, DOE published a Notice of Public Meeting and Availability of Preliminary Analysis Support Document for the furnace fans energy conservation standard rulemaking on July 10, 2012. 77 FR 40530. For the preliminary analysis, DOE decided that, although the title of the statutory section refers to “furnaces and boilers,” the provision governing the products at issue in this rulemaking was written using notably broader language than the other provisions within the same section, referring to “electricity used for purposes of circulating air through ductwork.”
Efficiency advocates expressed concern at the exclusion of furnace fans used in split-system CAC and heat pump products and requested that they be added to the scope. (Appliance Standards Awareness Project (ASAP), Preliminary Analysis, No. 43 at p. 17; Adjuvant, Preliminary Analysis, No. 43 at p. 39.) Specifically, efficiency advocates commented that although the fan energy use is incorporated as part of the efficiency metrics—SEER and HSPF—prescribed by DOE for these products (10 CFR part 430, subpart B, appendix M), the external static pressures (ESPs) used to determine the SEER and HSPF do not reflect as-installed conditions, in which ESP is generally significantly higher. (ASAP, Preliminary Analysis, No. 43 at p. 38; Earthjustice, Preliminary Analysis, No. 49 at p. 1.) In a joint comment from ACEEE, ASAP, the National Consumer Law Center (NCLC), NEEA, and the Natural Resources Defense Council (NRDC), hereinafter referred to as ACEEE,
Manufacturers' comments in response to the preliminary analysis regarding the scope of coverage were similar to their comments on the test procedure NOPR. In contrast to efficiency advocates and utilities, many manufacturers believe that the scope of coverage presented in the preliminary analysis exceeds the authority granted to DOE by EPCA and should not include any non-furnace products such as central air conditioners, heat pumps, or condensing unit-blower-coil combinations. (First Co., Preliminary Analysis, No. 53 at p. 1.)
DOE notes that, although the title of this statutory section refers to “furnaces and boilers,” the applicable provision at 42 U.S.C. 6295(f)(4)(D) was written using broader language than the other provisions within 42 U.S.C. 6295(f). Specifically, that statutory provision directs DOE to “consider and prescribe energy conservation standards or energy use standards for electricity used for purposes of circulating air through ductwork.” Such language could be interpreted as encompassing electrically-powered devices used in any residential HVAC product to circulate air through ductwork, not just furnaces, and DOE has received numerous comments on both sides of this issue. At the present time, however, DOE is only proposing test procedures for those circulation fans that are used in residential furnaces and modular blowers. As a result, DOE is not addressing public comments that pertain to fans in other types of HVAC products. The following list describes the furnace fans which DOE proposes to address as well as those not addressed in this rulemaking.
•
•
DOE is using the term “modular blower” to refer to HVAC products powered by single-phase electricity that comprise an encased circulation blower that is intended to be the principal air circulation source for the living space of a residence. A modular blower is not contained within the same cabinet as a residential furnace, CAC, or heat pump. Instead, modular blowers are designed to be paired with separate residential HVAC products that provide heating and cooling, typically a separate CAC/HP coil-only unit. DOE finds that modular blowers and electric furnaces are very similar in design. In many cases, the only difference between a modular blower and electric furnace is the presence of an electric resistance heating kit. DOE is aware that some modular blower manufacturers offer electric resistance heating kits to be installed in their modular blower models so that the modular blowers can be converted to stand-alone electric furnaces. In addition, FER values for modular blowers can be easily calculated using the proposed test procedure. DOE proposes to address the furnace fans used in modular blowers in this rulemaking for these reasons. The proposed definition for “modular blower” is provided in section III.C.
This proposed furnace fan test procedure would adopt a significant number of provisions from the DOE furnace test procedure and would not result in significant capital expenditures for manufacturers because they would not have to acquire or use any test equipment beyond the equipment that they already use to conduct the test method specified in the DOE furnace test procedure (i.e. the AFUE test setup). DOE also finds that the time to conduct a single furnace fan test according to its proposed furnace fan test procedure would be less than 3 hours and cost less than one percent of the manufacturer selling price of the product in which the
After considering available information and public comments regarding the test procedure being applicable to fan operation in cooling mode, DOE maintains its proposal to account for the electrical consumption of furnace fans while performing all active mode functions (
DOE is aware that electrical consumption of the fan is accounted for in the SEER and HSPF metrics that DOE uses for CAC and heat pump products. However, DOE does not agree with First Co.'s interpretation that the EPCA language limits DOE's authority to setting one standard for each major product function and precludes DOE from rating furnace fan consumption in operating modes that are accounted for by these metrics. (42 U.S.C. 6295(o)(5)) EPCA's language in section 6295(o)(5) is phrased in the permissive, rather than the restrictive.
In the NOPR in response to comments on the June 2010 Framework Document, DOE proposed to incorporate by reference ANSI/AMCA 210–07, citing comments that manufacturers currently use ANSI/AMCA 210–07 to measure furnace fan performance. The NOPR provides a more detailed discussion of DOE's consideration of ANSI/AMCA 210–07 and alternative reference standards. 77 FR at 28677 (May 15, 2012). Commenting on the NOPR, manufacturers recommended that DOE incorporate provisions from ASHRAE 37 instead of ANSI/AMCA 210–07. Ingersoll Rand commented that fan performance data from a DOE test procedure that references ANSI/AMCA 210–07 would not be consistent with existing data, which is generated using ASHRAE 37. (Ingersoll Rand, Public Meeting Transcript, No. 23 at p. 30) Lennox asserted that if DOE uses a test procedure that specifies an airflow calculation, then ANSI/AMCA 210 is not the appropriate standard. According to Lennox, ASHRAE 37 would be more appropriate if DOE specifies airflow calculations. (Lennox, No. 12 at p. 4.) Goodman stated that its airflow measurements for furnaces are currently performed using ASHRAE 37 setups and calculations. Further, Goodman pointed out that DOE test procedures to measure airflow and power input for central air conditioners and heat pumps as defined in Appendix M to Subpart B of 10 CFR part 430 require that furnace fan performance be measured per ASHRAE 37 for use in determining ratings for SEER and HSPF. Therefore, according to Goodman, DOE's proposal to use ANSI/AMCA 210–07 would require manufacturers to test the same product with two different test methods to rate furnace fans. Goodman believes that such an outcome is contrary to Congressional intent and the consumers' best interests. (Goodman, No. 17 at p. 4.) Morrison added that ANSI/AMCA 210–07 is designed to test stand-alone fans, while ASHRAE 37 is more appropriate for testing fans as part of appliances. (Morrison, Public Meeting Transcript, No. 23 at p. 38.) Interested parties commented that
DOE agrees with interested parties that furnace fans should be tested in a laboratory and as factory-installed in the HVAC product with which it is
In written comments, AHRI (with support from Goodman, Ingersoll Rand, Lennox, and Morrison) proposed an alternative test method that they argue would result in accurate and repeatable FER values that are comparable to the FER values resulting from the test procedure proposed in the NOPR, but at significantly reduced test burden. (AHRI, No. 16 at p. 3; Goodman, No. 17 at p. 4; Ingersoll Rand, No. 14 at p. 1; Morrison, No. 21 at p. 3.) AHRI recommends that DOE specify the following procedures to generate the measurements used to rate furnace fan performance (AHRI, No. 16 at p. 3):
• The furnace should be set up on the test stand that is used to measure AFUE.
• Initially, the furnace should be operated in the maximum airflow-control setting having adjusted the duct restrictions to achieve the external static pressure (ESP) proposed in the NOPR while in the heating mode (
• Subsequently, power should be measured while operating the furnace in the heating airflow-control setting and again while operating the furnace in the constant circulation airflow-control setting, both without changing the initial duct restrictions in any way and without firing the furnace.
• The maximum airflow used to normalize the FER metric should be calculated (instead of measured directly) based on the measured temperature rise, measured fuel input, AFUE, and the known heat capacity of air.
• Measurements should be taken at nominal voltage and no voltage adjustments should be allowed.
• FER should be calculated using the annual operating hours that DOE proposed in the NOPR.
AHRI estimates an approximate 80–90% reduction in testing burden through the adoption of its proposed test method. AHRI stated that this reduction is due, in part, to manufacturers not having to acquire or use any test equipment beyond the equipment that is already used to conduct the testing specified in the DOE furnace test procedure (
AHRI attributed some of the projected reduction in burden of its recommended test method to the labor savings that manufacturers would experience with respect to conducting tests and calculations. (AHRI, No. 16 at p. 3.) Allied Air Enterprises (“Allied Air”) commented that the time and cost of conducting the proposed test procedure would be unduly burdensome. (Allied Air, No 23 at p. 20.) Rheem and Lennox commented that measuring airflow is difficult, labor- and capital-intensive, and not necessary to rate furnace fan electrical energy use. (Rheem, No. 25 at p. 3; Lennox, No. 12 at p. 4.) As mentioned previously, Mortex suggested that airflow could be calculated by using the temperature rise methodology already employed for the DOE furnace test procedure prior to AHRI submitting its recommended alternative test method. (Mortex, Public Meeting Transcript, No. 23 at p. 234.) Goodman performed tests according to both DOE's proposed procedure and AHRI's suggested method and found that testing time is reduced by almost 60% using AHRI's method. (Goodman, No. 17 at p. 3.) Rheem also conducted tests according to both procedures and stated that the time to test a single-stage furnace was reduced from 4 hours to 45 minutes by using the AHRI method. (Rheem, No. 25 at p. 4.)
AHRI claimed that its suggested method would eliminate potential issues associated with fitting quadratic curves to the test data to derive FER as proposed in the NOPR. According to AHRI and Morrison, the quadratic curves can be easily manipulated. (AHRI, No. 16 at p. 3; Morrison, No. 21 at p. 5.) Furthermore, AHRI stated that the quadratic curves can be significantly skewed through a single incorrect measurement. (AHRI, No. 16 at p. 3.) Morrison agrees that DOE should abandon the system curve approach in favor of AHRI's proposed method because eliminating the need to curve fit and find the intersection of second order polynomials would reduce the burden on manufacturers. Morrison stated that the added burden of the NOPR method does not provide any added value to the purpose of saving energy, guiding consumers in making correct choices, or enhancing the regulatory process. (Morrison, No. 21 at p. 5.) NEEA explained that the need for quadratic curve-fitting could be eliminated by establishing the specified external static pressure values in a specific mode, and then running the remaining tests in other modes without modifying the physical test apparatus set-up. NEEA and NPPC suggested that DOE consider this simplified approach. According to NEEA and NPPC, the
Goodman commented that test results show that FER values generated using AHRI's test method are within 5% of the FER values generated using the test procedure proposed in the NOPR. (Goodman, No. 17 at p. 4.) Rheem's test results show similar results. (Rheem, No. 25 at p. 4.)
Efficiency advocates agreed that some hybrid of reference standards could be used to develop a test procedure that is less burdensome than wholly adopting ANSI/AMCA 210. However, the Joint Commenters stated that simply implementing ASHRAE 37 is an incomplete solution because this method lacks an electrical energy consumption measurement. (Joint Commenters, No. 13 at p. 3.) The CA IOU advised DOE to develop a hybrid test procedure that draws from AMCA 210, ASHRAE 37, and AHRI 210–240 but emphasized that portions of AMCA 210 are needed for measuring fan power at different airflow rates. (CA IOU, No. 20 at p. 1.) While unclear from CA IOU's comments, DOE infers that the CA IOU are referring to provisions for measuring fan performance in multiple airflow-control settings.
In today's notice, DOE proposes to adopt a modified version of the alternative test method proposed by AHRI. DOE agrees that the key concept embodied in the alternative method suggested by AHRI and manufacturers (using temperature rise to determine airflow) can be a viable approach to obtain accurate and repeatable FER values at significantly reduced burden. The methods suggested by AHRI are already used in existing industry and DOE test methods. ASHRAE 37 includes determining airflow based on temperature rise as an alternative method to using differential pressure across nozzles. In addition, the DOE test procedure for furnaces includes well established and accurate methods for measurement of temperature rise, fuel input, and steady state combustion efficiency based on flue gas temperature and carbon dioxide concentrations. Additionally, DOE recognizes the opportunity to reduce test burden by: (1) Aligning the furnace fan test set up and procedures with those of the existing DOE furnace test procedure; and (2) maintaining the same duct restrictions throughout the test after initial reference system conditions are met in lieu of the previously proposed methods of making multiple determinations in each airflow-control setting and curve-fitting to identify operating points. DOE also agrees with advocates and utilities that the proposed test procedure should reflect field ESP conditions and measure furnace fan electrical input power in multiple airflow-control settings. The AHRI method includes provisions that meet these goals. DOE has considered the AHRI approach and has concluded that some clarifications and modifications are necessary to make the approach more practicable and accurate. For these reasons, DOE proposes to adopt a modified version of the alternative furnace fan test procedure proposed by AHRI.
DOE proposes the following additions and modifications to the test method recommended by AHRI:
• Airflow in the maximum airflow-control setting would be calculated based on measured air temperature rise when the HVAC product is in a heating-mode airflow-control setting rather than in the maximum airflow-control setting.
• In the airflow calculation presented by AHRI, AFUE would be replaced by a function of steady state efficiency (Effy
• External static pressure would be measured as specified in ASHRAE 37.
• Additional thermocouples would be added to the outlet grids used to measure temperature rise.
• Use of a mixer, as described in ANSI/ASHRAE Standard 41.1–1986 (RA 2006), would be required to minimize outlet flow temperature gradients if the temperature difference between any two thermocouples is greater than 1.5 °F.
• Greater temperature measurement accuracy and tighter stabilization criteria would be specified.
• The 18 °F temperature rise minimum specified by ASHRAE 37–2005 would be incorporated by reference.
Each of the listed modifications is described and explained in more detail in subsequent sections.
AHRI proposes to calculate airflow based on measured temperature rise, rated input heat capacity, and AFUE using the following equation (AHRI, No. 26 at p. 23):
DOE is concerned that using AFUE and the nameplate fuel energy input rate, as defined in AHRI's proposal, would not result in accurate representations of airflow at the proposed operating conditions because: (1) Neither parameter is measured at the proposed operating conditions; and (2) AFUE is a function of off-cycle parameters such as infiltration heat loss and pilot light heat generation, which do not contribute to the temperature rise proposed to be used to calculate airflow. While temperature rise would be measured at the ESP levels outlined in AHRI's alternative method (which are equivalent to those proposed in the NOPR and herein), AFUE and nameplate input rate would be determined based on measurements taken at the ESP levels required by the DOE furnace test procedure (
DOE requests comments on the proposed changes to the equation for calculating airflow. DOE recognizes that the use of the 1.08 conversion factor assumes that the airflow has standard air properties (
DOE is concerned that certain of the test conditions proposed by AHRI could lead to test results that are not representative of actual furnace fan energy use. AHRI's recommended method specifies that the maximum airflow be calculated based on a temperature rise measurement taken while operating the furnace in the maximum airflow-control setting and firing the burner. (AHRI, No. 26 at p. 21.) DOE is aware that the maximum airflow-control setting is often designated for cooling operation and not for heating. DOE anticipates that firing the burner while the furnace is in the maximum airflow-control setting is not typical of furnace operation, and that achieving this combination of settings by interfacing with the furnace controls may not be possible. The AHRI approach also specifies electrical input power in the heating airflow-control setting be measured without firing the burner.
DOE proposes to modify the AHRI recommended method to specify that maximum airflow be calculated based on a temperature rise measurement taken while operating the furnace in the rated heating airflow-control setting and firing the burner at the heat input capacity associated with that airflow-control setting. For more details regarding the proposed rated airflow-control settings, refer to Table II.2 in the Summary of the NOPR, 77 FR at 28676 (May 15, 2012). DOE expects that these proposed combinations of operating conditions are typical of field furnace use. These requirements would help ensure that test results are representative of actual furnace fan energy use, and would minimize the potential difficulties associated with firing the furnace in an airflow-control setting not intended for heating. DOE is not proposing any changes in this notice to the rated airflow-control settings proposed in the NOPR. The procedure proposed herein would require that the temperature rise measurement be taken in the default heating airflow-control setting for single-stage furnaces and in the default low heating airflow-control setting for multi-stage and modulating furnaces.
DOE recognizes that, compared to AHRI's suggested method, more complex calculations are required to determine the airflow in the maximum airflow-control setting based on a temperature rise measurement in the heating airflow-control setting. DOE proposes to specify that ESP measurements be taken in conjunction with the temperature rise and furnace fan electrical input power measurements for each rated airflow-control setting. Airflow in the rated heating airflow-control setting can be calculated using the airflow calculation equation proposed above. Once the airflow in the rated heating airflow-control setting has been calculated, the physical constant (
The same value for
DOE is aware that ESP, airflow, and electrical input measurements could vary due to the different physical properties of air (particularly density) at higher temperature. As a result, a different
For operation of a furnace, the higher ESP that occurs when it is firing would reduce the mass flow of air. Consequently, the value of Q
DOE requests comment on the proposed adjustment to the
DOE recognizes that a more accurate measurement of temperature rise could be made at higher temperature rises because the allowable error in temperature measurements would represent a lower percentage of the overall temperature rise. For example, the maximum allowable proposed error of ± 1 °F (± 0.5 °F at both the inlet and outlet) would represent an approximate error of 3 percent for a temperature rise of 30 °F, and half as much for a 60 °F temperature rise. DOE is aware that operating the furnace in the reduced heat setting for multi-stage furnaces would result in a lower temperature rise than if fired in the maximum heat setting. DOE requests comment on whether the maximum airflow should be calculated based on the temperature rise measured while operating the furnace fan in the maximum default heat airflow-control setting and at maximum heat input capacity to minimize the effect of temperature measurement error on the overall FER calculation. (See Issue 3 under “Issues on Which DOE Seeks Comment” in section V.B of this SNOPR.)
DOE is concerned that at higher elevations the temperature rise would be greater due to reduced air mass flow, resulting in a higher calculated airflow. DOE requests comments on the magnitude of potential elevation impacts on calculated airflow and FER values. DOE also requests comments on whether specifications, such as a maximum test elevation or elevation adjustment factor, should be used to avoid circumvention associated with conducting this test at high elevation. (See Issue 4 under “Issues on Which DOE Seeks Comment” in section V.B of this SNOPR.)
DOE believes that more detailed specifications for setting and measuring ESP are required than those in the AHRI suggested test method. AHRI's suggested test method specifies that the reference system ESP be achieved by “symmetrically restricting the outlet of the test duct.” (AHRI, No. 26 at pp. 8, 19, 20) The AHRI test method does not provide details on the equipment or procedures that should be used to meet this requirement. (DOE is aware that independent test labs typically apply cardboard ducting or tape to the corners of the outlet to achieve the desired ESP.) DOE requests comments on whether one or more methods for restricting the outlet duct should be included in the test procedure. (See Issue 5 under “Issues on Which DOE Seeks Comment” in section V.B of this SNOPR.)
According to AHRI's suggested test method, use of a return air duct in the test setup is optional. (AHRI, No. 26 at p. 20.) DOE proposes to also allow for the optional use of a return air duct; however, DOE is concerned that ESP may differ when measured with a return air duct compared to when measured without a return air duct. DOE believes that each different motor type may react differently with the use of a return air duct, but the impacts on the FER measurements may be small. DOE requests comments on the ESP measurements and FER values that result when not using a return air duct compared to when a return air duct is used, and whether the test procedure should explicitly require use of a return air duct. (See Issue 6 under “Issues on Which DOE Seeks Comment” in section V.B of this SNOPR.)
AHRI's suggested test method specifies that ESP measurements be made between the furnace openings and any restrictions or elbows in the test plenums or ducts and as close as possible to the air supply and return openings of the furnace. (AHRI, No. 26 at p. 20) DOE proposes to incorporate by reference the ASHRAE 37 provisions for measuring ESP (sections 6.4 and 6.5), which are consistent with AHRI's suggested specifications and provide more detail. DOE anticipates that these more detailed specifications would minimize variations in test setups and, in turn, improve repeatability. DOE proposes to specify that ESP be measured according to the setup illustrated in Figure 8 of ASHRAE 37 when a return air duct is used. This setup would require direct measurement of the static pressure difference between the inlet and outlet of the unit under test as opposed to taking separate static measurements at the inlet and outlet and calculating the difference between the two measurements. Direct measurement in this context means that the inlet and outlet pressure signal tubing would be connected on opposite sides of a single manometer, rather than using two manometers or transducers, each being open to the ambient on one
DOE recognizes that FER results generated according to the proposed test procedure are sensitive to the temperature rise measurement that would be used to calculate the airflow in the maximum airflow-control setting. DOE expects that the equipment and methods used to measure temperature rise in the AHRI method can be improved, which would result in a more accurate and repeatable test procedure. The modifications that DOE proposes are mostly derived from the provisions of the alternative method for calculating airflow specified in section 7.7.1.2 and 7.7.4 of ASHRAE 37–2005.
AHRI's recommended method adopts ASHRAE 103–2007 provisions that specify that temperature measurements shall have an error no greater than ±2 °F. In the worst case scenario, an error of 2 °F on both the inlet and outlet temperature measurements could result in an error of 4 °F. DOE estimates that an error of 4 °F for the temperature rise measurement could yield an error of approximately 10% in FER for a typical temperature rise between 30 °F and 60 °F.
DOE proposes to specify that temperature measurements have an error no greater than ±0.5 °F. The accuracy requirements of existing test standards that are used to test these products are more stringent—Table 1 in section 4 of ASHRAE 37–2005 requires temperature measurement accuracy of ±0.2 °F. DOE requests comment on whether ±0.5 °F is reasonably achievable. (See Issue 8 under “Issues on Which DOE Seeks Comment” in section V.B of this SNOPR.)
AHRI's proposed method does not include a minimum temperature rise requirement. DOE is concerned that the allowable error in temperature measurements coupled with a low temperature rise could result in inaccurate test results. For this reason, DOE proposes to require a minimum temperature rise of 18 °F, as specified in ASHRAE 37–2005. DOE notes that with its proposed ±0.5 °F temperature measurement accuracy requirement and its proposed minimum 18 °F temperature rise, the maximum potential error in measured airflow associated with the temperature rise measurement is approximately 5.6%. DOE requests comments on whether a minimum temperature rise should be required and, if so, what is an appropriate value for the minimum temperature rise. (See Issue 9 under “Issues on Which DOE Seeks Comment” in section V.B of this SNOPR.)
AHRI's recommended method adopts the stabilization criteria of the DOE test procedure for residential furnaces. 10 CFR part 430, subpart B, appendix N, section 7.0. According to section 7.0 of the DOE test procedure for furnaces, which references section 8.0 of ASHRAE 103–1993, steady-state conditions for gas and oil furnaces are attained as indicated by a temperature variation in three successive readings, taken 15 minutes apart, of not more than:
• 3 °F in the stack gas temperature for furnaces equipped with draft diverters;
• 5 °F in the stack gas temperature for furnaces equipped with either draft hoods, direct exhaust, or direct vent systems; and
• 1 °F in the flue gas temperature for condensing furnaces.
For electric furnaces, steady-state conditions are reached as indicated by a temperature variation of not more than 5 °F in the outlet temperature in four successive temperature readings taken 15 minutes apart.
DOE is concerned that the temperature variations specified in the above stabilization criteria are not stringent enough to maximize accuracy and repeatability for evaluating furnace fan performance. As mentioned above, the FER results generated according to the proposed test procedure are sensitive to temperature variation because they are a function of the airflow calculated using measured temperature rise. DOE proposes the following stabilization criteria to address this concern. For testing furnace fans used in gas and oil furnaces, DOE proposes that steady-state conditions are attained as indicated by a temperature variation in three successive readings, taken 15 minutes apart, of not more than:
• 1.5 °F in the stack gas temperature for furnaces equipped with draft diverters;
• 2.5 °F in the stack gas temperature for furnaces equipped with either draft hoods, direct exhaust, or direct vent systems; and
• 0.5 °F in the flue gas temperature for condensing furnaces.
For electric furnaces, DOE proposes that steady-state conditions are reached as indicated by a temperature variation of not more than 1 °F in the outlet temperature in four successive temperature readings taken 15 minutes apart. DOE requests comments on whether the proposed stabilization criteria are reasonably achievable, and whether the stabilization criteria for the AFUE test would be sufficient to assure that the entire furnace has thermally stabilized to a point such that the measured air temperature rise would no longer significantly change. (See Issue 10 under “Issues on Which DOE Seeks Comment” in section V.B of this SNOPR.)
AHRI's approach does not include provisions to account for potential inlet or outlet airflow temperature gradients. DOE is concerned that temperature gradients are likely to be present, which would compromise the accuracy and repeatability of the temperature rise measurement results. DOE proposes to specify the use of a mixer, as depicted in Figure 10 of ASHRAE 37–2005, which references ANSI/ASHRAE Standard 41.1–1986 (RA 2001), to minimize outlet flow temperature gradients if the temperature difference between any two thermocouples of the outlet air temperature grid is greater than 1.5 °F. DOE has not had the opportunity to evaluate the potential inaccuracies associated with allowing larger temperature gradients, and instead bases this selection on its use as the maximum allowable temperature difference threshold in ASHRAE 210/240 for the “C” and “D” tests for CAC products. These tests use temperature rise and airflow measurement to determine cooling capacity. The proposed furnace fan test method uses the inverse of the relationship for these factors to determine airflow based on measured temperature rise and input heat capacity. Hence, the implications for temperature gradients to result in measurement errors are equivalent. DOE requests comment on whether the effect on static pressure of adding a mixer would prevent the test setup from achieving the ESP levels specified in the DOE test procedure for residential furnaces or the lower ESP levels specified in this notice for measuring fan performance in the lowest rated airflow setting. DOE also seeks comment on whether additional thermocouples are needed to measure the inlet air temperature. (See Issue 11 under “Issues
DOE proposes to adopt all definitions in section 3 of ASHRAE 103, which are already codified in section 2 of Appendix N to Subpart B of Part 430. DOE also proposes to include the additional and modified definitions listed below.
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(a) Is designed to be the principal air circulation source for the living space of a residence;
(b) Is not contained within the same cabinet as a furnace or central air conditioner; and
(c) Is designed to be paired with HVAC products that have a heat input rate of less than 225,000 Btu per hour and/or cooling capacity less than 65,000 Btu per hour.
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DOE provides sampling plans for all covered products. The purpose of a sampling plan is to provide statistically valid representations of energy consumption or energy efficiency for each covered product by capturing the variability inherent in the manufacturing and testing process. These sampling plans apply to all aspects of the EPCA program for consumer products, including public representations, labeling, and compliance with energy conservation standards. 10 CFR 429.11. In the NOPR, DOE proposed that the existing sampling plans used for furnaces be adopted and applied to measures of energy consumption for furnace fans. 77 FR at 28691 (May 15, 2012).
AHRI and manufacturers commented that the 97.5 percent confidence limit required by the furnace sampling plan is too stringent.
Efficiency advocates also support a less stringent confidence interval. Adjuvant commented that it strives for a 90 percent confidence interval in its work with HVAC products, which Adjuvant finds to be an appropriate level. Adjuvant added that it rarely uses 95 percent and would not push for anything higher than 90. (Adjuvant, Public Meeting Transcript, No. 23 at p. 229.) NPCC and NEEA commented that a 97.5 percent confidence limit is unrealistically stringent and might cause enforcement testing issues that are not helpful in certifying efficiency levels. NPCC and NEEA added that air flow and external static pressure measurements are prone to larger error bands than measurements such as power levels or temperatures, and are likely to cause real problems for manufacturers trying to certify to the 97.5 percent confidence limit. NPCC and NEEA recommended using the same confidence limits as those used for heat pump and air conditioning systems, which are subject to some of the same measurement error bands as air handlers. (NPCC/NEEA, No. 22 at p. 7.) AHRI stated that confidence limits historically have been set without supporting data and suggested that DOE do a rigorous analysis to determine an appropriate confidence limit. (AHRI, Public Meeting Transcript, No. 23 at p. 225.)
DOE agrees with interested parties that the furnace fan electrical input power measurements and external static pressure measurements that would be required by the test procedure proposed herein are different and inherently more variable than the measurements required for AFUE. DOE proposes to adopt a sampling plan that requires any represented value of FER to be greater or equal to the mean of the sample or the upper 90 percent (one-tailed) confidence limit divided by 1.05, as specified in the sampling plan for CAC/HP products. 10 CFR 429.16 DOE will continue to analyze the available test data to evaluate the proposed sampling plan parameters. DOE requests comments, including detailed data, regarding test result variance that it can use to assess the appropriateness of the sampling plan proposed herein. (See
EPCA, as amended by the Energy Independence and Security Act of 2007, Public Law 110–140 (EISA), requires that any final rule for a new or amended energy conservation standard adopted after July 1, 2010, must address standby mode and off mode energy use pursuant to 42 U.S.C. 6295(o). (42 U.S.C. 6295(gg)(3)) Thus, the statute implicitly directs DOE, when developing test procedures to support new energy conservation standards, to account for standby mode and off mode energy consumption. EISA also requires that such energy consumption be integrated into the overall energy efficiency, energy consumption, or other energy descriptor, unless the current test procedure already accounts for standby mode and off mode energy use. If an integrated test procedure is technically infeasible, DOE must prescribe a separate standby mode and off mode test procedure for the covered product, if technically feasible. (42 U.S.C. 6295(gg)(2)(A)) Accordingly, DOE must address the standby mode and off mode energy use of furnace fans in this test procedure. However, DOE has already fully incorporated standby mode and off mode energy use in the test procedures (or proposed test procedures) for all of the products to which this test procedure rulemaking would be applicable.
Table III.1 summarizes the test procedure rulemaking vehicles through which DOE addresses standby mode and off mode energy consumption for the various types of products which circulate air through ductwork.
DOE prescribed the measurement of standby mode and off mode energy use for non-weatherized gas furnaces, oil-fired furnaces, and electric furnaces in the furnace test procedure, 10 CFR part 430, subpart B, appendix N, section 8.0. DOE proposed coverage of standby mode and off mode energy use for modular blowers and weatherized gas furnaces in a June 2, 2010 NOPR. 75 FR 31224. In a September 13, 2011 NOPR, DOE proposed amendments to its furnace test procedure related to standby mode and off mode. 76 FR 56339. DOE subsequently published one SNOPR on April 1, 2011, and another on October 24, 2011, regarding standby mode and off mode test procedures for these products. 76 FR 18105; 76 FR 65616. DOE published a furnaces standby and off mode test procedure final rule on December 31, 2012. 77 FR 76831. Furnace fans are integrated in the electrical systems of the HVAC products in which they are used and controlled by the main control board. Therefore, the standby mode and off mode energy use associated with these furnace fans would be measured by the established or proposed test procedures associated with these products. There is no need for DOE to adopt additional test procedure provisions for these modes in this rulemaking.
In the NOPR, DOE identified four installation types with unique reference system ESP considerations:
• Heating-only units;
• Units with an internal evaporator coil;
• Units designed to be paired with an evaporator coil; and
• Manufactured home units.
DOE anticipated that some HVAC products may not be designed to provide cooling. Specifically, DOE identified hydronic air handler models that are not designed to be paired with an evaporator coil (either factory-installed or separate). DOE proposed to specify a lower reference system ESP for these products because they do not experience the additional pressure drop of circulating air past an evaporator coil.
Ingersoll Rand commented that it was not aware of any product that would be categorized as a heating-only product. Ingersoll Rand added that including this installation type could provide manufacturers with a means of gaming the test procedure by modifying its furnaces to eliminate factory-installed cooling capabilities, which would allow such furnaces to be tested at the lower ESP specified for heating-only units. For these reasons, Ingersoll Rand recommended that DOE eliminate the heating-only designation. (Ingersoll Rand, Public Meeting Transcript, No. 23 at p. 50.) NPCC and NEEA also suggested that DOE eliminate the heating-only installation type. (NPCC/NEEA, No. 22 at p. 6)
DOE agrees with interested parties that the heating-only installation type should be eliminated from consideration. The scope of applicability of the test procedure proposed herein does not include hydronic air handlers as discussed in section III.A. Consequently, DOE proposes to eliminate the heating-only product designation as a result.
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) at OMB.
The Regulatory Flexibility Act (5 U.S.C. 601
DOE reviewed today's proposed rule under the provisions of the Regulatory Flexibility Act and the procedures and policies published on February 19, 2003, 68 FR 7990. DOE has tentatively concluded that the proposed rule would not have a significant economic impact on a substantial number of small entities under the provisions of the Regulatory Flexibility Act. The factual basis for this certification is as follows:
The Small Business Administration (SBA) considers an entity to be a small business if, together with its affiliates, it employs fewer than a threshold number of workers as specified in 13 CFR part 121. The threshold values set forth in these regulations use size standards and codes established by the North American Industry Classification System (NAICS) that are available at:
This proposed rule would establish test procedures that would be used for representations of energy use and to test compliance with new energy conservation standards, which are being developed in a concurrent rulemaking, for the products that are the subject of this rulemaking. This notice proposes new test procedures for active mode testing for all such products. The proposed rule would require a modified version of the testing methods prescribed in a public submission from AHRI (the trade organization that represents manufacturers of furnace fans). The AHRI proposal recommends test methods that are purposely aligned with the current DOE test procedure for furnaces in order to minimize test burden. (AHRI, No. 26); Appendix N of subpart B of 10 CFR part 430. As discussed above, this would not represent a substantial burden to any furnace fan manufacturer, small or large. According to AHRI, its proposed method would result in an 80 to 90 percent reduction in test burden compared to the test procedure proposed by DOE in the NOPR. AHRI attributed this reduction primarily to manufacturers not having to acquire or use any test equipment beyond the equipment that is already used to conduct the test method specified in the DOE furnace test procedure (
DOE also expects that the time and cost to conduct testing according to the proposed test procedure will not be significantly burdensome. During discussions with manufacturers, DOE received feedback that the time to test a single unit according to the AHRI method would be 30 to 60 percent less relative to using the procedure DOE proposed in the NOPR. Goodman performed tests according to both DOE's NOPR test procedure proposal and AHRI's suggested method and found that testing time is reduced by almost 60 percent using AHRI's method. (Goodman, No. 17 at p. 3.) Rheem also conducted tests according to both procedures and stated that the time to test a single-stage furnace was reduced from 4 hours to 45 minutes by using the AHRI method. (Rheem, No. 25 at p. 4.) Assuming that the labor rate for a given manufacturer would be the same regardless of test method, DOE expects that the cost to conduct a test would also be reduced by 30 to 60 percent. DOE estimated that conducting a test according to its NOPR proposed test procedure would cost a small manufacturer $2.30 per unit shipped. This estimate is largely based on DOE's experience with third-party test lab labor rates for fan testing, 77 FR at 28691 (May 15, 2012). A 30 percent reduction would yield a conservative cost estimate of $1.61 per unit shipped to conduct a test according to AHRI's method. DOE does not expect that its proposed modifications to the AHRI method would result in additional costs to conduct a test. DOE finds that the selling price for HVAC products that incorporate furnace fans ranges from approximately $400 to $4,000. Therefore, the added cost of testing per DOE's revised proposed test procedure would be less than one percent of the manufacturer selling price (and lower than 0.1 percent in some cases).
For these reasons, DOE certifies that the proposed rule, if adopted, would not have a significant economic impact on a substantial number of small entities. Accordingly, DOE has not prepared a
There is currently no information collection requirement related to the test procedure for furnace fans. In the event that DOE proposes an energy conservation standard with which manufacturers must demonstrate compliance, or otherwise proposes to require the collection of information derived from the testing of furnace fans according to this test procedure, DOE will seek OMB approval of such information collection requirement.
Manufacturers of covered products must certify to DOE that their products comply with any applicable energy conservation standard, 10 CFR 429.12. In certifying compliance, manufacturers must test their products according to the applicable DOE test procedure, including any amendments adopted for that test procedure.
DOE established regulations for the certification and recordkeeping requirements for certain covered consumer products and commercial equipment, 76 FR 12422 (March 7, 2011). The collection-of-information requirement for the certification and recordkeeping was subject to review and approval by OMB under the Paperwork Reduction Act (PRA). This requirement was approved by OMB under OMB Control Number 1910–1400. Public reporting burden for the certification was estimated to average 20 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.
As stated above, in the event DOE proposes an energy conservation standard for furnace fans with which manufacturers must demonstrate compliance, DOE will seek OMB approval of the associated information collection requirement. DOE will seek approval either through a proposed amendment to the information collection requirement approved under OMB control number 1910–1400 or as a separate proposed information collection requirement.
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 notice of proposed rulemaking, DOE proposes a new test procedure for furnace fans. 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 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 proposed rule and has tentatively 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 today's proposed 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. With regard to 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 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, the proposed 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 proposed 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
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.
DOE has determined, under Executive Order 12630, “Governmental Actions and Interference with Constitutionally Protected Property Rights,” 53 FR 8859 (March 18, 1988), that this regulation 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 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 today's proposed 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 proposed significant energy action, the agency must provide 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 tentatively concluded that today's regulatory action, which would prescribe the test procedure for measuring the energy efficiency of furnace fans, is not a significant energy action because the proposed test procedure is not a significant regulatory action under Executive Order 12866 and is not likely to 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. Accordingly, DOE has not prepared a Statement of Energy Effects on the proposed rule.
Under section 301 of the Department of Energy Organization Act (Pub. L. 95–91), DOE must comply with all laws applicable to the former Federal Energy Administration, including section 32 of the Federal Energy Administration Act of 1974 (Pub. L. 93–275), as amended by the Federal Energy Administration Authorization Act of 1977 (Pub. L. 95–70). (15 U.S.C. 788) Section 32 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.
The proposed rule incorporates testing methods contained in the DOE test procedure for furnaces codified in Appendix N or subpart B of part 430 of the CFR (which incorporates by reference ANSI/ASHRAE Standard 103, “
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
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 compact disk (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, written in English, and 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 which 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).
Although DOE welcomes comments on any aspect of this proposal, DOE is particularly interested in receiving comments and views of interested parties concerning the following issues:
DOE is concerned that using AFUE and Q
DOE recognizes that the use of the 1.08 conversion factor assumes that the airflow has standard air properties (
DOE proposes to modify the AHRI recommended method to specify that maximum airflow be calculated based on a temperature rise measurement taken while operating the furnace in the rated heating airflow-control setting and firing the burner at the heat input capacity associated with that airflow-control setting. DOE recognizes that, compared to AHRI's suggested method, more complex calculations are required to determine the airflow in the maximum airflow-control setting based on a temperature rise measurement in the heating airflow-control setting. Section III.B.1 includes a detailed discussion of DOE's reasoning, methodology, and equations for the modified approach to calculating airflow in the maximum airflow control setting. DOE requests comments on the proposed modified method for calculating airflow in the maximum airflow-control setting. DOE also requests comment on whether the
DOE recognizes that a more accurate measurement of temperature rise could be made at higher throughput temperatures because the allowable error in temperature measurements would represent a lower percentage of the overall temperature rise. DOE requests comment on whether the maximum airflow should be calculated based on the temperature rise measured while operating the furnace fan in the maximum default heat airflow-control setting and at maximum heat input capacity to minimize temperature measurement error. Section III.B.1 includes a detailed discussion of this issue.
DOE is concerned that at higher elevations the temperature rise would be high due to reduced air mass flow, resulting in higher calculated airflow. DOE requests comments on the magnitude of potential elevation impacts on calculated airflow and FER values. DOE also requests comments on whether specifications, such as a maximum test elevation or elevation adjustment factors, should be used to avoid circumvention associated with conducting this test at high elevation.
AHRI's suggested test method specifies that the reference system ESP be achieved by “symmetrically restricting the outlet of the test duct.” (AHRI, No. 26 at p. 19.) The AHRI test method does not provide details on the method or equipment to be used to meet this requirement. DOE is aware that independent test labs typically apply cardboard ducting or tape to the corners of the outlet until the desired ESP is achieved. DOE requests comments on whether more specific methods for restricting the outlet duct should be included and what these specific duct restriction requirements should be. Section III.B.2 includes a detailed discussion of this issue.
According to AHRI's suggested test method, use of an return air duct in the test setup is optional. (AHRI, No. 26 at p. 20.) DOE proposes to also allow for the optional use of a return air duct; however, DOE is concerned that ESP may differ when measured with a return air duct compared to when measured without a return air duct. DOE requests comments on the relative ESP measurements and FER values that result when not using an air return duct compared to when an air return duct is used, and whether the test procedure should explicitly require use of a return air duct. Section III.B.2 includes a detailed discussion of this issue.
AHRI's suggested test method specifies that ESP measurements be made as close as possible to the air supply and return openings of the furnace and in all cases, between the furnace openings and any restrictions or elbows in the test plenums or ducts. (AHRI, No. 26 at p. 20.) DOE agrees with these specifications, but proposes to incorporate by reference the ASHRAE 37 provisions for measuring ESP (sections 6.4 and 6.5), which are consistent with AHRI's suggested specifications but are more detailed. DOE anticipates that these more detailed specifications would minimize variations in test setups and, in turn, improve repeatability. DOE requests comments on its proposed provisions for measuring ESP, which are adopted from ASHRAE 37–2005. Section III.B.2 includes details of DOE's proposal for measuring external static pressure.
AHRI's recommended method adopts ASHRAE 103–1993 provisions that specify that temperature measurements shall have an error no greater than ±2 °F. DOE proposes to specify that temperature measurements have an error no greater than ±0.5 °F to minimize error in the resulting FER values. DOE requests comment on whether ±0.5 °F is reasonably achievable. Section III.B.3 includes a more detailed discussion of this issue.
AHRI's method does not include a minimum temperature rise requirement. DOE is concerned that the allowable error in temperature measurements coupled with a low temperature rise could result in inaccurate test results. For this reason, DOE also proposes to require a minimum temperature rise of 18 °F, as specified in ASHRAE 37–2005. DOE requests comments on whether a minimum temperature rise should be required, and if so, what an appropriate value for the minimum temperature rise would be. Section III.B.3 includes a detailed discussion of this issue.
AHRI's recommended method adopts the stabilization criteria of the DOE test procedure for residential furnaces. 10 CFR part 430, subpart B, appendix N, section 7.0 DOE is concerned that the temperature variations specified in the residential furnace stabilization criteria are not stringent enough to maximize accuracy and repeatability for evaluating furnace fan performance according to the proposed test procedure. In section III.B.3 DOE proposes modified stabilization criteria to address this concern.. DOE requests comments on whether the proposed stabilization criteria are reasonably achievable, and whether the stabilization criteria for the AFUE test would be sufficient to assure that the entire furnace has thermally stabilized to a point such that the measured air temperature rise would no longer significantly change.
AHRI's approach does not include provisions to account for potential inlet or outlet airflow temperature gradients. DOE is concerned that temperature gradients are likely to be present, which would compromise the accuracy and repeatability of the temperature rise measurement results. DOE proposes to specify the use of a mixer, as depicted in Figure 10 of ASHRAE 37–2005, which references ANSI/ASHRAE Standard 41.1–1986 (RA 2001), to minimize outlet flow temperature gradients if the temperature difference between any two thermocouples of the outlet air temperature grid is greater than 1.5 °F. DOE requests comments on the proposed requirements for use of an air mixer. DOE also requests comment on whether the static pressure drop of adding a mixer would prevent the test setup from achieving the ESP levels specified in the DOE test procedure for furnaces or the lower ESP levels specified in this notice for measuring fan performance in the lowest rated airflow setting. DOE also seeks comment on whether additional thermocouples are needed for the inlet. Section III.B.3 includes a detailed discussion of this issue.
DOE agrees with interested parties that the furnace fan electrical input power measurements and external static pressure measurements that would be required by the test procedure proposed herein are different and inherently more variable than the measurements required for AFUE. DOE proposes to adopt a sampling plan that requires any represented value of FER to be greater or equal to the mean of the sample or the upper 90 percent (one-tailed) confidence limit divided by 1.05, as specified in the sampling plan for CAC/HP products. 10 CFR 429.16 DOE requests comments that include detailed data regarding test result variance that it can use to assess the appropriateness of the sampling plan proposed herein.
The Secretary of Energy has approved publication of today's notice of proposed rulemaking.
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 proposes to amend parts 429 and 430 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)
(2) For each basic model of heating, ventilation, and air-conditioning (HVAC) product using a furnace fan, a sample of sufficient size shall be randomly selected and tested to ensure that any represented value of fan energy rating (FER), rounded to the nearest integer, shall be greater than or equal to the higher of:
(i) The mean of the sample, where:
And,
(ii) The upper 90 percent confidence limit (UCL) of the true mean divided by 1.05, where:
And
(b)
42 U.S.C. 6291–6309; 28 U.S.C. 2461 note.
The addition reads as follows:
(f) * * *
(10) ANSI/ASHRAE Standard 103–2007, (“ASHRAE 103–2007”), Methods of Testing for Annual Fuel Utilization Efficiency of Residential Central Furnaces and Boilers, except for sections 7.2.2.5, 8.6.1.1, 9.1.2.2, 9.5.1.1, 9.5.1.2.1, 9.5.1.2.2, 9.5.2.1, 9.7.1, 11.2.12, 11.3.12, 11.4.12, 11.5.12 and appendices B and C, ASHRAE approved June 27, 2007, ANSI approved March 25, 2008, IBR approved for appendix AA to subpart B.
(cc)
Any representation made after September 30, 2013 for energy consumption of furnace fans must be based upon results generated under this test procedure. Upon the compliance date(s) of any energy conservation standard(s) for furnace fans, use of the applicable provisions of this test procedure to demonstrate compliance with the energy conservation standard will also be required.
1.
2.
2.1.
2.2.
2.3.
2.4.
2.5.
2.6.
2.7.
2.8.
2.9.
(a) Is designed to be the principal air circulation source for the living space of a residence;
(b) Is not contained within the same cabinet as a furnace or central air conditioner; and
(c) Is designed to be paired with HVAC products that have a heat input rate of less than 225,000 Btu per hour or cooling capacity less than 65,000 Btu per hour.
2.10.
2.11.
2.12.
2.13.
3.
4.
5.
5.1.
5.1.1.
6.
6.1.
6.2.
6.3.
6.4.
6.5.
6.6.
7.
7.1.
8.
8.1.
8.2.
8.3.
(a) 1.5 °F in the stack gas temperature for furnaces equipped with draft diverters;
(b) 2.5 °F in the stack gas temperature for furnaces equipped with either draft hoods, direct exhaust, or direct vent systems; and
(c) 0.5 °F in the flue gas temperature for condensing furnaces.
8.4.
8.5.
8.6.
8.6.1.
Once the specified ESP has been achieved, the same outlet duct restrictions shall be used for the remainder of the furnace fan test.
8.6.2.
8.6.3.
9.
10.
10.1.
The estimated national average operating hours presented in Table VI.2 shall be used to calculate FER.
Federal Aviation Administration (FAA), DOT.
Notice of proposed rulemaking (NPRM).
We propose to adopt a new airworthiness directive (AD) for certain General Electric Company (GE) GE90–76B, –85B, –90B, –94B, –110B1, and –115B turbofan engines. This proposed AD was prompted by multiple reports of failure of certain stage 1 high-pressure turbine (HPT) stator shrouds due to accelerated corrosion and oxidation. This proposed AD would require initial and repetitive on-wing borescope inspections (BSIs) for corrosion and oxidation, of the affected stage 1 HPT stator shrouds, and removal from service before further flight, if the parts fail the inspection. We are proposing this AD to prevent failure of the stage 1 HPT stator shrouds, resulting in in-flight shutdown of one or more engines, loss of thrust control, and damage to the airplane.
We must receive comments on this proposed AD by June 3, 2013.
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 AD, contact General Electric Company, One Neumann Way, MD Y–75, Cincinnati, OH; phone: 513–552–2913; email:
You may examine the AD docket on the Internet at
Jason Yang, Aerospace Engineer, Engine Certification Office, FAA, 12 New England Executive Park, Burlington, MA 01803; phone: 781–238–7747; fax: 781–238–7199; email:
We invite you to send any written relevant data, views, or arguments about this proposal. Send your comments to an address listed under the
We will post all comments we receive, without change, to
We received one report of an aborted takeoff, and multiple reports of stage 1 HPT stator shroud distress resulting in engine removals on airplanes with GE90 turbofan engines. Investigation revealed that the stage 1 HPT stator shrouds failed due to accelerated corrosion and oxidation. GE is still investigating the cause of the accelerated corrosion and oxidation. This condition, if not corrected, could result in failure of the stage 1 HPT stator shrouds, resulting in in-flight shutdown of one or more engines, loss of thrust control, and damage to the airplane.
We reviewed GE Service Bulletin (SB) No. GE90 S/B 72–1076, dated November 19, 2012, and SB No. GE90–100 S/B 72–0528, dated November 15, 2012. The SBs describe procedures for performing BSIs of the stage 1 HPT stator shrouds for accelerated corrosion and oxidation.
We are proposing this AD 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.
This proposed AD would require initial and repetitive on-wing BSIs of stage 1 HPT stator shrouds, part number (P/N) 1847M52P14, and P/N 1847M52P16, for corrosion and oxidation, and removal from service before further flight if the parts fail the inspection.
The SBs require completing and sending to GE the Inspection Findings Report Form after each inspection. This proposed AD does not.
We estimate that this proposed AD would affect about 100 GE90 engines installed on airplanes of U.S. registry. We also estimate that it would take about four hours per engine to perform one inspection. The average labor rate is $85 per hour. Based on these figures, we estimate the cost of the proposed AD on U.S. operators for one inspection to be $34,000.
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.
(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 to the extent that it justifies making a regulatory distinction, 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 June 3, 2013.
None.
This AD applies to General Electric Company (GE):
(1) GE90–76B, –85B, –90B, and –94B turbofan engines with stage 1 high-pressure turbine (HPT) stator shrouds, part number (P/N) 1847M52P14, installed.
(2) GE90–110B1 and –115B turbofan engines with stage 1 HPT stator shrouds, P/N 1847M52P16, installed.
This AD was prompted by multiple reports of failure of certain stage 1 HPT stator shrouds due to accelerated corrosion and oxidation. We are issuing this AD to prevent failure of the stage 1 HPT stator shrouds, resulting in in-flight shutdown of one or more engines, loss of thrust control, and damage to the airplane.
Comply with this AD within the compliance times specified, unless already done.
(1) Perform an initial on-wing borescope inspection (BSI) of the stage 1 HPT stator shrouds for corrosion and oxidation before accumulating 2,100 cycles since new (CSN), or within 100 cycles in service (CIS) after the effective date of this AD, whichever occurs later.
(2) Thereafter, repeat the BSI of the stage 1 HPT stator shrouds every 250 cycles since last inspection (CSLI) or fewer, depending on the results of the inspection.
(3) For engines listed in paragraph (c)(1) of this AD:
(i) Perform the inspections using Section 3.A of the Accomplishment Instructions of GE Service Bulletin (SB) No. GE90 S/B 72–1076, dated November 19, 2012; and
(ii) Use Section 3.B of the Accomplishment Instructions of SB No. GE90 S/B 72–1076, dated November 19, 2012, to determine the next inspection interval.
(4) For engines listed in paragraph (c)(2) of this AD:
(i) Perform the inspections using Section 3.A of the Accomplishment Instructions of GE SB No. GE90–100 S/B 72–0528, dated November 15, 2012; and
(ii) Use Section 3.B of the Accomplishment Instructions of SB No. GE90–100 S/B 72–0528, dated November 15, 2012, to determine the next inspection interval.
(5) Remove from service before further flight, any stage 1 HPT stator shrouds found with any hole further than 0.35-inch from the shroud leading edge and hole size more than 0.25-inch diameter, or more than 0.049 square inch area.
(6) The inspection findings reporting specified in Section 3.A of the
The Manager, Engine Certification Office, FAA, may approve AMOCs for this AD. Use the procedures in 14 CFR 39.19 to make your request.
(1) For more information about this AD, contact Jason Yang, Aerospace Engineer, Engine Certification Office, FAA, 12 New England Executive Park, Burlington, MA 01803; phone: 781–238–7747; fax: 781–238–7199; email:
(2) For service information identified in this AD, contact General Electric Company, One Neumann Way, MD Y–75, Cincinnati, OH; phone: 513–552–2913; email:
Federal Aviation Administration (FAA), DOT.
Notice of Draft Interpretation.
This action provides interested persons with the opportunity to comment on the FAA's draft interpretation regarding nonstop international supplemental operations scheduled for longer than 12 hours. Additionally, this draft interpretation discusses the appropriate international flight time limitations that would apply to the operation. As discussed in the draft interpretation, the FAA finds that the operation of such flights would be precluded under the flight time limitations of the “U.S. mainland rules” found in the supplemental flight and duty rules. However, the operation could be conducted under the “international rules” provisions of our regulations.
Comments must be received on or before May 2, 2013.
You may send comments identified by docket number FAA–2012–1239 using any of the following methods:
•
•
•
•
Dean E. Griffith, Attorney, International Law, Legislation and Regulations Division, Office of Chief Counsel, Federal Aviation Administration, 800 Independence Avenue SW., Washington, DC 20591; telephone: (202) 267–3073; email:
The FAA invites interested persons to submit written comments, data, or views concerning this interpretation. The most helpful comments reference a specific portion of the draft interpretation, explain the reason for any recommended change, and include supporting data. To ensure the docket does not contain duplicate comments, please send only one copy of written comments, or if you are filing comments electronically, please submit your comments only one time.
The FAA will file in the docket all comments received, as well as a report summarizing each substantive public contact with FAA personnel concerning this proposal. Before acting on this proposal, the FAA will consider all comments received on or before the closing date for comments and any late-filed comments if it is possible to do so without incurring expense or delay.
You can get an electronic copy using the Internet by—
(1) Searching the Federal eRulemaking Portal (
(2) Visiting the FAA's Regulations and Policies Web page at
(3) Accessing the Government Printing Office's Web page at
You can also get a copy by sending a request to the Federal Aviation Administration, Office of Rulemaking, ARM–1, 800 Independence Avenue SW., Washington, DC 20591, or by calling (202) 267–9680. Make sure to identify the docket number or notice number of this proposal.
The FAA publishes draft legal interpretations when the matter in question is likely to be highly controversial or the likely answer has the potential to significantly and adversely affect long-standing practices that regulated parties have been engaged in, reasonably believing that these practices were consistent with FAA regulations. The intent is not to seek input on whether the FAA is correct—the FAA has the responsibility for interpreting its regulations. Rather, the reason for publishing the draft interpretation for comment is to see whether there may be unintended consequences for regulated parties that merit a further examination of how the agency's regulatory provisions should be applied in conjunction with agency policy and guidance material.
We are issuing this draft interpretation because it has come to our attention that supplemental air carriers might be misinterpreting and misapplying the regulations governing flight time limitations for supplemental operations to operate international flight segments longer than 12 hours by reading § 121.509 of title 14, Code of Federal Regulations in isolation, without also complying with § 121.503(a) or, in the alternative, without adequate sleeping facilities for the flight crew as required under § 121.523(b). As discussed below, such a reading fails to consider the full meaning of the FAA's regulations.
The purpose of this notice of draft interpretation is to address whether a supplemental air carrier may conduct an international nonstop flight scheduled for more than 12 hours without crew rest facilities on board the aircraft. The answer is “no.”
For purposes of this interpretation we will use the hypothetical example of a supplemental air carrier that has scheduled four pilots to conduct a non-
Supplemental air carriers conducting overseas and international supplemental operations may elect, pursuant to § 121.513, to comply with the flight time limitations of §§ 121.515 and 121.521 through 121.525 (commonly referred to as the “international rules”), rather than the flight time limitations found in §§ 121.503 through 121.511 (commonly referred to as the “U.S. mainland rules”).
We will first evaluate whether the operation could be conducted under the “U.S. mainland rules” and then discuss how the operation could be conducted under the “international rules.”
Section 121.503 sets out the basic flight time limitations and rest requirements for pilots during supplemental operations. Section 121.503(a) establishes that a pilot may be scheduled to “fly in an airplane for eight hours or less during any 24 consecutive hours without a rest period during those eight hours.”
Section 121.503(f) provides an exception to the above 8-hour limit for transcontinental non-stop flights, allowing a crewmember to be scheduled for “more than eight but less than 10 hours of continuous duty without an intervening rest period” under certain conditions.
This exception to the hard limit of 8 hours came about as a result of the improvements in aircraft capabilities and range, which led to the ability to conduct transcontinental non-stop flights.
Section 121.509 establishes flight time limitations for four pilot crews in addition to those specified in § 121.503(a). This section provides that, in a 24 hour period, a pilot may not be scheduled for more than 8 hours of flight deck duty, 16 hours of duty aloft, and 20 hours of duty. 14 CFR 121.509(a)-(b). Read in the context of § 121.503(a), a pilot may be scheduled for a total of 16 hours of duty aloft,
Accordingly, unless the hypothetical operation is scheduled in segments of eight hours or less it cannot be conducted under the flight time limitations contained in §§ 121.503-.511.
In 1955, the CAB established SR–410 which extended the 8-hour rule for supplemental air carriers to 10 hours for transcontinental nonstop flights on “substantially the same basis as they are currently applied to scheduled air carriers.”
Additionally, when scheduled realistically, flights may exceed the 8 hour continuous flying time limit due to circumstances beyond the control of the certificate holder. In such circumstances, § 121.503(b) requires the pilot to have 16 hours of rest prior to being assigned any duty with the certificate holder.
The next question is whether the flight could be conducted under the “international rules” found in § 121.515 and §§ 121.521 through 121.525 if the certificate holder makes that election under § 121.513. In connection with that question is the issue of when and under what circumstances “adequate sleeping quarters” are required.
First, § 121.521 states that an airman may not be scheduled to be “aloft as a member of the flight crew in an airplane that has a crew of two pilots and at least one additional flight crewmember for more than 12 hours during any 24 consecutive hours.” Because the hypothetical flight in question is scheduled to be aloft for 12.5 hours, it could not be conducted with only two pilots and one additional flight crewmember because a certificate holder may only schedule this crew complement for 12 total hours aloft or less.
Next, § 121.523 establishes the flight time limitations for a crew of three or more pilots and additional airmen as required. Unlike § 151.521, this section allows flights lasting longer than 12 hours. In consideration of the longer flights, § 121.523 requires a crew of at least three pilots and additional airmen as required, provides additional rest provisions, limits flight deck duty time for flight engineers and navigators, and requires the certificate holder to “provide adequate sleeping quarters on the airplane whenever an airman is scheduled to be aloft as a flight crewmember for more than 12 hours during any 24 consecutive hours.” § 121.523(b). Because the operation in question is scheduled with a four-pilot complement, it would meet the crew requirements under this section. However, in order to operate under this provision, the certificate holder would need to comply with all of the provisions of § 121.523, including the need to provide adequate sleeping quarters on the airplane.
Therefore, the hypothetical supplemental air carrier operation in which four pilots are scheduled to conduct a non-stop flight lasting 12.5 hours, between a point outside the contiguous United States and a point in the contiguous United States, or other locations permitting the § 121.513 election, could only be operated under the flight time limitations of § 121.523 (including the required crew rest facilities on board the aircraft). It could not be conducted as proposed under the provisions of §§ 121.503, 121.509 or 121.521.
Office of the Secretary, Employment and Training Administration, Department of Labor.
Withdrawal of proposed rule.
With this document, the Department of Labor (DOL) is withdrawing its proposed rule that accompanied its direct final rule revising the regulations governing administrative claims under the Federal Tort Claims Act and related statutes.
Effective April 2, 2013 the proposed rule published on April 13, 2012 (77 FR 22236), is withdrawn.
Catherine P. Carter, Counsel for Claims and Compensation, Office of the Solicitor, U.S. Department of Labor, Room S–4325, 200 Constitution Avenue NW., Washington, DC 20210, Telephone: 202–693–5320 (this is not a toll-free number). Individuals with hearing or speech impairments may access this telephone number via TTY by calling the toll-free Federal Information Relay Service at 1–800–877–8339.
On April 13, 2012, DOL published a direct final rule (77 FR 22204) and concurrent notice of proposed rulemaking, proposing to amend the regulations governing administrative claims under the Federal Tort Claims Act and related statutes. In both the direct final rule and notice of proposed rulemaking, DOL explained that if no significant adverse comments were received to the notice of proposed rulemaking, DOL would withdraw the proposed rule and the direct final rule would become effective on July 12, 2012 without further notice. DOL has received no comments regarding either the direct final rule or the notice of proposed rulemaking. Accordingly, DOL is not proceeding with the proposed rule and is withdrawing it from the rulemaking process. DOL is also confirming the effective date of the direct final rule as July 12, 2012.
Coast Guard, DHS.
Notice of proposed rulemaking.
The Coast Guard proposes to establish a special local regulation on the waters of Charlotte Amalie Harbor in St Thomas, USVI during the St. Thomas Carnival Watersport Activities, a high speed boat race. The event is scheduled to take place on Sunday, April 21, 2013. Approximately 40 high-speed power boats will be participating in the races and it is anticipated that 50 spectator crafts will be present during the races. The special local regulation is necessary for the safety of race participants,
Comments and related material must be received by the Coast Guard on or before April 10, 2013.
You may submit comments identified by docket number using any one of the following methods:
(1)
(2)
(3)
See the “Public Participation and Request for Comments” portion of the
If you have questions on this rule, call or email Chief Warrant Officer Anthony Cassisa, Sector San Juan Prevention Department, Coast Guard; telephone (787) 289–2073, email
We encourage you to participate in this rulemaking by submitting comments and related materials. All comments received will be posted without change to
If you submit a comment, please include the docket number for this rulemaking, indicate the specific section of this document to which each comment applies, and provide a reason for each suggestion or recommendation. You may submit your comments and material online at
To submit your comment online, go to
If you submit your comments by mail or hand delivery, submit them in an unbound format, no larger than 8½ by 11 inches, suitable for copying and electronic filing. If you submit comments by mail and would like to know that they reached the Facility, please enclose a stamped, self-addressed postcard or envelope. We will consider all comments and material received during the comment period and may change the rule based on your comments.
To view comments, as well as documents mentioned in this preamble as being available in the docket, go to
Anyone can search the electronic form of comments received into any of our dockets by the name of the individual submitting the comment (or signing the comment, if submitted on behalf of an association, business, labor union, etc.). You may review a Privacy Act notice regarding our public dockets in the January 17, 2008, issue of the
We do not now plan to hold a public meeting. But you may submit a request for one, using one of the methods specified under
The Coast Guard is issuing this notice of proposed rulemaking (NPRM) with a comment period shorter than 30 days. The Coast Guard is doing this because the sponsor did not provide information regarding the event details with sufficient time to provide for a 30 day comment period. This is an annual event, which in the past has not received comments from the public, however, the Coast Guard prefers to allow the public an opportunity to comment, therefore it is publishing this NPRM with a comment period shorter than 30 days.
The legal basis for the rule is the Coast Guard's authority to establish special local regulations: 33 U.S.C. 1233. The purpose of the rule is to ensure safety of life on navigable waters of the United States during the St Thomas Carnival Watersport Activities.
On April 21, 2013, Virgin Islands Carnival Committee Inc. is sponsoring the St Thomas Carnival Watersport Activities, a series of high-speed boat races and jet ski races. The races will be held on the waters of Charlotte Amalie Harbor in St Thomas, USVI. Approximately 40 high-speed power
The special local regulation encompasses certain waters of Charlotte Amalie in St Thomas, USVI. The special local regulation will be enforced from 10 a.m. until 5 p.m. on April 21, 2013. The special local regulation consists of the following four areas: (1) A high-speed boat race area, where all persons and vessels, except those persons and vessels participating in the high-speed boat races, are prohibited from entering, transiting through, anchoring in, or remaining within; (2) a jet ski race area, where all persons and vessels, except those persons and vessels participating in the jet ski races, are prohibited from entering, transiting through, anchoring in, or remaining within; (3) a buffer zone around the race areas, where all persons and vessels, except those persons and vessels enforcing the buffer zone or authorized participants transiting to their respective race areas, are prohibited from entering, transiting through, anchoring in, or remaining within; and (4) a spectator area, where all vessels are prohibited from anchoring and from traveling in excess of wake speed unless authorized by the Captain of the Port San Juan or a designated representative. Persons and vessels may request authorization to enter, transit through, anchor in, or remain within the race area, or buffer zone; or to anchor or travel in excess of wake speed in the spectator area by contacting the Captain of the Port San Juan by telephone at (787) 289–2041, or a designated representative via VHF radio on channel 16. If authorization to enter, transit through, anchor in, or remain within the race area, or buffer zone; or to anchor or travel in excess of wake speed in the spectator area is granted by the Captain of the Port San Juan or a designated representative, all persons and vessels receiving such authorization must comply with the instructions of the Captain of the Port San Juan or a designated representative. The Coast Guard will provide notice of the special local regulations by Local Notice to Mariners, Broadcast Notice to Mariners, and on-scene designated representatives.
We developed this proposed rule after considering numerous statutes and executive orders related to rulemaking. Below we summarize our analyses based on a number of these statutes or executive orders.
This proposed rule is not a significant regulatory action under section 3(f) of Executive Order 12866, Regulatory Planning and Review, as supplemented by Executive Order 13563, Improving Regulation and Regulatory Review, and does not require an assessment of potential costs and benefits under section 6(a)(3) of Executive Order 12866 or under section 1 of Executive Order 13563. The Office of Management and Budget has not reviewed it under those Orders. The economic impact of this rule is not significant for the following reasons: (1) The special local regulations will be enforced for only seven hours; (2) although persons and vessels will not be able to enter, transit through, anchor in, or remain within the race area and buffer zone, or anchor in the spectator area, without authorization from the Captain of the Port San Juan or a designated representative, they may operate in the surrounding area during the enforcement period; (3) persons and vessels may still enter, transit through, anchor in, or remain within the race area and buffer zone, or anchor in the spectator area, during the enforcement period if authorized by the Captain of the Port San Juan or a designated representative; and (4) the Coast Guard will provide advance notification of the special local regulations to the local maritime community by Local Notice to Mariners and Broadcast Notice to Mariners.
Under the Regulatory Flexibility Act (5 U.S.C. 601–612), we have considered the impact of this proposed rule on small entities. The Coast Guard certifies under 5 U.S.C. 605(b) that this proposed rule will not have a significant economic impact on a substantial number of small entities.
This rule may affect the following entities, some of which may be small entities: the owners or operators of vessels intending to enter, transit through, anchor in, or remain within that portion of Charlotte Amalie harbor encompassed within the special local regulation from 10 a.m. until 5 p.m. on April 21, 2013. For the reasons discussed in the Regulatory Planning and Review section above, this rule will not have a significant economic impact on a substantial number of small entities.
If you think that your business, organization, or governmental jurisdiction qualifies as a small entity and that this rule would have a significant economic impact on it, please submit a comment (see
Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Pub. L. 104–121), we want to assist small entities in understanding this proposed rule. If the rule would affect your small business, organization, or governmental jurisdiction and you have questions concerning its provisions or options for compliance, please contact the person listed in the
This proposed rule will not call for a new collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501–3520.).
A rule has implications for federalism under Executive Order 13132, Federalism, if it has 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. We have analyzed this proposed rule under that Order and determined that this rule does not have implications for federalism.
The Coast Guard respects the First Amendment rights of protesters. Protesters are asked to contact the person listed in the
The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531–1538) requires Federal agencies to assess the effects of their discretionary regulatory actions. In particular, the Act addresses actions that may result in the expenditure by a State, local, or tribal government, in the aggregate, or by the private sector of $100,000,000 (adjusted for inflation) or more in any one year. Though this proposed rule would not result in such an expenditure, we do discuss the effects of this rule elsewhere in this preamble.
This proposed rule would not cause a taking of private property or otherwise have taking implications under Executive Order 12630, Governmental Actions and Interference with Constitutionally Protected Property Rights.
This proposed rule meets applicable standards in sections 3(a) and 3(b)(2) of Executive Order 12988, Civil Justice Reform, to minimize litigation, eliminate ambiguity, and reduce burden.
We have analyzed this proposed rule under Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks. This rule is not an economically significant rule and would not create an environmental risk to health or risk to safety that might disproportionately affect children.
This proposed rule does not have tribal implications under Executive Order 13175, Consultation and Coordination with Indian Tribal Governments, because it would not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes.
This proposed rule is not a “significant energy action” under Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use.
This proposed rule does not use technical standards. Therefore, we did not consider the use of voluntary consensus standards.
We have analyzed this proposed rule under Department of Homeland Security Management Directive 023–01 and Commandant Instruction M16475.lD, which guide the Coast Guard in complying with the National Environmental Policy Act of 1969 (NEPA) (42 U.S.C. 4321–4370f), and have made a preliminary determination that this action is one of a category of actions that do not individually or cumulatively have a significant effect on the human environment. This proposed rule involves a special local regulation issued in conjunction with a regatta or marine parade. This rule is categorically excluded from further review under paragraph 34(h) of Figure 2–1 of the Commandant Instruction. A preliminary environmental analysis checklist supporting this determination and a Categorical Exclusion Determination are available in the docket where indicated under
Marine safety, Navigation (water), Reporting and recordkeeping requirements, Waterways.
For the reasons discussed in the preamble, the Coast Guard proposes to amend part 100 as follows:
33 U.S.C. 1233.
(a)
(1)
(2)
(3)
(4)
(b)
(c)
(1) All persons and vessels are prohibited from:
(A) Entering, transiting through, anchoring in, or remaining within the power boat race area, unless participating in the power boat race.
(B) Entering, transiting through, anchoring in, or remaining within the
(C) Transiting through, anchoring in, or remaining within the buffer zone, unless enforcing the buffer zone or a race participant transiting to their designated race area.
(D) All persons and vessels are prohibited from anchoring in, or traveling in excess of wake speed in the spectator zone.
(2) Persons and vessels may request authorization to enter, transit through, anchor in, or remain within the race areas by contacting the Captain of the Port San Juan by telephone at (787) 289–2041, or a designated representative via VHF radio on channel 16. If authorization is granted by the Captain of the Port San Juan or a designated representative, all persons and vessels receiving such authorization must comply with the instructions of the Captain of the Port San Juan or a designated representative.
(3) The Coast Guard will provide notice of the regulated areas by Local Notice to Mariners, Broadcast Notice to Mariners, and on-scene designated representatives.
(d)
Environmental Protection Agency (EPA).
Proposed rule.
EPA is proposing to approve a revision to the State Implementation Plan (SIP) and Operating Permits Program to amend the definitions provisions of the rules. This SIP revision and revision to the Missouri operating permits program proposes to add the compounds propylene carbonate and dimethyl carbonate to the list of compounds which are excluded from the definition of Volatile Organic Compound (VOC) for consistency with the Federal definition of VOC. The SIP revision also proposes to correct two asbestos method subpart references. This revision also proposes approval of Missouri's request to amend the SIP to meet the 2008 fine particulate matter (PM
Comments on this proposed action must be received in writing by May 2, 2013.
Submit your comments, identified by Docket ID No. EPA–R07–OAR–2012–0749, by mail to: Craig Bernstein, Environmental Protection Agency, Air Planning and Development Branch, 11201 Renner Boulevard, Lenexa, Kansas 66219. Comments may also be submitted electronically or through hand delivery/courier by following the detailed instructions in the
Craig Bernstein at (913) 551–7688, or by email at
In the final rules section of the
Agricultural Marketing Service, USDA.
Notice of availability of draft guidance with request for comments.
This notice announces draft guidance for review and comment by accredited certifying agents, certified operations, material evaluation programs, and other organic industry stakeholders. The first set of draft guidance documents implements recommendations from the National Organic Standards Board (NOSB) concerning the classification of materials under the USDA organic regulations (7 CFR part 205). The Classification of Materials draft guidance, NOP 5033, details the procedures and decision trees for classifying materials used for organic crop production, livestock production, and handling. The second set of draft guidance documents, NOP 5034, provides clarification regarding materials for use in organic crop production. These documents include an itemization of allowed natural and synthetic materials and a limited appendix of materials prohibited in organic crop production.
The guidance explains the policy of the National Organic Program (NOP) concerning the portions of the regulations in question, referenced herein. The Agricultural Marketing Service (AMS) invites organic producers, handlers, certifying agents, material evaluation programs, consumers and other interested parties to submit comments about these guidance provisions. Notices of availability of final guidance on these topics will be issued upon final approval. Once finalized, final guidance documents will be available from NOP through “The Program Handbook: Guidance and Instructions for Certifying Agents 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
Comments must be submitted on or before June 3, 2013.
Submit written requests for hard copies of this draft guidance document to Toni Strother, Agricultural Marketing Specialist, National Organic Program, USDA–AMS–NOP, 1400 Independence Ave., SW., Room 2646 So., Ag Stop 0268, Washington, DC 20250–0268. See the
Interested persons may submit comments on these draft guidance documents using the following procedures:
•
•
Written comments responding to this request should be identified with the document number AMS–NOP–12–0060; NOP–12–14. Clearly indicate the draft guidance and, if applicable, the material(s) you are addressing, your support for or opposition to it, and the reason for your position. Please include only relevant information and data to support your position. AMS is specifically requesting comments on the status of some materials as described in the
USDA intends to make available all comments, including names and addresses when provided, regardless of submission procedure used, on
Melissa Bailey, Ph.D., Director, Standards Division, National Organic Program, USDA–AMS–NOP, 1400 Independence Ave. SW., Room 2646-So., Ag Stop 0268, Washington, DC 20250. Telephone: (202) 720–3252; Fax: (202) 205–7808.
The draft guidance documents announced through this notice were developed in response to outstanding NOSB recommendations. These documents also address the identified need to develop guidance to address requests by certifying agents and certified operations for clarification on the classification of materials and for more definitive information on materials used in organic crop production.
Under the Organic Foods Production Act (OFPA) (7 U.S.C. 6501–6522), the National List of Allowed and Prohibited Substance section of the USDA organic regulations must include synthetic substances which are permitted for use in organic crop production, and nonsynthetic (natural) substances which are prohibited for use in organic crop production.
Within the guidance, NOP has used the synonymous term “material” in place of the term “substance,” as the term “material” is more commonly used within the organic community.
Nonsynthetic (natural) materials are generally permitted to be used in organic production, but are not required to be included in the National List. At times, this unique construction of the National List has been a source of confusion or inconsistency in determining which input materials are allowed for organic production, since permitted nonsynthetic materials (
The draft guidance document NOP 5033, Classification of Materials, provides additional guidance to the industry on how materials are classified as nonsynthetic, synthetic, agricultural, or nonagricultural. The terms “nonsynthetic,” “synthetic,” “agricultural,” and “nonagricultural” are defined at 7 CFR 205.2 of the USDA organic regulations. This guidance implements a series of recommendations of the NOSB and provides clarification on how materials should be classified according to these defined terms. Draft guidance NOP 5033–1 includes a decision tree for classifying a material as synthetic or nonsynthetic. Draft guidance NOP 5033–2 includes a decision tree for classifying a material as agricultural or nonagricultural. For materials used in organic crop production, the classification guidance is intended to be used in conjunction with the draft guidance NOP 5034, Materials for Organic Crop Production, to assist in determining whether a material is permitted for use.
The draft guidance document NOP 5034, Materials for Organic Crop Production, provides guidance to the industry on materials used in organic crop production. Once finalized, NOP 5034–1 is intended to provide a tool for organic producers to understand which input materials are allowed in organic crop production. The guidance includes substances which are specifically allowed in section 205.601 of the USDA organic regulations, as well as materials which are permitted, but are not required to be included on the National List. The appendix NOP 5034–2 provides a list of materials that are specifically prohibited in organic crop production. The appendix of prohibited materials is not intended to be all inclusive, but is provided for guidance to the industry of items which have been previously reviewed by the NOSB and not recommended for use. The appendix of prohibited materials also includes materials which are specifically listed in section 205.602 the National List as prohibited for use in organic crop production (
NOP is aware that there may have been some inconsistency in the classification of a small number of materials used in organic crop production. NOP is issuing this draft guidance in an effort to clarify the status of these materials. Comments are specifically requested on the classification and descriptions provided in NOP 5034–1 for the following materials: bagasse, biochar, corn steep liquor, fatty acids, glycerin, molasses, vegetable protein hydrolysate, vinasse, and xanthan gum. NOP is requesting comments on whether these materials are accurately classified according to the draft guidance on classification, NOP 5033–1, and whether any amendments are needed to the descriptions provided in NOP 5034–1, Materials for Organic Crop Production.
This draft 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. The draft guidance, when finalized, will represent the NOP's current thinking on these topics. 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. The NOP strongly encourages industry to discuss alternative approaches with the 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.
7 U.S.C. 6501–6522.
The Sensors and Instrumentation Technical Advisory Committee (SITAC) will meet on April 23, 2013, 9:30 a.m., in the Herbert C. Hoover Building, Room 6087B, 14th Street between Constitution and Pennsylvania Avenues, NW., Washington, DC The Committee advises the Office of the Assistant Secretary for Export Administration on technical questions that affect the level of export controls applicable to sensors and instrumentation equipment and technology.
The open session will be accessible via teleconference to 20 participants on a first come, first serve basis. To join the conference, submit inquiries to Ms. Yvette Springer at
A limited number of seats will be available during the public session of the meeting. Reservations are not accepted. To the extent that time permits, members of the public may present oral statements to the Committee. The public may submit written statements at any time before or after the meeting. However, to facilitate distribution of public presentation materials to the Committee members, the Committee suggests that the materials be forwarded before the meeting to Ms. Springer.
The Assistant Secretary for Administration, with the concurrence of the General Counsel, formally determined on December 11, 2012 pursuant to Section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. app. 2 § 10(d), that the portion of this meeting dealing with pre-decisional changes to the Commerce Control List and U.S. export control policies shall be exempt from the provisions relating to public meetings found in 5 U.S.C. app.
For more information contact Yvette Springer on (202) 482–2813.
Import Administration, International Trade Administration, Department of Commerce.
The Department of Commerce (the Department) has received requests to conduct administrative reviews of the antidumping duty orders on certain frozen warmwater shrimp (shrimp) from India and Thailand. The anniversary month of these orders is February. In accordance with the Department's regulations, we are initiating these administrative reviews.
David Crespo at (202) 482–3693 (India) and Blaine Wiltse (202) 482–6345 (Thailand), AD/CVD Operations, Office 2, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230.
During the anniversary month of February 2013, the Department received timely requests, in accordance with 19 CFR 351.213(b), for administrative reviews of the antidumping duty orders on shrimp from India and Thailand from the Ad Hoc Shrimp Trade Action Committee (hereinafter, petitioner), the American Shrimp Processors Association (ASPA), and certain individual companies.
All deadlines for the submission of various types of information, certifications, or comments or actions by the Department discussed below refer to the number of calendar days from the applicable starting time.
If a producer or exporter named in this notice of initiation had no exports, sales, or entries during the period of review (POR), it must notify the Department within 60 days of publication of this notice in the
In the event the Department limits the number of respondents for individual examination for administrative reviews, the Department intends to select respondents based on U.S. Customs and Border Protection (CBP) data for U.S. imports during the POR. We intend to release the CBP data under Administrative Protective Order (APO) to all parties having an APO within seven days of publication of this initiation notice and to make our decision regarding respondent selection within 21 days of publication of this
In the event the Department decides it is necessary to limit individual examination of respondents and conduct respondent selection under section 777A(c)(2) of the Act:
In general, the Department has found that determinations concerning whether particular companies should be “collapsed” (
Pursuant to 19 CFR 351.213(d)(1), a party that has requested a review may withdraw that request within 90 days of the date of publication of the notice of initiation of the requested review. The regulation provides that the Department may extend this time if it is reasonable to do so. In order to provide parties additional certainty with respect to when the Department will exercise its discretion to extend this 90-day deadline, interested parties are advised that the Department does not intend to extend the 90-day deadline unless the requestor demonstrates that an extraordinary circumstance has prevented it from submitting a timely withdrawal request. Determinations by the Department to extend the 90-day deadline will be made on a case-by-case basis.
In accordance with 19 CFR 351.221(c)(1)(i), we are initiating administrative reviews of the antidumping duty orders on shrimp from India and Thailand. We intend to issue the final results of these reviews not later than February 28, 2014.
Interested parties must submit applications for disclosure under administrative protective orders in accordance with 19 CFR 351.305. On January 22, 2008, the Department published
Any party submitting factual information in an antidumping duty proceeding must certify to the accuracy and completeness of that information.
These initiations and this notice are in accordance with section 751(a) of the Act (19 U.S.C. 1675(a)) and 19 CFR 351.221(c)(1)(i).
Import Administration, International Trade Administration, Department of Commerce.
Brenda E. Waters, Office of AD/CVD Operations, Customs Unit, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230, telephone: (202) 482–4735.
Each year during the anniversary month of the publication of an antidumping or countervailing duty order, finding, or suspended investigation, an interested party, as defined in section 771(9) of the Tariff Act of 1930, as amended (“the Act”), may request, in accordance with 19 CFR 351.213, that the Department of Commerce (“the Department”) conduct an administrative review of that antidumping or countervailing duty order, finding, or suspended investigation.
All deadlines for the submission of comments or actions by the Department discussed below refer to the number of calendar days from the applicable starting date.
In the event the Department limits the number of respondents for individual examination for administrative reviews initiated pursuant to requests made for the orders identified below, the Department intends to select respondents based on U.S. Customs and Border Protection (“CBP”) data for U.S. imports during the period of review. We intend to release the CBP data under Administrative Protective Order (“APO”) to all parties having an APO within five days of publication of the initiation notice and to make our decision regarding respondent selection within 21 days of publication of the initiation
In the event the Department decides it is necessary to limit individual examination of respondents and conduct respondent selection under section 777A(c)(2) of the Act:
In general, the Department has found that determinations concerning whether particular companies should be “collapsed” (
Pursuant to 19 CFR 351.213(d)(1), a party that has requested a review may withdraw that request within 90 days of the date of publication of the notice of initiation of the requested review. The regulation provides that the Department may extend this time if it is reasonable to do so. In order to provide parties additional certainty with respect to when the Department will exercise its discretion to extend this 90-day deadline, interested parties are advised that, with regard to reviews requested on the basis of anniversary months on or after April 2013, the Department does not intend to extend the 90-day deadline unless the requestor demonstrates that an extraordinary circumstance has prevented it from submitting a timely withdrawal request. Determinations by the Department to extend the 90-day deadline will be made on a case-by-case basis.
The Department is providing this notice on its Web site, as well as in its “Opportunity to Request Administrative Review” notices, so that interested parties will be aware of the manner in which the Department intends to exercise its discretion in the future.
Opportunity to Request a Review: Not later than the last day of April 2013,
In accordance with 19 CFR 351.213(b), an interested party as defined by section 771(9) of the Act may request in writing that the Secretary conduct an administrative review. For both antidumping and countervailing duty reviews, the interested party must specify the individual producers or exporters covered by an antidumping finding or an antidumping or countervailing duty order or suspension agreement for which it is requesting a review. In addition, a domestic interested party or an interested party described in section 771(9)(B) of the Act must state why it desires the Secretary to review those particular producers or exporters.
Please note that, for any party the Department was unable to locate in prior segments, the Department will not accept a request for an administrative review of that party absent new information as to the party's location. Moreover, if the interested party who files a request for review is unable to locate the producer or exporter for which it requested the review, the interested party must provide an explanation of the attempts it made to locate the producer or exporter at the same time it files its request for review, in order for the Secretary to determine if the interested party's attempts were reasonable, pursuant to 19 CFR 351.303(f)(3)(ii).
As explained in
All requests must be filed electronically in Import Administration's Antidumping and Countervailing Duty Centralized Electronic Service System (“IA ACCESS”) on the IA ACCESS Web site at
The Department will publish in the
For the first administrative review of any order, there will be no assessment of antidumping or countervailing duties on entries of subject merchandise entered, or withdrawn from warehouse, for consumption during the relevant provisional-measures “gap” period, of the order, if such a gap period is applicable to the period of review.
This notice is not required by statute but is published as a service to the international trading community.
Import Administration, International Trade Administration, Department of Commerce.
In accordance with section 751(c) of the Tariff Act of 1930, as amended (“the Act”), the Department of Commerce (“the Department”) is automatically initiating five-year reviews (“Sunset Reviews”) of the antidumping duty orders listed below. The International Trade Commission (“the Commission”) is publishing concurrently with this notice its notice of
The Department official identified in the
The Department's procedures for the conduct of Sunset Reviews are set forth in its
In accordance with 19 CFR 351.218(c), we are initiating Sunset Reviews of the following antidumping duty orders:
As a courtesy, we are making information related to Sunset proceedings, including copies of the pertinent statute and Department's regulations, the Department's schedule for Sunset Reviews, a listing of past revocations and continuations, and current service lists, available to the public on the Department's Internet Web site at the following address: “
This notice serves as a reminder that any party submitting factual information in an AD/CVD proceeding must certify to the accuracy and completeness of that information.
Pursuant to 19 CFR 351.103(d), the Department will maintain and make available a service list for these proceedings. To facilitate the timely preparation of the service list(s), it is requested that those seeking recognition as interested parties to a proceeding contact the Department in writing within 10 days of the publication of the Notice of Initiation.
Because deadlines in Sunset Reviews can be very short, we urge interested parties to apply for access to proprietary information under administrative protective order (“APO”) immediately following publication in the
Domestic interested parties defined in section 771(9)(C), (D), (E), (F), and (G) of the Act and 19 CFR 351.102(b) wishing to participate in a Sunset Review must respond not later than 15 days after the date of publication in the
If we receive an order-specific notice of intent to participate from a domestic interested party, the Department's regulations provide that
This notice of initiation is being published in accordance with section 751(c) of the Act and 19 CFR 351.218 (c).
National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice.
The Department of Commerce, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995.
Written comments must be submitted on or before June 3, 2013.
Direct all written comments to Jennifer Jessup, Departmental Paperwork Clearance Officer, Department of Commerce, Room 6616, 14th and Constitution Avenue NW., Washington, DC 20230 (or via the Internet at
Requests for additional information or copies of the information collection instrument and instructions should be directed to David Ulmer, (757) 723–0303 or
This request is for extension of a current information collection.
Federally permitted dealers, and any individual acting in the capacity of a dealer, must submit to NOAA's National Marine Fisheries Service (NMFS) Regional Administrator or to the official designee a detailed report of all fish purchased or received for a commercial purpose, other than solely for transport on land by one of the available electronic reporting mechanisms approved by NMFS. The information obtained is used by economists, biologists, and managers in the management of the fisheries. The data collection parameters are consistent with the current requirements for Federal dealers under the authority of the Magnuson-Stevens Fishery Conservation and Management Act.
Dealers submit purchase information through an electronic process by either the Web-based system as administered by the Atlantic Coast Cooperative Statistics Program, the computer-based
Comments are invited on: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden (including hours and cost) of the proposed collection of information; (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 respondents, including through the use of automated collection techniques or other forms of information technology.
Comments submitted in response to this notice will be summarized and/or included in the request for OMB approval of this information collection; they also will become a matter of public record.
National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice.
The Department of Commerce, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995.
Written comments must be submitted on or before June 3, 2013.
Direct all written comments to Jennifer Jessup, Departmental Paperwork Clearance Officer, Department of Commerce, Room 6616, 14th and Constitution Avenue NW., Washington, DC 20230 (or via the Internet at
Requests for additional information or copies of the information collection instrument and instructions should be directed to Craig D'Angelo, (562) 980–4024 or
This request is for revision and extension of a current information collection. Under the Magnuson-Stevens Fishery Conservation and Management Act, 16 U.S.C. 1801 et
The permit application forms provide basic information about permit holders and the vessels and gear being used. This information is important for understanding the nature of the fisheries and provides a link to participants. It also aids in enforcement of regulations. Minor modifications of the current HMS permit application will occur to simplify application questions.
Forms are available on the internet; paper applications are also available and may be submitted by mail or FAX. In addition, an online submission option is expected to be available for Highly Migratory Species permits by April 30, 2013.
Comments are invited on: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden (including hours and cost) of the proposed collection of information; (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 respondents, including through the use of automated collection techniques or other forms of information technology.
Comments submitted in response to this notice will be summarized and/or included in the request for OMB approval of this information collection; they also will become a matter of public record.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of receipt of an application for an exempted fishing permit; request for comments.
NMFS announces the receipt of an application for an exempted fishing permit (EFP) from the Gulf Headboat Cooperative (Cooperative). The Cooperative proposes to evaluate the efficacy of an allocation-based management system, using a limited number of headboats in a 2-year pilot study. This study, to be conducted in the exclusive economic zone (EEZ) of the Gulf of Mexico (Gulf), is intended to assess whether such a system can better achieve conservation goals established in the Fishery Management Plan for the Reef Fish Resources of the Gulf of Mexico; evaluate the effectiveness of a more timely electronic data reporting system; and evaluate the potential social and economic benefits of an alternative management strategy for the headboat segment of the recreational fishing sector within the Gulf reef fish fishery.
Comments must be received no later than 5 p.m., eastern time, on May 2, 2013.
You may submit comments on the application, identified by RIN 0648–XC528, by any of the following methods:
•
•
The application and related documents are available for review upon written request to any of the above addresses.
Steve Branstetter, 727–824–5305; email:
The EFP is requested under the authority of the Magnuson-Stevens Fishery Conservation and Management Act (16 U.S.C. 1801
The described research program is being proposed by a sub-set of the headboat fleet in the Gulf reef fish fishery. A headboat is a for-hire vessel that charges a fee on an individual angler (per head) basis. These headboats have formed a Cooperative to conduct a pilot study to evaluate the efficacy of an allocation-based management strategy, which if proven successful, could potentially be implemented by the Gulf of Mexico Fishery Management Council (Council) for the entire reef fish headboat fleet in the Gulf.
Currently, headboats operate under a common set of management measures, such as recreational bag limits, size limits, and open fishing seasons. According to the Cooperative, regulatory responses to overharvesting of reef fish in the recreational sector and the need for more timely harvest data have resulted in shorter fishing seasons, reduced bag limits, and other factors that make it difficult to operate successful headboat businesses. Because headboat operators can now only fish for certain species during brief seasons in each year, there are increased regulatory discards during the closed seasons, and boats often lose out on potential customers during periods of high tourist traffic along the Gulf coast that do not coincide with those open fishing seasons. In addition, even long-time customers are losing confidence that if they book a headboat trip in advance, the fishing seasons for their target reef fish species will be open when their fishing trip occurs. This lack of certainty makes customers reluctant to book headboat fishing trips.
The Cooperative is requesting that they be issued an EFP authorizing their members to harvest a specific amount of red snapper and gag anytime during the 2014 and 2015 fishing years. The amount of fish that would be authorized for harvest by the Cooperative would be based on the Cooperative participants' 2011 aggregate landings of red snapper and gag reported through the Southeast Regional Headboat Survey (SRHS) program relative to the total recreational landings of red snapper and gag in 2011. That percentage would then be applied to the 2014 and 2015 red snapper recreational quota and gag recreational allocation to determine the amount of fish authorized under the EFP to be harvested by the Cooperative.
The Cooperative would be responsible for distributing the allotted fish to individual headboats in the program. Final distribution would be in numbers of fish, calculated from the proportional landings data, which are reported in weight. The Cooperative would then be responsible for reporting their landings electronically to the NMFS Southeast Regional Office.
NMFS would establish an electronic account for the Cooperative manager before the start of the 2014 fishing season. Vessel accounts would also be established by NMFS for each vessel participating in the EFP. NMFS would provide the Cooperative Manager and participating Gulf charter-headboat for reef fish permit holders each with a unique UserID and Personal Identification Number (PIN) to log-in to their accounts. The amount of fish authorized for harvest under the EFP would be deposited in the Cooperative manager's electronic account on January 1, each year. The Cooperative manager would then transfer fish to and from headboat vessel accounts. The number of fish each vessel receives would be determined by the Cooperative and not NMFS. Vessel account holders would be able to view the number of fish available for harvest at any point in time through their account. Landed fish would be deducted from the vessel account after each recorded trip. After all fish have been harvested, the vessel would either need to obtain additional fish from the Cooperative manager to continue landing fish or no longer harvest red snapper and gag for the remainder of the fishing year.
The Cooperative has proposed to provide a transparent real-time monitoring system. All vessels in the program would be required to purchase, install, activate, and maintain a Vessel Monitoring System (VMS) unit in accordance with NMFS Office of Law Enforcement procedures. A participating captain would “hail out” using the VMS device or by telephone as the vessel leaves the dock, notifying NMFS of the fishing trip. In return, the captain would receive a confirmation number for that particular trip. When returning to port, the vessel would be required to “hail in” using the VMS or by telephone at least 1 hour prior to landing, alerting law enforcement and port agents to his/her return. This would provide sufficient notice to allow a dockside intercept if deemed necessary by enforcement and headboat port samplers.
Landings would be reported at the end of the trip using a software application (iSnapper) developed by Texas A&M University's Harte Research Institute. The software application was pilot-tested by the for-hire fleet in the Gulf during 2011 and 2012. Before returning to the dock, the headboat captain would enter the species and number of fish retained during the trip, approximate GPS location to identify fishing zones, and social and economic information regarding the customers on each trip. At the end of the trip, the captain would use the iSnapper data to print out a receipt for each individual customer, which would include summary information such as species and number of fish landed, the date of the trip, and the name of the vessel. This receipt would be used at the dock to track the fish that had been landed on the Cooperative vessel participating in the EFP.
By using this electronic reporting methodology, the Cooperative would maintain a real-time, internet-based tracking system to ensure accounting of each fish landed. The data would be collected on remote servers and sent to NMFS. The Cooperative would maintain an electronic account with NMFS, specifying the numbers of red snapper and gag grouper that could be landed. As fish are landed, they would be deducted from the headboat's vessel account. Finally, headboat captains would continue submitting completed NMFS SRHS logbook data for each trip in compliance with 50 CFR 622.5.
The pilot project, if approved, offers an opportunity to evaluate the impacts of an alternative management system on the economic performance of the Gulf reef fish headboat industry. It also provides a valuable opportunity to customize data collection to maximize usefulness of the data for answering important management questions. Academic researchers, in collaboration with the Cooperative, would conduct a socio-economic study of the anticipated effects of the change in headboat cooperative management using currently available data sources. Simultaneously, the academic researchers and the Cooperative would develop additional survey instruments to gather economic data for a post-EFP analysis of the effects of the pilot project on Cooperative vessels after its first and second years. Data collection would emphasize post-EFP impacts of the pilot project. A partial list of impacts to assess in the study includes:
1. How has the pilot project changed the temporal and spatial distributions of fishing by Cooperative members?
2. How has the number of anglers/customers changed as a result of Cooperative members being able to better target their trips to the seasonality of demand specific to red snapper and gag?
3. Do headboat owners utilize increased flexibility to provide a more differentiated recreational product to customers?
4. How has the pilot project affected the cost and net revenue associated with a representative trip?
Data collection would include trip-level catch and effort characteristics (e.g., retained and discarded catch, spatial location, and number of customers), trip and season-level variable revenues and costs (e.g., trip pricing, gear, bait, ice, fuel, and maintenance expenditures), and labor employment and compensation information. Many trip-level data would be collected using the iSnapper application, whereas seasonal data would be collected through supplementary survey instruments.
The public and the Council questioned if the establishment of an allocation-based system for the Cooperative could be considered the establishment of an individual fishing quota (IFQ) program, which would require approval via a referendum. Section 303A(c)(6)(D), 16 U.S.C. 1853a(c)(6)(D), of the Magnuson-Stevens Act, requires a referendum to approve or implement a fishery management plan or plan amendment that creates an IFQ program for any species in the Gulf. Although the allocation-based system requested by the Cooperative might reasonably be considered to create such an IFQ program, the mere issuance of an EFP to test the program on a limited basis does not trigger the referendum requirement. The statutory language is explicit that the referendum is only required to approve a fishery management plan or plan amendment that would implement such a program. An EFP is neither a fishery management plan nor a plan amendment, and does not implement any new requirements for all or a portion of recreational participants. If issued, the EFP would only establish specific requirements for the members of the voluntary Cooperative who have requested the EFP. Therefore, NMFS has determined that no referendum is required.
Currently, the recreational red snapper fishing season begins on June 1 of each year, and is closed when NMFS projects the recreational quota will be landed. As noted above, the recreational seasons have become shorter each year, impacting the ability of headboats to operate in an efficient and economically viable manner. If this EFP is authorized, identified Gulf reef fish headboats in the Cooperative would be able to use their allocation to fish during the open recreational season, but also would be able to select days outside the designated season where they could use their red snapper allocation to meet specific customer demands. Nevertheless, in accordance with section 407(d)(1) (16 U.S.C. 1883(d)) of the Magnuson-Stevens Act, when NMFS determines the recreational red snapper fishing quota is reached, NMFS is required to prohibit the retention of red snapper caught during the rest of the fishing year. Should NMFS determine that the recreational red snapper quota is reached prior to the end of the 2014 or 2015 fishing year, including consideration of fish already harvested by the Cooperative, headboats participating under the EFP would have to cease retaining red snapper, even if the Cooperative still has allocation of red snapper available.
The Council reviewed the Cooperative's initial application at its April 2012 meeting, and recommended that NMFS approve the application. NMFS finds this application does warrant further consideration. Possible conditions the agency may impose on this permit, if it is indeed granted, include but are not limited to, a prohibition of conducting research within marine protected areas, marine sanctuaries, or special management zones, without additional authorization. A report on the research would be due at the end of the collection period, to be submitted to NMFS and reviewed by the Council.
A final decision on issuance of the EFP will depend on NMFS's review of public comments received on the application, the Council's recommendation, consultations with the affected states, and the U.S. Coast Guard, as well as a determination that it is consistent with all applicable laws.
16 U.S.C. 1801
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of correction of a public meeting.
The New England Fishery Management Council's (Council) Groundfish Oversight Committee will meet to consider actions affecting New England fisheries in the exclusive economic zone (EEZ).
The two-day meeting will be held on Tuesday, April 16, 2013 beginning at 12 p.m. and Wednesday, April 17, 2013 beginning at 8:30 a.m.
The meeting will be held at the Holiday Inn, 31 Hampshire Street, Mansfield, MA 02048; telephone: (508) 339–2200; fax: (508) 339–1040.
Paul J. Howard, Executive Director, New England Fishery Management Council; telephone: (978) 465–0492.
The original notice published in the
16 U.S.C. 1801
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice; proposed incidental harassment authorization; request for comments.
NMFS has received an application from the U.S. Navy's Office of Naval Research (ONR) for an Incidental Harassment Authorization (IHA) to take marine mammals, by harassment, incidental to conducting Acoustic Technology Experiments (ATE) in the western North Pacific Ocean. The Navy's activities are considered military readiness activities pursuant to the Marine Mammal Protection Act (MMPA), as amended by the National Defense Authorization Act for Fiscal Year 2004 (NDAA). Pursuant to the MMPA, NMFS is requesting comments on its proposal to issue an IHA to ONR to incidentally harass, by Level B harassment only, 34 species of marine mammals during the specified activity.
Comments and information must be received no later than May 2, 2013.
Comments on the application should be addressed to P. Michael Payne, Chief, Permits and Conservation Division, Office of Protected Resources, National Marine Fisheries Service, 1315 East-West Highway, Silver Spring, MD 20910. The mailbox address for providing email comments is
All comments received are a part of the public record and will generally be posted to
An electronic copy of the application containing a list of the references used in this document may be obtained by visiting the internet at:
Michelle Magliocca, Office of Protected Resources, NMFS, (301) 427–8401.
Section 101(a)(5)(A) and (D) of the MMPA (16 U.S.C. 1361
An authorization for incidental takings shall be granted if NMFS finds that the taking will have a negligible impact on the species or stock(s), will not have an unmitigable adverse impact on the availability of the species or stock(s) for subsistence uses (where relevant), and if the permissible methods of taking and requirements pertaining to the mitigation, monitoring, and reporting of such takings are set forth. NMFS has defined “negligible impact” in 50 CFR 216.103 as “* * * 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.”
Section 101(a)(5)(D) of the MMPA established an expedited process by which U.S. citizens can apply for a 1-year authorization to incidentally take small numbers of marine mammals by harassment, provided that there is no potential for serious injury or mortality to result from the activity. Section 101(a)(5)(D) establishes a 45-day time limit for NMFS' review of an application followed by a 30-day public notice and comment period on any proposed authorizations for the incidental harassment of marine mammals. Within 45 days of the close of the comment period, NMFS must either issue or deny the authorization.
The NDAA (Pub. L. 108–136) removed the “small numbers” and “specified geographical region” limitations and amended the definition of “harassment” as it applies to a “military readiness activity” to read as follows (section 3(18)(B) of the MMPA): (i) Any act that injures or has the significant potential to injure a marine mammal or marine mammal stock in the wild [Level A Harassment]; or (ii) Any act that disturbs or is likely to disturb a marine mammal or marine mammal stock in the wild by causing disruption of natural behavioral patterns, including, but not limited to, migration, surfacing, nursing, breeding, feeding, or sheltering, to a point where such behavioral patterns are abandoned or significantly altered [Level B Harassment].]
On December 20, 2012, NMFS received an application from ONR for the taking of marine mammals incidental to ATE in the western North Pacific Ocean. ONR provided additional information on March 7, 2013 and NMFS determined that the application was adequate and complete on March 7, 2013.
ONR proposes to conduct ATE in one of nine provinces comprising the western North Pacific Ocean. The proposed activity would occur for no more than 2 weeks during the spring or summer of 2013. Transmissions from four underwater active acoustic sources are likely to result in the take of marine mammals. Take, by Level B harassment only, of individuals of up to 34 species is anticipated to result from the specified activity.
The purpose of ONR's ATE is to collect data and demonstrate underwater acoustic technology in a realistic at-sea environment. The proposed activity fulfills the Navy's need for measured in situ scientific data on underwater acoustic technology from which the performance of the acoustic systems and their conceptual foundation can be assessed. No more than four underwater acoustic sources would be used from a vessel during the experiments and none of the sources would transmit concurrently. The acoustic sources are considered non-impulsive and non-continuous and no explosives would be used. All transmission frequencies would be below 1.5 kilohertz (kHz) and sound pressure levels would be less than 220 decibels (dB) (significantly lower than tactical mid-frequency or low-frequency active sonar) for a total of no more than 69 hours of acoustic transmissions over 6 days. Despite being classified, the detailed characteristics of the active acoustic sources were made known to NMFS staff and factored into our MMPA analysis. An environmental survey of the waters of the proposed action area would also be conducted employing an oceanographic acoustic source. The vessel would be stationary during deployment and transmission of the ATE underwater active acoustic sources, except that of the oceanographic acoustic source. The vessel would move at speeds less than 5 knots when the oceanographic source is transmitting. All equipment deployed during the ATE would be recovered once data collection is complete.
The ATE would take place during the spring or summer of 2013, and would last no longer than 2 weeks. No more than 69 hours of acoustic transmissions would occur over 6 at-sea days. The Navy is unable to define a detailed schedule of events because experimental work, such as the proposed activity, requires a degree of flexibility to respond to weather fluctuations and hardware conditions. However, a nominal outline of a schedule, including the amount of time each source would be expected to be used, and the possibility of temporal overlap in source transmissions has been planned (Table 1). At most, two of the acoustic sources would operate at the same time during specific experiment events. In all cases of concurrent source operations, there is sufficient horizontal and vertical separation between the active acoustic sources so that potential environmental effects associated with the operation of the sources is no more than the sources considered individually.
The ATE would take place in international waters, in one of nine provinces comprising the western North Pacific Ocean. The nine provinces are discrete areas identified with the following geographic titles: Sea of Japan, East China Sea, South China Sea, North Philippine Sea, West Philippine Sea, East of Japan, Offshore Guam, Northwest Pacific Ocean: 25° to 40° north latitude, or Northwest Pacific Ocean: 10° to 25° north latitude. The proposed action area would be between 360,000–800,000 square kilometers (km
This section includes a brief explanation of the sound measurements frequently used in the discussions of acoustic effects in this document. Sound pressure is the sound force per unit area, and is usually measured in micropascals (μPa), where 1 pascal (Pa) is the pressure resulting from a force of one newton exerted over an area of one square meter. Sound pressure level (SPL) is expressed as the ratio of a measured sound pressure and a reference level. The commonly used reference pressure level in underwater acoustics is 1 μPa, and the units for SPLs are dB re: 1 μPa.
SPL is an instantaneous measurement and can be expressed as the peak, the peak-peak (p-p), or the root mean square (rms). RMS, which is the square root of the arithmetic average of the squared instantaneous pressure values, is typically used in discussions of the effects of sounds on vertebrates and all references to SPL in this document refer to the root mean square unless otherwise noted. SPL does not take the duration of a sound into account.
Thirty-four marine mammal species may potentially occur in at least one of the nine provinces comprising the western North Pacific Ocean in which the ATE may occur. Eight of these species are listed as endangered under the U.S. Endangered Species Act of 1973 (ESA; 16 U.S.C. 1531 et seq.) and depleted under the MMPA: blue whale (
The distribution and densities of cetaceans and pinnipeds are highly “patchy.” Patchy distributions are characterized by irregular clusters (patches) of occurrence that can frequently be correlated with that of their prey, which often are associated with productive continental shelves, ocean fronts, upwelling areas,
Density estimates were derived for each marine mammal species potentially occurring in the nine provinces of the western North Pacific in which the ONR ATE may occur during the spring or summer (Tables 4–13). The process for developing density estimates was a multi-step procedure. Direct estimates from line-transect surveys that occurred in or near the experiment area were utilized first (e.g., Buckland
Species-specific information on marine mammals potentially occurring in at least one of the nine provinces of the western North Pacific Ocean is provided in ONR's application (
Acoustic stimuli generated by underwater signals from no more than four acoustic sources have the potential to cause Level B harassment of marine mammals in the proposed action area. The impacts to marine mammals from these sources are expected to be limited to some masking effects and behavioral responses in the areas ensonified by the acoustic sources.
Permanent hearing impairment, in the unlikely event that it occurrs, would constitute injury, but temporary threshold shift (TTS) is considered a type of Level B harassment (Southall
Studies on marine mammal tolerance to sound in the natural environment are relatively rare. Richardson
The term masking refers to the inability of a subject to recognize the occurrence of an acoustic stimulus as a result of the interference of another acoustic stimulus (Clark
Acoustic masking from low-frequency ocean noise is increasingly being considered as a threat, especially to low-frequency hearing specialists such as baleen whales (Clark
Redundancy and context can also facilitate detection of weak signals. These phenomena may help marine mammals detect weak sounds in the presence of natural or manmade noise. Most masking studies in marine mammals present the test signal and the masking noise from the same direction. The sound localization abilities of marine mammals suggest that, if signal and noise come from different directions, masking would not be as severe as the usual types of masking studies might suggest (Richardson
Toothed whales, and probably other marine mammals as well, have additional capabilities besides directional hearing that can facilitate detection of sounds in the presence of background noise. There is evidence that some toothed whales can shift the dominant frequencies of their echolocation signals from a frequency range with a lot of ambient noise toward frequencies with less noise (Au
These adaptations for reduced masking pertain mainly to the very high-frequency echolocation signals of toothed whales. There is less information about the existence of corresponding mechanisms at moderate or low frequencies or in other types of marine mammals. For example, Zaitseva
Behavioral disturbance includes a variety of effects, including subtle to conspicuous changes in behavior, movement, and displacement. Marine mammal reactions to sound, if any, depend on species, state of maturity, experience, current activity, reproductive state, time of day, and many other factors (Richardson
Low-frequency signals of the Acoustic Thermometry of Ocean Climate sound source were not found to affect dive times of humpback whales in Hawaiian waters (Frankel and Clark, 2000). Balaenopterid whales exposed to moderate SURTASS LFA sonar demonstrated no responses or change in foraging behavior that could be attributed to the low-frequency sounds (Croll
Social interactions between mammals can be affected by noise via the disruption of communication signals or by the displacement of individuals. In one study, sperm whales responded to military sonar, apparently from a submarine, by dispersing from social aggregations, moving away from the sound source, remaining relatively silent, and becoming difficult to approach (Watkins
Vocal changes in response to anthropogenic noise can occur across the repertoire of sound production modes used by marine mammals, such as whistling, echolocation click production, calling, and singing. Changes may result in response to a need to compete with an increase in background noise or may reflect an increased vigilance or startle response. For example, in the presence of low-frequency active sonar, humpback whales have been observed to increase the length of their “songs” (Miller
Avoidance is the displacement of an individual from an area as a result of the presence of a sound. Richardson
In 1998, the Navy conducted a Low Frequency Sonar Scientific Research Program (LFS SRP) to investigate avoidance behavior of gray whales to low-frequency sound signals. The objective was to determine whether whales respond more strongly to received levels, sound gradient, or distance from the source, and to compare whale avoidance responses to a low-frequency source in the center of the migration corridor versus in the offshore portion of the migration corridor. A single source was used to broadcast LFA sonar sounds up to 200 dB. The Navy reported that the whales showed some avoidance responses when the source was moored 1.8 km offshore, in the migration path, but
Also during the LFS SRP, researchers sighted numerous odontocete and pinniped species in the vicinity of the sound exposure tests with LFA sonar. The mid-frequency and high-frequency hearing specialists present in the study area showed no immediately obvious responses or changes in sighting rates as a function of source conditions. Consequently, the researchers concluded that none of these species had any obvious behavioral reaction to LFA signals at received levels similar to those that produced only minor but short-term behavioral responses in the baleen whales (Clark and Southall, 2009).
Under some circumstances, marine mammals that are exposed to active sonar transmissions will continue their normal behavioral activities; in other circumstances, individual animals will respond to sonar transmissions at lower received levels and move to avoid additional exposure or exposures at higher received levels (Richardson
Aicken
Exposure to high intensity sound for a sufficient duration may result in auditory effects such as a noise-induced threshold shift—an increase in the auditory threshold after exposure to noise (Finneran, Carder, Schlundt, and Ridgway, 2005). Factors that influence the amount of threshold shift include the amplitude, duration, frequency content, temporal pattern, and energy distribution of noise exposure. The magnitude of hearing threshold shift normally decreases over time following cessation of the noise exposure. The amount of threshold shift just after exposure is called the initial threshold shift. If the threshold shift eventually returns to zero (i.e., the threshold returns to the pre-exposure value), it is called temporary threshold shift (TTS) (Southall
Researchers have derived TTS information for odontocetes from studies on the bottlenose dolphin and beluga. For baleen whales, there are no data, direct or indirect, on levels or properties of sound that are required to induce TTS. The frequencies to which baleen whales are most sensitive are assumed to be lower than those to which odontocetes are most sensitive, and natural background noise levels at those low frequencies tend to be higher. As a result, auditory thresholds of baleen whales within their frequency band of best hearing are believed to be higher (less sensitive) than are those of odontocetes at their best frequencies (Clark and Ellison, 2004). From this, it is suspected that received levels causing TTS onset may also be higher in baleen whales (Southall
Marine mammal hearing plays a critical role in communication with conspecifics and in interpretation of environmental cues for purposes such as predator avoidance and prey capture. Depending on the degree (elevation of threshold in dB), duration (i.e., recovery time), and frequency range of TTS and the context in which it is experienced, TTS can have effects on marine mammals ranging from discountable to serious. For example, a marine mammal may be able to readily compensate for a brief, relatively small amount of TTS in a non-critical frequency range that takes place during a time when the animal is traveling through the open ocean, where ambient noise is lower and there are not as many competing sounds present. Alternatively, a larger amount and longer duration of TTS sustained during a time when communication is critical for successful mother/calf interactions could have more serious impacts if it were in the same frequency band as the necessary vocalizations and of a severity that it impeded communication. The fact that animals exposed to levels and durations of sound that would be expected to result in this physiological response would also be expected to have behavioral responses of a comparatively more severe or sustained nature is also notable and potentially of more importance than the simple existence of a TTS. For this proposed study, TTS is considered unlikely given: (1) The slow speed of the vessel during activities (less than 5 knots); (2) the motility of free-ranging marine mammals in the water column; (3) the propensity for marine mammals to avoid obtrusive sounds; and (4) the relatively low densities of marine mammals in the proposed nine provinces of the western North Pacific Ocean.
Relationships between TTS and PTS thresholds have not been studied in marine mammals, but are assumed to be similar to those in humans and other terrestrial mammals. PTS might occur at a received sound level at least several decibels above that inducing mild TTS if the animal were exposed to strong sound pulses with rapid rise times. Based on data from terrestrial mammals, a precautionary assumption is that the PTS threshold for impulse sounds is at least 6 dB higher than the TTS threshold on a peak-pressure basis, and probably greater than six dB (Southall
Given the higher level of sound necessary to cause PTS as compared with TTS, it is considerably less likely that PTS would occur during the demonstration. ONR's underwater acoustical modeling showed that none of the cumulative energy values exceeded the 215 dB threshold. Therefore, Level A takes of marine mammals are not expected during the ONR ATE.
Specific sound-related processes that lead to strandings and mortality are not well documented, but may include:
• Swimming in avoidance of a sound into shallow water;
• A change in behavior (such as a change in diving behavior) that might contribute to tissue damage, gas bubble formation, hypoxia, cardiac arrhythmia, hypertensive hemorrhage or other forms of trauma;
• A physiological change such as a vestibular response leading to a behavioral change or stress-induced hemorrhagic diathesis; leading in turn to tissue damage; and
• Tissue damage directly from sound exposure, such as through acoustically-mediated bubble formation and growth or acoustic resonance of tissues.
Some of these mechanisms are unlikely to apply in the case of impulse sounds. However, there are increasing indications that gas-bubble disease (analogous to the bends), induced in supersaturated tissue by a behavioral response to acoustic exposure, could be a pathologic mechanism for the strandings and mortality of some deep-diving cetaceans exposed to sonar. The cause or causes of most strandings are unknown (Geraci
Several sources have published lists of mass stranding events of cetaceans in an attempt to identify relationships between those stranding events and military active sonar (Hildebrand, 2004; IWC, 2005; Taylor
Cox
No ESA-designated critical habitats of any marine mammal species are located in or near the waters of the nine western North Pacific Ocean provinces in which the proposed ONR ATE may be conducted. There are also no international marine mammal protected areas located within the vicinity of the experiment area. During the ONR ATE, only acoustic transducers and receivers as well as standard oceanographic equipment would be deployed. Experimental systems are planned to be retrieved after data collection has been completed. The acoustic and oceanographic instrumentation that would be deployed operates in accordance with all applicable international rules and regulations related to environmental compliance, especially for discharge of potentially hazardous materials. Therefore, no discharges of pollutants would result from the deployment and operation of the acoustic and oceanographic instruments and systems.
During the ONR ATE, deployment and operation of the sound sources would result in no physical alterations to the marine environment other than addition of elevated underwater sound levels, which may have some effect on marine mammals. Any increase in underwater sound levels would be temporary (lasting no more than 2 weeks) and limited in geographic scope. A small number of marine mammals present near the proposed activity may be temporarily displaced due to sound source transmissions. However, concentrations of marine mammals and/or marine mammal prey species are not expected to be encountered in or near the vicinity of the waters in the western North Pacific provinces in which the ONR ATE may occur. There are no critical feeding, breeding, or migrating areas for any marine mammal species that may occur in the proposed action area. No long-term impacts associated with the increase in ambient noise levels are expected.
In order to issue an incidental take authorization (ITA) under section 101(a)(5)(D) of the MMPA, NMFS must prescribe, where applicable, the permissible methods of taking pursuant to such activity, and other means of effecting the least practicable impact on such species or stock and its habitat, paying particular attention to rookeries, mating grounds, and areas of similar significance, and the availability of such
The NDAA of 2004 amended the MMPA as it relates to military-readiness activities and the ITA process such that “least practicable adverse impact” shall include consideration of personnel safety, practicality of implementation, and impact on the effectiveness of the “military readiness activity.” The training activities described in ONR's application are considered military readiness activities.
ONR has proposed the following mitigation measures to be implemented during the ONR ATE:
ONR would maneuver the research vessel, as feasible, to avoid closing within 457 m (1,499 ft) of a marine mammal. Standard operating procedures for the research vessel would be to avoid collision with marine mammals, including maintaining a minimum safe maneuvering distance from detected animals.
ONR proposes to use a 1-km mitigation zone to avoid take by Level A harassment and reduce the potential impacts to marine mammals from ONR ATE. Mitigation zones are measured as the radius from a source and represent a distance that visual observers would monitor during daylight hours to ensure that no marine mammals enter the designated area. The mitigation zone would be monitored for 30 minutes before the active acoustic source transmissions begin and would continue until 30 minutes after the active acoustic source transmissions are terminated, or 30 minutes after sunset, whichever comes first. Visual detections of marine mammals would be communicated immediately for information dissemination and appropriate action, as described directly below.
During daytime transmissions, ONR proposes to immediately delay or shut down active acoustic source transmissions if a marine mammal is visually detected within the 1 km exclusion zone. NMFS further proposes that transmissions would not commence/resume for 15 minutes (for small odontocetes and pinnipeds) or 30 minutes (for mysticetes and large odontocetes) after the animal has moved out of the exclusion zone or there has been no further visual detection of the animal. During nighttime transmissions, ONR proposes to immediately delay or shut down active acoustic source transmissions if a marine mammal is detected using passive acoustic monitoring. NMFS further proposes that transmissions would commence/resume 15 minutes (for small odontocetes and pinnipeds) or 30 minutes (for mysticetes and large odontocetes) after there has been no further detection of the animal.
NMFS has carefully evaluated the applicant's proposed mitigation measures and considered a range of other measures in the context of assuring that NMFS prescribes 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, including consideration of personnel safety, practicality of implementation, and impact on the effectiveness of the military readiness activity.
Based on our evaluation of the applicant's proposed measures and those proposed by NMFS, we have preliminarily determined that the proposed mitigation measures provide the means of effecting the least practicable adverse impact on marine mammal species or stocks and their habitat, paying particular attention to rookeries, mating grounds, and areas of similar significance, while also considering personnel safety, practicality of implementation, and impact on the effectiveness of the military readiness activity.
In order to issue an ITA for an activity, section 101(a)(5)(D) of the MMPA states that NMFS must set forth, where applicable, “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 ITAs 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 are expected to be present in the proposed action area.
ONR proposes to conduct marine mammal monitoring during the proposed activity for the purpose of implementing required mitigation and to provide information on species presence and abundance in the action area. ONR proposes that protected species observers (both visual and acoustic) would maintain a log that includes duration of time spent searching/listening for marine mammals; numbers and species of marine mammals detected; any unusual marine mammal behavior; and the date, time, and location of the animal and any sonobuoy deployments. ONR's proposed Monitoring Plan is described below this section.
If a passively detected sound is estimated to be from a marine mammal, the acoustic observer would notify the appropriate personnel and shutdown procedures would be implemented. For any marine mammal detection, the Test
ONR proposes that protected species observers (both visual and acoustic) would maintain a log that includes duration of time spent searching/listening for marine mammals; numbers and species of marine mammals detected; any unusual marine mammal behavior; and the date, time, and location of the animal and any sonobuoy deployments. Data would be used to estimate numbers of animals potentially `taken' by harassment (as defined in the MMPA). NMFS further proposes that protected species observers record the behavioral state of all marine mammals observed and the status of the active acoustic source when observers see an animal.
ONR would submit two reports to NMFS within 90 days after the end of the proposed activity: one unclassified report and one classified report. The reports would describe the operations that were conducted and sightings of marine mammals near the operations. The reports would provide full documentation of methods, results, and interpretation pertaining to all monitoring. The 90-day reports would summarize the dates and locations of active acoustic source transmissions, and all marine mammal sightings (dates, times, locations, activities, associated active acoustic transmissions). The reports would also include estimates of the number and nature of exposures that could result in `takes' of marine mammals.
In the unanticipated event that the specified activity clearly causes the take of a marine mammal in a manner prohibited by the IHA (if issued), such as an injury (Level A harassment), serious injury, or mortality (e.g., ship-strike, gear interaction, and/or entanglement), ONR would immediately cease the specified activities and immediately report the incident to the Chief of the Permits and Conservation Division, Office of Protected Resources, NMFS. The report must include the following information:
• 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 (e.g., wind speed and direction, Beaufort sea state, cloud cover, and visibility);
• Description of all marine mammal observations in the 24 hrs 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).
Activities would not resume until NMFS is able to review the circumstances of the prohibited take. NMFS would work with ONR to determine what is necessary to minimize the likelihood of further prohibited take and ensure MMPA compliance. ONR may not resume their activities until notified by NMFS via letter, email, or telephone.
In the event that ONR discovers an injured or dead marine mammal, and the lead protected species observer determines that the cause of the injury or death is unknown and the death is relatively recent (i.e., in less than a moderate state of decomposition as described in the next paragraph), ONR would immediately report the incident to the Chief of the Permits and Conservation Division, Office of Protected Resources, NMFS. The report must include the same information identified in the paragraph above. Activities may continue while NMFS reviews the circumstances of the incident. NMFS would work with ONR to determine whether modifications in the activities are appropriate.
In the event that ONR discovers an injured or dead marine mammal, and the lead protected species observer determines that the injury or death is not associated with or related to the activities authorized in the IHA (e.g., previously wounded animal, carcass with moderate to advanced decomposition, or scavenger damage), ONR would report the incident to the Chief of the Permits and Conservation Division, Office of Protected Resources, NMFS within 24 hours of the discovery. ONR would provide photographs or video footage (if available) or other documentation of the stranded animal sighting to NMFS.
With respect to military readiness activities, section 3(18)(B) of the MMPA defines “harassment” as: any act that injures or has the significant potential to injure a marine mammal or marine mammal stock in the wild [Level A harassment]; or (ii) any act that disturbs or is likely to disturb a marine mammal or marine mammal stock in the wild by causing disruption of natural behavioral patterns, including, but not limited to, migration, surfacing, nursing, breeding, feeding, or sheltering, to a point where such behavioral patterns are abandoned or significantly altered [Level B harassment].
Only take by Level B harassment is anticipated and proposed for authorization as a result of the proposed activity. Acoustic stimuli (i.e., increased underwater sound) generated during the transmission of active acoustic sources have the potential to cause temporary, short-term changes in marine mammal behavior. There is no evidence that the planned activities would result in injury, serious injury, or mortality within the specified geographic area for which ONR seeks the IHA. The mitigation and monitoring measures proposed for implementation are expected to minimize any potential risk for injury or mortality.
To estimate the potential risk of physical auditory or behavioral effects due to the transmissions from the no more than four acoustic sources deployed in one of the nine provinces of the western North Pacific Ocean during the ONR ATE, the Navy performed underwater acoustical modeling and associated analyses. Historically, acoustic exposure thresholds for marine mammal behavior have been just that, fixed thresholds or step functions. However, step functions do not accurately represent most animal behavior. Accurately representing animal behavior was one of the driving factors in the creation of the behavior risk function (BRF, also known as the risk continuum function), where the probability of significant behavioral response is considered a function of received sound pressure level. This is described in more detail and illustrated in section 6 of the Navy's application. While behavioral response is almost certainly determined by more factors than exposure level, it is also likely that in the limited situation of exposure to acoustic energy when all other contextual factors are known and held constant, received sound level can be used as a proxy for behavioral response.
To estimate the acoustic exposure an animal is likely to receive while the active sources employed in ONR ATE during spring or summer are transmitting, the movement of potentially occurring marine mammals and the acoustic field to which they may be exposed were modeled. The sound fields around the active acoustic
To estimate the risk of harassment from each acoustic source, which includes behavior and TTS effects, potentially resulting from exposure to the active acoustic sources employed in ONR ATE, both the maximum received level and the cumulative energy level (sound exposure level) for each animat from each source were determined. The maximum received level for each animat was inputed into the risk continuum function to estimate Level B harassment. Note that there are two BRFs, one for mysticetes and one for odontocetes and pinnipeds. To determine the potential for TTS and PTS in the marine mammal species potentially occurring in the nine western North Pacific provinces, the modeled sound exposure level values were compared to the appropriate sound exposure level threshold (Table 13). Since TTS is recoverable and is considered to result from the temporary, non-injurious fatigue of hearing-related tissues, it represents the upper bound of the potential for Level B effects. PTS, however, is non-recoverable and, by definition, results from the irreversible impacts on auditory sensory cells, supporting tissues, or neural structures within the auditory system. PTS is thus considered within the potential for Level A effects.
In determining the potential effects of the marine mammal species possibly occurring in the nine provinces during spring or summer in which ONR ATE may occur, the Navy made the following assumptions regarding modeling on the underwater acoustic sources:
• Each of the ONR ATE sources was modeled individually and its potential effects computed independent of other experiment activities;
• Acoustic propagation model BELLHOP was used to model the acoustic environment;
• Spring and summer sound velocity profiles from GDEM 2.5 database, the Navy standard database for sound velocity profiles, were used;
• Bathymetry was derived from the ETOP02 database;
• A surface wind speed of 7.7 m/sec (15 knots) was used in the Bechmann-Spezzichino model to estimate surface loss;
• Seafloor properties, including bottom loss, were derived from the Navy standard CBLUG and MGS databases;
• Animal movement parameters for the species occurring in the proposed test area were extracted from the database created by Marine Acoustics, Inc.;
• Densities for marine mammals in the nine provinces of the western North Pacific Ocean were derived using the best available data;
• Animats that encountered the geographic boundaries of the model area “reflected” back into the model area, maintaining a constant overall animat model density; and
• No mitigation was applied to the analysis results.
The precision with which environmental effects can be calculated is largely determined by the accuracy with which the marine mammal densities are estimated for the selected geographic area and season. While the marine mammal densities used in this analysis represent the best available data in spring and summer for the waters of the nine provinces in which the ONR ATE may be conducted, few dedicated marine mammal surveys for the purpose of deriving densities have been undertaken in these waters and only rarely are data available for estimating seasonal populations.
The Navy's analysis conducted on the ONR ATE activities to assess the potential for effects on marine mammals has shown that the possibility of marine mammals being exposed to Level A harassment is not likely. Any impacts to marine mammals are expected to be limited to some masking effects and behavioral responses (Level B harassment) in the areas temporarily ensonified by the active acoustic sources. For all ESA-listed species, the probability of Level B harassment occurring is low, with the highest potential for fin whales; with an estimated 1.7 fin whales potentially experiencing behavioral reactions or TTS from exposure to the active acoustic sources. For non ESA-listed species, the maximum amount of take by Level B harassment for a single species is estimated to be 87 short-beaked common dolphins. The modeled takes for each of the nine provinces are provided in section 6 of the Navy's LOA application. Below is the maximum amount of take expected for any of the nine provinces in the western North Pacific Ocean.
ONR developed density estimates for every species possibly occurring in the demonstration area through a multi-step procedure. Direct density estimates from line-transect surveys in or near the demonstration area were used first. When survey-based density estimates were not available, then density estimates for individual species were extrapolated from a region with similar oceanographic characteristics to the demonstration area. For example, the eastern tropical Pacific has been extensively surveyed and provides a comprehensive understanding of the marine mammal populations in temperate oceanic waters (Ferguson and Barlow, 2001 and 2003). If sufficient data were not available, even by extrapolation, then density estimates were pooled for species of the same genus (i.e.,
NMFS has defined “negligible impact” in 50 CFR 216.103 as “* * * 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.” In making a negligible impact determination, NMFS considers a variety of factors, including, but not limited to:
As mentioned previously, NMFS estimates that 34 species of marine mammals could be affected by Level B harassment during the ONR ATE. No injuries, serious injuries, or mortalities are anticipated to occur as a result of the demonstration, and none are proposed to be authorized. Additionally, for reasons presented earlier in this document, temporary or permanent hearing impairment is not anticipated to occur during the proposed specified activity. Only short-term behavioral disturbance is anticipated to occur due to the limited duration of active acoustic sonar transmissions and the estimated
NMFS has preliminarily determined, provided that the aforementioned mitigation and monitoring measures are implemented, that the impact of conducting the ONR ATE, may result, at worst, in a temporary modification in behavior and/or low-level physiological effects (Level B harassment) of certain species of marine mammals.
Of the ESA-listed marine mammals that may potentially occur in the proposed survey area, North Pacific right whale populations lack sufficient data on trends in abundance and sperm whale populations are not well known in the southern hemisphere. There is no designated critical habitat for marine mammals in the proposed survey area. There are also no known important habitat areas (e.g., breeding, calving, feeding, etc.) for marine mammals known around the area that would overlap with the proposed demonstration. While behavioral modifications, including temporarily vacating the area during the transmission of active acoustic sonar, may be made by these species to avoid the resultant acoustic disturbance, the availability of alternate areas and the short and sporadic duration of the demonstration, have led NMFS to preliminary determine that this action will have a negligible impact on the species in the specified geographic region.
Based on the analysis contained herein of the likely effects of the specified activity on marine mammals and their habitat, and taking into consideration the implementation of the mitigation and monitoring measures, NMFS preliminarily finds that ONR's proposed demonstration would result in the incidental take of marine mammals, by Level B harassment only, and that the total taking from the demonstration would have a negligible impact on the affected species or stocks.
There are no relevant subsistence uses of marine mammals implicated by this action. Therefore, NMFS has determined that the total taking of affected species or stocks would not have an unmitigable adverse impact on the availability of such species or stocks for taking for subsistence purposes.
Of the species of marine mammals that may occur in the proposed demonstration area, eight are listed as endangered under the ESA: blue whale, fin whale, gray whale, humpback whale, North Pacific right whale, sei whale, sperm whale, and Hawaiian monk seal. Under section 7 of the ESA, ONR has initiated formal consultation with NMFS, Office of Protected Resources, Endangered Species Act Interagency Cooperation Division, on this proposed demonstration. NMFS' Office of Protected Resources, Permits and Conservation Division, has also initiated formal consultation under section 7 of the ESA with NMFS' Office of Protected Resources, Endangered Species Act Interagency Cooperation Division, to obtain a Biological Opinion evaluating the effects of issuing the IHA on threatened and endangered marine mammals and, if appropriate, authorizing incidental take. NMFS will conclude formal section 7 consultation prior to making a determination on whether or not to issue the IHA. If the IHA is issued, ONR, in addition to the mitigation and monitoring requirements included in the IHA, would be required to comply with the Terms and Conditions of the Incidental Take Statement corresponding to NMFS' Biological Opinion issued to both ONR and NMFS' Office of Protected Resources, Permits and Conservation Division.
ONR has prepared a draft Overseas Environmental Assessment (OEA) to address the potential environmental impacts that could occur as a result of the proposed activity. To meet NMFS' National Environmental Policy Act (NEPA; 42 U.S.C. 4321 et seq.) requirements for the issuance of an IHA to ONR, NMFS will prepare an independent NEPA analysis. This analysis will be completed prior to issuance of a final IHA.
As a result of these preliminary determinations, NMFS proposes to issue an IHA to ONR for conducting the ONR ATE in one of nine provinces in this western North Pacific Ocean, provided the previously mentioned mitigation, monitoring, and reporting requirements are incorporated. The proposed IHA language is provided below:
The Office of Naval Research (2000 Navy Pentagon, Washington, DC 20350–2000), is hereby authorized under section 101(a)(5)(D) of the Marine Mammal Protection Act (MMPA; 16 U.S.C. 1371(a)(5)(D)) to harass marine mammals incidental to the Office of Naval Research (ONR) Acoustic Technology Experiments (ATE) in the western North Pacific Ocean, contingent upon the following conditions:
1. This Authorization is valid from May XX, 2013, through May XX, 2014.
2. This Authorization is valid only for ONR's activities associated with the ATE occurring in the western North Pacific Ocean.
3.
(a). The incidental taking of marine mammals, by Level B harassment only, is limited to the following species:
(i). Blue whale (
(ii). Bryde's whale (
(iii). Minke whale (
(iv). Fin whale (
(v). Gray whale (
(vi). Humpback whale (
(vii). North Pacific right whale (
(viii). Sei whale (
(ix). Baird's beaked whale (
(x). Blainville's beaked whale (
(xi). Bottlenose dolphin (
(xii). Cuvier's beaked whale (
(xiii). Dall's porpoise (
(xiv). Dwarf sperm whale (
(xv). False killer whale (
(xvi). Fraser's dolphin (
(xvii). Gingko-toothed beaked whale (
(xviii). Hubb's beaked whale (
(xix). Killer whale (
(xx).
(xxi). Longman's beaked whale (
(xxii). Melon-headed whale (
(xxiii).
(xxiv). Pacific white-sided dolphin (
(xxv). Pantropical spotted dolphin (
(xxvi). Pygmy killer whale (
(xxvii). Pygmy sperm whale (
(xxviii). Risso's dolphin (
(xxix). Rough-toothed dolphin (
(xxx). Short-beaked common dolphin (
(xxxi). Short-finned pilot whale (
(xxxii). Sperm whale (
(xxxiii). Spinner dolphin (
(xxxiv). Stejneger's beaked whale (
(xxxv). Striped dolphin (
(xxxvi). Hawaiian monk seal (
(xxxvii). If any marine mammal species are encountered during ONR ATE activities that are not listed here for authorized taking and are likely to be exposed to sound pressure levels (SPLs) greater than or equal to 160 dB re 1 μPa (rms), then the Holder of this Authorization must alter speed or course, or shut-down equipment to avoid take.
(b). The taking by injury (Level A harassment), serious injury, or mortality of any of the species listed in Condition 3(a) above or the taking of any other species of marine mammal is prohibited and may result in the modification, suspension, or revocation of this Authorization.
4. The methods authorized for taking, by Level B harassment only, are limited to four underwater acoustic sources with transmission frequencies below 1.5 kHz and sound pressure levels less than 220 dB.
5. The taking of any marine mammal in a manner prohibited under this Authorization must be reported immediately to the Chief, Permits and Conservation Division, Office of Protected Resources, National Marine Fisheries Service (NMFS) or his designee, at 301–427–8401.
6.
(a). Vessel movement—The Holder shall maneuver the research vessel, as feasible, to avoid closing within 457 m (1,499 ft) of a marine mammal.
(b). Mitigation zone—During operation of active acoustic sources, a 1-km mitigation zone shall be established around the sound source. This area will be continuously monitored by visual observers during daylight hours for marine mammals 30 minutes before transmissions begin, during transmissions, and for 30 minutes after transmissions are terminated, or 30 minutes after sunset (whichever comes first). Shutdown procedures will occur if a marine mammal is visually detected within the 1-km zone.
(c). Delay and shutdown procedures—During daytime transmissions, active acoustic source transmissions shall be immediately delayed or shut down if a marine mammal is visually detected within the 1-km mitigation zone. Transmissions would not commence/resume for 15 minutes (for small odontocetes and pinnipeds) or 30 minutes (for large whales) after the animal has moved out of the mitigation zone or there has been no further visual detection of the animal.
During nighttime transmissions, active acoustic source transmissions shall be immediately delayed or shutdown if a marine mammal is detected using passive acoustic monitoring. Transmissions would not commence/resume for 15 minutes (for small odontocetes and pinnipeds) or 30 minutes (for large whales) after there has been no further detection of the animal.
7.
(a). Visual monitoring—During daylight hours, two protected species observers shall continuously monitor for marine mammals when active acoustic sources are being used. One observer shall be positioned on the deck level above the bridge and the second observer shall be positioned on the bridge level. Monitoring shall begin 30 minutes before active acoustic source transmissions are scheduled to commence and shall continue until 30 minutes after active acoustic source transmissions are terminated, or 30 minutes after sunset (whichever comes first).
(b). Passive acoustic monitoring—During nighttime hours (and any other periods of decreased visual observation capabilities), the Holder shall conduct continuous passive acoustic monitoring when active acoustic sources are being used. Passive acoustic monitoring shall include listening for vocalizations and visually inspecting spectrograms of radio frequency-transmitted signals from a deployed sonobuoy by personnel trained in detecting and identifying marine mammal sounds. Monitoring shall begin 30 minutes before active acoustic source transmissions are scheduled to commence and shall continue until 30 minutes after active acoustic source transmissions are terminated, or 30 minutes after sunrise (whichever comes first).
If a passively detected sound is estimated to be from a marine mammal, the acoustic observer shall notify the appropriate personnel and shutdown procedures shall be implemented. For any marine mammal detection, the appropriate personnel shall order the immediate delay/suspension of the active acoustic source transmissions and/or deployment. Transmissions may commence/resume 15 minutes (for small odontocetes and pinnipeds) or 30 minutes (large whales) after there has been no further detection of the animal.
8.
(a). Submit two reports on all activities and monitoring results to the Office of Protected Resources, NMFS, within 90 days after the end of the specified activity: one unclassified report and one classified report. This report must contain and summarize the following information for when a marine mammal sighting is made:
(i). Dates, times, locations, heading, speed, weather, sea conditions (including Beaufort sea state and wind force), and associated activities during all active acoustic transmissions and marine mammal sightings;
(ii). Species, group size, age, individual size, sex (if determinable) of all marine mammal sightings;
(iii). Behavior of animal when first sighted, subsequent behaviors, and status of active acoustic sources;
(iv). Bearing and distance of observation from the vessel, sighting cue, and exhibited reaction to the active acoustic transmission or vessel (e.g., none, avoidance, approach, etc.), behavioral pace, and depth at time of detection;
(v). Fin/fluke characteristics and angle of fluke when an animal submerges to determine if the animal executed a deep or surface dive;
(vi). Type and nature of sounds heard;
(vii). Any other relevant information;
(viii). An estimate of the number (by species) of marine mammals that are known to have been exposed to active acoustic transmissions (based on visual observation and passive acoustic monitoring) at received levels greater than or equal to 195 dB re 1 µPa
(ix). A description of the implementation and effectiveness of the mitigation measures of the Incidental Harassment Authorization.
(b). When shutdown is required for mitigation purposes, the following information will also be recorded:
(i). The basis for decisions resulting in shutdown of active acoustic transmissions;
(ii). Information needed to estimate the number of marine mammals potentially taken by harassment;
(iii). Information on the frequency of occurrence, distribution, and activities of marine mammals in the demonstration area;
(iv). Information on the behaviors and movements of marine mammals during and without operation of active acoustic sources; and
(v). Any adverse effects the shutdown had on the demonstration.
(c). Submit a final report to the Chief, Permits and Conservation Division, Office of Protected Resources, NMFS, 1315 East West Highway, Silver Spring, Maryland, 20910, within 30 days after receiving comments from NMFS on the draft report. If NMFS decides that the draft report needs no comments, the draft report shall be considered the final report.
(d). In the unanticipated event that the specified activity clearly cause the take of a marine mammal in a manner prohibited by this Authorization, such as an injury (Level A harassment), serious injury, or mortality (e.g., ship-strike, gear interaction, and/or entanglement), ONR shall immediately cease operations and report the incident to the Chief of the Permits and Conservation Division, Office of Protected Resources, NMFS, at 301–427–8401 and/or by email to
(i) Time, date, and location (latitude/longitude) of the incident;
(ii) The name and type of vessel involved;
(iii) The vessel's speed during and leading up to the incident;
(iv) Description of the incident;
(v) Status of all sound source use in the 24 hours preceding the incident;
(vi) Water depth;
(vii) Environmental conditions (e.g., wind speed and direction, Beaufort sea state, cloud cover, and visibility);
(viii) Description of marine mammal observations in the 24 hours preceding the incident;
(ix) Species identification or description of the animal(s) involved;
(x) The fate of the animal(s); and
(xi) Photographs or video footage of the animal (if equipment is available).
Activities shall not resume until NMFS is able to review the circumstances of the prohibited take. NMFS will work with ONR to determine what is necessary to minimize the likelihood of further prohibited take and ensure MMPA compliance. ONR may not resume their activities until notified by NMFS via letter, email, or telephone.
(e). In the event that ONR discovers an injured or dead marine mammal, and the lead protected species observer determines that the cause of the injury or death is unknown and the death is relatively recent (i.e., in less than a moderate state of decomposition as described in the next paragraph), ONR shall immediately report the incident to the Chief of the Permits and Conservation Division, Office of Protected Resources, NMFS, at 301–427–8401, and/or by email to
(f). In the event that ONR discovers an injured or dead marine mammal, and the lead protected species observer determines that the injury or death is not associated with or related to the activities authorized in Condition 2 of this Authorization (e.g., previously wounded animal, carcass with moderate to advanced decomposition, or scavenger damage), ONR shall report the incident to the Chief of the Permits and Conservation Division, Office of Protected Resources, NMFS, at 301–427–8401, and/or by email to
9. The Holder of this Authorization is required to comply with the Terms and Conditions of the Incidental Take Statement (ITS) corresponding to NMFS' Endangered Species Act Biological Opinion issued to both the Office of Naval Research and NMFS' Office of Protected Resources.
10. A copy of this Authorization must be in the possession of all contractors and protected species observers operating under the authority of this Incidental Harassment Authorization.
11.
Any person who violates any provision of this Incidental Harassment Authorization is subject to civil and criminal penalties, permit sanctions, and forfeiture as authorized under the MMPA.
Commodity Futures Trading Commission.
Final order.
The Commodity Futures Trading Commission (“CFTC” or “Commission”) is exempting certain transactions between entities described in section 201(f) of the Federal Power Act (“FPA”), and/or other electric utility cooperatives, from the provisions of the Commodity Exchange Act (“CEA” or “Act”) and the Commission's regulations, subject to certain anti-fraud, anti-manipulation, and record inspection conditions. Authority for this exemption is found in section 4(c) of the CEA.
David Van Wagner, Chief Counsel, (202) 418–5481,
On June 8, 2012, the Commission received a petition (“Petition”) from a group of trade associations and other organizations representing the interests of government and/or cooperatively-owned electric utilities
Section 4(c) of the CEA provides the Commission with broad authority to exempt certain transactions and market participants from the requirements of the Act in order to “provid[e] certainty and stability to existing and emerging markets so that financial innovation and market development can proceed in an effective and competitive manner.”
[t]he Conferees do not intend that the exercise of exemptive authority by the Commission would require any determination beforehand that the agreement, instrument, or transaction for which an exemption is sought is subject to the [CEA]. Rather, this provision provides flexibility for the Commission to provide legal certainty to novel instruments where the determination as to jurisdiction is not straightforward. Rather than making a finding as to whether a product is or is not a futures contract, the Commission in appropriate cases may proceed directly to issuing an exemption.
Petitioners represented that section 201(f) of the Federal Power Act (“FPA”), administered by the Federal Energy Regulatory Commission (“FERC”), provides broad-based relief from most provisions of Part II of the FPA
[n]o provision in [Part II of the FPA] shall apply to, or be deemed to include, the United States, a State or any political subdivision of a State, an electric cooperative that receives financing under the Rural Electrification Act of 1936 (7 U.S.C. 901
Petition at 16 (quoting 16 U.S.C. 824(f)).
While CEA section 4(c)(6) prompted the Petitioners to request relief for FPA section 201(f) entities, Petitioners also sought to include in their definition of NFP Electric Entities, in accordance with CEA sections 4(c)(1) and 4(c)(2), any Federally-recognized Indian tribe and the very small number of electric cooperatives that are not described by FPA section 201(f). Petitioners argued that FERC has precedent for treating Federally-recognized Indian tribes as FPA 201(f) government entities.
Petitioners limited the relief requested to certain Electric Operations-Related Transactions that meet defined criteria. The Petition described seven specific categories of transactions that traditionally occur between NFP Electric Entities and provided examples of each: Electric energy delivered, generation capacity, transmission services, fuel delivered, cross-commodity transactions, other goods and services, and environmental rights, allowances or attributes.
The Commission published for comment in the
The Commission proposed a definition of Exempt Entities intended to capture the same scope of entities for which relief was requested by Petitioners. Generally, these entities included (i) electric facilities owned by government entities described in FPA section 201(f), (ii) electric facilities owned by Federally-recognized Indian tribes, (iii) any cooperatively-owned electric utility treated as a cooperative under Federal tax laws, and (iv) any other not-for-profit entity wholly-owned by one or more of the foregoing.
The Commission's proposed definition of Exempt Non-Financial Energy Transaction was narrower in scope than the transaction definition proposed by Petitioners. Namely, the Commission declined to propose categorical relief for any transaction not described by one of the seven categories included in the Petition because the broader transaction definition is too vague for the Commission to conduct a considered and robust public interest and CEA purposes analysis under CEA section 4(c).
Pursuant to CEA section 4(c)(1), the Commission also proposed conditioning its relief. First, the Commission proposed to reserve its general anti-fraud, anti-manipulation, and enforcement authority.
Given the scope of the relief contemplated by the Proposed Order as just described, the Commission was able to make the public interest determinations required under CEA sections 4(c)(1) and 4(c)(2). In the Proposed Order, the Commission determined that (i) Exempt Non-Financial Energy Transactions were innovative products necessary to meet the unique production, distribution, and usage needs of Exempt Entities that were constantly changing due to factors beyond their control;
In addition to requesting comment on the scope of the relief and the Commission's 4(c) determinations, the Commission posed specific questions
In response to the Proposed Order's Request for Comments, the Commission received two responses, both of which were generally supportive. The Electric Power Supply Association and the Edison Electric Institute, writing together (“Joint Associations”), voiced general support for the Proposed Order and the Commission's determinations that the exemption would be in the public interest, and did not request any clarification or propose any changes.
Upon careful consideration of the comments received, the Commission has determined to finalize the Proposed Order, with certain revisions to the “Final Order,”
Generally, Petitioners agreed with the scope of entities included in the definition of Exempt Entity. In response to a question posed by the Commission,
The Proposed Order defined Exempt Entities to include not only those entities described in FPA section 201(f),
Petitioners suggested a number of minor revisions to the language used in defining Exempt Entities in the Proposed Order in order “to clearly encompass the appropriate categories of electric entities discussed in the Petition and elsewhere in the Proposal.”
Petitioners also requested that the Commission remove the reference to “lowest cost possible” from clause (iii) in the Proposed Order's definition of electric “cooperatives” that qualify as Exempt Entities in order “to recognize that electric cooperatives have operational objectives in addition to low cost,
Lastly, Petitioners requested that the Commission delete the qualifier, “not-for-profit,” from clause (iv) of the Exempt Entity definition describing entities that are wholly-owned by one or multiple other Exempt Entities.
Similar to their suggested revisions to the definition of Exempt Entity, Petitioners suggested a number of minor revisions to the definition of Exempt Non-Financial Energy Transaction in order to align the Final Order more closely with Congressional intent. First, Petitioners requested that the Commission substitute the words “public service obligations” for “contractual obligations” in Section IV.B of the proposed definition to account for the fact that “Exempt Entities' obligations to electric customers arise in some cases under Federal or state law, or under local municipal ordinances or city charters, under Tribal laws or, for electric cooperatives, under organizational charters or by-laws, rather than under individual customer contracts.”
The Commission agrees with these suggestions and has revised the definition of Exempt Non-Financial Energy Transaction accordingly. The Commission notes, however, that by allowing Exempt Non-Financial Energy Transactions to be included as part of larger commercial agreements, it is not providing relief to any other type of transaction or component of the agreement that is not explicitly defined in the Final Order. That is, the inclusion of an Exempt Non-Financial Energy Transaction within a broader commercial agreement does not thereby provide relief to every transaction included within the entire agreement.
Petitioners also requested certain other clarifications with respect to the definition of Exempt Non-Financial Energy Transaction. First, the Commission is confirming that any “agricultural product or diesel fuel or [other] grade of crude oil that is used as fuel for electric generation may be the underlying commodity upon which an `Exempt Non-Financial Energy Transaction' is based.”
Next, the Petitioners' requested certain changes to the proposed definition of Exempt Non-Financial Energy Transactions regarding what ultimate purpose the transactions must serve. First, Petitioners requested that the Commission substitute the words “related to” for “to facilitate” in Section IV.B of the proposed definition because in some cases, such as with an agreement to share a generation asset in order to more cost-effectively comply with environmental standards, the transaction may “limit rather than facilitate electric generation, transmission or distribution operations.”
The Commission has determined to revise the purpose language to address Petitioners' concerns with the “intent to physically deliver” requirement. The amended definition no longer directly modifies an Exempt Entity's public service obligation as “facilitating” generation, transmission and/or delivery of electric energy service, and no longer includes the “intent to physically deliver” language. Rather, the amended definition provides that an Exempt Non-Financial Energy Transaction “would not have been entered into, but for an Exempt Entities' need to manage supply and/or price risks arising from its existing or anticipated public service obligations to physically generate, transmit, and/or deliver electric energy service to customers.”
The effect of the Commission's revisions to the definition should make it clear that Exempt Non-Financial Energy Transactions do not necessarily result in an immediate net increase in generation, transmission, and/or delivery of electric energy for each Exempt Entity involved. The Commission interprets the Final Order definition, as amended, in the larger context of an Exempt Entity's public service obligations, which can include certain reliability, conservation, and environmental considerations related to their operations and facilities. Thus,
These revisions are based on the Commission's recognition that not all Exempt Non-Financial Energy Transactions necessarily result in making or taking physical delivery of the “commodity” upon which the transaction is based, although many will.
Lastly, while not requested by commenters, the Commission has further revised the Exempt Non-Financial Energy Transaction definition. The descriptions of “Fuel Delivered” and “Cross-Commodity Pricing” transactions have been modified by replacing the operative verb “include” with “consist of.” While the category description is not necessarily closed, the Commission notes that the change is intended to reflect that there are certain characteristics that must be present for these types of transactions. The “consist of” language is consistent with the other four Exempt Non-Financial Energy Transaction category descriptions. Additionally, the Commission has added the qualification that Exempt Non-Financial Energy Transactions are not entered into on or subject to the rules of a registered entity, submitted for clearing to a derivatives clearing organization (“DCO”), and/or reported to a swap data repository (“SDR”). This modification is based on Petitioners' representation that Exempt Non-Financial Energy Transactions are not standardized instruments suitable for exchange trading, clearing, or reporting.
Regarding the condition that the Commission reserves the right to revisit any of the terms and conditions of the exemptive relief,
Petitioners requested that the Commission remove references in the Proposed Order to CEA section 4c(b) and Commission regulation 32.4 as non-exclusive provisions being reserved for purposes of conditioning the relief on the Commission's general anti-fraud, anti-manipulation, and enforcement authority.
The Commission has declined to remove the reference to CEA section 4c(b) and Commission regulation 32.4 from the Conditions of the Final Order. As is standard practice with past exemptive orders issued pursuant to CEA section 4(c), the Commission reserves its general anti-fraud and anti-manipulation authority, as well as the ability to revisit the terms and conditions of the relief at any time and determine that certain transactions are jurisdictional in order to execute the Commission's duties and advance the public interests and purposes of the CEA. The Commission also believes it prudent to reserve certain scienter-based prohibitions in the Act and Commission regulations (without finding it necessary in this particular context to preserve other enforcement authority), and has modified the language in the Final Order to make the scope of this reservation clear. While Petitioners are correct that the provisions in question do not articulate the Commission's general anti-fraud, anti-manipulation and enforcement authority directly, the provisions exemplify a possible statutory basis for bringing an enforcement action, were a need to arise for the Commission to do so, and notes that the inclusion of these provisions is not intended to bring any transactions under CFTC jurisdiction for purposes other than enforcement.
The Commission also has determined to add new CEA sections 4s(h)(1)(A) and 4s(h)(4)(A)
Finally, the Commission is adding CEA section 4(d) to the non-exclusive list of reserved enforcement authority. The Commission believes it is important to highlight that, as with all exemptions issued pursuant to CEA section 4(c), the exemption “shall not affect the authority of the Commission under any other provision of [the CEA] to conduct investigations in order to determine compliance with the requirements or conditions of such exemption or to take enforcement action for any violation of any provision of [the CEA] or any rule, regulation or order thereunder caused by the failure to comply with or satisfy such conditions or requirements.”
The Commission is providing further clarification with respect to the appropriate uses of Exempt Non-Financial Energy Transactions and responding to other comments made by the Petitioners.
The Commission requested comment on whether Exempt Non-Financial Energy Transactions, as defined in the Proposed Order, could be used to hedge price risk in an underlying commodity, and if so, whether the Commission explicitly should exclude such price-hedging transactions.
The Commission is persuaded that Congress intended for the Commission to consider providing relief for transactions managing price risk entered into between FPA section 201(f) entities that goes beyond the relief available through the end-user exception for price hedging transactions, if in the public interest. Therefore, the Commission has made explicit in the Final Order definition that the scope of relief covers transactions entered into not only to manage supply risk arising from an Exempt Entity's public service obligation to physically generate, transmit, and/or deliver electric energy service, but also any price risk associated with an underlying commodity used to facilitate the public service obligation. The Commission believes that the overall effect of the revisions to the definition of Exempt Non-Financial Energy Transaction
The Commission sought comment on whether it should grant Petitioners' original request for the effective date of any 4(c) relief issued to be retroactive to the date of enactment of the Dodd-Frank Act.
In response to the Commission's specific request for comments on the topic,
As acknowledged by Petitioners elsewhere in their comment letter, Congress intended for all transactions occurring within the closed-loop of FPA section 201(f) entities to be “eligible for” an exemption,
Accordingly, as stated in the Proposed Order, the Commission does not believe it can determine conclusively that it would be in the public interest to exempt any transaction entered into between Exempt Entities. Even if a transaction were to meet the requirements of the Exempt Non-Financial Energy Transactions definition, but not be described by one of the six enumerated transaction categories, the Commission would lack the necessary information about the specific nature of the transaction in order to make the requisite public interest determination.
The Commission is issuing the Final Order pursuant its authority in CEA sections 4(c)(1) and 4(c)(6).
Due to the bespoke nature of Exempt Non-Financial Energy Transactions, the Commission does not believe that the exchange-trading requirement of CEA section 4(a) should apply. Generally, the exchange-trading requirement is meant to facilitate the price discovery and price transparency processes. Because (i) exchange-traded contracts are less effective at adequately performing as risk management substitutes for Exempt Non-Financial Energy Transactions; and (ii) Exempt Non-Financial Energy Transactions are executed within a closed-loop of Exempt Entities, and thus are not market facing, Exempt Non-Financial Energy Transactions do not materially impair price discovery in Commission-regulated markets and can continue to be executed bilaterally. For that reason, the Commission is limiting the Final Order to Exempt Non-Financial Energy Transactions entered into between Exempt Entities.
The Commission continues to believe that the scope of the Final Order is consistent with the public interest supported by the CEA.
As discussed previously in response to Petitioners' comments, the Commission has clarified in the Final Order that Exempt Non-Financial Energy Transactions can be used to hedge prices of underlying commodities, so long as the transaction meets the other definitional criteria and falls into one of the delineated transaction categories.
The Commission also believes that the Final Order is consistent with the purposes of the CEA.
The Commission believes that Exempt Entities, as defined in the Final Order, are all “appropriate persons” for purposes of satisfying the CEA section 4(c)(2) requirement.
The Commission believes that Exempt Entities not explicitly described in FPA section 201(f) are also appropriate persons.
Next, some non-FPA section 201(f) electric cooperatives may qualify as appropriate persons under the CEA section 4(c)(3)(F) criteria by having a net worth exceeding $1,000,000 or total assets exceeding $5,000,000. For any non-FPA section 201(f) cooperative that does not otherwise qualify as an appropriate person under the specific provisions of section 4(c)(3), the Commission believes that such entities are at least as financially sophisticated and operationally capable as FPA section 201(f) cooperatives. Such cooperatives would not qualify as FPA section 201(f) entities because they sell in excess of 4,000,000 megawatt hours of electricity per month, and/or receive financing from lenders other than the RUS. In either case, such cooperatives likely would have greater assets due to the increased sales, which could qualify them for better financing terms than those offered by the RUS. Additionally, the Commission notes that such cooperatives are not exempt from FERC's jurisdiction, and thus subject to more regulatory oversight than FPA section 201(f) electric cooperatives. The Commission interprets such FERC oversight of non-FPA section 201(f) electric cooperatives as the type of “appropriate regulatory protections” within the meaning of CEA section 4(c)(3)(K) that Congress had in mind when promulgating new exemptive authority for FPA 201(f) entities in CEA section 4(c)(6)(C).
As stated previously, Exempt Non-Financial Energy Transactions are bespoke and executed within the closed-loop of Exempt Entities, meaning they do not materially affect trading or pricing of transactions involving the same underlying commodity in Commission-regulated markets. Additionally, the Commission has retained its anti-fraud and anti-manipulation authority, as well as certain scienter-based prohibitions. Accordingly, the Commission does not believe that the exemptive relief provided in the Final Order will have a materially adverse effect on the ability of the Commission or any contract market to discharge their regulatory or self-regulatory duties under the CEA. As noted above, the Commission is limiting the Final Order to Exempt Non-Financial Energy Transactions entered into other than on or subject to the rules of a registered entity, submitted for clearing to a DCO, and/or reported to a SDR.
The Regulatory Flexibility Act (“RFA”) requires that Federal agencies consider whether proposed rules will have a significant economic impact on a substantial number of small entities and, if so, provide a regulatory flexibility analysis on the impact.
In response to the Proposed Order, the Commission received several comments from the Petitioners relevant to the RFA. The Petitioners requested that the Commission conduct future analyses of the impact on small entities the Petitioners represent if the Commission ever were to revisit the terms and conditions of the relief, and that the Commission provide relief retroactively to the enactment of the Dodd-Frank Act in the Final Order. In response to the request that the Commission conduct a future Small Business Regulatory Enforcement Fairness Act (“SBREFA”) analysis,
With regards to the Petitioners' general conclusion that the organizations that they represent fall within the definition of “small entity,”
Under the Paperwork Reduction Act (“PRA”), 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 control number from the Office of Management and Budget (“OMB”). The Commission determined that the Proposed Order did not contain any new information collection requirements, and did not receive any comments regarding this determination. As the Commission has left the conditions that were contained in the Proposed Order unchanged, the Final Order therefore also does not contain any new information collection requirements that would require approval of OMB under the PRA.
Prior to the passage of the Dodd-Frank Act, swap market activity was largely unregulated. In the wake of the financial crisis of 2008, Congress adopted the Dodd-Frank Act, in part, to address conditions with respect to swap market activities. Among other things, the Dodd-Frank Act amends the CEA to expand its scope beyond regulation of “contract[s] of sale of a commodity for future delivery”
Section 15(a) of the CEA
The Commission considers the costs and benefits of the Final Order to the public and market participants, including Exempt Entities, against the backdrop of the CEA regulatory regime for derivatives, as amended by the Dodd-Frank Act, and absent the relief provided by the Final Order.
The Commission remains cognizant of the regulatory landscape as it existed before the enactment of Dodd-Frank. As such, the Commission notes that any Exempt Non-Financial Energy Transactions engaged in between Exempt Entities that are swaps (excluding options) under the statutory definition and Commission rules were not regulated prior to Dodd-Frank. Thus, measured against a pre-Dodd-Frank Act reference point, Exempt Entities engaging in such swaps could experience costs attributable to the conditions placed upon the Final Order. For example, Exempt Entities were not subject to the Commission's routine regulatory inspection authorities with respect to records of Exempt Non-Financial Energy Transactions transacted bilaterally away from a trading facility prior to the enactment and effectiveness of the Dodd-Frank Act. The same was not true to the extent Exempt Non-Financial Energy Transactions are futures contracts, as such contracts have always been regulated by the Commission and Dodd-Frank did not fundamentally alter the futures regulatory scheme.
The Proposed Order expressly requested public comment on the Commission's cost-benefit considerations, including with respect to reasonable alternatives; the magnitude of specific costs and benefits (including data or other information to estimate a dollar valuation); and any impact on the public interest factors specified in CEA section 15(a).
In the discussion that follows, the Commission considers the costs and benefits of the Final Order to the public and market participants, generally, and to Exempt Entities, specifically. As discussed above, the Commission has refined the Final Order to clarify several issues identified in the Petitioners' comment letter.
The Final Order provides Exempt Entities with relief from regulatory requirements of the CEA for the narrow category of Exempt Non-Financial Energy Transactions engaged in between them. As with any exemption, this order is permissive, meaning that potentially eligible entities are not required to avail themselves of the relief it offers. Accordingly, the Commission presumes that an entity would rely on the Final Order only if the anticipated benefits warrant the costs. Here, the Final Order provides for the continued application of the Commission's general anti-fraud and anti-manipulation authority, and certain scienter-based prohibitions, under the CEA and its implementing regulations, and additionally reserves the Commission's inspection authority for books and records that the Exempt Entities currently prepare and retain.
The Commission has considered whether an exemption from the CEA for Exempt Non-Financial Energy Transactions engaged in between Exempt Entities will expose market participants and the public to the risks that the CEA guards against—a potential cost. For a variety of reasons, the Commission believes that it does not. These reasons—which were identified in the Proposed Order and not disputed by commenters—include the following:
• Exempt Non-Financial Energy Transactions are ill-suited for exchange trading, as evidenced by their bespoke nature to manage Exempt Entities' operational risks, and thus do not serve a material price discovery function.
• The incentive structure for Exempt Entities—as generally limited to not-for-profit governmental, tribal, and IRC section 501(c)(12) or section 1381(a)(2)(c) electric cooperative entities
• Exempt Non-Financial Energy Transactions are executed bilaterally
Besides carefully defining the boundaries for Exempt Non-Financial Energy Transactions between Exempt Entities, the Final Order incorporates conditions designed to protect the markets subject to the Commission's jurisdiction. Specifically, the Commission retains its general anti-fraud and anti-manipulation authority, and certain scienter-based prohibitions, contained in the CEA and its implementing regulations. Additionally, the Commission retains authority to inspect books and records kept in the normal course of business, pursuant to its regulatory inspection authorities, in the event that circumstances warrant greater visibility with respect to Exempt Non-Financial Energy Transactions as they relate to Exempt Entities' overall market positions and compliance with this Final Order. This retained authority to inspect books and records also provides a tool for the Commission to monitor any evolution and/or change in the usage of Exempt Non-Financial Energy Transactions to ensure that they conform to the expectations described in this order and that the relief provided herein remains appropriate and in the public interest. Accordingly, for the narrow subset of electric industry transactions covered by this Final Order, the Commission believes that the risk potential, at most, is remote and the prescribed conditions appropriate to contain it. The Final Order, therefore, should not give rise to any costs attributable to increased risk.
Next, the Commission considered the potential that price discovery in jurisdictional, non-exempt markets could be diminished because Exempt Entities, acting under the relief provide in this Final Order, eschewed such markets in favor of performing production and price risk management via Exempt Non-Financial Energy Transactions with one another. The Commission deems the risk of this occurring to be insignificant. While an underlying commodity may be similar or identical to that which underlies a standardized product available for trading in a non-exempt, jurisdictional market, the bespoke nature of Exempt Non-Financial Energy Transactions is such that it is unlikely that non-exempt market transactions would be an effective substitute for Exempt Entities going forward. As such, and in addition to the Commission's anticipation that the number of Exempt Entity transactions will be small relative to the total number of transactions in related non-exempt markets, any distortive impact on price discovery in Commission-regulated markets would be immaterial.
Similarly, the Commission considered whether the Final Order would have any impact on the efficiency, competitiveness,
The Commission does not view the various refinements that it incorporated in the Final Order in response to comments as altering the continuing logic or validity of these reasons; rather, as explained above,
Relative to no exemption, the Final Order will benefit Exempt Entities by lessening the likelihood that compliance with the CEA and Commission regulations would diminish their ability and/or incentives to continue to engage in Exempt Non-Financial Energy Transactions that, as described in the Petition, the Proposed Order, and above, are an operational tool relied upon by Exempt Entities to effectively execute their public service mission. The exemption will benefit Exempt Entities by providing assurances that these Exempt Non-Financial Energy Transactions upon which they rely are not subject to the CEA and Commission regulations.
To the extent Exempt Non-Financial Energy Transactions are swaps, as a threshold matter, absent Commission action, CEA section 2(e) would prohibit Exempt Entities from executing them away from a registered DCM unless both Exempt Entity counterparties qualify as ECPs. The relevant criteria for determining ECP status varies for Exempt Entities that are governmental entities (or political subdivisions of governmental entities) and those that are not. For the former, governmental Exempt Entities must meet certain line of business requirements,
If Exempt Entities are not ECPs, and given that Petitioners have represented that Exempt Non-Financial Energy Transactions are bespoke and therefore unsuitable for exchange trading, absent Commission action, non-ECP Exempt Entities would be unable to engage bilaterally in any Exempt Non-Financial Energy Transactions that are swaps. Relative to a circumstance that would preclude non-ECP Exempt Entities from continuing to engage in Exempt Non-Financial Energy Transactions that are swaps, the Final Order allows for the continued use of transactions that are closely related to Exempt Entities' public service mission to provide affordable, reliable electricity—a benefit. The Final Order also saves Exempt Entities the time and expense necessary to determine if they are ECPs. While under the Final Order, ECP status becomes largely irrelevant, without it, Exempt Entities may have to concern themselves with ECP status determinations as a threshold for engaging in certain transactions.
Even assuming,
Lastly, to the extent that Exempt Non-Financial Energy Transactions are swaps, the Final Order also avoids potential costs that Exempt Entities might incur to comply with swap data reporting and recordkeeping requirements as articulated in Commission regulations.
Swap Data Recordkeeping and Reporting Requirements 77 FR 2136 (Jan. 13, 2012) (adopting 17 CFR part 45); Swap Data Recordkeeping and Reporting Requirements: Pre-enactment and Transition Swaps 77 FR 35200 (June 12, 2012) (adopting 17 CFR part 46);
Even for Exempt Non-Financial Energy Transactions that are not swaps, if Exempt Entities perceived some potential that they could be swaps (now or as they evolve in the future), Exempt Entities would likely need to expend resources to monitor contemplated transactions and make status determinations as to them. Moreover, the bespoke nature of these transactions could complicate the ability to generalize conclusions across transactions, potentially resulting in a need for more frequent, individualized assessments that could multiply determination costs. While the Commission lacks a basis to meaningfully project any such benefit in dollar terms, qualitatively it expects that the benefit would include the avoided costs of training staff to differentiate between swap and non-swap transactions and, in some cases at least, to obtain an expert legal opinion to support a determination. Additionally, uncertainty about whether a certain transaction would or would not be deemed a swap could prompt an Exempt Entity to forego a beneficial transaction or to substitute a transaction that served the operational needs less effectively. The Commission considers avoiding a result that would diminish the use of operationally-efficient Exempt Non-Financial Energy Transactions to be an important benefit.
For reasons similar to those discussed in the Commission's analysis of the Proposed Order under CEA sections 4(c)(1) and 4(c)(6), the Commission asserts that this Final Order will benefit the public, generally.
First, in that the Exempt Entities share the same public-service mission of providing affordable, reliable electricity to their customers, those aspects of the Final Order that benefit Exempt Entities directly should benefit their customers indirectly as well. For example, the Final Order would enable non-ECP Exempt Entities to engage in Exempt Non-Financial Energy Transactions, to the extent they are swaps, that would be barred to them under CEA section 2(e), or facilitate the likelihood that they would continue to engage in Exempt Non-Financial Energy Transactions that they might choose to forego for regulatory uncertainty or cost reasons absent the exemption. In these circumstances, Exempt Entity customers likely would be the ultimate beneficiaries (via supply reliability and affordability) of the operational risk-management and efficiencies that Exempt Non-Financial Energy Transactions afford. Similarly, to the extent that the Final Order enables Exempt Entities to avoid compliance and/or monitoring costs they would otherwise incur, the non-profit structure, conformance with requisite Internal Revenue Code guidelines, and public service mission that Exempt Entities share means that the cost savings should be passed through to members and other customers in the form of lower electricity prices.
Second, the public also benefits by the promotion of economic and financial innovation that this Final Order facilitates.
Accordingly, the Final Order provides an overall benefit to the public.
The chief alternatives to this Final Order are for the Commission to (i)
With respect to the first alternative—decline to exempt—the costs and benefit consideration is the mirror-image of that discussed above. A decision not to provide an exemption in this circumstance would preserve the current post-Dodd-Frank regulatory environment.
Relative to the second alternative—adopting the exemption as proposed—the Commission has made two substantive changes to the definition of Exempt Non-Financial Energy Transaction based upon Petitioners' comments. These are: i) Striking the requirement that Exempt Non-Financial Energy Transactions be “intended for making or taking physical delivery of the commodity upon which the agreement, contract, or transaction is based” (the “physical delivery requirement”); and ii) consistent with the first change, explicitly clarifying that Exempt Non-Financial Energy Transactions can be used to “manage supply and/or
Eliminating the physical delivery requirement and clarifying that Exempt Non-Financial Energy Transactions may be used to manage price risk (as well as supply risk) arguably blurs the definitional distinction that the Proposed Order otherwise would have expressly provided between Exempt Non-Financial Energy Transactions and jurisdictional futures contracts.
However, even without the physical-delivery requirement and with the price-risk management clarification, the Commission does not expect the Final Order to undermine the exchange trading requirement for, or the Commission's oversight of, futures.
The Commission also has revised the Final Order from what was proposed to accommodate Petitioners' request that final exemptive relief apply retroactively to the enactment of the Dodd-Frank Act. As a consequence, Exempt Entities will be saved any costs associated with determining whether certain Exempt Non-Financial Energy Transactions entered into prior to the effective date of the Final Order were historical swaps or not, and reporting those historical transactions to an SDR.
Relative to the third alternative of exercising its exemptive authority more broadly and in a manner that would provide categorical relief from all of the requirements of the CEA as requested by Petitioners in their original Petition, the Commission purposefully has defined the categories of exempt transactions more narrowly, and preserved certain aspects of CEA jurisdiction with respect to them. As reiterated in their comment letter,
Finally, the exemption reserves the Commission's general anti-fraud and anti-manipulation authority, and certain scienter-based prohibitions, as well as the Commission's authority to review books and records already kept in the ordinary course of business in the event that circumstances warrant the need to gain greater visibility with respect to Exempt Non-Financial Energy Transactions as they relate to Exempt Entities' overall market positions, and to ensure compliance with the terms of this Final Order.
As explained above, the Commission does not foresee that the Final Order will negatively affect the protection of market participants and the public. More specifically, Exempt Non-Financial Energy Transactions, as transacted bilaterally and in a closed loop between Exempt Entities in the highly specialized and unique electric-industry circumstances, do not appear to generate risks of the nature addressed by the CEA. The Commission has delineated the definitional boundaries for Exempt Entities and Exempt Non-Financial Energy Transactions in a manner that appropriately ring-fences against the possibility that they could generate such risks, either now or as they may evolve in the future. Moreover, the exemption incorporates conditions
The Commission foresees little, if any, negative impact from the Final Order on the efficiency, competitiveness, and financial integrity of markets regulated under the CEA. This is because, to the extent any are jurisdictional, Exempt Non-Financial Energy Transactions entered into between Exempt Entities constitute only a narrow market segment limited to bespoke transactions, executed bilaterally between non-financial entities primarily in order to satisfy existing or expected operations-related public service obligations. Moreover, the Commission anticipates the Final Order will help to maintain the competitive landscape and efficiency of the market segment for Exempt Non-Financial Energy Transactions entered into between Exempt Entities. As previously discussed, the Final Order maintains the number of counterparties that Exempt Entities will be able to face—namely, other Exempt Entities with which they already conduct Exempt Non-Financial Energy Transactions—by exempting Exempt Non-Financial Energy Transactions between Exempt Entities from CEA section 2(e), and eliminates the possibility that entering into Exempt Non-Financial Energy Transactions will subject Exempt Entities to the full array of compliance costs arising from the Commission's ongoing oversight regime.
Further, as an exercise of the Commission's CEA section 4(c) authority to provide legal certainty for novel instruments as Congress intended, the Final Order affords Exempt Entities transactional flexibility that the Commission understands to be valuable to their ability to efficiently deploy their limited resources.
The Commission does not believe that the Final Order will materially impair price discovery in non-exempt, jurisdictional markets. The Commission recognizes that a desire to avoid regulation in theory could incentivize Exempt Entities to participate in Exempt Non-Financial Energy Transactions to a greater extent than they otherwise might choose to do, vis-à-vis related non-exempt markets. This is unlikely, however, due to the requirement that Exempt Non-Financial Energy Transactions be entered into only to manage supply and/or price risk arising from their public service obligations to physically supply electric energy service to customers, and only with other Exempt Entities. The relatively small size of trading in this market segment also renders it unlikely that the Final Order will materially impair price discovery in jurisdictional markets even were the Final Order to incentivize Exempt Entities to execute some of their customer-serving transactions pursuant to the Final Order instead of on a registered entity. Thus, against the backdrop of Congress' mandate to consider exempting transactions between FPA 201(f) entities, the Commission believes that the Final Order would not materially distort price discovery in non-exempt, jurisdictional markets.
The Final Order will promote the ability of Exempt Entities to manage the operational risks posed by unique electricity market characteristics, including the non-storable nature of electricity and demand that can and frequently does fluctuate dramatically within a short time-span. As discussed above, the Commission understands that Exempt Non-Financial Energy Transactions are an important tool facilitating the ability of Exempt Entities to efficiently manage operational risk in fulfillment of their public service mission to provide affordable, reliable electricity.
In exercising its exemptive authority under CEA sections 4(c)(1) and 4(c)(6) in the Final Order, the Commission is acting to promote the broader public interest in facilitating the generation, transmission, and delivery of affordable, reliable electric energy service as Congress contemplated.
Based on the Petitioners' representations, and for the reasons set forth above, the Commission hereby
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On this matter, Chairman Gensler and Commissioners Sommers, Chilton, O'Malia and Wetjen voted in the affirmative. No Commissioner voted in the negative.
I support the final order regarding certain electricity and electricity-related energy transactions between rural electric cooperatives and/or federal, state, municipal, and tribal power authorities (as defined in section 201F of the Federal Power Act).
Congress authorized that these transactions be exempt from certain provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act, which is consistent with previous exemptions Congress has granted from the Federal Power Act. For decades, these entities have been generally recognized as performing a public service mission to provide their customers or cooperative members with reliable, affordable electric energy service. They have been largely exempt from regulation by the Federal Energy Regulatory Commission because of their government entity status or their not-for-profit cooperative status.
This final order responds to a petition filed by a group of these cooperatives and authorities and has benefitted from public input.
The scope of the final order is carefully tailored to physically backed electricity and electricity-related energy transactions that are necessary for the generation, transmission and delivery of electric energy services to customers.
Office of the Under Secretary of Defense for Personnel and Readiness, DoD.
Notice.
In compliance with Section 3506(c)(2)(A) of the
Consideration will be given to all comments received by June 3, 2013.
You may submit comments, identified by docket number and title, by any of the following methods:
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To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to the Defense Manpower Data Center, ATTN: Daniel McCarthy, 400 Gigling Road, Seaside, CA 93955, or call the DBIDS Office at 831–583–2400 x4744.
Respondents are individuals who require physical access to DoD installations. Basic identifying information is collected from the individuals including several biometrics. Additional information may also be collected (such as contact information, vehicle information, organization affiliation, etc.) but is not required for that person to be registered and gain access to the controlled installation.
Department of Defense (DOD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).
Notice of request for public comments regarding an extension to an existing OMB clearance.
Under the provisions of the Paperwork Reduction Act, the Regulatory Secretariat will be submitting to the Office of Management and Budget (OMB) a request to review and approve an extension to a previously approved information collection requirement concerning prompt payment. A notice was published in the
Submit comments on or before May 2, 2013.
Submit comments identified by Information Collection 9000–0102, Prompt Payment, by any of the following methods:
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Submit comments via the Federal eRulemaking portal by searching the OMB control number. Select the link “Submit a Comment” that corresponds with “Information Collection 9000–0102, Prompt Payment”. Follow the instructions provided at the “Submit a Comment” screen. Please include your name, company name (if any), and “Information Collection 9000–0102, Prompt Payment” on your attached document.
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Mr. Edward Chambers, Procurement Analyst, Office of Acquisition Policy, GSA (202) 501–3221 or email
Part 32 of the FAR and the clause at FAR 52.232–5, Payments Under Fixed-Price Construction Contracts, require that contractors under fixed-price construction contracts certify, for every progress payment request, that payments to subcontractors/suppliers have been made from previous payments received under the contract and timely payments will be made from the proceeds of the payment covered by the certification, and that this payment request does not include any amount which the contractor intends to withhold from a subcontractor/supplier. Part 32 of the FAR and the clause at 52.232–27, Prompt Payment for Construction Contracts, further require that contractors on construction contracts—
(a) Notify subcontractors/suppliers of any amounts to be withheld and furnish a copy of the notification to the contracting officer;
(b) Pay interest to subcontractors/suppliers if payment is not made by 7 days after receipt of payment from the Government, or within 7 days after correction of previously identified deficiencies;
(c) Pay interest to the Government if amounts are withheld from subcontractors/suppliers after the Government has paid the contractor the amounts subsequently withheld, or if the Government has inadvertently paid the contractor for nonconforming performance; and
(d) Include a payment clause in each subcontract which obligates the contractor to pay the subcontractor for satisfactory performance under its subcontract not later than 7 days after such amounts are paid to the contractor, include an interest penalty clause which obligates the contractor to pay the subcontractor an interest penalty if payments are not made in a timely manner, and include a clause requiring each subcontractor to include these clauses in each of its subcontractors and to require each of its subcontractors to include similar clauses in their subcontracts.
These requirements are imposed by Public Law 100–496, the Prompt Payment Act Amendments of 1988.
Contracting officers will be notified if the contractor withholds amounts from subcontractors/suppliers after the Government has already paid the contractor the amounts withheld. The contracting officer must then charge the contractor interest on the amounts withheld from subcontractors/suppliers. Federal agencies could not comply with the requirements of the law if this information were not collected.
Data from the Federal Procurement Data System (FPDS) regarding fixed price construction contracts for Fiscal Year (FY) 2011 revealed that the number of affected contracts and, therefore, respondents has been reduced from the previously approved information collection. Based on the data, an estimated 2,679 contractors or respondents will provide an average of 18.27 responses per year to meet the requirements of this collection. The time required to assemble and prepare notification or certification regarding withhold is estimated at .11 hours per notice. This estimate is based on the assumption that some construction contractors will be required to notify the Government of withholding and others will have to provide their payment certification. This estimate also assumes automation of contractor records. The recordkeeping burden is based on the revised number of contracts for FY11 and the estimated hours from the previously approved collection.
DoD.
Meeting notice.
Under the provisions of the Federal Advisory Committee Act of 1972 (5 U.S.C., Appendix, as amended), the Government in the Sunshine Act of 1976 (5 U.S.C. 552b, as amended), and 41 CFR 102–3.150, the Department of Defense announces the following Federal advisory committee meeting of the Defense Business Board.
The public meeting of the Defense Business Board (hereafter referred to as “the Board”) will be held on Thursday, April 25, 2013. The meeting will begin at 12:30 p.m. and end at 3:00 p.m. (escort required; see guidance in
Room 3E863 in the Pentagon, Washington, DC (escort required; see guidance in
The Board's Designated Federal Officer is Phyllis Ferguson, Defense Business Board, 1155 Defense Pentagon, Room 5B1088A, Washington, DC 20301–1155,
Pursuant to 41 CFR 102–3.105(j) and 102–3.140, and section 10(a)(3) of the Federal Advisory Committee Act of 1972, the public or interested organizations may submit written comments to the Board about its mission and topics pertaining to this public meeting.
Written comments should be received by the DFO at least five (5) business days prior to the meeting date so that the comments may be made available to the Board for their consideration prior to the meeting. Written comments should be submitted via email to the address for the DFO given in this notice in either Adobe Acrobat or Microsoft Word format. Please note that since the Board operates under the provisions of the Federal Advisory Committee Act, as amended, all submitted comments and public presentations will be treated as public documents and will be made available for public inspection, including, but not limited to, being posted on the Board's Web site.
Office of Elementary and Secondary Education, Department of Education.
Notice.
Advanced Placement Test Fee Program. Notice inviting applications for new awards for fiscal year (FY) 2013.
Catalog of Federal Domestic Assistance (CFDA) Number: 84.330B.
Dates:
The Department is not bound by any estimates in this notice.
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For the purposes of this program, the Bureau of Indian Education in the U.S. Department of the Interior is treated as an SEA.
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To obtain an application package from the Department use the following address: Francisco Ramirez, U.S. Department of Education, 400 Maryland Avenue SW., room 3E224, Washington, DC 20202–6200. Telephone: (202) 260–1541 or by email:
If you use a telecommunications device for the deaf (TDD) or a text telephone (TTY), call the Federal Relay Service (FRS), toll free, at 1–800–877–8339.
Individuals with disabilities can obtain a copy of the application package in an accessible format (e.g., braille, large print, audiotape, or compact disc) by contacting the program contact person listed in this section.
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Applications for grants under this program must be submitted electronically using the Grants.gov Apply site (Grants.gov). For information (including dates and times) about how to submit your application electronically, or in paper format by mail or hand delivery if you qualify for an exception to the electronic submission requirement, please refer to section IV. 7.
We do not consider an application that does not comply with the deadline requirements.
Individuals with disabilities who need an accommodation or auxiliary aid in connection with the application process should contact the person listed under
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a. Have a Data Universal Numbering System (DUNS) number and a Taxpayer Identification Number (TIN);
b. Register both your DUNS number and TIN with the Central Contractor Registry (CCR)—and, after July 24, 2012, with the System for Award Management (SAM), the Government's primary registrant database;
c. Provide your DUNS number and TIN on your application; and
d. Maintain an active CCR or SAM registration with current information while your application is under review by the Department and, if you are awarded a grant, during the project period.
You can obtain a DUNS number from Dun and Bradstreet. A DUNS number can be created within one business day.
If you are a corporate entity, agency, institution, or organization, you can obtain a TIN from the Internal Revenue Service. If you are an individual, you can obtain a TIN from the Internal Revenue Service or the Social Security Administration. If you need a new TIN, please allow 2–5 weeks for your TIN to become active.
The CCR or SAM registration process may take five or more business days to complete. If you are currently registered with the CCR, you may not need to make any changes. However, please make certain that the TIN associated with your DUNS number is correct. Also note that you will need to update your registration annually. This may take three or more business days to complete. Information about SAM is available at SAM.gov.
In addition, if you are submitting your application via Grants.gov, you must (1) be designated by your organization as an Authorized Organization Representative (AOR); and (2) register yourself with Grants.gov as an AOR. Details on these steps are outlined at the following Grants.gov Web page:
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Applications for grants under the AP Test Fee program, CFDA number 84.330B, must be submitted electronically using the Governmentwide Grants.gov Apply site at
We will reject your application if you submit it in paper format unless, as described elsewhere in this section, you qualify for one of the exceptions to the electronic submission requirement and submit, no later than two weeks before the application deadline date, a written statement to the Department that you qualify for one of these exceptions.
You may access the electronic grant application for the AP Test Fee program at
Please note the following:
• When you enter the Grants.gov site, you will find information about submitting an application electronically through the site, as well as the hours of operation.
• Applications received by Grants.gov are date and time stamped. Your application must be fully uploaded and submitted and must be date and time stamped by the Grants.gov system no later than 4:30:00 p.m., Washington, DC time, on the application deadline date. Except as otherwise noted in this section, we will not accept your application if it is received—that is, date and time stamped by the Grants.gov system—after 4:30:00 p.m., Washington, DC time, on the application deadline date. We do not consider an application that does not comply with the deadline requirements. When we retrieve your application from Grants.gov, we will notify you if we are rejecting your application because it was date and time stamped by the Grants.gov system after 4:30:00 p.m., Washington, DC time, on the application deadline date.
• The amount of time it can take to upload an application will vary depending on a variety of factors, including the size of the application and the speed of your Internet connection. Therefore, we strongly recommend that you do not wait until the application deadline date to begin the submission process through Grants.gov.
• You should review and follow the Education Submission Procedures for submitting an application through Grants.gov that are included in the application package for this program to ensure that you submit your application in a timely manner to the Grants.gov system. You can also find the Education Submission Procedures pertaining to Grants.gov under News and Events on the Department's G5 system home page at
• You will not receive additional point value because you submit your application in electronic format, nor will we penalize you if you qualify for an exception to the electronic submission requirement, as described elsewhere in this section, and submit your application in paper format.
• You must submit all documents electronically, including all information you typically provide on the following forms: The Application for Federal Assistance (SF 424), the Department of Education Supplemental Information for SF 424, Budget Information—Non-Construction Programs (ED 524), and all necessary assurances and certifications.
• You must upload any narrative sections and all other attachments to your application as files in a PDF (Portable Document) read-only, non-modifiable format. Do not upload an interactive or fillable PDF file. If you upload a file type other than a read-only, non-modifiable PDF or submit a password-protected file, we will not review that material.
• Your electronic application must comply with any page-limit requirements described in this notice.
• After you electronically submit your application, you will receive from Grants.gov an automatic notification of receipt that contains a Grants.gov tracking number. (This notification indicates receipt by Grants.gov only, not receipt by the Department.) The Department then will retrieve your application from Grants.gov and send a second notification to you by email. This second notification indicates that the Department has received your application and has assigned your application a PR/Award number (a Department-specified identifying number unique to your application).
• We may request that you provide us original signatures on forms at a later date.
If you are prevented from electronically submitting your application on the application deadline date because of technical problems with the Grants.gov system, we will grant you an extension until 4:30:00 p.m., Washington, DC time, the following business day to enable you to transmit your application electronically or by hand delivery. You also may mail your application by following the mailing instructions described elsewhere in this notice.
If you submit an application after 4:30:00 p.m., Washington, DC time, on the application deadline date, please contact the person listed under
The extensions to which we refer in this section apply only to the unavailability of, or technical problems with, the Grants.gov system. We will not grant you an extension if you failed to fully register to submit your application to Grants.gov before the application deadline date and time or if the technical problem you experienced is unrelated to the Grants.gov system.
• You do not have access to the Internet; or
• You do not have the capacity to upload large documents to the Grants.gov system; and
• No later than two weeks before the application deadline date (14 calendar days or, if the fourteenth calendar day before the application deadline date falls on a Federal holiday, the next business day following the Federal holiday), you mail or fax a written statement to the Department, explaining which of the two grounds for an exception prevents you from using the Internet to submit your application.
If you mail your written statement to the Department, it must be postmarked no later than two weeks before the application deadline date. If you fax your written statement to the Department, we must receive the faxed statement no later than two weeks before the application deadline date.
Address and mail or fax your statement to: Francisco Ramirez, U.S. Department of Education, 400 Maryland Avenue SW., room 3E224, Washington, DC 20202–6200. FAX: (202) 260–8969.
Your paper application must be submitted in accordance with the mail or hand delivery instructions described in this notice.
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If you qualify for an exception to the electronic submission requirement, you
U.S. Department of Education, Application Control Center, Attention: (CFDA Number 84.330B), LBJ Basement Level 1, 400 Maryland Avenue SW., Washington, DC 20202–4260.
You must show proof of mailing consisting of one of the following:
(1) A legibly dated U.S. Postal Service postmark.
(2) A legible mail receipt with the date of mailing stamped by the U.S. Postal Service.
(3) A dated shipping label, invoice, or receipt from a commercial carrier.
(4) Any other proof of mailing acceptable to the Secretary of the U.S. Department of Education.
If you mail your application through the U.S. Postal Service, we do not accept either of the following as proof of mailing:
(1) A private metered postmark.
(2) A mail receipt that is not dated by the U.S. Postal Service.
If your application is postmarked after the application deadline date, we will not consider your application.
The U.S. Postal Service does not uniformly provide a dated postmark. Before relying on this method, you should check with your local post office.
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If you qualify for an exception to the electronic submission requirement, you (or a courier service) may deliver your paper application to the Department by hand. You must deliver the original and two copies of your application by hand, on or before the application deadline date, to the Department at the following address: U.S. Department of Education, Application Control Center, Attention: (CFDA Number 84.330B), 550 12th Street SW., Room 7041, Potomac Center Plaza, Washington, DC 20202–4260. The Application Control Center accepts hand deliveries daily between 8:00 a.m. and 4:30:00 p.m., Washington, DC time, except Saturdays, Sundays, and Federal holidays.
If you mail or hand deliver your application to the Department—
(1) You must indicate on the envelope and—if not provided by the Department—in Item 11 of the SF 424 the CFDA number, including suffix letter, if any, of the competition under which you are submitting your application; and
(2) The Application Control Center will mail to you a notification of receipt of your grant application. If you do not receive this notification within 15 business days from the application deadline date, you should call the U.S. Department of Education Application Control Center at (202) 245–6288.
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For FY 2013, the Department expects to award approximately $28,727,000 in new grants under this program. Based on the anticipated number of applications and other available information, the Department expects this amount to be sufficient to pay all but $10 of the cost of each advanced placement exam taken by low-income students. Accordingly, SEAs may use AP Test Fee program funds to cover a portion of the cost of each approved advanced placement exam taken by low-income students as follows: (a) Up to $45 for each Advanced Placement test administered by the College Board; (b) up to $94 for each Diploma Programme test administered by the International Baccalaureate Organization; and (c) up to $43.50 for each Advanced Subsidiary test and up to $71 for each Advanced test administered by Cambridge International Examinations.
For FY 2013, AP Test Fee program funds may not be used to pay advanced placement test candidate registration fees on behalf of low-income students. Therefore, the candidate registration fees charged by the International Baccalaureate Organization and Cambridge International Examinations are not allowable costs under this program for FY 2013.
Also, in determining whether to approve an application for a new award (including the amount of the award) from an applicant with a current grant under this program, the Department will consider the amount of any carryover funds under the existing grant and the applicant's use of funds under previous AP Test Fee grant awards.
We remind potential applicants that in reviewing applications in any discretionary grant competition, the Secretary may consider, under 34 CFR 75.217(d)(3), the past performance of the applicant in carrying out a previous award, such as the applicant's use of funds, achievement of project objectives, and compliance with grant conditions. The Secretary may also consider whether the applicant failed to submit a timely performance report or submitted a report of unacceptable quality.
In addition, in making a competitive grant award, the Secretary also requires various assurances including those applicable to Federal civil rights laws that prohibit discrimination in programs or activities receiving Federal financial assistance from the Department of Education (34 CFR 100.4, 104.5, 106.4, 108.8, and 110.23).
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If your application is not evaluated or not selected for funding, we notify you.
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We reference the regulations outlining the terms and conditions of an award in the
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(b) At the end of your project period, you must submit a final performance report, including financial information, as directed by the Secretary. The Secretary may also require more frequent performance reports under 34
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Francisco Ramirez, U.S. Department of Education, 400 Maryland Avenue SW., Room 3E224, Washington, DC 20202–6200. Telephone: (202) 260–1541 or by email:
If you use a TDD or a TTY, call the FRS, toll free, at 1–800–877–8339.
You may also access documents of the Department published in the
U.S. Department of Education, Office of Postsecondary Education, National Advisory Committee on Institutional Quality and Integrity.
Announcement of the time and location of the June 6–7, 2013 National Advisory Committee on Institutional Quality and Integrity (NACIQI) meeting.
U.S. Department of Education, Office of Postsecondary Education, 1990 K Street NW., Room 8072, Washington, DC 20006.
• The establishment and enforcement of the criteria for recognition of accrediting agencies or associations under Subpart 2, Part H, Title IV, of the HEA, as amended.
• The recognition of specific accrediting agencies or associations or a specific State approval agency.
• The preparation and publication of the list of nationally recognized accrediting agencies and associations.
• The eligibility and certification process for institutions of higher education under Title IV, of the HEA, together with recommendations for improvement in such process.
• The relationship between (1) accreditation of institutions of higher education and the certification and eligibility of such institutions, and (2) State licensing responsibilities with respect to such institutions.
• Any other advisory function relating to accreditation and institutional eligibility that the Secretary may prescribe.
This meeting notice is an update to the previous notice (Wednesday, February 13, 2013) and sets forth the time and location for the June 6–7, 2013, meeting of the National Advisory Committee on Institutional Quality and Integrity (NACIQI).
Carol Griffiths, Executive Director, NACIQI, U.S. Department of Education, 1990 K Street NW., Room 8073, Washington, DC 20006–8129, telephone: (202) 219–7035, fax: (202) 219–7005, or email:
You may also access documents of the Department published in the
U.S. Department of Energy.
Notice and request for comments.
The Department of Energy (DOE), pursuant to the Paperwork Reduction Act of 1995, intends to extend for three years an information collection request with the Office of Management and Budget (OMB). Comments are invited on: (a) Whether the extended collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall 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 respondents, including through the use of automated collection techniques or other forms of information technology.
Comments regarding this proposed information collection must be received on or before June 3, 2013. If you anticipate difficulty in submitting comments within that period, contact the person listed below as soon as possible.
Written comments may be sent to Sarah Ball at 202–287–1563 or by fax at 202–287–1656 or by email at
Requests for additional information or copies of the information collection instrument and instructions should be directed to Sarah Ball by email at
Information for the Excess Personal Property Furnished to Non-Federal Recipients and the Exchange/Sale Report is collected using GSA's Personal Property Reporting Tool and can be found at the following link:
Information for the Annual Motor Vehicle Fleet Report and the Federal Fleet Report is collected using the Federal Automotive Statistical Tool and can be found at the following link:
This information collection request contains: (1)
○ The burden hours for responding to the Exchange/Sale Report are estimated at 5 hours for each of the 44 estimated respondents, for a total of 220 burden hours.
○ The burden hours for responding to the Excess Personal Property Furnished to Non-Federal Recipients are estimated at 5 hours for each of the 44 estimated respondents, for a total of 220 burden hours.
○ The burden hours for responding to the Annual Motor Vehicle Fleet Report are estimated at 24 hours for each of the 44 estimated respondents, for a total of 1056 burden hours.
○ The burden hours for responding to the Federal Fleet Report are estimated at 24 hours for each of the 44 estimated respondents, for a total of 1056 burden hours.
(A) 41 CFR 102–39.85, (B) 41 CFR 102–36.295 and 102–36.300, (C) OMB Circular A–11 section 25.5, (D) 41 CFR 102–34.335.
Office of Fossil Energy, Department of Energy (DOE).
Notice of orders.
The Office of Fossil Energy (FE) of the Department of Energy gives notice that during December 2012, it issued orders granting authority to import and export natural gas and liquefied natural gas and vacating prior
Take notice that the following hydroelectric application has been filed with the Commission and is available for public inspection.
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Comments, protests, and interventions may be filed electronically via the Internet in lieu of paper; see 18 CFR 385.2001(a)(1)(iii) and the instructions on the Commission's Web site at
The Commission's Rules of Practice and Procedure require all intervenors filing documents with the Commission to serve a copy of that document on each person on the official service list for the project. Further, if an intervenor files comments or documents with the Commission relating to the merits of an issue that may affect the responsibilities of a particular resource agency, they must also serve a copy of the document on that resource agency.
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m. This filing is available for review and reproduction at the Commission in the Public Reference Room, Room 2A, 888 First Street NE., Washington, DC 20426. The filing may also be viewed on the web at
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p. All filings must (1) bear in all capital letters the title “PROTEST,” “MOTION TO INTERVENE,” “COMMENTS,” “REPLY COMMENTS,” “RECOMMENDATIONS,” “TERMS AND CONDITIONS,” or “PRESCRIPTIONS;” (2) set forth in the heading, the name of the applicant and the project number of the application to which the filing responds; (3) furnish the name, address, and telephone number of the person protesting or intervening; and (4) otherwise comply with the requirements of 18 CFR 385.2001 through 385.2005. All comments, recommendations, terms and conditions or prescriptions must set forth their evidentiary basis and otherwise comply with the requirements of 18 CFR 4.34(b). Agencies may obtain copies of the application directly from the applicant. Any of these documents must be filed by providing the original and seven copies to: The Secretary, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426. An additional copy must be sent to Director, Division of Hydropower Administration and Compliance, Office of Energy Projects, Federal Energy Regulatory Commission, at the above address. A copy of any protest or motion to intervene must be served upon each representative of the applicant specified in the particular application. A copy of all other filings in reference to this application must be accompanied by proof of service on all persons listed in the service list prepared by the Commission in this proceeding, in accordance with 18 CFR 4.34(b) and 385.2010.
Take notice that the Commission received the following electric corporate filings:
Take notice that the Commission received the following electric rate filings:
Take notice that the Commission received the following open access transmission tariff 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 on March 15, 2013, Columbia Gas Transmission, LLC (Columbia) 5151 San Felipe, Suite 2500, Houston, Texas 77056, filed in Docket No. CP13–104–000, an application pursuant to sections 157.205, 157.208, and 157.216(b) of the Commission's Regulations under the Natural Gas Act (NGA) as amended, to abandon and construct certain natural gas pipeline facilities in Johnson and Martin Counties, Kentucky, under Columbia's blanket certificate issued in Docket No. CP83–76–000,
Columbia proposes to abandon and replace approximately 6.5 miles of bare, coupled 10-inch diameter pipeline originally constructed in 1912 without cathodic protection on its Line PM–117 in Johnson and Martin Counties, Kentucky. Columbia also proposes to replace the abandoned pipeline with approximately 7.4 miles of new 6-inch diameter coated, cathodically protected, steel pipeline. Columbia states that the reduction in pipeline diameter would have no adverse effect on Columbia's ability to meet its operational and firm commitments on this pipeline. Columbia also states that it would cost approximately $15,400,000 to replace the aging pipe on Line PM–117.
Columbia states that because of the necessary relocation of a significant portion of Line PM–117, Columbia has identified 10 mainline consumer taps that would be abandoned as part of the proposed replacement. Columbia also states that continuity of service to the affected consumers would be maintained by converting them to an alternate energy source.
Any questions concerning this application may be directed to Fredric J. George, Senior Counsel, Columbia Gas Transmission, LLC, P.O. Box 1273, Charleston, West Virginia 25325–1273 or via telephone at (304) 357–2359 or by facsimile (304) 357–3206.
This filing is available for review at the Commission or may be viewed on the Commission's Web site at
Any person or the Commission's staff may, within 60 days after issuance of the instant notice by the Commission, file pursuant to Rule 214 of the Commission's Procedural Rules (18 CFR 385.214) a motion to intervene or notice of intervention and pursuant to Section 157.205 of the regulations under the NGA (18 CFR 157.205), a protest to the request. If no protest is filed within the time allowed therefore, the proposed activity shall be deemed to be authorized effective the day after the time allowed for filing a protest. If a protest is filed and not withdrawn within 30 days after the allowed time for filing a protest, the instant request shall be treated as an application for authorization pursuant to Section 7 of the NGA.
Western Area Power Administration, DOE.
Notice of Final Transmission Service Rates.
The Deputy Secretary of Energy confirmed and approved Rate Order No. WAPA–157 and Rate Schedules INT–FT5 and INT–NFT4, placing firm and nonfirm transmission service rates for the Pacific Northwest-Pacific Southwest Intertie Project (Intertie) of the Western Area Power Administration (Western) into effect on an interim basis. The provisional rates will be in effect until the Federal Energy Regulatory Commission (FERC) confirms, approves, and places them into effect on a final basis, or until they are replaced by other rates. The
Rate Schedules INT–FT5 and INT–NFT4 are effective on the first day of the first full billing period beginning on or after May 1, 2013.
Mr. Jack Murray, Rates Manager, Desert Southwest Customer Service Regional Office, Western Area Power Administration, P.O. Box 6457, Phoenix, AZ 85005–6457, (602) 605–2442, email
The previous Rate Schedules INT–FT4 and INT–NFT3 for Rate Order No. WAPA–130, were approved by FERC for a 5-year period through September 30, 2012.
By Delegation Order No. 00–037.00, effective December 6, 2001, the Secretary of Energy delegated: (1) The authority to develop power and transmission rates to Western's Administrator, (2) the authority to confirm, approve, and place such rates into effect on an interim basis to the Deputy Secretary of Energy, and (3) the authority to confirm, approve, and place into effect on a final basis, to remand, or to disapprove such rates to FERC. Existing Department of Energy procedures for public participation in power rate adjustments (10 CFR part 903) were published on September 18, 1985.
Under Delegation Order Nos. 00–037.00 and 00–001.00D, and in compliance with 10 CFR part 903 and 18 CFR part 300, I hereby confirm, approve, and place Rate Order No. WAPA–157 and the proposed rates for transmission service into effect on an interim basis. The new Rate Schedules INT–FT5 and INT–NFT4 will be submitted promptly to FERC for confirmation and approval on a final basis.
In the matter of: Western Area Power Administration Rate Adjustment for the Pacific Northwest-Pacific Southwest Intertie Project.
These rates were established in accordance with section 302 of the Department of Energy (DOE) Organization Act (42 U.S.C. 7152). This Act transferred to and vested in the Secretary of Energy the power marketing functions of the Secretary of the Department of the Interior and the Bureau of Reclamation under the Reclamation Act of 1902 (ch. 1093, 32 Stat. 388), as amended and supplemented by subsequent laws, particularly section 9(c) of the Reclamation Project Act of 1939 (43 U.S.C. 485h(c)), and other Acts that specifically apply to the project involved.
By Delegation Order No. 00–037.00, effective December 6, 2001, the Secretary of Energy delegated: (1) The authority to develop power and transmission rates to Western's Administrator, (2) the authority to confirm, approve, and place such rates into effect on an interim basis to the Deputy Secretary of Energy, and (3) the authority to confirm, approve, and place into effect on a final basis, to remand, or to disapprove such rates to the Federal Energy Regulatory Commission. Existing DOE procedures for public participation in power rate adjustments (10 CFR part 903) were published on September 18, 1985.
As used in this Rate Order, the following acronyms and definitions apply:
The new provisional rates will take effect on the first day of the first full billing period beginning on or after May 1, 2013, and will remain in effect through April 30, 2018, pending approval by FERC on a final basis.
Western followed the Procedures for Public Participation in Power and Transmission Rate Adjustments and Extensions, 10 CFR part 903, in developing these rates. The steps Western took to involve interested parties in the rate process were:
1. A FRN was published on June 11, 2012, (77 FR 34381) announcing the proposed rates for transmission service, initiating a public consultation and comment period, and setting forth the dates and locations of public information and public comment forums.
2. On June 14, 2012, Western notified all Intertie customers and interested parties of the rate adjustment and provided a copy of the published FRN.
3. On June 28, 2012, Western held a public information forum in Phoenix, Arizona. Western explained the proposed rates and potential changes to the proposed rates, answered questions, and provided rate brochures and presentation handouts.
4. On July 10, 2012, Western held a public comment forum in Phoenix, Arizona, to give the public an opportunity to comment for the record. Four individuals commented at this forum.
5. On August 14, 2012, Western received a data request for information.
6. On August 31, 2012, Western provided the information requested by sending a compact disc containing numerous electronic data files.
7. On September 10, 2012, Western received requests to extend the 90-day consultation and comment period to allow interested parties sufficient time to analyze the information Western distributed on August 31, 2012, and respond accordingly.
8. On September 19, 2012, Western's Acting Administrator extended the consultation and comment period through October 8, 2012.
9. On September 20, 2012, Western notified all Intertie customers and interested parties of the extension and provided a copy of the notice from Western's Acting Administrator.
10. Western received three comment letters during the consultation and comment period. All formally submitted comments have been considered in preparing this Rate Order.
11. Western provided a Web site for information about this rate adjustment process. The Web site is located at
Representatives of the following organizations made oral comments: Arizona Power Authority, Phoenix, Arizona; Arizona Municipal Power Users' Association, Phoenix, Arizona; K.R. Saline & Associates, Mesa, Arizona; and Irrigation & Electrical Districts Association of Arizona, Phoenix, Arizona.
Written comments were received from the following organizations: Arizona Municipal Power Users' Association, Phoenix, Arizona; Griffith Energy LLC, Houston, Texas; and Irrigation & Electrical Districts Association of Arizona, Phoenix, Arizona.
The Intertie was authorized by Section 8 of the Pacific Northwest Power Marketing Act of August 31, 1964 (16 U.S.C. 837g). The basic purpose of the Intertie was to provide, through transmission system interconnections among certain Federal and non-Federal power systems, maximum use of power resources to meet growing demands. This purpose was to be accomplished through the exchange of summer-winter surplus peaking capacity between the northwest and southwest to reduce capital expenditures for new generating capacity; the sale of northwest secondary energy to the southwest; the sale of southwest energy to the northwest to “firm” peaking hydroelectric sources during critical water years; conservation of significant amounts of fuel through the use of surplus hydroelectric energy; and increased efficiency in the operation of hydroelectric and thermal resources. As authorized, the Intertie was to be a cooperative construction venture by Federal and non-Federal entities, incorporating the capability for alternating current (AC) and direct current (DC) transmission service.
The Lower Colorado Region of Reclamation was assigned construction jurisdiction for: (i) The Celilo-Mead 750-kV DC transmission line from the Oregon-Nevada border to Mead Substation; (ii) Mead Substation; and (iii) all facilities south of Mead Substation. Several delays in construction funding for the Celilo-Mead 750-kV DC transmission line revised its estimated in-service date to the point that potential users withdrew their interest. This, and the subsequent lack of congressional funding, resulted in the May 1969 indefinite postponement of the Celilo-Mead 750-kV DC transmission line construction. The only facilities constructed were Mead Substation and all facilities south of Mead Substation, which provide AC transmission service. Pursuant to section 302 of the Department of Energy Organization Act (42 U.S.C. 7152), dated August 4, 1977, these Reclamation constructed facilities were transferred to Western.
Western's Desert Southwest Region administers these facilities as a stand-alone transmission project for operational, financial, and repayment purposes. The transmission facilities consist of a 256-mile, 500-kV transmission line from Mead Substation (Nevada) to Perkins Substation (Arizona); a 202-mile, 500-kV transmission line from Mead Substation to Adelanto Switching Substation (California); a 238-mile, 345-kV transmission line from Mead Substation to Liberty Substation (Arizona); a 19-mile, 230-kV transmission line from Liberty Substation to Westwing Substation (Arizona); and a 22-mile, 230-kV transmission line from Westwing Substation to Pinnacle Peak Substation (Arizona).
The existing rates for point-to-point transmission service consist of a firm rate and a nonfirm rate. The current rate for firm point-to-point transmission service under Rate Schedule INT–FT4 is $15.24/kW-year. The current rate for nonfirm point-to-point transmission service under Rate Schedule INT–NFT3 is 1.74 mills/kWh. The existing rates under Rate Schedules INT–FT4 and INT–NFT3 expire September 30, 2013.
The provisional rates will supersede the existing rates and become effective on an interim basis on the first day of the first full billing period beginning on or after May 1, 2013. The provisional rate for firm point-to-point transmission service under Rate Schedule INT–FT5 is $19.32/kW-year. The provisional rate for nonfirm point-to-point transmission service under Rate Schedule INT–NFT4 is 2.21 mills/kWh. The provisional rates will result in a rate increase of approximately 27 percent when compared to the existing rates. A comparison of the existing and provisional rates for transmission service follows:
Western's Acting Administrator certified that the provisional rates for transmission service under Rate Schedules INT–FT5 and INT–NFT4 are the lowest possible rates consistent with sound business principles. The provisional rates were developed following administrative policies and applicable laws.
According to Reclamation Law, Western must establish rates sufficient to recover annual O&M, purchase power, transmission service and other costs, interest expense, and repay investments. Western prepares a PRS each fiscal year to determine if the existing rates will provide adequate revenues to repay all power system costs within the required time. Repayment criteria are based on existing law and applicable policies, including DOE Order RA 6120.2. To meet the cost recovery criteria outlined in DOE Order RA 6120.2, a PRS using the provisional rates has been developed to demonstrate that sufficient revenues will be available to meet future obligations.
The existing rates are insufficient and do not provide adequate revenues to cover costs. The revenue deficiency is a result of lower-than-projected sales of transmission service. The existing rates were based on projected sales of 500-kV transmission service increasing each year during the 5-year cost evaluation period. The actual demand for transmission capacity was significantly less than expected and the projected sales did not materialize. As a result, the revenue derived from the sales of 500-kV transmission service over the 5-year cost evaluation period has been considerably lower than planned. The provisional rates include a notable reduction in the sales forecast for 500-kV transmission service over the next 5-year cost evaluation period, which is the primary factor that led to the rate increase.
A secondary factor of the rate increase is that when the existing rates were established, purchase power was handled separately for each power system and the Intertie, being a stand-alone transmission project, had no purchase power costs to recover. Since then, Western's BA for the Desert Southwest Region has initiated power purchases for reliability purposes and the associated costs are allocated to all of the applicable transmission projects within the BA, including the Intertie. These annual purchase power costs are subject to recovery and have been included in the provisional rates.
Another factor impacting the rate increase is the requirement to pay off maturing debt associated with the original project. In 1970, a major element of the original project was placed into commercial service, which initiated the repayment cycle. This debt of $28.4 million must be paid by 2020, which is the last year this investment is allowed to remain unpaid. Principal payments for this debt have been included in the provisional rates.
The following table provides a summary of projected revenue and expense data for the provisional rates through the 5-year approval period.
The comments and responses regarding the proposed rates, paraphrased for brevity when not affecting the meaning of the statement(s), are discussed below. Direct quotes from comment letters are used for clarification where necessary.
All brochures, studies, comments, letters, memorandums, and other documents that Western used to develop the provisional rates are available for inspection and copying at the Desert Southwest Customer Service Regional Office, Western Area Power Administration, 615 South 43rd Avenue, Phoenix, AZ 85009–5313. Many of these documents and supporting information are available on Western's Web site at
In compliance with the NEPA of 1969 (42 U.S.C. 4321,
Western has an exemption from centralized regulatory review under Executive Order 12866; accordingly, no clearance of this notice by the Office of Management and Budget is required.
The provisional interim rates herein confirmed, approved, and placed into effect, together with supporting documents, will be submitted to FERC for confirmation and final approval.
In view of the foregoing and under the authority delegated to me, I confirm and approve on an interim basis, effective May 1, 2013, Rate Schedules INT–FT5 and INT–NFT4 for the Pacific Northwest-Pacific Southwest Intertie Project of the Western Area Power Administration. The rate schedules shall remain in effect on an interim basis pending FERC's confirmation and approval of them or substitute rates on a final basis through April 30, 2018.
Discounts may be offered from time-to-time in accordance with Western's Open Access Transmission Tariff (OATT).
The charge for unreserved use is two times the maximum allowable rate for the service at issue, assessed as follows: The penalty for a single hour of unreserved use is based on the daily short-term rate. The penalty for more than one assessment of unreserved use for any given duration (e.g., daily) increases to next longest duration (e.g., weekly). The penalty for multiple instances of unreserved use (e.g., more than one hour) within a day is based on the daily short-term rate. The penalty for multiple instances of unreserved use isolated to one calendar week is based on the weekly short-term rate. The penalty for multiple instances of unreserved use during more than one week in a calendar month is based on the monthly short-term rate.
A customer that exceeds its reserved capacity at any point of receipt or point of delivery, or a customer that uses transmission service at a point of receipt or point of delivery that it has not reserved, is required to pay for all ancillary services that were provided by the Western Area Lower Colorado (WALC) Balancing Authority and associated with the unreserved use. The customer will pay for ancillary services based on the amount of transmission service used and not reserved.
The charge for unreserved use is two times the maximum allowable rate for the service at issue, assessed as follows: The penalty for a single hour of unreserved use is based on the daily short-term rate. The penalty for more than one assessment of unreserved use for any given duration (e.g., daily) increases to next longest duration (e.g., weekly). The penalty for multiple instances of unreserved use (e.g., more than one hour) within a day is based on the daily short-term rate. The penalty for multiple instances of unreserved use isolated to one calendar week is based on the weekly short-term rate. The penalty for multiple instances of unreserved use during more than one week in a calendar month is based on the monthly short-term rate.
A customer that exceeds its reserved capacity at any point of receipt or point of delivery, or a customer that uses transmission service at a point of receipt or point of delivery that it has not reserved, is required to pay for all ancillary services that were provided by the Western Area Lower Colorado (WALC) Balancing Authority and associated with the unreserved use. The customer will pay for ancillary services based on the amount of transmission service used and not reserved.
Environmental Protection Agency (EPA).
Notice.
There will be a 4-day meeting of the Federal Insecticide, Fungicide, and Rodenticide Act Scientific Advisory Panel (FIFRA SAP) to consider and review proposed Endocrine Disruptor Screening Program (EDSP) Tier 2 Ecotoxicity Tests.
The meeting will be held on June 25–28, 2013, from 9 a.m. to approximately 5:30 p.m.
The meeting will be held at the Environmental Protection Agency, Conference Center, Lobby Level, One Potomac Yard (South Bldg.), 2777 S. Crystal Dr., Arlington, VA 22202.
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Additional instructions on commenting or visiting the docket, along with more information about dockets generally, is available at
If your comments contain any information that you consider to be CBI or otherwise protected, please contact the DFO listed under
Sharlene Matten, DFO, Office of Science Coordination and Policy (7201M), Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460–0001; telephone number: (202) 564–0130; fax number: (202) 564–8382; email address:
This action is directed to the public in general. This action may, however, be of interest to persons who are or may be required to conduct testing of chemical substances under the Federal Food, Drug, and Cosmetic Act (FFDCA) and FIFRA. Since other entities may also be interested, the Agency has not attempted to describe all the specific entities that may be affected by this action.
When submitting comments, remember to:
1. Identify the document by docket ID number and other identifying information (subject heading,
2. Follow directions. The Agency may ask you to respond to specific questions or organize comments by referencing a Code of Federal Regulations (CFR) part or section number.
3. Explain why you agree or disagree; suggest alternatives and substitute language for your requested changes.
4. Describe any assumptions and provide any technical information and/or data that you used.
5. If you estimate potential costs or burdens, explain how you arrived at your estimate in sufficient detail to allow for it to be reproduced.
6. Provide specific examples to illustrate your concerns and suggest alternatives.
7. Explain your views as clearly as possible, avoiding the use of profanity or personal threats.
8. Make sure to submit your comments by the comment period deadline identified.
You may participate in this meeting by following the instructions in this unit. To ensure proper receipt by EPA, it is imperative that you identify docket ID number EPA–HQ–OPP–2013–0182 in the subject line on the first page of your request.
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• Ecotoxicology (fish, avian, and/or amphibian toxicology);
• Comparative Endocrinology and Endocrine Toxicology;
• Histopathology;
• Biostatistics;
• Population Modeling;
• Regulatory toxicology/risk assessment;
• Invertebrate Toxicology and Endocrinology;
• Reproductive physiology;
• Developmental biology/toxicology;
• Thyroid physiology;
• Toxicological pathology;
• Morphometrics;
• Quantitative ecology/biostatistics; and
• Systems biology.
The selection of scientists to serve on FIFRA SAP is based on the function of the panel and the expertise needed to address the Agency's charge to the panel. No interested scientists shall be ineligible to serve by reason of their membership on any other advisory committee to a Federal department or agency or their employment by a Federal department or agency except the EPA. Other factors considered during the selection process include availability of the potential panel member to fully participate in the panel's reviews, absence of any conflicts of interest or appearance of lack of impartiality, independence with respect to the matters under review, and lack of bias. Although financial conflicts of interest, the appearance of lack of impartiality, lack of independence, and bias may result in disqualification, the absence of such concerns does not assure that a candidate will be selected to serve on FIFRA SAP. Numerous qualified candidates are identified for each panel. Therefore, selection decisions involve carefully weighing a number of factors including the candidates' areas of expertise and professional qualifications and achieving an overall balance of different scientific perspectives on the panel. In order to have the collective breadth of experience needed to address the Agency's charge for this meeting, the Agency anticipates selecting approximately 12–15 ad hoc scientists.
FIFRA SAP members are subject to the provisions of 5 CFR part 2634, Executive Branch Financial Disclosure, as supplemented by the EPA in 5 CFR part 6401. In anticipation of this requirement, prospective candidates for service on the FIFRA SAP will be asked to submit confidential financial information which shall fully disclose, among other financial interests, the candidate's employment, stocks and bonds, and where applicable, sources of research support. The EPA will evaluate the candidates financial disclosure form to assess whether there are financial conflicts of interest, appearance of a lack of impartiality or any prior involvement with the development of the documents under consideration (including previous scientific peer review) before the candidate is considered further for service on FIFRA SAP. Those who are selected from the pool of prospective candidates will be asked to attend the public meetings and to participate in the discussion of key issues and assumptions at these meetings. In addition, they will be asked to review and to help finalize the meeting minutes. The list of FIFRA SAP members participating at this meeting will be posted on the FIFRA SAP Web site at
FIFRA SAP serves as the primary scientific peer review mechanism of EPA's Office of Chemical Safety and Pollution Prevention (OCSPP) and is structured to provide scientific advice, information and recommendations to the EPA Administrator on pesticides and pesticide-related issues as to the impact of regulatory actions on health and the environment. FIFRA SAP is a Federal advisory committee established in 1975 under FIFRA that operates in accordance with requirements of the Federal Advisory Committee Act. FIFRA SAP is composed of a permanent panel consisting of seven members who are appointed by the EPA Administrator from nominees provided by the National Institutes of Health and the National Science Foundation. FIFRA established a Science Review Board consisting of at least 60 scientists who are available to the SAP on an ad hoc basis to assist in reviews conducted by the SAP. As a peer review mechanism, FIFRA SAP provides comments, evaluations and recommendations to improve the effectiveness and quality of analyses made by Agency scientists. Members of FIFRA SAP are scientists who have sufficient professional qualifications, including training and experience, to provide expert advice and recommendation to the Agency.
Section 408(p) of the Federal Food Drug and Cosmetic Act (FFDCA) requires the EPA to:
Subsequent to passage of the Food Quality Protection Act in 1996, which amended FFDCA and FIFRA, and amendments to the Safe Drinking Water Act the same year, the EPA formed the Endocrine Disruptor Screening and Testing Advisory Committee (EDSTAC), a Federal advisory committee of scientists and stakeholders that was charged by the EPA to provide recommendations on how to implement its EDSP. The EDSP is described in detail at the following Web site:
The EDSTAC also recommended the Agency adopt a two-tiered screening and testing program. Tier 1 is an integrated battery of relatively short-term
The EDSP is mandated under FFDCA to use “validated” assays to screen and test for endocrine disrupting chemicals. The focus of this SAP review is on the validation status, based on Organization for Economic Co-Operation and Development (OECD) and Interagency Coordinating Committee on the Validation of Alternative Methods (ICCVAM) validation principles, for the proposed EDSP Tier 2 ecotoxicity tests including:
1. Japanese quail two-generation toxicity test.
2. Larval amphibian growth and development assay.
3. Medaka multigeneration test.
4. Mysid two-generation toxicity test.
The EDSP Tier 2 ecotoxicity tests have been developed and validated based on selected chemicals known to interact with the estrogen, androgen and/or thyroid hormonal pathways of the endocrine system. In general, the performance of respective Tier 2 ecotoxicity tests to determine the magnitude and duration of endocrine mediated effects and quantitatively assess concentration-response relationships will be the focus of this SAP. The SAP will be asked to comment on the reproducibility of results and factors that may impact interpretation of whether or not the proposed Tier 2 tests are sufficient to provide a more comprehensive assessment of the potential of a test chemical to cause endocrine mediated adverse effects in the subject taxa.
EPA's background paper, related supporting materials, charge/questions to FIFRA SAP, FIFRA SAP composition (i.e., members and ad hoc members for this meeting), and the meeting agenda will be available approximately 15 days prior to the meeting. In addition, the Agency may provide additional background documents as the materials become available. You may obtain electronic copies of these documents, and certain other related documents that might be available electronically, at
FIFRA SAP will prepare meeting minutes summarizing its recommendations to the Agency approximately 90 days after the meeting. The meeting minutes will be posted on the FIFRA SAP Web site or may be obtained from the OPP Docket or at
Environmental protection, Pesticides and pests.
Farm Credit Administration.
Notice is hereby given, pursuant to the Government in the Sunshine Act, of the regular meeting of the Farm Credit Administration Board (Board).
The regular meeting of the Board will be held at the offices of the Farm Credit Administration in McLean, Virginia, on April 11, 2013, from 9:00 a.m. until such time as the Board concludes its business.
Dale L. Aultman, Secretary to the Farm Credit Administration Board, (703) 883–4009, TTY (703) 883–4056.
Farm Credit Administration, 1501 Farm Credit Drive, McLean, Virginia 22102–5090.
Parts of this meeting of the Board will be open to the public (limited space available) and parts will be closed to the public. In order to increase the accessibility to Board meetings, persons requiring assistance should make arrangements in advance. The matters to be considered at the meeting are:
• March 14, 2013.
• Adjusting Civil Money Penalties for Inflation—Final Rule.
• Quarterly Report on Farm Credit System Condition.
• FCS Building Association Auditor's Report on 2012 Financial Audit.
• Meeting with Auditors.
• Office of Examination Supervisory and Oversight Activities Report
The notificants listed below have applied under the Change in Bank Control Act (12 U.S.C. 1817(j)) and § 225.41 of the Board's Regulation Y (12 CFR 225.41) to acquire shares of a bank or bank holding company. The factors that are considered in acting on the notices are set forth in paragraph 7 of the Act (12 U.S.C. 1817(j)(7)).
The notices are available for immediate inspection at the Federal Reserve Bank indicated. The notices also will be available for inspection at the offices of the Board of Governors. Interested persons may express their views in writing to the Reserve Bank indicated for that notice or to the offices of the Board of Governors. Comments must be received not later than April 16, 2013.
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 Kansas City (Dennis Denney, Assistant Vice President) 1 Memorial Drive, Kansas City, Missouri 64198–0001:
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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.
A. Federal Reserve Bank of Kansas City (Dennis Denney, Assistant Vice President) 1 Memorial Drive, Kansas City, Missouri 64198–0001:
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Office of the Secretary, HHS.
Notice.
In compliance with section 3507(a)(1)(D) of the Paperwork Reduction Act of 1995, the Office of the Secretary (OS), Department of Health and Human Services, has submitted an Information Collection Request (ICR), described below, to the Office of Management and Budget (OMB). The ICR is for a new collection. Comments submitted during the first public review of this ICR will be provided to OMB. OMB will accept further comments from the public on this ICR during the review and approval period.
Comments on the ICR must be received on or before May 2, 2013.
Submit your comments to
Information Collection Clearance staff,
When submitting comments or requesting information, please include the document identifier HHS–OS–18521–30D for reference.
Department of Health and Human Services, Office of the Secretary, Office of the Assistant Secretary for Health.
Notice.
As stipulated by the Federal Advisory Committee Act, the U.S. Department of Health and Human Service (DHHS) is hereby giving notice that the Presidential Advisory Council on HIV/AIDS (PACHA) will hold a meeting to discuss implementation of the Patient Protection and Affordable Care Act. The meeting will be open to the public.
The meeting will be held April 22, 2013, from 9:00 a.m. to approximately 5:30 p.m. (EDT).
U.S. Department of Health and Human Services, 200 Independence Avenue SW., Washington, DC 20201 in the Auditorium.
Ms. Caroline Talev, Public Health Assistant, Presidential Advisory Council on HIV/AIDS, Department of Health and Human Services, 200 Independence Avenue SW., Room 443H, Washington, DC 20201; (202) 205–1178. More detailed information about PACHA can be obtained by accessing the Council's Web site
PACHA was established by Executive Order 12963, dated June 14, 1995 as amended by Executive Order 13009, dated June 14, 1996. The Council was established to provide advice, information, and recommendations to the Secretary regarding programs and policies intended to promote effective prevention of HIV disease and AIDS. The functions of the Council are solely advisory in nature.
The Council consists of not more than 25 members. Council members are selected from prominent community leaders with particular expertise in, or knowledge of, matters concerning HIV and AIDS, public health, global health, philanthropy, marketing or business, as well as other national leaders held in high esteem from other sectors of society. Council members are appointed by the Secretary or designee, in consultation with the White House Office on National AIDS Policy. The agenda for the upcoming meeting will be posted on the Council's Web site at
Public attendance at the meeting is limited to space available. Individuals who plan to attend and need special assistance, such as sign language interpretation or other reasonable accommodations, should notify the designated contact person. Pre-registration for public attendance is advisable and can be accomplished by contacting Caroline Talev at
Office on Women's Health, Office of the Assistant Secretary for Health, Office of the Secretary, Department of Health and Human Services.
Notice.
The Department of Health and Human Services (HHS), Office on Women's Health (OWH) invites public and private-sector health-related organizations to participate in National Women's Health Week (NWHW) as partners to help create awareness of women's health issues and educate women about improving their health and preventing disease.
Representatives of women's health organizations should submit expressions of interest no later than April 18, 2013.
Expressions of interest, comments, and questions may be submitted by electronic mail to
Henrietta Terry on (202) 205–1952.
The OWH was established in 1991 to improve the
NWHW is a week-long health observance that kicks off on Mother's Day, Sunday, May 12 and ends Saturday, May 18, 2013. NWHW seeks to educate women about improving their physical and mental health and preventing disease. More than 2,200 events were held nationwide in 2012. Week-long, daily messages encourage women to make their health a top priority and take simple steps for a longer, healthier, and happier life. For more information about NWHW, please visit
Part C (Centers for Disease Control and Prevention) of the Statement of Organization, Functions, and Delegations of Authority of the Department of Health and Human Services (45 FR 67772–76, dated October 14, 1980, and corrected at 45 FR 69296, October 20, 1980, as amended most recently at 78 FR 5812, dated January 28, 2013) is amended to reflect the reorganization of the Office for State, Tribal, Local, and Territorial Support.
Section C–B, Organization and Functions, is hereby amended as follows:
Delete in its entirety the title and function statements for the Knowledge Management Office (CQA5), Office of the Director (CQA).
Revise the functional statement for the Public Health Law Office (CQA2), Office of the Director (CQA) as follows:
After item (8), insert the following: (9) establish collaboration and coordination between clinical medicine and public health to better coordinate and partner for healthier communities.
Part C (Centers for Disease Control and Prevention) of the Statement of Organization, Functions, and Delegations of Authority of the Department of Health and Human Services (45 FR 67772–76, dated October 14, 1980, and corrected at 45 FR 69296, October 20, 1980, as amended most recently at 78 FR 5812, dated January 28, 2013) is amended to reflect the reorganization of the Office of the Associate Director for Science, Office of the Director, Centers for Disease Control and Prevention.
Section C–B, Organization and Functions, is hereby amended as follows:
Delete in its entirety the title and function statements for the Public Health Prevention Service Branch (CPLCC), Division of Leadership and Practice (CPLP).
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration's (FDA) Center for Devices and Radiological Health (CDRH or Center) is announcing an invitation for participation in its Experiential Learning Program (ELP). The ELP provides a formal training mechanism for regulatory review staff to visit research, clinical, manufacturing, and health care facilities to observe firsthand how medical devices are designed, developed, and utilized. This training is intended to provide CDRH staff with an opportunity to observe the device development life cycle and provide a better understanding of the medical devices they review, and the challenges faced throughout development, testing, manufacturing, and clinical use. The purpose of this document is to invite medical device and health care facilities to participate in this formal training program for FDA's medical device review staff, or to contact CDRH for more information regarding the program.
Submit either an electronic or written request for participation in this program by May 2, 2013. The request should include a description of your facility relative to product areas CDRH regulates. Please include the Area of Interest/Medical Device or Technology (identified in table 1or 2) that the visit will demonstrate to CDRH staff.
Submit either electronic requests to
Latonya Powell, Center for Devices and Radiological Health, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 66, Rm. 4448, Silver Spring, MD 20993–0002, 301–796–6965, FAX: 301–827–3079,
CDRH launched the ELP Pilot in 2012 and will fully implement the program in 2013. The Center is responsible for ensuring the safety and effectiveness of medical devices marketed in the United States. Furthermore, CDRH assures that patients and providers have timely and continued access to safe, effective, high-quality medical devices and safe radiation-emitting products. In support of this mission, the Center launched various training and development initiatives to enhance performance of its regulatory review staff and other staff involved in the premarket review process. CDRH is driven to advance regulatory science; provide industry with predictable, consistent, transparent, and efficient regulatory pathways; and assure consumer
These formal training visits are not a mechanism for FDA to inspect, assess, judge, or perform a regulatory function (i.e., compliance inspection), but rather, are an opportunity to provide the CDRH review staff a better understanding of the products they review. Through this notice, CDRH is formally requesting participation from companies, academia, and clinical facilities. This request includes those that have previously participated in the ELP or other FDA Site Visit programs, as well as new interested parties.
In this program, groups of CDRH staff will observe operations of medical device establishments, including, research, manufacturing, academia, and health care facilities. The areas of focus and specific areas of interest for visits may include the following:
CDRH will be responsible for all travel expenses associated with the site visits. Therefore, selection of potential facilities will be based on the coordination of CDRH's priorities for staff training and the resources available for this program. In addition to logistical and other resource factors, all sites must have a successful compliance record with FDA or another Agency with which FDA has a memorandum of understanding. If a site visit involves a visit to a separate physical location of another firm under contract to the applicant, that firm must agree to participate in the program and must also have a satisfactory compliance history.
Identify requests for participation with the docket number found in the brackets in the heading of this document. Received requests are available for public examination in the Division of Dockets Management (see
Food and Drug Administration, HHS.
Notice; establishment of docket; request for data, information, and comments.
The Food and Drug Administration (FDA) is establishing a public docket for interested parties to submit to FDA comments on the Institute of Medicine's (IOM) recommendation regarding third-party governance of industry-sponsored tobacco product research.
Submit electronic or written comments by September 30, 2013.
You may submit comments, identified by Docket No. FDA–2013–N–0305, by any of the following methods:
Submit electronic comments in the following way:
•
Submit written submissions in the following ways:
•
Laila Noory, Center for Tobacco Products, Food and Drug Administration, 9200 Corporate Blvd., Rockville, MD 20850, 1–877–287–1373 (choose Option 4), FAX: 240–276–3761, email:
On June 22, 2009, President Obama signed into law the Family Smoking Prevention and Tobacco Control Act (Pub. L. 111–31) (Tobacco Control Act). The Tobacco Control Act amends the Federal Food, Drug, and Cosmetic Act (the FD&C Act) by adding chapter IX (21 U.S.C. 387
FDA expects that tobacco product manufacturers will undertake tobacco product research as part of activities regulated under the Tobacco Control Act, including submission of applications for marketing orders under sections 910 and 911 of the FD&C Act. Section 911 of the FD&C Act requires FDA to issue regulations or guidance (or any combination thereof) on the scientific evidence required for assessment and ongoing review of modified risk tobacco products (MRTPs). Section 911(
Specifically, the IOM report states “[t]here is profound distrust of the tobacco industry and of research supported by the tobacco industry. This distrust is the direct result of the tobacco industry's history of improperly influencing or manipulating scientific findings and messaging about the health
As a result of these findings, the IOM recommends in its report that “MRTP sponsors should consider use of independent third parties to undertake one or more key functions, including the design and conduct of research, the oversight of specific studies, and the distribution of sponsor funds for research. Such independent third parties should be approved by the FDA in advance of the research.”
The IOM report focuses on research to support MRTP applications, but FDA is also interested in information on third-party governance as it relates more generally to industry-sponsored tobacco research. FDA is interested in receiving information on whether some form of third-party governance should be considered for other types of industry-sponsored tobacco product research, including research to support premarket tobacco product applications and other submissions to FDA, as well as research designed to contribute to general knowledge regarding tobacco products.
As FDA considers how and whether to implement third-party governance of industry-sponsored tobacco product research, we are requesting comments on the IOM's recommendation. We encourage you to submit any available research or evidence to support your comments. FDA specifically requests comments on:
1. What are some potential models of third-party governance of industry-sponsored tobacco product research? What are the strengths and weaknesses of these models?
2. What criteria could FDA use to evaluate any potential model of third-party governance of industry-sponsored tobacco product research?
3. What role would various interested parties (e.g., individual researchers, academic institutions, for-profit and not-for-profit research organizations) play in a third-party governance model of tobacco product research?
4. Who would participate in a third-party governance model? How could a governance model be structured to reduce conflict of interest and bias in industry-sponsored tobacco product research?
5. What barriers, if any, would have to be overcome to encourage the broader scientific community to participate in a third-party governance model?
6. Are there unique research challenges faced by small manufacturers and how should they be addressed in a third-party governance model?
7. What kinds of tobacco product research could be subject to third-party governance? For example, could it be applied to:
• Product testing?
• Nonclinical studies?
• Studies in human subjects? (e.g., health effects research, behavioral research, abuse liability studies, consumer perception research)
• Computational modeling?
• Postmarket surveillance?
8. What aspects of tobacco product research could be subject to third-party governance? For example, should both the design and conduct of research studies be subject to third-party governance?
9. Are there governance models or other steps FDA can take that are more effective for overseeing research to produce generalizable knowledge, such as establishing better testing/research methods and standards, compared to specific product research?
Interested persons may submit either electronic comments regarding this document to
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA) is announcing the availability of the guidance entitled “User Fees and Refunds for Premarket Approval Applications (PMAs) and Device Biologics License Applications (BLAs).” The purpose of this guidance document is to identify the types of PMAs and BLAs subject to device user fees, including supplements and other submissions, as well as those that do not have an associated user fee. The guidance also identifies industry and FDA actions on these submissions that may result in a refund of the fee. The draft of this document was issued on March 16, 2009.
Submit either electronic or written comments on this guidance at any time. General comments on agency guidance documents are welcome at any time.
Submit written requests for single copies of the guidance document entitled “User Fees and Refunds for Premarket Approval Applications and Device Biologics License Applications” to the Division of Small Manufacturers, International, and Consumer Assistance, Center for Devices and Radiological Health, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 66, Rm. 4613, Silver Spring, MD 20993–0002 or Office of Communication, Outreach and Development (HFM–40), Center for Biologics Evaluation and Research (CBER), Food and Drug Administration, 1401 Rockville Pike, Rockville, MD 20852–1448. Send one self-addressed adhesive label to assist that office in processing your request, or fax your request to 301–847–8149. See the
Submit electronic comments on the guidance to
Nicole Wolanski, Center for Devices and Radiological Health, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 66, Rm. 1650, Silver Spring, MD 20993–0002, 301–796–6570; or Stephen Ripley, Center for Biologics Evaluation and Research (HFM–17), Food and Drug Administration, 1401 Rockville Pike, Suite 200N, Rockville, MD 20852, 301–827–6210.
The Medical Device User Fee Amendments of 2012 (MDUFA III), amended the Federal Food, Drug, and Cosmetic Act (the FD&C Act) to authorize FDA to collect user fees for the review of certain premarket submissions received on or after October 1, 2012, including PMAs and device BLAs. The additional funds obtained from user fees will enable FDA, with the cooperation of industry, to improve the medical device review process to meet certain performance goals and implement improvements for the medical device review process.
This guidance is being issued consistent with FDA's good guidance practices regulation (21 CFR 10.115). The guidance represents the agency's current thinking on user fees and refunds for PMAs and device BLAs. It does not create or confer any rights for or on any person and does not operate to bind FDA or the public. An alternative approach may be used if such approach satisfies the requirements of the applicable statute and regulations.
Persons interested in obtaining a copy of the guidance may do so by using the Internet. A search capability for all Center for Devices and Radiological Health guidance documents is available at
This draft guidance refers to previously approved collections of information found in FDA regulations. These collections of information are subject to review by the Office of Management and Budget (OMB) under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501–3520). The collections of information in 21 CFR part 814 have been approved under OMB control number 0910–0231.
Interested persons may submit either electronic comments regarding this document to
Food and Drug Administration, HHS.
Notice; extension of comment period.
The Food and Drug Administration (FDA) is extending the comment period for the notice entitled “Implementation of the FDA Food Safety Modernization Act Provision Requiring FDA To Establish Pilot Projects and Submit a Report to Congress for the Improvement of Tracking and Tracing of Food” that appeared in the
Submit either electronic or written comments by July 3, 2013.
You may submit comments and information, identified by Docket No. FDA–2012–N–1153, by any of the following methods:
Submit electronic comments and information in the following way:
•
Submit written submissions in the following way:
•
Sherri A. McGarry, Office of Foods, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 1, Rm. 1212, Silver Spring, MD 20903, 301–796–3851.
In the
The Agency has received requests for a 120-day extension of the comment period for the notice. Each request conveyed concern that the current 30-day comment period does not allow sufficient time to develop a meaningful or thoughtful response to the notice.
FDA has considered the requests and is extending the comment period for all interested persons for 90 days, until July 3, 2013. The Agency believes that a 90-day extension allows adequate time for interested persons to submit comments.
Interested persons may submit either electronic comments regarding this document to
Food and Drug Administration, HHS.
Notice of public meeting; request for comments.
The Food and Drug Administration (FDA) is announcing a public meeting entitled “International Consortium of Cardiovascular Registries.” The purpose of this meeting is to discuss the development of an international consortium of cardiovascular registries with a broad array of interested stakeholders. The initial pilot phase of this effort will be developing relationships and analysis strategies for transcatheter cardiac valve registries, with the understanding that these efforts would be expanded to additional cardiovascular devices in the future.
To register for the public meeting, please visit FDA's Medical Devices News & Events—Workshops & Conferences calendar at
If you need special accommodations due to a disability, please contact Susan Monahan (
Regardless of attendance at the public meeting, interested persons may submit either electronic comments regarding this document to
Cardiovascular procedures are performed in hundreds of thousands of patients every year to treat all manner of cardiovascular disease from coronary artery disease to peripheral vascular disease, intracardiac ablation to surgical interventions, implant of stents to implants of pacemakers, defibrillators, and their associated leads. Information obtained from clinical trials is often limited due to small size, short followup, and lack of generalizability. Observational studies and registries have become increasingly important data sources for assessing the performance of cardiovascular therapeutic medical devices in the real-world setting. However, these registries are often limited in scope and size to a specific country, region, or health care provider system.
Developing a comprehensive understanding of the performance of these devices requires not only an indepth analysis across data sources to link device use to clinical outcomes, but also to incorporate data from international experience with these devices and procedures. FDA is holding this workshop to discuss the development of an international consortium of cardiovascular registries that would allow for broad-based analysis and surveillance of medical device exposure and related clinical outcomes. This effort follows on the successful model of the International Consortium of Orthopedic Registries (ICOR), which has developed a framework for distributed analysis across their member registries around the world. The development of a similar consortium of cardiovascular registries will begin with a narrowed scope incorporating transcatheter valve therapy devices and procedures.
At the end of this workshop, FDA intends that the participants and stakeholders will develop a comprehensive plan for the development of an operational international consortium of cardiovascular registries. This plan will identify specific issues that must be addressed and provide a “roadmap” for full implementation.
Topics to be discussed at this meeting include:
• The role of registry consortia in postmarket surveillance,
• Goals of the International Consortium of Cardiovascular Registries,
• Lessons learned from the development of the ICOR,
• Development of an international consortium of transcatheter valve registries as a pilot phase,
• Analysis of near- and long-term outcomes reported through registries, and
• Discussion of capabilities, challenges, and limitations of existing transcatheter valve registries.
Food and Drug Administration, HHS.
Notice; correction.
The Food and Drug Administration (FDA) is correcting a notice that appeared in the
Sara J. Anderson, Center for Devices and Radiological Health, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 66, Rm. 1611, Silver Spring, MD 20993–0002,
In FR doc. 2013–04543, appearing on page 13347 in the
1. On page 13347, in the first column, under the section entitled “Date and Time”, the date is corrected to be April 25, 2013.
2. On page 13347, in the second column, the section entitled “Agenda” is corrected to read as follows:
The committee will also discuss and make recommendations on the appropriate regulatory classification for diagnostic devices known as phencyclidine (PCP) enzyme immunoassays and PCP radioimmunoassays. PCP enzyme immunoassays and PCP radioimmunoassays are considered pre-Amendment devices since they were in commercial distribution prior to May 28, 1976 when the Medical Device Amendments became effective. PCP enzyme immunoassays are currently regulated under the heading of “Enzyme Immunoassay, Phencyclidine,” Product Code LCM, and “Radioimmunoassay, Phencyclidine,” Product Code LCL, as unclassified under the 510(k) premarket notification authority. FDA is seeking panel input on the safety and effectiveness of PCP enzyme immunoassays and PCP radioimmunoassays.
The committee will also discuss and make recommendations on the appropriate regulatory classification for diagnostic devices known as isoniazid test strips. Isoniazid test strips are considered pre-Amendment devices since they were in commercial distribution prior to May 28, 1976 when the Medical Device Amendments became effective. Isoniazid test strips are currently regulated under the heading of “Strip, Test Isoniazid,” Product Code MIG, as unclassified under the 510(k) premarket notification authority. Isoniazid test strips are a qualitative assay used for detecting isonicotinic acid and its metabolites in
FDA intends to make background material available to the public no later than 2 business days before the meeting. If FDA is unable to post the background material on its Web site prior to the meeting, the background material will be made publicly available at the location of the advisory committee meeting, and the background material will be posted on FDA's Web site after the meeting. Background material is available at
3. On page 13347, in the third column, the section entitled “Procedure” is corrected to read as follows:
Interested persons may present data, information, or views, orally or in writing, on issues pending before the committee. Written submissions may be made to the contact person on or before April 16, 2013. On April 25, 2013, oral presentations from the public regarding Methotrexate Test Systems will be scheduled between approximately 9:15 a.m. and 9:45 a.m.; regarding phencyclidine (PCP) Test Systems between approximately 1:55 p.m. and 2:25 p.m.; and regarding Isoniazid Test Systems between approximately 4:15 p.m. and 4:45 p.m. Those individuals interested in making formal oral presentations should notify the contact person and submit a brief statement of the general nature of the evidence or arguments they wish to present, the names and addresses of proposed participants, and an indication of the approximate time requested to make their presentation on or before April 8, 2013. Time allotted for each presentation may be limited. If the number of registrants requesting to speak is greater than can be reasonably accommodated during the scheduled open public hearing session, FDA may conduct a lottery to determine the speakers for the scheduled open public hearing session. The contact person will notify interested persons regarding their request to speak by April 9, 2013.
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA) is announcing that we have concluded that certain statements set forth in the FDA-approved labels of over-the-counter nicotine replacement therapy products, related to concomitant use with other nicotine-containing products and duration of use, can be modified. In light of currently available evidence, these statements are no longer believed to be necessary in their current form to ensure the safe and effective use of over-the-counter nicotine replacement therapy products for their approved intended use as aids to smoking cessation. We encourage the submission of supplemental new drug applications (labeling supplements) to modify these statements as described in this notice.
Submit labeling supplements to the Center for Drug Evaluation and Research, Food and Drug Administration, Central Document Room (CDR), 5901–B Ammendale Rd., Beltsville, MD 20705–1266. Copies of the recommended revisions to product labeling may be requested from the Center for Drug Evaluation and Research's Division of Nonprescription Clinical Evaluation, 10903 New Hampshire Ave., Bldg. 22, Stop 5411, Silver Spring, MD 20993, 301–796–2080. Copies of published studies that can be used to support labeling supplements will be on display in the Division of Dockets Management (HFA–305), Food and Drug Administration, 5630 Fishers Lane, Rm. 1061, Rockville, MD 20852, and can be seen by interested persons between 9 a.m. and 4 p.m., Monday through Friday.
Doris J. Bates, Center for Drug Evaluation and Research, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 22, Rm. 4417, Silver Spring, MD 20993, 301–796–1040, FAX: 301–796–9721, email:
Tobacco use is the leading preventable cause of death and disease in the United States. According to an estimate by the Centers for Disease Control and Prevention, cigarette smoking causes 443,000 deaths each year in the United States, including nearly 50,000 deaths per year from involuntary exposure to tobacco smoke (Ref. 1). Smoking is known to cause multiple cancers, heart disease, stroke, complications of pregnancy, chronic obstructive pulmonary disease, and many other diseases that, on average, shorten smokers' lifespans by 14 years (Ref. 2).
Surveys show that approximately 70 percent of current smokers want to stop smoking, and nearly half of all smokers make a quit attempt each year (Ref. 3). Unfortunately, dependence on nicotine—the primary addictive substance in tobacco—is a chronic disease that often requires repeated intervention and multiple quit attempts to overcome. As a result, only a small percentage of smokers successfully quit each year (Ref. 3).
Nicotine replacement therapy (NRT) products are designed to help people stop smoking by supplying controlled amounts of nicotine to ease the withdrawal symptoms associated with a quit attempt. NRT products do not contain all of the carcinogens and other harmful constituents that are found in cigarette smoke. There are currently three types of NRT products approved by FDA for over-the-counter (OTC) use as smoking cessation aids: Nicotine gum, transdermal nicotine patch, and nicotine lozenge products.
Currently, the FDA-approved labeling for OTC NRT products instructs consumers that they should stop smoking when they begin using the product and that they should not use
In recent years, a number of stakeholders in the public health and health care provider communities have suggested that these labeling statements act as barriers to the effective use of OTC NRT products for smoking cessation. These stakeholders have argued that the statement advising against concomitant use of the NRT products with cigarettes may cause some smokers to abandon quit attempts if they experience a lapse (e.g., if they have a cigarette while using an NRT product). Stakeholders have also argued that use of more than one NRT product (e.g., patch plus gum) is more effective for some smokers than use of a single NRT product in achieving cessation, and that current labeling discourages such use. With regard to duration of use, stakeholders have argued that the use of OTC NRT products beyond the labeled treatment period may increase the chances of quitting for certain smokers.
Over the nearly 30 years since NRT products were first approved, evidence has accumulated to suggest that the current labeling provisions on concomitant use and duration of use may no longer be necessary to ensure the safe use of OTC NRT products for smoking cessation. Based on this evidence, FDA has concluded that the current labeling statements for OTC NRT products concerning concomitant use and duration of use can be modified as described in this document. We invite the products' sponsors to submit supplemental NDAs (labeling supplements) to modify these statements in the labeling of their drug products. To facilitate the process, the Agency has identified revisions to the labeling of OTC NRT products that can be included in these labeling supplements. Those revisions are set forth in section II.
The “Drug Facts” section of the label for OTC NRT products currently contains two statements relating to the use of these products with other nicotine-containing products. The first statement is found under the “Do not use” subheading of the “Warnings” section. It instructs consumers not to use the OTC NRT product if they “continue to smoke, chew tobacco, use snuff, or use [a different NRT product] or other nicotine containing products.” This statement was included in the labeling because at the time during which these products were switched to OTC use, there was little reliable data on the safety of the higher levels of nicotine that would result from using NRT products in combination with other nicotine-containing products. The second statement appears under the “Directions” section, and tells consumers to “stop smoking completely when you begin using the [NRT product].” This statement was included in the label because in the clinical trials that were conducted for the original NRT product approvals, individuals who stopped smoking completely when they began using NRT were more likely to quit.
Since we first approved NRT products for OTC use, a number of studies have been conducted that provide information on the safety of using NRT products in combination with other nicotine-containing products. Many of these studies focused on the effects of using NRT products while smoking. For example, there have been studies on the use of NRT products by smokers who were not immediately interested in quitting (see Hatsukami et al., 2007), on the use of NRT products as an aid to smoking reduction (see Wennike et al., 2003; Batra et al., 2005), and on the use of NRT products before initiating a quit attempt (Lindson and Aveyard, 2011). In addition, several studies have been conducted on the use of higher-than-standard-dose NRT products (Tønnesen et al., 1999) and on the concomitant use of more than one type of NRT product (see Bohadana et al., 2000; Piper et al., 2009).
Upon reviewing the published reports of these and other studies, we have determined that the concomitant use of OTC NRT products with cigarettes or with other nicotine-containing products does not raise significant safety concerns. The published literature contains few reports of adverse events arising from the use of NRT products while smoking or using another NRT product. The Agency also notes that few adverse events have been reported in studies of concomitant use conducted under the investigational new drug (IND) process, which involves mandatory reporting of adverse events.
Accordingly, we are announcing that the statements in the current labeling of OTC NRT products relating to concomitant use of those products with other nicotine-containing products can be modified. The following specific changes to the current approved “Drug Facts” labeling are recommended:
•
•
Currently, the labeling of OTC NRT products recommends a specific duration of use of up to 12 weeks, depending on the product. For example, the “Drug Facts” section of the label for nicotine gum and lozenge products recommends that those products be used for 12 weeks; the label for certain nicotine patch products recommends a duration of use of 8 weeks, others 10 weeks. These labeled durations of use reflect the treatment periods that were studied in the clinical trials that supported the switch of these products to OTC status. Because NRT products treat the acute withdrawal symptoms associated with a quit attempt, and those symptoms typically diminish over time, most of the clinical trials conducted to support approval were short—generally between 6 and 12 weeks in length.
In addition to recommending a specific duration of use, current OTC NRT product labels direct consumers to stop using the product at the end of the recommended treatment period and to talk to a doctor if they feel they need to use the product longer. This statement was included in the labeling because at the time of the first prescription-to-OTC switch, there was insufficient data to
In the years since NRT products became available for OTC use, a number of studies have examined the use of NRT products over periods longer than 12 weeks. We have reviewed the published literature on this longer-term use of NRT products and have not identified any safety risks associated with such use. A well-known and highly regarded study on the effects of long-term use of NRT products is the Lung Health Study, in which almost 6,000 smokers were given access to free nicotine gum for up to 5 years (see Murray et al., 1996). In this study, over 1,000 subjects were still using the gum after 1 year. The adverse effects of long-term nicotine gum use reported by these subjects were described as minor and transient, and there was no correlation between long-term gum use and cardiovascular events. A followup study found that long-term ad lib use of nicotine gum neither increased nor decreased the Lung Health Study subjects' likelihood of developing cancer (see Murray et al., 2009). Other informative studies on the effects of long-term use of NRT products include a 52-week study of NRT product use in which nearly half of the subjects used two or more OTC NRT products in combination (see Joseph et al., 2011), and a trial involving the use of nicotine patches for 6 to 12 months by nonsmokers with mild cognitive impairment (see Newhouse et al., 2012). Both of these studies had high rates of completion and reported few adverse events from long-term use of NRT products.
We also note that although any nicotine-containing product has the potential to be addicting, based on the available evidence, currently marketed OTC NRT products do not appear to have significant potential for abuse or dependence. A 2010 review of historical reports made to the Agency's Adverse Event Reporting System and to the Substance Abuse and Mental Health Services Administration's Drug Abuse Warning Network between 1984 and 2009 suggested that NRT products have a low potential for abuse. Several published studies have also found that the abuse liability and dependence potential of NRT products is low, especially compared to cigarettes (see West et al., 2000; Houtsmuller et al., 2002).
Accordingly, we are announcing that the statement in the labeling of OTC NRT products directing consumers to stop using the NRT product at the end of the recommended treatment period can be modified. The following specific change to the current approved “Drug Facts” labeling is recommended:
•
In light of currently available evidence on the concomitant use of OTC NRT products with cigarettes or other nicotine-containing products, and on the use of OTC NRT products beyond the labeled period of treatment, the following changes to the “Drug Facts” labeling of OTC NRT products are recommended:
We have determined that these labeling revisions may be addressed through a changes being effected (CBE) supplement under 21 CFR 314.70(c)(6).
We are also recommending conforming changes to other FDA-approved labeling for OTC NRT products, such as product user guides and leaflets. Copies of the recommended changes to these other labeling items may be obtained from the Center for Drug Evaluation and Research's Division of Nonprescription Clinical Evaluation (see
We have determined that the current OTC NRT products can be used safely and effectively for their approved intended use as aids to smoking cessation with the labeling modifications identified in section II. We encourage the submission of labeling supplements for these drug products. These supplements should modify the labeling statements concerning concomitant use and duration of use as described in section II. The requirement for data to support these labeling changes may be met by citing the published literature we relied on in preparing this notice. A list of the published literature and reprints of the reports will be available for public inspection in the Division of Dockets Management (see
The published literature we have relied on in making the determinations contained in this notice is listed in this section of the document. Copies of the published literature will be on display in the Division of Dockets Management (see
The following references have been placed on display in the Division of Dockets Management (see
Indian Health Service, HHS.
Notice.
In compliance with Section 3506(c)(2)(A) of the Paperwork
National health care standards developed by the Centers for Medicare and Medicaid Services, the Joint Commission, and other accrediting organizations require health care facilities to review, evaluate and verify the credentials, training and experience of medical staff applicants prior to granting medical staff privileges. In order to meet these standards, IHS health care facilities require all medical staff applicants to provide information concerning their education, training, licensure, and work experience and any adverse disciplinary actions taken against them. This information is then verified with references supplied by the applicant and may include: former employers, educational institutions, licensure and certification boards, the American Medical Association, the Federation of State Medical Boards, the National Practitioner Data Bank, and the applicants themselves.
In addition to the initial granting of medical staff membership and clinical privileges, the Joint Commission standards require that a review of the medical staff be conducted not less than every two years. This review evaluates the current competence of the medical staff and verifies whether they are maintaining the licensure or certification requirements of their specialty.
The medical staff credentials and privileges records are maintained at the health care facility where the health care provider is a medical staff member. The establishment of these records at IHS health care facilities is a Joint Commission requirement. Prior to the establishment of this Joint Commission requirement, the degree to which medical staff applications were maintained at all health care facilities in the United States that are verified for completeness and accuracy varied greatly across the Nation.
The application process has been streamlined and is using information technology to make the application electronically available on the Internet. The application may be found at the IHS.gov Web site address:
The table below provides: Types of data collection instruments, Estimated number of respondents, Number of annual number of responses, Average burden per response, and Total annual burden hours.
In compliance with the requirement of Section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995, for opportunity for public comment on proposed data collection projects, the John E. Fogarty International Center, National Institutes of Health (NIH), will publish periodic summaries of proposed projects to be submitted to the Office of Management and Budget (OMB) for review and approval.
Written comments and/or suggestions from the public and affected agencies are invited on one or more of the following points: (1) Whether the proposed collection of information is necessary for the proper performance of the function of the agency, including whether the information will have practical utility; (2) 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) 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 those who are to respond, including the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology.
OMB approval is requested for 1 year. There are no costs to respondents other than their time. The total estimated annualized burden hours are 151.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of a meeting of the National Advisory Council on Drug Abuse.
The meeting will be open to the public as indicated below, with attendance limited to space available. Individuals who plan to attend and need special assistance, such as sign language interpretation or other reasonable accommodations, should notify the Contact Person listed below in advance of the 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.
Any member of the public interested in presenting oral comments to the committee may notify the Contact Person listed on this notice at least 10 days in advance of the meeting. Interested individuals and representatives of organizations may submit a letter of intent, a brief description of the organization represented, and a short description of the oral presentation. Only one representative of an organization may be allowed to present oral comments and if accepted by the committee, presentations may be limited to five minutes. Both printed and electronic copies are requested for the record. In addition, any interested person may file written comments with the committee by forwarding their statement to the Contact Person listed on this notice. The statement should include the name, address, telephone number and when applicable, the business or professional affiliation of the interested person.
Information is also available on the Institute's/Center's home page:
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.
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.
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 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.
Coast Guard, DHS.
Notice and request for comments.
The Coast Guard is seeking public comment regarding the merchant mariner medical evaluation program. Section 718 of the Coast Guard Authorization Act of 2012 directed the Commandant of the Coast Guard to submit to Congress an assessment of the Coast Guard National Maritime Center's merchant mariner medical evaluation program and alternatives to the program. Congress specifically asked the Coast Guard to include an analysis of how a system similar to the Federal Motor Carrier Safety Administration's National Registry of Certified Medical Examiners program, and the Federal Aviation Administration's Designated Aviation Medical Examiners program, could be applied by the Coast Guard in making medical fitness determinations for issuance of merchant mariners' documents. The Coast Guard will accept comments from the public on the perceived benefits and concerns with adopting a similar program for the medical evaluation of merchant mariners.
Comments and related material must either be submitted to our online docket via
You may submit comments identified by docket number USCG–2013–0089 using any one of the following methods:
(1)
(2)
(3)
(4)
To avoid duplication, please use only one of these four methods. See the “Public Participation” portion of the
If you have questions about this notice, call or email Lieutenant Ashley Holm, Office of Commercial Vessel Compliance(CG–CVC–4), U.S. Coast Guard, telephone (202) 372–1128, email
You may submit comments and related material regarding this notice. All comments received will be posted, without change, to
To submit your comment online, go to
We will consider all comments and material received during the comment period.
Section 718 of the Coast Guard Authorization Act of 2012 (Pub. L. 112–213) directed the Commandant of the Coast Guard to, not later than 180 days after enactment, submit to the Committee on Transportation and Infrastructure of the House of Representatives and the Committee on Commerce, Science, and Transportation of the Senate an assessment of the Coast Guard National Maritime Center's merchant mariner medical evaluation program and alternatives to the program. Section 718 also directed that the assessment contain the following:
(1) An overview of the adequacy of the program for making medical certification determinations for issuance of merchant mariners' documents;
(2) An analysis of how a system similar to the Federal Motor Carrier Safety Administration's National Registry of Certified Medical Examiners program, and the Federal Aviation Administration's Designated Aviation Medical Examiners program, could be applied by the Coast Guard in making medical fitness determinations for issuance of merchant mariners' documents; and
(3) An explanation of how the amendments to the International Convention on Standards of Training, Certification and Watchkeeping for Seafarers, 1978, that entered into force on January 1, 2012, required changes to the Coast Guard's merchant mariner medical evaluation program.
Currently, the Coast Guard maintains an “open” system of medical evaluation. While the ultimate determination of medical fitness rests with the Coast Guard, mariners may have any authorized medical professional fill out the appropriate evaluation forms which are then submitted to the Coast Guard. The evaluation reports are reviewed by the National Maritime Center and a fitness determination is then made. Conversely, a “closed” system would require mariners to have their physical evaluations done by designated medical examiners who are authorized by the Coast Guard to conduct physical examinations of mariners. Subject to detailed policy guidance, medical certificates may be issued by the designated medical examiner.
Finally, a hybrid system could be adopted whereby the designated medical examiner would issue medical certificates when mariners meet certain pre-established criteria, and the Coast Guard would only be involved in reviewing those mariners who have certain conditions.
The Coast Guard would like public input on the relative merits of a closed, open, or hybrid system of medical evaluation, noting advantages and disadvantages of the different systems. We would also be interested in knowing any other suggestions or comments that address the subject of the assessment required by section 718 of the Coast Guard Authorization Act of 2012.
This notice is issued under the authority of 46 U.S.C chapter 71, Department of Homeland Security Delegation No. 0710.1, and 46 CFR 10.215.
U.S. Customs and Border Protection (CBP), Department of Homeland Security.
60-Day notice and request for comments; Extension of an existing information collection: 1651–0110.
As part of its continuing effort to reduce paperwork and respondent burden, CBP invites the general public and other Federal agencies to comment on an information collection requirement concerning the Visa Waiver Program Carrier Agreement (CBP Form I–775). This request for comment is being made pursuant to the Paperwork Reduction Act of 1995 (Public Law 104–13; 44 U.S.C. 3505(c)(2)).
Written comments should be received on or before June 3, 2013, to be assured of consideration.
Direct all written comments to U.S. Customs and Border Protection, Attn: Tracey Denning, Regulations and Rulings, Office of International Trade, 90 K Street NE., 10th Floor, Washington, DC. 20229–1177.
Requests for additional information should be directed to Tracey Denning, U.S. Customs and Border Protection, Regulations and Rulings, Office of International Trade, 90 K Street NE., 10th Floor, Washington, DC. 20229–1177, at 202–325–0265.
CBP invites the general public and other Federal agencies to comment on proposed and/or continuing information collections pursuant to the Paperwork Reduction Act of 1995 (Pub. L. 104–13; 44 U.S.C. 3505(c)(2)). The comments should address: (a) Whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimates of the burden of the collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; (d)
The Visa Waiver Program Carrier Agreement (CBP Form I–775) is used by carriers to request acceptance by CBP into the Visa Waiver Program (VWP). This form is an agreement whereby carriers agree to the terms of the VWP as delineated in Section 217(e) of the INA (8 U.S.C. 1187(e)). Once participation is granted, CBP Form I–775 serves to hold carriers liable for the transportation costs, to ensure the completion of required forms, and to share passenger data. Regulations are promulgated at 8 CFR Part 233. A copy of CBP Form I–775 is accessible at:
Office of the Assistant Secretary for Fair Housing and Equal Opportunity, HUD.
Notice of information collection.
The proposed information collection requirement described below will be submitted to the Office of Management and Budget (OMB) for review, as required by the Paperwork Reduction Act of 1995. HUD is soliciting public comments on the subject proposal. Developers of new projects describe their intent (marketing efforts) to assure that they meet the Fair Housing guidelines in how the project is marketed to the public.
Interested persons are invited to submit comments regarding this proposed information collection requirement. Comments should refer to the proposal by name and/or OMB Control Number, and should be sent to: Reports Liaison Officer, Department of Housing and Urban Development, 451 7th Street SW., Washington, DC 20410–2000; or for the hearing and speech impaired the number for the Federal Relay Service Relay Service 1–800–877–8339.
Tracy E. Richardson, Director, Program Standards and Compliance Division, Office of Fair Housing and Equal Opportunity, Department of Housing and Urban Development, 451 Seventh Street SW., Room 5240, Washington, DC 20410–2000; email to
The Department is submitting this proposed information collection requirement to OMB for review, as required by the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35, as amended).
This Notice is soliciting comments from members of the public and affected agencies concerning the proposed collection of information to: (1) Evaluate whether the proposed collection 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; (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 the use of appropriate automated collection techniques or other forms of information technology, e.g., permitting electronic submission of responses.
This Notice also lists the following information:
The Paperwork Reduction Act of 1995, 44 U.S.C. Chapter 35, as amended.
Fish and Wildlife Service, Interior.
Notice; request for comments.
We (U.S. Fish and Wildlife Service) have sent an Information Collection Request (ICR) to OMB for review and approval. We summarize the ICR below and describe the nature of the collection and the estimated burden and cost. This information collection is scheduled to expire on April 30, 2013. 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. However, under OMB regulations, we may continue to conduct or sponsor this information collection while it is pending at OMB.
You must submit comments on or before May 2, 2013.
Send your comments and suggestions on this information collection to the Desk Officer for the Department of the Interior at OMB—OIRA at 202–395–5806 (fax) or
To request additional information about this ICR, contact Hope Grey at
The Migratory Bird Treaty Act Protocol Amendment (1995) (Amendment) provides for the customary and traditional use of migratory birds and their eggs for subsistence use by indigenous inhabitants of Alaska. The Amendment states that its intent is not to cause significant increases in the take of species of migratory birds relative to their continental population sizes. A submittal letter from the Department of State to the White House (May 20, 1996) accompanied the Amendment and specified the need for harvest monitoring. The submittal letter stated that the Service, the Alaska Department of Fish and Game (ADFG), and Alaska Native organizations would collect harvest information cooperatively within the subsistence eligible areas. Harvest survey data help to ensure that customary and traditional subsistence uses of migratory birds and their eggs by indigenous inhabitants of Alaska do not significantly increase the take of species of migratory birds relative to their continental population sizes.
Between 1989 and 2004, we monitored subsistence harvest of migratory birds using annual household surveys in the Yukon–Kuskokwim Delta, which is the region of highest subsistence bird harvest in the State of Alaska. In 2004, we began monitoring subsistence harvest of migratory birds in subsistence eligible areas Statewide. The Statewide harvest assessment program helps to track trends and changes in levels of harvest. The harvest assessment program relies on collaboration among the Service, the
We gather information on the annual subsistence harvest of about 60 bird species/species categories (ducks, geese, swans, cranes, upland game birds, seabirds, shorebirds, and grebes, and loons) in the subsistence eligible areas of Alaska. The survey covers 11 regions of Alaska, which are further divided into 29 subregions. We survey the regions and villages in a rotation schedule to accommodate budget constraints and to minimize respondent burden. The survey covers spring, summer, and fall harvest in most regions.
In collaboration with Alaska Native organizations, we hire local resident surveyors to collect the harvest information. The surveyors list all households in the villages to be surveyed and provide survey information and harvest report forms to randomly selected households that have agreed to participate in the survey. To ensure anonymity of harvest information, we identify households by a numeric code. The surveyor visits households three times during the survey year. At the first household visit, the surveyor explains the survey purposes and invites household participation. The surveyor returns at the end of the season of most harvest and at the end of the two other seasons combined to help the household complete the harvest report form.
We have designed the survey methods to streamline procedures and reduce respondent burden. We plan to use two forms for household participation:
• FWS Form 3–2380 (Tracking Sheet and Household Consent). The surveyor visits each household selected to participate in the survey to provide information on the objectives and to obtain household consent to participate. The surveyor uses this form to record consent and track subsequent visits for completion of harvest reports.
• FWS Forms 3–2381–1, 3–2381–2, 3–2381–3, and 3–2381–4 (Harvest Report). The Harvest Report has drawings of bird species most commonly available for harvest in the different regions of Alaska with fields for writing down the numbers of birds and eggs taken. There are four versions of this form: Interior Alaska, North Slope, Southern Coastal Alaska, and Western Alaska. This form has a sheet for each season surveyed, and each sheet has fields for the household code, community name, harvest year, date of completion, and comments.
We again 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.
Fish and Wildlife Service, Interior.
Notice of receipt of application for approval; request for comment.
The public is invited to comment on the following application for approval to conduct certain activities with birds that are protected in accordance with the Wild Bird Conservation Act of 1992.
Written data, comments, or requests for a copy of this application must be received by May 2, 2013.
Documents and other information submitted with this application are available for review, subject to the requirements of the Privacy Act and Freedom of Information Act, by any party who submits a written request for a copy of such documents within 30 days of the date of publication of this notice to: Chief, U.S. Fish and Wildlife Service, Division of Management Authority, 4401 North Fairfax Drive, Room 212, Arlington, VA 22203; fax 703/358–2298.
Craig Hoover, Chief, Branch of Operations, Division of Management Authority, at 703–358–2104.
The public is invited to comment on the following application for approval to conduct certain activities with bird species covered under the Wild Bird Conservation Act of 1992. This notice is provided pursuant to Section 112(4) of the Wild Bird Conservation Act of 1992, 50 CFR 15.26(c). Written data, comments, or requests for copies of this complete application should be submitted to the Chief (address above).
The applicant wishes to establish a cooperative breeding program for Red-necked Aracari (
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.
Fish and Wildlife Service, Interior.
Notice of availability; request for comments.
We, the U.S. Fish and Wildlife Service, invite the public to comment on the following applications for permits to conduct activities with the purpose of enhancing the survival of endangered species. The Endangered Species Act of 1973, as amended (Act), prohibits certain activities with respect to endangered species unless a Federal permit allows such activity. The Act also requires that we invite public comment before issuing such permits.
To ensure consideration, please send your written comments by May 2, 2013.
Endangered Species Program Manager, Ecological Services, U.S. Fish and Wildlife Service, Pacific Regional Office, 911 NE 11th Avenue, Portland, OR 97232–4181. Please refer to the permit number for the application when submitting comments.
Grant Canterbury, Fish and Wildlife Biologist, at the above address or by telephone (503–231–6131) or fax (503–231–6243).
The Act (16 U.S.C. 1531
A permit granted by us under section 10(a)(1)(A) of the Act authorizes the permittee to conduct activities (including take or interstate commerce) with respect to U.S. endangered or threatened species for scientific purposes or enhancement of propagation or survival. Our regulations implementing section 10(a)(1)(A) of the Act for these permits are found at 50 CFR 17.22 for endangered wildlife species, 50 CFR 17.32 for threatened wildlife species, 50 CFR 17.62 for endangered plant species, and 50 CFR 17.72 for threatened plant species.
We invite local, State, and Federal agencies, and the public to comment on the following applications. Please refer to the appropriate permit number for the application when submitting comments.
Documents and other information submitted with these applications are available for review by request from the Endangered Species Program Manager at the address listed in the
The applicant requests a new recovery permit to take (capture and release) the Fender's blue butterfly (
The applicant requests a new recovery permit to take (capture and release) the Modoc sucker (
All comments and materials we receive in response to this request will be available for public inspection, by appointment, during normal business hours at the address listed in the
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.
We provide this notice under section 10 of the Act (16 U.S.C. 1531
Fish and Wildlife Service, Interior.
Notice of issuance of permits.
We, the U.S. Fish and Wildlife Service (Service), have issued the following permits to conduct certain activities with endangered species, marine mammals, or both. We issue these permits under the Endangered Species Act (ESA) and Marine Mammal Protection Act (MMPA).
Brenda Tapia, Division of Management Authority, U.S. Fish and Wildlife Service, 4401 North Fairfax Drive, Room 212, Arlington, VA 22203; fax (703) 358–2280; or email
Brenda Tapia, (703) 358–2104 (telephone); (703) 358–2280 (fax);
On the dates below, as authorized by the
Documents and other information submitted with these applications are available for review, subject to the requirements of the Privacy Act and Freedom of Information Act, by any party who submits a written request for a copy of such documents to: Division of Management Authority, U.S. Fish and Wildlife Service, 4401 North Fairfax Drive, Room 212, Arlington, VA 22203; fax (703) 358–2280.
Fish and Wildlife Service, Interior.
Notice of receipt of applications for permit.
We, the U.S. Fish and Wildlife Service, invite the public to comment on the following applications to conduct certain activities with endangered species, marine mammals, or both. With some exceptions, the Endangered Species Act (ESA) prohibits activities with listed species unless Federal authorization is acquired that allows such activities.
We must receive comments or requests for documents on or before May 2, 2013.
Brenda Tapia, Division of Management Authority, U.S. Fish and Wildlife Service, 4401 North Fairfax Drive, Room 212, Arlington, VA 22203; fax (703) 358–2280; or email
Brenda Tapia, (703) 358–2104 (telephone); (703) 358–2280 (fax);
Send your request for copies of applications or comments and materials concerning any of the applications to the contact listed under
Please make your requests or comments as specific as possible. Please confine your comments to issues for which we seek comments in this notice, and explain the basis for your comments. Include sufficient information with your comments to allow us to authenticate any scientific or commercial data you include.
The comments and recommendations that will be most useful and likely to influence agency decisions are: (1) Those supported by quantitative information or studies; and (2) Those that include citations to, and analyses of, the applicable laws and regulations. We will not consider or include in our administrative record comments we receive after the close of the comment period (see
Comments, including names and street addresses of respondents, will be available for public review at the street address listed under
To help us carry out our conservation responsibilities for affected species, and in consideration of section 10(a)(1)(A) of the Endangered Species Act of 1973, as amended (16 U.S.C. 1531
The applicant requests a captive-bred wildlife registration under 50 CFR 17.21(g) for the barasingha (
The applicant requests a permit authorizing interstate and foreign commerce, export, and cull of excess scimitar-horned oryx (
The applicant requests a captive-bred wildlife registration under 50 CFR 17.21(g) for the barasingha (
The applicant requests a permit authorizing interstate and foreign commerce, export, and cull of excess barasingha (
The applicant requests a permit to export six female live, captive-born Orinoco crocodiles (
The applicant requests a permit to export/re-export and reimport nonliving museum specimens of endangered and threatened species previously accessioned into the applicant's collection for scientific research. This notification covers activities to be conducted by the applicant over a 5-year period.
The following applicants each request a permit to import the sport-hunted trophy of one male bontebok (
Bureau of Land Management, Interior.
Notice of public meetings.
In accordance with the Federal Land Policy and Management Act (FLPMA), the Federal Advisory Committee Act of 1972 (FACA, the U.S. Department of the Interior, Bureau of Land Management (BLM) Twin Falls District Resource Advisory Council (RAC) will meet as indicated below.
On April 23 2013, the Twin Falls District RAC members will meet at the LaQuinta Inns & Suites, 539 Poleline Road, Twin Falls Idaho. The meeting will begin at 9:00 a.m. and end no later than 4:00 p.m. The public comment period for the RAC meeting will take place 9:10 a.m. to 9:40 a.m.
Heather Tiel-Nelson, Twin Falls District, Idaho, 2536 Kimberly Road, Twin Falls, Idaho, 83301, (208) 736–2352.
The 15-member RAC advises the Secretary of the Interior, through the Bureau of Land Management, on a variety of planning and management issues associated with public land management in Idaho. During the April 23rd meeting, there will be a Craters of the Moon National Monument Resource Management Plan (RMP) Amendment update and field office updates. Additional topics may be added and will be included in local media announcements. More information is available at
RAC meetings are open to the public. For further information about the meeting, please contact Heather Tiel-Nelson, Public Affairs Specialist for the Twin Falls District BLM at (208) 736–2352.
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 IC is scheduled to expire on February 28, 2014. We may not conduct or sponsor a survey, and a person is not required to respond to a collection of
To ensure that we are able to consider your comments on this IC, we must receive them by June 3, 2013.
Send your comments on the IC to Madonna L. Baucum, Information Collection Clearance Officer, National Park Service, 1201 I Street NW., MS 1237, Washington, DC 20005 (mail); or
To request additional information about this IC, contact Garry Oye, Chief, Wilderness Stewardship Division at (702) 895–4893; or 4505 Maryland Parkway, Box 452040–RAJ284, Las Vegas, NV 89154–2040 (mail); or
In 1976, the NPS initiated a backcountry registration system in accordance with the regulations found at 36 CFR 1.5, 1.6 and 2.10. The objective of the use permit system is to provide users access to backcountry areas of national parks with continuing opportunities for solitude, while enhancing resource protection and providing a means of disseminating public safety messages regarding the backcountry travel. NPS backcountry program managers, by designating access routes and overnight camping locations, can redistribute campers in response to user impact, high fire danger, flood or wind hazard, bear activity or other situations that may temporarily close a portion of the backcountry. The NPS may also use the permit system as a means of ensuring that each backcountry user receives up-to-date information on backcountry sanitation procedures, food storage, wildlife activity, trail conditions and weather projections so that concerns for visitor safety are met.
The Backcountry Use Permit is an extension of the NPS statutory authority responsibility to protect the park areas it administers and to manage the public use thereof (16 U.S.C. 1 and 3). NPS regulations codified in 36 CFR parts 1 through 7, 12 and 13 are designated to implement statutory mandates that provide for resource protection and pubic enjoyment. The Backcountry Use Permit is the primary form used to provide access into NPS backcountry areas including those areas that require a reservation to enter where use limits are imposed in accordance with other NPS regulations. Such permitting enhances the ability to the NPS to education users on potential hazards, search and rescue efforts, and resource protection.
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 of availability.
Pursuant to the National Environmental Policy Act of 1969, 42 U.S.C. 4332(2)(C), the National Park Service announces the availability of a Draft Environmental Impact Statement for the General Management Plan (EIS/GMP) for Fort Raleigh National Historic Site, North Carolina. The draft describes and analyzes several alternatives to guide the management of the site over the next 15 to 20 years. The NPS preferred alternative incorporates various management prescriptions to ensure access to and protection and enjoyment of the monument's resources.
We will accept comments for a period of 60 days following publication of the Environmental Protection Agency's notice of availability in the
You may submit comments by the following methods:
• Via the internet on the PEPC Web site
• Via mail to Superintendent, Fort Raleigh National Historic Site, 1401 National Park Drive, Manteo, NC 27954.
• Via hand delivery to the above address.
Electronic copies of the Draft EIS/GMP will be available online at
Superintendent Barclay Trimble, Fort Raleigh National Historic Site, 1401 National Park Drive, Manteo, NC 27954 or telephone at (252) 473–2111, ext. 148.
Public meetings, newsletters, and internet updates have kept the public informed and involved throughout the planning process. The Draft EIS/GMP provides a
• Alternative A (no action) provides a baseline for evaluating changes and impacts of the two action alternatives.
• Alternative B would greatly expand the scope of the National Historic Site's partnerships through greater partner involvement in interpretation of the Roanoke Voyages. The NPS staff would interpret other National Historic Site stories. This alternative encourages more on-site experiences through partnerships and through additional interpretive efforts, marketing, and facilities.
• Alternative C, the NPS preferred alternative, would increase our research on the site's history, archeology, inhabitants and events with emphasis on interpretive themes and preservation. As a result of our expanded research and coordination with other research organizations and agencies, visitors would benefit by gaining increased knowledge of the National Historic Site and its multiple cultural and natural themes. This alternative would respond to the mandates of Public Law 101–603, which broadened the interpretive and resource preservation purpose of the National Historic Site.
The three alternatives are described in detail in chapter 2 of the Draft EIS/GMP. Chapter 4 details the key impacts of implementing the three alternatives.
Before including your address, phone number, email address, or other personal identifying information in your comment, please 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.
Office of Surface Mining Reclamation and Enforcement.
Notice and request for comments.
In compliance with the Paperwork Reduction Act of 1995, the Office of Surface Mining Reclamation and Enforcement (OSM) is announcing its intention to request renewed approval from the Office of Management and Budget to continue collecting information for Permit Applications—Minimum Requirements for Legal, Financial, Compliance, and Related Information. The information collection request describes the nature of the information collection and its expected burden and cost.
Comments on the proposed information collection must be received by June 3, 2013, to be assured of consideration.
Comments may be mailed to John Trelease, Office of Surface Mining Reclamation and Enforcement, 1951 Constitution Ave NW., Room 203—SIB, Washington, DC 20240. Comments may also be submitted electronically to
To receive a copy of the information collection request contact John Trelease, at (202) 208–2783 or by email at
OMB regulations at 5 CFR 1320, which implement provisions of the Paperwork Reduction Act of 1995 (Pub. L. 104–13), require that interested members of the public and affected agencies have an opportunity to comment on information collection and recordkeeping activities [see 5 CFR 1320.8 (d)]. This notice identifies an information collection that OSM will be submitting to OMB for extension. This collection is contained in 30 CFR Part 778—Permit Applications—Minimum Requirements for Legal, Financial, Compliance, and Related Information.
OSM has revised burden estimates, where appropriate, to reflect current reporting levels or adjustments based on reestimates of burden or respondents. OSM will request a 3-year term of approval for each information collection activity.
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 number for this collection of information is 1029–0117 and is displayed at 30 CFR 778.8. Responses are required to obtain a benefit.
Comments are invited on: (1) The need for the collection of information for the performance of the functions of the agency; (2) the accuracy of the agency's burden estimates; (3) ways to enhance the quality, utility and clarity of the information collection; and (4) ways to minimize the information collection burden on respondents, such as use of automated means of collection of the information. A summary of the public comments will be included in OSM's submissions of the information collection request to OMB.
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.
United States International Trade Commission.
Notice.
The Commission hereby gives notice of the institution of an investigation and commencement of preliminary phase antidumping investigation No. 731–TA–1206 (Preliminary) under section 733(a) of the Tariff Act of 1930 (19 U.S.C. 1673b(a)) (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 imports from Japan of diffusion-annealed, nickel-plated steel flat-rolled products, provided for primarily in subheadings 7210.90 and 7212.50 of the Harmonized Tariff Schedule of the United States, that are alleged to be sold in the United States at less than fair value.
For further information concerning the conduct of this investigation and rules of general application, consult the Commission's Rules of Practice and Procedure, part 201, subparts A through E (19 CFR part 201), and part 207, subparts A and B (19 CFR part 207).
Nathanael Comly (202–205–3174), 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 (
In accordance with sections 201.16(c) and 207.3 of the rules, each document filed by a party to the investigation must be served on all other parties to the investigation (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.
This investigation is 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.
Employment and Training Administration, Labor.
Notice.
Announcement regarding a change in eligibility for Unemployment Insurance (UI) claimants in Alaska, Georgia, Louisiana, Maryland, Mississippi, Missouri, Montana, Ohio, South Carolina and Texas in the Emergency Unemployment Compensation (EUC08) program, and the Federal-State Extended Benefits (EB) program.
The U.S. Department of Labor (Department) produces trigger notices indicating which states qualify for both EB and EUC08 benefits, and provides the beginning and ending dates of payable periods for each qualifying state. The trigger notices covering state eligibility for these programs can be found at:
The following changes have occurred since the publication of the last notice regarding states EUC08 and EB trigger status:
• Maryland and Texas have triggered “off” in Tier 3 of EUC08
Maryland and Texas began a 13-week mandatory “on” period in Tier 3 of EUC08 on October 7, 2012. Based on data released from the Bureau of Labor Statistics, these states are below the 7.0 percent threshold rate necessary to remain “on” in Tier 3 of EUC08. As a result, they have concluded a payable period in Tier 3 and the week ending January 5, 2013, was the last week in which EUC08 claimants in these states could exhaust Tier 2, and establish Tier 3 eligibility. Under the phase-out provisions, claimants could receive any remaining entitlement they had in Tier 3 after January 5, 2013.
• Georgia, Mississippi and South Carolina have triggered “off” in Tier 4 of EUC08.
The three month average, seasonally adjusted total unemployment rate in these states fell below the 9.0 percent threshold rate to remain “on” in Tier 4 of EUC08. This triggered these states “off” of Tier 4 and the week ending January 12, 2013, was the last week in which EUC08 claimants in these states could exhaust Tier 3, and establish Tier 4 eligibility. Under the phase-out provisions, claimants could receive any remaining entitlement they had in Tier 4 after January 12, 2013.
• Louisiana, Missouri, and Ohio have triggered “off” in Tier 3 of EUC08.
The three month average, seasonally adjusted total unemployment rate in Louisiana, Missouri, and Ohio fell below the 7.0 percent threshold rate to remain “on” in Tier 3 of EUC08. This triggered these states “off” of Tier 3 and the week ending January 12, 2013, was the last week in which EUC08 claimants in these states could exhaust Tier 2, and establish Tier 3 eligibility. Under the phase-out provisions, claimants could receive any remaining entitlement they had in Tier 3 after January 12, 2013.
• Montana has triggered “off” in Tier 2 of EUC08.
The three month average, seasonally adjusted total unemployment rate in Montana fell below the 6.0 percent threshold rate to remain “on” in Tier 2 of EUC08. This triggered Montana “off” of Tier 2 and the week ending January 12, 2013, was the last week in which EUC08 claimants in Montana could have exhausted Tier 1, and establish Tier 2 eligibility. Under the phase-out provisions, claimants could receive any remaining entitlement they had in Tier 2 after January 12, 2013.
• Alaska has triggered “on” Tier 4 of EUC08.
Alaska's 13-week insured unemployment rate for the week ending January 19, 2013, rose to meet the 6 percent threshold to trigger “on” to Tier 4 of EUC08. The payable period for Alaska in Tier Four of EUC08 began February 3, 2013. As a result, the current maximum potential entitlement for claimants in Alaska in EUC08 has increased from 37 weeks to 47 weeks.
• Alaska triggers “on” to EB.
Alaska's 13-week insured unemployment rate for the week ending January 19, 2013, rose to meet the 6 percent threshold to trigger “on” to EB. Alaska's payable period in EB began February 3, 2013.
The duration of benefits payable in the EUC08 program, and the terms and conditions under which they are payable, are governed by Public Laws 110–252, 110–449, 111–5, 111–92, 111–118, 111–144, 111–157, 111–205, 111–312, 112–96, and 112–240, and the operating instructions issued to the states by the Department. The duration of benefits payable in the EB program, and the terms and conditions on which they are payable, are governed by the Federal-State Extended Unemployment Compensation Act of 1970, as amended, and the operating instructions issued to the states by the Department.
In the case of a state beginning or concluding a payable period in EB or EUC08, the State Workforce Agency (SWA) will furnish a written notice of any change in potential entitlement to each individual who could establish, or had established, eligibility for benefits (20 CFR 615.13 (c)(1) and (c)(4)). Persons who believe they may be entitled to benefits in the EB or EUC08 programs, or who wish to inquire about their rights under these programs, should contact their SWA.
Tony Sznoluch, U.S. Department of Labor, Employment and Training Administration, Office of Unemployment Insurance, 200 Constitution Avenue NW., Frances Perkins Bldg. Room S–4524, Washington, DC 20210, telephone number (202) 693–3176 (this is not a toll-free number) or by email:
Employment and Training Administration, Labor.
Notice.
Public Law 105–220, the Workforce Investment Act (WIA), requires the Secretary of Labor (Secretary) to conduct reallotment of dislocated worker formula allotted funds based on State financial reports submitted as of the end of the prior program year (PY). This notice publishes the dislocated worker PY 2012 funds for recapture by State and the amount to be reallotted to eligible States.
This notice is effective April 2, 2013.
Ms. Amanda Ahlstrand, Acting Administrator, U.S. Department of Labor, Office of Workforce Investment, Employment and Training Administration, Room C–4526, 200 Constitution Avenue NW, Washington, DC Telephone (202) 693–3052 (this is not a toll-free number) or fax (202) 693–3981.
WIA Section 132(c) requires the Secretary to conduct reallotment of dislocated worker funds based on financial reports submitted by States as of the end of the prior program year. The procedures the Secretary uses for recapture and reallotment of funds are described in WIA regulation at 20 CFR 667.150. Training and Employment Guidance Letter 19–11 advised States that reallotment of funds under WIA will occur during PY 2012 based on State obligations made in PY 2011. We will not recapture any
Excess unobligated State funds in the amount of $69,038 will be captured from PY 2012 formula allotted funds for the Dislocated Worker program for one State and distributed by formula to PY 2012 dislocated worker funds for eligible States. The description of the methodology used for the
WIA Section 132(c) requires the Governor to prescribe equitable procedures for making funds available from the State and local areas in the event that the State is required to make funds available for reallotment.
(1) ETA computes the State's total amount of PY 2011 State obligations (including Fiscal Year (FY) 2012 funds) for the Dislocated Worker (DW) program. State obligations are considered to be the total of the DW statewide activities obligations, Rapid Response obligations, and 100 percent of local DW program authorized (which includes local admin authorized). The State's total unobligated balance for the DW program is the PY 2011 DW allotment amount (minus the total DW obligations) (adjusted for recapture/reallotment and statutory formula-based rescissions, if applicable. This year a rescission was applicable to all States that the recapture for Maine was applicable, but reallotment for all other States was not applicable). (For reallotment purposes, DW allotted funds transferred to the Navajo Nation are added back to Arizona, New Mexico, and Utah Local DW authorized amounts.)
(2) Section 667.150 of the regulations provides that the recapture calculations exclude the reserve for state administration. Data on State administrative authorized and obligated amounts are not normally available on WIA 9130 financial reports. In the preliminary calculation to determine States potentially liable for recapture, the DW portion of the State administrative amount authorized is estimated by calculating the five percent maximum amount for State DW administrative costs using the DW State allotment amounts (adjusted for recapture/reallotment and statutory formula-based rescissions). For the DW portion of the State administrative amount obligated, 100 percent of the estimated authorized amount is treated as obligated, although this estimate of State administration obligations is limited by reported statewide activities obligations overall.
(3) ETA requests that those States potentially liable for recapture provide additional data on state administrative amounts which are not regularly reported on the PY 2011 and FY 2012 statewide activities reports. The additional information requested is the amount of statewide activities funds that were authorized and obligated for State administration as of June 30, 2012. If a State provides actual State DW administrative costs, authorized and obligated, in the comments section of revised 9130 reports, this data replaces the estimates. Based on the requested additional actual data submitted by potentially liable States on revised reports, the DW total allotment for these States is reduced by the DW portion of the State administrative amount authorized. Likewise, the DW total obligations for these States are reduced by the DW portion of the obligated State administrative funding.
(4) States (including those adjusted by State administrative data) with unobligated balances exceeding 20 percent of the combined PY2011/FY2012 DW allotment amount (adjusted for recapture/reallotment and statutory formula-based rescissions) will have their PY 2012 DW funding (from the FY 2013 portion) reduced (recaptured) by the amount of the excess.
(5) Finally, States with unobligated balances which do not exceed 20 percent (eligible states) will receive a share of the total recaptured amount (based on their share of the total PY 2011/FY2012 DW allotments of eligible states) in their PY 2012 DW funding (FY 2013 portion).
National Aeronautics and Space Administration (NASA).
Notice of Centennial Challenges 2014 Night Rover Challenge.
This notice is issued in accordance with 51 U.S.C. 20144(c).
The 2014 Night Rover Challenge is scheduled and teams that wish to compete may register. Centennial Challenges is a program of prize competitions to stimulate innovation in technologies of interest and value to NASA and the nation. The 2014 Night Rover Challenge is a prize competition designed to encourage development of new energy storage technologies or application of existing storage technologies in unique ways for application in extreme space environments. Competitors will need to demonstrate high energy density storage systems (>330w–hr/kg) that would enable a rover to operate throughout lunar darkness cycles. Cleantech Open of Palo Alto, California administers the Challenge for NASA. NASA is providing the $1,500,000 prize purse.
2014 Night Rover Challenge will be held January 20–April 4, 2014.
2014 Night Rover Challenge will be conducted at the NASA Glenn Research Center, Plumbrook Station located in Sandusky, OH.
To register for or get additional information regarding the 2014 Night Rover Challenge, please visit:
For general information on the NASA Centennial Challenges Program please visit:
Solar energy is a renewable source that would be available on the Moon and at other destinations in space. To enable practical system demonstrations of diverse design solutions by independent teams, Phase I of this Challenge will be conducted in an ambient Earth environment in a NASA test chamber. The Phase I Challenge will be to demonstrate a portable energy storage system through two cycles of lunar daylight and darkness. During the daylight period, systems will receive electrical energy from a simulated solar collector. During darkness, the stored energy will be used for simulated tasks of thermal management, scientific experimentation, communications, and rover movement. The competitors may store and extract the energy by any means they desire. The winning system
A planned future Phase II Challenge will entail testing energy storage systems in NASA thermal and thermal-vacuum chambers to demonstrate applicability to the space and lunar environment.
The total Night Rover Challenge purse is $1,500,000 (one million five hundred thousand U.S. dollars). Prizes will be offered for entries that meet specific requirements detailed in the Night Rover Challenge Rules.
To be eligible to win a NASA prize, competitors must (1) Register and comply with all requirements in the rules and team agreement; (2) in the case of a private entity, shall be incorporated in and maintain a primary place of business in the United States, and in the case of an individual, whether participating singly or in a group, shall be a citizen or permanent resident of the United States; and (3) shall not be a Federal entity or Federal employee acting within the scope of their employment.
The NASA prize purse will be awarded to the energy storage systems with the highest energy density that meet all requirements of the competition. The complete rules and team agreement for the 2014 Night Rover Challenge can be found at:
National Aeronautics and Space Administration.
Notice of Availability of Inventions for Licensing.
Patent applications on the inventions listed below assigned to the National Aeronautics and Space Administration, have been filed in the United States Patent and Trademark Office, and are available for licensing.
April 2, 2013.
James J. McGroary, Patent Counsel, Marshall Space Flight Center, Mail Code LS01, Huntsville, AL 35812; telephone (256) 544–0013; fax (256) 544–0258.
NASA Case No.: MFS–32761–1–CIP: Multi-Channel Flow Plug with Eddy Current Minimization for Metering, Mixing, and Conditioning;
NASA Case No.: MFS–32761–1–CON: Multi-Channel Flow Plug with Eddy Current Minimization for Meeting, Mixing, and Conditioning.
National Aeronautics and Space Administration.
Notice of Availability of Inventions for Licensing.
Patent applications on the inventions listed below assigned to the National Aeronautics and Space Administration, have been filed in the United States Patent and Trademark Office, and are available for licensing.
April 2, 2013.
Robin W. Edwards, Patent Counsel, Langley Research Center, Mail Stop 30, Hampton, VA 23681–2199; telephone (757) 864–3230; fax (757) 864–9190.
NASA Case No.: LAR–18202–1: Method for Ground-to-Space Laser Calibration System;
NASA Case No.: LAR–18132–1: Modeling of Laser Ablation and Plume Chemistry in a Boron Nitride Nanotube Production Rig;
NASA Case No.: LAR–17681–2: System for Repairing Cracks in Structures.
National Aeronautics and Space Administration.
Notice of Availability of Inventions for Licensing.
Patent applications on the inventions listed below assigned to the National Aeronautics and Space Administration, have been filed in the United States Patent and Trademark Office, and are available for licensing.
April 2, 2013.
Robert H. Earp, III, Patent Attorney, Glenn Research Center at Lewis Field, Code 21–14, Cleveland, OH 44135; telephone (216) 433–5754; fax (216) 433–6790.
NASA Case No.: LEW–18889–1: High Speed Idle Engine Control Mode;
NASA Case No.: LEW–18629–1: Electrospray Collection of Lunar Dust;
NASA Case No.: LEW–18565–1: Catalytic Microtube Rocket Igniter;
NASA Case No.: LEW–18605–2: Dual-Mode Hybrid-Engine (DMH-Engine): A Next-Generation Electric Propulsion Thruster;
NASA Case No.: LEW–18919–1: Wireless controlled Chalcogenide Nanoionic Radio Frequency Switch;
NASA Case No.: LEW–18893–1: Novel Aerogel-Based Antennas (ABA) for Aerospace Applications;
NASA Case No.: LEW–18752–1: Large Strain Transparent Magneto-active Polymer Nanocomposites.
National Aeronautics and Space Administration.
Notice of Availability of Inventions for Licensing.
Patent applications on the inventions listed below assigned to the National Aeronautics and Space Administration, have been filed in the United States Patent and Trademark Office, and are available for licensing.
April 2, 2013.
Robert M. Padilla, Patent Counsel, Ames Research Center, Code 202A–4, Moffett Field, CA 94035–1000; telephone (650) 604–5104; fax (650) 604–2767.
NASA Case No.: ARC–16644–1: Variable Camber Continuous Aerodynamic Control Surfaces and Methods for Active Wing Shaping Control;
NASA Case No.: ARC–16846–1: Dynamic Weather Routes Tool;
NASA Case No.: ARC 16902–1: Nanosensors for Medical Diagnosis;
NASA Case No.: ARC 16942–2: A New Family of Low Density Flexible Ablators;
NASA Case No.: ARC 16450–1CIP: Distributed Prognostics and Health Management with a Wireless Network Architecture;
NASA Case No.: ARC 16607–1: An Approach to Make Flexible Ablators that are Flexible Char Formers;
NASA Case No.: ARC 16340–1: Method for Formation and Manufacture of Carbon Nanotube Mesh Bucky Paper Capsules for Transplantation of Cells and Tissue and Implantation of Medical Devices;
NASA Case No.: ARC 16844–1: Adaptive Control and Disturbance Rejection of Non-Minimum Phase Plants Using Residual Mode Filters.
National Aeronautics and Space Administration.
Notice of Availability of Inventions for Licensing.
Patent applications on the inventions listed below assigned to the National Aeronautics and Space Administration, have been filed in the United States Patent and Trademark Office, and are available for licensing.
April 2, 2013.
Bryan A. Geurts, Patent Counsel, Goddard Space Flight Center, Mail Code 140.1, Greenbelt, MD 20771–0001; telephone (301) 286–7351; fax (301) 286–9502.
NASA Case No.: GSC–16193–1: Improved Approach to Exoplanet Coronagraphy.
National Aeronautics and Space Administration.
Notice of Intent to Grant Exclusive License.
This notice is issued in accordance with 35 U.S.C. 209(e) and 37 CFR 404.7(a)(1)(i). NASA hereby gives notice of its intent to grant an exclusive license in the United States to practice the invention described and claimed in U.S. Patent Application Serial No. 13/800,692 entitled Interconnect Device and Assemblies Made Therewith, to Topline Corporation, having its principal place of business in Irvine, CA. The patent rights in these inventions as applicable have been assigned to the United States of America as represented by the Administrator of the National Aeronautics and Space Administration. The prospective partially exclusive license will comply with the terms and conditions of 35 U.S.C. 209 and 37 CFR 404.7.
The prospective exclusive license may be granted unless, within fifteen (15) days from the date of this published notice, NASA receives written objections including evidence and argument that establish that the grant of the license would not be consistent with the requirements of 35 U.S.C. 209 and 37 CFR 404.7. Competing applications completed and received by NASA within fifteen (15) days of the date of this published notice will also be treated as objections to the grant of the contemplated exclusive license.
Objections submitted in response to this notice will not be made available to the public for inspection and, to the extent permitted by law, will not be released under the Freedom of Information Act, 5 U.S.C. 552.
Objections relating to the prospective license may be submitted to Mr. James J. McGroary, Chief Patent Counsel/LS01, Marshall Space Flight Center, Huntsville, AL 35812, (256) 544–0013.
Mr. Sammy A. Nabors, Technology Transfer Office/ZP30, Marshall Space Flight Center, Huntsville, AL 35812, (256) 544–5226. Information about other NASA inventions available for licensing can be found online at
National Aeronautics and Space Administration (NASA).
Notice of a Privacy Act system of records.
Each Federal agency is required by the Privacy Act of 1974 to publish a description of a system of records containing personal information it establishes and maintains. This notice provides notification that NASA has established an internal system pertaining to its Guest Operations that maintains a listing of individuals invited to view one of NASA's satellite launches, Expendable Launch Vehicle (ELV) launches, or other significant events.
Submit comments within 60 calendar days from the date of this publication.
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,
NASA Guest Operations System.
None.
Location 1, as set forth in Appendix A.
This system maintains information on individuals who have been invited to attend NASA events. These individuals can be members of the NASA community such as principal and prominent management and staff officials, program and project managers, scientists, engineers, speakers, other selected employees involved in newsworthy activities, and other participants in Agency programs, as well members of the general public who are invited to attend NASA events.
Records in this system may include personal information about the individuals invited or attending events, such as their names, home addresses, nationality and passport information.
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. Records from this system may be disclosed in accordance with NASA standard routine uses as set forth in Appendix B.
The information contained in this system of records is compiled, updated, and maintained as electronic records in a central database on a secure server at NASA Headquarters.
Records are searched and retrieved by name, business, or address.
An approved security plan for this system has been established in accordance with OMB Circular A–130, Management of Federal Information Resources. Individuals will have access to the system only in accordance with approved authentication methods. Only key authorized employees with appropriately configured system roles can access the system and only from workstations within the NASA Intranet.
Records are retained in a computer database and managed, retained and dispositioned in accordance with the guidelines defined in the NASA Records Retention Schedules (NRRS), Schedule 1, Item 37A.
System Manager: Guest Operations Manager, Office of Communications, Location 1, as set forth in Appendix A.
Individuals interested in inquiring about their records should notify the system manager.
Individuals who wish to gain access to their records should submit their request in writing to the system manager.
The NASA regulations governing access to records, procedures for contesting the contents and for appealing initial determinations are set forth in 14 CFR part 1212.
The information contained in the GOS is obtained directly from the individuals, who provide the information on a voluntary basis.
None.
National Aeronautics and Space Administration (NASA).
Notice of Privacy Act system of records.
Each Federal agency is required by the Privacy Act of 1974 to publish a description of a system of records containing personal information it establishes and maintains. This notice provides notification that NASA has established an internal system of records pertaining to carpool, parking, and other aspects of employee transit and transit benefits.
Submit comments within 60 calendar days from the date of this publication.
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,
Parking and Transit System (PATS)
None.
Locations 1 and 4, as set forth in Appendix A.
This system maintains information on NASA civil servants and contractors who are holders of parking permits; applicants or members of carpools, vanpools and other ridesharing programs; applicants and recipients of fare subsidies issued by NASA; and applicants for other NASA transit benefit programs.
Records in this system may include information about individuals, including name, home address, badge number, monthly commuting cost, email address, years of government service, grade, personal vehicle make and model, and person vehicle license number. These records may be captured as parking, rideshare, or other transit program applications, status or participation reports of individuals' participation in the programs.
51 U.S.C. 20113(a); 44 U.S.C. 3101; 40 U.S.C. Section 471; and, 40 U.S.C. Section 486.
Any disclosures of information will be compatible with the purpose for which the Agency collected the information, which is the issuance of NASA Parking Permits and NASA Fare Subsidies.
Records in this system may be disclosed:
1. To other Federal agencies to confirm that an individual is not receiving transit benefits from multiple agencies concurrently.
2. In accordance with the NASA Standard Routine Uses as listed in Appendix B.
Records are stored in hard copy and electronically in systems on secure NASA servers.
Records are retrieved by name or by zip code of residence.
Hard copy records are kept in locked cabinets. Electronic records are maintained in NASA systems with approved security plans established in accordance with OMB Circular A–130, Management of Federal Information Resources. Only key authorized employees in parking and fare subsidy management offices whose official duties require access and who possess appropriately configured system roles have access to the systems in accordance with approved authentication methods can access the system.
Records are maintained and disposed of in accordance with NASA Records Retention Schedule 6, Item 11 and General Records Schedule 9, Item 7.
Transportation Officer, Headquarters Facilities and Administrative Services Division, Location 1, as set forth in Appendix A.
Subsystem Manager: Transportation Subsidy Program Lead, Logistics Management Division, Location 4, as set forth in Appendix A.
Individuals interested in inquiring about their records should notify the System Manager or Subsystem Manager at the addresses given above.
Individuals who wish to gain access to their records should submit their request in writing to the System Manager or Subsystem Manager at the address given above.
The NASA regulations governing access to records and procedures for contesting the contents and for appealing initial determinations are set forth in 14 CFR Part 1212.
Information is provided by individuals in applications submitted for parking permits, carpool and vanpool membership, ridesharing information, and fare subsidies.
None.
Pursuant to Section 189a. (2) of the Atomic Energy Act of 1954, as amended (the Act), the U.S. Nuclear Regulatory Commission (NRC) is publishing this regular biweekly notice. The Act requires the Commission publish notice of any amendments issued, or proposed to be issued and grants the Commission the authority to issue and make immediately effective any amendment to an operating license or combined license, as applicable, upon a determination by the Commission that such amendment involves no significant hazards consideration, notwithstanding the pendency before the Commission of a request for a hearing from any person.
This biweekly notice includes all notices of amendments issued, or proposed to be issued from March 7, 2013, to March 20, 2013. The last biweekly notice was published on March 19, 2013 (78 FR 16876).
You may access information and comment submissions related to this document, which the NRC possesses and is publicly available, by searching on
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For additional direction on accessing information and submitting comments, see “Accessing Information and Submitting Comments” in the
Please refer to Docket ID NRC–2013–0060 when contacting the NRC about the availability of information regarding this document. You may access information related to this document, which the NRC possesses and is publicly available, by the following methods:
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Please include Docket ID NRC–2013–0060 in the subject line of your comment submission, in order to ensure that the NRC is able to make your comment submission available to the public in this docket.
The NRC cautions you not to include identifying or contact information that that you do not want to be publicly disclosed in your comment submission. The NRC will post all comment submissions at
If you are requesting or aggregating comments from other persons for submission to the NRC, then you should inform those persons not to include identifying or contact information that they do not want to be publicly disclosed in their comment submission. Your request should state that the NRC
The Commission has made a proposed determination that the following amendment requests involve no significant hazards consideration. Under the Commission's regulations in section 50.92 of Title 10 of the
The Commission is seeking public comments on this proposed determination. Any comments received within 30 days after the date of publication of this notice will be considered in making any final determination.
Normally, the Commission will not issue the amendment until the expiration of 60 days after the date of publication of this notice. The Commission may issue the license amendment before expiration of the 60-day period provided that its final determination is that the amendment involves no significant hazards consideration. In addition, the Commission may issue the amendment prior to the expiration of the 30-day comment period should circumstances change during the 30-day comment period such that failure to act in a timely way would result, for example in derating or shutdown of the facility. Should the Commission take action prior to the expiration of either the comment period or the notice period, it will publish in the
Within 60 days after the date of publication of this notice, any person(s) whose interest may be affected by this action may file a request for a hearing and a petition to intervene with respect to issuance of the amendment to the subject facility operating license or combined license. Requests for a hearing and a petition for leave to intervene shall be filed in accordance with the Commission's “Agency Rules of Practice and Procedure” in 10 CFR part 2. Interested person(s) should consult a current copy of 10 CFR 2.309, which is available at the NRC's PDR, located at One White Flint North, Room O1–F21, 11555 Rockville Pike (first floor), Rockville, Maryland 20852. The NRC regulations are accessible electronically from the NRC Library on the NRC's Web site at
As required by 10 CFR 2.309, a petition for leave to intervene shall set forth with particularity the interest of the petitioner in the proceeding, and how that interest may be affected by the results of the proceeding. The petition should specifically explain the reasons why intervention should be permitted with particular reference to the following general requirements: (1) The name, address, and telephone number of the requestor or petitioner; (2) the nature of the requestor's/petitioner's right under the Act to be made a party to the proceeding; (3) the nature and extent of the requestor's/petitioner's property, financial, or other interest in the proceeding; and (4) the possible effect of any decision or order which may be entered in the proceeding on the requestor's/petitioner's interest. The petition must also identify the specific contentions which the requestor/petitioner seeks to have litigated at the proceeding.
Each contention must consist of a specific statement of the issue of law or fact to be raised or controverted. In addition, the requestor/petitioner shall provide a brief explanation of the bases for the contention and a concise statement of the alleged facts or expert opinion which support the contention and on which the requestor/petitioner intends to rely in proving the contention at the hearing. The requestor/petitioner must also provide references to those specific sources and documents of which the petitioner is aware and on which the requestor/petitioner intends to rely to establish those facts or expert opinion. The petition must include sufficient information to show that a genuine dispute exists with the applicant on a material issue of law or fact. Contentions shall be limited to matters within the scope of the amendment under consideration. The contention must be one which, if proven, would entitle the requestor/petitioner to relief. A requestor/petitioner who fails to satisfy these requirements with respect to at least one contention will not be permitted to participate as a party.
Those permitted to intervene become parties to the proceeding, subject to any limitations in the order granting leave to intervene, and have the opportunity to participate fully in the conduct of the hearing.
If a hearing is requested, the Commission will make a final determination on the issue of no significant hazards consideration. The final determination will serve to decide when the hearing is held. If the final determination is that the amendment request involves no significant hazards consideration, the Commission may issue the amendment and make it immediately effective, notwithstanding the request for a hearing. Any hearing held would take place after issuance of the amendment. If the final determination is that the amendment request involves a significant hazards consideration, then any hearing held would take place before the issuance of any amendment.
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
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 the NRC guidance available on the NRC's 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's 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 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 upon 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 which is available to the public at
Petitions for leave to intervene must be filed no later than 60 days from the date of publication of this notice. Requests for hearing, petitions for leave to intervene, and motions for leave to file new or amended contentions that are filed after the 60-day deadline will not be entertained absent a determination by the presiding officer that the filing demonstrates good cause by satisfying the following three factors in 10 CFR 2.309(c)(1): (i) The information upon which the filing is based was not previously available; (ii) the information upon which the filing is based is materially different from information previously available; and (iii) the filing has been submitted in a timely fashion based on the availability of the subsequent information.
For further details with respect to this license amendment application, see the application for amendment which is available for public inspection at the NRC's PDR, located at One White Flint North, Room O1–F21, 11555 Rockville Pike (first floor), Rockville, Maryland 20852. Publicly available documents created or received at the NRC are accessible electronically through ADAMS in the NRC Library at
Will operation of the facility in accordance with the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No.
The accident of concern related to the proposed change is the FHA [fuel handling accident]. This accident assumes a dropped fuel assembly with resulting damage and release of the gap activity from the entire assembly. The FHA assumes that fuel movement is delayed for some time period after shutdown to accommodate for radioactive decay of the short-lived fission products. The probability of a FHA occurrence is dependent on moving fuel not when the fuel movement occurs. Reducing the decay time required by TS
Reducing the decay time requirement in TS
Based on the reasons presented above, operation of the facility in accordance with the proposed amendment would not involve a significant increase in the probability or consequences of an accident previously evaluated.
Will operation of the facility in accordance with the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?
Response: No.
The proposed change will not create the possibility of a new or different kind of accident from any accident previously evaluated. No new accident will be created as a result of reducing the decay time requirement in TS
Therefore, the proposed change does not create the possibility of a new or different kind of accident from any previously evaluated.
Will operation of the facility in accordance with the proposed change involve a significant reduction in the margin of safety?
Response: No.
The proposed change does not significantly reduce the margin of safety. The current analysis of record for the FHA already accounts for irradiated fuel with at least 100 hours of decay. This approved analysis has shown that the projected doses will remain within applicable regulatory limits; therefore, the margin of safety is unchanged.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment request involves no significant hazards consideration.
1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously identified?
Response: No.
The proposed change would not change the current limiting EDG [emergency diesel generator] failure but would credit four rather than three can cooler units for containment heat removal. Four fan cooler units are available after the single failure. The fan cooler units are not accident initiators so the probability of an accident does not increase. Crediting all four fan cooler units will keep the post accident containment pressure within current limits and therefore does not increase the probability or consequences of a previously evaluated accident, but is a change from the analyses approved by the NRC [Nuclear Regulatory Commission] during stretch power uprate.
Therefore the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.
2. Does the change create the possibility of a new of different kind of accident from any accident previously evaluated?
Response: No.
There are no changes to design, no changes to operating procedures, and the revised licensing basis change is consistent with the available equipment following the postulated worst case single failure.
Therefore the proposed change does not create the possibility of a new or different kind of accident from any accident previously evaluated.
3. Does the proposed change involve a significant reduction in a margin of safety?
Response: No.
The change reflects the credit for equipment that was always available but not previously credited (as a conservatism) in the licensing basis analyses. With credit for four fan cooler units, the post accident containment pressure remains within current limits and there is no reduction in a margin of safety.
Therefore the proposed change does not involve a significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment request involves no significant hazards consideration.
1. Operation of the facility in accordance with the proposed amendment would not involve a significant increase in the probability of occurrence of consequences of an accident previously evaluated.
The proposed TS changes do not involve a significant increase in the probability or consequences of an accident previously evaluated. Except for a setpoint change for automatic PORV [power-operated relief valve] actuation, there are no physical changes to the plant being introduced by the proposed changes to the heatup and cooldown limitation curves. The proposed changes do not modify the RCS pressure boundary. That is, there are no changes in operating pressure, materials, or seismic loading. The proposed changes do not adversely affect the integrity of the RCS pressure boundary such that its function in the control of radiological consequences is affected. The proposed heatup and cooldown limitation curves were generated in accordance with the fracture toughness requirements of 10CFR50 [10 CFR 50] Appendix G, and ASME B&PV code [American Society of Mechanical Engineers Boiler and Pressure Vessel Code], Section XI, Appendix G edition with 2000 Addenda. The proposed heatup and cooldown limitation curves were established in compliance with the methodology used to calculate and predict effects of radiation on embrittlement of RPV [reactor pressure vessel] beltline materials. Use of this methodology provides compliance with the intent of 10CFR50 [10 CFR 50] Appendix G and provides margins of safety that ensure non-ductile failure of the RPV will not occur. The proposed heatup and cooldown limitation curves prohibit operation in regions where it is possible for non-ductile failure of carbon and low alloy RCS materials to occur. Hence, the primary coolant pressure boundary integrity will be maintained throughout the limit of applicability of the curves, 48 EFPY [Effective Full Power Years].
Operation within the proposed LTOP limits ensures that overpressurization of the RCS at low temperatures will not result in component stresses in excess of those allowed by the ASME B&PV Code Section XI Appendix G.
Consequently, the proposed changes do not involve a significant increase in the probability or the consequences of an accident previously evaluated.
2. Operation of the facility in accordance with the proposed amendment would not create the possibility of a new or different kind of accident from any accident previously evaluated.
The proposed TS changes do not create the possibility of a new or different kind of accident from any accident previously evaluated. No new modes of operation are introduced by the proposed changes. The proposed changes will not create any failure mode not bounded by previously evaluated accidents. Further, the proposed changes to the heatup and cooldown limitation curves and the LTOP limits do not affect any activities or equipment other than the RCS pressure boundary and do not create the possibility of a new or different kind of accident from any accident previously evaluated.
Consequently, the proposed changes do not create the possibility of a new or different kind of accident, from any accident previously evaluated.
3. Operation of the facility in accordance with the proposed amendment would not involve a significant reduction in the margin of safety.
The Proposed TS changes do not involve a significant reduction in the margin of safety. The revised heatup and cooldown limitation curves and LTOP limits are established in accordance with current regulations and the ASME B&PV Code 1998 edition with 2000 Addenda. These proposed changes are acceptable because the ASME B&PV Code maintains the margin of safety required by 10CFR50.55(a) [10 CFR 50.55(a)]. Because operation will be within these limits, the RCS materials will continue to behave in a non-brittle manner consistent with the original design bases.
The proposed changes to the allowable operation of charging and safety injection pumps when LTOP is required to be operable is consistent with the IP2 licensing bases as established in TS Amendment 262.
Therefore, Entergy has concluded that the proposed changes do not involve a significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, and with the changes noted above in square brackets, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment request involves no significant hazards consideration.
1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No.
The proposed change would not change the current EDG [emergency diesel generator] failure but limits the RWST temperature to ≤105 °F and containment pressure to ≤1.5 psig [pounds per square inch gauge] (when RWST temperature is >95 °F or containment/accumulator temperature is >125 °F). The proposed change also removes a redundant TS for Containment testing and corrects the peak pressure in the containment testing program. The initial conditions assumed in accident analysis are not accident initiators so the probability of an accident does not increase. The change in initial conditions compensates for the error corrections and maintains the post accident containment pressure within 0.38 psig of the current value and within Containment testing limits and therefore does not increase the probability or consequences of a previously evaluated accident. Therefore the proposed change does not involve a significant increase in the
2. Does the change create the possibility of a new or different kind of accident from any accident previously evaluated?
Response: No.
The change to the initial conditions assumed in the analysis for peak containment pressure, the removal of a redundant Technical Specification and the correction to the peak pressure limit in the Containment testing program do not create the possibility of a new or different accident. There are no changes to design or operating procedures that could create a new or different kind of accident since the changes only affect the initiating conditions. The revised analysis is consistent with the available equipment following the postulate worst case single failure.
Therefore the proposed change does not create the possibility of a new or different kind of accident from any accident previously evaluated.
3. Does the proposed change involve a significant reduction in a margin of safety?
Response: No.
The change in peak containment pressure is from 42 psig to 42.38 psig as a result of the error corrections of NSAL–11–5 and change to the initial conditions for the RWST temperature and containment pressure. There is an insignificant impact on other programs due to change in peak containment pressure, which remains well below the containment design pressure of 47 psig. Therefore there is not significant reduction in margin.
Therefore the proposed change does not involve a significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment request involves no significant hazards consideration.
1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No.
The proposed change removes License Conditions within the LSCS Unit 2 Operating License related to interim configurations of the SFP during the installation of the NETCO–SNAP–IN® inserts and the required completion date for installation. All changes proposed by EGC in this license amendment request are administrative in nature because they remove License Conditions that have either been satisfied or that are no longer applicable. There are no physical changes to the facilities, nor any changes to the station operating procedures, limiting conditions for operation, or limiting safety system settings.
Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.
2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?
Response: No.
The proposed change removes License Conditions within the LSCS Unit 2 Operating License related to interim configurations of the SFP during the installation of the NETCO–SNAP–IN® inserts and the required completion date for installation. There are no changes to the SFP criticality analysis associated with the proposed change. No physical changes to the plant are proposed, and there are no changes to the manner in which the plant is operated. Rather, the proposed change is administrative because it involves removing License Conditions that have either been satisfied or that are no longer applicable.
Therefore, the proposed change does not create the possibility of a new or different kind of accident from any accident previously evaluated.
3. Does the proposed change involve a significant reduction in a margin of safety?
Response: No.
The proposed change removes License Conditions within the LSCS Unit 2 Operating License related to interim configurations of the SFP during the installation of the NETCO–SNAP–IN® inserts and the required completion date for installation. Plant safety margins are established through limiting conditions for operation, limiting safety system settings, and safety limits specified in Technical Specifications. The proposed change does not alter these established safety margins. The proposed change does not alter the criticality analysis for the SFP and does not affect the SFP criticality safety margin. The proposed change is administrative because it involves removing License Conditions that have either been satisfied or that are no longer applicable.
Therefore, the proposed change does not involve a significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the requested amendments involve no significant hazards consideration.
1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No.
The proposed change makes no physical changes to the plant, nor does it alter any of the assumptions or conditions upon which the UHS is designed. These assumptions and conditions as described in the LSCS UFSAR include failure of the cooling lake dike, a loss of offsite power, and a DBA LOCA on one unit and a normal shutdown of the other unit.
The accidents analyzed in the UFSAR are assumed to be initiated by the failure of plant structures, systems, or components (SSCs). An inoperable UHS is not an initiator of any analyzed events as described in the UFSAR. The impact on the structural integrity of the UHS due to a potential increase water temperature prior to and during the UHS design basis event has been evaluated, and does not increase the probability of the failure of the cooling lake dike. The proposed temperature limit for cooling water supplied to the plant from the CSCS Pond could reduce the commercial capability of the LSCS units; however, it does not result in an increase in the probability of occurrence for any of the events described in the UFSAR.
The basis provided in Regulatory Guide 1.27, “Ultimate Heat Sink for Nuclear Power Plants,” Revision 1, dated March 1974, was employed for the temperature analysis of the LSCS UHS to implement General Design Criteria 2, “Design bases for protection
The analysis shows that with an initial UHS temperature less than or equal to the proposed time-of-day-based limit, the required safety-related heat loads can be adequately cooled for 30 days while continuing to ensure safety-related cooling water temperature remains less than the design temperature for LSCS, Units 1 and 2.
Based on the above, it has been demonstrated that the change of the initial temperature limit for cooling water supplied to the plant from the CSCS Pond to less than or equal to a temperature based on the time of day will not impede the ability of the equipment and components cooled by the UHS during a UHS design basis event to perform their safety functions.
There is no impact of this change on LSCS safety analyses including the consequences of all postulated events since all required safety-related equipment continues to perform as designed. The effects of the proposed change on the ability of the UHS to assure that a 30-day supply of water is available considering losses due to evaporation, seepage, and firefighting have been considered. Sufficient inventory remains available to mitigate the design basis event for the LSCS UHS for the required 30-day period.
Therefore, the proposed activity does not involve a significant increase in the probability or consequences of an accident previously evaluated.
2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?
Response: No.
The proposed change does not physically alter the operation, testing, or maintenance of any plant SSCs beyond operating with a UHS temperature limit based on the time of day. The proposed change is bounded by existing design analyses. Moreover, the UHS temperature does not initiate accident precursors. The impact of increased UHS temperature can affect the commercial operation of the plant, but the proposed change would not create any accident not considered in the LSCS UFSAR.
This proposed change will not alter the manner in which equipment operation is initiated, nor will the functional demands on credited equipment be changed. No alteration in the procedures that ensure the LSCS units remain within analyzed limits is proposed, and no change is being made to procedures relied upon to respond to an off-normal event.
As such, no new failure modes are being introduced. The proposed change does not alter assumptions made in the LSCS safety analysis.
Changing the temperature of cooling water supplied to the plant from the CSCS Pond (i.e., the UHS) as proposed has no impact on plant accident response. The proposed temperature limits do not introduce new failure mechanisms for SSCs. An engineering analysis performed to support the change in temperature of cooling water supplied to the plant from the CSCS Pond provides the basis to conclude that the equipment is adequately designed for operation as proposed.
All systems that are important to safety will continue to be operated and maintained within their design bases, and the proposed change will continue to ensure that all associated systems and components are operated reliably within their design capabilities.
The proposed change will ensure the maximum temperature of the cooling water supplied to the plant during the UHS design basis event remains less than the current safety-related cooling water design temperature for LSCS, Units 1 and 2. Therefore, there is no impact of this change on the LSCS safety analyses including inventory and cooling requirements for safety-related systems using the UHS as their cooling water supply.
All systems will continue to be operated within their design capabilities, no new failure modes are introduced, nor is there any adverse impact on plant equipment; therefore, the proposed change does not result in the possibility of a new or different kind of accident from any accident previously evaluated.
3. Does the proposed change involve a significant reduction in a margin of safety?
Response: No.
The margin of safety is determined by the design and qualification of the plant equipment, the operation of the plant within analyzed limits, and the point at which protective or mitigative actions are initiated. The proposed change does not impact any of these factors. There are no required design changes or equipment performance parameter changes associated with the proposed change. No protection setpoints are affected as a result of this change. The proposed change in the limit for the temperature of cooling water supplied to the plant from the CSCS Pond will not change the operational characteristics of the design of any equipment or system. All accident analysis assumptions and conditions will continue to be met.
Therefore, the proposed change does not involve a significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the requested amendments involve no significant hazards consideration.
1. The proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.
The proposed changes (1) remove the index from the TS, (2) correct an error in the units of activity for 100/E in TS 3.4.8, Reactor Coolant System Specific Activity, and (3) remove an incorrect, non-applicable reference in TS 6.8, Core Operating Limits Report. The proposed changes are all administrative in nature. The administrative changes are not initiators of any accident previously evaluated, and, consequently, the probability and consequences of an accident previously evaluated is not significantly increased.
Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.
2. The proposed change does not create the possibility of a new or different kind of accident from any previously evaluated.
The proposed changes are administrative in nature so no new or different accidents result from the proposed changes. The changes do not involve a physical alteration of the plant (i.e., no new or different type of equipment will be installed), a significant change in the method of plant operation, or new operator actions. The changes do not alter assumptions made in the safety analysis.
Therefore, the proposed change does not create the possibility of a new or different kind of accident from any accident previously evaluated.
3. The proposed changes do not involve a significant reduction in the margin of safety.
Margin of safety is associated with confidence in the ability of the fission product barriers (i.e., fuel cladding, reactor coolant system pressure boundary, and containment structure) to limit the level of radiation dose to the public. The proposed administrative changes do not involve a change in the method of plant operation, do not affect any accident analyses, and do not relax any safety system settings.
Therefore, the proposed change does not involve a significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment request involves NSHC.
1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No.
Operation of the Prairie Island Nuclear Generating Plant (PINGP) in accordance with the proposed amendment does not increase the probability or consequences of accidents previously evaluated. Engineering analyses, which may include engineering evaluations, probabilistic safety assessments, and fire modeling evaluations, have been performed to demonstrate that the performance-based requirements of National Fire Protection Association Standard 805 (NFPA 805) have been satisfied. The PINGP Updated Safety Analysis Report (USAR) documents the analyses of design basis accidents (DBAs) at PINGP. The proposed amendment does not adversely affect accident initiators nor alter design assumptions, conditions, or configurations of the facility that would increase the probability or consequences of accidents previously evaluated. Further, the changes to be made for fire hazard protection and mitigation do not adversely affect the ability of structures, systems, and components (SSCs) to perform their design functions, nor do they affect the postulated initiators or assumed failure modes for accidents described and evaluated in the USAR. SSCs required to safely shut down the reactor and to maintain it in a safe shutdown condition will remain capable of performing their design functions.
The purpose of this proposed amendment is to permit PINGP to adopt a new fire protection licensing basis which complies with the requirements in 10 CFR 50.48(a) and (c) and the guidance in Revision 1 of Regulatory Guide (RG) 1.205. The NRC considers that NFPA 805 provides an acceptable methodology and performance criteria for licensees to identify fire protection systems and features that are an acceptable alternative to the 10 CFR Part 50, Appendix R fire protection features (69 FR 33536; June 16, 2004). Engineering analyses, in accordance with NFPA 805, have been performed to demonstrate that the risk-informed, performance-based (RI–PB) requirements per NFPA 805 have been met.
NFPA 805, taken as a whole, provides an acceptable alternative to 10 CFR 50.48(b), satisfies 10 CFR 50.48(a) and General Design Criterion (GDC) 3 of Appendix A to 10 CFR Part 50, and meets the underlying intent of the NRC's existing fire protection regulations and guidance, and provides for defense-in-depth. The goals, performance objectives, and performance criteria specified in Chapter 1 of NFPA 805 ensure that if there are any increases in the net core damage frequency (CDF) or risk associated with this license amendment request (LAR) submittal, the increase will be small and consistent with the Commission's Safety Goal Policy.
Based on this, the implementation of this amendment does not significantly increase the probability of any accident previously evaluated. Equipment required to mitigate an accident remains capable of performing the assumed function(s). The proposed amendment will not affect the source term, containment isolation, or radiological release assumptions used in evaluating the radiological consequences of any accident previously evaluated.
Therefore, the consequences of any accident previously evaluated are not significantly increased with the implementation of the proposed amendment.
2. Does the proposed amendment create the possibility of a new or different kind of accident from any accident previously evaluated?
Response: No.
Operation of PINGP in accordance with the proposed amendment does not create the possibility of a new or different kind of accident from any accident previously evaluated. Any scenario or previously analyzed accident with offsite dose was included in the evaluation of DBAs documented in the USAR. The proposed change does not alter the requirements or function for systems required during accident conditions. Implementation of the new fire protection licensing basis which complies with the requirements in 10 CFR 50.48(a) and (c) and the guidance in Revision 1 of RG 1.205 will not result in new or different accidents.
The proposed amendment does not introduce new or different accident initiators nor alter design assumptions or conditions of the facility. The proposed amendment does not adversely affect the ability of SSCs to perform their design function. SSCs required to safely shut down the reactor and maintain it in a safe shutdown condition remain capable of performing their design functions.
The purpose of this amendment is to permit PINGP to adopt a new fire protection licensing basis which complies with the requirements in 10 CFR 50.48(a) and (c) and the guidance in Revision 1 of RG 1.205. The NRC considers that NFPA 805 provides an acceptable methodology and performance criteria for licensees to identify fire protection systems and features that are an acceptable alternative to the 10 CFR Part 50, Appendix R fire protection features (69 FR 33536, June 16, 2004). The requirements in NFPA 805 address only fire protection and the impacts of fire on the plant that have already been evaluated. Based on this, the implementation of this amendment does not create the possibility of a new or different kind of accident from any kind of accident previously evaluated. The proposed amendment does not introduce any new accident scenarios, transient precursors, failure mechanisms, malfunctions, or limiting single failures that could initiate a new accident. There will be no adverse effect or challenges imposed on a safety related system as a result of this proposed amendment.
Therefore, the possibility of a new or different kind of accident from any kind of accident previously evaluated is not created with the implementation of this amendment.
3. Does the proposed amendment involve a significant reduction in a margin of safety?
Response: No.
Operation of PINGP in accordance with the proposed amendment does not involve a significant reduction in a margin of safety.
The purpose of this amendment is to permit PINGP to adopt a new fire protection licensing basis which complies with the requirements in 10 CFR 50.48(a) and (c) and the guidance in Revision 1 of RG 1.205. The NRC considers that NFPA 805 provides an acceptable methodology and performance criteria for licensees to identify fire protection systems and features that are an acceptable alternative to the 10 CFR Part 50, Appendix R fire protection features (69 FR 33536; June 16, 2004). Engineering analyses, which may include engineering evaluations, probabilistic safety assessments, and fire modeling evaluations, have been performed to demonstrate that the performance-based methods do not result in a significant reduction in a margin of safety.
Based on this, the implementation of this amendment does not significantly reduce a margin of safety. The proposed changes are evaluated to ensure that the risk and safety margins are kept within acceptable limits.
Therefore, the transition to NFPA 805 does not involve a significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment requests involve no significant hazards consideration.
1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No.
The proposed amendment changes the low pressure safety limit in Technical Specification (TS) 2.1.1 from 785 psig [pounds per square inch gauge] to 557 psig based on the capabilities of the current critical power correlation used by Susquehanna (SPCB). The SPCB correlation is approved for CPR [critical power ratio] calculations by the NRC for reactor pressures > 571.4 psia [pounds per square inch absolute] and is listed as an approved analytical method in TS 5.6.5.b.
The proposed changes will not alter existing Final Safety Analysis Report (FSAR) design basis accident analysis assumptions, add any accident initiators, or affect the function of the plant safety-related structures, systems, or components (SSCs) as to how they are operated, maintained, modified, tested, or inspected.
Therefore, the proposed amendment does not involve a significant increase in the probability or consequences of an accident previously evaluated.
2. Does the proposed amendment create the possibility of a new or different kind of, accident from any accident previously evaluated?
Response: No.
The change to the Low Pressure Safety Limits does not result in the need for any new or different FSAR design basis accident analysis. The inclusion does not introduce new equipment that could create a new or different kind of accident, and no new equipment failure modes are created. In addition, the proposed change does not affect the function of any safety-related SSC as to how they are operated, maintained, modified, tested or inspected. As a result, no new accident scenarios, failure mechanisms, or limiting single failures are introduced as a result of this proposed amendment.
Therefore, the proposed amendment does not create a possibility for an accident of a new or different type than those previously evaluated.
3. Does the proposed amendment involve a significant reduction in a margin of safety?
Response: No.
The margin of safety is associated with the confidence in the ability of the fission product barriers (i.e., fuel cladding, reactor coolant pressure boundary, and containment structure) to limit the level of radiation to the public. Evaluation of the 10 CFR Part 21, “Reporting of Defects and Noncompliance” issue that identified the need for the proposed change determined that there was no decrease in the safety margin and therefore no threat to fuel cladding integrity. The proposed changes to the Low Pressure Safety Limits would not alter the way safety-related SSCs function and would not alter the way PPL Susquehanna Units 1 and 2 are operated. The proposed changes to the safety limit are within the capabilities of the existing NRC approved CPR correlation and ensure valid CPR calculations for the Anticipated Operational Occurrences (AOOs) defined in the FSAR. The proposed amendment would have no impact on the structural integrity of the fuel cladding, reactor coolant pressure boundary, or containment structure. Based on the above considerations, the proposed amendment would not degrade the confidence in the ability of the fission product barriers to limit the level of radiation to the public.
Therefore, the proposed change does not involve a significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment request involves no significant hazards consideration.
1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No.
The Control Room Emergency Air Conditioning System (CREACS) is not an initiator of or a precursor to any accident or transient. The CREACS system is in standby during normal operation and initiates in the
The design of plant equipment is not being modified by the proposed amendment. The elimination of the action to secure the isolation dampers between the normal Control Area Air Conditioning System (CAACS) and the CREACS when these dampers are inoperable and entering the actions for the inoperable control room boundary will ensure operation of the plant within the limits of the radiological, smoke and chemical hazard analyses. The intent of the original action for securing the inoperable isolation damper in the closed position was to maintain the boundary of the CRE. The actions for an inoperable control room boundary ensure that mitigating actions are implemented that maintain the CRE boundary within the limits of the radiological, smoke and chemical hazard analyses.
Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.
2. Does the proposed amendment create the possibility of a new or different kind of accident from any accident previously evaluated?
Response: No.
The proposed changes to the TS to implement the actions for an inoperable control room boundary when a normal CAACS and CREACS isolation damper is inoperable do not introduce any new accident precursors and do not involve any physical plant alterations or changes in the methods governing normal plant operation that could initiate a new or different kind of accident. The proposed amendment does not alter the function of the system to initiate and pressurize the control room envelope in the event of a DBA nor alter the ability to initiate CREACS in the recirculation mode in response to a fire or chemical release that occurs outside of the CRE.
Therefore, the proposed change does not create the possibility of a new or different kind of accident from any previously evaluated.
3. Does the proposed amendment involve a significant reduction in a margin of safety?
Response: No.
Margin of safety is related to the ability of the fission product barriers (fuel cladding, reactor coolant system, and primary containment) to perform their design functions during and following postulated accidents. The proposed amendment does not alter setpoints or limits established or assumed by the accident analyses. The control room envelope is considered a barrier for the control room operators during a design basis accident radiological release and a barrier in the event of a fire or chemical hazard that occurs outside of the CRE. Implementing the actions for an inoperable control room boundary in the event of an inoperable isolation damper between the normal CAACS and CREACS ensure operation of the plant within the limits of the radiological, smoke and chemical hazard analysis. The actions for an inoperable control room boundary ensure that mitigating actions are implemented that maintain the CRE boundary within the limits of the radiological, smoke and chemical hazard analyses. Therefore the plant will continue to be operated consistent with the plant safety analyses.
Therefore, the proposed change does not involve a significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment requests involve no significant hazards consideration.
Because this proposed change requires a departure from Tier 1 information in the Westinghouse Advanced Passive 1000 design control document (DCD), the licensee also requested an exemption from the requirements of the Generic DCD Tier 1 in accordance with 52.63(b)(1).
1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No.
The changes to provide a spring-assisted check valve located in the bypass line around the makeup stop check valve would continue to meet the existing design functions because the ASME Boiler and Pressure Vessel Code (ASME Code) Section III valves will maintain the flow isolation design function and preserve the Reactor Coolant System (RCS) pressure boundary safety function. The replacement of the Chemical and Volume Control System (CVS) zinc addition inboard containment isolation lift check valve with an air operated globe valve and addition of a pressure relief valve would continue to meet the containment isolation and RCS pressure boundary design functions because the replacement valves will be designed, analyzed, tested and qualified, including seismic qualification, to ASME Code Section III requirements. Separating the zinc and hydrogen injection paths and relocating the zinc injection point would continue to meet containment boundary requirements, including containment isolation and in-service testing, and preserve the RCS pressure boundary safety functions because the revised containment isolation configuration is consistent with those described in 10 CFR Part 50, Appendix A, General Design Criterion (GDC) 55, and the additional valves and piping will be qualified to ASME Code Section III. Because the proposed CVS changes would preserve the CVS safety-related design functions, the probability of an accident previously evaluated is not affected.
The CVS safety functions have been preserved, because the proposed CVS configuration changes, including revised valve types, will perform the same safety functions as the current design. The proposed CVS configuration changes would neither impact any accident source term parameter or fission product barrier nor affect radiological dose consequence analysis.
Therefore, the proposed changes do not involve a significant increase in the probability or consequences of an accident previously evaluated.
2. Does the proposed amendment create the possibility of a new or different kind of accident from any accident previously evaluated?
Response: No.
The additional containment penetration is similar in form, fit, and function to the CVS combined zinc/hydrogen containment penetration that is currently described in the Updated Final Safety Analysis Report. Because the CVS changes use valve types, piping, and a containment penetration consistent with those already described in the Updated Final Safety Analysis Report, no new failure modes or equipment failure initiators are introduced by these changes. Accordingly, the proposed changes do not create any new malfunctions, failure mechanisms, or accident initiators.
Therefore, the proposed amendment will not create the possibility of a new or different kind of accident from any accident previously evaluated.
3. Does the proposed amendment involve a significant reduction in a margin of safety?
Response: No.
The containment isolation and pressure relief functions would not be changed by this activity and are consistent with the existing design. The proposed CVS containment penetration is similar in form, fit, and function to existing CVS combined zinc/hydrogen containment penetration and, therefore, does not affect containment or its ability to perform its design function. The addition of these CVS components, including piping, a spring-assisted check valve, an air-operated containment isolation valve, a thermal relief valve and the additional CVS containment penetration do not impact a design basis or safety limit. Because the CVS design functions of controlling the RCS oxygen concentration, reducing radiation fields, containment isolation and overpressure protection within existing limits are not changed by this activity and are bounded by the existing design, there is no change to any current margin of safety.
Therefore, the proposed changes do not involve a significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment request involves no significant hazards consideration.
1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No.
The Integrated System Validation (ISV) provides a comprehensive human performance-based assessment of the design of the AP1000 Human-System Interface (HSI) resources, based on their realistic operation within a simulator-driven Main Control Room (MCR). The ISV is part of the overall AP1000 Human Factors Engineering (HFE) program. The changes are to the ISV Plan to clarify the scope and amend the details of the methodology. The ISV Plan is needed to perform, in the simulator, the scenarios described in the document. The functions and tasks allocated to plant personnel can still be accomplished after the proposed changes. The performance of the tests governed by the ISV Plan provides additional assurances that the operators can appropriately respond to plant transients. The ISV Plan does not affect the plant itself. Changing the ISV Plan does not affect prevention and mitigation of abnormal events, e.g., accidents, anticipated operational occurrences, earthquakes, floods and turbine missiles, or their safety or design analyses. No safety-related structure, system, component (SSC) or function is adversely affected. The changes do not involve nor interface with any SSC accident initiator or initiating sequence of events, and thus, the probabilities of the accidents evaluated in the UFSAR are not affected. Because the changes do not involve any safety-related SSC or function used to mitigate an accident, the consequences of the accidents evaluated in the UFSAR are not affected.
Therefore, there is no significant increase in the probability or consequences of an accident previously evaluated.
2. Does the proposed amendment create the possibility of a new or different kind of accident from any accident previously evaluated?
Response: No.
The changes to the ISV Plan affect the testing and validation of the Main Control Room and Human System Interface using a plant simulator. Therefore, the changes do not affect the safety-related equipment itself, nor do they affect equipment which, if it failed, could initiate an accident or a failure of a fission product barrier. No analysis is adversely affected. No system or design function or equipment qualification will be adversely affected by the changes. This activity will not allow for a new fission product release path, nor will it result in a new fission product barrier failure mode, nor create a new sequence of events that would result in significant fuel cladding failures. In addition, the changes do not result in a new failure mode, malfunction or sequence of events that could affect safety or safety-related equipment.
Therefore, this activity does not create the possibility of a new or different kind of accident than any accident previously evaluated.
3. Does the proposed amendment involve a significant reduction in a margin of safety?
Response: No.
The changes to the ISV Plan affect the testing and validation of the Main Control Room and Human System Interface using a plant simulator. Therefore, the changes do not affect the assessments or the plant itself. These changes do not affect safety-related equipment or equipment whose failure could initiate an accident, nor does it adversely interface with safety-related equipment or fission product barriers. No safety analysis or design basis acceptance limit/criterion is challenged or exceeded by the requested change.
Therefore, there is no significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment request involves no significant hazards consideration.
During the period since publication of the last biweekly notice, the Commission has issued the following amendments. The Commission has determined for each of these amendments that the application complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations. The Commission has made appropriate findings as required by the Act and the Commission's rules and regulations in 10 CFR Chapter I, which are set forth in the license amendment.
A notice of consideration of issuance of amendment to facility operating license or combined license, as applicable, proposed no significant hazards consideration determination, and opportunity for a hearing in connection with these actions, was published in the
Unless otherwise indicated, the Commission has determined that these amendments satisfy the criteria for categorical exclusion in accordance with 10 CFR 51.22. Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared for these amendments. If the Commission has prepared an environmental assessment
For further details with respect to the action see (1) The applications for amendment, (2) the amendment, and (3) the Commission's related letter, Safety Evaluation and/or Environmental Assessment as indicated. All of these items are available for public inspection at the NRC's Public Document Room (PDR), located at One White Flint North, Room O1–F21, 11555 Rockville Pike (first floor), Rockville, Maryland 20852. Publicly available documents created or received at the NRC are accessible electronically through the Agencywide Documents Access and Management System (ADAMS) in the NRC Library at
The Commission's related evaluation of the amendments is contained in a Safety Evaluation dated March 19, 2013.
The Commission's related evaluation of the amendment is contained in a Safety Evaluation dated March 7, 2013.
The Commission's related evaluation of the amendment is contained in a Safety Evaluation dated March 1, 2013.
No significant hazards consideration comments received: No.
For The Nuclear Regulatory Commission.
Nuclear Regulatory Commission [NRC–2013–0001]
Weeks of April 1, 8, 15, 22, 29, May 6, 2013
Commissioners' Conference Room, 11555 Rockville Pike, Rockville, Maryland
Public and Closed
This meeting will be webcast live at the Web address—
This meeting will be webcast live at the Web address—
There are no meetings scheduled for the week of April 8, 2013.
There are no meetings scheduled for the week of April 15, 2013.
This meeting will be webcast live at the Web address—
This meeting will be webcast live at the Web address—
There are no meetings scheduled for the week of April 29, 2013.
There are no meetings scheduled for the week of May 6, 2013.
*The schedule for Commission meetings is subject to change on short notice. To verify the status of meetings, call (recording)—301–415–1292. Contact person for more information: Rochelle Bavol, 301–415–1651.
The NRC Commission Meeting Schedule can be found on the Internet at:
The NRC provides reasonable accommodation to individuals with disabilities where appropriate. If you need a reasonable accommodation to participate in these public meetings, or need this meeting notice or the transcript or other information from the public meetings in another format (e.g. braille, large print), please notify Kimberly Meyer, NRC Disability Program Manager, at 301–287–0727, or by email at
This notice is distributed electronically to subscribers. If you no longer wish to receive it, or would like to be added to the distribution, please contact the Office of the Secretary, Washington, DC 20555 (301–415–1969), or send an email to
Securities and Exchange Commission (“Commission”).
Notice of an application for an order under sections 6(b) and 6(e) of the Investment Company Act of 1940 (the “Act”) granting an exemption from all provisions of the Act, except sections 9, 17, 30 and 36 through 53, and the rules and regulations under the Act (the “Rules and Regulations”). With respect to sections 17(a), (d), (f), (g), and (j) of the Act, sections 30(a), (b), (e), and (h) of the Act and the Rules and Regulations and rule 38a–1 under the Act, applicants request a limited exemption as set forth in the application.
Applicants request an order to exempt certain limited partnerships formed for the benefit of eligible employees of Davis Polk & Wardwell LLP and its affiliates from certain provisions of the Act. Each limited partnership will be an “employees' securities company” within the meaning of section 2(a)(13) of the Act.
Stetson Capital Fund LP (the “Existing Fund”) and Davis Polk & Wardwell LLP (“DPW”).
The application was filed on October 10, 2000, and amended on January 22, 2004, July 25, 2008, April 10, 2012, and December 21, 2012. Applicants have agreed to file an amendment during the notice period, the substance of which is reflected in this notice.
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 April 22, 2013, and should be accompanied by proof of service on applicants, in the form of an affidavit or, for lawyers, a certificate of service. Hearing requests should state the nature of the writer's interest, 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.
Elizabeth M. Murphy, Secretary, U.S. Securities and Exchange Commission, 100 F Street NE., Washington, DC, 20549–1090. Applicants, 450 Lexington Avenue, New York, NY 10017.
Deepak T. Pai, Senior Counsel, at (202) 551–6876 or Mary Kay Frech, Branch Chief, at (202) 551–6821 (Division of Investment Management, Exemptive Applications 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 for an applicant using the Company name box, at
1. DPW, a New York limited liability partnership, is an international law firm. Entities controlling, controlled by, or under common control with DPW, including any related law partnership affiliated with DPW, are the “DPW Entities.”
2. The Existing Fund is a Delaware limited partnership formed in 2000 pursuant to a limited partnership agreement. The applicants may in the future offer additional pooled investment vehicles substantially similar in all material respects (other than form of organization, investment objective and strategy, and other differences described in the application) to Eligible Investors (as defined below) (the “Subsequent Funds” and, together with the Existing Fund, the “Investment Funds”). The applicants anticipate that each Subsequent Fund also will be structured as a limited partnership, although a Subsequent Fund could be structured as a domestic or offshore general partnership, limited liability company or corporation. The operating agreements of the Investment Funds are the “Investment Fund Agreements.” An Investment Fund may include a single vehicle designed to issue interests in series or having similar features to enable a single Investment Fund to function as if it were several successive Investment Funds for ease of administration. Each Investment Fund will be an employees' securities company within the meaning of section 2(a)(13) of the Act.
3. The Existing Fund has been established to enable certain Eligible Investors to participate in certain investment opportunities that come to
4. Interests in an Investment Fund (“Interests”) will be offered and sold in reliance upon the exemption from registration under section 4(2) of the Securities Act of 1933 (the “Securities Act”) or pursuant to Regulation D under the Securities Act. Interests in any Investment Fund (other than short-term paper) will be offered only to DPW, DPW Entities, or Eligible Investors. “Eligible Investors” means persons who at the time of investment are: (a) current or former partners of, or lawyers employed by, or key administrative employees of, DPW or a DPW Entity (“Eligible Employees”), (b) the immediate family members of Eligible Employees, which are parents, children, spouses of children, spouses, and siblings, including step or adoptive relationships (“Immediate Family Members”), and (c) trusts or other entities or arrangements the sole beneficiaries of which consist of Eligible Employees or their Immediate Family Members, or the settlors and the trustees of which consist of Eligible Employees or Eligible Employees together with Immediate Family Members (“Eligible Trusts”). To qualify as an Eligible Investor with respect to an Investment Fund, each such person must, if purchasing an Interest from an Investment Fund or from a Member, be an “accredited investor” as that term is defined in Regulation D under the Securities Act, or, in the case of Eligible Trusts, a trust, entity or arrangement for which an Eligible Employee is a settlor and principal investment decision-maker.
5. An Investment Fund will be managed by its general partner (“General Partner”). The managing member of the General Partner (“Managing Member”) is a limited liability company that is managed by the members of the management committee of DPW, who expect to delegate most of their authority to an investment committee (“Investment Committee”). The Investment Committee of an Investment Fund will consist of approximately five persons who include the members of the management committee of DPW and selected additional Members of such Investment Fund. If a General Partner is formed as a wholly-owned subsidiary of DPW, the members of the relevant Investment Committee will be officers and/or directors of the subsidiary. The chief function of the Investment Committee will be to review and select Investments for an Investment Fund or a series thereof from time to time. The General Partner will register as an investment adviser under the Investment Advisers Act of 1940 (the “Advisers Act”), if such registration is required under the Advisers Act and the rules thereunder.
6. Administration of each Investment Fund will be vested in the General Partner. The General Partner may determine to delegate administrative activities to a third-party administrator. If a third-party administrator is retained by the General Partner, the administrator will not recommend Investments or exercise investment discretion. The only functions of the administrator will be ministerial.
7. The specific investment objectives and strategies for an Investment Fund will be set forth in an informative memorandum relating to the Interests being offered, and in the relevant Investment Fund Agreement, and each Eligible Investor will receive a copy of the informative memorandum and Investment Fund Agreement before making an investment in the Investment Fund. The terms of an Investment Fund will be disclosed to each Eligible Investor at the time the investor is invited to participate in the Investment Fund.
8. The value of the Members' capital accounts will be determined at such times as the General Partner deems appropriate or necessary; however, such valuation will be done at least annually at the Investment Fund's fiscal year-end. The General Partner will value the assets held by an Investment Fund at the current market price (closing price) in the case of marketable securities. All other securities or assets will be valued by the General Partner in good faith at fair value.
9. Each Investment Fund will generally bear its own expenses. DPW may be reimbursed by an Investment Fund for reasonable and necessary out of pocket costs directly associated with the organization and operation of the Investment Fund, including administrative expenses. No Investment Fund will be charged legal fees by DPW, and there will be no allocation of any of DPW's operating expenses to the Investment Funds. Some of the investment opportunities available to an Investment Fund may involve parties for which DPW was, is or will be retained to act as legal counsel, and DPW may be paid by such parties for legal services and for related disbursements and charges. These amounts paid to DPW will not be paid by an Investment Fund itself but by the entities in which an Investment Fund invests or their sponsors. No management fee or other compensation will be paid by an Investment Fund or the Members to the Investment Committee or the General Partner. Also, no fee of any kind will be charged in connection with the sale of Interests in an Investment Fund.
10. Within 120 days after the end of its fiscal year, or as soon as practicable thereafter, each Investment Fund will send its Members an annual report regarding its operations. The annual report of the Investment Fund will contain financial statements audited by an independent accounting firm. For purposes of this requirement, “audit” has the meaning defined in rule 1–02(d) of Regulation S–X. The Investment Fund will maintain a file containing any financial statements and other information received from the issuers of the Investments held by the Investment
11. Members will not be entitled to redeem their Interests in an Investment Fund. A Member will be permitted to transfer his or her Interest only with the express consent of the General Partner, which may be withheld in the discretion of the General Partner, and then only to DPW, a DPW Entity or an Eligible Investor. A Member will not be subject to removal except for good cause as determined by the General Partner, or if the General Partner, in its discretion, deems such withdrawal to be in the best interest of the Investment Fund. The Interests of a Member who is no longer eligible to own interests in an employees' securities company as defined in section 2(a)(13) of the Act will be repurchased, subject to the minimum payment provisions described below. The General Partner does not currently intend to require any Member to withdraw.
12. Each Member will commit to contribute a fixed amount of capital to an Investment Fund (“Capital Commitment”). To provide flexibility in connection with an Investment Fund's obligation to contribute capital to fund an Investment, and the associated obligation of the Members to make capital contributions with respect to their Capital Commitments, an Investment Fund Agreement may provide that the Investment Fund may engage in borrowings in connection with such funding of Investments. All borrowings by an Investment Fund with respect to the funding of Investments will be non-recourse to the Members,
13. An Investment Fund will not acquire any security issued by a registered investment company if immediately after the acquisition the Investment Fund would own more than 3% of the total outstanding voting stock of the registered investment company.
1. Section 6(b) of the Act provides, in part, that the Commission will exempt employees' securities companies from the provisions of the Act to the extent that the exemption is consistent with the protection of investors. Section 6(b) provides that the Commission will consider, in determining the provisions of the Act from which the company should be exempt, the company's form of organization and capital structure, the persons owning and controlling its securities, the price of the company's securities and the amount of any sales load, the disposition of the proceeds of any sales of the company's securities, how the company's funds are invested, and the relationship between the company and the issuers of the securities in which it invests. Section 2(a)(13) defines an employees' securities company as any investment company all of whose securities (other than short-term paper) are beneficially owned (a) by current or former employees, or persons on retainer, of one or more affiliated employers, (b) by immediate family members of such persons, or (c) by such employer or employers together with any of the persons in (a) or (b).
2. Section 7 of the Act generally prohibits investment companies that are not registered under section 8 of the Act from selling or redeeming their securities. Section 6(e) of the Act provides that, in connection with any order exempting an investment company from any provision of section 7, certain provisions of the Act, as specified by the Commission, will be applicable to the company and other persons dealing with the company as though the company were registered under the Act. Applicants request an order under sections 6(b) and 6(e) of the Act exempting applicants from all provisions of the Act, except sections 9, 17, 30, 36 through 53, and the Rules and Regulations. With respect to sections 17(a), (d), (f), (g) and (j) and 30(a), (b), (e) and (h) of the Act and the Rules and Regulations, and rule 38a–1 under the Act, applicants request a limited exemption as set forth in the application.
3. Section 17(a) of the Act generally prohibits any affiliated person of a registered investment company, or any affiliated person of an affiliated person, acting as principal, from knowingly selling or purchasing any security or other property to or from the company. Applicants request an exemption from section 17(a) to permit an Investment Fund: to invest in or participate as a selling security-holder in a principal transaction with one or more affiliated persons (as defined in section 2(a)(3) of the Act) of an Investment Fund (“First-Tier Affiliates”) and affiliated persons of such First-Tier Affiliates (“Second-Tier
4. Applicants submit that the exemptions sought from section 17(a) are consistent with the purposes of the Act and the protection of investors. Applicants state that the Members will be informed in an Investment Fund's offering materials of the possible extent of the dealings by such Investment Fund and any portfolio company with DPW, any DPW Entity or any affiliated person thereof. Applicants also state that, as experienced professionals acting on behalf of financial services businesses, the Members will be able to evaluate the risks associated with such dealings. Applicants assert that the community of interest among the General Partner, the Members, DPW and the DPW Entities will serve to reduce the risk of abuse in transactions involving an Investment Fund and DPW, any DPW Entity or any affiliated person thereof.
5. Section 17(d) of the Act and rule 17d–1 under the Act prohibit any affiliated person of a registered investment company, or any affiliated person of such person, acting as principal, from participating in any joint arrangement with the registered investment company unless authorized by the Commission. Applicants request an exemption from section 17(d) and rule 17d–1 to the extent necessary to permit an Investment Fund to engage in transactions in which an Affiliate participates as a joint or a joint and several participant with such Investment Fund.
6. Joint transactions in which an Investment Fund could participate might include the following: (a) a joint investment by one or more Investment Funds in a security in which DPW or a DPW Entity, or another Investment Fund, is a joint participant or plans to become a participant; (b) a joint investment by one or more Investment Funds in another Investment Fund; and (c) a joint investment by one or more Investment Funds in a security in which an Affiliate is an investor or plans to become an investor, including situations in which an Affiliate has a partnership or other interest in, or compensation arrangements with, such issuer, sponsor or offeror.
7. Applicants assert that compliance with section 17(d) and rule 17d–1 would cause an Investment Fund to forego investment opportunities simply because a Member, DPW, a DPW Entity or other affiliated persons of the Investment Fund, DPW or the DPW Entities also had or contemplated making a similar investment. In addition, because attractive investment opportunities of the types considered by an Investment Fund often require that each participant make available funds in an amount that may be substantially greater than that available to the investor alone, there may be certain attractive opportunities of which an Investment Fund may be unable to take advantage except as a co-participant with other persons, including Affiliates. Applicants believe that the flexibility to structure co- and joint investments in the manner described above will not involve abuses of the type section 17(d) and rule 17d–1 were designed to prevent. Applicants acknowledge that any transactions subject to section 17(d) and rule 17d–1 for which exemptive relief has not been requested in the application would require specific approval by the Commission.
8. Section 17(f) of the Act designates the entities that may act as investment company custodians, and rule 17f–2 under the Act allows an investment company to act as self-custodian. Applicants request an exemption to permit the following exceptions from the requirements of rule 17f–2: (i) Compliance with paragraph (b) of the rule may be achieved through safekeeping in the locked files of DPW or a DPW partner; (ii) for the purposes of the rule, (A) employees of DPW or a DPW Entity will be deemed employees of the Investment Funds, (B) officers and members of the Managing Member and members of the Investment Committee will be deemed to be officers of such Investment Funds, and (C) officers and members of the Managing Member and members of the Investment Committee will be deemed to be the board of directors of such Investment Funds; and (iii) instead of the verification procedure under paragraph (f) of the rule, verification will be effected quarterly by two employees, each of whom shall have sufficient knowledge, sophistication and experience in business matters to perform such examination. Applicants expect that most of the Investments will be evidenced by partnership agreements or similar documents. Such instruments are most suitably kept in DPW's files, where they can be referred to as necessary. Applicants will comply with all other provisions of rule 17f–2.
9. Section 17(g) and rule 17g–1 generally require the bonding of officers and employees of a registered investment company who have access to its securities or funds. Rule 17g–1 requires that a majority of directors who are not interested persons of a registered investment company (“disinterested directors”) take certain actions and give certain approvals relating to fidelity bonding. Applicants request an exemption from the requirement, contained in rule 17g–1, that a majority of the “directors” of the Investment Funds who are not “interested persons” of the respective Investment Funds (as defined in the Act) take certain actions and make certain approvals concerning bonding and request instead that such actions and approvals be taken by the Managing Members, regardless of whether any of them is deemed to be an interested person of the Investment Funds. Each Managing Member will be an interested person of the Investment Funds.
10. The Investment Funds request an exemption from the requirements of rule 17g–1(g) and (h) relating to the filing of copies of fidelity bonds and related information with the Commission and relating to the provisions of notices to the board of directors. Applicants also request an exemption from the requirements of rule 17g–1(j)(3) that the Investment Funds have a majority of disinterested directors, that those disinterested directors select and nominate any other disinterested directors, and that any legal counsel for those disinterested directors be independent legal counsel. Applicants believe that the filing requirements of rule 17g–1 are burdensome and unnecessary as applied to the Investment Funds. The General Partner will maintain the materials otherwise required to be filed with the Commission by rule 17g–1(g) and the applicants agree that all such material will be subject to examination by the Commission and its staff. The General Partner will designate a person to maintain the records otherwise required to be filed with the Commission under paragraph (g) of the rule. The Investment Funds will comply with all other requirements of rule 17g–1. The fidelity bond of the Investment Funds will cover the Investment Committee, the General Partner and all employees of DPW or any DPW Entity who have access to the securities or funds of the Investment Funds.
11. Applicants request an exemption from the requirements, contained in section 17(j) of the Act and rule 17j–1 under the Act, that every registered investment company adopt a written code of ethics and every “access person” of such registered investment company report to the investment company with respect to transactions in any security in which such access person has, or by reason of the transaction acquires, any direct or indirect beneficial ownership in the security. Applicants request an exemption from the requirements in rule 17j–1, with the exception of rule
12. Applicants request an exemption from the requirements in sections 30(a), 30(b), and 30(e) of the Act, and the Rules and Regulations under those sections, that registered investment companies prepare and file with the Commission and mail to their shareholders certain periodic reports and financial statements. Applicants contend that the forms prescribed by the Commission for periodic reports have little relevance to the Investment Funds and would entail administrative and legal costs that outweigh any benefit to the Members. Applicants request exemptive relief to the extent necessary to permit the Investment Funds to report annually to their Members. Applicants also request an exemption from section 30(h) of the Act to the extent necessary to exempt the General Partner, any 10 percent shareholder, and any other person who may be deemed to be an officer, director, member of an advisory board, or otherwise subject to section 30(h), from filing Forms 3, 4 and 5 under section 16 of the Securities Exchange Act of 1934 (“Exchange Act”) with respect to their ownership of Interests in the Investment Funds. Applicants assert that, because there is no trading market for Interests and the transfer of Interests is severely restricted, these filings are unnecessary for the protection of investors and burdensome to those required to make them.
13. Rule 38a–1 requires investment companies to adopt, implement and periodically review written policies reasonably designed to prevent violation of the federal securities laws and to appoint a chief compliance officer. Each Investment Fund will comply with rule 38a–1(a), (c) and (d), except that (i) the members of the Investment Committee of each Investment Fund will fulfill the responsibilities assigned to the board of directors under the rule, and (ii) because all members of the Investment Committee would be considered interested persons of the Investment Funds, approval by a majority of the disinterested board members required by rule 38a–1 will not be obtained. In addition, the Investment Funds will comply with the requirement in rule 38a–1(a)(4)(iv) that the chief compliance officer meet with the disinterested directors by having the chief compliance officer meet with the members of the Investment Committee.
The applicants agree that any order granting the requested relief will be subject to the following conditions:
1. Each proposed transaction, to which an Investment Fund is a party, otherwise prohibited by section 17(a) or section 17(d) and rule 17d–1 (the “Section 17 Transactions”) will be effected only if the Investment Committee determines that: (a) The terms of the Section 17 Transaction, including the consideration to be paid or received, are fair and reasonable to Members of the Investment Fund and do not involve overreaching of the Investment Fund or its Members on the part of any person concerned; and (b) the Section 17 Transaction is consistent with the interests of the Members of the Investment Fund, the Investment Fund's organizational documents and the Investment Fund's reports to its Members.
In addition, the Investment Committee will record and preserve a description of such Section 17 Transactions, the findings of the Investment Committee, the information or materials upon which their findings are based and the basis therefor. All such records will be maintained for the life of the Investment Fund and at least six years thereafter, and will be subject to examination by the Commission and its staff. All such records will be maintained in an easily accessible place for at least the first two years.
2. If purchases or sales are made by an Investment Fund from or to an entity affiliated with the Investment Fund by reason of a member of the Investment Committee (a) serving as an officer, director, general partner or investment adviser of the entity, or (b) having a 5% or more investment in the entity, such individual will not participate in the Investment Fund's determination of whether or not to effect the purchase or sale.
3. The Investment Committee will adopt, and periodically review and update, procedures designed to ensure that reasonable inquiry is made, prior to the consummation of any Section 17 Transaction, with respect to the possible involvement in the transaction of any affiliated person or promoter of or principal underwriter for the Investment Fund, or any affiliated person of such a person, promoter, or principal underwriter.
4. The Investment Committee will not purchase for an Investment Fund any Investment in which a Co-Investor, as defined below, has or proposes to acquire the same class of securities of the same issuer, where the investment involves a joint enterprise or other joint arrangement within the meaning of rule 17d–1 in which the Investment Fund and the Co-Investor are participants, unless any such Co-Investor, prior to disposing of all or part of its investment: (a) Gives the Investment Fund holding such investment sufficient, but not less than one day's notice of its intent to dispose of its investment, and (b) refrains from disposing of its investment unless the Investment Fund holding such investment has the opportunity to dispose of its investment prior to or concurrently with, on the same terms as, and on a pro rata basis with the Co-Investor. The term “Co-Investor” with respect to an Investment Fund means any person who is: (a) An affiliated person of the Investment Fund; (b) DPW and any DPW Entity; (c) a current or former partner, lawyer employed by or key administrative employee of DPW or a DPW Entity; (d) a company in which a member of the Investment Committee, DPW or a DPW Entity acts as an officer, director, or general partner, or has a similar capacity to control the sale or disposition of the company's securities; or (e) an investment vehicle offered, sponsored, or managed by DPW or an affiliated person of DPW.
The restrictions contained in this condition, however, shall not be deemed to limit or prevent the disposition of an investment by a Co-Investor: (a) To its direct or indirect wholly-owned subsidiary, to any company (a “Parent”) of which the Co-Investor is a direct or indirect wholly-owned subsidiary, or to a direct or indirect wholly-owned subsidiary of its Parent; (b) to immediate family members of the Co-Investor or a trust established for the benefit of any such family member; (c) when the investment is comprised of securities that are listed on a national securities exchange registered under section 6 of the Exchange Act; (d) when the investment is comprised of securities that are national market system (“NMS”) stocks pursuant to section 11A(a)(2) of the Exchange Act and rule 600(a) of Regulation NMS thereunder; (e) when
5. An Investment Fund will send, within 120 days after the end of its fiscal year, or as soon as practicable thereafter, to each Member who had an interest in the Investment Fund at any time during the fiscal year then ended, reports and information regarding the Investments, including financial statements for such Investment Fund audited by an independent accounting firm. The Investment Committee will make a valuation or have a valuation made of all of the assets of an Investment Fund as of each fiscal year end. In addition, within 90 days after the end of each fiscal year of the Investment Fund or as soon as practicable thereafter, the Investment Fund shall send a report to each person who was a Member at any time during the fiscal year then ended, setting forth such tax information as shall be necessary for the preparation by the Member of his or her federal and state income tax returns and a report of the investment activities of the Investment Fund during such year.
6. An Investment Fund will maintain and preserve, for the life of the Investment Fund and at least six years thereafter, such accounts, books, and other documents as constitute the record forming the basis for the audited financial statements and annual reports of the Investment Fund to be provided to its Members, and agrees that all such records will be subject to examination by the Commission and its staff. All such records will be maintained in an easily accessible place for at least the first two years. For the Commission, by the Division of Investment Management, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”),
The Exchange proposes to amend Chapter XV, Section 2 entitled “BX Options Market—Fees and Rebates” to amend various fees for routing options to away markets.
While these amendments are effective upon filing, the Exchange has designated the proposed amendments to be operative on April 1, 2013.
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.
The purpose of this filing is to recoup costs that the Exchange incurs for routing and executing certain orders in equity options to away markets. Today, the Exchange calculates Routing Fees by assessing certain Exchange costs related to routing orders to away markets plus the away market's transaction fee. The Exchange assesses a $0.05 per contract
C2 recently filed a rule change to amend its transaction fees and rebates for simple, non-complex orders, in equity options classes which became operative on February 1, 2013.
The Exchange is proposing to further simplify its Routing Fees by assessing a flat rate of $0.95 per contract on all non-Customer orders routed to any away market. The Exchange would no longer pass any rebate paid by an away market for non-Customer orders. With respect to Customer orders, the Exchange is proposing to continue to assess Customer orders routed to NOM and PHLX a fixed fee of $0.05 per contract (“Fixed Fee”) in addition to the actual transaction fee assessed by the away market. These fees are not changing. The Exchange proposes to assess a Customer Routing Fee of $0.11 per contract (“Fixed Fee”) in addition to the actual transaction fee when routing to an options exchange other than NOM and PHLX, as is the case today. The Exchange is amending the payment of rebates and will no longer pay rebates when routing Customer orders to an away market, instead the Exchange will not assess a Routing Fee if a Customer order is routed to an away market that pays a rebate.
BX believes that its proposal to amend its pricing is consistent with Section 6(b) of the Act
The Exchange believes that its proposal to amend its non-Customer Routing Fees from a fixed fee plus actual transaction charges to a flat rate is reasonable because the flat rate makes it easier for market participants to anticipate the Routing Fees which they would be assessed at any given time. The Exchange believes that assessing all non-Customer orders the same flat rate will provide market participants with certainty with respect to Routing Fees. While, each destination market's transaction charge varies and there is a cost incurred by the Exchange when routing orders to away markets, including clearing costs, administrative and technical costs associated with operating NOS, membership fees at away markets, ORFs and technical costs associated with routing options, the Exchange believes that the proposed Routing Fees will enable it to recover the costs it incurs to route non-Customer orders away markets. Other exchanges similarly assess a fixed rate fee to route non-Customer orders.
The Exchange believes that its proposal to amend the non-Customer Routing Fees from a fixed fee plus actual transaction charges to a flat rate is equitable and not unfairly discriminatory because the Exchange would uniformly assess the same Routing Fees to all non-Customer market participants. Under its flat fee structure, taking all costs to the Exchange into account, the Exchange may operate at a slight gain or a slight loss for non-Customer orders routed to and executed at away markets. The proposed Routing Fee for non-Customer orders is an approximation of the maximum fees the Exchange will be charged for such executions, including costs, at away markets. As a general matter, the Exchange believes that the proposed fees will allow it to recoup and cover its costs of providing routing services for non-Customer orders. The Exchange believes that the fixed rate non-Customer Routing Fee is equitable and not unfairly discriminatory because market participants have the ability to directly route orders to an away market and avoid the Routing Fee. Participants may choose to mark the order as ineligible for routing to avoid incurring these fees.
The Exchange believes that its proposal to not pass a rebate that is offered by an away market for non-Customer orders is reasonable because to the extent that another market is paying a rebate, the Exchange will assess a $0.95 per contract fee as its total cost in each instance. The Routing Fee is transparent and simple. If a market participant desires the rebate, the market participant has the option to direct the order to that away market. Other options exchanges today do not pass the rebate.
The Exchange believes that it is reasonable to also not assess a Customer Routing Fee when routing to all other options exchanges, except NOM and PHLX,
The Exchange believes that it is reasonable, equitable and not unfairly discriminatory to continue to assess Customer orders that are routed to NOM and PHLX a Fixed Fee of $0.05 per contract and orders that are routed to other away markets, other than NOM and PHLX, a Fixed Fee of $0.11 per contract because the cost, in terms of actual cash outlays, to the Exchange to route to NOM and PHLX is lower. For example, costs related to routing to NOM and PHLX are lower as compared to other away markets because NOS is utilized by all three exchanges to route orders.
Finally, the Exchange believes that it is reasonable, equitable and not unfairly discriminatory to assess different fees for Customers orders as compared to non-Customer orders because the Exchange has traditionally assessed lower fees to Customers as compared to non-Customers. Customers will continue to receive the lowest fees or no fees when routing orders, as is the case today. Other options exchanges also assess lower Routing Fees for customer orders as compared to non-customer orders.
The Exchange does not believe that the proposed rule change will impose any burden on competition not necessary or appropriate in furtherance of the purposes of the Act. The Exchange does not believe that the proposal creates intra-market competition because the Exchange is applying the same Routing Fees and credits to all market participants in the same manner dependent on the routing venue, with the exception of Customers. The Exchange has proposed separate Customer Routing Fees. Customers will continue to receive the lowest fees or no fees when routing orders, as is the case today. Other options exchanges also assess lower Routing Fees for customer orders as compared to non-customer orders.
The Exchange's proposal would allow the Exchange to recoup its costs when routing orders to away markets when such orders are designated as available for routing by the market participant. The Exchange is passing along savings realized by leveraging NASDAQ OMX's infrastructure and scale to market participants when those orders are routed to NOM and PHLX and is providing those saving to all market participants. Participants may choose to mark the order as ineligible for routing to avoid incurring these fees.
The Exchange operates in a highly competitive market, comprised of eleven exchanges, in which market participants can easily and readily direct order flow to competing venues if they deem fee levels at a particular venue to be excessive. Accordingly, the fees that are assessed by the Exchange must remain competitive with fees charged by other venues and therefore must continue to be reasonable and equitably allocated to those Participants that opt to direct orders to the Exchange rather than competing venues.
No written comments were either solicited or received.
The foregoing rule change 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 Elizabeth M. Murphy, 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 January 24, 2013, 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” or “Exchange Act”)
The Exchange proposes to list and trade Shares of the Fund pursuant to NYSE Arca Equities Rule 8.600, which governs the listing and trading of Managed Fund Shares. The Shares will be offered by SSgA Active ETF Trust (“Trust”), which is organized as a Massachusetts business trust and is registered with the Commission as an open-end management investment company.
The investment objective of the Fund is to provide current income consistent with the preservation of capital. Under normal market conditions,
According to the Exchange, in pursuing its investment objective, the Fund, under normal market conditions, will seek to outperform a primary and secondary loan index (as described below) by investing at least 80% of its net assets (plus any borrowings for investment purposes) in “Senior Loans.”
The Fund will not seek to track either the Primary or Secondary Index, but rather will seek to outperform those indices. In doing so, the Sub-Adviser represents that the Portfolio will primarily invest in Senior Loans.
The Sub-Adviser considers Senior Loans to be first lien senior secured floating rate bank loans. A Senior Loan is an advance or commitment of funds made by one or more banks or similar financial institutions to one or more corporations, partnerships, or other business entities and typically pays interest at a floating or adjusting rate that is determined periodically at a designated premium above a base lending rate, most commonly the London-Interbank Offered Rate. A Senior Loan is considered senior to all other unsecured claims against the borrower and senior to or pari passu with all other secured claims, meaning that in the event of a bankruptcy, the Senior Loan, together with other first lien claims, is entitled to be the first to be repaid out of proceeds of the assets securing the loans before other existing unsecured claims or interests receive repayment. However, in bankruptcy proceedings, there may be other claims, such as taxes or additional advances which take precedence.
According to the Exchange, the Portfolio will invest in Senior Loans that are made predominantly to businesses operating in North America, but may also invest in Senior Loans made to businesses operating outside of North America. The Portfolio may invest in Senior Loans directly, either from the borrower as part of a primary issuance or in the secondary market through assignments of portions of Senior Loans from third parties or participations in Senior Loans, which are contractual relationships with an existing lender in a loan facility whereby the Portfolio purchases the right to receive principal and interest payments on a loan, but the existing lender remains the record holder of the loan. Under normal market conditions, the Portfolio expects to maintain an average interest rate duration of less than 90 days.
In selecting securities for the Portfolio, the Sub-Adviser will seek to construct a portfolio of loans that it believes is less volatile than the general loan market. In addition, when making investments, the Sub-Adviser will seek to maintain appropriate liquidity and price transparency for the Portfolio. On an on-going basis, the Sub-Adviser will add or remove those individual loans that it believes will cause the Portfolio to outperform or underperform, respectively, either the Primary or Secondary Index.
When identifying prospective investment opportunities in Senior Loans, the Sub-Adviser currently intends to invest primarily in Senior Loans that are below investment grade quality and will rely on fundamental credit analysis in an effort to attempt to minimize the loss of the Portfolio's capital.
The Sub-Adviser intends to invest in Senior Loans or other debt of companies that it believes have developed strong positions within their respective markets and exhibit the potential to maintain sufficient cash flows and profitability to service their obligations in a range of economic environments. The Sub-Adviser will seek Senior Loans or other debt of companies that it believes possess advantages in scale, scope, customer loyalty, product pricing, or product quality versus their competitors, thereby minimizing business risk and protecting profitability.
The Sub-Adviser intends to invest primarily in Senior Loans or other debt of established companies which have demonstrated a record of profitability and cash flows over several economic cycles. The Sub-Adviser believes such companies are well-positioned to maintain consistent cash flow to service and repay their obligations and maintain growth in their businesses or market share. The Sub-Adviser does not intend to invest in Senior Loans or other debt of primarily start-up companies, companies in turnaround situations, or companies with speculative business plans.
The Sub-Adviser intends to focus on investments in which the Senior Loans or other debt of a target company has an experienced management team with an established track record of success. The Sub-Adviser will typically require companies to have in place proper incentives to align management's goals with the Portfolio's goals.
The Sub-Adviser will seek to invest in Senior Loans or other debt broadly among companies and industries, thereby potentially reducing the risk of a downturn in any one company or industry having a disproportionate impact on the value of the Portfolio's holdings. However, as a result of its investment in participations in loans and the fact that originating banks may be deemed issuers of loans, the Portfolio may be deemed to concentrate its investments in the financial services industries. Loans, and the collateral securing them, are typically monitored by agents for the lenders, which may be the originating bank or banks.
The Portfolio and the Fund are expected to be managed in a “master-feeder” structure, under which the Fund, under normal market conditions, will invest all of its assets in the Portfolio, the corresponding “master fund,” which is a separate 1940 Act-registered mutual fund that has an identical investment objective. As a result, the Fund (
The Sub-Adviser will manage the investments of the Portfolio. Under the master-feeder arrangement, investment advisory fees charged at the master fund level are deducted from the advisory fees charged at the feeder fund level. According to the Exchange, this arrangement avoids a “layering” of fees,
According to the Exchange, historically, the amount of public information available about a specific Senior Loan has been less extensive than if the loan were registered or exchange-traded. As noted above, the loans in which the Portfolio will invest will, in most instances, be Senior Loans, which are secured and senior to other indebtedness of the borrower. Each Senior Loan will generally be secured by collateral such as accounts receivable; inventory; equipment; real estate; intangible assets such as trademarks, copyrights, and patents; and securities of subsidiaries or affiliates. The value of the collateral generally will be determined by reference to financial statements of the borrower, by an independent appraisal, by obtaining the market value of such collateral (in the case of cash or securities if readily ascertainable), or by other customary valuation techniques considered appropriate by the Sub-Adviser. The value of collateral may decline after the Portfolio's investment, and collateral may be difficult to sell in the event of default. Consequently, the Portfolio may not receive all the payments to which it is entitled. By virtue of their senior position and collateral, Senior Loans typically provide lenders with the first right to cash flows or proceeds from the sale of a borrower's collateral if the borrower becomes insolvent (subject to the limitations of bankruptcy law, which may provide higher priority to certain claims such as employee salaries, employee pensions, and taxes). This means Senior Loans are generally repaid before unsecured bank loans, corporate bonds, subordinated debt, trade creditors, and preferred or common stockholders. To the extent that the Portfolio invests in unsecured loans, if the borrower defaults on such loans, there is no specific collateral on which the lender can foreclose. If the borrower defaults on a subordinated loan, the collateral may not be sufficient to cover both the senior and subordinated loans.
There is no organized exchange on which loans are traded, and reliable market quotations may not be readily available. A majority of the Portfolio's assets are likely to be invested in loans that are less liquid than securities traded on national exchanges. Loans with reduced liquidity involve greater risk than securities with more liquid markets. Available market quotations for such loans may vary over time, and if the credit quality of a loan unexpectedly declines, secondary trading of that loan may decline for a period of time. During periods of infrequent trading, valuing a loan can be more difficult, and buying and selling a loan at an acceptable price can be more difficult and delayed. In the event that the Portfolio voluntarily or involuntarily liquidates Portfolio assets during periods of infrequent trading, it may not receive full value for those assets. Therefore, elements of judgment may play a greater role in the valuation of loans. To the extent that a secondary market exists for certain loans, the market may be subject to irregular trading activity, wide bid/ask spreads, and extended trade settlement periods.
Senior Loans will usually require, in addition to scheduled payments of interest and principal, the prepayment of the Senior Loan from free cash flow. The degree to which borrowers prepay Senior Loans, whether as a contractual requirement or at their election, may be affected by general business conditions, the financial condition of the borrower, and competitive conditions among loan investors, among other factors. As such, prepayments cannot be predicted with accuracy. Recent market conditions, including falling default rates among others, have led to increased prepayment frequency and loan renegotiations. These renegotiations are often on terms more favorable to borrowers. Upon a prepayment, either in part or in full, the actual outstanding debt on which the Portfolio derives interest income will be reduced. However, the Portfolio may receive a prepayment penalty fee assessed against the prepaying borrower.
The Fund may (indirectly through its investments in the Portfolio or, in extraordinary circumstances, directly) invest in certain other types of investments. According to the Exchange, in addition to the principal investments described above, the Portfolio may invest in bonds, including corporate bonds, high-yield debt securities, and U.S. Government obligations.
The Portfolio may invest in repurchase agreements with commercial banks, brokers, or dealers to generate income from its excess cash balances and its securities lending cash collateral.
Subject to limitations, the Portfolio may invest in secured loans that are not first lien loans or loans that are unsecured. These loans have the same characteristics as Senior Loans except that such loans are not first in priority of repayment and/or may not be secured by collateral. Accordingly, the risks associated with these loans are higher than the risks for loans with first priority over the collateral. Because these loans are lower in priority and/or unsecured, they are subject to the additional risk that the cash flow of the borrower may be insufficient to meet scheduled payments after giving effect to the secured obligations of the borrower or in the case of a default, recoveries may be lower for unsecured loans than for secured loans.
The Portfolio may invest in short-term instruments, including money market instruments (including money market funds advised by the Adviser), cash, and
The Portfolio may invest in the securities of other investment companies, including closed-end funds (including loan-focused closed end funds), subject to applicable limitations under Section 12(d)(1) of the 1940 Act.
In addition, the Portfolio may invest in exchange-traded notes, such as securities listed on the Exchange under NYSE Arca Equities Rule 5.2(j)(6), which are debt obligations of investment banks that are traded on exchanges and the returns of which are linked to the performance of certain reference assets, which may include market indexes.
The Portfolio will not invest 25% or more of the value of its total assets in securities of issuers in any one industry; however it may be deemed to concentrate its investment in any of the industries or group of industries in the financial services sector (consisting of financial institutions, including commercial banks, insurance companies, and other financial companies and their respective holding companies) to the extent that the banks originating or acting as agents for the lenders, or granting or acting as intermediaries in participation interests, in loans held by the Portfolio are deemed to be issuers of such loans.
The Portfolio may hold up to an aggregate amount of 15% of its net assets in illiquid securities (calculated at the time of investment), including Rule 144A securities, junior subordinated loans, and unsecured loans deemed illiquid by the Adviser and Sub-Adviser. The Portfolio will monitor its portfolio liquidity on an ongoing basis to determine whether, in light of current circumstances, an adequate level of liquidity is being maintained, and will consider taking appropriate steps in order to maintain adequate liquidity if, through a change in values, net assets, or other circumstances, more than 15% of the Portfolio's net assets are held in illiquid securities. Illiquid securities include securities subject to contractual or other restrictions on resale and other instruments that lack readily available markets as determined in accordance with Commission staff guidance.
Except for investments in ETFs that may hold non-U.S. issues, the Portfolio will not otherwise invest in non-U.S.-registered equity issues. In addition, the Portfolio will not invest in options contracts, futures contracts, or swap agreements.
In certain situations or market conditions, the Portfolio may temporarily depart from its normal investment policies and strategies provided that the alternative is consistent with the Portfolio's investment objective and is in the best interest of the Portfolio. For example, the Portfolio may hold a higher than normal proportion of its assets in cash in times of extreme market stress.
The Portfolio will be classified as a “diversified” investment company under the 1940 Act and intends to qualify for and to elect treatment as a separate regulated investment company under Subchapter M of the Internal Revenue Code.
The Portfolio's investments will be consistent with the Portfolio's investment objective and will not be used to enhance leverage.
While the Fund, which would be listed pursuant to the criteria applicable to actively managed funds under NYSE Arca Equities Rule 8.600, is not eligible for listing under NYSE Arca Equities Rule 5.2(j)(3) applicable to listing and trading of Investment Company Units based on a securities index, the Adviser and Sub-Adviser represent that, under normal market conditions, the Fund would generally satisfy the generic fixed income initial listing requirements in NYSE Arca Equities Rule 5.2(j)(3), Commentary .02 on a continuous basis measured at the time of purchase, as described below.
(a) Eligibility Criteria for Index Components. Upon the initial listing of a series of Units pursuant to Rule 19b–4(e) under the Exchange Act, the components of an index or portfolio underlying a series of Units shall meet the following criteria:
(1) The index or portfolio must consist of Fixed Income Securities;
(2) Components that in aggregate account for at least 75% of the weight of the index or portfolio each shall have a minimum original principal amount outstanding of $100 million or more;
(3) A component may be a convertible security, however, once the convertible security component converts to the underlying equity security, the component is removed from the index or portfolio;
(4) No component fixed-income security (excluding Treasury Securities and GSE Securities) shall represent more than 30% of the weight of the index or portfolio, and the five most heavily weighted component fixed-income securities in the index or portfolio shall not in the aggregate account for more than 65% of the weight of the index or portfolio;
(5) An underlying index or portfolio (excluding one consisting entirely of exempted securities) must include a minimum of 13 non-affiliated issuers; and
(6) Component securities that in aggregate account for at least 90% of the weight of the index or portfolio must be either (a) from issuers that are required to file reports pursuant to Sections 13 and 15(d) of the Exchange Act; (b) from issuers that have a worldwide market value of its outstanding common equity held by non-affiliates of $700 million or more; (c) from issuers that have outstanding securities that are notes, bonds debentures, or evidence of indebtedness having a total remaining principal amount of at least $1 billion; (d) exempted securities as defined in Section 3(a)(12) of the Exchange Act; or (e) from issuers that are a government of a foreign country or a political subdivision of a foreign country.
With respect to the requirement of Commentary .02(a)(1), the Fund (through its investment in the Portfolio) will invest at least 80% of its net assets (plus any borrowings for investment purposes) in Senior Loans. The Adviser and Sub-Adviser expect that substantially all of the Fund's assets will be invested in Fixed Income Securities or cash/cash-like instruments.
With respect to the requirement of Commentary .02(a)(2), the Portfolio's Adviser and Sub-Adviser expect that substantially all, but at least 75%, of the Portfolio will be invested in loans that have an aggregate outstanding exposure of greater than $100 million.
With respect to the requirement of Commentary .02(a)(3), the Sub-Adviser represents that the Portfolio will not typically invest in convertible securities; however, should the Portfolio make such investments, the Sub-Adviser would direct the Portfolio to divest any converted equity security as soon as practicable.
With respect to the requirement of Commentary .02(a)(4), the Sub-Adviser represents that the Portfolio will not concentrate its investments in excess of 30% in any one security (excluding Treasury Securities and GSE Securities) and will not invest more than 65% of its assets in five or fewer securities (excluding Treasury Securities and GSE Securities).
With respect to the requirement of Commentary .02(a)(5), the Sub-Adviser represents that the Portfolio will invest in Senior Loans issued to at least 13 non-affiliated borrowers.
With respect to the requirements of Commentary .02(a)(6), the Sub-Adviser represents that the Portfolio may make investments on a continuous basis in compliance with such requirement at the time of purchase; however, the market for Senior Loans differs in several material respects from the market of other fixed income securities (
Additional information regarding the Fund, the Portfolio, and the Shares, including investment strategies, risks, Senior Loan market, Primary and Secondary Indices, creation and redemption procedures, fees, Portfolio holdings disclosure policies, distributions and taxes is included in the Notice and Registration Statement.
After careful review, the Commission finds that the proposed rule change is consistent with the requirements of Section 6 of the Act
The Commission 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 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 represents that the Shares are deemed to be equity securities, thus rendering trading in the Shares subject to the Exchange's existing rules governing the trading of equity securities. In support of this proposal, the Exchange has made 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 trading in the Shares will be subject to the existing trading surveillances, administered by FINRA on behalf of the Exchange, which are designed to detect violations of Exchange rules and applicable federal securities laws and 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 applicable federal securities laws.
(4) Prior to the commencement of trading, the Exchange will inform its Equity Trading Permit Holders in an Information Bulletin of the special characteristics and risks associated with trading the Shares. Specifically, the Information Bulletin will discuss the following: (a) The procedures for purchases and redemptions of Shares in Creation Unit aggregations (and that Shares are not individually redeemable); (b) NYSE Arca Equities Rule 9.2(a), which imposes a duty of due diligence on its Equity Trading Permit Holders to learn the essential facts relating to every customer prior to trading the Shares; (c) the risks involved in trading the Shares during the Opening and Late Trading Sessions when an updated PIV will not be calculated or publicly disseminated; (d) how information regarding the PIV is disseminated; (e) the requirement that Equity Trading Permit Holders deliver a prospectus to investors purchasing newly issued Shares prior to or concurrently with the confirmation of a transaction; and (f) trading information.
(5) For initial and/or continued listing, the Fund will be in compliance with Rule 10A–3 under the Act,
(6) It is anticipated that the Portfolio, in accordance with its principal investment strategy, will invest approximately 50% to 75% of its net assets in Senior Loans that are eligible for inclusion and meet the liquidity thresholds of the Primary and/or the Secondary Indices. Each of the Portfolio's Senior Loan investments will have no less than $250 million USD par outstanding. The Sub-Adviser does not intend to purchase Senior Loans that are in default, and it is the expectation that the Portfolio will only invest in broadly syndicated loans.
(7) Under normal market conditions, the Fund would generally satisfy the generic fixed income initial listing requirements in NYSE Arca Equities Rule 5.2(j)(3), Commentary .02 on a continuous basis measured at the time of purchase.
(8) The Fund will not invest in non-U.S.-registered equity issues (except for Underlying ETFs that may hold non-U.S. issues). The Portfolio may hold in the aggregate up to 15% of its net assets in illiquid securities (calculated at the time of investment), including Rule 144A securities, junior subordinated loans, and unsecured loans deemed illiquid by the Adviser and Sub-Adviser. The Portfolio will not invest in options contracts, futures contracts, or swap agreements.
(9) The Portfolio's and Fund's investments will be consistent with the Portfolio's and Fund's investment objective and will not be used to enhance leverage.
(10) A minimum of 100,000 Shares of the Fund will be outstanding at the commencement of trading on the Exchange.
This approval order is based on all of the Exchange's representations, including those set forth above and in
For the foregoing reasons, the Commission finds that the proposed rule change is consistent with Section 6(b)(5) 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 (“Act”),
NASDAQ is proposing to extend for three months the fee pilot pursuant to which NASDAQ distributes the NASDAQ Last Sale (“NLS”) market data products. NLS allows data distributors to have access to real-time market data for a capped fee, enabling those distributors to provide free access to the data to millions of individual investors via the internet and television. Specifically, NASDAQ offers the “NASDAQ Last Sale for NASDAQ” and “NASDAQ Last Sale for NYSE/Amex”
This pilot program supports the aspiration of Regulation NMS to increase the availability of proprietary data by allowing market forces to determine the amount of proprietary market data information that is made available to the public and at what price. During the pilot period, the program has vastly increased the availability of NASDAQ proprietary market data to individual investors. Based upon data from NLS distributors, NASDAQ believes that since its launch in July 2008, the NLS data has been viewed by over 50,000,000 investors on Web sites operated by Google, Interactive Data, and Dow Jones, among others.
The text of the proposed rule change is below. Proposed new language is underlined; proposed deletions are in brackets.
(a) For a three month pilot period commencing on [January]
(1)—(2) No change.
(b)—(c) No change.
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, of the most significant parts of such statements.
Prior to the launch of NLS, public investors that wished to view market data to monitor their portfolios generally had two choices: (1) Pay for real-time market data or (2) use free data that is 15 to 20 minutes delayed. To increase consumer choice, NASDAQ proposed a pilot to offer access to real-time market data to data distributors for a capped fee, enabling those distributors to disseminate the data at no cost to millions of internet users and television viewers. NASDAQ now proposes a three-month extension of that pilot program, subject to the same fee structure as is applicable today.
NLS consists of two separate “Level 1” products containing last sale activity within the NASDAQ market and reported to the jointly-operated FINRA/NASDAQ TRF. First, the “NASDAQ Last Sale for NASDAQ” data product is a real-time data feed that provides real-time last sale information including execution price, volume, and time for executions occurring within the NASDAQ system as well as those reported to the FINRA/NASDAQ TRF. Second, the “NASDAQ Last Sale for NYSE/NYSE MKT” data product provides real-time last sale information including execution price, volume, and time for NYSE- and NYSE MKT-securities executions occurring within the NASDAQ system as well as those reported to the FINRA/NASDAQ TRF. By contrast, the securities information processors (“SIPs”) that provide “core” data consolidate last sale information from all exchanges and trade reporting facilities (“TRFs”). Thus, NLS replicates a subset of the information provided by the SIPs.
NASDAQ established two different pricing models, one for clients that are able to maintain username/password entitlement systems and/or quote counting mechanisms to account for usage, and a second for those that are not. Firms with the ability to maintain username/password entitlement systems and/or quote counting mechanisms are eligible for a specified fee schedule for the NASDAQ Last Sale for NASDAQ Product and a separate fee schedule for the NASDAQ Last Sale for NYSE/NYSE MKT Product. Firms that are unable to maintain username/password
NASDAQ also established a cap on the monthly fee, currently set at $50,000 per month for all NASDAQ Last Sale products. The fee cap enables NASDAQ to compete effectively against other exchanges that also offer last sale data for purchase or at no charge.
As with the distribution of other NASDAQ proprietary products, all distributors of the NASDAQ Last Sale for NASDAQ and/or NASDAQ Last Sale for NYSE/NYSE MKT products pay a single $1,500/month NASDAQ Last Sale Distributor Fee in addition to any applicable usage fees. The $1,500 monthly fee applies to all distributors and does not vary based on whether the distributor distributes the data internally or externally or distributes the data via both the internet and television.
NASDAQ believes that the proposed rule change is consistent with the provisions of Section 6 of the Act,
NASDAQ believes that its NASDAQ Last Sale market data products are precisely the sort of market data product that the Commission envisioned when it adopted Regulation NMS. The Commission concluded that Regulation NMS—by lessening regulation of the market in proprietary data—would itself further the Act's goals of facilitating efficiency and competition:
[E]fficiency is promoted when broker-dealers who do not need the data beyond the prices, sizes, market center identifications of the NBBO and consolidated last sale information are not required to receive (and pay for) such data. The Commission also believes that efficiency is promoted when broker-dealers may choose to receive (and pay for) additional market data based on their own internal analysis of the need for such data.
The recent decision of the United States Court of Appeals for the District of Columbia Circuit in
The Court in
NASDAQ does not believe that the proposed rule change will result in any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act, as amended. NASDAQ's ability to price its Last Sale Data Products is constrained by (1) Competition between exchanges and other trading platforms that compete with each other in a variety of dimensions; (2) the existence of inexpensive real-time consolidated data and market-specific data and free delayed consolidated data; and (3) the inherent contestability of the market for proprietary last sale data.
The market for proprietary last sale data products is currently competitive and inherently contestable because there is fierce competition for the inputs necessary to the creation of proprietary data and strict pricing discipline for the proprietary products themselves. Numerous exchanges compete with each other for listings, trades, and market data itself, providing virtually limitless opportunities for entrepreneurs who wish to produce and distribute their own market data. This proprietary data is produced by each individual
Transaction execution and proprietary data products are complementary in that market data is both an input and a byproduct of the execution service. In fact, market data and trade execution are a paradigmatic example of joint products with joint costs. The decision whether and on which platform to post an order will depend on the attributes of the platform where the order can be posted, including the execution fees, data quality and price, and distribution of its data products. Without trade executions, exchange data products cannot exist. Moreover, data products are valuable to many end users only insofar as they provide information that end users expect will assist them or their customers in making trading decisions.
The costs of producing market data include not only the costs of the data distribution infrastructure, but also the costs of designing, maintaining, and operating the exchange's transaction execution platform and the cost of regulating the exchange to ensure its fair operation and maintain investor confidence. The total return that a trading platform earns reflects the revenues it receives from both products and the joint costs it incurs. Moreover, the operation of the exchange is characterized by high fixed costs and low marginal costs. This cost structure is common in content and content distribution industries such as software, where developing new software typically requires a large initial investment (and continuing large investments to upgrade the software), but once the software is developed, the incremental cost of providing that software to an additional user is typically small, or even zero (
An exchange's BD customers view the costs of transaction executions and of data as a unified cost of doing business with the exchange. A BD will direct orders to a particular exchange only if the expected revenues from executing trades on the exchange exceed net transaction execution costs and the cost of data that the BD chooses to buy to support its trading decisions (or those of its customers). The choice of data products is, in turn, a product of the value of the products in making profitable trading decisions. If the cost of the product exceeds its expected value, the BD will choose not to buy it. Moreover, as a BD chooses to direct fewer orders to a particular exchange, the value of the product to that BD decreases, for two reasons. First, the product will contain less information, because executions of the BD's trading activity will not be reflected in it. Second, and perhaps more important, the product will be less valuable to that BD because it does not provide information about the venue to which it is directing its orders. Data from the competing venue to which the BD is directing orders will become correspondingly more valuable.
Similarly, in the case of products such as NLS that are distributed through market data vendors, the vendors provide price discipline for proprietary data products because they control the primary means of access to end users. Vendors impose price restraints based upon their business models. For example, vendors such as Bloomberg and Reuters that assess a surcharge on data they sell may refuse to offer proprietary products that end users will not purchase in sufficient numbers. Internet portals, such as Google, impose a discipline by providing only data that will enable them to attract “eyeballs” that contribute to their advertising revenue. Retail BDs, such as Schwab and Fidelity, offer their customers proprietary data only if it promotes trading and generates sufficient commission revenue. Although the business models may differ, these vendors' pricing discipline is the same: they can simply refuse to purchase any proprietary data product that fails to provide sufficient value. NASDAQ and other producers of proprietary data products must understand and respond to these varying business models and pricing disciplines in order to market proprietary data products successfully. Moreover, NASDAQ believes that products such as NLS can enhance order flow to NASDAQ by providing more widespread distribution of information about transactions in real time, thereby encouraging wider participation in the market by investors with access to the internet or television. Conversely, the value of such products to distributors and investors decreases if order flow falls, because the products contain less content.
Analyzing the cost of market data distribution in isolation from the cost of all of the inputs supporting the creation of market data will inevitably underestimate the cost of the data. Thus, because it is impossible to create data without a fast, technologically robust, and well-regulated execution system, system costs and regulatory costs affect the price of market data. It would be equally misleading, however, to attribute all of the exchange's costs to the market data portion of an exchange's joint product. Rather, all of the exchange's costs are incurred for the unified purposes of attracting order flow, executing and/or routing orders, and generating and selling data about market activity. The total return that an exchange earns reflects the revenues it receives from the joint products and the total costs of the joint products.
Competition among trading platforms can be expected to constrain the aggregate return each platform earns from the sale of its joint products, but different platforms may choose from a range of possible, and equally reasonable, pricing strategies as the means of recovering total costs. NASDAQ pays rebates to attract orders, charges relatively low prices for market information and charges relatively high prices for accessing posted liquidity. Other platforms may choose a strategy of paying lower liquidity rebates to attract orders, setting relatively low prices for accessing posted liquidity, and setting relatively high prices for market information. Still others may provide most data free of charge and rely exclusively on transaction fees to recover their costs. Finally, some platforms may incentivize use by providing opportunities for equity ownership, which may allow them to charge lower direct fees for executions and data.
In this environment, there is no economic basis for regulating maximum prices for one of the joint products in an industry in which suppliers face competitive constraints with regard to the joint offering. Such regulation is unnecessary because an “excessive” price for one of the joint products will ultimately have to be reflected in lower prices for other products sold by the firm, or otherwise the firm will experience a loss in the volume of its sales that will be adverse to its overall
The level of competition and contestability in the market is evident in the numerous alternative venues that compete for order flow, including thirteen SRO markets, as well as internalizing BDs and various forms of alternative trading systems (“ATSs”), including dark pools and electronic communication networks (“ECNs”). Each SRO market competes to produce transaction reports via trade executions, and two FINRA-regulated TRFs compete to attract internalized transaction reports. It is common for BDs to further and exploit this competition by sending their order flow and transaction reports to multiple markets, rather than providing them all to a single market. Competitive markets for order flow, executions, and transaction reports provide pricing discipline for the inputs of proprietary data products.
The large number of SROs, TRFs, BDs, and ATSs that currently produce proprietary data or are currently capable of producing it provides further pricing discipline for proprietary data products. Each SRO, TRF, ATS, and BD is currently permitted to produce proprietary data products, and many currently do or have announced plans to do so, including NASDAQ, NYSE, NYSE MKT, NYSE Arca, BATS, and Direct Edge.
Any ATS or BD can combine with any other ATS, BD, or multiple ATSs or BDs to produce joint proprietary data products. Additionally, order routers and market data vendors can facilitate single or multiple BDs' production of proprietary data products. The potential sources of proprietary products are virtually limitless.
The fact that proprietary data from ATSs, BDs, and vendors can by-pass SROs is significant in two respects. First, non-SROs can compete directly with SROs for the production and sale of proprietary data products, as BATS and Arca did before registering as exchanges by publishing proprietary book data on the internet. Second, because a single order or transaction report can appear in a core data product, an SRO proprietary product, and/or a non-SRO proprietary product, the data available in proprietary products is exponentially greater than the actual number of orders and transaction reports that exist in the marketplace. Indeed, in the case of NLS, the data provided through that product appears both in (i) real-time core data products offered by the SIPs for a fee, and (ii) free SIP data products with a 15-minute time delay, and finds a close substitute in last-sale products of competing venues.
In addition to the competition and price discipline described above, the market for proprietary data products is also highly contestable because market entry is rapid, inexpensive, and profitable. The history of electronic trading is replete with examples of entrants that swiftly grew into some of the largest electronic trading platforms and proprietary data producers: Archipelago, Bloomberg Tradebook, Island, RediBook, Attain, TracECN, BATS Trading and Direct Edge. A proliferation of dark pools and other ATSs operate profitably with fragmentary shares of consolidated market volume.
Regulation NMS, by deregulating the market for proprietary data, has increased the contestability of that market. While BDs have previously published their proprietary data individually, Regulation NMS encourages market data vendors and BDs to produce proprietary products cooperatively in a manner never before possible. Multiple market data vendors already have the capability to aggregate data and disseminate it on a profitable scale, including Bloomberg and Thomson Reuters.
Moreover, consolidated data provides two additional measures of pricing discipline for proprietary data products that are a subset of the consolidated data stream. First, the consolidated data is widely available in real-time at $1 per month for non-professional users. Second, consolidated data is also available
The competitive nature of the market for products such as NLS is borne out by the performance of the market. In May 2008, the internet portal Yahoo! began offering its Web site viewers real-time last sale data (as well as best quote data) provided by BATS. In response, in June 2008, NASDAQ launched NLS, which was initially subject to an “enterprise cap” of $100,000 for customers receiving only one of the NLS products, and $150,000 for customers receiving both products. The majority of NASDAQ's sales were at the capped level. In early 2009, BATS expanded its offering of free data to include depth-of-book data. Also in early 2009, NYSE Arca announced the launch of a competitive last sale product with an enterprise price of $30,000 per month. In response, NASDAQ combined the enterprise cap for the NLS products and reduced the cap to $50,000 (
In this environment, a super-competitive increase in the fees charged for either transactions or data has the potential to impair revenues from both products. “No one disputes that competition for order flow is `fierce'.”
In establishing the price for the NASDAQ Last Sale Products, NASDAQ considered the competitiveness of the market for last sale data and all of the implications of that competition. NASDAQ believes that it has considered all relevant factors and has not considered irrelevant factors in order to establish fair, reasonable, and not unreasonably discriminatory fees and an equitable allocation of fees among all
Three comment letters were filed regarding the proposed rule change as originally published for comment NASDAQ responded to these comments in a letter dated December 13, 2007. Both the comment letters and NASDAQ's response are available on the SEC Web site at
While containing a few superficial modifications from prior letters, SIFMA and NetCoalition's most recently submitted letter continues to mischaracterize the import of the original
The petitioners believe that the SEC's market-based approach is prohibited under the Exchange Act because the Congress intended “fair and reasonable” to be determined using a cost-based approach. The SEC counters that, because it has statutorily-granted flexibility in evaluating market data fees, its market-based approach is fully consistent with the Exchange Act. We agree with the SEC.
SIFMA and NetCoalition further contend the prior filing lacked evidence supporting a conclusion that the market for NLS is competitive, asserting that arguments about competition for order flow and substitutability were rejected in
The foregoing rule change 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 Elizabeth M. Murphy, Secretary, Securities and Exchange Commission,
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1)
The Exchange proposes to modify the NYSE Amex Options Fee Schedule to Establish Fees for Mini-Options Contracts. The text of 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, of the most significant parts of such statements.
The Exchange proposes to modify the Fee Schedule to establish fees for Minis.
The Exchange represented in its filing with the Commission to establish Minis that, “the current schedule of Fees will not apply to the trading of mini-options contracts. The Exchange will not commence trading of mini-option contracts until specific fees for mini-options contracts trading have been filed with the Commission.”
Minis have a smaller exercise and assignment value due to the reduced number of shares they deliver as compared to standard option contracts. As such, the Exchange is proposing generally lower per contract fees as compared to standard option contracts, with some exceptions to be fully described below. Despite the smaller exercise and assignment value of a Mini, the cost to the Exchange to process quotes and orders in Minis, perform regulatory surveillance and retain quotes and orders for archival purposes is the same as a for a standard contract. This leaves the Exchange in a position of trying to strike the right balance of fees applicable to Minis—too low and the costs of processing Mini quotes and orders will necessarily cause the Exchange to either raise fees for everyone or only for participants trading Minis; too high and participants may be deterred from trading Minis, leaving the Exchange less able to recoup costs associated with development of the product, which is designed to offer investors a way to take less risk in high dollar securities. The Exchange, therefore, believes that adopting fees for Minis that are in some cases lower than fees for standard contracts, and in other cases the same as for standard contracts, is appropriate, not unreasonable, not unfairly discriminatory and not burdensome on competition between
The following is a discussion of the existing Fee Schedule as it relates to the treatment of Mini options as compared to standard option contracts.
Trading Permit Fees: The number of Trading Permits or ATPs required by participants is unchanged by the introduction of Mini options.
Specialist/e-Specialist/DOMM Rights Fees: The monthly rights fees charged to Specialists, e-Specialists and Directed Order Market Makers (“DOMMs”) will continue to apply to them for transactions executed in Mini options. For purposes of calculating the Rights Fee, a transaction in a Mini option shall be counted the same as a transaction in a standard option contract from a volume perspective (i.e., one contract in a Mini will equal one contract in a standard option contract).
Premium Product Issues List—Monthly NYSE Amex Options Market Maker Participation Fee: Currently, the Premium Product Issues List is comprised of SPY, AAPL, IWM, QQQ, BAC, EEM, GLD, JPM, XLF and VXX. The Exchange notes that of these, three will have Mini options available for trading, specifically AAPL, GLD and SPY. To the extent that a NYSE Amex Options Market Maker transacts in any option series associated with a Premium Product Issue, including Mini option series, it will become liable for the associated Monthly Fee of $1,000 per product, which is capped at $7,000 per NYSE Amex Options Market Maker per month.
Options Regulatory Fee: Presently the Exchange charges an Options Regulatory Fee (“ORF”) of $0.005 per contract. The ORF is assessed on each ATP Holder for all options transactions executed or cleared by the ATP Holder that are cleared by The Options Clearing Corporation (“OCC”) in the customer range, regardless of the exchange on which the transaction occurs. The Exchange is proposing to charge the same rate for transactions in Mini options, $0.005 per contract, since, as noted, the costs to the Exchange to process quotes, orders, trades and the necessary regulatory surveillance programs and procedures in Minis are the same as for standard option contracts. As such, the Exchange feels that it is appropriate to charge the ORF at the same rate as the standard option contract. The Exchange is proposing a non-substantive change to remove obsolete text describing a recent effective date for a change in the rate of the ORF.
Below, the Exchange will discuss the newly proposed per contract transaction charges applicable to Minis. The table below will show the per contract charge applicable to electronic, manual, electronic complex orders, and QCC executions in Minis for various participants on the Exchange:
As with standard options, Customers transacting Mini options on the Exchange will trade for free. Mini options contracts on the Exchange will NOT count toward the Customer Electronic average daily volume (“ADV”) Tiers or associated rebates paid to Order Flow Providers (“OFPs”) described in endnote 17 to the current Fee Schedule.
NYSE Amex Options Market Makers trading Mini options will be charged $.02 per contract, except for QCC executions, where the charge will be $.10 per contract. As with standard options, when an NYSE Amex Options Market Maker trades contra to a Customer electronic order or Customer electronic Complex order, it will be subject to marketing charges. The marketing charges for Mini options will be $.02 for Penny Pilot names and $.06 for non-Penny Pilot names. These charges are generally anywhere from slightly less than
Firm transactions in Mini options will be charged at the rate of $.09 per contract, except for QCC trades, where they will be charged $.10 per contract, and Firm Facilitation trades, which will be charged $.00 per contract. Additionally, the existing Firm Proprietary monthly fee cap for manual or open outcry trades described in endnote 6 of the current Fee Schedule will NOT apply to Mini transactions. As noted earlier, the cost to the Exchange to process quotes, orders and trades in Minis is the same as for standard options, therefore the Exchange does not wish to include Firm trades in Mini options in the monthly fee cap. Further, the proposed charge is higher than
Non-NYSE Amex Options Market Makers in Mini options will be charged at the rate of $.09 per contract, except for QCC trades, where they will be charged $.10 per contract ($.05 charge per contract side). The proposed charge is higher than
Professional Customer and Broker Dealer participants in Mini options will be charged at the rate of $.09 per contract, except for QCC trades, where they will be charged $.10 per contract. The proposed charge is higher than
NYSE Amex Floor Brokers who execute Mini options will be eligible for a $.02 per contract rebate for Mini options trades executed as a QCC trade. As with standard options, the rebate will NOT be paid for Customer to Customer QCC trades, as described in endnote 15 to the current Fee Schedule.
Routing Surcharge: In order to comply with the requirements of the Distributive Linkage Plan,
Limit Of Fees On Options Strategy Executions: Presently, the Exchange has a $750 cap on transaction fees for Strategy Executions involving reversals and conversions, box spreads, short stock interest spreads, merger spreads and jelly rolls. The fees for these Strategy Executions are further capped at $25,000 per month per initiating firm.
The Exchange will NOT include Mini option transactions as being eligible for any part of these per trade or per month Strategy Execution caps. As noted earlier, the cost to the Exchange to process quotes, orders and trades in Minis is the same as for standard options. Given that the per contract transaction fees are already substantially lower than the per contract fees for standard options, inclusion of Mini options in these fee caps is not warranted.
Order To Trade Ratio Fee: For purposes of calculating the Order To Trade Ratio Fee, an order and an execution in Mini options will be counted the same as an order and an execution in standard option contracts.
Messages To Contracts Traded Ratio Fee: For purpose of calculating the Messages to Contracts Traded Ratio Fee, quotes, orders and any executed contracts in Mini options will be counted the same as quotes, orders and any executed contracts involving standard option contracts.
Cancellation Fee: For purposes of calculating the Cancellation Fee, orders and executions in Mini options will be counted as being equivalent to an order or execution for a standard option contract.
As noted, the cost to the Exchange to process quotes, orders and trades in Minis is the same as for standard options and, as such, treating Minis the same as standard option contracts for the purposes of calculating any of the Excessive Bandwidth Utilization Fees is reasonable and equitable.
The Exchange proposes to implement these changes on March 18, 2013.
The Exchange believes that the proposed rule change is consistent with Section 6(b) of the Act,
For purposes of the Fee Schedule relating to ATP fees, Specialist/e-Specialist/DOMM Rights Fees, the Premium Product Issues List—Monthly NYSE Amex Options Market Maker Participation Fee and the regulatory fees, including the ORF, the Exchange is not proposing any changes as a result of the introduction of Minis. This is due to, in part, the fact that the Exchange intends to have the Minis trade with the existing Specialist, e-Specialists and NYSE Amex Options Market Makers who trade AAPL. The Exchange is doing so as it believes it will foster transparency and better price discovery in Minis. This means that for example, the existing Specialist, e-Specialist, and NYSE Amex Options Market Makers will be able, and in fact obligated, to quote and trade AAPL Minis. This being the case, the Exchange believes it is entirely appropriate and, in fact, necessary, to treat Mini options the same as standard options with respect to the fees listed above. The fees listed above for standard options have not been deemed to be unreasonable, inequitable, or unfairly discriminatory and the introduction of Mini options raises no new issues with respect to such fees. Hence, the treatment of Minis in the same manner as standard option contracts for purposes of the ATP fees, Specialist/e-Specialist/DOMM Rights Fees, the Premium Product Issues List—Monthly NYSE Amex Options Market Maker Participation Fee and the regulatory fees, including the ORF, is reasonable, equitable and not unfairly discriminatory. Further, the Exchange notes, particularly in the context of the ORF, that the cost to perform surveillance to ensure compliance with various Exchange and industry-wide rules is no different for a Mini option than it is for a standard option contract. Reducing the ORF for Mini options could result in a higher ORF for standard options. Such an outcome would arguably be discriminatory towards investors in standard options for the benefit of investors in Minis. As such, the appropriate approach is to treat both Minis and standard options the same with respect to the amount of the ORF that is being charged.
The Exchange noted earlier that, while Minis have a smaller exercise and assignment value due to the reduced number of shares to be delivered as compared to standard option contracts, and despite the smaller exercise and assignment value of a Mini, the cost to the Exchange to process quotes and orders in Minis, perform regulatory surveillance and retain quotes and orders for archival purposes is the same as for a standard contract. This leaves the Exchange in a position of trying to strike the right balance of fees applicable to Minis—too low and the costs of processing Mini quotes and orders will necessarily cause the Exchange to either raise fees for everyone or only for participants trading Minis; too high and participants may be deterred from trading Minis, leaving the Exchange less able to recoup costs associated with development of the product, which is designed to offer investors a way to take less risk in high dollar securities. Given these realities, the Exchange believes that adopting fees for Minis that are in some cases lower than standard contracts, and in other cases the same as for standard contracts, is appropriate, not unreasonable, not unfairly discriminatory and not burdensome on competition between participants, or between the Exchange and other exchanges in the listed options market place.
In the case of most trade related charges, the Exchange has decided to offer lower per contract fees to participants as part of trying to strike the right balance between recovering costs associated with trading Minis and encouraging use of the new Mini option contracts, which are designed to allow investors to reduce risk in high dollar underlying securities.
The Exchange proposal to charge Customers $.00 per contract is reasonable, as Customers have long traded for free all options on the Exchange. The ability to trade for free attracts Customer order flow to the Exchange, which is beneficial to all other participants on the Exchange who generally seek to trade with Customer order flow. The proposed fee of $.00 per contract is the same fee charged to Customer orders in standard option contracts, which is an effective fee on the Exchange and has not been determined to be inequitable or unfairly discriminatory. Therefore, the proposed Customer pricing for Minis is equitable and not unfairly discriminatory. The Exchange feels that different rates for Customer transaction fees as compared to other market participants is equitable and not unfairly discriminatory because non-Customers wish to have Customer orders attracted to the Exchange by having lower fees, and is equitable and not unfairly discriminatory to Firms and Broker Dealers because Market Makers have obligations that are not required of Firms and Broker Dealers and because Market Makers have additional costs that are not applicable to Firms and Broker Dealers.
The Exchange proposal to exclude volumes attributable to Customer executions in Mini options from the Customer Electronic ADV Tiers and associated rebates paid to OFPs described in endnote 17 to the current Fee Schedule is reasonable, equitable and not unfairly discriminatory for the following reasons. First, as noted above, the Exchange's cost to process quotes, orders and trades in Minis is the same as for standard options. Given the overall lower expected revenues from Mini options, it is reasonable to exempt Mini option volumes from qualifying for the OFP rebate paid on standard option contracts. It is also equitable, since paying the rebate on Mini option volumes would likely necessitate either reducing the rebates paid to OFPs for all activity, or raising other participant fees. It is not unfairly discriminatory, as it will apply equally to all Customer executions in Mini options, regardless of the market participant submitting the order.
The Exchange proposal to charge NYSE Amex Market Makers, including Specialists, e-Specialists, Non-DOMMs and DOMMs a flat rate of $.02 per contract, plus either $.02 (for Penny Pilot issues) or $.06 (for non-Penny Pilot issues) per contract in Marketing Charges when they trade contra to an electronic Customer order or an electronic Customer complex order, is reasonable. Generally, these fees range from slightly more than, to slightly less than, 10% of what the various NYSE Amex Options Market Maker participants pay today. Charging all types of NYSE Amex Options Market Makers the same fees to trade Minis is not unfairly discriminatory, as it applies to all of them equally. The fees are reasonable in light of the fact that the Minis do have a smaller exercise and
The Exchange feels that different rates for NYSE Amex Market Maker transaction fees as compared to other market participants is equitable and not unfairly discriminatory because non-Customers wish to have Customer orders attracted to the Exchange by having lower fees, and is equitable and not unfairly discriminatory to Firms and Broker Dealers because NYSE Amex Market Makers have obligations that are not required of Firms and Broker Dealers and because NYSE Amex Market Makers have additional costs that are not applicable to Firms and Broker Dealers. For example, NYSE Amex Options Market Makers are required to have trading permits in order to stream quotes. The number of permits is variable based on the number of options traded, and can cost as much as $26,000 per month to quote all issues on the Exchange as an NYSE Amex Options Market Maker. Conversely, Firms pay a monthly permit fee of $1,000 per month and broker dealers, Professional Customers and Non-NYSE Amex Options Market Makers typically access the facilities of the Exchange through either a Firm or Order Flow Provider who may or may not pass along the $1,000 per month permit fee cost. Consequently, when all fees are taken together, the difference charged to NYSE Amex Options Market Makers as compared to Professional Customers, broker dealers, Non-NYSE Amex Options Market Makers and Firms is reasonable, equitable and not unfairly discriminatory. The Exchange further notes that there are no limits on the number of NYSE Amex Options Market Makers that are permitted to quote in a given option and that any of the other participant types are free to apply to the Exchange to become a NYSE Amex Options Market Maker to avail themselves of the transaction charges applicable to NYSE Amex Options Market Makers presuming they are willing to accept the quoting obligations applicable to NYSE Amex Options Market Makers, which serve to foster price discovery and transparency.
The Exchange proposal to charge Firm proprietary trades $.09 per contract, charge Firm Facilitation trades $.00 and to exclude Mini options from the Firm monthly fee cap is reasonable, equitable and not unfairly discriminatory. First, the per contract charge is lower than what Firms pay for a standard contract in acknowledgement of the smaller exercise and assignment value. Although more than 10% of the rate paid by a Firm for a standard contract, this is warranted by the fact that the Exchange's cost to process quotes, orders and trades in Minis is the same as for standard options. In this regard the proposal is reasonable and it is also equitable, as it allows the Exchange to offer this innovative product to investors without raising fees for other investors who may have no interest in trading Minis. Likewise, excluding Mini option volumes from the Firm monthly fee cap for manual trades is reasonable and equitable in light of the Exchange's desire to fund the costs associated with Minis with revenues from only those participants who trade them. Offering a fee cap for a product with reduced fees might necessitate raising costs for other participants; therefore, the Exchange believes that the exclusion from the Firm monthly fee cap for manual trades is both reasonable and equitable. The per contract Mini pricing for all Firms is the same, the proposal is also not unfairly discriminatory. Finally, as noted earlier, the Exchange recognizes that Firms can be an important source of liquidity when they facilitate their own customer volumes. Firm Facilitation trades add transparency and promote price discovery to the benefit of all market participants. For these reasons, the proposal to bill Firm Facilitation trades in Minis at the rate of $.00 per contract is both reasonable and equitable. It is also not unfairly discriminatory as it applies equally to all Firms and their customers whose business is facilitated by the Firms.
The Exchange proposal to charge non-NYSE Amex Options Market Maker Mini trades $.09 per contract is reasonable, equitable and not unfairly discriminatory. First, the per contract charge is lower than what non-NYSE Amex Options Market Makers pay for a standard contract, in acknowledgement of the smaller exercise and assignment value. Although more than 10% of the rate paid by a non-NYSE Amex Options Market Maker for a standard contract, this is warranted by the fact that the Exchange's cost to process quotes, orders and trades in Minis is the same as for standard options. In this regard, the proposal is reasonable and it is also equitable as it allows the Exchange to offer this innovative product to investors without raising fees for other investors who may have no interest in trading Minis. As the per contract Mini pricing for all non-NYSE Amex Options Market Makers is the same, the proposal is also not unfairly discriminatory.
The Exchange feels that different rates for non-NYSE Amex Options Market Maker transaction fees as compared to other market participants is equitable and not unfairly discriminatory because non-Customers wish to have Customer orders attracted to the Exchange by having lower fees, and is equitable and not unfairly discriminatory to Firms and Broker Dealers, including non-NYSE Amex Market Makers, because NYSE Amex Options Market Makers have obligations that are not required of Firms and Broker Dealers, including non-NYSE Amex Market Makers, and because NYSE Amex Market Makers have additional costs that are not applicable to Firms and Broker Dealers, including non-NYSE Amex Market Makers. For example, as noted earlier, NYSE Amex Options Market Makers are required to have trading permits in order to stream quotes. The number of permits is variable based on the number of options traded, and can cost as much as $26,000 per month to quote all issues on the Exchange as an NYSE Amex Options Market Maker. Conversely, Firms pay a monthly permit fee of $1,000 per month and broker dealers, Professional Customers and Non-NYSE Amex Options Market Makers typically access the facilities of the Exchange through either a Firm or Order Flow Provider who may or may not pass along the $1,000 per month permit fee cost. Consequently, when all fees are taken together, the difference charged to NYSE Amex Options Market Makers as compared to Professional Customers, broker dealers, Non-NYSE Amex Options Market Makers and Firms is reasonable, equitable and not unfairly discriminatory. The Exchange further notes that there are no limits on the number of NYSE Amex Options Market Makers that are permitted to quote in a given option and that any of the other participant types are free to apply to the
The Exchange proposal to charge Professional Customer and Broker Dealer Mini trades $.09 per contract and exclude Mini option volumes from the Professional Customer and Broker Dealer Electronic ADV Tiers For Taking Liquidity, as described in endnote 16 of the current Fee Schedule, is reasonable, equitable and not unfairly discriminatory. First, the per contract charge is lower than what Professional Customers and Broker Dealers pay for a standard contract, in acknowledgement of the smaller exercise and assignment value. Although more than 10% of the rate paid by a Professional Customer and Broker Dealers for a standard contract, this is warranted by the fact that the Exchange's cost to process quotes, orders and trades in Minis is the same as for standard options. In this regard, the proposal is reasonable and it is also equitable as it allows the Exchange to offer this innovative product to investors without raising fees for other investors who may have no interest in trading Minis. As the per contract Mini pricing for all Professional Customer and Broker Dealers is the same, the proposal is also not unfairly discriminatory. The Exchange proposal to exclude volumes attributable to Professional Customer and Broker Dealer executions in Mini options from the Professional Customer and Broker Dealer Electronic ADV Tiers For Taking Liquidity, as described in endnote 16 of the current Fee Schedule, is reasonable, equitable and not unfairly discriminatory for the following reasons. First, as noted above, the Exchange's cost to process quotes, orders and trades in Minis is the same as for standard options. Given the overall lower expected revenues from Mini options, it is reasonable to exempt Mini option volumes from Professional Customer and Broker Dealer Electronic ADV Tiers For Taking Liquidity, as the per contract charge for Minis is quite low to begin with—for example, the lowest fee charged to the highest volume Professional Customer and Broker Dealer is $.23 per contract, which is still more than double the proposed Mini pricing of $.09 per contract. It is also equitable since paying the rebate on Mini option volumes would likely necessitate either reducing the rebates paid to Professional Customers and Broker Dealers for standard option contracts volumes, or raising other participant fees. It is not unfairly discriminatory as it will apply equally to all Professional Customer and Broker Dealer executions in Mini options.
The Exchange feels that different rates for Professional Customer and Broker Dealer transaction fees as compared to other market participants is equitable and not unfairly discriminatory because non-Customers wish to have Customer orders attracted to the Exchange by having lower fees, and is equitable and not unfairly discriminatory to Professional Customers, Firms and Broker Dealers because NYSE Amex Market Makers have obligations that are not required of Professional Customer, Firms and Broker Dealers and because NYSE Amex Market Makers have additional costs that are not applicable to Professional Customers, Firms and Broker Dealers. For example, as noted earlier, NYSE Amex Options Market Makers are required to have trading permits in order to stream quotes. The number of permits is variable based on the number of options traded, and can cost as much as $26,000 per month to quote all issues on the Exchange as an NYSE Amex Options Market Maker. Conversely, Firms pay a monthly permit fee of $1,000 per month and broker dealers, Professional Customers and Non-NYSE Amex Options Market Makers typically access the facilities of the Exchange through either a Firm or Order Flow Provider who may or may not pass along the $1,000 per month permit fee cost. Consequently, when all fees are taken together, the difference charged to NYSE Amex Options Market Makers as compared to Professional Customers, broker dealers, Non-NYSE Amex Options Market Makers and Firms is reasonable, equitable and not unfairly discriminatory. The Exchange further notes that there are no limits on the number of NYSE Amex Options Market Makers that are permitted to quote in a given option and that any of the other participant types are free to apply to the Exchange to become a NYSE Amex Options Market Maker to avail themselves of the transaction charges applicable to NYSE Amex Options Market Makers presuming they are willing to accept the quoting obligations applicable to NYSE Amex Options Market Makers, which serve to foster price discovery and transparency.
The Exchange proposal for QCC pricing for Minis is to charge Customers $.00, as is the case with standard options, and all non-Customers will be charged $.10 per contract, as compared with $.20 per contract for standard options. The Exchange will also offer NYSE Amex Floor Brokers a rebate of $.02 per contract for all Mini options they execute as a QCC trade, as compared to $.07 per contract rebate for standard options. The Exchange believes that this pricing is reasonable, equitable and not unfairly discriminatory. First, the Exchange has always charged a premium for non-Customer participants for QCC trades in standard options due to the fact that qualifying QCC trades are executed immediately, upon entry, without exposure or any opportunity for other participants to participate on the trade. This pricing proposal preserves that premium and, as such, is reasonable. It is equitable since, as noted, the Exchange's cost to process quotes, orders and trades in Minis is the same as for standard options, so charging a relatively small premium for the opportunity to trade without exposure is warranted, given the Exchange's need to cover the costs of participants trading Minis so as to avoid sharing those costs with other participants who are not trading Minis. The proposal is also not unfairly discriminatory as it applies equally to all Customers. Likewise all non-Customers are treated the same under this proposal. The Floor Broker rebate of $.02 is reasonable and equitable as it is designed to allow Floor Brokers to compete for QCC volumes that might otherwise execute on an exchange that offers a front end order entry system, like ISE PrecISE Trade application
The Exchange feels that different rates for QCC fees for different market participants is equitable and not unfairly discriminatory because non-Customers wish to have Customer orders attracted to the Exchange by having lower fees, and is equitable and not unfairly discriminatory to Firms and Broker Dealers because Market Makers have obligations that are not required of Firms and Broker Dealers and because Market Makers have additional costs that are not applicable to Firms and Broker Dealers. The Exchange notes that QCC pricing for standard options is $.20 for non-Customers and $.00 for Customers. Such differential has been shown by virtue of its effectiveness for
The Exchange proposal to treat Mini options the same as standard options for purposes of the Routing Surcharge is reasonable, equitable and not unfairly discriminatory for the following reasons. Presently, the Exchange charges a Routing Surcharge of $.11 per contract plus a pass through of the fees associated with the execution of the routed order on the other exchanges. The $.11 is designed to recover the Exchange's costs in routing orders to the other exchanges. Those costs include clearance charges imposed by The OCC and per contract routing fees charged by the broker dealers who charge the Exchange for the use of their systems to route orders to other exchanges. The Exchange has spoken with both The OCC and the broker dealers, who have informed the Exchange that their charges applicable to Mini options will be the same as for standard option contracts, as their cost to process a contract (i.e., routing or clearing) is the same irrespective of the exercise and assignment value of the contract. As such, the Exchange intends to charge the same Routing Surcharge for Mini options as it presently does for standard options, as described in endnote 7 of the current Fee Schedule. The Exchange notes that participants can avoid the Routing Surcharge in several ways. First they can simply route to the exchange with the best priced interest. The Exchange, in recognition of the fact that markets can move while orders are in flight, also offers participants the ability to utilize order types that do not route to other exchanges. Specifically, the PNP order modifier is one such order that would never route to another exchange. In addition, there are others, such as PNP Blind and PNP Plus,
The Exchange is proposing to exclude Mini option volumes from being eligible for the Limit Of Fees On Options Strategy Executions. Presently the Exchange has a $750 cap on transaction fees for Strategy Executions involving reversals and conversions, box spreads, short stock interest spreads, merger spreads and jelly rolls. The fees for these Strategy Executions are further capped at $25,000 per month per initiating firm. The Exchange will NOT include Mini option transactions as being eligible for any part of these per trade or per month Strategy Execution caps. As noted earlier, the cost to the Exchange to process quotes, orders and trades in Minis is the same as for standard options. Given that the per contract transaction fees for Minis are already substantially lower than the per contract fees for standard options, inclusion of Mini options in these fee caps is not warranted, and is reasonable and equitable. Further, it is not unfairly discriminatory as the exclusion on Mini volumes from the cap on fees for Strategy Executions applies equally to all participants on the Exchange.
The Exchange proposes to treat Mini options the same as standard options for purposes of the Excessive Bandwidth Utilization Fees, which include the Order To Trade Ratio Fee, the Messages to Contracts Traded Ratio Fee and the Cancellation Fees. As noted, the cost to the Exchange to process quotes, orders and trades in Minis is the same as for standard options and, as such, treating Minis the same as standard option contracts for the purposes of calculating any of the Excessive Bandwidth Utilization Fees is reasonable and equitable. It is also not unfairly discriminatory, as such treatment will apply to all participants equally.
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.
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. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send paper comments in triplicate to Elizabeth M. Murphy, 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)
The Exchange proposes to modify the NYSE Arca Options Fee Schedule (the “Fee Schedule”) to establish fees for mini-options contracts (“Minis”). The text of 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, of the most significant parts of such statements.
The Exchange proposes to modify the Fee Schedule to establish fees for Minis.
The Exchange represented in its filing with the Commission to establish Minis that “the current schedule of Fees will not apply to the trading of mini-options contracts. The Exchange will not commence trading of mini-option contracts until specific fees for mini-options contracts trading have been filed with the Commission.”
Minis have a smaller exercise and assignment value due to the reduced number of shares they deliver as compared to standard option contracts. As such, the Exchange is proposing generally lower per contract fees as compared to standard option contracts, with some exceptions to be fully described below. Despite the smaller exercise and assignment value of a Mini, the cost to the Exchange to process quotes and orders in Minis, perform regulatory surveillance and retain quotes and orders for archival purposes is the same as a for a standard contract. This leaves the Exchange in a position of trying to strike the right balance of fees applicable to Minis—too low and the costs of processing Mini quotes and orders will necessarily cause the Exchange to either raise fees for everyone or just for participants trading Minis; too high and participants may be deterred from trading Minis, leaving the Exchange less able to recoup costs associated with development of the product, which is designed to offer investors a way to take less risk in high dollar securities. The Exchange believes, therefore, that adopting fees for Minis that are in some cases lower than fees for standard contracts, and in other cases the same as for standard contracts, is appropriate, not unreasonable, not unfairly discriminatory and not burdensome on competition between participants, or between the Exchange and other exchanges in the listed options market place.
What follows is a discussion of the existing Fee Schedule as it relates to the treatment of Mini options as compared to standard option contracts.
Trading Permit Fees: The number of Trading Permits or OTPs required by participants is unchanged by the introduction of Mini options.
Lead Market Maker (“LMM”) Rights Fees: The monthly rights fees charged to LMMs will continue to apply to them for transactions executed in Mini options. For purposes of calculating the Rights Fee, a transaction in a Mini option shall be counted the same as a transaction in a standard option contract from a volume perspective (i.e., one contract in a Mini will equal one contract in a standard option contract).
Options Regulatory Fee: Presently the Exchange charges an Options Regulatory Fee (“ORF”) of $0.005 per contract. The ORF is assessed on each OTP Holder for all options transactions executed or cleared by the OTP Holder that are cleared by The Options Clearing Corporation (“OCC”) in the customer range, regardless of the exchange on which the transaction occurs. The Exchange is proposing to charge the same rate for transactions in Mini options, $0.005 per contract, since, as noted, the costs to the Exchange to process quotes, orders, trades and the necessary regulatory surveillance
The Exchange discusses below the newly proposed per contract transaction charges applicable to Minis. The tables below show the per contract charge applicable to electronic, manual, electronic complex orders, and QCC executions in Minis for various participants on the Exchange:
As with standard options, Customers manually transacting Mini options on the Exchange will trade for free. Mini options contracts on the Exchange will NOT count toward the Customer Monthly Posting Credit Tiers or Super Tier and Qualifications for Executions in Penny Pilot Issues and SPY or associated rebates paid to Order Flow Providers (“OFPs”) described in endnote 8 to the current Fee Schedule.
Customers electronically transacting Mini options in Penny Pilot issues will receive a rebate of $.03 when they post liquidity and be charged $.06 when they take liquidity. Customers electronically transacting Mini options in non-Penny Pilot issues will receive a rebate of $.04 when they post liquidity and be charged $.08 when they take liquidity. For Complex Order to Complex Order executions, Customers electronically transacting Mini options will receive a rebate of $.03 in Penny Pilot issues and will receive a rebate of $.04 in non-Penny Pilot issues. For Complex Orders that execute against the Consolidated Book, Customers electronically transacting Mini options will be charged $.06 in Penny Pilot issues and will be charged $.08 in non-Penny Pilot issues.
For Mini option transactions, all NYSE Arca Market Makers, including Lead Market Makers, will have the same rates and charges applied. NYSE Arca Options Market Makers manually trading Mini options will be charged $.02 per contract. NYSE Arca Options Market Makers electronically transacting Mini options in Penny Pilot issues will receive a rebate of $.04 when they post liquidity and be charged $.07 when they take liquidity. NYSE Arca Options Market Makers electronically transacting Mini options in non-Penny Pilot issues will receive a rebate of $.06 when they post liquidity and be charged $.10 when they take liquidity. For Complex Order to Complex Order executions, NYSE Arca Options Market Makers electronically transacting Mini options will be charged $.08 in Penny Pilot issues and will be charged $.10 in non-Penny Pilot issues. For Complex Orders that execute against the Consolidated Book, NYSE Arca Options Market Makers electronically transacting Mini options will be charged $.07 in Penny Pilot issues and will be charged $.10 in non-Penny Pilot issues. These NYSE Arca Options Market Maker charges are generally anywhere from slightly less than 1/10th to slightly more than 1/10th of the charges incurred by NYSE Arca Options Market Makers today for standard option contract transactions.
Firm and Broker Dealer manual transactions, in Mini options will be charged at the rate of $.09 per contract. Firms and Broker Dealers electronically transacting Mini options in Penny Pilot issues will receive a rebate of $.01 when they post liquidity and be charged $.09 when they take liquidity. Firms and Broker Dealers electronically transacting Mini options in non-Penny Pilot issues will neither be charged nor receive a credit (
Additionally, the existing $75,000 cap per month of fees on Firm and Broker Dealer open outcry trades described in endnote 9 of the current Fee Schedule will NOT include Mini transactions. As noted earlier, the cost to the Exchange to process quotes, orders and trades in Minis is the same as for standard options, therefore the Exchange does not wish to include Firm and Broker Dealer trades in Mini options in the monthly fee cap. Further, the proposed charge is slightly higher than 1/10th of the current charges applicable to Firm Proprietary trades. This relatively higher rate is necessitated by the fact that the cost to the Exchange to process quotes, orders and trades in Minis is the same as for standard options.
OTP Holders or OTP Firms that execute QCC transactions in Minis will be charged $0.05 per contract side. QCC transactions in Minis executed by a Floor Broker on the Floor of the Exchange will be eligible for a $0.01 rebate per contract side rebate.
Routing Surcharge: In order to comply with the requirements of the Distributive Linkage Plan,
Limit Of Fees On Options Strategy Executions: Presently, the Exchange has a $750 cap on transaction fees for Strategy Executions involving reversals and conversions, box spreads, short stock interest spreads, merger spreads and jelly rolls. The fees for these Strategy Executions are further capped at $25,000 per month per initiating firm. The Exchange will NOT include Mini option transactions as being eligible for any part of these per trade or per month Strategy Execution caps. As noted earlier, the cost to the Exchange to process quotes, orders and trades in Minis is the same as for standard options. Given that the per contract transaction fees are already substantially lower than the per contract fees for standard options, inclusion of Mini options in these fee caps is not warranted.
Order To Trade Ratio Fee: For purposes of calculating the Order To Trade Ratio Fee, an order and an execution in Mini options will be counted the same as an order and an execution in standard option contracts.
The Exchange proposes to implement these changes on March 18, 2013.
The Exchange believes that the proposed rule change is consistent with Section 6(b) of the Act,
For purposes of the Fee Schedule relating to OTP fees, LMM Rights Fees, and the regulatory fees, including the ORF, the Exchange is not proposing any changes as a result of the introduction of Minis. This is due to, in part, the fact that there will be no separate allocation for Minis—the existing LMMs and NYSE Arca Options Market Makers who trade AAPL, for example, will automatically be able, and obligated, to quote and trade AAPL Minis. Since this is the case, the Exchange believes it is entirely appropriate and, in fact, necessary, to treat Mini options the same as standard options with respect to the fees listed above. The fees listed above have not been deemed to be unreasonable, inequitable, or unfairly discriminatory, and the introduction of Mini options raises no new issues with respect to such fees. Therefore, the treatment of Minis in the same manner as standard option contracts for purposes of the OTP fees, LMM Rights Fees, and the regulatory fees, including the ORF, is reasonable, equitable and not unfairly discriminatory. Further, the Exchange notes, particularly in the context of the ORF, that the cost to perform surveillance to ensure compliance with various Exchange and industry-wide rules is no different for a Mini option than it is for a standard option contract. Reducing the ORF for Mini options could result in a higher ORF for standard options. Such an outcome would arguably be discriminatory towards investors in standard options for the benefit of
The Exchange noted earlier that, while Minis have a smaller exercise and assignment value due to the reduced number of shares to be delivered as compared to standard option contracts, and despite the smaller exercise and assignment value of a Mini, the cost to the Exchange to process quotes and orders in Minis, perform regulatory surveillance and retain quotes and orders for archival purposes is the same as for a standard contract. This leaves the Exchange in a position of trying to strike the right balance of fees applicable to Minis—too low and the costs of processing Mini quotes and orders will necessarily cause the Exchange to either raise fees for everyone or just for participants trading Minis; too high and participants may be deterred from trading Minis, leaving the Exchange less able to recoup costs associated with development of the product, which is designed to offer investors a way to take less risk in high dollar securities. The Exchange believes, therefore, that adopting fees for Minis that are in some cases lower than standard contracts, and in other cases the same as for standard contracts, is appropriate, not unreasonable, not unfairly discriminatory and not burdensome on competition between participants, or between the Exchange and other exchanges in the listed options market place.
In the case of most trade related charges, the Exchange has decided to offer lower per contract fees to participants as part of trying to strike the right balance between recovering costs associated with trading Minis and encouraging use of the new Mini option contracts, which are designed to allow investors to reduce risk in high dollar underlying securities.
The Exchange proposal to charge Customers $.00 per contract for manual orders is reasonable, as Customers have long traded manual orders for free on all options on the Exchange. The ability to trade manual orders for free attracts Customer order flow to the Exchange, which is beneficial to all other participants on the Exchange who generally seek to trade with Customer order flow. The proposed fee of $.00 per contract is the same fee charged to Customer manual orders in standard option contracts, which is an effective fee on the Exchange and has not been determined to be inequitable or unfairly discriminatory. Therefore, the proposed Customer pricing for Minis is equitable and not unfairly discriminatory. The Exchange feels that different rates for Customer manual transaction fees as compared to other market participants is equitable and not unfairly discriminatory because non-Customers wish to have Customer orders attracted to the Exchange by having lower fees, and is equitable and not unfairly discriminatory to Firms and Broker Dealers because Market Makers have obligations that are not required of Firms and Broker Dealers and because Market Makers have additional costs that are not applicable to Firms and Broker Dealers.
The Exchange proposal to credit Customers electronically transacting Mini options in Penny Pilot and non-Penny Pilot issues $.03 and $.04, respectively, per contract when they post liquidity and charging them $.06 and $.08, respectively, when they take liquidity is reasonable, as Customers are currently subject to the same pricing structure (albeit at higher rates) for standard options. The rates proposed for Customer Minis transactions for Complex Order to Complex Order executions (a rebate of $.03 in Penny Pilot issues and a rebate of $.04 in non-Penny Pilot issues) and Complex Orders that execute against the Consolidated Book (a charge of $.06 in Penny Pilot issues and a charge of $.08 in non-Penny Pilot issues) is also reasonable, as Customers are currently subject to the same pricing structure (albeit at higher rates) for standard options. The Exchange feels that different rates for Customer electronic transaction fees as compared to other market participants is equitable and not unfairly discriminatory because non-Customers wish to have Customer orders attracted to the Exchange by having lower fees, and is equitable and not unfairly discriminatory to Firms and Broker Dealers because Market Makers have obligations that are not required of Firms and Broker Dealers and because Market Makers have additional costs that are not applicable to Firms and Broker Dealers.
The Exchange proposal to exclude Mini options from the Customer Monthly Posting Credit Tiers or Super Tier and Qualifications for Executions in Penny Pilot Issues and SPY and associated rebates paid to OFPs described in endnote 8 to the current Fee Schedule is reasonable, equitable and not unfairly discriminatory for the following reasons. First, as noted above, the Exchange's cost to process quotes, orders and trades in Minis is the same as for standard options. Given the overall lower expected revenues from Mini options, it is reasonable to exempt Mini option volumes from qualifying for the OFP rebates paid on standard option contracts. It is also equitable, since paying the rebate on Mini option volumes would likely necessitate either reducing the rebates paid to OFPs for all activity, or raising other participant fees. It is not unfairly discriminatory, as it will apply equally to all Customer executions in Mini options, regardless of the market participant submitting the order.
The Exchange proposal to charge NYSE Arca Market Makers manually trading Mini options $.02 per contract is reasonable. Additionally, the Exchange proposal for NYSE Arca Market Makers electronically trading Mini options in Penny Pilot issues to receive a rebate of $.04 or $.06 when they post liquidity in Penny Pilot and non-Penny Pilot classes, respectively, and to be charged $.07 or $.10 when they take liquidity in Penny Pilot and non-Penny Pilot classes, respectively, is also reasonable. The Complex Order rates proposed for NYSE Arca Options Market Makers electronically transacting Mini options are also reasonable. Generally, these fees range from slightly more than, to slightly less than, 10% of what the various NYSE Arca Options Market Maker participants pay today. Charging all types of NYSE Arca Options Market Makers, including Lead Market Makers, the same fees to trade Minis is certainly not unfairly discriminatory, as it applies to all of them equally. The fees are reasonable in light of the fact that the Minis do have a smaller exercise and assignment value, specifically
The Exchange feels that different rates for Market Maker transaction fees as compared to other market participants is equitable and not unfairly discriminatory because non-Customers wish to have Customer orders attracted to the Exchange by having lower fees, and is equitable and not unfairly discriminatory to Firms and Broker Dealers because Market Makers have obligations that are not required of Firms and Broker Dealers and because Market Makers have additional costs that are not applicable to Firms and Broker Dealers. For example, NYSE Arca Options Market Makers are required to have trading permits in
The Exchange proposal to charge Firms and Broker Dealers,, the rates proposed herein for their transactions in Minis and to exclude Mini options from the $75,000 cap per month of fees on Firm and Broker Dealer open outcry executions described in endnote 9 of the current Fee Schedule is reasonable, equitable and not unfairly discriminatory. First, the per contract charges proposed are lower than what Firms and Broker Dealers pay for a standard contract in acknowledgement of the smaller exercise and assignment value. Although some of these proposed rates are more than 10% of the rate paid by a Firm or Broker Dealer for a standard contract, this is warranted by the fact that the Exchange's cost to process quotes, orders and trades in Minis is the same as for standard options. In this regard the proposal is reasonable and it is also equitable, as it allows the Exchange to offer this innovative product to investors without raising fees for other investors who may have no interest in trading Minis. Likewise, excluding Mini option volumes from the monthly fee cap for Firm and Broker Dealer open outcry executions is reasonable and equitable in light of the Exchange's desire to fund the costs associated with Minis with revenues from only those participants who trade them. Offering a fee cap for a product with reduced fees might necessitate raising costs for other participants; therefore, the Exchange believes that the exclusion from the monthly fee cap for Firm and Broker Dealer open outcry executions is both reasonable and equitable. As the per contract Mini pricing for all Firms and Broker Dealers is the same, the proposal is also not unfairly discriminatory.
The Exchange feels that different rates for Firm and Broker Dealer transaction fees as compared to other market participants is equitable and not unfairly discriminatory because non-Customers wish to have Customer orders attracted to the Exchange by having lower fees, and is equitable and not unfairly discriminatory to Firms and Broker Dealers because Market Makers have obligations that are not required of Firms and Broker Dealers and because Market Makers have additional costs that are not applicable to Firms and Broker Dealers. For example, NYSE Arca Options Market Makers are required to have trading permits in order to stream quotes. The number of permits is variable based on the number of options traded, and can cost as much as $16,000 per month to quote all issues on the Exchange as an NYSE Arca Options Market Maker. Conversely, Firms pay a monthly permit fee of $1,000 per month and Broker Dealers, typically access the facilities of the Exchange through either a Firm or Order Flow Provider who may or may not pass along the $1,000 per month permit fee cost. Consequently, when all fees are taken together, the difference charged to NYSE Arca Options Market Makers as compared to Broker Dealers, and Firms is reasonable, equitable and not unfairly discriminatory. The Exchange further notes that there are no limits on the number of NYSE Arca Options Market Makers that are permitted to quote in a given option and that any of the other participant types are free to apply to the Exchange to become a NYSE Arca Options Market Maker to avail themselves of the transaction charges applicable to NYSE Arca Options Market Makers presuming they are willing to accept the quoting obligations applicable to NYSE Arca Options Market Makers, which serve to foster price discovery and transparency.
The Exchange proposal for QCC pricing for Minis is to charge Customers and non-Customers $.10 per contract ($.05 charge per contract side), as compared with $.20 per contract for standard options ($.10 charge per contract side). The Exchange will also offer NYSE Arca Floor Brokers a rebate of $.02 per contract ($.01 rebate per contract side) for all Mini options they execute as a QCC trade, as compared to $.07 per contract rebate for standard options ($.035 rebate per contract side). The Exchange believes that this pricing is reasonable, equitable and not unfairly discriminatory. First, the Exchange has always charged for QCC trades in standard options due to the fact that qualifying QCC trades are executed immediately, upon entry, without exposure or any opportunity for other participants to participate on the trade. This pricing proposal preserves this, and, as such, is reasonable. It is equitable since, as noted, the Exchange's cost to process quotes, orders and trades in Minis is the same as for standard options, so charging a relatively small premium for the opportunity to trade without exposure is warranted, given the Exchange's need to cover the costs of participants trading Minis so as to avoid sharing those costs with other participants who are not trading Minis. The proposal is also not unfairly discriminatory as it applies equally to all Customers and non-Customers. The Floor Broker rebate of $.02 ($.01 rebate per contract side) is reasonable and equitable as it is designed to allow Floor Brokers to compete for QCC volumes that might otherwise execute on an exchange that offers a front end order entry system, like ISE PrecISE Trade application
The Exchange proposal to treat Mini options the same as standard options for purposes of the Routing Surcharge is reasonable, equitable and not unfairly discriminatory for the following reasons. Presently, the Exchange charges a Routing Surcharge of $.11 per contract plus a pass through of the fees associated with the execution of the routed order on the other exchanges. The $.11 is designed to recover the Exchange's costs in routing orders to the other exchanges. Those costs include clearance charges imposed by The OCC and per contract routing fees charged by the Broker Dealers who charge the Exchange for the use of their systems to route orders to other exchanges. The Exchange has spoken with both The OCC and the Broker Dealers, who have informed the Exchange that their charges applicable to Mini options will be the same as for standard option contracts, as their cost to process a contract (i.e., routing or clearing) is the
The Exchange is proposing to exclude Mini option volumes from being eligible for the Limit Of Fees On Options Strategy Executions. Presently the Exchange has a $750 cap on transaction fees for Strategy Executions involving reversals and conversions, box spreads, short stock interest spreads, merger spreads and jelly rolls. The fees for these Strategy Executions are further capped at $25,000 per month per initiating firm. The Exchange will NOT include Mini option transactions as being eligible for any part of these per trade or per month Strategy Execution caps. As noted earlier, the cost to the Exchange to process quotes, orders and trades in Minis is the same as for standard options. Given that the per contract transaction fees for Minis are already substantially lower than the per contract fees for standard options, inclusion of Mini options in these fee caps is not warranted, and is reasonable and equitable. Further, it is not unfairly discriminatory as the exclusion of Mini volumes from the cap on fees for Strategy Executions applies equally to all participants on the Exchange.
The Exchange proposes to treat Mini options the same as standard options for purposes of the Ratio Threshold Fee. As noted, the cost to the Exchange to process quotes, orders and trades in Minis is the same as for standard options and, as such, treating Minis the same as standard option contracts for the purposes of calculating the Ratio Threshold Fee is reasonable and equitable. It is also not unfairly discriminatory, as such treatment will apply to all participants equally.
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 change designed to provide greater specificity and precision within the Fee Schedule with respect to the fees that will be applicable to Minis when they begin trading on the Exchange on March 18, 2013.
The Exchange believes that adopting fees for Minis that are in some cases lower than for standard contracts, but in other cases the same as for standard contracts, strikes the appropriate balance between fees applicable to standard contracts versus fees applicable to Mini's, and will not impose a burden on competition among various market participants on the Exchange, or between the Exchange and other exchanges in the listed options market place, that is not necessary or appropriate in furtherance of the purposes of the Act.
The Exchange feels that different rates for different market participants will not impose a burden on competition because non-Customers wish to have Customer orders attracted to the Exchange by having lower fees, and will not impose a burden on competition to Firms and Broker Dealers because Market Makers have obligations that are not required of Firms and Broker Dealers and because Market Makers have additional costs that are not applicable to Firms and Broker Dealers. Further the Exchange notes that for standard options a greater difference in fees for various participants already exists than that which is being proposed for Minis. For example, Customers already trade for lower Take Liquidity fees than an NYSE Arca Options Market Maker. An NYSE Arca Market Maker who trades with a Customer electronically in a non-Penny name can pay as much as $0.80 per contract. Similarly, Firms and Broker Dealers pay $0.85 per contract when they Take Liquidity in non-Penny Pilot names opposed to Customers, who pay a lower Take Liquidity rate in the same issues of $0.79 per contract in standard options. For Minis, the greatest differential being proposed is in Manual Trades in mini-options, where Customers will trade for free, and Firms and Broker Dealers will pay $0.09 per contract. Firms and Broker Dealers pay $.25 per contract versus $.00 per contract for Customers, in standard options. The differential for mini-options is de minimus as compared to the differential for standard options.
The Exchange notes that the difference in fees for various participants in standard options has not proven to be a burden on competition. Therefore, the fee differential for Minis, being quite a bit smaller, should not prove to be a burden on competition at all. In this regard, as Minis are a new product being introduced into the listed options marketplace, the Exchange is unable at this time to absolutely determine the impact that the fees and rebates proposed herein will have on trading in Minis. That said, however, the Exchange believes that the rates proposed for Minis, on their face, would not impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act.
Finally, the Exchange notes that it operates in a highly competitive market in which market participants can readily favor competing venues. In such an environment, the Exchange must continually review, and consider adjusting, its fees and credits to remain competitive with other exchanges. For the reasons described above, the Exchange believes that the proposed rule change reflects this competitive environment.
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. 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 Elizabeth M. Murphy, 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 January 31, 2013, ICE Clear Credit LLC (“ICC”) filed with the Securities and Exchange Commission (“Commission”) the proposed rule change SR–ICC–2013–01 pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The purpose of the proposed rule change is to update Chapter 26 (Cleared CDS Products) of the ICC Rules and remove Schedule 502 (List of Pre-Approved Products) from the ICC Rules. The proposed rule change also includes a conforming edit within Chapter 5 (Risk Committee) of the ICC Rules. This update will provide direct reference within the ICC Rules to the cleared products list always available on the ICC Web site (“Approved Products List”) and add additional standards for certain ICC cleared products. ICC agrees that rule submissions for updates to ICC's cleared product offering will be required under certain circumstances (e.g., certain financial single names, additional single-name constituents of the Emerging Markets Index, and High Yield single names).
ICC proposes to amend Chapter 26 of its rules to update the definitions of Eligible CDX.NA Untranched Index (Rule 26A–102), Eligible SNAC Reference Entities (Rule 26B–102), Eligible SNAC Reference Obligations (Rule 26B–102), Eligible CDX.EM Untranched Index (Rule 26C–102), Eligible SES Reference Entities (Rule 26D–102), Eligible SES Reference Obligations (Rule 26D–102), Eligible iTraxx Europe Untranched Index (Rule 26F–102), Eligible SDEC Reference Entities (Rule 26G–102) and Eligible SDEC Reference Obligations (Rule 26G–102) to include the requirement that the products must be determined by ICC to be eligible.
ICC proposes to amend Chapter 26 of its rules to update the definitions of List of Eligible CDX.NA Untranched Indexes (Rule 26A–102), List of Eligible SNAC Reference Entities (Rule 26B–102), List of Eligible CDX.EM Untranched Indexes (Rule 26C–102), List of Eligible SES Reference Entities (Rule 26D–102), List of Eligible iTraxx Europe Untranched Indexes (Rule 26F–102) and List of Eligible SDEC Reference Entities (Rule 26G–102) to include the reference that the Approved Products List will be maintained, updated and published on the ICC Web site.
ICC proposes to amend Chapter 26 of its rules to add the definition of Eligible SNAC Sector in Rule 26B–102 of the
ICC proposes to amend Chapter 26 of its rules to add the definition of Eligible SDEC Sector in Rule 26G–102 of the ICC Rules. The listed Eligible SDEC Sectors are: Basic Materials, Consumer Goods, Consumer Services, Energy, Financials, Healthcare, Industrials, Technology, Telecommunications Services, and Utilities. The requirement to list the Eligible SDEC Sector on the List of Eligible SDEC Reference Entities is also added to the definition of List of Eligible SDEC Reference Entities in Rule 26G–102.
ICC proposes to amend Chapter 26 of its rules to include within the definition of List of Eligible SES Reference Entities in Rule 26D–102 the requirement to list the Sector, Government, in the List of Eligible SES Reference Entities.
ICC proposes to remove Schedule 502 from the ICC Rules as Schedule 502 provides information available in the Approved Products List on the ICC Web site. The Approved Products List provides the information currently available in Schedule 502 as well as all additional product information listed in the definitions of List of Eligible CDX.NA Untranched Indexes (Rule 26A–102), List of Eligible SNAC Reference Entities (Rule 26B–102), List of Eligible CDX.EM Untranched Indexes (Rule 26C–102), List of Eligible SES Reference Entities (Rule 26D–102), List of Eligible iTraxx Europe Untranched Indexes (Rule 26F–102) and List of Eligible SDEC Reference Entities (Rule 26G–102).
ICC proposes to make one conforming amendment to Chapter 5 of its rules, specifically Rule 502(a), to change a reference to Schedule 502 of the ICC Rules to reference the Approved Products List on the ICC Web site.
The proposed changes to the ICC Rules will provide direct reference within the ICC Rules to the cleared products list available on the ICC Web site and add additional standards for certain ICC cleared products. The proposed rule changes do not require any changes to the ICC risk management framework including the ICC margin methodology, guaranty fund methodology, pricing parameters and pricing model.
Section 19(b)(2)(C) of the Act
The Commission finds that the proposed rule change is consistent with the requirements of Section 17A of the Act
On the basis of the foregoing, the Commission finds that the proposal is consistent with the requirements of the Act and in particular with the requirements of Section 17A 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 (“Act”),
NASDAQ proposes to amend Chapter XV, entitled “Options Pricing,” at Section 2 governing pricing for NASDAQ members using the NASDAQ Options Market (“NOM”), NASDAQ's facility for executing and routing standardized equity and index options. Specifically, NOM proposes to amend its Routing Fees.
While these amendments are effective upon filing, the Exchange has designated the proposed amendments to be operative on April 1, 2013.
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. 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.
NASDAQ proposes to amend its Routing Fees at Chapter XV, Section 2(3) of the Exchange Rules in order to recoup costs that the Exchange incurs for routing and executing orders in equity options to various away markets.
Today, the Exchange calculates Routing Fees by assessing certain Exchange costs related to routing orders to away markets plus the away market's transaction fee. The Exchange assesses a $0.05 per contract
C2 recently filed a rule change to amend its transaction fees and rebates for simple, non-complex orders, in equity options classes which became operative on February 1, 2013.
The Exchange is proposing to further simplify its Routing Fees by assessing a flat rate of $0.95 per contract on all non-Customer orders routed to any away market. The Exchange would no longer pass any rebate paid by an away market for non-Customer orders. With respect to Customer orders, the Exchange is proposing to continue to assess Customer orders routed to PHLX a fixed fee of $0.05 per contract (“Fixed Fee”) in addition to the actual transaction fee assessed by the away market. This fee is not changing. With respect to Customer orders that are routed to BX Options, the Exchange will not assess a Routing Fee and will not pass the rebate. Today, BX Options pays a Customer Rebate to Remove Liquidity as follows: Customers are paid $0.12 per contract in IWM, SPY and QQQ, $0.32 per contract in All Other Penny Pilot Options and $0.70 per contract in Non-Penny Pilot Options.
As with all fees, the Exchange may adjust these Routing Fees in response to competitive conditions by filing a new proposed rule change.
NASDAQ believes that its proposal to amend its pricing is consistent with Section 6(b) of the Act
The Exchange believes that its proposal to amend its non-Customer Routing Fees from a fixed fee plus actual transaction charges to a flat rate is reasonable because the flat rate makes it easier for market participants to anticipate the Routing Fees which they would be assessed at any given time. The Exchange believes that assessing all non-Customer orders the same flat rate will provide market participants with certainty with respect to Routing Fees. While, each destination market's transaction charge varies and there is a
The Exchange believes that its proposal to amend the non-Customer Routing Fees from a fixed fee plus actual transaction charges to a flat rate is equitable and not unfairly discriminatory because the Exchange would uniformly assess the same Routing Fees to all non-Customer market participants. Under its flat fee structure, taking all costs to the Exchange into account, the Exchange may operate at a slight gain or a slight loss for non-Customer orders routed to and executed at away markets. The proposed Routing Fee for non-Customer orders is an approximation of the maximum fees the Exchange will be charged for such executions, including costs, at away markets. As a general matter, the Exchange believes that the proposed fees will allow it to recoup and cover its costs of providing routing services for non-Customer orders. The Exchange believes that the fixed rate non-Customer Routing Fee is equitable and not unfairly discriminatory because market participants have the ability to directly route orders to an away market and avoid the Routing Fee. Participants may choose to mark the order as ineligible for routing to avoid incurring these fees.
The Exchange believes that its proposal to not pass a rebate that is offered by an away market for non-Customer orders is reasonable because to the extent that another market is paying a rebate, the Exchange will assess a $0.95 per contract fee as its total cost in each instance. The Routing Fee is transparent and simple. If a market participant desires the rebate, the market participant has the option to direct the order to that away market. Other options exchanges today do not pass the rebate.
The Exchange believes that amending the Customer Routing Fee to BX Options from $0.05 per contract in addition to the actual transaction fee to $0.00 is reasonable, because, unlike PHLX,
Further, the Exchange believes that it is reasonable to also not assess a Customer Routing Fee when routing to all other options exchanges, except PHLX and BX Options, if the away market pays a rebate. The Exchange will continue to assess a Fixed Fee of $0.11 per contract plus the actual transaction charge assessed by the away market when routing to all other options exchanges, except PHLX and BX Options, but instead of paying the rebate, as is the case today, the Exchange will not assess a Customer Routing Fee to that away market because the Exchange will collect the rebate to offset the fee. The Exchange believes that market participants will have more certainty as to the Customer Routing Fee that will be assessed by the Exchange. The Exchange believes that the proposed pricing for the Customer Routing Fee to all other away markets, except PHLX and BX Options, is equitable and not unfairly discriminatory because while the Exchange may operate at a slight gain or a slight loss when routing Customer orders to the away market, depending on the rebate paid by the away market, the proposal would apply uniformly to all market participants when routing to an away market that pays a rebate.
The Exchange believes that it is reasonable, equitable and not unfairly discriminatory to continue to assess Customer orders that are routed to PHLX a Fixed Fee of $0.05 per contract and orders that are routed to other away markets, other than PHLX and BX Options, a Fixed Fee of $0.11 per contract because the cost, in terms of actual cash outlays, to the Exchange to route to PHLX (and BX Options)
Finally, the Exchange believes that it is reasonable, equitable and not unfairly discriminatory to assess different fees for Customers orders as compared to
NASDAQ Exchange does not believe that the proposed rule change will impose any burden on competition not necessary or appropriate in furtherance of the purposes of the Act. The Exchange does not believe that the proposal creates intra-market competition because the Exchange is applying the same Routing Fees and credits to all market participants in the same manner dependent on the routing venue, with the exception of Customers. The Exchange has proposed separate Customer Routing Fees. Customers will continue to receive the lowest fees or no fees when routing orders, as is the case today. Other options exchanges also assess lower Routing Fees for customer orders as compared to non-customer orders.
The Exchange's proposal would allow the Exchange to recoup its costs when routing orders to away markets when such orders are designated as available for routing by the market participant. The Exchange is passing along savings realized by leveraging NASDAQ OMX's infrastructure and scale to market participants when those orders are routed to PHLX and is providing those saving to all market participants. Participants may choose to mark the order as ineligible for routing to avoid incurring these fees.
The Exchange operates in a highly competitive market, comprised of eleven exchanges, in which market participants can easily and readily direct order flow to competing venues if they deem fee levels at a particular venue to be excessive. Accordingly, the fees that are assessed by the Exchange must remain competitive with fees charged by other venues and therefore must continue to be reasonable and equitably allocated to those Participants that opt to direct orders to the Exchange rather than competing venues.
No written comments were either solicited or received.
The foregoing rule change 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 Elizabeth M. Murphy, 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.
The Social Security Administration (SSA) publishes a list of information collection packages requiring clearance by the Office of Management and Budget (OMB) in compliance with Public Law 104–13, the Paperwork Reduction Act of 1995, effective October 1, 1995. This notice includes revisions and an extension of OMB-approved information collections.
SSA is soliciting comments on the accuracy of the agency's burden estimate; the need for the information; its practical utility; ways to enhance its quality, utility, and clarity; and ways to minimize burden on respondents, including the use of automated collection techniques or other forms of information technology. Mail, email, or fax your comments and recommendations on the information collection(s) to the OMB Desk Officer
Office of Management and Budget, Attn: Desk Officer for SSA, Fax: 202–395–6974, Email address:
Social Security Administration, DCRDP, Attn: Reports Clearance Director, 107 Altmeyer Building, 6401 Security Blvd., Baltimore, MD 21235, Fax: 410–966–2830, Email address:
I. The information collections below are pending at SSA. SSA will submit them to OMB within 60 days from the date of this notice. To be sure we consider your comments, we must receive them no later than June 3, 2013. Individuals can obtain copies of the collection instruments by writing to the above email address.
1. Request to be Selected as a Payee—20 CFR 404.2010–404.2055, 416.601–416.665—0960–0014. An individual applying to be a representative payee for a Social Security beneficiary or Supplemental Security Income (SSI) recipient must first complete Form SSA–11–BK. SSA obtains information from applicant payees regarding their relationship to the beneficiary, personal qualifications, concern for the beneficiary's well-being, and intended use of benefits if appointed as payee. The respondents are individuals, private sector businesses and institutions, and State and local government institutions and agencies applying to become representative payees.
2. Representative Payee Evaluation Report—20 CFR 404.2065 & 416.665—0960–0069. Sections 205(j) and 1631(a)(2) of the Social Security Act (Act) state SSA may appoint a representative payee to receive title II benefits or title XVI payments on behalf of individuals unable to manage or direct the management of those funds themselves. SSA requires appointed representative payees to report once each year on how they used or conserved those funds. When a representative payee fails to adequately report to SSA as required, SSA conducts a face-to-face interview with the payee and completes Form SSA–624, Representative Payee Evaluation Report, to determine the continued suitability of the representative payee to serve as a payee. The respondents are individuals or organizations serving as representative payees for individuals receiving title II benefits or title XVI payments who fail to comply with SSA's statutory annual reporting requirement.
3. Child Care Dropout Questionnaire—20 CFR 404.211(e)(4)—0960–0474. If individuals applying for title II disability benefits cared for their own or their spouse's children under age 3 and had no steady earnings during that time period, they may exclude that period of care from the disability computation period. We call this the child-care dropout exclusion. SSA uses the information from Form SSA–4162 to determine if an individual qualifies for
4. Beneficiary Recontact Form—20 CFR 404.703, 404.705—0960–0502. SSA investigates recipients of disability payments to determine their continuing eligibility for payments. Research indicates recipients may fail to report circumstances that affect their eligibility. Two such cases are: (1) When parents receiving disability benefits for their child marry and (2) the removal of an entitled child from parents' care. SSA uses Form SSA–1588–OCR–SM to ask mothers or fathers about their marital status and children currently in their care to detect overpayments and to avoid continuing payment to those no longer entitled. Respondents are recipients of mothers' or fathers' Social Security benefits.
5. Program Discrimination Complaint—0960–0585. SSA collects information on Form SSA–437 to investigate and formally resolve complaints of discrimination based on disability, race, color, national origin (including limited English language proficiency), sex, sexual orientation, age, religion, or retaliation for having participated in a proceeding under this administrative complaint process in connection with an SSA program or activity. Individuals who believe SSA discriminated against them on any of the above bases may file a written complaint of discrimination. SSA uses the information to (1) Identify the complaint; (2) identify the alleged discriminatory act; (3) establish the date of such alleged action; (4) establish the identity of any individual(s) with information about the alleged discrimination; and (5) establish other relevant information that would assist in the investigation and resolution of the complaint. Respondents are individuals who believe SSA or SSA employees, contractors or agents in programs or activities conducted by SSA discriminated against them.
6. Waiver of Supplemental Security Income Payment Continuation—20 CFR 416.1400–416.1422—0960–0783. SSI recipients who wish to discontinue their SSI payments while awaiting a determination on their appeal complete Form SSA–263–U2, Waiver of Supplemental Security Income Payment Continuation, to inform SSA of this decision. SSA collects the information to determine whether the SSI recipient meets the provisions of the Act regarding waiver of payment continuation and as proof respondents no longer want their payments to continue. Respondents are recipients of SSI payments who wish to discontinue receiving payment while awaiting a determination on their appeal.
II. SSA submitted the information collections below to OMB for clearance. Your comments regarding the information collections would be most useful if OMB and SSA receive them 30 days from the date of this publication. To be sure we consider your comments, we must receive them no later than May 2, 2013. Individuals can obtain copies of the OMB clearance packages by writing to
1. Supplemental Statement Regarding Farming Activities of Person Living Outside the U.S.A.—0960–0103. When a beneficiary or claimant reports farm work from outside the United States, SSA documents this work on Form SSA–7163A–F4. Specifically, SSA uses the form to determine if we should apply foreign work deductions to the recipient's title II benefits. We collect the information either annually or every other year, depending on the respondent's country of residence.
2. Internet Direct Deposit Application—31 CFR 210—0960–0634. SSA requires all applicants and recipients of Social Security Old Age, Survivors, and Disability Insurance (OASDI) benefits, or SSI payments to receive these benefits and payments via direct deposit at a financial institution. SSA receives Direct Deposit/Electronic Funds Transfer (DD/EFT) enrollment information from OASDI beneficiaries and SSI recipients to facilitate DD/EFT of their funds with their chosen financial institution. We also use this information when an enrolled individual wishes to change their DD/EFT information. For the convenience of the respondents, we collect this information through several modalities, including an Internet application, in-office or telephone interviews, and our automated telephone system. In addition to using the direct deposit information to enable DD/EFT of funds to the recipient's chosen financial institution, we also use the information through our Direct Deposit Fraud Indicator to ensure the correct recipient receives the funds. Respondents are OASDI beneficiaries and SSI recipients requesting that we enroll them in the Direct Deposit program or change their direct deposit banking information.
3. International Direct Deposit—31 CFR 210—0960–0686. SSA's International Direct Deposit (IDD) Program allows beneficiaries living abroad to receive their payments via direct deposit to an account at a financial institution outside the United States. SSA uses Form SSA–1199–(Country) to enroll title II beneficiaries residing abroad in IDD, and to obtain the direct deposit information for foreign accounts. Routing account number information varies slightly for each foreign country, so we use a variation of the Treasury Department's Form SF–1199A for each country. The respondents are Social Security beneficiaries residing abroad who want SSA to deposit their benefits payments directly to a foreign financial institution.
Sections 202(a), 203, 204, and 207 of the Foreign Missions Act (codified at 22 U.S.C. 4301
Additionally, I hereby determine the provision of such application services by private entities for foreign missions in the United States to be subject to such terms and conditions as may be established by the Department's Office of Foreign Missions and that any state or local laws to the contrary are hereby preempted.
In accordance with § 211(a) of the Act, it shall be unlawful for any person to make available any benefits to a foreign mission that are contrary to the Act. The United States, acting on its own behalf or on behalf of a foreign mission, has standing to bring or intervene in an action to obtain compliance with this chapter, including any action for injunctive or other equitable relief.
Federal Motor Carrier Safety Administration (FMCSA), DOT.
Notice of final disposition.
FMCSA announces its decision to exempt 19 individuals from its rule prohibiting persons with insulin-treated diabetes mellitus (ITDM) from operating commercial motor vehicles (CMVs) in interstate commerce. The exemptions will enable these individuals to operate CMVs in interstate commerce.
The exemptions are effective April 2, 2013. The exemptions expire on April 2, 2015.
Elaine M. Papp, Chief, Medical Programs Division, (202) 366–4001,
You may see all the comments online through the Federal Document Management System (FDMS) at:
On February 4, 2013, FMCSA published a notice of receipt of Federal diabetes exemption applications from 19 individuals and requested comments from the public (78 FR 7852). The public comment period closed on March 6, 2013, and no comments were received.
FMCSA has evaluated the eligibility of the 19 applicants and determined that granting the exemptions to these individuals would achieve a level of safety equivalent to or greater than the level that would be achieved by complying with the current regulation 49 CFR 391.41(b)(3).
The Agency established the current requirement for diabetes in 1970 because several risk studies indicated that drivers with diabetes had a higher rate of crash involvement than the general population. The diabetes rule provides that “A person is physically qualified to drive a commercial motor vehicle if that person has no established medical history or clinical diagnosis of diabetes mellitus currently requiring insulin for control” (49 CFR 391.41(b)(3)).
FMCSA established its diabetes exemption program, based on the Agency's July 2000 study entitled “A Report to Congress on the Feasibility of a Program to Qualify Individuals with Insulin-Treated Diabetes Mellitus to Operate in Interstate Commerce as Directed by the Transportation Act for the 21st Century.” The report concluded that a safe and practicable protocol to allow some drivers with ITDM to operate CMVs is feasible. The September 3, 2003 (68 FR 52441),
These 19 applicants have had ITDM over a range of 4 to 44 years. These applicants report no severe hypoglycemic reactions resulting in loss of consciousness or seizure, requiring the assistance of another person, or resulting in impaired cognitive function that occurred without warning symptoms, in the past 12 months and no recurrent (2 or more) severe hypoglycemic episodes in the past 5 years. In each case, an endocrinologist verified that the driver has demonstrated a willingness to properly monitor and manage his/her diabetes mellitus, received education related to diabetes management, and is on a stable insulin regimen. These drivers report no other disqualifying conditions, including diabetes-related complications. Each meets the vision requirement at 49 CFR 391.41(b)(10).
The qualifications and medical condition of each applicant were stated and discussed in detail in the February 4, 2013,
FMCSA received no comments in this proceeding.
Under 49 U.S.C. 31136(e) and 31315, FMCSA may grant an exemption from the diabetes requirement in 49 CFR 391.41(b)(3) if the exemption is likely to achieve an equivalent or greater level of safety than would be achieved without the exemption. The exemption allows the applicants to operate CMVs in interstate commerce.
To evaluate the effect of these exemptions on safety, FMCSA considered medical reports about the applicants' ITDM and vision, and reviewed the treating endocrinologists' medical opinion related to the ability of the driver to safely operate a CMV while using insulin.
Consequently, FMCSA finds that in each case exempting these applicants from the diabetes requirement in 49 CFR 391.41(b)(3) is likely to achieve a level of safety equal to that existing without the exemption.
The terms and conditions of the exemption will be provided to the applicants in the exemption document and they include the following: (1) That each individual submit a quarterly monitoring checklist completed by the treating endocrinologist as well as an annual checklist with a comprehensive medical evaluation; (2) that each individual reports within 2 business days of occurrence, all episodes of severe hypoglycemia, significant complications, or inability to manage diabetes; also, any involvement in an accident or any other adverse event in a CMV or personal vehicle, whether or not it is related to an episode of hypoglycemia; (3) that each individual provide a copy of the ophthalmologist's or optometrist's report to the medical examiner at the time of the annual medical examination; and (4) that each individual provide a copy of the annual medical certification to the employer for retention in the driver's qualification file, or keep a copy in his/her driver's qualification file if he/she is self-employed. The driver must also have a copy of the certification when driving, for presentation to a duly authorized Federal, State, or local enforcement official.
Based upon its evaluation of the 19 exemption applications, FMCSA exempts Nicholas C. Bolton (NY), Isaias Gomez (IN), Brandon E. Hamlett (NV), Douglas F. Keller (MI), Mark R. Loesel (WI), Steven A. Marion (MA), Jason E. McAnnally (AL), Robert W. Moen (IA), Craig S. Moran (CA), Wayne A. Ondrusek (PA), Lenicia R. Riley (TX), Mark L. Sandager (MN), Samuel L. Sergio (MA), Jason L. Shaw (OK), Paul M. Shierk (OR), Kailey J. Skroko (IN), Samantha K. Tsuchiya (CA), David W. West (MO), and Eugene Zollner, II (OH) from the ITDM requirement in 49 CFR 391.41(b)(3), subject to the conditions listed under “Conditions and Requirements” above.
In accordance with 49 U.S.C. 31136(e) and 31315 each exemption will be valid for two years unless revoked earlier by FMCSA. The exemption will be revoked if the following occurs: (1) The person fails to comply with the terms and conditions of the 1/exemption; (2) the exemption has resulted in a lower level of safety than was maintained before it was granted; or (3) continuation of the exemption would not be consistent with the goals and objectives of 49 U.S.C. 31136(e) and 31315. If the exemption is still effective at the end of the 2-year period, the person may apply to FMCSA for a renewal under procedures in effect at that time.
Notification of the Opening of the National Baseball Hall of Fame Commemorative Coin Program Design Competition on April 11, 2013.
The United States Mint announces the opening of a national coin design competition that will culminate in the Secretary of the Treasury's selection of the image for the obverse (heads side) of the 2014 National Baseball Hall of Fame Commemorative Coins. The competition, which is open to all United States citizens and permanent residents ages 14 and over, begins on April 11, 2013, at 12 noon Eastern Daylight Time (EDT). The submission period will end at 12 noon EDT on April 26, 2013, if 10,000 or more entries have been received by that time. If fewer than 10,000 entries have been received by 12 noon EDT on April 26, 2013, then the submission period will remain open until 10,000 entries have been received, but will end no later than May 11, 2013, at 12 noon EDT. The winner of the design competition will be awarded $5,000, and the winner's initials will appear on the minted coins.
The National Baseball Hall of Fame Commemorative Coin Act (Act), Public Law 112–152 (Aug. 3, 2012), requires the Secretary of the Treasury to mint and issue three 2014 commemorative coins to recognize and celebrate the National Baseball Hall of Fame: up to 50,000 $5 gold coins, up to 400,000 $1 silver coins, and up to 750,000 half-dollar clad coins. The Act requires a competition, which Challenge.gov is hosting, to select a common obverse design emblematic of the game of baseball. Additionally, the Act expresses Congress's sense that the $5 gold and $1 silver coins have a shape such that the obverse is concave and the reverse is convex.
Entries will be evaluated during a selection process consisting of an initial screening for minimum requirements and four evaluation rounds. The Citizens Coinage Advisory Committee, the U.S. Commission of Fine Arts, and the National Baseball Hall of Fame will review the finalist designs, after which the United States Mint will put forward a recommended design to the Secretary of the Treasury for selection.
Official rules, guidelines, and entry instructions for the United States Mint National Baseball Hall of Fame Commemorative Coin Program Design Competition can be found at
The United States Mint's Competition Administrator is Leslie Schwager, Program Specialist. She can be reached at
National Baseball Hall of Fame Commemorative Coin Act, Public Law 112–152.
Notification of the Opening of the United States Mint Kids' Baseball Coin Design Challenge on April 11, 2013.
The United States Mint announces the opening of a national kids' baseball coin design challenge on April 11, 2013, that seeks design entries from contestants age 13 years or younger on the theme, “What's Great about Baseball.” As part of the United States Mint's education initiative, this challenge is designed to provide learning materials for children, teachers, and parents on the United States Mint and its coins and medals, to build awareness of the bureau's operations and programs, and to complement the United States Mint National Baseball Hall of Fame Commemorative Coin Program Design Competition, which is a national competition for individuals 14 or older to create the design for the common obverse (front) of coins to be issued under the 2014 National Baseball Hall of Fame Commemorative Coin Program.
In creating their design entries, contestants are allowed to use any medium—acrylics, watercolor, pencil, charcoal, marker, spray paint, crayon,
On behalf of each contestant, a parent or guardian must submit a completed application on Challenge.gov, including uploading the design entry and agreeing to the Parent/Legal Guardian Consent Form and Rights Transfer Agreement. Entries must be submitted no later than May 23, 2013, at 11:59 p.m. Eastern Daylight Time. Official rules, guidelines, and entry instructions for the United States Mint Kids' Baseball Coin Design Challenge can be found at
The United States Mint's Kids' Challenge Administrator is Mr. K. Jenkins, Education Coordinator. He can be reached at
America COMPETES Reauthorization Act of 2010, Public Law 111–358.
Environmental Protection Agency (EPA).
Proposed rule.
The EPA is proposing to amend the Greenhouse Gas Reporting Rule and to clarify or change specific provisions. Particularly, the EPA is proposing to amend a table in the General Provisions, to reflect revised global warming potentials of some greenhouse gases that have been published by the Intergovernmental Panel on Climate Change and to add global warming potentials for certain fluorinated greenhouse gases not currently listed in the table. This action also proposes confidentiality determinations for the reporting of new or substantially revised (i.e., requiring additional or different data to be reported) data elements contained in these proposed amendments to the Greenhouse Gas Reporting Rule.
You may submit your comments, identified by Docket ID No. EPA–HQ–OAR–2012–0934 by any of the following methods:
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Should you choose to submit information that you claim to be CBI, clearly mark the part or all of the information that you claim to be CBI. For information that you claim to be CBI in a disk or CD ROM that you mail to the EPA, mark the outside of the disk or CD ROM as CBI and then identify electronically within the disk or CD ROM the specific information that is claimed as CBI. In addition to one complete version of the comment that includes information claimed as CBI, a copy of the comment that does not contain the information claimed as CBI must be submitted for inclusion in the public docket. Information marked as CBI will not be disclosed except in accordance with procedures set forth in 40 CFR part 2. Send or deliver information identified as CBI to only the mail or hand/courier delivery address listed above, attention: Docket ID No. EPA–HQ–OAR–2012–0934. If you have any questions about CBI or the procedures for claiming CBI, please consult the person identified in the
Do not submit information that you consider to be CBI or otherwise protected through
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 suppliers and direct emitters of GHGs. If you have questions regarding the applicability of this action to a particular facility, consult the person listed in the preceding
The first section of this preamble contains background information regarding the origin of the proposed amendments. This section also discusses EPA's legal authority under the Clean Air Act (CAA) to promulgate (including subsequent amendments to) 40 CFR part 98 of the Greenhouse Gas Reporting Rule (hereinafter referred to as “Part 98”). Section II of this preamble is organized by Part 98 subpart and contains detailed information on the proposed revisions to the GHG Reporting Rule and the rationale for the proposed amendments. Section III of this preamble discusses the effective date of the proposed revisions for new and existing reporters and the options EPA is considering for revising and republishing emissions estimates for the reporting years 2010, 2011, and 2012. Section IV of this preamble discusses the proposed confidentiality determinations for new or substantially revised (i.e., requiring additional or different data to be reported) data reporting elements. Section V of this preamble discusses the impacts of the proposed amendments, primarily for current and new reporters of gases proposed to have revised or new global warming potentials (GWPs) listed in Part 98. Finally, Section VI of this preamble describes the statutory and executive order requirements applicable to this action.
Part 98 was published in the
Changes proposed in this notice for certain source categories include, among other things, clarifying the data reporting requirements for certain facilities; correcting ambiguities or minor inconsistencies in greenhouse gas monitoring, calculation, and reporting requirements; amending monitoring and quality assurance methods to provide flexibility for certain facilities; and making other corrections identified as a result of working with the affected sources during rule implementation and outreach. In conjunction with this action, we are proposing confidentiality determinations for the new and substantially revised (i.e., requiring additional or different data to be reported) data elements under this proposed amendment.
In the first two years of implementation of Part 98, the EPA responded to thousands of questions from reporters and engaged in a stakeholder and public testing process to help improve development of EPA's electronic reporting system. Through these extensive outreach efforts, the EPA has improved our understanding of the technical challenges and burden associated with implementation of Part 98 provisions. The proposed changes would improve the Greenhouse Gas Reporting Program (GHGRP) by clarifying compliance obligations and reducing confusion for reporters, improving the consistency of the data collected, and ensuring that data collected through the GHGRP is representative of industry and comparable to other inventories.
The EPA is also proposing amendments to Table A–1 to Subpart A, General Provisions, of Part 98 to revise the values for the GWP of some GHGs and adding some GHGs (with associated GWP values) that are not currently included in the table.
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, October 30, 2009), 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 (74 FR 16448, April 10, 2009) and final Part 98 (74 FR 56260) for further information.
In addition, the EPA is proposing confidentiality determinations for certain new or substantially revised data elements required under the proposed GHG Reporting Rule under its authorities provided in sections 114, 301 and 307 of the CAA. As mentioned above, CAA section 114 provides the EPA authority to obtain the information in Part 98. Section 114(c) requires that EPA make publicly available information obtained under section 114 except for information (excluding emission data) that qualify for confidential treatment. The Administrator has determined that this action (proposed amendments and confidentiality determinations) is subject to the provisions of section 307(d) of the CAA.
The EPA is proposing to revise Part 98 to introduce technical corrections, clarifying revisions, and other amendments to Part 98 to improve the
• Revising GWPs for GHGs defined in Table A–1 of subpart A of Part 98 for consistency with the Inventory, and adding GWPs for fluorinated greenhouse gases (F–GHGs) used by Part 98 facilities that are not currently included in Table A–1 to reflect industry practices.
• Changes to clarify the applicability of calculation methods to certain sources at a facility.
• Corrections to terms and definitions in certain equations to provide clarity or better reflect actual operating conditions.
• Changes to correct typographical errors or cross references within and between subparts.
• Amending monitoring and quality assurance methods to provide flexibility for certain facilities.
• Corrections to data reporting requirements so that they more closely conform to the information used to perform emission calculations.
• Adding readily available data reporting requirements that would allow the EPA to verify the data submitted and assess the reasonableness of the data reported.
• Other amendments or corrections related to certain issues identified during rule implementation and outreach.
Sections II.A through II.AA of this preamble describe the more substantive corrections, clarifying, and other amendments we are proposing for each subpart. The proposed amendments discussed in this preamble include: Changes that affect the applicability of a subpart, changes that affect the applicability of a calculation method to a specific source at a facility, changes or corrections to calculation methods that substantially revise the calculation method or output of the equation, revisions to data reporting requirements that would substantively clarify the reported data element or introduce a new data element, clarifications of general monitoring and quality assurance requirements, and new terms and definitions. To reduce the length of this preamble, we have summarized less substantive corrections for each subpart in the memorandum, “Table of 2013 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–2012–0934). The proposed changes discussed in the Table of Revisions are straightforward clarifications of requirements to better reflect the EPA's intent, simple corrections to calculation terms or cross-references that do not affect the output of calculations, harmonizing changes within a subpart (such as changes to terminology), simple editorial and minor error corrections, or removal of redundant text. The Table of Revisions describes each proposed change within a subpart, including those itemized in this preamble, and provides the current rule text and the proposed correction. Where the proposed change is listed only in the Table of Revisions, the rationale for the proposed change is also listed there. You may comment on those proposed technical corrections, clarifying and other amendments identified in the Table of Revisions as well as any other part of this proposal.
In today's action, we are proposing to revise Table A–1 of subpart A of Part 98 (hereafter referred to as “Table A–1”) by updating the GWP values of certain compounds and adding certain F–GHGs and their GWPs not previously included in Table A–1. These proposed changes relate to facilities and suppliers under Part 98 reporting the following greenhouse gases: methane (CH
The changes are being proposed for two reasons. First, we propose to revise GWPs for GHGs currently in Table A–1 to ensure continued consistency with the Inventory as the Inventory begins to use GWPs from the IPCC Fourth Assessment Report. Second, we propose to add GWPs for F–GHGs that are not currently included in Table A–1 but that are emitted in significant quantities or for which newly available data or literature supports the establishment of a GWP in Table A–1. The background and general rationale for these proposed amendments are discussed in Section II.A.1.a of this preamble. The proposed changes to the GWPs currently in Table A–1 and the GWP determinations for new proposed compounds in Table A–1 are discussed in Sections II.A.1.b and II.A.1.c of this preamble. The schedule for the proposed amendments is discussed in Section III.A of this preamble.
The EPA is also considering options for revising and republishing emissions estimates for the reporting years 2010, 2011, and 2012 using the revised GWPs in Table A–1. The EPA is seeking comment on these options, which are discussed in Section III.B of this preamble. Because reporters affected by the GHG reporting rule use the GWPs in Table A–1 to calculate annual GHG emissions (or GHGs supplied, as applicable), and, for source categories with a carbon dioxide equivalent (CO
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 existing U.S. government programs related to climate policy and research, including the Inventory submitted to the UNFCCC. The GHGRP provides data to develop and inform inventories and other U.S. climate programs by advancing the understanding of emission processes and monitoring methodologies for particular source categories or sectors. Specifically, the GHGRP complements the Inventory and other U.S. programs by providing data from individual facilities and suppliers above certain thresholds.
Collected facility, unit, and process-level GHG data from the GHGRP will provide or confirm the national statistics and emission estimates presented in the Inventory, which are calculated using aggregated national data. The EPA has received encouragement from stakeholders to use GHG data from the GHGRP to complement the Inventory, such as from EPA's stakeholder workshop for natural gas systems.
During the development of the GHG Reporting Rule, the EPA generally proposed and finalized estimation methodologies and reporting metrics that were based on recent scientific data and that were consistent with the international reporting standards under the UNFCCC. This approach allows the data collected under the GHGRP to be easily compared to the data in the Inventory and to data from other national and international programs. Specifically, the EPA generally promulgated GWP values published in the IPCC Second Assessment Report (hereinafter referred to as “SAR GWP values”) to convert mass emissions (or supply) of each GHG into a common unit of measure, CO
The IPCC AR4 was published in 2007 and is among the most current and comprehensive peer-reviewed assessments of climate change. The AR4 provides revised GWPs of several GHGs relative to the values provided in previous assessment reports, following advances in scientific knowledge on the radiative efficiencies and atmospheric lifetimes of these GHGs and of CO
On March 15, 2012, the UNFCCC published a decision, reached by UNFCCC member parties, to require countries submitting an annual report in 2015 and beyond to use GWP values from the IPCC AR4 (hereinafter referred to as the “AR4 GWP values”).
We recognize that some other EPA programs use the GWP values in Table A–1 to determine applicability of the program to direct emitters or suppliers above certain thresholds. For example, EPA's Greenhouse Gas Tailoring Rule (75 FR 31514; June 3, 2010) cross-references Table A–1 for calculating GHG emissions under the PSD and title V permitting programs. See, e.g., 40 CFR 52.21(b)(49)(ii)(a). Because the permitting applicability is based partly on CO
Use of the AR4 GWPs is also in keeping with other EPA programs. For example, the Agency decided to use these values in rules published jointly with the Department of Transportation, National Highway Traffic Safety Administration, the “Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards” (75 FR 25324, May 7, 2010).
Section II.A.1.b of this preamble lists the changes we are proposing to incorporate as a result of the updated AR4 GWPs.
During implementation of Part 98, the EPA has collected data on the range and volume of F–GHGs emitted and supplied in the U.S. market by various F–GHG producers, importers, exporters, and manufacturers using F–GHGs in their production processes (e.g., electronics manufacturing, magnesium production).
The EPA is proposing to amend Table A–1 to subpart A of Part 98 to add 26 F–GHGs for which we have identified a GWP based on an assessment of recent scientific literature. Table A–1 to subpart A is a compendium of GWP values of select GHGs that are required to be reported under one or more subparts of Part 98, and where the EPA has identified the GWP in the IPCC AR4 report or other sources. As acknowledged in the preamble to the final Part 98 (74 FR 56260, October 30, 2009), Table A–1 is not a complete listing of current or potential compounds, but reflects only those GWPs for listed materials that had been synthesized, their atmospheric properties investigated, and the results published and reviewed prior to promulgation of the final rule. Currently, some Part 98 source categories provide calculation methodologies and reporting requirements for F–GHGs for which GWP values were not available in the IPCC SAR, TAR, AR4, or other scientific assessments at promulgation. As noted in the preamble to the final Part 98 (74 FR 56260), it is the EPA's intent to periodically update Table A–1 as GWPs are evaluated or re-evaluated by the scientific community.
The proposed amendments to Table A–1 would revise the GWPs for 23 GHGs to reflect the 100-year GWP values adopted by the UNFCCC and published in the IPCC AR4. Table 2 of this preamble lists the GHGs whose GWP values we are proposing to revise, along with the GWP values currently listed in Table A–1 and the proposed revised GWP values from the IPCC AR4.
We are proposing to adopt only GWP values based on a 100-year time horizon, although other time horizons are available in the IPCC AR4 (e.g., 20-year or 500-year GWPs). As acknowledged in the April 10, 2009 proposed GHG reporting rule (74 FR 16448), the parties to the UNFCCC agreed to use GWPs based upon a 100-year time horizon. Therefore, 100-year GWPs are used as the metric in the Inventory. Because the proposed changes are intended to make the GHGRP reporting methods more consistent with the Inventory, we are not considering the use of GWPs based on other time horizons.
As noted above, Table A–1 already includes AR4 GWPs for chemicals for which GWPs were not presented in the SAR (e.g., fluorinated ethers); the EPA is therefore proposing to retain the current GWPs for these chemicals (and for sevoflurane, which has not been included in any IPCC assessment but already is included in Table A–1). A complete listing of the current GWPs in Table A–1 to subpart A and the AR4 GWP values may be found in the memorandum, “Assessment of Emissions and Cost Impacts of 2013 Revisions to the Greenhouse Gas Reporting Rule” (hereafter referred to as “Impacts Analysis”) (see Docket ID No. EPA–HQ–OAR–2012–0934).
For one set of chemicals, fluorinated ethers and alcohols, the EPA is seeking comment on adopting GWPs from an international scientific assessment published more recently than AR4, the WMO (World Meteorological Organization)
The current Table A–1 includes AR4 GWPs for several fluorinated ethers and alcohols, including several hydrofluoroethers (HFEs), which could be updated through the WMO Scientific Assessments. These fluorinated ethers and alcohols are not required to be included in national GHG inventories reported under the UNFCCC. In general, the compounds required to be reported under the GHGRP go beyond the minimum reporting requirements of the UNFCCC (e.g., NF
The 2010 WMO Scientific Assessment includes significant updates to the GWPs for several HFEs in commerce, reflecting improved understanding of the atmospheric lifetimes and radiative efficiencies of these chemicals. In a number of cases, estimated 100-year GWPs for HFEs have approximately doubled; in one, (for HFE–338mmz1), the estimated 100-year GWP rose by over a factor of six, from 380 to 2570. (The changes to the estimated GWPs of other fluorinated GHGs, such as the HFCs and PFCs, were far smaller.) To ensure consistency between the GHGRP and UNFCCC reporting, the EPA is not proposing to adopt GWPs from the 2010 WMO Scientific Assessment for chemicals other than fluorinated ethers and alcohols. However, the EPA requests comment on adopting GWPs from the 2010 WMO Scientific Assessment for a subset of chemicals, fluorinated ethers and alcohols, that are not reported under the Inventory.
We are not proposing to include GWPs for ozone-depleting substances controlled by the Montreal Protocol
We are proposing to include 26 new F–GHGs in Table A–1 of subpart A for which the EPA has identified scientific assessments of the GWPs. These F–GHGs were not included in AR4 for a variety of reasons.
In some cases, the proposed additions to Table A–1 would help to ensure that all Part 98 facilities emitting or supplying the identified F–GHGs would use consistent GWPs to calculate emissions of CO
The proposed F–GHGs include F–GHGs for which the EPA has previously reviewed scientific assessments from requests for provisional GWPs, F–GHGs submitted by a fluorinated GHG producer with suggested GWPs and supporting data and analysis on August 21, 2012, and F–GHGs for which evaluations of the GWPs were performed by the EPA (e.g., as part of evaluations associated with EPA's Significant New Alternative Policy (SNAP) program), or published in peer-reviewed scientific journals.
• Seven compounds for which the EPA has approved provisional GWPs for purposes of the calculations in 40 CFR 98.123(c)(1). The EPA reviewed scientific assessments of the GWPs for these F–GHGs as provided with provisional GWP requests received from Honeywell International (“Honeywell”) and DuPont de Nemours, Inc. (“DuPont”) and published in the February 3, 2012 Notice of Data Availability (77 FR 5514). The EPA approved provisional GWPs for one F–GHG for Honeywell, and for six F–GHGs for DuPont. The EPA finalized its determinations for these compounds on February 24, 2012 (see Docket ID No. EPA–HQ–OAR–2009–0927–0273). Based on EPA's review of the GWP estimation methods for these compounds, we are proposing to amend Table A–1 to include these seven gases.
• Four compounds submitted with provisional GWP requests for which the EPA did not approve provisional GWPs (including three F–GHGs for DuPont, and one F–GHG for Honeywell). The companies submitted scientific data supporting the GWPs of these four compounds, which was made available in the February 3, 2012 Notice of Data Availability (77 FR 5514). (see Docket ID No. EPA–HQ–OAR–2009–0927–0256 for further discussion of the scientific assessments reviewed). The EPA did evaluate the GWPs of these F–GHGs, but not for the purposes of the calculations in 40 CFR 98.123(c) because the calculated emission rates of these chemicals, when using the default GWP, did not exceed the 10,000 metric tons CO
• Ten F–GHGs submitted by DuPont on August 21, 2012, with supporting data and analysis (see Table 3 of this preamble). We are proposing to include the ten compounds in Table A–1. For each compound, DuPont included peer-reviewed scientific data supporting the suggested GWP.
• Five F–GHGs which were identified from the EPA's review of industrial gases produced for or used in the electronics manufacturing, fluorinated gas production, magnesium production, electrical equipment manufacture or refurbishment, and industrial gas supplier source categories and for which scientific assessments or other documentation of the GWPs were identified through the EPA's SNAP Program or peer-reviewed literature. These compounds are identified under the common names FK–5–1–12 (Novec
For the first 11 compounds in Table 3 (seven with approved provisional GWPs and the four without approved provisional GWPs), the EPA determined that the methods used to estimate the GWPs were likely to overestimate the GWPs by an order of magnitude or more (see Docket ID No. EPA–HQ–OAR–2009–0927–0256). These compounds are all relatively short-lived, and the analyses to determine the GWP for these compounds used the simplifying assumptions that the compounds are well-mixed in the atmosphere. In general, the assumption that short-lived compounds are well-mixed overestimates the radiative forcing of these gases and may affect estimates of the atmospheric lifetime. Because of this simplifying assumption, the proposed GWPs are likely to be overestimates. However, the EPA has determined that the proposed GWPs for these short-lived gases represent the most current, peer-reviewed, scientific knowledge of the radiative properties and lifetimes of these gases. For subpart L reporters, the proposed GWPs would provide a more accurate calculation of CO
For the ten F–GHGs submitted by DuPont on August 21, 2012, the radiative efficiency of each compound is derived using a constant mixing ratio of the compounds in the troposphere (i.e., the methods assume that the compounds are well-mixed). These compounds are all anticipated to be short-lived in the atmosphere. Therefore, the constant mixing ratio likely overestimates the share of these compounds that reside higher in the atmosphere and consequently overestimates the radiative efficiency (and GWP). For four of the 10 compounds, the approach used to calculate the atmospheric lifetimes likely underestimates the lifetimes of these compounds.
For the five F–GHGs identified through scientific assessments published through EPA's SNAP program or in peer-reviewed literature, the EPA evaluated the estimation methods used to determine the GWP for each compound. The EPA's determination for each compound (identified by common name) and the proposed GWPs are as follows:
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A complete analysis of each of these compounds and the proposed GWPs are included in the memorandum, “GWP Determinations for Proposed Additional F–GHGs for Table A–1,” Docket ID No. EPA–HQ–OAR–2012–0934.
For commenters providing new estimates of GWPs for the proposed compounds for inclusion in Table A–1, we request that the commenter submit the following types of scientific data and analyses to support the estimated GWP:
(1) Data and analysis related to the low-pressure gas phase infrared absorption spectrum of the compound;
(2) Data and analysis related to reaction mechanisms and rates such as photolysis and reaction with atmospheric components such as hydroxyl radicals (OH), ozone (O
(3) Radiative transfer analyses that integrate the lifetime and infrared absorption spectrum data to calculate the GWP; or,
(4) Published or unpublished studies of the GWP of the compound.
The EPA intends to review and consider additional information submitted during the public comment period to assess the proposed GWPs and consider other accurate estimates of the GWP for each compound. We anticipate requesting comment on additional compounds in a separate action.
In addition to the proposed amendments to global warming potentials in Table A–1, we are also proposing corrections and other clarifications to certain provisions of subpart A of Part 98. The more substantive corrections, clarifying, and other amendments to subpart A are found here. Additional minor corrections are discussed in the Table of Revisions to this rulemaking (see Docket ID No. EPA–HQ–OAR–2012–0934).
The EPA is proposing to revise the reporting requirements of 40 CFR 98.3(c)(1). Section 98.3(c)(1) requires reporting of the physical address of the facility where the emissions occur (not the parent company address). Some facilities do not have a physical street address assigned to them and their mailing address is not co-located with their facility operations. In order to more accurately report the physical location of these facilities, the EPA is proposing that those without a physical address at their operations site provide latitude and longitude coordinates instead. This proposed addition is not intended as an option for any facility whose physical address coincides with their facility operations. It also is not intended for use by suppliers and importers and/or exporters covered by Part 98, or facilities reporting under subpart W in the natural gas distribution (40 CFR 98.230(a)(8)) or onshore petroleum and natural gas production (40 CFR 98.230(a)(2)) industry segments.
We are proposing to add a requirement to 40 CFR 98.3(c)(13) for all facilities with a power generating unit to report the facility Office of the Regulatory Information System (ORIS)
We are proposing to add a provision to 40 CFR 98.3(c)(11) to include instructions for the reporting of a United States parent company legal name and address. The proposed amendment would specify that a facility or supplier must use the reporting instructions found in e-GGRT when reporting a parent company. The proposed amendment would facilitate verification of the emissions reported by allowing the EPA to provide a common naming convention through e-GGRT that would be used to easily identify parent companies and to accurately attribute GHG emissions to the correct parent companies. Instructions regarding reporting of parent company name and address have been posted to the docket for this action (See docket ID no. EPA–HQ–OAR–2012–0934).
Additionally, we are proposing to amend 40 CFR 98.3(h)(4) to clarify the provisions for requesting an extension of the 45-day period for submission of revised reports in 40 CFR 98.3(h)(1) and (2). Specifically, we are clarifying the timing requirements for approval or denial of the automatic 30-day extension and any subsequent extensions provided in 40 CFR 98.3(h)(4). The proposed amendments would require reporters to submit a request for any additional extension beyond the 30-day automatic extension at least 5 business days prior to the expiration of the initial 30-day extension. If the request demonstrates that it is not practicable to submit the data or information needed to resolve a potential reporting error following the 30-day automatic extension, the Administrator may approve an additional extension request. The proposed amendment would provide a reasonable timeline for reporters to submit extension requests and for the EPA's collection and verification of reported data.
We are proposing to add a definition of fluidized bed combustor (FBC) to 40 CFR 98.6. The definition is necessary to be consistent with the proposed addition of FBC-specific N
Finally, we are proposing revisions to the definitions of three terms in subpart A: degasification system, ventilation well or shaft, and ventilation system. These terms are used only in subpart FF, Underground Coal Mines, and are proposed to be revised to more closely align with common terminology used in the coal mining industry.
We are proposing revisions to the requirements of 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources) to clarify the use of the Tier methodologies and to update high heat value (HHV) and emission factors. The more substantive corrections, clarifying, and other amendments to subpart C are found here. Additional minor corrections are discussed in the Table of Revisions to this rulemaking (see Docket ID No. EPA–HQ–OAR–2012–0934).
First, we are proposing to amend 40 CFR 98.33(b)(1) to expand the use of the Tier 1 methodology in one situation that currently requires the use of the Tier 3 methodology. Generally, subpart C requires the use of the Tier 3 methodology for combustion units that are greater than 250 million Btus per hour for all fuels listed in Table C–1, and, for fuels not listed in Table C–1 if the fuel provides 10 percent or more of the annual heat input to the unit. To reduce the monitoring burden of determining carbon content of Table C–1 fuels that are used in relatively small amounts annually, we are proposing a change to 40 CFR 98.33(b)(1) that will allow the Tier 1 methodology to be used for Table C–1 fuels that are combusted in a unit with a maximum rated heat input capacity greater than 250 million Btus per hour, if the fuel provides less than 10 percent of the annual heat input to the unit.
We are proposing changes to Table C–1 to update the HHV and emission factors for several fuels and to add emission factors for culm and gob. The EPA received a number of comments and questions through the GHGRP Help Desk with suggestions for improvements to these factors. We researched these factors to ensure the most scientifically valid values were reflected. An analysis of the proposed changes to Table C–1 as a result of this research can be found in the memorandum “Review and Evaluation of 40 CFR Part 98 CO
In response to a Petition for Rulemaking (“Sierra Club Petition”),
Table 4 of this preamble shows a summary of the proposed Table C–1 revisions, and major changes are explained below.
The changes include a change to the HHV for wood and wood residuals. The HHV in Table C–1 for Wood and Wood Residuals is a wet basis value that assumes a moisture content of 12 percent. GHGRP reporters have indicated that they use wood fuel with highly variable moisture content, and so the existing factor results in calculation inaccuracies of CO
Revisions are proposed to the HHV and emission factors for the individual components of liquid petroleum gases (LPG) including propane, propylene, ethane, ethylene, isobutane, isobutylene, butane, and butylene. Since the HHV for these LPGs are presented on the basis of million Btu per gallon, and these compounds are gases under standard conditions, the heating value must be presented using a stated temperature and pressure. For all LPG except ethylene, we are proposing estimates of HHV at 60 degrees Fahrenheit (°F) and saturation pressure. For ethylene, since it cannot be liquefied above 48.6°F, we have selected a value for HHV that is determined at 41°F (slightly under the critical temperature) and the corresponding saturation pressure. The emission factors for these compounds have also been updated using the proposed HHV and the fraction of carbon contained in the compound.
We are proposing a correction to the emission factor for coke because it appears that the emission factor currently in Table C–1 was inadvertently listed as the emission factor for petroleum coke. We have also changed the name in Table C–1 to “coal coke” to differentiate this substance from “petroleum coke,” which has a different HHV and EF. We are also proposing updated emission factors for the four types of coal and the four listed factors for mixed coals based on the most recent version of the factors used in the Inventory.
The HHV for the biomass fuel “solid byproducts” would be revised to reflect the average of the solid byproducts consumed by the facilities that reported HHV in the 1999 survey conducted by the Energy Information Administration. The proposed value is presented on a wet basis, and is more consistent with other biomass fuels. Based on our research, we are also proposing minor changes to the HHV and/or emission factors for the following substances: natural gas, used oil, petrochemical feedstocks, and tires. Other proposed changes to Table C–1 include updates to emission factors and HHV based on our latest research and to standardize conversion factors. These corrections are discussed in the memorandum “Review and Evaluation of 40 CFR Part 98 CO
We are also proposing to revise 40 CFR 98.33(e)(3)(iv). The method in 40 CFR 98.33(e)(3)(iv) for calculating biogenic CO
The EPA received a Petition for Reconsideration and Rulemaking from the American Forest & Paper Association (AF&PA) and the American Wood Council (AWC) on November 16, 2012 (hereafter referred to as “AF&PA Petition”).
Table 5 of this preamble summarizes the proposed Table C–2 revisions, and major changes are explained below.
Specifically, based on our analysis of this emissions test data, we are proposing to add a row for wood and wood residuals in Table C–2 that contains CH
We are also proposing to add coal, culm, and gob N
We are proposing to add “fuel gas” to Table C–2 of subpart C to address a program gap discovered through the verification process. Because fuel gas is not currently included in Table C–2, instructions are included in subparts X and Y to use the default CH
We are proposing one revision to the reporting requirements of 40 CFR part 98, subpart H (Cement Production). The current Part 98, published on October 30, 2009, provides that facilities subject to subpart H report the monthly cement production from each kiln at the facility for verification of reported emissions. In the preamble to the Technical Corrections, Clarifying, and Other Amendments to Certain Provisions of the Mandatory Greenhouse Gas Reporting Rule (75 FR 66434, October 28, 2010), the EPA stated its intent to change the cement production reporting requirements under 40 CFR 98.86 to require annual, facility-wide cement production instead of monthly, kiln-specific cement production (75 FR 66440). Reporting cement production on a kiln-specific basis is inconsistent with cement plant manufacturing practices, because kilns produce clinker (an intermediate product in cement manufacturing) and do not make cement. Although it was obviously the EPA's intention to revise the rule accordingly, inadvertently, this change was not reflected in the rule. This change is also consistent with the requirement in 40 CFR 98.86(b)(3), which requires facilities without continuous emissions monitoring systems (CEMS) to report annual cement production at the facility. Therefore, we are proposing to amend 40 CFR 98.96(a)(2) to require reporting of facility-wide cement production.
We are proposing two corrections to subpart K of Part 98 (Ferroalloy Production). First, we are proposing to revise Equation K–3 of subpart K to correct the equation. The equation in the current Part 98 does not include a conversion factor from kilograms to metric tons. Therefore, we are proposing to correct Equation K–3 to revise the numerical term “2000/2205” to “2/2205” to account for this conversion.
Next, we are proposing to amend 40 CFR 98.116(e) to require the reporting of the annual process CH
Under subpart L of Part 98 (Fluorinated Gas Production), the EPA is proposing to extend temporary, less detailed reporting requirements for fluorinated gas producers for an additional year. In a final rule published on August 24, 2012, the EPA promulgated temporary, less detailed reporting requirements for reporting years 2011 and 2012 (77 FR 51477). As discussed in that final rule, this was intended to allow the EPA time to evaluate concerns raised by the producers that EPA release of the more detailed reporting required by the 2010 final rule would reveal trade secrets, and to consider how the rule might be changed to balance these concerns with the need to obtain the data necessary to inform the development of future GHG policies and programs. The proposed extension would require the same less detailed reporting for reporting year 2013 as for reporting years 2011 and 2012. The extension would allow the EPA, as well as stakeholders, to consider the various options for reporting emissions under subpart L in conjunction with EPA's on-going evaluations regarding reporting inputs to emission equations for subpart L, whose reporting deadline was deferred until 2015. Fluorinated gas producers and other commenters have often noted that whether or not disclosure of a particular data element poses confidentiality concerns depends on the other data that would be required to be reported and/or disclosed. The extension would allow the various potential reporting requirements and confidentiality determinations to be considered simultaneously.
We are proposing several clarifying revisions to subpart N of Part 98 (Glass Production). The more substantive corrections, clarifying, and other amendments to subpart N are found here. Additional minor corrections are discussed in the Table of Revisions (see Docket ID No. EPA–HQ–OAR–2012–0934).
We are proposing to revise the monitoring methods used to measure carbonate-based mineral mass-fractions to allow for more accurate measurement methods and to add flexibility for reporters. The current Part 98 requires that such measurements are based on sampling using ASTM D3682–01 (Reapproved 2006) Standard Test Method for Major and Minor Elements in Combustion Residues from Coal Utilization Processes or ASTM D6349–09 Standard Test Method for Determination of Major and Minor Elements in Coal, Coke, and Solid Residues from Combustion of Coal and Coke by Inductively Coupled Plasma—Atomic Emission Spectrometry. However, we have determined that industry consensus standards that specify analysis by X-ray fluorescence (e.g., ASTM C25–11 Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime and ASTM C1271–99 Standard Test Method for X ray Spectrometric Analysis of Lime and Limestone) are more accurate than ASTM D6349–09, which uses inductively coupled plasma or ASTM D3682–01, which uses atomic absorption. Therefore, we are proposing to revise 40 CFR 98.144(b) to specify that reporters determining the carbonate-based mineral mass fraction must use sampling methods that specify X-ray fluorescence. We are proposing to remove ASTM D6349–09 and ASTM D3682–01 from the requirements in 98.144(b). The proposed amendment would allow reporters flexibility in choosing a sampling method (since multiple X-ray fluorescence methods are available) while ensuring that more accurate available measurement methods are applied. For measurements made in the emission reporting year 2013 or prior years, reporters would continue to have the option to use ASTM D6349–09 and ASTM D3682–01. The EPA is not proposing to have reporters revise previously submitted annual reports. These facilities would have the option, but not be required, to use the newly proposed option for the reports submitted to EPA in 2013.
The EPA is proposing clarifying amendments and other corrections to Subpart O (HFC–22 Production and HFC–23 Destruction); the more substantive corrections, clarifying, and other amendments to Subpart O are found in this section. Additional minor corrections to Subpart O are discussed in the Table of Revisions (see Docket ID No. EPA–HQ–OAR–2012–0934).
We are proposing to add a sentence to 40 CFR 98.156(c) to clarify how to report the HFC–23 concentration at the outlet of the destruction device in the event that the concentration falls below the detection limit of the measuring device. The provisions of 40 CFR 98.156(c) require facilities that destroy HFC–23 to report the concentration of HFC–23 measured at the outlet of the destruction device during the facility's annual HFC–23 concentration measurements at the outlet of the destruction device. However, if the concentration during the measurements falls below the detection limit of the measuring device, the facility will not be able to report a specific concentration. The proposed sentence clarifies that in this situation, facilities are required to report the detection limit of the measuring device and that the concentration was below that detection limit.
We are proposing several clarifying revisions to subpart P of Part 98 (Hydrogen Production). The more substantive corrections, clarifying, and other amendments to subpart P are found here. Additional minor corrections are discussed in the Table of Revisions (see Docket ID No. EPA–HQ–OAR–2012–0934).
We are proposing to revise 40 CFR 98.163(b) to clarify that when the fuel and feedstock material balance approach is followed, the average carbon content and molecular weight for each month used in Equations P–1, P–2, or P–3 may be based on analyses performed annually or analyses performed more frequently than monthly (based on the requirements of 40 CFR 98.164(b)). If the carbon content or molecular weight measurements are performed annually, reporters would use the annual value as the monthly average. If the analyses are performed more often than monthly, then the reporter would use the arithmetic average of these values as the monthly average. The term definitions in Equations P–1, P–2, and P–3 currently refer to the “results of one or more analyses for month n”; however, the monitoring frequencies specified at 40 CFR 98.163(b)(2), (b)(3) and (b)(4) range from weekly to annually, so this clarification is necessary to align these requirements. Further, we are proposing to revise the term definitions in Equations P–1, P–2, and P–3 to remove references to “one or more analyses” since multiple analyses in a month are not always required, as described above.
We are also proposing to modify 40 CFR 98.164(b)(5) to reduce burden by adding flexibility to the fuel and feedstock analysis requirements, consistent with EPA's original intent
We are proposing to move recordkeeping requirements currently included in 40 CFR 98.164 (Monitoring and QA/QC requirements) to 40 CFR 98.167 (Records that must be retained). Specifically, 40 CFR 98.164(c) and (d) will be moved to new paragraphs 40 CFR 98.167(c) and (d). Finally, we are proposing to revise 40 CFR 98.166(a)(2) and (a)(3) to remove the requirement to report hydrogen and ammonia production for all units combined. The individual unit production is already reported and can be summed to obtain the production for all units combined.
We are proposing multiple amendments to subpart Q of Part 98 (Iron and Steel Production) to provide clarification for certain provisions and calculation methods. The more substantive corrections, clarifying, and other amendments to subpart Q are found here. Additional minor corrections are discussed in the Table of Revisions (see Docket ID No. EPA–HQ–OAR–2012–0934).
We are proposing to amend the definition of the iron and steel production source category in subpart Q, 40 CFR 98.170, to include direct reduction furnaces not co-located with an integrated iron and steel manufacturing process. Reporters are required to report CO
The EPA is proposing to amend Equation Q–5 in subpart Q to account for the use of gaseous fuels in EAFs. Many EAF operators use supplemental natural gas for melting scrap in the furnace. One facility that provided input to the EPA on this issue meets approximately 20 percent of its energy requirement with natural gas. Because natural gas combustion products can constitute a significant portion of CO
Additionally, we are proposing to revise 40 CFR 98.173(d) to clarify when the Tier 4 calculation methodology must be used to calculate and report combined stack emissions. The proposed amendment would clarify that the Tier 4 calculation methodology would be used (and emissions would be reported under subpart C of Part 98) if the GHG emissions from a taconite indurating furnace, basic oxygen furnace, non-recovery coke oven battery, sinter process, EAF, decarburization vessel, or direct reduction furnace are vented through a stack equipped with a CEMS that complies with the Tier 4 methodology in subpart C of this part, or through the same stack as any combustion unit or process equipment that reports CO
We are also proposing to amend 40 CFR 98.174(c)(2) by removing the term “furnace” from the statement “For the furnace exhaust,” because decarburization vessels are not furnaces. We are also proposing to amend 40 CFR 98.174(c)(2) by dividing (c)(2) into two separate sub paragraphs to separately specify the sampling time for continuously charged EAFs. Newer and more efficient EAFs use the “Consteel®” process, which involves continuous, rather than batch, scrap feed. Thus, “production cycles” may be an ambiguous term for reporters who operate a continuous EAF, and could be interpreted to require lengthy test periods as a single production cycle could extend for several days during which steel was continuously tapped. Therefore, we are proposing to remove the term “production cycles” for continuous EAFs and provide owners or operators with the option of sampling for a period spanning at least three hours.
We are proposing to amend 40 CFR 98.175(a) to clarify that 100 percent data availability is not required for process inputs and outputs that contribute less than one percent of the total mass of carbon into or out of the process. In accordance with 40 CFR 98.174(b)(4), reporters do not collect the monthly mass or annual carbon content of inputs or outputs that contribute less than one percent of the total mass of carbon into or out of the process. Therefore, reporters are not required to estimate missing data for these inputs. Similarly, we are proposing to amend 40 CFR 98.176(e) by clarifying that the reporting requirements of 40 CFR 98.176(e) do not apply to process inputs and outputs that contribute less than one percent of the total mass of carbon into or out of the process.
We are proposing changes to subpart X of Part 98 (Petrochemical Production). In addition, we are providing flexibility for reporters and clarifying the calculation methodology, monitoring and reporting requirements, missing data procedures and other provisions under the rule. The more substantive corrections, clarifying, and other amendments to subpart X are found here. Additional minor corrections are discussed in the Table of Revisions to this rulemaking (see Docket ID No. EPA–HQ–OAR–2012–0934).
We are proposing to revise 40 CFR 98.242(b)(2) to clarify that reporters using the mass balance option for a petrochemical process are not to report emissions from the combustion of petrochemical off-gas in any combustion unit, regardless of whether or not the combustion unit is part of the petrochemical process unit. Subpart X currently states that emissions of CO
We are proposing a change to the calculation methodology in 40 CFR 98.243(b) for CH
We are proposing to modify both 40 CFR 98.243(c)(3) and 40 CFR 98.244(b)(4) to allow subpart X reporters that use the mass balance calculation method to obtain carbon content measurements from a customer of the product. Subpart X currently requires petrochemical manufacturers to determine product carbon contents from their own analyses. This change would provide additional flexibility for sources to obtain the carbon content measurement, and it is consistent with the current option that allows petrochemical manufacturers to obtain the carbon content of feedstocks from feedstock suppliers.
We are proposing a change to 40 CFR 98.243(c)(4) for the alternative sampling requirements for feedstocks and products when the composition is greater than 99.5 percent of a single compound for reporters using the mass balance calculation method. Currently, the alternative can only be used during periods of normal operation and when the product meets specifications. We are proposing changes that will allow the alternative method to be used during all times that the average monthly concentration is above 99.5 percent. The proposed changes would allow greater flexibility for reporters.
For reporters using the mass balance calculation method in 40 CFR 98.243(c)(5), we are proposing to revise definitions for five of the terms in Equation X–1. First, we are proposing to clarify that the term “C
We are proposing to modify the test method description for chromatographic analysis in 40 CFR 98.244(b)(4)(xiii) to remove the word “gas.” The proposed change would clarify that a chromatograph other than a gas chromatograph may be used. We are also proposing to modify 40 CFR 98.244(b)(4)(xv) to allow additional methods for the analysis of carbon black feedstock oils and carbon black products. This section of subpart X currently specifies that a reporter may use an industry standard practice for such feedstocks and products. The proposed changes would provide additional flexibility by also allowing the use of a method published by a consensus-based standards organization (i.e., a published method that is not already specifically listed in 98.244(b)(4)). For clarity, the proposed amendments also would list known consensus-based standards organizations and add a requirement for facilities to document the standard method that they use in the facility monitoring plan required under 40 CFR 98.3(g)(5).
We are proposing to add a requirement under 40 CFR 98.244(c) to clarify the monitoring and quality assurance requirements for flares. Following implementation of Part 98, the EPA received questions concerning the monitoring and quality assurances requirements for flares because while the rule refers to subpart Y for flare emission calculation methods, it does not specify monitoring and quality assurance requirements. As a result, we are clarifying the requirements for flares to specify that facilities must conduct monitoring and quality assurance in accordance with 40 CFR 98.254. The proposed monitoring requirements for flares harmonize subpart X with other subparts under Part 98.
We are proposing to clarify the missing data procedures in 40 CFR 98.245 for missing feedstock and product flow rates and missing feedstock and product carbon contents. This section of subpart X currently specifies that reporters are to develop substitute values for these parameters using the same procedures as for missing fuel carbon contents as specified in 40 CFR 98.35. The proposed amendment clarifies that the procedures for missing fuel carbon contents in 40 CFR 98.35(b)(1) are to be used only for missing feedstock and product carbon contents, and the procedures for missing fuel usage in 40 CFR 98.35(b)(2) are to be used to develop substitute values for missing feedstock and product flow rates. We are also proposing to add missing data requirements for missing flare data and for missing molecular weights for gaseous feedstocks and products. The amendment would require reporters to develop substitute values for missing molecular weights using the procedures for missing fuel carbon contents as specified in 40 CFR 98.35(b)(1), and substitute values for missing flare data would be developed using the procedures in 40 CFR 98.255(b) and (c). We are proposing these additional missing data procedures so that reporters do not have to contact the EPA individually for guidance on how to proceed in the absence of instructions in the rule. We also expect that these changes will promote consistency both among subpart X reporters and between subpart X reporters and other reporters (e.g., subpart Y reporters).
We are proposing two amendments to clarify the reporting requirements of 40 CFR 98.246(a)(6) for reporters using the mass balance method. This section of subpart X currently requires a reporter to report the name of each method listed in 40 CFR 98.244 that is used to determine a measured parameter. In addition, when a method is not listed in 40 CFR 98.244 (i.e., for flow or mass measurements), the reporter is required to provide a description of the manufacturer's recommended method. The only methods listed in 40 CFR 98.244 are methods for determining carbon content or molecular weight, and they are all in paragraph (b)(4) of 40 CFR 98.244. Thus, one proposed amendment to clarify 40 CFR 98.246(a)(6) would require reporters to report the name of each method that is used to determine carbon content or molecular weight in accordance with 40 CFR 98.244(b)(4). The current requirement to provide a description of manufacturer's recommended method has been interpreted in various ways, and a wide variety of information has been provided in reports to date. To simplify this reporting requirement,
We are proposing to revise 40 CFR 98.246(a)(8) to specify that reporters using the mass balance calculation method must identify combustion units outside of the petrochemical process unit that burned process off-gas. This section of subpart X currently requires identification of each combustion unit that burned both process off-gas and supplemental fuel. Supplemental fuel is defined as fuel burned in a petrochemical process that is not produced within the process itself. Thus, the current language in 40 CFR 98.246(a)(8) requires identification of only those combustion units within a petrochemical process unit that burn off-gas from the process. The purpose of the proposed change is to extend this requirement to combustion units that combust fuel gas generated by the petrochemical process but are not part of the petrochemical process. This additional information is needed to allow us to verify correct reporting of fuel gas in subpart C.
We are proposing to revise 40 CFR 98.246(a)(9) for reporters using the alternative to sampling and analysis for carbon content as specified in 40 CFR 98.243(c)(4) of the mass balance calculation method. One of the proposed changes would clarify the units of time to report in (days) for periods during which off-specification product was produced. A second proposed revision would eliminate reporting of the volume or mass of off-specification products produced. If a facility is complying with 40 CFR 98.243(c)(4) for a product and produces off-specification products so that the average monthly purity does not fall below 99.5 percent, then the facility need not report the amount of off-specification product. However, if the average monthly purity does fall below 99.5 percent, the facility must use the carbon content procedures in 40 CFR 98.243(c)(3) for the off-specification product, and must report the amount and carbon content of the off-specification product under 40 CFR 98.246(a)(4). The proposed revision would reduce the burden on reporters.
We are proposing several changes to the CEMS reporting requirements in 40 CFR 98.246(b)(4), (b)(5), and (b)(6) to improve the accuracy of emissions attributed to subpart X sources, clarify requirements, and reduce burden. We would revise 40 CFR 98.246(b)(4) to specify that for each CEMS monitoring location where CO
We are proposing changes, technical corrections and clarifying amendments for subpart Y of Part 98 (Petroleum Refineries). The more substantive corrections, clarifying, and other amendments to subpart Y are found here. Additional minor corrections are discussed in the Table of Revisions (see Docket ID No. EPA–HQ–OAR–2012–0934).
In conjunction with the addition of fuel gas to Table C–2 as discussed in Section II.B of this preamble, we are proposing revisions to subpart Y to change the reference to Table C–2 at 40 CFR 98.253(b)(2) and (b)(3) from “Petroleum Products” to “Fuel Gas” for calculation of CH
We are proposing to revise 40 CFR 98.253(f)(4) and the terms “F
We are proposing to clarify 40 CFR 98.253(j) regarding when Equation Y–19 must be used for calculation of CH
We are proposing an additional requirement, minor corrections, and clarifications to subpart Z of Part 98 (Phosphoric Acid Production). The more substantive corrections, clarifying, and other amendments to subpart Z of Part 98 are discussed in this section. Additional minor corrections are discussed in the Table of Revisions (see Docket ID No. EPA–HQ–OAR–2012–0934).
The terminology used in the introductory text of 40 CFR
We are also proposing to revise 40 CFR 98.266(b) to require that the annual report must include the annual phosphoric acid production capacity (tons), rather than the annual permitted phosphoric acid production capacity. Through implementation of the rule, the EPA has learned that not all facilities have a “permitted” production capacity. The EPA is proposing to revise this requirement to report annual production capacity, as opposed to permitted production capacity, in the current Part 98.
We are also proposing to amend 40 CFR 98.266 to add a requirement to report the number of times missing data procedures were used to estimate the CO
We are proposing changes to subpart AA of Part 98 (Pulp and Paper Manufacturing) to revise default emission factors and clarify the information that must be reported. The more substantive corrections, clarifying, and other amendments to subpart AA of Part 98 are discussed in this section. Additional minor corrections are discussed in the Table of Revisions (see Docket ID No. EPA–HQ–OAR–2012–0934).
We are proposing to amend 40 CFR 98.273(a)(3), 40 CFR 98.276(e) and Equation AA–1 to remove the references to site-specific emissions factors because there are no methods or requirements in subpart AA for deriving the site-specific GHG emission factors for biomass combustion.
We are proposing revisions to the emission factors shown in Tables AA–1 and AA–2 to correct format errors that occurred in the printing of the rule in the CFR. Specifically, in Table AA–1, the CH
In addition to correcting formatting errors, we are proposing revisions to the CH
We are also proposing additional changes to Table AA–2 to (1) Amend the title to remove the reference to fossil fuel since the table contains a biogenic fuel as well (biogas); (2) specify that the emission factors for residual and distillate oil apply for any type of residual (no. 5 or 6) or distillate (no. 1, 2 or 4) fuel oil to clarify our intent that the emissions factors apply to all grades of these fuel types; and (3) add a row to specify that the Table C–2 emission factor for CH
We are proposing to amend 40 CFR 98.276(k) to clarify the EPA's intent regarding the annual pulp and/or paper production information that must be reported. Since publication of the rule, we have received questions from the industry about what this requirement means and the units of measure to use for reporting pulp production. Hence, we are proposing to amend the rule to clarify that the annual production information must consist of the production of air-dried, unbleached virgin pulp produced onsite during the reporting year and the production of paper products exiting the paper machine(s) during the reporting year, prior to application of any off-machine coatings.
We are proposing several revisions to subpart BB of Part 98 (Silicon Carbide Production). The more substantive corrections, clarifying, and other amendments to subpart BB of Part 98 are discussed in this section. Additional minor corrections are discussed in the Table of Revisions (see Docket ID No. EPA–HQ–OAR–2012–0934).
We are proposing to revise 40 CFR 98.282(a) to remove the requirement for silicon carbide production facilities to report CH
Reporters must continue to monitor and report CO
We are proposing two substantive corrections to subpart DD (Electrical Transmission and Distribution Equipment Use) in this section. We are proposing to revise 40 CFR 98.304(c)(1) and (c)(2) to correct the accuracy and precision requirements for weighing cylinders. In the current Part 98, the subpart DD regulatory text for 40 CFR 98.304(c)(1) and (c)(2) presents the required scale accuracies as “2 pounds of the scale's capacity.” The scale accuracy requirement for subpart DD was intended to be “2 pounds of true weight,” as expressed in the “Technical Support Document: Emissions from Electric Power Equipment Use” and “EPA's Response to Public Comments: Subpart DD: Electric Transmission and Distribution Equipment Use”
We are proposing multiple amendments to subpart FF of Part 98 (Underground Coal Mines) to clarify certain provisions and equation terms, harmonize reporting requirements, and improve verification of annual GHG reports. The more substantive corrections, clarifying, and other amendments to subpart FF of Part 98 are discussed in this section. Additional minor corrections are discussed in the Table of Revisions (see Docket ID No. EPA–HQ–OAR–2012–0934).
We are proposing to revise the terminology in subpart FF in response to questions submitted by reporters. Reporters have noted that ventilation does not take place through wells, but rather mine ventilation system shafts or vent holes, and degasification systems do not use shafts, but rather wells or gob gas vent holes. Reporters have also stated that mine ventilation air is not flared, rather it is destroyed using a ventilation air methane (VAM) oxidizer. Therefore we are proposing to revise provisions in 40 CFR 98.320(b), 40 CFR 98.322(b) and (d), 40 CFR 98.323(c), and 40 CFR 98.324(b) and (c) to adopt terminology that more accurately reflects industry operations.
We are also proposing to revise the reporting requirements of subpart FF to include additional data elements that will allow the EPA to verify the data submitted, perform a year to year comparison of the data, and assess the reasonableness of the data reported.
We are proposing multiple revisions to 40 CFR part 98, subpart HH (Municipal Solid Waste Landfills) to clarify equations and amend monitoring requirements to reduce burden for reporters. The more substantive corrections, clarifying, and other amendments to subpart HH are discussed in this section. Additional minor corrections are discussed in the Table of Revisions (see Docket ID No. EPA–HQ–OAR–2012–0934).
We are proposing to amend the definition of the degradable organic carbon (DOC) term for Equation HH–1 to indicate that the DOC values for a waste type must be selected from Table HH–1. When we originally proposed subpart HH in April of 2009, Equation HH–1 applied to both MSW and industrial waste landfills. When we finalized Subpart HH for MSW landfills only, the definition of the DOC term allowed for the default value from Table HH–1 or measurement data, if available. Although we included measurement methods for determining site-specific DOC values for industrial waste streams within Subpart TT, we do not consider that these laboratory methods are suitable for determining the DOC for MSW landfills in subpart HH because of the variability and heterogeneity of MSW.
The EPA may take into consideration the usage of site-specific DOC values for MSW landfills in Equation HH–1 if suitable measurement methods are available. We specifically request comment from reporters who have used measurement methods for determining DOC. We request that the commenter provide information on the type of waste streams for which measurement methods were used, the analytical method used to determine DOC, and procedures used to ensure that the samples tested were representative of the waste stream tested for different years. We also note that, if measurements of DOC are made for different years, the DOC variable in Equation HH–1 should be a function of
We are proposing to amend the definition of the term “F” in Equation HH–1 (fraction by volume of CH
We are also proposing to revise the definition of parameter “N” in Equation HH–4 and the provisions of 40 CFR 98.343(b)(2)(i), (ii), (iii)(A), and (iii)(B). We received comments from landfill owners and operators that the requirement to sample CH
We are proposing to amend the oxidation fraction default value used in Equations HH–5, HH–6, HH–7, and HH–8 of subpart HH. We received comments from landfill owners and operators that the oxidation fraction default value of 10 percent that is required to be used in these equations is too low and that many landfills exhibit much higher oxidation fractions. Over the past several years, numerous U.S. landfills have been tested to estimate the oxidation fraction; the newly tested landfills have been predominately landfills with gas collection systems and clay soil or “other soil mixture” covers. We reviewed the oxidation study data and analyzed Subpart HH data to evaluate various options for revising the default oxidation fraction. Based on our review, we agree that the 10 percent soil oxidation fraction likely underestimates the amount of methane oxidized in the surface soil layer when the landfill gas flow through the soil surface is reduced, as is the case for landfills with gas collection systems. We considered a revised single default oxidation fraction or a default oxidation fraction based on the type of cover soil used at the landfill, but these defaults do not take in account the key variable, which is the methane flux rate entering the surface soil layer. Based on our analysis, we are proposing three different default oxidation fractions depending on the methane flux “bin,” found in new proposed Table HH–4. For cases where the methane flux is projected to be high (greater than 70 grams/m
We are also proposing to amend Equations HH–6, HH–7, and HH–8 and surrounding text to generalize these equations in the event that the landfill contains multiple landfill gas collection system measurement locations and/or multiple destruction devices. When there is a single landfill gas measurement location, these equations are identical to the existing equations. However, the existing equations were inadequate to calculate CH
We are also proposing to amend the first sentence in 40 CFR 98.345(c) to revise “in reporting years” to “in the reporting year” to clarify that the missing data procedures are for a reporting year and that reporters do not need to report substitute data information for years prior to the current reporting year, thereby reducing the burden on reporters.
Finally, we are proposing to revise 40 CFR 98.346(d)(1) and (e) to move the reporting elements pertaining to the methane correction factor (MCF) from paragraph (d)(1) to paragraph (e) because MCF is not a function of the waste type. This amendment eliminates the duplicative reporting requirements for MCF and its related reporting elements (i.e., reporters would no longer be required to report this information for each waste type).
We are proposing multiple revisions to 40 CFR part 98, subpart LL (Suppliers of Coal-based Liquid Fuels) to clarify requirements and amend data reporting requirements to reduce burden for reporters. This section includes the more substantive corrections, clarifying, and other amendments to subpart LL. Additional minor corrections are discussed in EPA's Table of Revisions (see Docket ID No. EPA–HQ–OAR–2012–0934).
To reduce burden, we are proposing to remove the requirements at 40 CFR 98.386(a)(1), (a)(5), (a)(13), (b)(1), and (c)(1) for each facility, importer, and exporter to report the annual quantity of each product or natural gas liquid on the basis of the measurement method used. Reporters would continue to report the annual quantities of each product or natural gas liquid in metric tons or barrels at 40 CFR 98.386(a)(2), (a)(6), (a)(14), (b)(2), and (c)(2). We are also retaining the requirement to report a complete list of methods used to measure the annual quantities reported for each product or natural gas liquid.
We are proposing several revisions to 40 CFR part 98, subpart MM (Suppliers of Petroleum Products) to clarify requirements and amend data reporting requirements to reduce burden for reporters. This section includes the more substantive corrections, clarifying, and other amendments to subpart MM. Additional minor corrections are discussed in the Table of Revisions (see Docket ID No. EPA–HQ–OAR–2012–0934).
We are proposing to clarify the equation term for “Product
As with the proposed changes to subpart LL, in order to reduce burden for reporters, we are proposing to remove the requirements of 40 CFR 98.396(a)(1), (a)(5), (a)(13), (b)(1), and (c)(1) for each facility, importer, and exporter to report the annual quantity of each petroleum product or natural gas liquid on the basis of the measurement method used. Reporters would continue to report the annual quantities of each petroleum product or natural gas liquid in metric tons or barrels at 40 CFR 98.396(a)(2), (a)(6), (a)(14), (b)(2), and (c)(2). We are also retaining the requirement to report a complete list of methods used to measure the annual quantities reported for each product or natural gas liquid.
In order to reduce the recordkeeping and reporting burden, the EPA is proposing to eliminate the reporting requirement for individual batches of crude oil feedstocks. The reporting requirements for crude oil at 40 CFR 98.396(a)(20) are proposed to be changed to require only the annual quantity of crude oil. We are also proposing to eliminate the requirement to measure the API gravity and the sulfur content of each batch of crude oil at 40 CFR 98.394(d). We are also proposing to remove the requirement at 40 CFR 98.394(a)(1) that a standard method by a consensus-based standards organization be used to measure crude oil on site at a refinery, if such a method exists. Other associated changes to the rule to harmonize with this change include removing the definition of “batch,” removing the procedures for estimating missing data for determination of API gravity and sulfur content at 40 CFR 98.395(c), and the recordkeeping requirement for crude oil quantities at 40 CFR 98.397(b). Reporters would still be required to maintain all the records required to support information contained in the reports as specified at 40 CFR 98.397(a).
We are proposing to include the definitions of natural gas liquids (NGL) and bulk NGLs in the subpart MM definitions at 40 CFR 98.397 to clarify the distinction between NGL and bulk NGL for reporting purposes under subpart MM. “Natural gas liquids (NGLs)” for purposes of reporting under subpart MM means hydrocarbons that are separated from natural gas as liquids through the process of absorption, condensation, adsorption, or other methods, and are sold or delivered as differentiated product. Generally, such liquids consist of ethane, propane, butanes, or pentanes plus. Those subject to subpart MM are required to report NGLs as the individual differentiated product and are not required to conduct testing to determine additional components (i.e., impurities) that are contained within the differentiated product. For a mixture, the individual components should be reported. For example, if a refinery receives a known mixture of propane and ethane, the refiner must report the quantities of propane and ethane individually. Undifferentiated NGLs would be reported as bulk NGLs for subpart MM. We are also proposing to clarify the reporting requirements for bulk NGLs and NGLs. NGLs should be reported either as differentiated NGLs or as bulk NGLs. The requirement at 40 CFR 98.396(a)(22) is proposed to be modified to specify that NGLs reported in 40 CFR 98.396(a)(2) should not be reported again in 40 CFR 98.396(a)(22).
Finally, we are proposing to revise the default density and emission factors in Table MM–1 for propane, propylene, ethane, ethylene, isobutane, isobutylene, butane, and butylene. Because these compounds are gases under standard conditions, the default density metric must be presented using a stated temperature and pressure. For all compounds except ethylene, we are proposing estimates of density and calculated emission factors at 60 degrees F and saturation pressure, the standard temperature and pressure conditions used by industry. For ethylene, because it cannot be liquefied above 48.6°F, we have selected as a basis for the values of density and emission factor conditions at 41°F (slightly under the critical temperature) and the corresponding saturation pressure. The current and proposed values for default density and emission factors are included in Table 6 of this preamble.
The EPA is proposing multiple corrections and clarifying amendments to the provisions of subpart NN (Suppliers of Natural Gas and Natural Gas Liquids). The more substantive corrections, clarifying, and other amendments to subpart NN are discussed in this section. Additional minor corrections are discussed in the Table of Revisions (see Docket ID No. EPA–HQ–OAR–2012–0934).
First, we are proposing to amend the definition of Local Distribution Companies (LDCs) in 40 CFR 98.400(b) to coincide with the definition of LDCs in 40 CFR 98.230(a)(8) (40 CFR part 98, subpart W). For LDCs that operate in multiple states, we are proposing to clarify that the operations in each state are considered a separate LDC. For example, if an LDC owns and operates pipelines in two adjacent states, the LDC is considered two separate entities both for the purpose of determining applicability and for registering and reporting under subpart NN. We are also proposing a revision to clarify that interstate and intrastate pipelines delivering natural gas either directly to major industrial users or to farm taps upstream of the local distribution company inlet are not included in the definition of an LDC. The proposed changes are harmonizing changes that improve the consistency of provisions across Part 98.
We are also proposing to revise 40 CFR 98.406(b)(7).
The EPA received comments that the multiple streams of natural gas included in Equation NN–5 may have different characteristics (e.g., HHV). Subpart NN currently requires the use of a single emission factor for all types of gas streams accounted for in Equation NN–5 (e.g., gas stored, liquefied natural gas removed from storage, natural gas received from local production). Because the characteristics of these streams may differ, the EPA agrees that emissions associated with the supply of natural gas would be more accurately calculated using emission factors specific to each stream. To allow reporters the flexibility to use different emission factors for different natural gas streams, the EPA is proposing Equation NN–5 be replaced with two equations, Equations NN–5a and NN–5b. The greenhouse gas quantity associated with the net amount of natural gas that is placed into or removed from storage during the year is proposed to be calculated using Equation NN–5a. Emissions that would result from the combustion or oxidation of natural gas supplied that bypassed the city gate are proposed to be calculated using Equation NN–5b. Separating Equation NN–5 into two equations does not impose additional burden on reporters. LDCs already monitor the volume of gas placed into or removed from storage separately from natural gas that bypassed the city gate. Further, LDCs may use different emission factors in Equations NN–5a and NN–5b, though they are not required to. The default value may be used. Additionally, we are proposing a change to Equation NN–6 that incorporates the two proposed NN–5 equations. With this change, all the equation terms resulting in net additions to the CO
We are also proposing changes to the HHV and emission factors in Table NN–1 and NN–2. As discussed in this preamble for subpart C and subpart MM, we are proposing to revise the default HHV and emission factors for the individual components of liquid petroleum gases (LPG) including propane, ethane, isobutane, and butane. These values for Table NN–1 and NN–2 are based on the same HHV, density and carbon share used for the HHV and emission factors in Table C–1 and MM–1. Since these compounds are gases under standard conditions, the default emission factors in Table NN–1 and NN–2 (kg CO
We are proposing three substantive amendments to subpart PP of Part 98 (Suppliers of Carbon Dioxide) that are described in this section. One additional minor correction is discussed in the Table of Revisions (see Docket ID No. EPA–HQ–OAR–2012–0934).
We are proposing to amend 40 CFR 98.423(a)(3)(i) to clarify that both capture and extraction facilities may use Equation PP–3a to aggregate annual data from multiple flow meters. In the December 17, 2010 Technical Corrections, Clarifying, and Other Amendments to the GHG Reporting Rule (75 FR 79092), we modified the provisions of 40 CFR 98.423(a)(3) to add Equation PP–3b to account for situations where a CO
Finally, we are proposing to amend the reporting requirements of 40 CFR 98.426(f)(10) and (f)(11), which require reporting the aggregated annual CO
We are proposing multiple revisions to 40 CFR part 98, subpart QQ (Importers and Exporters of Fluorinated Greenhouse Gases Contained in Pre-Charged Equipment or Closed-Cell Foams). The more substantive corrections, clarifying, and other amendments to subpart QQ are discussed in this section. Additional minor corrections are discussed in the Table of Revisions (see Docket ID No. EPA–HQ–OAR–2012–0934). We are proposing to correct the equation term “S
We are proposing to amend an example within the definition of “closed-cell foam” at 40 CFR 98.438. The revised text would read “
We are proposing to revise the reporting requirements for 40 CFR 98.436(a)(6)(iii) and (b)(6)(iii) to match the reported data element to the units required to be reported. The proposed revision is a change from “mass in CO
We are proposing to amend the definition of “pre-charged electrical equipment component” at 40 CFR 98.438. The EPA is revising the definition to include components charged with any fluorinated greenhouse gas. The current definition is limited to components charged with SF
We are also proposing to remove the following reporting requirements to alleviate burden on reporters: 40 CFR 98.436(a)(5), (a)(6)(iv), (b)(5), and (b)(6)(iv). These provisions require reporters to supply the dates on which pre-charged equipment or closed-cell foams were imported or exported. The EPA established these reporting requirements to allow the agency to compare these data with shipment manifest data from Customs and Border Protection (CBP). The EPA has since learned that the data required under this subpart is more specific than the data found in the manifests, and has determined that the remaining information provided by the facilities is sufficient for verification purposes. The EPA can compare total annual imports and exports of appliances with reported data without needing date-specific information. In addition, the EPA has been made aware of the burden created by tracking and reporting each shipment by date. Many importers and exporters do not maintain data that include the appliance charge and foam type by date of import or export. Some of those that do indicated to the EPA that this would result in tens of thousands of reports. We do not believe that this level of specificity is necessary to understand the net import and export of fluorinated greenhouse gases within appliances and closed-cell foams. Given the burden and low utility of this data, the EPA is proposing to remove these requirements. The EPA is also not proposing any changes to the recordkeeping requirements of 40 CFR 98.437 as the current requirements do not require the records to be organized by date in this manner. We have determined that the current recordkeeping requirements are sufficient because they would contain a complete record of imports and exports without requiring an aggregation of this data by date.
We are proposing several corrections to subpart RR of Part 98 (Geologic Sequestration of Carbon dioxide). The more substantive corrections, clarifying, and other amendments to subpart RR are discussed in this section. Additional minor corrections are discussed in the Table of Revisions (see Docket ID No. EPA–HQ–OAR–2012–0934).
We are proposing to add a requirement for facilities to report the standard or method used to calculate the mass or volume of contents in containers that is redelivered to another facility without being injected into the well.
We are proposing clarifying amendments and other corrections to subpart SS of Part 98 (Electrical Equipment Manufacture or Refurbishment); the more substantive corrections, clarifying, and other amendments to subpart SS are discussed in this section. Additional minor corrections to subpart SS are discussed in the Table of Revisions (see Docket ID No. EPA–HQ–OAR–2012–0934).
We are proposing to harmonize 40 CFR 98.453(d) and 40 CFR 98.453(h), clarifying the options available to estimate the mass of SF
The EPA intended to provide four options for the calculation of SF
The proposed changes are designed to correct inconsistencies between paragraphs so that all options are clearly identified as available. We are proposing to add text to 40 CFR 98.453(d) to include the options to use the nameplate capacity of the equipment by itself and to use the nameplate capacity along with a calculation of the partial shipping charge; these options were inadvertently omitted from that paragraph. The provisions of 40 CFR 98.453(h) currently state that reporters “must” use the nameplate capacity of the equipment, or calculate the partial shipping charge, to determine the mass of SF
We are proposing several amendments to 40 CFR part 98, subpart TT to clarify and correct calculation methods, provide additional flexibility for certain monitoring requirements, and clarify reporting requirements. The more substantive corrections, clarifying, and other amendments to subpart TT are discussed in this section. Additional minor corrections are discussed in the Table of Revisions (see Docket ID No. EPA–HQ–OAR–2012–0934).
We are proposing to revise the definition of the term “DOC
We are also proposing similar revisions to Equation TT–7, which is used to determine a waste stream-specific DOC value when a facility performs a 60-day anaerobic biodegradation test. The DOC value from Equation TT–7 is then used as an input to Equation TT–1 for that waste stream. Consistent with our proposed revision of the “DOC
We are also proposing to delete the term “1/(MCD
We are proposing to revise 40 CFR 98.464(b) and (c) to broaden the provisions to determine volatile solids concentration for historically managed waste streams for the purposes of 40 CFR 98.460(c)(2)(xii) (exemption as an inert waste) so that they may also be used for determining a site-specific DOC value for historically managed waste streams. When we added the 60-day anaerobic biodegradation test in the 2011 Technical Corrections, Clarifying, and Other Amendments (76 FR, 73886; November 2011), we had not considered the impact of those amendments to this section. We did not intend to prevent facilities from using the 60-day anaerobic biodegradation test for similar waste streams for determining if a waste stream is inert. Furthermore, if a facility tests a similar waste stream and the waste stream is not inert, we did not intend to prevent the facility from using that result as the DOC value for their waste stream for purposes of calculating CH
We are proposing to amend 40 CFR 98.466(b)(1) to clarify that the number of waste streams for which Equation TT–1 is used includes the number of “Inert” waste streams disposed of in the landfill.
As part of the 2011 Technical Corrections, Clarifying, and Other Amendments (76 FR, 73886), we amended Equation TT–4 to become Equation TT–4a and added Equation TT–4b for the calculation of historical waste disposal quantities. However, we neglected to amend the reporting requirements specific to Equations TT–4a and TT–4b in 40 CFR 98.466(c)(4). We also noted that the reporting elements associated with Equations TT–4a or TT–4b were not waste-stream specific and therefore did not need to be reported for each waste stream as indicated by the introduction in 40 CFR 98.466(c). In order to eliminate duplicative reporting requirements and to clarify the reporting requirements when using Equations TT–4a or TT–4b, we are proposing several amendments to 40 CFR 98.466(c). First, we are proposing to revise the introductory text in 40 CFR 98.466(c) to read “Report the following historical waste information” rather than “For each waste stream identified in paragraph (b) of this section, report the following information.” Second, we are proposing to move the reporting of the decay rate (k) from paragraph (c)(1) to a new paragraph (b)(5) as this reporting
To harmonize with the proposed changes to subpart HH, and in order to more accurately reflect the amount of methane oxidized in the surface soil layer of industrial waste landfills, we are proposing to amend the oxidation fraction default value (“OX”) in Equation TT–6. Reporters would be referred to newly proposed Table HH–4 to determine the value for “OX” to be used in Equation TT–6. Please see Section II.Q of this preamble for more detailed explanation.
In addition to adding reporting of the oxidation factor used, we are also proposing clarification of the reporting requirements for CH
Finally, we are proposing changes to Table TT–1 of subpart TT of Part 98. During implementation of Part 98, a question arose regarding the default value for pulp and paper wastes questioning whether the 2006 IPCC Guidelines recommended value of 0.09 instead should be used for wastewater sludges. We reviewed the 2006 IPCC Guidelines as well as laboratory test data results for pulp and paper wastewater sludges provided by NCASI (see memorandum “Calculations documenting the greenhouse gas emissions from the pulp and paper industry” from R.A. Miner, NCASI, to B. Nicholson, RTI International, dated May 21,2008, in Docket ID No. EPA–HQ–OAR–2012–0934). Based on the available data, we agree that the industrial sludge default value for DOC of 0.09 appears to provide a more accurate estimate of the DOC than the generic industry defaults currently provided in the rule. Consequently, we are proposing to revise Table TT–1 to include the DOC default value of 0.09 for “Industrial Sludge.”
We are also proposing to revise the titles of the industry specific categories in Table TT–1 to note that these industry specific parameters apply to the industry waste streams “(other than sludge).” The addition of the new default DOC value for industrial sludge in Table TT–1 also requires the addition of corresponding k-values. The 2006 IPCC Guidelines do not provide default k-values for industrial wastes (sludge or otherwise); the IPCC Waste Model (a spreadsheet tool to help implement the 2006 IPCC Guidelines for landfills) uses the same k-values for industrial wastes as for bulk MSW. While it is anticipated that sludge generated by different industries will have different decay rates (and therefore different k-values), we have very little data by which to determine industry-specific k-values for the new default “Industrial Sludge” waste type. The k-values for “Other Industrial Solid Waste” waste type in Table TT–1 were selected based on country-specific default k-values for bulk MSW in U.S. landfills following the general default assumptions used in the IPCC Waste Model. These same k-values (0.02, 0.04, and 0.06 for dry, moderate, and wet climates, respectively) are being proposed as the default k-values for the new “Industrial Sludge” waste type for the same reasons (i.e., based on country-specific default k-values for bulk MSW in U.S. landfill following general default assumptions used in the IPCC Waste model). We specifically request comment from reporters on these proposed k-values and we further request that the commenters provide any applicable data to support comments.
We are proposing technical amendments to 40 CFR part 98, subpart UU (Injection of Carbon Dioxide) to clarify provisions and improve verification of reported GHG data. The more substantive corrections, clarifying, and other amendments to subpart UU are discussed in this section. Additional minor corrections are discussed in the Table of Revisions for this rulemaking (see Docket ID No. EPA–HQ–OAR–2012–0934).
The EPA is proposing to add a requirement to subpart UU for a facility to report the purpose of CO
We are also proposing to add a requirement for facilities to report the standard or method used to calculate the parameters for CO
In addition to the corrections, clarifying, and other amendments proposed in Sections II.A through II.Z of this preamble, we are proposing minor corrections to subparts E, G, O, S, V, and II 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–2012–0934, 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 typo or error corrections, and removal of redundant text.
The EPA is planning to address the comments on these proposed changes and publish any final amendments before the end of 2013. This section describes when the proposed amendments would become effective for existing reporters and new facilities that could be required to report as a result of the proposed amendments to Table A–1 of subpart A. This section also discusses proposed amendments to subpart A for the use of best available monitoring methods (BAMM) by new reporters and for options considered for revising emissions estimates due to the change in GWPs for 2010, 2011, and 2012 reports previously submitted by existing reporters.
We have determined that it would be feasible for existing reporters to implement the proposed changes for the 2013 reporting year because these changes are consistent with the data collection and calculation methodologies in the current rule. The proposed revisions primarily provide additional clarifications or flexibility regarding the existing regulatory requirements, would not add new monitoring requirements, and would not substantially affect the information that must be collected. Where calculation equations are proposed to be modified, the changes clarify equation terms or simplify the calculations and do not require any additional data monitoring. The owners or operators are not required to actually submit reporting year 2013 reports until March 31, 2014, which is several months after we expect a final rule based on this proposal to be finalized, thus providing an opportunity for reporters to adjust to any finalized amendments.
We are proposing that existing GHGRP reporters begin using the updated GWPs in Tables A–1 for their reporting year 2013 annual reports, which must be submitted by March 31, 2014. In keeping with the March 15, 2012 UNFCCC decision, the Inventory submitted to the UNFCCC in 2015 must use AR4 GWP values (see Section II.A.1.a of this preamble). Development of the 2015 Inventory will rely in part on data from the GHGRP reports submitted in 2014 to supplement the top-down national estimate. Existing GHGRP reporters would also begin calculating facility GHG emissions or supply using the proposed GWPs for the additional F–GHGs discussed in Section II.A.1.c of this preamble for their reporting year 2013 annual reports. The proposed amendments would pose a minimal burden to existing reporters. Part 98 already requires that existing reporters report these F–GHGs in metric tons of chemical emitted or supplied.
In some cases we are proposing revisions to reporting requirements to clarify requirements or to make harmonizing changes within a subpart or between subparts under Part 98. The EPA anticipates that the proposed reporting requirements are either already being collected by reporters or would be readily available to reporters. For example, we are revising reporting requirements to 40 CFR part 98, subpart A to include additional data for identification purposes, such as the latitude and longitude for facilities without a physical address, or the ORIS code for power generation units (an identifier assigned by the Energy Information Administration). In the case of 40 CFR part 98, subpart K (Ferroalloy Production), we are proposing to add a requirement to report the annual process CH
In the case of subpart N (Glass Production), we are proposing to revise the monitoring methods used to measure carbonate-based mineral mass-fractions to allow for more accurate measurement methods and to add flexibility for reporters. The proposed amendments would specify that reporters determining the carbonate-based mineral mass fraction must use sampling methods that specify X-ray fluorescence, instead of the current methods that use inductively coupled plasma or atomic absorption. For measurements made in the emission reporting year 2013 or prior years, reporters would continue to have the option to use the current monitoring methods in Part 98. This change would allow reporters flexibility in choosing a sampling method (since multiple X-ray fluorescence methods are available) while ensuring that more accurate available measurement methods are applied in future reporting years. These facilities would have the option, but not be required, to use the newly proposed option for the reporting year 2013 reports submitted to the EPA in 2014.
In some cases, we are proposing to require reporting of additional data elements to improve verification of the reported GHGs emitted or supplied. For example, for 40 CFR part 98, subpart FF (Underground Coal Mines), we are proposing to substantiate the data collected for identification of each well and shaft by adding a requirement to report the start date and close date of each well or shaft and the number of days the well or shaft was in operation during the reporting year. In the case of subpart UU (Injection of Carbon Dioxide), we are proposing to require reporting of the purpose of CO
In the case of 40 CFR part 98, subpart NN (Suppliers of Natural Gas and Natural Gas Liquids), we are proposing a change to Equation NN–5 to better reflect actual operating conditions. We are proposing to replace Equation NN–5 with two equations, NN–5a and NN–5b, with harmonizing changes to Equation NN–6. The proposed equations would allow for the use of different emission factors for natural gas that is stored and for natural gas that bypasses the city gate, such as natural gas received from local production. We are proposing harmonizing changes to the reporting requirements to specify the quantity of gas that bypasses the city gate and the net quantity of gas that is placed into or withdrawn from on-system storage during the reporting year. The proposed changes do not substantially revise the calculation methodology, but are changes that would provide more accurate GHG estimates in situations where the LDC receives several different streams of natural gas with different characteristics. Furthermore, the proposed changes do not revise the information that must be collected for recordkeeping or reporting. Therefore, we have concluded that under the proposed amendments, existing sources could use the same information that they have been collecting under the current Part 98 and readily available information for each subpart to determine applicability and to calculate and report GHG emissions for reporting year 2013.
The EPA specifically seeks comment on the conclusion that it is appropriate to implement these amendments and incorporate the requirements in the data reported to the EPA by March 31, 2014. Further, we specifically seek comment on whether there are specific subparts or amendments for which this timeline may not be feasible or appropriate due to the nature of the proposed changes or the way in which data have been collected thus far. We request that commenters provide specific examples of how and why the proposed implementation schedule would not be feasible.
As a result of the proposed amendments to the GWPs in Table A–1 of subpart A, some facilities that were never previously required to report under Part 98 may be required to report (see Section V.A of this preamble). Given that a final rule based on this proposed rule would not be finalized until the second half of 2013, we have determined that it would not be feasible for these new facilities to acquire, install, and calibrate monitoring equipment, collect data, and implement these changes for reporting year 2013. Therefore, we are proposing that new reporters who would be required to report under Part 98 as a result of the proposed changes to Table A–1 would begin collecting data on January 1, 2014 for the 2014 reporting year. New reporters would be required to submit their first reports, covering the 2014 reporting year, on March 31, 2015. The intended schedule (including publication of any final rule by the end of 2013) would allow time for new reporters to acquire, install, and calibrate monitoring equipment for the 2014 reporting year.
We are also proposing to add provision 40 CFR 98.3(l) to subpart A to allow new reporters who would be required to report as a result of the proposed new or revised GWPs to have the option of using BAMM from January 1, 2014 to March 31, 2014 for any parameter that cannot reasonably be measured according to the monitoring and QA/QC requirements of a relevant subpart. The EPA understands that because any final rule based on this proposal likely would not be promulgated until the fall of 2013, facilities that do not already have the monitoring systems required by the rule in place might not have time to install and begin operating them by January 1, 2014. Therefore, we are proposing that reporters be allowed to use BAMM during the January 1, 2014 to March 31, 2014 time period without formal request to the EPA. Reporters would also have the opportunity to request an extension for the use of BAMM beyond March 31, 2014; those owners or operators must submit a request to the Administrator by 60 days after the effective date of the final rule. The EPA anticipates granting approval for BAMM no later than December 31, 2014. The EPA has concluded that the time period allowed under this schedule (including the provision for facility-specific requests) is reasonable and will allow facilities that do not currently have the required monitoring systems sufficient time to begin implementing the monitoring methods required by the rule. The proposed schedule would allow approximately six months to prepare for data collection, which is consistent with existing BAMM provisions provided under subpart A of Part 98. By allowing the additional time, many facilities may also be able to install any necessary equipment during other planned (or unplanned) process unit downtime, thus avoiding process interruptions.
The EPA is proposing to independently recalculate revised CO
The proposed revised GWP values in Table A–1 will likely result in changes to the CO
This option would allow the EPA to publish revised emission and supply totals without increasing burden on reporters. This option would remove the need for reporters to resubmit and recertify revised reports. However, Option 2 would not give reporters the opportunity to provide feedback on their individual revised emissions or supply totals, or allow them to certify the amended totals at any point before or after republication. As reporters would be unable to submit revised emission estimates or comment on the estimation methods used to calculate the updated CO
In this notice we are proposing confidentiality determinations for the new or substantially revised reporting data elements (i.e., the data required to be reported would change under the proposed revision) in the proposed subpart rule amendments, except for inputs to equations.
• 75 FR 39094, July 7, 2010; hereafter referred to as the “July 7, 2010 CBI proposal.” Describes the data categories 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 to be reported under nine subparts I, W, DD, QQ, RR, SS, UU; except for those data elements that are inputs to emission equations, and finalized confidentiality determinations for new data elements added to subparts
• 77 FR 51477, August 24, 2012; hereafter referred to as the “2012 Technical Corrections and Subpart L Confidentiality Determinations.” Finalized confidentiality determinations for new data elements added to subpart L.
In this action, the EPA is proposing confidentiality determinations for new or substantially revised data elements. The new and substantially revised data elements result from the proposed corrections, clarifying, and other amendments that are described in Section II of this preamble. These proposed confidentiality determinations would be finalized based on public comment. The EPA currently plans to finalize these determinations at the same time the proposed rule amendments described in Sections II and III of this preamble are finalized. We are not proposing new confidentially determinations for data reporting elements that may be minimally revised for clarification or to correct insignificant errors, 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 data elements are unaffected by this proposed amendment and continue to apply.
In this action, we are proposing to add or substantially revise data reporting requirements in subparts A, H, K, X, Y, Z, AA, FF, HH, NN, QQ, RR, TT, and UU. We propose to assign each of the newly proposed or substantially revised data elements in these subparts to one of the direct emitter or supplier data categories created in the 2011 Final CBI Rule (76 FR 30782, May 26, 2011). 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,” the EPA determined in the 2011 Final CBI Rule that the data elements assigned to those categories are not emission data but did not make categorical CBI determinations. Rather, the EPA made CBI determinations for individual data elements assigned to these two data categories. Similarly, for three supplier data categories, “GHGs Reported,” “Production/Throughput Quantities and Composition,” and “Unit/Process Operating Characteristics,” the EPA determined in the 2011 Final CBI Rule that the data elements assigned to those categories are not emission data but did not make categorical CBI determinations; instead the EPA made CBI determinations for individual data elements assigned to these two data categories. In subsequent amendments to Part 98,
Please see the memorandum titled “Proposed data category assignments and confidentiality determinations for new and substantially revised data elements in the proposed `2013 Revisions to the Greenhouse Gas Reporting Rule and Confidentiality Determinations for New or Substantially Revised Data Elements' ” (“Confidentiality Determinations Memorandum”) in Docket EPA–HQ–OAR–2012–0934 for a list of the proposed new or substantially revised data elements, their proposed category assignments, and their proposed confidentiality determinations (whether categorical or individual) except for those assigned to the inputs to equations category. Section IV.C of this preamble discusses the proposed CBI determinations and supporting rationale for individual data elements.
The EPA is proposing individual CBI determinations for 16 data elements assigned to the “Unit/Process `Static' Characteristics that Are Not Inputs to Emission Equations”, “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. (There are no new data elements proposed to be assigned to the “GHGs Reported” supplier data category.) These data elements consist of three new data elements in the direct emitter subpart FF and eight in the supplier subpart UU. We are also proposing individual CBI determinations for five substantially revised data elements in the subparts Z, NN, TT, and QQ. Table 9 of this preamble provides the category assignment and proposed rationale for the proposed determinations.
As discussed in Section IV.C of this preamble, the EPA is proposing category assignment for the new and substantially revised data elements. As shown in the Confidentiality Determinations Memorandum (see Docket Id. No. EPA–HQ–OAR–2012–0934), the EPA is proposing to assign 13 new data elements to the “inputs to emission equations category”: Two in subpart FF, five in subpart HH, and six in subpart TT. The EPA had previously deferred the reporting deadlines for inputs to emissions equations until March 2013 for some data elements and March 2015 for others to allow EPA sufficient time to conduct an “in-depth evaluation of the potential impact from the release of inputs to equations” (76 FR 53057 and 53060, August 25, 2011); (77 FR 48072, August 13, 2012). We are not proposing to defer the reporting of these 13 data elements. The EPA has conducted an evaluation of these inputs following the process outline in the memorandum “Process for Evaluating and Potentially Amending Part 98 Inputs to Emission Equations” (Docket ID EPA–HQ–OAR–2010–0929), which accompanied the Final Deferral Rule (76 FR 53057). This evaluation is summarized in the memorandum “Summary of Evaluation of `Inputs to Emission Equations' Data Elements Proposed to be Added with the 2013 Revisions to the Greenhouse Gas Reporting Rule.” (See Docket ID No. EPA–HQ–OAR–2012–0934.) Because the EPA has completed the above mentioned evaluation for these 13 data elements, EPA does not see a need to defer their reporting. Accordingly, under this proposed amendment, these data elements would be reported in 2014 along with the rest of the proposed changes.
For the CBI component of this rulemaking, we are soliciting comment on the following specific issues. First, we specifically seek comment on the proposed data category assignment for each of the new or substantially revised data elements in the proposed amendments to subparts A, H, K, X, Y, Z, AA, FF, HH, NN, QQ, RR, TT, and UU.
If you believe that the EPA has improperly assigned certain new or substantially revised 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 new data elements may be mis-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 seek comment on the proposed confidentiality status of the new or substantially revised 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, in particular comments identifying data they consider sensitive and their rationales and supporting documentation; this opportunity 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
When submitting comments regarding the confidentiality determinations we are proposing in this action, please identify each individual proposed new or revised 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 and 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 in your comments and include all information necessary for the EPA to evaluate your comments.
This section of the preamble examines the costs and economic impacts of the proposed rulemaking and the estimated economic impacts of the rule on affected entities, including estimated impacts on small entities.
There are two primary reasons that Part 98 requires direct emitters and suppliers of GHGs to use the GWP values in Table A–1 to subpart A to calculate emissions (or supply) of GHGs in CO
For most GHGs whose GWPs we are proposing to amend, the proposed AR4 GWP values are greater than the GWP values in the current Table A–1. Therefore, the proposed amendments would likely result in higher reported emissions of CO
For the additional F–GHGs and associated GWPs we are proposing to include in Table A–1, we do not anticipate significant impacts for existing reporters. Per 40 CFR 98.3(c), facilities are required to report annual CO
Equation A–1 is also used to determine whether the rule applies to direct emitters and suppliers in certain source categories where the applicability of the GHG reporting rule is based on a threshold quantity of GHGs that is either generated, emitted, imported, or exported over a calendar year, expressed in CO
If finalized, the proposed amendments to Table A–1 would result in a collective increase in annual reported emissions from all subparts of more than 104 million metric tons CO
Additional reporters would be expected to report under subparts I, W, HH, II, OO, and TT due to an increase in the number of facilities exceeding the CO
The total cost of compliance for the additional expected reporters is $3.9 million for the first year and $1.2 million per year for subsequent years. The annual costs for the additional reporters is an approximate increase of 1.2 percent above the current reporters
The EPA evaluated the number of reporters affected by the proposed amendments by examining the 2010 and 2011 reporters that are already affected under Part 98. For the number of affected facilities, the EPA examined available e-GGRT data from the 2010 reporting year and summary data that were developed to support the current Part 98 to determine the number of existing affected facilities. We then evaluated the number of additional facilities that could be required to report under each subpart by determining what additional facilities could exceed Part 98 source category thresholds. Affected subparts that might have additional reporters due to the proposed new or revised GWPs are those that meet all of the following criteria: (1) The subpart has a reporting threshold that is based on CO
In order to determine the number of additional reporters expected under these subparts, we used data from industry surveys and publicly available data sources to compile a list of facilities that could be affected in each subpart. Combined with source-specific data, we used these facility lists to estimate the change in facility emissions or supply using the proposed new and revised GWPs and to identify the additional facilities in each subpart that could meet a CO
The EPA determined the estimated increases in reported emissions for each subpart by examining the available data for 2010 and 2011 reporters. For existing facilities submitting an initial annual report for reporting year 2010, the increase in calculated emissions from each facility was estimated by adjusting the reported GHG mass emissions to CO
Additional information on the EPA's analysis of the estimated number of reporters and the increase in reported CO
The compliance costs associated with the proposed amendments were determined for those additional reporters who would be required to submit an annual report under Part 98 if the proposed amendments to Table A–1 were finalized. The total compliance costs for additional reporters are estimated to be $3.9 million for the first year and $1.2 million for subsequent years (2011 dollars).
Costs for additional reporters are summarized in Table 11 of this preamble, which presents the first-year and subsequent-year costs for each source category.
To estimate the cost impacts for additional reporters, the EPA used the methodologies from the subpart-specific regulatory impacts analyses from the original GHG reporting rule and updated the cost information to 2011 dollars. In general, we determined total reporting costs for each subpart by assigning model facility costs to individual affected facilities in each industry sector. Labor costs were determined for monitoring, recordkeeping, and reporting according to the rule requirements. Capital costs for monitoring equipment were also estimated for each model facility. The total cost for each subpart was determined by multiplying the model facility cost by the number of affected facilities.
For existing reporters that have submitted an annual report for reporting year 2010 or 2011, there would be no significant cost impacts resulting from the proposed amendments to Table A–1; using the proposed GWPs would not affect the cost of monitoring and recordkeeping and would not materially affect the cost for calculating emissions for these facilities. See the Impacts Analysis (Docket ID No. EPA–HQ–OAR–2012–0934) for more details.
The proposed corrections also include clarifications to terms and definitions for certain emission equations, simplifications to calculation methods and data reporting requirements, or corrections for consistency between provisions within a subpart or between subparts in Part 98. In general, these clarifications and corrections do not fundamentally affect the applicability, monitoring requirements, or data collected and reported or increase the recordkeeping and reporting burden associated with Part 98. Although we have added a few new reporting provisions to select source categories, the data we are proposing to collect is expected to be readily available to reporters; in most cases, it would already have been recorded and would not require additional monitoring or monitoring equipment for existing reporters. Additionally, the proposed confidentiality determinations for new or revised data elements would not affect whether and how data are reported and therefore, would not impose any additional burden on sources. See the EPA's full analysis of the additional impacts of the corrections, clarifying, and other amendments in the Impacts Analysis in Docket ID No. EPA–HQ–OAR–2012–0934).
This action is not a “significant regulatory action” under the terms of Executive Order 12866 (58 FR 51735, October 4, 1993) and is therefore not subject to review under Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011). This action (1) proposes to clarify or change specific provisions in the Greenhouse Gas Reporting Rule, including amending Table A–1 of Subpart A to incorporate new and revised GWPs, and (2) proposes confidentiality determinations for the reporting of new or substantially revised (i.e., requiring additional or different data to be reported) data elements contained in the proposed amendments. The EPA prepared an analysis of the potential compliance costs associated with the proposed amendments and amendments to revise global warming potentials in subpart A. This analysis is contained in the Impacts Analysis (see Docket ID No. EPA–HQ–OAR–2012–0934). A copy of the analysis is available in the docket for this action and the analysis is briefly summarized here. The total compliance costs for additional reporters are $1,195,000 ($2011). The highest costs are anticipated for 99 facilities affected by subpart W, Petroleum and Natural Gas Systems, ($860,000), and 57 facilities affected by subpart HH, Municipal Solid Waste Landfills ($137,500). New facilities required to report under subparts I, II, OO, and TT would incur a combined cost of $197,000. The proposed confidentiality determinations for new and substantially revised data elements do not increase the existing compliance costs. The compliance costs associated with the proposed amendments are less than the significance threshold of $100 million per year. The compliance costs for individual facilities are not expected to impose a significant economic burden.
This action does not impose any new information collection burden. This action proposes amended GWP values in subpart A and other corrections and harmonizing revisions, and proposes confidentiality determinations for the reporting of new or substantially revised (i.e., requiring additional or different data to be reported) data elements contained in the proposed amendments. These proposed amendments and confidentiality determinations do not make any substantive changes to the reporting requirements in any of the subparts for which amendments are being proposed. The proposed amendments to subpart A include revision of GWPs in Table A–1 of subpart A. As discussed in Section V of this preamble, the proposed amendments could affect the total number of facilities reporting under Part 98 and increase the collective annual emissions or supply reported. The EPA prepared an analysis of the potential compliance costs associated with the proposed amendments to Table A–1 in the Impacts Analysis (see Docket ID No. EPA–HQ–OAR–2012–0934).
Other proposed amendments to subpart A include adding requirements that provide reporters instruction regarding reporting of location, ownership, and facility identification (i.e., reporting of ORIS codes). The remaining proposed changes also include revising and adding definitions. The proposed revisions are clarifications or require reporting of information that facilities are expected to have readily available (e.g., latitude and longitude of the facility, ORIS code for each power generating unit), and are not expected to result in significant burden for reporters.
The proposed amendments to the reporting requirements in the source category-specific subparts generally do not change the nature of the data reported and are not anticipated to result in significant burden for reporters. For example, several of the proposed amendments are clarifications or corrections to existing reporting requirements. For example, for subpart H, the EPA is proposing to require reporting of annual, facility-wide cement production instead of monthly, kiln-specific cement production for facilities that use a CEMS to measure CO
The EPA is also proposing changes that would reduce the reporting burden. For example, for subpart BB (Silicon Carbide Production), the EPA is proposing to remove the requirement for facilities to report CH
Additional changes to the reporting requirements in each subpart are detailed in the Impacts Analysis (see Docket ID No. EPA–HQ–OAR–2012–0934). The Office of Management and Budget (OMB) has previously approved the information collection requirements for 40 CFR part 98 under the provisions of the
The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions.
For purposes of assessing the impacts of this proposed rule on small entities, small entity is defined as: (1) A small business as defined by the Small Business Administration's regulations at 13 CFR 121.201; (2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) a small organization that is any not-for-profit enterprise which is independently owned and operated and is not dominant in its field.
After considering the economic impacts of today's proposed rule on small entities, I certify that this action will not have a significant economic impact on a substantial number of small entities. The small entities directly regulated by this proposed rule are small businesses. We have determined that up to 37 small municipal solid waste landfills, representing up to a .03% increase in regulated businesses in this industry, will experience an impact of .02 to .60% of revenues; up to 3 suppliers of industrial GHGs, representing up to a .02% increase in regulated businesses in this industry, will experience an impact of .02 to .14% of revenues; and that up to 19 industrial waste landfills (primarily co-located with food processing facilities), representing up to a .19% increase in regulated businesses in this industry, will experience an impact of .01 to .48% of revenues.
Although this proposed rule will not have a significant economic impact on a substantial number of small entities, the EPA nonetheless has tried to reduce the impact of this rule on small entities. For example, the EPA conducted several meetings with industry associations to discuss regulatory options and the corresponding burden on industry, such as recordkeeping and reporting. The EPA continues to conduct significant outreach on the mandatory GHG reporting rule 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.
The proposed rule amendments and confidentiality determinations do not contain a federal mandate that may result in expenditures of $100 million or more for state, local, and tribal governments, in the aggregate, or the private sector in any one year. Thus, the proposed rule amendments and confidentiality determinations are not subject to the requirements of section 202 and 205 of the UMRA.
This rule is also not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments. The proposed rule amends specific provisions in subpart A, General Provisions, to reflect global warming potentials that have been published by the IPCC and to propose global warming potentials for certain fluorinated greenhouse gases. Also in this action, the EPA is revising specific provisions to provide clarity on what is to be reported. In some cases, the EPA has increased flexibility in the selection of methods used for calculating and monitoring GHGs. Therefore, this action is not subject to the requirements of section 203 of the UMRA.
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, as specified in Executive Order 13132.
These proposed amendments and confidentiality determinations apply directly to facilities that directly emit greenhouses gases or that are suppliers of greenhouse gases. They do not apply to governmental entities unless the government entity owns a facility that directly emits greenhouse gases above threshold levels (such as a landfill or large combustion device), so relatively few government facilities would be affected. Moreover, for government facilities that are subject to the rule, the proposed revisions will not have a significant cost impact. This regulation also does not limit the power of States or localities to collect GHG data and/or regulate GHG emissions. Thus, Executive Order 13132 does not apply to this action.
In the spirit of Executive Order 13132, and consistent with EPA policy to promote communications between the EPA and state and local governments, we specifically solicit comment on this proposed action from state and local officials.
This action does not have tribal implications, as specified in Executive Order 13175 (65 FR 67249, November 9, 2000). The proposed amendments and confidentiality determinations apply directly to facilities that directly emit greenhouses gases or that are suppliers of greenhouse gases. They would not have tribal implications unless the tribal entity owns a facility that directly emits greenhouse gases above threshold levels (such as a landfill or large combustion device). Relatively few tribal facilities would be affected. Thus, Executive Order 13175 does not apply to this action.
The EPA interprets Executive Order 13045 (62 FR 19885, April 23, 1997) as applying only to those regulatory actions that concern health or safety risks, such that the analysis required under section 5–501 of the Executive Order has the potential to influence the regulation. This action is not subject to Executive Order 13045 because it does not establish an environmental standard intended to mitigate health or safety risks.
This action is not subject to Executive Order 13211 (66 FR 28355 (May 22, 2001)), because it is not a significant regulatory action under Executive Order 12866.
Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (NTTAA), Public Law 104–113 (15 U.S.C. 272 note) 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. Voluntary consensus standards are technical standards (e.g., materials specifications, test methods, sampling procedures, and
This proposed rulemaking does not involve the use of any new technical standards, but allows for greater flexibility for reporters to use consensus standards where they are available. Therefore, the EPA is not considering the use of specific voluntary consensus standards.
Executive Order 12898 (59 FR 7629, (February 16, 1994) establishes Federal executive policy on environmental justice. Its main provision directs Federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in the United States.
The EPA has determined that this proposed rule will not have disproportionately high and adverse human health or environmental effects on minority or low-income 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, Suppliers, Reporting and recordkeeping requirements.
For the reasons stated in the preamble, title 40, chapter I, of the Code of Federal Regulations is proposed to be amended as follows:
42 U.S.C. 7401,
(c) * * *
(1) Facility name or supplier name (as appropriate), and physical street address of the facility or supplier, including the city, State, and zip code. If the facility does not have a physical street address, then the facility must provide the latitude and longitude representing the location of facility operations in decimal degree format. This must be provided in a comma-delimited “latitude, longitude” coordinate pair reported in decimal degrees to at least four digits to the right of the decimal.
(11) * * *
(viii) The facility or supplier must refer to the reporting instructions of the electronic GHG reporting tool regarding standardized conventions for the naming of a parent company.
(13) ORIS code for each power generation unit that has been assigned an ORIS code by the Energy Information Administration.
(h) * * *
(4) Notwithstanding paragraphs (h)(1) and (h)(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 (h)(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 at least 5 business days 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 (h)(2) within 75 days. The Administrator will approve the extension request if the request demonstrates that it is not practicable to collect and process the data needed to resolve potential reporting errors identified pursuant to paragraphs (h)(1) or (h)(2) of this section within 75 days.
(j) * * *
(3) * * *
(ii) Any subsequent extensions to the original request must be submitted to the Administrator within 4 weeks of the owner or operator identifying the need to extend the request, but in any event no later than 4 weeks before the date for the planned process equipment or unit shutdown that was provided in the original or most recently approved request.
(k)
(2)
(l)
(1)
(i) Monitoring methods currently used by the facility that do not meet the specifications of a relevant subpart.
(ii) Supplier data.
(iii) Engineering calculations.
(iv) Other company records.
(2)
(i)
(ii)
(A) A list of specific items of monitoring instrumentation for which the request is being made and the locations where each piece of monitoring instrumentation will be installed.
(B) Identification of the specific rule requirements (by rule subpart, section, and paragraph numbers) for which the instrumentation is needed.
(C) A description of the reasons that the needed equipment could not be obtained and installed before April 1, 2014.
(D) If the reason for the extension is that the equipment cannot be purchased and delivered by April 1, 2014, supporting documentation such as the date the monitoring equipment was ordered, investigation of alternative suppliers and the dates by which alternative vendors promised delivery, backorder notices or unexpected delays, descriptions of actions taken to expedite delivery, and the current expected date of delivery.
(E) If the reason for the extension is that the equipment cannot be installed without a process unit shutdown, include supporting documentation demonstrating that it is not practicable to isolate the equipment and install the monitoring instrument without a full process unit shutdown. Include the date of the most recent process unit shutdown, the frequency of shutdowns for this process unit, and the date of the next planned shutdown during which the monitoring equipment can be installed. If there has been a shutdown or if there is a planned process unit shutdown between April 2, 2013 and April 1, 2014, include a justification of why the equipment could not be obtained and installed during that shutdown.
(F) A description of the specific actions the facility will take to obtain and install the equipment as soon as reasonably feasible and the expected date by which the equipment will be installed and operating.
(iii)
(b) * * *
(1) * * *
(viii) May be used for the combustion of a fuel listed in Table C–1 if the fuel is combusted in a unit with a maximum rated heat input capacity greater than 250 mmBtu/hr (or, pursuant to § 98.36(c)(3), in a group of units served by a common supply pipe, having at least one unit with a maximum rated heat input capacity greater than 250
(A) The use of Tier 4 is not required.
(B) The fuel provides less than 10 percent of the annual heat input to the unit, or if § 98.36(c)(3) applies, to the group of units served by a common supply pipe.
(ix) May not be used for the combustion of waste coal (i.e., waste anthracite (culm) and waste bituminous (gob)).
(3) * * *
(ii) * * *
(A) The use of Tier 1 or 2 is permitted, as described in paragraphs (b)(1)(iii), (b)(1)(v), (b)(1)(viii), and (b)(2)(ii) of this section.
(e) * * *
(1) * * *
(ii) The procedures in paragraph (e)(4) of this section.
(3) * * *
(iv) * * *
(B) Multiply the result from paragraph (e)(3)(iv)(A) of this section by the appropriate default factor to determine the annual biogenic CO
(b) * * *
(3) Maximum rated heat input capacity of the unit, in mmBtu/hr.
(c) * * *
(3) * * * As a second example, in accordance with § 98.33(b)(1)(v), Tier 1 may be used regardless of unit size when natural gas is transported through the common pipe, if the annual fuel consumption is obtained from gas billing records in units of therms or mmBtu.* * *
(b) * * *
(3) You must measure the adipic acid production rate during the test and calculate the production rate for the test period in tons per hour.
(d) If the adipic acid production unit exhausts to any N
(e) If the adipic acid production unit exhausts to any N
(g) * * *
(1) * * *
(2) * * *
(3) * * *
(e) You must determine the monthly amount of adipic acid produced. You must also determine the monthly amount of adipic acid produced during which N
(f) You must determine the annual amount of adipic acid produced. You must also determine the annual amount of adipic acid produced during which N
(b) * * *
(4) You must calculate the annual process CO
(5) * * *
(b) For missing feedstock supply rates used to determine monthly feedstock consumption or monthly waste recycle stream quantity, you must determine the best available estimate(s) of the parameter(s), based on all available process data.
(a) If a CEMS is used to measure CO
(b) If a CEMS is not used to measure emissions, then you must report all of the following information in this paragraph (b):
(13) Annual CO
(a) * * *
(2) Annual facility cement production.
(d) * * *
(1) * * *
(e) * * *
(2) Annual process CH
(j)
(1)
(3) * * *
(i) If you choose to use a default GWP rather than your best estimate of the GWP for fluorinated GHGs whose GWPs are not listed in Table A–1 of Subpart A of this part, use a default GWP of 10,000 for fluorinated GHGs that are fully fluorinated GHGs and use a default GWP of 2000 for other fluorinated GHGs.
You must calculate and report the annual process CO
(b) For each continuous glass melting furnace that is not subject to the requirements in paragraph (a) of this section, calculate and report the process and combustion CO
(2) * * *
(iv) * * *
(b) 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,
(b) * * *
(4) Carbonate-based mineral decimal mass fraction for each carbonate-based raw material charged to a continuous glass melting furnace.
(6) The decimal fraction of calcination achieved for each carbonate-based raw material, if a value other than 1.0 is used to calculate process mass emissions of CO
(7) Method used to determine decimal fraction of calcination.
(b) * * *
(5) The decimal fraction of calcination achieved for each carbonate-based raw material, if a value other than 1.0 is used to calculate process mass emissions of CO
(c) For HCFC–22 production facilities that do not use a destruction device or that have a destruction device that is not directly connected to the HCFC–22 production equipment, HFC–23 emissions shall be estimated using Equation O–4 of this section:
(d) For HCFC–22 production facilities that use a destruction device connected to the HCFC–22 production equipment, HFC–23 emissions shall be estimated using Equation O–5 of this section:
(j) The number of sources of equipment type t with screening values less than 10,000 ppmv shall be the difference between the number of leak sources of equipment type t that could emit HFC–23 and the number of sources of equipment type t with screening values greater than or equal to 10,000 ppmv as determined under paragraph (i) of this section.
(c) Each HFC–23 destruction facility shall report the concentration (mass fraction) of HFC–23 measured at the outlet of the destruction device during the facility's annual HFC–23 concentration measurements at the outlet of the device. If the concentration of HFC–23 is below the detection limit of the measuring device, report the detection limit and that the concentration is below the detection limit.
(b)
(1) * * *
(2) * * *
(3) * * *
(b) * * *
(3) Determine the carbon content of fuel oil, naphtha, and other liquid fuels and feedstocks at least monthly, except annually for standard liquid hydrocarbon fuels and feedstocks having consistent composition, or upon delivery for liquid fuels and feedstocks delivered by bulk transport (
(4) Determine the carbon content of coal, coke, and other solid fuels and feedstocks at least monthly, except annually for standard solid hydrocarbon fuels and feedstocks having consistent composition, or upon delivery for solid fuels and feedstocks delivered by bulk transport (
(5) You must use the following applicable methods to determine the carbon content for all fuels and feedstocks, and molecular weight of gaseous fuels and feedstocks. Alternatively, you may use the results of chromatographic analysis of the fuel and feedstock, provided that the chromatograph is operated, maintained, and calibrated according to the manufacturer's instructions; and the methods used for operation, maintenance, and calibration of the chromatograph are documented in the written monitoring plan for the unit under § 98.3(g)(5).
(a) * * *
(2) Annual quantity of hydrogen produced (metric tons) for each process unit.
(3) Annual quantity of ammonia produced (metric tons), if applicable, for each process unit.
(c) For units using the calculation methodologies described 98.163(b), the records required under § 98.3(g) must include both the company records and a detailed explanation of how company records are used to estimate the following:
(1) Fuel and feedstock consumption, when solid fuel and feedstock is combusted and a CEMS is not used to measure GHG emissions.
(2) Fossil fuel consumption, when, pursuant to § 98.33(e), the owner or operator of a unit that uses CEMS to quantify CO
(3) Sorbent usage, if the methodology in § 98.33(d) is used to calculate CO
(d) The owner or operator must document the procedures used to ensure the accuracy of the estimates of fuel and feedstock usage and sorbent usage (as applicable) in § 98.163(b), including, but not limited to, calibration of weighing equipment, fuel and feedstock flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided.
The iron and steel production source category includes facilities with any of the following processes: taconite iron ore processing, integrated iron and steel manufacturing, cokemaking not colocated with an integrated iron and steel manufacturing process, direct reduction furnaces not collocated with an integrated iron and steel manufacturing process, and electric arc furnace (EAF) steelmaking not colocated with an integrated iron and steel manufacturing process. * * *
(b) * * *
(1) * * *
(i) * * *
(ii) * * *
(iii) * * *
(iv) * * *
(v) For EAFs, estimate CO
(vi) * * *
(vii) * * *
(c) You must determine emissions of CO
(d) If GHG emissions from a taconite indurating furnace, basic oxygen furnace, non-recovery coke oven battery, sinter process, EAF, decarburization vessel, or direct reduction furnace are vented through a stack equipped with a CEMS that complies with the Tier 4 methodology in subpart C of this part, or through the same stack as any combustion unit or process equipment that reports CO
(b) * * *
(1) * * * Determine the mass rate of fuels using the procedures for combustion units in § 98.34. No determination of the mass of steel output from decarburization vessels is required.
(c) * * *
(2)(i) For the exhaust from basic oxygen furnaces, EAFs, decarburization vessels, and direct reduction furnaces, sample the furnace exhaust for at least three complete production cycles that start when the furnace is being charged and end after steel or iron and slag have been tapped. For EAFs that produce both carbon steel and stainless or specialty (low carbon) steel, develop an emission factor for the production of both types of steel.
(ii) For the exhaust from continuously charged EAFs, sample the exhaust for a period spanning at least three hours. For EAFs that produce both carbon steel and stainless or specialty (low carbon) steel, develop an emission factor for the production of both types of steel.
(a) Except as provided in § 98.174(b)(4), 100 percent data availability is required for the carbon content of inputs and outputs for facilities that estimate emissions using the carbon mass balance procedure in § 98.173(b)(1) or facilities that estimate emissions using the site-specific emission factor procedure in § 98.173(b)(2).
(e) If you use the carbon mass balance method in § 98.173(b)(1) to determine CO
(b) When the carbon mass balance method is used to estimate emissions for a process, the monthly mass of each process input and output that are used to determine the annual mass, except that no determination of the mass of steel output from decarburization vessels is required.
(a) Lime manufacturing plants (LMPs) engage in the manufacture of a lime product by calcination of limestone, dolomite, shells or other calcareous substances as defined in 40 CFR 63.7081(a)(1).
(a) If all lime kilns meet the conditions specified in § 98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report under this subpart the combined process and combustion CO
(b) * * *
(1) Calculate and report under this subpart the combined process and combustion CO
(2) Calculate and report process and combustion CO
(ii) You must calculate a monthly emission factor for each type of calcined byproduct or waste sold (including lime kiln dust) using Equation S–2 of this section:
(iii) You must calculate the annual CO
(iv) You must calculate annual CO
(a) You must determine the total quantity of each type of lime product that is produced and each calcined byproduct or waste (such as lime kiln dust) that is sold. The quantities of each should be directly measured monthly with the same plant instruments used for accounting purposes, including but not limited to, calibrated weigh feeders, rail or truck scales, and barge measurements. The direct measurements of each lime product shall be reconciled annually with the difference in the beginning of and end of year inventories for these products, when measurements represent lime sold.
(b) You must determine the annual quantity of each calcined byproduct or waste generated that is not sold by either direct measurement using the same instruments identified in paragraph (a) of this section or by using a calcined byproduct or waste generation rate.
(c) You must determine the chemical composition (percent total CaO and percent total MgO) of each type of lime product that is produced and each type of calcined byproduct or waste sold according to paragraph (c)(1) or (2) of this section. You must determine the chemical composition of each type of lime product that is produced and each type of calcined byproduct or waste sold on a monthly basis. You must determine the chemical composition for each type of calcined byproduct or waste that is not sold on an annual basis.
(a) For each missing value of the quantity of lime produced (by lime type), and quantity of calcined byproduct or waste produced and sold, the substitute data value shall be the best available estimate based on all available process data or data used for accounting purposes.
(a) * * *
(1) Method used to determine the quantity of lime that is produced and quantity of lime that is sold.
(2) Method used to determine the quantity of calcined lime byproduct or waste sold.
(4) Beginning and end of year inventories for calcined lime byproducts or wastes sold, by type.
(5) Annual amount of calcined lime byproduct or waste sold, by type (tons).
(7) Annual amount of calcined lime byproduct or waste that is not sold, by type (tons).
(b) * * *
(1) Annual CO
(2) Monthly emission factors (metric ton CO
(3) Monthly emission factors for each calcined byproduct or waste by lime type that is sold.
(4) Standard method used (ASTM or NLA testing method) to determine chemical compositions of each lime type produced and each calcined lime byproduct or waste type.
(5) Monthly results of chemical composition analysis of each type of lime product produced and calcined byproduct or waste sold.
(6) Annual results of chemical composition analysis of each type of lime byproduct or waste that is not sold.
(9) Method used to determine the quantity of calcined lime byproduct or waste sold.
(10) Monthly amount of calcined lime byproduct or waste sold, by type (tons).
(11) Annual amount of calcined lime byproduct or waste that is not sold, by type (tons).
(14) Beginning and end of year inventories for calcined lime byproducts or wastes sold.
(a) You must report N
(b) You must conduct an annual performance test for each nitric acid train according to paragraphs (b)(1) through (b)(3) of this section.
(1) You must conduct the performance test at the absorber tail gas vent, referred to as the test point, for each nitric acid train according to § 98.224(b) through (f). If multiple nitric acid trains exhaust to a common abatement technology and/or emission point, you must sample each process in the ducts before the emissions are combined, sample each process when only one process is operating, or sample the combined emissions when multiple processes are operating and base the site-specific emission factor on the combined production rate of the multiple nitric acid trains.
(3) You must measure the production rate during the performance test and
(d) If nitric acid train “t” exhausts to any N
(e) If nitric acid train “t” exhausts to any N
(g) * * *
(1) * * *
(2) If multiple N
(3) If multiple N
(4) * * *
(i) You must determine the total annual amount of nitric acid produced on each nitric acid train “t” (tons acid produced, 100 percent acid basis), according to § 98.224(f).
(c) You must determine the production rate(s) (100 percent acid basis) from each nitric acid train during the performance test according to paragraphs (c)(1) or (c)(2) of this section.
(e) You must determine the total monthly amount of nitric acid produced. You must also determine the monthly amount of nitric acid produced while N
(f) You must determine the annual amount of nitric acid produced. You must also determine the annual amount of nitric acid produced while N
(a) Nitric Acid train identification number.
(n) If you requested Administrator approval for an alternative method of determining N
(o) [Reserved]
(p) Fraction control factor for each abatement technology (percent of total emissions from the nitric acid train that are sent to the abatement technology) if Equation V–3c is used.
(b) * * *
(2) If you comply with § 98.243(c), report CO
(b)
(1) Determine CO
(2) For each stack (except flare stacks) that includes emissions from combustion of petrochemical process off-gas, calculate CH
(3) For each flare, calculate CO
(c) * * *
(3) Collect a sample of each feedstock and product at least once per month and determine the carbon content of each sample according to the procedures of § 98.244(b)(4). If multiple valid 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 carbon content in accordance with paragraphs (c)(4)(i) through (iii) of this section.
(i) Calculate the carbon content assuming 100 percent of that feedstock or product is the specific compound.
(ii) Maintain records of any determination made in accordance with this paragraph (c)(4) along with all supporting data, calculations, and other information.
(iii) Reevaluate determinations made under this paragraph (c)(4) after any process change that affects the feedstock or product composition. Keep records of the process change and the corresponding composition determinations. If the feedstock or product composition changes so that the average monthly concentration falls below 99.5 percent, you are no longer permitted to use this alternative method.
(5) * * *
(i) * * *
(d) * * *
(3) * * *
(i) For all gaseous fuels that contain ethylene process off-gas, use the emission factors for “Fuel Gas” in Table C–2 of subpart C of this part (General Stationary Fuel Combustion Sources).
(b) * * *
(4) * * * Analyses conducted in accordance with methods specified in paragraphs (b)(4)(i) through (b)(4)(xv) of this section may be performed by the owner or operator, by an independent laboratory, by the supplier of a feedstock, or by a product customer.
(xiii) The results of chromatographic analysis of a feedstock or product, provided that the chromatograph is operated, maintained, and calibrated according to the manufacturer's instructions.
(xiv) The results of mass spectrometer analysis of a feedstock or product, provided that the mass spectrometer is operated, maintained, and calibrated according to the manufacturer's instructions.
(xv) * * *
(A) An industry standard practice or a method published by a consensus-based standards organization if such a method exists for carbon black feedstock oils and carbon black products. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428–B2959, (800) 262–1373,
(c) If you comply with § 98.243(b) or (d), conduct monitoring and QA/QC for flares in accordance with § 98.254.
For missing feedstock and product flow rates, use the same procedures as for missing fuel usage as specified in § 98.35(b)(2). For missing feedstock and product carbon contents and missing molecular weights for gaseous feedstocks and products, use the same procedures as for missing carbon contents and missing molecular weights for fuels as specified in § 98.35(b)(1). For missing flare data, follow the procedures in § 98.255(b) and (c).
(a) * * *
(6) For each feedstock and product, provide the information specified in paragraphs (a)(6)(i) through (a)(6)(iii) of this section.
(i) Name of each method used to determine carbon content or molecular weight in accordance with 98.244(b)(4);
(ii) Description of each type of device (e.g., flow meter, weighing device) used to determine flow or mass in accordance 98.244(b)(1) through (3).
(iii) Identification of each method (i.e., method number, title, or other description) used to determine flow or mass in accordance with 98.244(b)(1) through (3).
(8) Identification of each combustion unit that burned both process off-gas and supplemental fuel, including combustion units that are not part of the petrochemical process unit.
(9) If you comply with the alternative to sampling and analysis specified in § 98.243(c)(4), the number of days during which off-specification product was produced, and if applicable, the date of any process change that reduced the composition to less than 99.5 percent.
(11) If you determine carbon content or composition of a feedstock or product using a method under § 98.244(b)(4)(xv)(B), report the information listed in paragraphs (a)(11)(i) through (a)(11)(iii) of this section. Include the information in paragraph (a)(11)(i) of this section in each annual report. Include the information in paragraphs (a)(11)(ii) and (a)(11)(iii) of this section only in the first applicable annual report, and provide any changes to this information in subsequent annual reports.
(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. Sections § 98.36(c)(2)(ii) and (c)(2)(ix) do 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), and § 98.36(e)(2)(vi).
(4) For each CEMS monitoring location that meets the conditions in paragraph (b)(2) or (3) of this section, provide an estimate based on engineering judgment of the fraction of the total CO
(5) For each CEMS monitoring location that meets the conditions in paragraph (b)(2) of this section, report the CH
(i) [Reserved]
(ii)[Reserved]
(iii) [Reserved]
(iv)[Reserved]
(6) [Reserved]
(c) * * *
(4) Name and annual quantity of each feedstock (metric tons).
48. Section 98.247 is amended by revising paragraphs (b) introductory text and (b)(2) to read as follows:
(b) If you comply with the mass balance methodology in § 98.243(c), then you must retain records of the information listed in paragraphs (b)(1) through (b)(4) of this section.
(2) Start and end times for time periods when off-specification product is produced, if you comply with the alternative methodology in § 98.243(c)(4) for determining carbon content of product.
(a) * * * (Use the default CH
(i) CO
(b) * * *
(2) * * *
(3) * * *
(f) * * *
(2) Flow measurement. If you have a continuous flow monitor on the sour gas feed to the sulfur recovery plant or the sour gas feed sent for off-site sulfur recovery, you must use the measured flow rates when the monitor is operational to calculate the sour gas flow rate. If you do not have a continuous flow monitor on the sour gas feed to the sulfur recovery plant or the sour gas feed sent for off-site sulfur recovery, you must use engineering calculations, company records, or similar estimates of volumetric sour gas flow.
(3) Carbon content. If you have a continuous gas composition monitor capable of measuring carbon content on the sour gas feed to the sulfur recovery plant or the sour gas feed sent for off-site for sulfur recovery, or if you monitor gas composition for carbon content on a routine basis, you must use the measured carbon content value. Alternatively, you may develop a site-specific carbon content factor using limited measurement data or engineering estimates or use the default factor of 0.20.
(4) Calculate the CO
(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
(k) For uncontrolled blowdown systems, you must calculate CH
(m) For storage tanks, except as provided in paragraph (m)(3) of this section, calculate CH
(f) * * *
(6) If you use a CEMS, the relevant information required under § 98.36 for the Tier 4 Calculation Methodology, the CO
(h) For on-site sulfur recovery plants and for emissions from sour gas sent off-site for sulfur recovery, the owner and operator shall report:
(2) For each on-site sulfur recovery plant, the maximum rated throughput (metric tons sulfur produced/stream day), a description of the type of sulfur recovery plant, and an indication of the method used to calculate CO
(3) The calculated CO
(4) If you use Equation Y–12 of this subpart, the annual volumetric flow to the on-site and off-site sulfur recovery plant (in scf/year), the molar volume conversion factor (in scf/kg-mole), and the annual average mole fraction of carbon in the sour gas (in kg-mole C/kg-mole gas).
(5) If you recycle tail gas to the front of an on-site sulfur recovery plant, indicate whether the recycled flow rate and carbon content are included in the measured data under § 98.253(f)(2) and (3). Indicate whether a correction for CO
(6) If you use a CEMS, the relevant information required under § 98.36 for the Tier 4 Calculation Methodology, the CO
(j) * * *
(10) If you use Equation Y–19 of this subpart, the relevant information required under paragraph (l)(5) of this section.
(k) * * *
(4) For each set of coking drums that are the same dimensions: The number of coking drums in the set, the height and diameter of the coke drums (in feet), the cumulative number of vessel openings for all delayed coking drums in the set, the typical venting pressure (in psig), void fraction (in cf gas/cf of vessel), and the mole fraction of methane in coking gas (in kg-mole CH
(6) If you use Equation Y–19 of this subpart, the relevant information required under paragraph (l)(5) of this section for each set of coke drums or vessels of the same size.
(o) * * *
(4) * * *
(vi) If you did not use Equation Y–23, the tank-specific methane composition data and the annual gas generation volume (scf/yr) used to estimate the cumulative CH
(5) [Reserved]
(6) [Reserved]
(7) [Reserved]
(b) * * *
(1) * * *
(ii) If your process measurement provides the CO
(a) You must obtain a monthly grab sample of phosphate rock directly from the rock being fed to the process line before it enters the mill using one of the following methods. You may conduct the representative bulk sampling using a method published by a consensus standards organization, or you may use industry consensus standard practice methods, including but not limited to the Phosphate Mining States Methods Used and Adopted by the Association of Fertilizer and Phosphate Chemists (AFPC). If phosphate rock is obtained from more than one origin in a month, you must obtain a sample from each origin of rock or obtain a composite representative sample.
(b) You must determine the carbon dioxide or inorganic carbon content of each monthly grab sample of phosphate rock (consumed in the production of phosphoric acid). You may use a method published by a consensus standards organization, or you may use industry consensus standard practice methods, including but not limited to the Phosphate Mining States Methods Used and Adopted by AFPC.
A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter must be used in the calculations as specified in paragraphs (a) and (b) of this section.
(a) For each missing value of the inorganic carbon content or CO
(a) Annual phosphoric acid production, by origin of the phosphate rock (tons).
(b) Annual phosphoric acid production capacity (tons).
(d) Annual phosphate rock consumption from monthly measurement records by origin (tons).
(f) * * *
(5) Monthly inorganic carbon content of phosphate rock for each wet-process phosphoric acid process line for which Equation Z–1a is used (percent by weight, expressed as a decimal fraction), or CO
(6) Monthly mass of phosphate rock consumed, by origin, in production for each wet-process phosphoric acid process line (tons).
(8) Number of times missing data procedures were used to estimate phosphate rock consumption (months), inorganic carbon contents of the phosphate rock (months), and CO
(a) Monthly mass of phosphate rock consumed by origin (tons).
(c) Documentation of the procedures used to ensure the accuracy of monthly phosphate rock consumption by origin.
(a) * * *
(3) Calculate biogenic CO
(e) The default emission factor for CO
(k) Annual production of pulp and/or paper products produced (metric tons) as follows:
(1) Report the total annual production of unbleached virgin pulp produced
(i) Do not include secondary fiber repulped for paper production in the virgin pulp production total.
(ii) You must report a positive (non-zero) value for pulp production unless your pulp mill did not operate during the reporting year.
(2) Report the total annual production of paper products exiting the paper machine(s), prior to application of any off-machine coatings, in air-dried metric tons per year. If you operate multiple paper machines, report the sum (total) of the air-dried metric tons of paper produced during the reporting year for all paper machines at the mill.
(a) CO
You must calculate and report the combined annual process CO
(a) Calculate and report under this subpart the combined annual process CO
(b) Calculate and report under this subpart the combined annual process CO
(2) Calculate annual CO
(b) If a CEMS is not used to measure process CO
(c) * * *
(1) Ensure that cylinders returned to the gas supplier are consistently weighed on a scale that is certified to be accurate and precise to within 2 pounds of true weight and is periodically recalibrated per the manufacturer's specifications. Either measure residual gas (the amount of gas remaining in returned cylinders) or have the gas supplier measure it. If the gas supplier weighs the residual gas, obtain from the gas supplier a detailed monthly accounting, within ± 2 pounds, of
(2) Ensure that cylinders weighed for the beginning and end of year inventory measurements are weighed on a scale that is certified to be accurate and precise to within 2 pounds of true weight and is periodically recalibrated per the manufacturer's specifications. All scales used to measure quantities that are to be reported under § 98.306 must be calibrated using calibration procedures specified by the scale manufacturer. Calibration must be performed prior to the first reporting year. After the initial calibration, recalibration must be performed at the minimum frequency specified by the manufacturer.
(b) * * *
(1) Each ventilation system shaft or vent hole, including both those points where mine ventilation air is emitted and those where it is sold, used onsite, or otherwise destroyed (including by ventilation air methane (VAM) oxidizers).
(2) Each degasification system well or gob gas vent hole, including degasification systems deployed before, during, or after mining operations are conducted in a mine area. This includes both those wells and vent holes where coal bed gas is emitted, and those where the gas is sold, used onsite, or otherwise destroyed (including by flaring).
(b) You must report CH
(d) You must report under this subpart the CO
(a) * * *
(2) Values of V, C, T, P, and (f
(b) * * *
(1) Values for V, C, T, P, and (f
(2) * * *
(c) If gas from a degasification system or ventilation system is sold, used onsite, or otherwise destroyed (including by flaring or VAM oxidation), you must calculate the quarterly CH
(1) * * *
(b) For CH
(c) * * *
(2) Collect weekly (once each calendar week, with at least three days between measurements) or more frequent samples, for all degasification wells and gob gas vent holes. Determine weekly or more frequent flow rates, methane concentration, temperature, and pressure from these degasification wells and gob gas vent holes. Methane composition should be determined either by submitting samples to a lab for analysis, or from the use of methanometers at the degasification monitoring site. Follow the sampling protocols for sampling of methane emissions from ventilation shafts, as described in § 98.324(b)(1). 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.
(d) * * *
(2) * * *
(iii) * * *
(a) Quarterly CH
(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.
(h) Weekly volumetric flow rate used to calculate CH
(i) Quarterly CH
(j) Weekly volumetric flow rate used to calculate CH
(o) Temperatures (°R), pressure (atm), moisture content, and the moisture correction factor (if applicable) used in Equation FF–1 and FF–3 of this subpart; and the gaseous organic concentration correction factor, if Equation FF–9 was required.
(r) Identification information and description for each well and shaft, including paragraphs (r)(1) through (r)(3) of this section:
(1) Indication of whether the well or shaft is monitored individually, or as part of a centralized monitoring point. Note which method (sampling or continuous monitoring) was used.
(2) Start date and close date of each well or shaft.
(3) Number of days the well or shaft was in operation during the reporting year.
(t) Quarterly CH
(u) Mine Safety and Health Administration (MSHA) identification for this coal mine.
(a) * * *
(1) * * *
(b) * * *
(1) * * *
(2) * * *
(i) Continuously monitor gas flow rate and determine the cumulative volume of landfill gas each month and the cumulative volume of landfill gas each year that is collected and routed to a destruction device (before any treatment equipment). Under this option, the gas flow meter is not required to automatically correct for temperature, pressure, or, if necessary, moisture content. If the gas flow meter is not equipped with automatic correction for temperature, pressure, or, if necessary, moisture content, you must determine these parameters as specified in paragraph (b)(2)(iii) of this section.
(ii) Determine the CH
(iii) * * *
(A) Determine the temperature and pressure in the landfill gas that is collected and routed to a destruction device (before any treatment equipment) in a location near or representative of the location of the gas flow meter at least once each calendar month; if only one measurement is made each calendar month, there must be at least fourteen days between measurements.
(B) If the CH
(c) * * *
(1) * * *
(3) * * *
(i) Calculate CH
(ii) Calculate CH
(e) For landfills electing to measure the fraction by volume of CH
(1) Use a gas composition monitor capable of measuring the concentration of CH
(2) Use Equation HH–10 of this section to correct the measured CH
(f) The owner or operator shall document the procedures used to ensure the accuracy of the estimates of disposal quantities and, if applicable, gas flow rate, gas composition, temperature, pressure, and moisture content measurements. These procedures include, but are not limited to, calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided.
(c) For missing daily waste disposal quantity data for disposal in the reporting year, the substitute value shall be the average daily waste disposal quantity for that day of the week as measured on the week before and week after the missing daily data.
(d) * * *
(1) Degradable organic carbon (DOC) and fraction of DOC dissimilated (DOC
(e) Fraction of CH
(h) For landfills without gas collection systems, the annual methane emissions (i.e., the methane generation, adjusted for oxidation, calculated using Equation HH–5 of this subpart), reported in metric tons CH
(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 an indication of whether a back-up destruction device is present at the landfill, the annual operating hours for the primary destruction device, the annual operating hours for the back-up destruction device (if present), and the destruction efficiency used (percent).
(8) Methane generation corrected for oxidation calculated using Equation HH–5 of this subpart, reported in metric tons CH
(10) Methane generation corrected for oxidation calculated using Equation HH–7 of this subpart, reported in metric tons CH
(11) Methane emissions calculated using Equation HH–6 of this subpart, reported in metric tons CH
(12) Methane emissions calculated using Equation HH–8 of this subpart, reported in metric tons CH
(d) * * *
(2) * * *
(a) * * *
(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(2) of this section.
(8) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(6) of this section.
(9) * * *
(v) The calculated CO
(11) * * *
(v) The calculated CO
(14) For each specific type of biomass that enters the coal-to-liquid facility to be co-processed with fossil fuel-based feedstock to produce a product reported in paragraph (a)(6) of this section, report the annual quantity in metric tons or barrels.
(15) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(14) of this section.
(18) Annual CO
(b) * * *
(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (b)(2) of this section.
(5) * * *
(v) The calculated CO
(6) * * *
(i) The density test results in metric tons per barrel.
(c) * * *
(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (c)(2) of this section.
(5) * * *
(v) The calculated CO
(d) * * *
(2) For a product that enters the facility to be further refined or otherwise used on site that is a blended feedstock, producers must meet the reporting requirements of paragraph (a)(2) of this section by reflecting the individual components of the blended feedstock.
(3) For a product that is produced, imported, or exported that is a blended product, producers, importers, and exporters must meet the reporting requirements of paragraphs (a)(6), (b)(2), and (c)(2) of this section, as applicable, by reflecting the individual components of the blended product.
(a) * * *
(1) * * *
(2) * * *
(h) * * *
(1) A reporter using Calculation Method 1 to determine the emission factor of a petroleum product shall calculate the CO
(2) A refinery using Calculation Method 1 of this subpart to determine the emission factor of a non-crude petroleum feedstock shall calculate the CO
(a) * * *
(1) The quantity of petroleum products, natural gas liquids, and biomass, shall be determined as follows:
(3) The annual quantity of crude oil received shall be determined according to one of the following methods. You may use an appropriate standard method published by a consensus-based standards organization or you may use an industry standard practice.
(b) * * *
(3) For units and processes that operate continuously with infrequent outages, it may not be possible to complete the calibration of a flow meter or other measurement device without disrupting normal process operation. In such cases, the owner or operator may postpone the calibration until the next scheduled maintenance outage. The best available information from company records may be used in the interim. Such postponements shall be documented in the monitoring plan that is required under § 98.3(g)(5).
(c) Procedures for Calculation Method 2 of this subpart.
(a)
(b)
(a) * * *
(1) [Reserved]
(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(2) of this section.
(5) [Reserved]
(8) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(6) of this section.
(9) For every feedstock reported in paragraph (a)(2) of this section for which Calculation Method 2 of this subpart was used to determine an emissions factor, report:
(iii) The carbon share test results in percent mass.
(v) The calculated CO
(10) For every non-solid feedstock reported in paragraph (a)(2) of this section for which Calculation Method 2 of this subpart was used to determine an emissions factor, report:
(11) For every petroleum product and natural gas liquid reported in paragraph (a)(6) of this section for which Calculation Method 2 of this subpart was used to determine an emissions factor, report:
(iii) The carbon share test results in percent mass.
(13) [Reserved]
(15) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(14) of this section.
(18) The CO
(20) For all crude oil that enters the refinery, report the annual quantity in barrels.
(21) The 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 (a)(2) of this section.
(22) Volume of crude oil in barrels that you injected into a crude oil supply or reservoir.
(b) In addition to the information required by § 98.3(c), each importer shall report all of the following information at the corporate level:
(1) [Reserved]
(2) For each petroleum product and natural gas liquid listed in Table MM–1 of this subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product.
(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (b)(2) of this section.
(5) For each product reported in paragraph (b)(2) of this section for which Calculation Method 2 of this subpart 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 of this subpart was used to determine an emissions factor, report:
(c) * * *
(1) [Reserved]
(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (c)(2) of this section.
(5) For each product reported in paragraph (c)(2) of this section for which Calculation Method 2 of this subpart 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 of this subpart used was used to determine an emissions factor, report:
(d) * * *
(2) For a product that enters the refinery to be further refined or otherwise used on site that is a blended non-crude feedstock, refiners must meet the reporting requirements of paragraphs (a)(2) of this section by reflecting the individual components of the blended non-crude feedstock.
(3) For a product that is produced, imported, or exported that is a blended product, refiners, importers, and exporters must meet the reporting requirements of paragraphs (a)(6), (b)(2), and (c)(2) of this section, as applicable, by reflecting the individual components of the blended product.
(b) Reporters shall maintain records to support quantities that are reported under this subpart, including records documenting any estimations of missing data and the number of calendar days in the reporting year for which substitute data procedures were followed. For all reported quantities of petroleum products, natural gas liquids, and biomass, reporters shall maintain metering, gauging, and other records normally maintained in the course of business to document product and feedstock flows including the date of initial calibration and the frequency of recalibration for the measurement equipment used.
(d) Reporters shall maintain laboratory reports, calculations and worksheets used in the measurement of density and carbon share for any petroleum product or natural gas liquid for which CO
(a) Natural gas liquids fractionators are installations that fractionate natural gas liquids (NGLs) into their constituent liquid products or mixtures of products (ethane, propane, normal butane, isobutane or pentanes plus) for supply to downstream facilities.
(b) Local Distribution Companies (LDCs) are companies that own or operate distribution pipelines, not interstate pipelines or intrastate pipelines, that physically deliver natural gas to end users and that are within a single state that are regulated as separate operating companies by State public utility commissions or that operate as independent municipally-owned distribution systems. LDCs do not include pipelines (both interstate and intrastate) delivering natural gas directly to major industrial users and farm taps upstream of the local distribution company inlet.
(a) * * *
(2) * * *
(b) * * *
(1) For natural gas that is received for redelivery to downstream gas transmission pipelines and other local distribution companies, use Equation NN–3 of this section and the default values for the CO
(2)(i) For natural gas delivered to end-users registering a supply equal to or greater than 460,000 Mscf per year, use Equation NN–4 of this section and the default values for the CO
(ii) * * *
(3) For the net change in natural gas stored on system by the LDC during the reporting year, use Equation NN–5a of this section. For natural gas that is received by means other than through the city gate, and is not otherwise accounted for by Equation NN–1 or NN–2 of this section, use Equation NN–5b of this section.
(i) For natural gas received by the LDC that is injected into on-system storage, and/or liquefied and stored, and for gas removed from storage and used for deliveries, use Equation NN–5a of this section and the default value for the CO
(ii) For natural gas received by the LDC that bypassed the city gate, use Equation NN–5b of this section. This includes natural gas received directly by LDC systems from producers or natural gas processing plants from local production, received as a liquid and vaporized for delivery, or received from any other source that bypassed the city gate. Use the default value for the CO
(4) Calculate the total CO
(c) * * *
(2) Calculate the total CO
(a) * * *
(5) For an LDC using Equation NN–1 or NN–2 of this subpart, the point(s) of measurement for the natural gas volume received shall be the LDC city gate meter(s).
(7) An LDC using Equation NN–4 of this subpart shall measure natural gas at the end-user's meter(s). Where an end-user is known to have more than one meter located at their facility, the reporter shall measure the natural gas at each meter and sum the annual volume delivered to all meters located at the end-user's facility to determine the total volume delivered to the end-user. Otherwise, the reporter shall consider the total annual volume delivered through each single meter at a single particular location to be the volume delivered to an individual end-user.
(8) An LDC using Equation NN–5a and/or NN–5b of this subpart shall measure natural gas as follows:
(ii) Fuel
(iii) Fuel
(9) An LDC shall measure all natural gas under the following standard industry temperature and pressure conditions: Cubic foot of gas at a temperature of 60 degrees Fahrenheit and at an absolute pressure of one atmosphere.
(c) * * *
(2) When a reporter used the default EF provided in this section to calculate Equation NN–2, NN–3, NN–4, NN–5a, NN–5b, or NN–7 of this subpart, the
(d) * * *
(1) Equipment used to measure quantities in Equations NN–1, NN–2, NN–5a and NN–5b of this subpart shall be calibrated prior to its first use for reporting under this subpart, using a suitable standard method published by a consensus based standards organization or according to the equipment manufacturer's directions.
(2) Equipment used to measure quantities in Equations NN–1, NN–2, NN–5a, and NN–5b of this subpart shall be recalibrated at the frequency specified by the standard method used or by the manufacturer's directions.
(3) Equipment used to measure quantities in Equations NN–3 and NN–4 of this subpart shall be recalibrated at the frequency commonly used within the industry.
(a) * * *
(4) Annual quantities (in barrels) of y-grade, o-grade, and other bulk NGLs:
(i) Received.
(ii) Supplied to downstream users that are not fractionated by the reporter.
(7) Annual CO
(b) * * *
(2) Annual volume in Mscf of natural gas placed into storage or liquefied and stored (Fuel
(3) Annual volume in Mscf of natural gas withdrawn from on-system storage and annual volume in Mscf of vaporized liquefied natural gas (LNG) withdrawn from storage for delivery on the distribution system (Fuel
(4) [Reserved]
(5) Annual volume in Mscf of natural gas that bypassed the city gate(s) and was supplied through the LDC distribution system. This includes natural gas from producers and natural gas processing plants from local production, or natural gas that was vaporized upon receipt and delivered, and any other source that bypassed the city gate (Fuel
(7) Annual volume in Mscf of natural gas delivered by the LDC to each end-user facility that received from the LDC deliveries equal to or greater than 460,000 Mscf during the calendar year, if known; otherwise, report the annual volume in Mscf of natural gas delivered by the LDC to each meter registering supply equal to or greater than 460,000 Mscf during the calendar year.
(9) Annual CO
(12) The customer name, address, and meter number of each end-user reported in paragraph (b)(7) of this section. Additionally, report whether the quantity of natural gas reported in paragraph (b)(7) of this section is the total quantity delivered to the end-user, or the quantity delivered to a specific meter.
In addition to the information required by § 98.3(g), the reporter shall retain the following records:
(a) * * *
(3) * * *
(i) For facilities with production process units or production wells that capture or extract a CO
(b) * * *
(4) * * *
(i) Quarterly density of the CO
(ii) Quarterly density of CO
(f) * * *
(10) Injection of CO
(11) Geologic sequestration of carbon dioxide that is covered by subpart RR of this part.
(a) * * *
(b) * * *
(b) The inputs to the annual submission must be reviewed against the import or export transaction records to ensure that the information submitted to EPA is being accurately transcribed as the correct chemical or blend in the correct pre-charged equipment or closed-cell foam in the correct quantities and units.
Removing and reserving paragraphs (a)(5), (a)(6)(iv), (b)(5), and (b)(6)(iv).
(a) * * *
(3) For closed-cell foams that are imported inside of equipment, the identity of the fluorinated GHG contained in the foam, the mass of the fluorinated GHG contained in the foam in each piece of equipment, and the number of pieces of equipment imported with each unique combination of mass and identity of fluorinated GHG within the closed-cell foams.
(4) For closed cell-foams that are not imported inside of equipment, the identity of the fluorinated GHG in the foam, the density of the fluorinated GHG in the foam (kg fluorinated GHG/cubic foot), and the volume of foam imported (cubic feet) for each type of closed-cell foam with a unique combination of fluorinated GHG density and identity.
(5) [Reserved]
(6) * * *
(ii) For closed-cell foams that are imported inside of equipment, the mass of the fluorinated GHGs in CO
(iii) For closed-cell foams that are not imported inside of equipment, the density in CO
(iv) [Reserved]
(b) * * *
(3) For closed-cell foams that are exported inside of equipment, the identity of the fluorinated GHG contained in the foam in each piece of equipment, the mass of the fluorinated GHG contained in the foam in each piece of equipment, and the number of pieces of equipment exported with each unique combination of mass and identity of fluorinated GHG within the closed-cell foams.
(4) For closed-cell foams that are not exported inside of equipment, the identity of the fluorinated GHG in the foam, the density of the fluorinated GHG in the foam (kg fluorinated GHG/cubic foot), and the volume of foam exported (cubic feet) for each type of closed-cell foam with a unique combination of fluorinated GHG density and identity.
(5) [Reserved]
(6) * * *
(ii) For closed-cell foams that are exported inside of equipment, the mass of the fluorinated GHGs in CO
(iii) For closed-cell foams that are not exported inside of equipment, the density in CO
(iv) [Reserved]
(a) * * *
(2) * * *
(d) * * *
(3) To aggregate production data, you must sum the mass of all of the CO
(f) * * *
(2) * * *
(b) * * *
(5) The standard or method used to calculate each value in paragraphs (b)(1), (b)(2), and (b)(3) of this section.
(d) Estimate the mass of SF
(h) If the mass of SF
(1) Determine the equipment's actual nameplate capacity, by measuring the nameplate capacities of a representative sample of each make and model and calculating the mean value for each make and model as specified at § 98.454(f).
(2) If equipment is shipped with a partial charge, calculate the partial shipping charge by multiplying the nameplate capacity of the equipment by the ratio of the densities of the partial charge to the full charge.
(i) * * *
(m) The values for EF
(o) If the mass of SF
(p) If the mass of SF
(c) * * *
(2) * * *
(xiii) Other waste material that has a DOC value of 0.3 weight percent (on a wet basis) or less. DOC value must be determined using a 60-day anaerobic biodegradation test procedure identified in § 98.464(b)(4)(i).
(a) * * *
(1) * * *
(2) * * *
(ii) * * *
(C) * * *
(b) * * *
(1) * * *
(b) For each waste stream placed in the landfill during the reporting year for which you choose to determine volatile solids concentration and/or a waste stream-specific DOC
(4) * * *
(i) * * *
(E) * * *
(c) For each waste stream that was historically managed in the landfill but was not received during the first reporting year for which you choose to determine volatile solids concentration and/or a waste stream-specific DOC
(1) If you can identify a similar waste stream to the waste stream that was historically managed in the landfill, you must determine the volatile solids concentration or DOC
(2) If you cannot identify a similar waste stream to the waste stream that was historically managed in the landfill, you may determine the volatile solids concentration or DOC
(b) * * *
(1) The number of waste steams (including “Other Industrial Solid Waste (not otherwise listed)” and “Inerts”) for which Equation TT–1 of this subpart is used to calculate modeled CH
(5) For each waste stream, the decay rate (k) value used in the calculations.
(c) Report the following historical waste information:
(1) [Reserved]
(2) For each waste stream identified in paragraph (b) of this section, the method(s) for estimating historical waste disposal quantities and the range of years for which each method applies.
(3) For each waste stream identified in paragraph (b) of this section for which Equation TT–2 of this subpart is used, provide:
(4) If Equation TT–4a of this subpart is used, provide:
(5) If Equation TT–4b of this subpart is used, provide:
(i) WIP (i.e., the quantity of waste in-place at the start of the reporting year from design drawings or engineering estimates (metric tons) or, for closed landfills for which waste in-place quantities are not available, the landfill's design capacity).
(ii) The cumulative quantity of waste placed in the landfill for the years for which disposal quantities are available from company record or from Equation TT–3 of this part.
(iii) YrLast.
(iv) YrOpen.
(v) NYrData.
(d) * * *
(3) For each waste stream, the degradable organic carbon (DOC
(h) For landfills with gas collection systems, in addition to the reporting requirements in paragraphs (a) through (f) of this section, provide:
(1) The annual methane generation, adjusted for oxidation, calculated using Equation TT–6 of this subpart, reported in metric tons CH
(2) The oxidation factor used in Equation TT–6 of this subpart; and
(3) All information required under 40 CFR 98.346(i)(1) through (i)(7) and 40 CFR 98.346(i)(9) through (i)(12).
In addition to the information required by § 98.3(g), you must retain the calibration records for all monitoring equipment, including the method or manufacturer's specification used for calibration, and all measurement data used for the purposes of paragraphs § 98.460(c)(2)(xii) or (c)(2)(xiii) or used to determine waste stream-specific DOC
(a) * * *
(2) * * *
(b) * * *
(2) * * *
(b) * * *
(5) The standard or method used to calculate each value in paragraphs (b)(1), (b)(2), and (b)(3) of this section.
(e) Report the following:
(1) Whether the facility received a Research and Development project exemption from reporting under 40 CFR part 98, subpart RR, for this reporting year. If you received an exemption, report the start and end dates of the exemption approved by EPA.
(2) Whether the facility includes a well or group of wells where a CO
(3) Whether the facility includes a well or group of wells where a CO
(4) Whether the facility includes a well or group of wells where a CO
(5) Whether the facility includes a well or group of wells where a CO
Commodity Futures Trading Commission.
Final order.
The Commodity Futures Trading Commission (“CFTC” or “Commission”) is issuing a final order (“Final Order”) in response to a consolidated petition (“Petition”)
A copy of the Petition is available on the Commission's Web site at
Robert B. Wasserman, Chief Counsel, 202–418–5092,
On July 21, 2010, President Obama signed the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”).
The Commission shall have exclusive jurisdiction, except to the extent otherwise provided in the Wall Street Transparency and Accountability Act of 2010 (including an amendment made by that Act) and subparagraphs (C), (D), and (I) of this paragraph and subsections (c) and (f), with respect to accounts, agreements (including any transaction which is of the character of * * * an “option”), and transactions involving swaps or contracts of sale of a commodity for future delivery (including significant price discovery contracts) traded or executed on a contract market * * * or a swap execution facility * * * or any other board of trade, exchange, or market * * *.
The Dodd-Frank Act also added a savings clause that addresses the roles of the Commission, FERC, and state agencies as they relate to certain agreements, contracts, or transactions traded pursuant to the tariff or rate schedule of an RTO or ISO.
(I)(i) Nothing in this Act shall limit or affect any statutory authority of the Federal Energy Regulatory Commission or a State regulatory authority (as defined in section 3(21) of the Federal Power Act (16 U.S.C. 796(21)) with respect to an agreement, contract, or transaction that is entered into pursuant to a tariff or rate schedule approved by the Federal Energy Regulatory Commission or a State regulatory authority and is—
(I) not executed, traded, or cleared on a registered entity or trading facility; or
(II) executed, traded, or cleared on a registered entity or trading facility owned or operated by a regional transmission organization or independent system operator.
(ii) In addition to the authority of the Federal Energy Regulatory Commission or a State regulatory authority described in clause (i), nothing in this subparagraph shall limit or affect—
(I) any statutory authority of the Commission with respect to an agreement, contract, or transaction described in clause (i); or
(II) the jurisdiction of the Commission under subparagraph (A) with respect to an agreement, contract, or transaction that is executed, traded, or cleared on a registered entity or trading facility that is not owned or operated by a regional transmission organization or independent system operator (as defined by sections 3(27) and (28) of the Federal Power Act (16 U.S.C. 796(27), 796(28)).
In addition, Dodd-Frank Act section 722(g) (not codified in the United States Code) expressly states that FERC's pre-existing statutory enforcement authority is not limited or affected by amendments to the CEA. Section 722(g) states:
(g) AUTHORITY OF FERC.—Nothing in the Wall Street Transparency and Accountability Act of 2010 or the amendments to the Commodity Exchange Act made by such Act shall limit or affect any statutory enforcement authority of the Federal Energy Regulatory Commission pursuant to section 222 of the Federal Power Act and section 4A of the Natural Gas Act that existed prior to the date of enactment of the Wall Street Transparency and Accountability Act of 2010.
The Dodd-Frank Act granted the Commission specific powers to exempt certain contracts, agreements, or transactions from duties otherwise required by statute or Commission regulation by adding new sections to the CEA, sections 4(c)(6)(A) and (B). Specifically, sections 4(c)(6)(A) and (B) provide for exemptions for certain transactions entered into (a) pursuant to a tariff or rate schedule approved or permitted to take effect by FERC, or (b) pursuant to a tariff or rate schedule establishing rates or charges for, or protocols governing, the sale of electric energy approved or permitted to take effect by the regulatory authority of the State or municipality having jurisdiction to regulate rates and charges for the sale of electric energy within the State or municipality.
(6) If the Commission determines that the exemption would be consistent with the public interest and the purposes of this Act, the Commission shall, in accordance with paragraphs (1) and (2), exempt from the requirements of this Act an agreement, contract, or transaction that is entered into—
(A) pursuant to a tariff or rate schedule approved or permitted to take effect by the Federal Energy Regulatory Commission;
(B) pursuant to a tariff or rate schedule establishing rates or charges for, or protocols governing, the sale of electric energy approved or permitted to take effect by the regulatory authority of the State or municipality having jurisdiction to regulate rates and charges for the sale of electric energy within the State or municipality; or
(C) between entities described in section 201(f) of the Federal Power Act (16 U.S.C. 824(f)).
The Commission must act “in accordance with” sections 4(c)(1) and (2) of the CEA, when issuing an exemption under section 4(c)(6).
In granting exemptive authority to the Commission under new section 4(c), the Conferees recognize the need to create legal certainty for a number of existing categories of instruments which trade today outside of the forum of a designated contract market.
The provision included in the Conference substitute is designed to give the Commission broad flexibility in addressing these products
*****
In this respect, the Conferees expect and strongly encourage the Commission to use its new exemptive power promptly upon enactment of this legislation in four areas where significant concerns of legal uncertainty have arisen: (1) Hybrids, (2) swaps, (3) forwards, and (4) bank deposits and accounts.
The Commission is not required to ascertain whether a particular transaction would fall within its jurisdiction prior to exercising its exemptive authority under section 4(c). The Conferees stated that they did:
not intend that the exercise of exemptive authority by the Commission would require any determination beforehand that the agreement, instrument, or transaction for which an exemption
H.R. Rep. No. 102–978, 102d Cong. 2d Sess. at 82–83 (1992).
(a) Any person that qualifies for one of ten defined categories of appropriate persons; or
(b) such other persons that the Commission determines to be appropriate in light of their financial or other qualifications, or the applicability of appropriate regulatory protections.
On February 7, 2012, the Requesting Parties
The Requesting Parties specifically petitioned the Commission to exempt from most provisions of the CEA certain “financial transmission rights,” “energy transactions,” “forward capacity transactions,” and “reserve or regulation transactions,” as defined in the Petition, if such transactions are offered or entered into pursuant to a Tariff under which a Requesting Party operates that has been approved by FERC or PUCT, as applicable, as well as any persons (including the Requesting Parties, their members and their market participants) offering, entering into, rendering advice, or rendering other services with respect to such transactions.
On August 28, 2012, the Commission issued the Proposed Order.
The Commission proposed to exempt the purchase and sale of four types of transactions
An “FTR” was proposed to be defined as “a transaction, however named, that entitles one party to receive, and obligates another party to pay, an amount based solely on the difference between the price for electricity, established on an electricity market administered by a Requesting Party at a specified source (
“Energy Transactions” were proposed to be defined as transactions in a “Day-Ahead Market”
“Forward Capacity Transactions” were proposed to include transactions in which a Requesting Party, for the benefit of load-serving entities (“LSEs”) purchases the rights described in the Proposed Order.
“Reserve Regulation Transactions” were defined in the Proposed Order as transactions:
(1) In which a Requesting Party, for the benefit of [LSEs] and resources, purchases, through auction, the right, during a period of time specified in the Requesting Party's Tariff, to require the seller to operate electric facilities in a physical state such that the facilities can increase or decrease the rate of injection or withdrawal of electricity to the electric power transmission system operated by the Requesting Party with:
(a) Physical performance by the seller's facilities within a response interval specified in the Requesting Party's Tariff (Reserve Transaction); or
(b) Prompt physical performance by the seller's facilities (Area Control Error Regulation Transaction);
(2) For which the seller receives, in consideration, one or more of the following:
(a) Payment at the price established in the Requesting Party's Day-Ahead or Real-Time Market, as those terms are defined in the Proposed Order, price for electricity applicable whenever the Requesting Party exercises its right that electric energy be delivered (including Demand Response, as defined [in the Proposed] Order);
(b) Compensation for the opportunity cost of not supplying or consuming electricity or other services during any period during which the Requesting Party requires that the seller not supply energy or other services;
(c) An upfront payment determined through the auction administered by the Requesting Party for this service;
(d) An additional amount indexed to the frequency, duration, or other attributes of physical performance as specified in the Requesting Party's Tariff; and
(3) In which the value, quantity and specifications for such Transactions for a Requesting Party for any period of time are limited by the physical capability of the electric transmission system operated by Requesting Parties.
Finally, in the Proposed Order, the Commission clarified that financial transactions that are not tied to the allocation of the physical capabilities of an electric energy transmission grid would not be suitable for exemption, and were therefore not covered by the Proposed Order, because such activity would not be inextricably linked to the physical delivery of electric energy.
The Commission proposed to limit the exemption to the transactions described in the Proposed Order in which all parties thereto fall within one of the appropriate persons categories in CEA sections 4(c)(3)(A) through (J), or, pursuant to CEA section 4(c)(3)(K), that otherwise qualify as an eligible contract participant (“ECP”), as such term is defined in section 1a(18)(A) of the Act and in Commission regulation 1.3(m).
In the Proposed Order, the Commission proposed two conditions precedent to the issuance of a final exemption. First, the Commission proposed that it would not issue a final order to a specific RTO or ISO until (i) such time as the Requesting Parties had adopted in their Tariffs all of the requirements set forth in FERC regulation 35.47;
The Proposed Order included two information-sharing conditions subsequent. First, the Commission proposed that, after promulgation of the order, none of a Requesting Party's Tariffs or other governing documents may include any requirement that the Requesting Party notify a member prior to providing information to the Commission in response to a subpoena or other request for information or documentation.
Second, the Commission proposed that the exemption be conditioned upon information sharing arrangements that are satisfactory to the Commission between the Commission and FERC and between the Commission and PUCT being in full force and effect.
In the Proposed Order, the Commission expressly noted that the proposed exemption was based upon the representations made in the Petition and in the supporting materials provided by the Requesting Parties and their counsel, and that any material change or omission in the facts and circumstances that alter the grounds for the Proposed Order might require the Commission to reconsider its finding that the exemption contained therein is appropriate and/or in the public interest and consistent with the purposes of the CEA.
The public comment period on the Proposed Order ended on September 27, 2012. The Commission received twenty-three (23) comment letters on the Proposed Order,
The Commission received multiple comments regarding the scope of the transactions that are covered by the exemption set forth in the Final Order, including comments requesting: (1) Clarification of the types of transactions that the Commission intended to include within the definitions of the transactions proposed for exemption; (2) a broad expansion of the Covered Transactions in the Final Order to include, for example, additional transactions that are “logical outgrowths” of a Requesting Party's core function as an RTO or ISO; (3) expansion of the exemptive relief specifically to include virtual and convergence bids and offers; and (4) an expedited process for expanding the exemption to include additional transactions.
Some commenters requested that the Commission confirm that the exemption is not limited to products currently traded in their respective markets, and that modifications to existing products and new products, however named, that fall within the definitions of the Covered Transactions and that are offered pursuant to the Requesting Parties' Tariffs would be covered by the Final Order.
The Commission confirms that the definitions of the Covered Transactions included in the Final Order do not limit the exemption to those products that are currently traded in a Requesting Party's markets. Any products that are offered by a Requesting Party, presently or in the future, pursuant to a FERC- or PUCT-approved Tariff and that fall within these definitions, as well as any modifications to existing products that are offered by a Requesting Party pursuant to a FERC- or PUCT-approved Tariff and that do not alter the characteristics of the Covered Transactions in a way that would cause such products to fall outside these definitions, are intended to be included within the Final Order. Accordingly, with respect to the request to expressly specify transactions that are excluded from the exemption, the Commission notes that a Requesting Party would not be required to request or to obtain future supplemental relief for a product that is modified as described above or a product that it subsequently (but does not currently) offer, if the product qualifies as one of the four types of Covered Transactions in the Final Order.
The Commission notes that the definitions of the Covered Transactions set forth in the Final Order are sufficiently broad to include modifications to existing products and new products that fall within such definitions. These definitions are substantially similar to the specific definitions that were requested in the Petition. Moreover, commenters have had the opportunity to identify and comment upon instances, if any, of existing transactions that fall outside the scope of the Proposed Order. In addition, the Commission is concerned that providing lists of excluded transactions may limit the Requesting Parties' flexibility, may require more frequent requests for supplemental relief (possibly incurring inadvertent delays), and may add market confusion. As such, consistent with the confirmation set forth above, the Commission believes it would be inappropriate and inefficient to set forth all transactions that would be excluded from the scope of the Final Order.
Multiple commenters requested that the scope of transactions eligible for the exemption in the Final Order be expanded to include (a) transactions and services that are logical outgrowths of the Requesting Parties' functions as RTOs or ISOs,
Nonetheless, one commenter agreed that a modification to the Final Order should be required for new products that do not logically fit within the Final Order's specified categories, noting that the Commission should have the opportunity to evaluate whether exempting such products would be consistent with the public interest.
As set forth above, the Commission re-affirms that the exemption extends to any transaction that falls within the Covered Transactions set forth in this Final Order, whether currently existing or later included in a Requesting Party's Tariff. The Commission declines, however, to magnify the Final Order to include the expansive terms requested by the specified commenters. Section 4(c)(6) of the CEA, by its terms, was not intended to permit a blanket exemption for all transactions entered into pursuant to a FERC- or PUCT- approved Tariff. Moreover, section 4(c)(6) expressly prohibits the Commission from issuing an exemption for such transactions unless it affirmatively determines that exempting them would be consistent with the public interest and the purposes of the CEA. While the Commission has been able to perform this evaluation for the Covered Transactions delineated in the Final Order, phrases such as “logical outgrowth,” “natural outgrowth,” and “economically comparable” are too vague and potentially too far reaching to permit meaningful analysis under the statutory standard of review. Commenters have not provided, by way of explanation or example, sufficient insight as to what, if any, boundaries an exemption would have if it were extended to the degrees requested.
Moreover, the Commission's determination that this exemption is in the public interest and consistent with the purposes of the CEA is grounded, in part, on certain characteristics of the Covered Transactions and market circumstances described by the Requesting Parties including, for example, that the Covered Transactions are “part of, and inextricably linked to, the organized wholesale electricity markets that are subject to FERC or PUCT regulation and oversight.”
Finally, there may be differences in opinion among the Requesting Parties with respect to the expansion of relief beyond the Covered Transactions. Indeed, the Requesting Parties themselves request that future supplemental relief not be automatically granted to all Requesting Parties and the Commission notes that it has already received supplemental requests for relief that would apply only to certain Requesting Parties, and might be objected to by other Requesting Parties.
In light of these considerations and the potential for adverse consequences that may result from an exemption that includes transactions whose qualities and effect on the broader market cannot be fully appreciated absent further specification, a virtually unlimited exemption would be contrary to the public interest and purposes of the CEA. In addition, consideration of new categories of transactions could be aided by the public notice and comment process. Furthermore, the Commission notes that it is prepared to review requests for supplemental relief from the Requesting Parties.
In discussing the scope of “Energy Transactions” included in the Proposed Order, the Commission stated that such transactions “are also referred to as Virtual Bids or Convergence Bids.”
The particular categories of contracts, agreements and transactions to which the Proposed Exemption would apply correspond to the types of transactions for which relief was explicitly requested in the Petition. Petitioners requested relief for four specific types of transactions and the Proposed Exemption would exempt those transactions. With respect to those transactions, the Petition also included the parenthetical “(including generation, demand response or convergence or virtual bids/transactions).” The Commission notes that such transactions would be included within the scope of the exemption if they would qualify as the financial transmission rights, energy transactions, forward capacity transactions or reserve or regulation transactions for which relief is explicitly provided within the exemption.
77 FR 52163 (internal citations omitted).
Several commenters expressed concerns that certain statements regarding the physical nature of transactions proposed to be exempt, and the role of market participants as physical generators, transmitters, and distributors of electric energy, cast further doubt as to whether the Commission intended to include virtual and convergence bids and offers within the scope of the Proposed Order. One commenter noted that the Commission's statement that the transactions proposed to be exempt are “primarily entered into by commercial participants that are in the business of generating, transmitting and distributing electricity” suggested that virtual and convergence bids and offers may not qualify as Covered Transactions because both traditional and non-traditional utilities engage in such transactions, yet many do not own physical generation or wholesale
Despite their uncertainty with respect to particular statements, multiple commenters contended that virtual and convergence bids and offers fell within the transactions described in the Proposed Order.
Commenters represented that virtual and convergence bids and offers were established as a means by which to improve efficiency and competitiveness in the electric energy markets through the convergence of Day-Ahead Market and RTM prices,
In response to commenters' concerns, the Commission has added language to the Energy Transactions definition to clarify in the Final Order that Energy Transactions “includ[e] * * * Virtual and Convergence Bids and Offers.”
Finally, CAISO and ISO NE requested that the proposed definition of “Energy Transactions” be amended to allow for cash settlement based upon the Day-Ahead Market price (in addition to the Real-Time Market price), due to the fact that for both CAISO and ISO NE., the Day-Ahead Market may be preferable to the Real-Time Market as a source of settlement prices for certain energy transactions.
Several commenters requested a streamlined or expedited process for Commission review of supplemental requests for related exemptions submitted by the Requesting Parties.
Another commenter generally noted that “the Commission * * * should provide an efficient process for Petitioners to confirm the applicability of the exemptive relief to new or modified products in a timely manner,”
As discussed above, the Commission notes that that there is no need to review new or revised Tariffs that are limited to transactions that fall within the definitions of the Covered Transactions set forth in the Final Order. A supplemental exemption is not necessary in such instances. The Commission declines to adopt a streamlined or expedited process for the review of supplemental requests to expand the exemption to additional transactions. As noted above, section 4(c)(6) of the CEA mandates that the Commission, in granting any exemption thereunder, must act in accordance with CEA sections 4(c)(1) and (2). The Commission will strive to address any requests for supplemental relief as expeditiously as possible.
The Commission proposed to exempt any persons (including the Requesting Parties, their members and their market participants) offering, entering into,
In the Proposed Order, the term “Requesting Party” was defined to include the six Requesting Parties (
On October 21, 2010, FERC adopted FERC regulation 35.47
Several commenters argued against this prerequisite, citing FERC's authority over the implementation of FERC regulation 35.47,
With respect to ERCOT, several commenters objected to the condition precedent because ERCOT is subject to PUCT's jurisdiction and not that of FERC,
ERCOT has represented that it implemented protocols that are comparable to
As discussed in detail below in section IV.B.2.e.ii., the Commission believes that the DCO Core Principles provide a useful framework to help measure the extent to which the exemption is in the public interest and consistent with the purposes of the CEA. Because substantial compliance with the standards set forth in FERC regulation 35.47 forms the basis for the determination that the Tariffs and activities of the Requesting Parties are congruent with, and—in the context of the Covered Transactions—sufficiently accomplish, the regulatory objectives of the DCO Core Principles, such compliance is necessary for the Commission's public interest and purposes of the CEA determination.
With respect to ERCOT, the Commission has considered the comments regarding ERCOT's efforts to reform its market protocols in a manner that is the same as or substantially similar to the credit requirements of FERC regulation 35.47. The Commission believes, on the basis of ERCOT's representations, as set forth above, that ERCOT's market protocols differ from the standards set forth in FERC regulation 35.47 in a manner that is sufficiently minor as to permit the Commission to accept them for the purpose of determining that the requested exemption with respect to ERCOT is in the public interest and consistent with the purposes of the CEA. Thus, for ERCOT, adopting measures that are substantially similar to standards that are the same as those set forth in FERC regulation 35.47, as measured by PUCT's permitting all of the ERCOT protocols that are discussed above and as set forth in the Revised FERC Order No. 741 Implementation Chart to take effect, is a necessary prerequisite to the effectiveness of the exemption in the Final Order with respect to ERCOT.
The Proposed Order contemplated requiring, as a condition precedent to the issuance of a Final Order, that each Requesting Party provide a well-reasoned legal opinion or memorandum from outside counsel that, in the Commission's sole discretion, provides the Commission with assurance that the netting arrangements contained in the approach selected by the particular Requesting Party to satisfy the obligations contained in FERC regulation 35.47(d)
The Commission received three types of comments on this requirement: (1) Comments that opposed the condition precedent; (2) comments that did not opine on the propriety of the requirement, but expressed concern with respect to the possible unintended and adverse tax consequences the obligation may have for the Requesting Parties; and (3) a comment that objected to the specific requirement that the memorandum or opinion of counsel be signed by the law firm as opposed to an individual partner of the law firm.
Commenters that opposed the condition precedent generally did so on the basis that the Commission “should not be the arbiter of whether a FERC-approved RTO regime consistent with” FERC regulation 35.47 “meets bankruptcy goals,”
In addition, two commenters urged the Commission to avoid taking any action that could undermine a Requesting Party's tax-exempt status and continued ability to use tax-exempt financing to finance its operations,
With respect to the comments opposing the condition precedent, the Commission reiterates that this requirement is designed to permit the Commission to avoid being the arbiter of whether a Requesting Party has satisfied the requirements of FERC regulation 35.47(d). The Commission notes that no Requesting Party has asserted that it would be unable to obtain such a document. In addition, the Commission notes that the ambiguities discussed in the Proposed Order with respect to some Requesting Parties' interpretations
With respect to the comment that the condition precedent requiring a legal memorandum or opinion of outside counsel may create adverse tax consequences, the Commission notes that such tax issues are beyond the scope of this Final Order.
The Proposed Order included a condition requiring that “neither the tariffs nor any other governing documents of the particular RTO or ISO pursuant to whose tariff the agreement, contract, or transaction is to be offered or sold, shall include any requirement that the RTO or ISO notify its members prior to providing information to the Commission in response to a subpoena or other request for information or documentation.”
One commenter asked “[d]oes the Commission's subpoena secrecy requirement described in the Proposed Order mandate that FERC approve tariff changes that are required by the Commission regardless of whether FERC views them to be `just and reasonable' as required by the Federal Power Act?”
In response to the comments, the Commission recognizes that while this condition may require a Tariff change for some Requesting Parties, this is a necessary condition to the exemptive relief. As an initial matter, RTOs and ISOs amend their Tariffs on a regular basis. Thus, amending one Tariff provision would not necessarily result in opening unrelated Tariff provisions.
The Proposed Order contemplated two conditions that addressed the Commission's ability to obtain information from the Requesting Parties.
Of those commenters that addressed the information sharing condition precedent for ERCOT, all viewpoints received requested that the Commission refrain from requiring that an information sharing agreement between PUCT and the Commission be in place prior to a final exemption becoming effective for ERCOT. The Requesting Parties and PUCT noted that fulfillment of such a requirement is beyond the control of ERCOT in terms of timing and terms, and therefore would be more appropriate as a condition subsequent to the effectiveness of the exemption in
Regarding the Commission's contemplation of affirmatively requiring all Requesting Parties to cooperate with requests for information as a condition of the exemption, commenters did not respond directly, although one commenter suggested that the imposition of additional requirements upon the Requesting Parties for purposes of obtaining information through FERC or PUCT as the Requesting Parties' primary regulator amounts to indirect regulation.
In response to the comments opposing an information sharing agreement between PUCT and the Commission as a condition precedent to the effectiveness of relief for ERCOT, the Commission has determined not to pursue such a condition, and thus has stricken the execution of an information-sharing agreement with PUCT as a condition of the Final Order. Rather, with respect to ERCOT, the Final Order conditions the exemption upon “the Commission's ability to request, and obtain, on an as-needed basis from ERCOT, concurrently with the provision of written notice to PUCT and in connection with an inquiry consistent with the CEA and Commission regulations, positional and transactional data within ERCOT's possession for products in ERCOT's markets that are related to markets that are subject to the Commission's jurisdiction, including any pertinent information concerning such data, and ERCOT's compliance with such requests by sharing the requested information.”
Consistent with the revised language noted above requiring ERCOT to comply with the Commission's requests for related market data on an as-needed basis, the Commission has revised the information sharing condition applicable to the FERC-regulated Requesting Parties. The Final Order conditions the exemption with respect to FERC-regulated Requesting Parties upon: (1) Information sharing arrangements between the Commission and FERC that are acceptable to the Commission and that continue to be in effect
The Commission notes that any contemplated request for related market data would not be an attempt to indirectly regulate the Requesting Parties or their markets, contrary to some commenters' suggestion. In order for the Commission to determine that the Final Order is consistent with the public interest and the purposes of the CEA, the terms of the Final Order cannot adversely affect the ability of the Commission to discharge its regulatory duties under the CEA in monitoring energy markets under its jurisdiction.
As discussed above in section I., the Dodd-Frank Act amended CEA section 4(c) to add sections 4(c)(6)(A) and (B), which provide for exemptions for certain transactions entered into (a) pursuant to a tariff or rate schedule approved or permitted to take effect by FERC, or (b) pursuant to a tariff or rate schedule establishing rates or charges for, or protocols governing, the sale of electric energy approved or permitted to take effect by the regulatory authority of the State or municipality having jurisdiction to regulate rates and charges for the sale of electric energy within the State or municipality, as eligible for exemption pursuant to the Commission's 4(c) exemptive authority.
(6) If the Commission determines that the exemption would be consistent with the public interest and the purposes of this Act, the Commission shall, in accordance with paragraphs (1) and (2), exempt from the requirements of this Act an agreement, contract, or transaction that is entered into—
(A) pursuant to a tariff or rate schedule approved or permitted to take effect by the Federal Energy Regulatory Commission;
(B) pursuant to a tariff or rate schedule establishing rates or charges for, or protocols governing, the sale of electric energy approved or permitted to take effect by the regulatory authority of the State or municipality having jurisdiction to regulate rates and charges for the sale of electric energy within the State or municipality; or
(C) between entities described in section 201(f) of the Federal Power Act (16 U.S.C. 824(f)).
As described above in section I., CEA section 4(c)(1) requires that the Commission act “by rule, regulation or order, after notice and opportunity for hearing.” It also provides that the Commission may act “either unconditionally or on stated terms or conditions or for stated periods and either retroactively or prospectively or both” and that the Commission may provide an exemption from any provisions of the CEA except subparagraphs (C)(ii) and (D) of section 2(a)(1).
(c)(1) In order to promote responsible economic or financial innovation and fair competition, the Commission by rule, regulation, or order, after notice and opportunity for hearing, may (on its own initiative or on application of any person, including any board of trade designated or registered as a contract market or derivatives transaction execution facility for transactions for future delivery in any commodity under section 5 of this Act) exempt any agreement, contract, or transaction (or class thereof) that is otherwise subject to subsection (a) (including any person or class of persons offering, entering into, rendering advice or rendering other services with respect to, the agreement, contract, or transaction), either unconditionally or on stated terms or conditions or for stated periods and either retroactively or prospectively, or both, from any of the requirements of subsection (a), or from any other provision of this Act (except subparagraphs (C)(ii) and (D) of section 2(a)(1), except that—
(A) unless the Commission is expressly authorized by any provision described in this subparagraph to grant exemptions, with respect to amendments made by subtitle A of the Wall Street Transparency and Accountability Act of 2010—
(i) with respect to—
(I) paragraphs (2), (3), (4), (5), and (7), paragraph (18)(A)(vii)(III), paragraphs (23), (24), (31), (32), (38), (39), (41), (42), (46), (47), (48), and (49) of section 1a, and sections 2(a)(13), 2(c)(1)(D), 4a(a), 4a(b), 4d(c), 4d(d), 4r, 4s, 5b(a), 5b(b), 5(d), 5(g), 5(h), 5b(c), 5b(i), 8e, and 21; and
(II) section 206(e) of the Gramm-Leach-Bliley Act (Public Law 106–102; 15 U.S.C. 78c note); and
(ii) in sections 721(c) and 742 of the Dodd-Frank Wall Street Reform and Consumer Protection Act; and
(B) the Commission and the Securities and Exchange Commission may by rule, regulation, or order jointly exclude any agreement, contract, or transaction from section 2(a)(1)(D)) if the Commissions determine that the exemption would be consistent with the public interest.
As set forth above in section I., CEA section 4(c)(2) requires the Commission to determine that: to the extent an exemption provides relief from any of the requirements of CEA section 4(a), the requirement should not be applied to the agreement, contract or transaction; the exempted agreement, contract, or transactions will be entered into solely between appropriate persons;
As explained in section I. above, CEA section 4(c)(3) outlines who may constitute an appropriate person for the purpose of a 4(c) exemption, including as relevant to this Final Order: (a) Any person that fits in one of ten defined categories of appropriate persons; or (b) such other persons that the Commission determines to be appropriate in light of their financial or other qualifications, or the applicability of appropriate regulatory protections.
Subject to the limitations set forth in the CEA, sections 4(c)(6)(A) and (B) of the Act grant the Commission the authority to exempt certain electric energy transactions provided that the Commission determines, among other things, that such exemption is consistent with the public interest and purposes of the CEA.
Two commenters argued that, the Commission should “interpret the Dodd-Frank Act as not applying to any contract or agreement traded in an RTO or ISO market pursuant to a FERC-accepted or approved rate schedule or tariff” and that the Commission should exclude RTO or ISO contracts or instruments from the definition of swap.
A different commenter claimed that the Commission should not regulate “[a]ccess to physical electricity markets.”
Another commenter recognized the Commission's exemptive authority under section 4(c)(6), but requested that the Commission affirmatively state in any final order that it makes no determination as to whether the transactions included in the final order fall within the Commission's jurisdiction because the absence of such statement “could actually undermine the very regulatory certainty being requested by Petitioners, and potentially
In response to the comments, the Commission notes that the definition of a “swap” set forth in Commission regulations is beyond the scope of this Final Order. The Commission further notes that the interpretation of the Dodd-Frank Act proffered by the commenters is contrary to the express language of that statute. The Dodd-Frank Act added a savings clause to the CEA that addresses the roles of the Commission, FERC, and state agencies as they relate to transactions traded pursuant to FERC- or state-approved tariffs or rate schedules. Section 2(a)(1)(I) of the Act repeats the Commission's exclusive jurisdiction and clarifies that the Commission retains its authority over transactions that are within its jurisdiction. Moreover, while, section 4(c)(6) of the CEA, added by the Dodd-Frank Act, empowers the Commission to exempt contracts, agreements or transactions traded pursuant to a Tariff or rate schedule that has been approved or permitted to take effect by FERC or a state regulatory authority, it does not permit the Commission to automatically or mechanically apply the exemption. Instead, section 4(c)(6) mandates that the Commission initially determine that the exemption would be in the public interest and consistent with the purposes of the CEA, that the exemption would be applied only to agreements, contracts, or transactions that are entered into solely between appropriate persons, and that the exemption will not have a material adverse effect on the ability of the Commission or any contract market to discharge its regulatory or self-regulatory duties under the CEA.
As required by CEA section 4(c)(2)(A), as well as section 4(c)(6), the Commission determines that the Final Order is consistent with the public interest and the purposes of the CEA. Section 3(a) of the CEA provides that transactions subject to the CEA affect the national public interest by providing a means for managing and assuming price risk, discovering prices, or disseminating pricing information through trading in liquid, fair and financially secure trading facilities.
It is the purpose of this Act to serve the public interests described in subsection (a) through a system of effective self-regulation of trading facilities, clearing systems, market participants and market professionals under the oversight of the Commission. To foster these public interests, it is further the purpose of this Act to deter and prevent price manipulation or any other disruptions to market integrity; to ensure the financial integrity of all transactions subject to this Act and the avoidance of systemic risk; to protect all market participants from fraudulent or other abusive sales practices and misuses of customer assets; and to promote responsible innovation and fair competition among boards of trade, other markets and market participants.
Consistent with the proposed determinations set forth in the Proposed Order,
Furthermore, as explained by the Requesting Parties and discussed in the Proposed Order, the Commission notes that the Covered Transactions are entered into primarily by commercial participants that are in the business of generating, transmitting, and distributing electric energy,
Moreover, fundamental to this “public interest” and “purposes of the [Act]” analysis is the fact that the Covered Transactions are inextricably tied to the Requesting Parties' physical delivery of electric energy.
Finally, the extent to which the Final Order is consistent with the public interest and the purposes of the Act can, in major part, be assessed by the extent to which the Tariffs and activities of the Requesting Parties, and supervision by FERC and PUCT, are congruent with, and sufficiently accomplish, the regulatory objectives of the relevant Core Principles set forth in the CEA for DCOs and SEFs. Specifically, providing a means for managing or assuming price risk and discovering prices, as well as prevention of price manipulation and other disruptions to market integrity, are addressed by the Core Principles for SEFs. Ensuring the financial integrity of the Covered Transactions and the avoidance of systemic risk, as well as protection from the misuse of participant assets, are addressed by the Core Principles for DCOs. Deterrence of price manipulation (or other disruptions to market integrity) and protection of market participants from fraudulent sales practices is achieved by the Commission retaining and exercising its jurisdiction over these matters. Therefore, the Commission has incorporated its DCO and SEF Core Principle analyses, set forth in the Proposed Order, into its consideration of the Final Order's consistency with the public interest and the purposes of the Act.
The Commission specifically requested comment on whether it used the appropriate standard in making its section 4(c) determination. The Commission received comments with respect to compliance with FERC's credit reform policy as a precondition to the issuance of a Final Order, which are discussed in sections IV.A.3.a.i. and IV.B.2.e.i., and on the Commission's use of the DCO and SEF Core Principles, which are discussed in sections IV.B.2.e.i.–ii. below.
The Commission received a number of comments regarding the appropriateness of the public interest and purposes of the CEA standard outlined above.
The Commission has considered the comments, and believes that it has used the appropriate standard in making its public interest and purpose of the CEA determination for purposes of this Final Order. The Commission disagrees that the existence of pervasive FERC and PUCT regulations is, by itself, a sufficient standard to analyze that the requested exemptive relief is consistent with the public interest and the purposes of the CEA, because, as set forth above,
After consideration of the comments received and for the reasons set forth in this Final Order, the Commission has determined that the exemption set forth in this Final Order is consistent with the public interest and the purposes of the CEA.
CEA section 4(c)(2)(A) requires, in part, that the Commission determine that the Covered Transactions described in the Final Order should not be subject to CEA section 4(a)—generally, the Commission's exchange trading requirement for a contract for the purchase or sale of a commodity for future delivery. As set forth in the Proposed Order, the Commission has examined the Covered Transactions, the Requesting Parties, and their markets using the CEA Core Principle requirements applicable to a DCO and to a SEF as a framework for its public interest and purposes of the CEA determination.
Section 4(c)(2)(B)(i) of the CEA
The Commission proposed to limit the exemption to transactions where all parties thereto either (a) satisfy the appropriate persons criteria set forth in sections 4(c)(3)(A) through (J) or, (using its authority under section 4(c)(3)(K)) (b) qualify as ECPs, as defined in section 1a(18)(A) of the CEA and in Commission regulation 1.3(m).
The Commission did not receive any comment objecting to its proposed determination, pursuant to section 4(c)(3)(K) of the Act, that ECPs be included within the definition of appropriate persons for purposes of the Final Order. Accordingly, and pursuant to the authority set forth in section 4(c)(3)(K) of the CEA, the Commission has determined that ECPs, as defined in section 1a(18)(A) of the CEA and in Commission regulation 1.3(m), are appropriate persons for purposes of the Final Order in light of their financial or other qualifications, or the applicability of regulatory protections. In addition, in response to confusion regarding whether market participants are required to establish compliance with section 4(c)(3)(F) or demonstrate their ECP status for purposes of this Final Order through the use of audited financial statements, the Commission also is clarifying that market participants that qualify as appropriate persons under section 4(c)(3)(F) of the CEA or on the grounds that they are ECPs as defined in section 1a(18)(A) of the Act and Commission regulation 1.3(m), are not required to prove such qualification through the use of audited financial statements.
The Commission also received several comments requesting that it exercise its statutory authority under section 4(c)(3)(K) to expand further the definition of appropriate person for purposes of the Final Order. These comments generally fell into three categories: requests to extend the definition to specific subsets of market participants; requests to expand the definition more broadly to include, for example, all market participants that satisfy the participant eligibility criteria established by the Requesting Parties; and requests to clarify that certain market participants are included in the definition of appropriate person set forth in CEA sections 4(c)(3)(F) and (H). Several commenters also requested that all market participants who engage in particular types of transactions (such as virtual and demand response transactions) be included in the definition of appropriate person for the purpose of the Final Order.
The Commission received multiple requests to include various categories of market participants within the scope of appropriate person for purposes of the Final Order. One commenter urged the Commission to expand the definition to include all persons who actively participate in the generation, transmission, or distribution of electric energy, noting that the proposed definition of appropriate person could exclude traditionally active market participants whose participation facilitates demand response activities, and reduces costs.
Multiple commenters requested that electric cooperatives be deemed appropriate persons for purposes of the Final Order.
After consideration of the comments described above, the Commission is using the authority provided by section 4(c)(3)(K) of the CEA to determine that a “person who actively participates in the generation, transmission, or distribution of electric energy,” as defined within the Final Order, is an appropriate person for purposes of the exemption provided therein.
Although the Commission expects that the definition of a “person who actively participates in the generation, transmission, or distribution of electric energy” will capture many of the market participants referenced in the comments that the Commission received,
Several commenters advocated that the Commission use the authority provided by section 4(c)(3)(K) of the CEA to expand the definition of appropriate persons for purposes of the Final Order to include all entities that satisfy the market participant eligibility requirements established by the RTOs and ISOs.
Multiple commenters asserted that the Commission should deem all RTO and ISO market participants as appropriate persons for purposes of the Final Order by referencing specific types of participation standards established by the RTOs and ISOs.
Certain commenters claimed that some entities that currently participate in the RTO and ISO markets might not be able to satisfy the appropriate person standard set forth in the Proposed Order and would exit the market.
Several commenters alleged that the exit of existing market participants would have a negative impact on the functioning of the RTO and ISO markets.
Certain commenters supported the inclusion of all RTO and ISO market participants in the appropriate persons definition for purposes of the Final Order by claiming that recently increased collateral requirements have reduced the default risks of particular RTOs
However, certain commenters who contended that the Commission should invoke the authority provide by section 4(c)(3)(K) of the CEA to include all RTO and ISO market participants in the definition of appropriate persons for purposes of the Final Order nonetheless suggested that the market impact of the participation limitations imposed by the proposed appropriate persons definition could be minimal.
As set forth above, the Commission considered requests from the commenters to categorize particular types of entities as appropriate persons for purposes of the Final Order and, pursuant to the authority provided by section 4(c)(3)(K) of the CEA, is expanding the definition to include a “person who actively participates in the generation, transmission, or distribution of electric energy.”
The Commission declines to generally and broadly extend the exemption contained in the Final Order to transactions involving all persons that satisfy the market participant eligibility criteria established by the RTOs and ISOs. The Commission notes that the definition of appropriate person set forth in sections 4(c)(3)(A) through (J) of the CEA explicitly defines the types of qualified entities that Congress intended to be eligible for an exemption under section 4(c).
One commenter asked that the Commission affirm that public power systems, and that units or instrumentalities of tribal governments are “appropriate persons” under section 4(c)(3)(H) of the CEA.
The Commission interprets section 4(c)(3)(H) to include public power systems and the units or instrumentalities of tribal governments within the meaning of “governmental entities.” This interpretation is consistent with both the Commission's approach to public power entities, which are operated by local governments for the benefit of its citizens
Section 4(c)(3)(F) of the CEA defines “appropriate person” to include “[a] corporation, partnership, proprietorship, organization, trust or other business entity with a net worth exceeding $1,000,000 or total assets exceeding $5,000,000,
In addition, one commenter requested that the Commission provide guidance as to what would be acceptable as a “keepwell, support, or other agreement” for purposes of section 4(c)(3)(F),
The Commission clarifies that a market participant that provides to the RTO or ISO an unlimited guaranty or other support in the form of a “letter of credit or keepwell, support, or other agreement,” which guarantee or other support has been issued by an appropriate person, thereby supports its obligation to the RTO or ISO and, thus, satisfies the section 4(c)(3)(F) criteria. The guaranteeing or supporting entity will not be required by the Final Order to demonstrate its status as an “appropriate person”
As discussed in greater detail above,
In the Proposed Order, in determining whether an exemption for the transactions defined therein was consistent with the public interest and the purposes of CEA, the Commission preliminarily determined, based upon the Requesting Parties' representations and in the context of the Requesting Parties' activities with respect to the transactions within the scope of the Proposed Order, that the Requesting Parties' practices or Tariffs and supervision by FERC and PUCT appeared to be congruent with, and sufficiently accomplish, the regulatory objectives of the Core Principles set forth in the CEA for DCOs.
The Commission received several comments regarding the use of the DCO Core Principles as part of the public interest and purposes of the CEA analysis.
The Commission believes that the analysis drawing from the DCO Core Principles contained in the Proposed Order should be used to determine whether the exemption is consistent with the public interest and the purposes of the CEA. The Commission is not using the analysis to determine whether the Requesting Parties are DCOs. The Commission is not holding the Requesting Parties to the same standards as DCOs, and is not concluding that the Requesting Parties would meet the standards set forth in section 5b(c)(2) of the CEA and part 39 of the Commission's regulations. Nonetheless, the Commission believes that the DCO Core Principles provide a useful framework by which to measure the extent to which the Tariffs and activities of the Requesting Parties, and supervision by FERC and PUCT, are congruent with, and—in the context of the Covered Transactions—sufficiently accomplish, the regulatory objectives of the CEA. As discussed herein, particularly in sections IV.A.3.a.i. and IV.B.2.e.i., the Commission believes that the standards set forth in FERC regulation 35.47 appear to achieve goals similar to the regulatory objectives of the Commission's DCO Core Principles. Moreover, as set forth in the Commission's DCO Core Principle analysis in the Proposed Order,
In the Proposed Order, in determining whether the proposed exemption was consistent with the public interest and the purposes of CEA, the Commission preliminarily determined, based upon the Requesting Parties' representations and in the context of the Requesting Parties' activities with respect to the transactions within the scope of the Proposed Order, that the Requesting Parties' practices or Tariffs, and supervision by FERC and PUCT, appeared to be congruent with, and sufficiently accomplish, the regulatory objectives of the Core Principles set forth in the CEA for SEFs.
One commenter implored the Commission to allow the RTO and ISO markets to continue to exist largely as they currently do by not requiring compliance with the SEF Core Principles.
Regarding the Commission's 4(c) public interest analysis, one commenter agreed “that rules and regulations under the Petitioners' [Open Access Transmission Tariffs] in general satisfy the Core Principles and regulatory requirements that would apply to entities seeking designation as a SEF.”
Similar to its view of the DCO Core Principles analysis and comment received thereon, the Commission believes its analysis drawing from the SEF Core Principles contained in the Proposed Order should be used to determine whether the exemption is consistent with the public interest and purposes of the Act—not as a determination that the Requesting Parties are SEFs themselves, or that the products traded in their markets are swaps. To the contrary, and consistent with the legislative history behind CEA section 4(c), the Commission takes no position as to the jurisdictional status of any Requesting Party or Covered Transaction in the Final Order. Furthermore, in making its public interest and purposes of the CEA determination based upon, in part, the SEF Core Principle analysis, the Commission is not holding the Requesting Parties to the same standards as SEFs, nor is it concluding that the
Nonetheless, the Commission views the SEF Core Principles as a useful way of measuring the extent to which the Tariffs and activities of the Requesting Parties, and supervision by FERC and PUCT, are congruent with, and—in the context of the Covered Transactions—sufficiently accomplish, the regulatory objectives of the CEA. As set forth in the Commission's SEF Core Principles analysis in the Proposed Order,
In the Proposed Order, the Commission requested comment as to whether “the lack of position limits or position accountability thresholds for speculators in Petitioners' markets, given the nature of their markets and market participants, and the other regulatory protections applicable to these markets as described [in the Proposed Exemption], would prevent the Commission from determining that the Proposed Exemption is consistent with the public interest and the purposes of the CEA.”
Generally, commenters responded that the Commission should not impose position limits on the Covered Transactions. Several commenters objected on the ground that, because the Commission had not determined that the transactions subject to the Proposed Order were subject to the jurisdiction of the Commission, the imposition of an existing regulatory regime on such transactions would be unreasonable.
Commenters also highlighted that the Requesting Parties' markets are administrated so that the total amount of energy represented by instruments created on the markets is related to the deliverable capacity of the physical transmission systems, making them a more effective limitation than position limits since, as currently constructed under the Commission's rules, position limits do not cap overall open interest.
Without making any determinations regarding the merits of the commenters' concerns regarding position limits, the Commission's Final Order does not impose position limits on the Covered Transactions. The Commission accepts the Requesting Parties' representations that the physical capability of their transmission grids limits the size of positions that any single market participant can take at a given time. Moreover, based upon the representations made in the Petition, the Proposed Order provided that each category of exempted transaction, including FTRs, would be limited by the physical capability of the electric energy transmission system. Accordingly, as the Final Order continues to limit each Covered Transaction category to the physical capability of the transmission grid,
The Proposed Exemption specifically sought public comment as to whether the Requesting Parties “should [be] capable of re-creating the Day-Ahead Market and Real-Time prices.”
Some commenters contested the underlying utility of being able to re-create the market. The Requesting Parties argued that it is impossible to predict how other market participants would have reacted to a hypothetical situation.
Regardless of underlying utility, necessity, or relevance, the Requesting Parties noted that building the capability to re-run a market (other than a straight reproduction of what occurred) would be extremely expensive in all cases, and in some cases, impossible to do.
Generally, the Commission notes that the ability to re-create market prices entails simulating what price outcomes in a market auction would have occurred, but for certain bids and offers being placed. This ability is required of Commission-regulated DCMs
Nevertheless, due to the potentially significant costs for the Requesting Parties that could be associated with building the capability to re-run their markets, the Commission is not requiring such a capability as a condition of the Final Order. While the Commission encourages FERC and PUCT to continue contemplating requiring the Requesting Parties to implement the ability to re-run their markets, the Commission does not believe that such a capability is necessary at this time to its determination that the Final Order is consistent with the public interest and purposes of the Act.
CEA section 4(c)(2)(B)(ii) requires the Commission to make a determination regarding whether exempting the Covered Transactions will have a material adverse effect on the ability of the Commission or any contract markets to perform regulatory or self-regulatory duties.
The Commission proposed to determine that the exemption would not have a material adverse effect on the Commission's or any contract market's ability to discharge its regulatory function. In the Proposed Order, the Commission noted the following assertion by the Requesting Parties as support for its determination:
Under Section 4(d) of the Act, the Commission will retain authority to conduct investigations to determine whether Petitioners are in compliance with any exemption granted in response to this request. * * * [T]he requested exemptions would also preserve the Commission's existing enforcement jurisdiction over fraud and manipulation. This is consistent with section 722 of the Dodd-Frank Act, the existing MOU between the FERC and the Commission and other protocols for inter-agency cooperation. The Petitioners will continue to retain records related to the Transactions, consistent with existing obligations under FERC and PUCT regulations.
The regulation of exchange-traded futures contracts and significant price discovery contracts (“SPDCs”) will be unaffected by the requested exemptions. Futures contracts based on electricity prices set in Petitioners' markets that are traded on a designated contract market and SPDCs will continue to be regulated by and subject to the requirements of the Commission. No current requirement or practice of the ISOs/RTOs or of a contract market will be affected by the Commission's granting the requested exemptions.
In addition, the Commission stated that the limitation of the exemption to transactions delineated in the Proposed Order between certain appropriate persons avoids potential issues regarding financial integrity and customer protection.
Moreover, the Commission did not propose to exempt the Requesting Parties from certain CEA provisions, including, but not limited to, sections 2(a)(1)(B), 4b, 4c(b), 4
In addition, the Commission proposed that granting the exemption for the transactions delineated in the Proposed Order would not have a material adverse effect on the ability of any contract market to discharge its self-regulatory duties under the Act.
Finally, the Commission noted that if the transactions described in the Proposed Order could ever be used in combination with trading activity or in a position in a DCM contract to conduct market abuse, both the Commission and DCMs have sufficient independent authority over DCM market participants to monitor for such activity.
While the Commission did not receive any comments on its proposed determination that the exemption would not have a material adverse effect on the Commission's ability to discharge its
For the reasons set forth herein and in the Proposed Order, the Commission determines that the exemption for the Covered Transactions in this Final Order would not have a material adverse effect on the Commission's or any contract market's ability to discharge its regulatory function.
The Commission proposed to issue a single exemptive order for all Requesting Parties in lieu of the six separate exemptive orders requested by the Requesting Parties because, as explained in the Proposed Order, there are “ `[congruents] in [the Petitioners'] markets and operations,' ”
Several commenters urged the Commission to adopt separate final orders for particular Requesting Parties because of concerns surrounding the delays and regulatory uncertainty that may be caused by requiring compliance by all Requesting Parties with the proposed conditions precedent.
Another commenter requested that the Commission clarify that any supplemental relief requested by one Requesting Party would not, if granted, apply to any other Requesting Party, unless specifically requested by that Requesting Party.
After careful consideration of these comments, the Commission has determined, for the same reasons set forth in the Proposed Order,
The Commission also confirms that individual Requesting Parties may file individual requests for supplemental exemptions. Future requests for supplemental relief will be dealt with as expeditiously as practicable based upon the petition submitted, the facts and circumstances at the time of the submission, and the Commission's resources at the time. The Requesting Parties have noted the importance of quick action, and the Commission notes that certain efficiencies may stem from coordinated action for relief.
As described in detail above,
In addition, the Commission proposed to exclude from the exemptive relief its general anti-fraud, anti-manipulation, and enforcement authority over the Requesting Parties and the transactions described in the Proposed Order under the CEA, including, but not limited to, sections 2(a)(1)(B), 4b, 4c(b), 4o, 4s(h)(1)(A), 4s(h)(4)(A), 6(c), 6(d), 6(e), 6c, 6d, 8, 9, and 13 of the CEA and any implementing regulations promulgated thereunder including, but not limited to, Commission regulations 23.410(a) and (b), 32.4, and part 180.
One commenter expressed full support for this reservation of authority because “the Commission's continued oversight in these vital areas protects the markets, market participants, and the customers they serve.”
After consideration of the comments, the Commission believes it prudent to reserve in the Final Order its anti-fraud and anti-manipulation authority, as well as those scienter-based prohibitions in the specified provisions of the Act and Commission regulations (without finding it necessary in this particular context to preserve other enforcement authority). The Commission notes that reservation of enforcement authority is standard practice with exemptive orders issued pursuant to CEA section 4(c). While the commenter is correct that section 4c(b) and regulation 32.4 do not articulate the Commission's general anti-fraud, anti-manipulation, and enforcement authority directly, these provisions exemplify a possible statutory basis for bringing an enforcement action, should there be a need for the Commission to do so, and notes that the inclusion of these provisions is not intended to bring any transactions under CFTC jurisdiction for purposes other than enforcement. In addition, these carve-outs are consistent with past exemptive orders and do not expand the Commission's jurisdiction.
The Commission also is adding CEA section 4(d) to the non-exclusive list of reserved enforcement authority. The Commission believes it is important to highlight that, as with all exemptions issued pursuant to CEA section 4(c), the exemption “shall not affect the authority of the Commission under any other provision of [the CEA] to conduct investigations in order to determine compliance with the requirements or conditions of such exemption or to take enforcement action for any violation of any provision of [the CEA] or any rule, regulation or order thereunder caused by the failure to comply with or satisfy such conditions or requirements.”
The Commission proposed to make the exemption effective immediately.
Several commenters requested that the Commission issue a final order as quickly as possible or practical, respectively.
Another commenter stated that, if the Commission determines not to issue separate exemption orders, it should specify how and when a single order will take effect for each Requesting Party.
The Commission notes that it is not anticipated that any individual Requesting Party will be in need of a final order to continue its present business until the date by which all Requesting Parties have satisfied the conditions precedent described in the Proposed Order. Indeed, the Commission also notes that the Commission's Divisions of Clearing and Risk, Market Oversight, and Swap and Intermediary Oversight issued a no-action letter preserving the regulatory status quo of the transactions that are the subject of the Proposed Order until the earlier of March 31, 2013, or such earlier date as the Commission may establish in taking final action on the Proposed Order.
With respect to the required legal memorandum or opinion of counsel, the Commission is delegating to the Director of the Division of Clearing and Risk and to his designees, in consultation with the General Counsel or the General Counsel's designees, the authority to accept or reject the legal memorandum or opinion. The Director of Clearing and Risk will affirmatively communicate to the Requesting Party when the Requesting Party's legal memorandum or opinion has been accepted or rejected.
With respect to the condition requiring compliance with the standards set forth in FERC regulation 35.47, Requesting Parties governed by FERC will be deemed to have satisfied this condition upon FERC's acceptance and approval of all of the Requesting Parties' Tariffs that are necessary to implement such standards.
The Regulatory Flexibility Act (“RFA”) requires that agencies consider whether the exemption set forth in the Final Order will have a significant economic impact on a substantial number of small entities and, if so, provide a regulatory flexibility analysis respecting the impact.
Commission staff also performed an independent RFA analysis based on Subsector 221 of sector 22 (utilities companies), which defines any small utility corporation as one that does not generate more than 4 million of megawatts of electric energy per year, and Subsector 523 of Sector 52 (Securities Commodity Contracts, and Other Financial Investments and Related Activities) of the SBA standards, 13 CFR 121.201 (1–1–11 Edition), which identifies a small business size standard of $7 million or less in annual receipts. Staff concluded that none of the Requesting Parties is a small entity, based on the following information:
MISO reports 594 million megawatt hours per year,
ERCOT reports 335 million megawatt hours per year,
CAISO reports 200 million megawatts per year,
NYISO reports 17 million megawatts per month, which calculates to 204 megawatts per year,
PJM reports $35.9 billion billed in 2011,
ISO NE reports 32,798 gigawatt hours in the first quarter of 2011, which translates into almost 33 million megawatts for the first quarter of 2011,
In response to its request for comments on the Proposed Order, the Commission received comment letters relevant to the RFA that primarily focused on the scope of the term “appropriate persons.”
The Commission is further of the view that the Final Order relieves the economic impact that the exempt entities, including any small entities that may opt to take advantage of the exemption set forth in the Final Order otherwise would be subjected to by exempting certain of their transactions from the application of substantive regulatory compliance requirements of the CEA and Commission regulations thereunder. Indeed, pursuant to section 4(c)(3)(K) of the CEA, the Final Order expands the category of persons that are “appropriate persons” that may avail themselves of the exemption. Accordingly, the Commission does not expect the Final Order to have a significant impact on a substantial number of small entities. Therefore, the Chairman, on behalf of the Commission, hereby certifies, pursuant to 5 U.S.C. 605(b), that the exemption set forth in the Final Order would not have a significant economic impact on a substantial number of small entities.
The purposes of the Paperwork Reduction Act of 1995, 44 U.S.C. 3501 et seq. (“PRA”) are, among other things, to minimize the paperwork burden to the private sector, ensure that any collection of information by a government agency is put to the greatest possible uses, and minimize duplicative information collections across the government. The PRA applies to all information, “regardless of form or format,” whenever the government is “obtaining, causing to be obtained [or] soliciting” information, and includes and requires “disclosure to third parties or the public, of facts or opinions,” when the information collection calls for “answers to identical questions posed to, or identical reporting or recordkeeping requirements imposed on, ten or more persons.” The Proposed Order provided that the exemption would be expressly conditioned upon information sharing: “With respect to ERCOT, information sharing arrangements between the Commission and PUCT that are acceptable to the Commission are executed and continue to be in effect. With respect to all other Requesting Parties, information sharing arrangements between the Commission and FERC that are acceptable to the Commission continue to be in effect.”
The Final Order has amended the information sharing conditions to provide that the exemption is expressly conditioned upon information sharing:
(1) With respect to all Requesting Parties subject to the jurisdiction of FERC, information sharing arrangements between the Commission and FERC that are acceptable to the Commission continue to be in effect, and those Requesting Parties' compliance with the Commission's requests through FERC to share, on an as-needed basis and in connection with an inquiry consistent with the CEA and Commission regulations, positional and transactional data within the Requesting Parties' possession for products in the Requesting Parties' markets that are related to markets that are subject to the Commission's jurisdiction, including any pertinent information concerning such data.
(2) With respect to ERCOT, the Commission's ability to request, and obtain, on an as-needed basis from ERCOT, concurrently with the provision of written notice to PUCT and in connection with an inquiry consistent with the CEA and Commission regulations, positional and transactional data within ERCOT's possession for products in ERCOT's markets that are related to markets that are subject to the Commission's jurisdiction, including any pertinent information concerning such data, and ERCOT's compliance with such requests by sharing the requested information.
As discussed in section I. above, the Dodd-Frank Act amended CEA section 4(c) to add sections 4(c)(6)(A) and (B), which permit exemptions for certain transactions entered into (a) pursuant to a tariff or rate schedule approved or permitted to take effect by FERC, or (b) pursuant to a tariff or rate schedule establishing rates or charges for, or protocols governing, the sale of electric energy approved or permitted to take effect by the regulatory authority of the State or municipality having jurisdiction to regulate rates and charges for the sale of electric energy within the State or municipality pursuant to the Commission's 4(c) exemptive authority. However, the Commission must act “in accordance with” sections 4(c)(1) and (2) of the CEA.
On February 7, 2012, the Requesting Parties filed a joint Petition
The Requesting Parties requested that, due to the commonalities in their markets, the exemption apply to all Requesting Parties and their respective market participants with respect to each category of electricity energy transactions described in the Petition, regardless of whether such transactions are offered or entered into at the current time pursuant to an individual RTO or ISO's Tariff. The Requesting Parties asserted that this uniformity would avoid an individual RTO or ISO being required to seek future amendments to the exemption in order to offer or enter into the same type of transactions currently offered by another RTO or ISO.
Section 15(a) of the CEA
Upon consideration of the Petition, the Commission issued the Proposed Order which proposed to exempt certain transactions pursuant to section 4(c)(6) of the CEA.
In the Proposed Order, the Commission clarified that financial transactions that are not tied to the allocation of the physical capabilities of an electric energy transmission grid would not be suitable for exemption, and were therefore not covered by the Proposed Order because such activity would not be inextricably linked to the physical delivery of electric energy.
The Proposed Order expressly requested public comment on the Commission's proposed cost-benefit consideration, including with respect to reasonable alternatives; the magnitude of specific costs and benefits, and data or other information to estimate a dollar valuation; and any impact on the public interest factors specified in CEA section 15(a).
The Commission requested, but received no comments providing data or other information to enable the Commission to better quantify the expected costs and benefits attributable to the Final Order. In terms of qualitative cost and benefit comments, COPE stated that the Commission's Proposed Order creates confusion and inefficient, duplicative regulation, thus, imposing unnecessary costs.
Another commenter, NYSIO, asserted that the benefit of Commission
The Financial Marketers Coalition stated that excluding one set of market participants (
The Industrial Coalitions generally supported the Proposed Order, stating that the Commission's continued jurisdiction over fraud and manipulation in the ISO and RTO markets provides crucial ongoing market oversight necessary for market transparency and customer protection.
Regarding whether the Commission should extend the definitions of the transactions set forth in the Proposed Order to include “logical outgrowths” of the same, NEPOOL stated that absent such an inclusion, market participants and Requesting Parties would be required to seek additional exemptions from the Commission for relatively minor modifications to existing Tariffs and/or transactions, which in turn could dramatically increase the Commission's workload.
Regarding the proposed requirement related to the memorandum of counsel stating that their netting arrangements satisfy FERC regulation 35.47(d), the Requesting Parties stated that the Commission should forego that requirement as redundant with their existing obligations to FERC.
In response to a request for comment, the Requesting Parties stated that the Commission should not require RTOs and ISOs to have the ability to recreate Day-Ahead and RTM prices.
As discussed above, the Final Order makes certain determinations with respect to the scope of relief, including the scope of the Covered Transactions
The Final Order also sets forth certain conditions subsequent and conditions to the effectiveness of the exemption set forth therein. More specifically, two conditions subsequent relate to information requests by the Commission. First, the Commission must be able to obtain, either directly from ERCOT, or through FERC with respect to the other Requesting Parties, positional and transactional data within the Requesting Parties' possession for products in the Requesting Parties' markets that are related to markets subject to the Commission's
There are also two conditions to the effectiveness of the exemption set forth in the Final Order. For a Requesting Party subject to the jurisdiction of FERC, the exemption set forth in the Final Order is effective upon satisfaction of all of the following: (1) Submission and acceptance of a legal opinion or memorandum of outside counsel that is satisfactory to the Commission, in the Commission's sole discretion, and that provides the Commission with assurance that the netting arrangements contained in the approach selected by that Requesting Party to satisfy the obligations contained in FERC regulation 35.47(d) will, in fact, provide the Requesting Party with enforceable rights of set off against any of its market participants under title 11 of the United States Code in the event of the bankruptcy of the market participant; and (2) demonstration that the Requesting Party has fully complied with FERC regulation 35.47, as measured by FERC's acceptance and approval of all of the Requesting Party's submissions that are necessary to implement the requirements of FERC regulation 35.47.
In the discussion that follows, the Commission considers the costs and benefits of the Final Order to the public and market participants generally, and to the Requesting Parties specifically. It also considers the costs and benefits of the exemption described in the Final Order, in light of the public interest factors enumerated in CEA section 15(a).
The Final Order is exemptive and provides “appropriate persons” engaging in Covered Transactions relief from certain of the requirements of the CEA and attendant Commission regulations. As with any exemptive rule or order, the exemption in the Final Order is permissive, meaning that the Requesting Parties were not required to request it and are not required to rely on it. Accordingly, the Commission assumes that the Requesting Parties would rely on the exemption only if the anticipated benefits warrant the costs of the exemption.
In response to the comments of NYISO and others, the Commission is of the view that the Requesting Parties will experience minimal, if any, ongoing costs as a result of the determinations and conditions set forth in the Final Order because, as the Requesting Parties certify pursuant to Commission regulation 140.99(c)(3)(ii), the attendant conditions are substantially similar to requirements that the Requesting Parties and their market participants already incur in complying with FERC or PUCT regulations.
The requirement that all parties to the agreements, contracts, or transactions that are covered by the exemption in the Final Order must be (1) an “appropriate person,” as defined sections 4(c)(3)(A) through (J) of the CEA; (2) an “eligible contract participant,” as defined in section 1a(18)(A) of the CEA and in Commission regulation 1.3(m); or (3) a “person who actively participates in the generation, transmission, or distribution of electric energy,” as defined in paragraph 5(g) of the Order—is not likely to impose any significant, incremental costs on the Requesting Parties because their existing legal and regulatory obligations under the FPA and FERC or PUCT regulations mandate that only eligible market participants may engage in the Covered Transactions, as explained above.
The requirement that the Covered Transactions must be offered or sold pursuant to a Requesting Party's Tariff—which has been approved or permitted to take effect by: (1) In the case of ERCOT, the PUCT or; (2) in the case of all other Requesting Parties, FERC—is a statutory requirement for the exemption set forth in CEA section 4(c)(6) and therefore is not a cost attributable to an act of discretion by the Commission.
As described above, FERC and PUCT impose on the Requesting Parties, and their MMUs, various information management requirements. These existing requirements are not materially different from the condition that none of a Requesting Party's Tariffs or other governing documents may include any requirement that the Requesting Party notify a member prior to providing information to the Commission in response to a subpoena, special call, or other request for information or documentation. While the Commission is mindful that the process of changing Tariffs will cause the Requesting Parties to incur costs, those costs are necessary for the Commission to find that the exemption is in the public interest and consistent with the purposes of the CEA.
Requiring that an information sharing arrangement between the Commission and FERC be in full force and effect is not a cost to the Requesting Parties or to other members of the public because it has been an inter-agency norm since 2005. The requirement that the Requesting Parties comply with the Commission's requests on an as-needed basis for related transactional and positional market data will impose only minimal costs on the Requesting Parties to respond because the Commission contemplates that any information requested will already be in the possession of the Requesting Parties.
The legal opinion or memorandum of counsel requirement
The Commission's comprehensive action in this Final Order benefits the public and market participants in several substantial if unquantifiable ways, as discussed below. First, by considering a single application from all Requesting Parties at the same time, and deciding to allow all provisions of the exemption set forth in the Final Order to apply to all Requesting Parties and their respective market participants, the Final Order provides a cost-mitigating, procedural efficiency.
By cabining the Covered Transactions to the definitions provided in this Final Order, the Commission limits the potential that purely financial risk can accumulate outside the comprehensive regime for swaps regulation established by Congress in the Dodd-Frank Act and implemented by the Commission. The mitigation of such risk inures to the benefit of the Requesting Parties, market participants, and the public, especially electric energy ratepayers.
The condition that only appropriate persons may enter the Covered Transactions benefits the public, and the excluded market participants themselves, by ensuring that only persons with resources sufficient to understand and manage the risks of the transactions are permitted to engage in the same. Further, the condition requiring that the Covered Transactions only be offered or sold pursuant to a FERC- or PUCT-approved Tariff benefits the public by, for example, ensuring that the Covered Transactions are subject to a regulatory regime that is focused on the physical provision of reliable electric energy, and also has credit requirements that are designed to achieve risk management goals congruent with the regulatory objectives of the Commission's DCO and SEF Core Principles. Absent these and other similar limitations on participant- and financial-eligibility, the integrity of the markets at issue could be compromised, and members and ratepayers left unprotected from potentially significant losses resulting from purely financial, speculative activity. Moreover, the Commission's requirement that the Requesting Parties file an opinion of counsel regarding the right of set off in bankruptcy provides a benefit in that the analytical process necessary to formulate such an opinion would highlight risks faced by the Requesting Parties, and permit them to adapt their structure and procedures in a manner best calculated to mitigate such risks, and thus helps ensure the orderly handling of financial affairs in the event a participant defaults as a result of the Covered Transactions. Further, ensuring that the Requesting Parties have enforceable rights of set off against any of its market participants in the event of a bankruptcy of a market participant also provides a benefit in reducing costs to the Requesting Party that arise from a bankruptcy proceeding.
The Commission's retention of its authority to redress any fraud or manipulation in connection with the Covered Transactions protects market participants and the public generally, as well as the financial markets for electric energy products. For example, the Final Order is conditioned upon the Commission's ability to obtain certain positional and transactional data within the Requesting Parties' possession from the Requesting Parties. Through this condition, the Commission expects that it will be able to continue discharging its regulatory duties under the CEA. Further, the condition that the Requesting Parties remove any Tariff provisions that would require a Requesting Party to notify members prior to providing the Commission with information will help maximize the effectiveness of the Commission's enforcement program.
The chief alternatives to this Final Order relate to the scope of RTO and ISO market participants that are eligible for the exemption set forth therein, and the scope of Covered Transactions.
As discussed above in section IV.B.2.d.i., the Commission received several requests to include various subsets of market participants in the definition of “appropriate person” pursuant to 4(c)(3)(K) of the CEA for purposes of the exemption described in the Proposed Order, including requests to extend the exemption to (1) any persons who qualify under market participant standards set forth in FERC- or PUCT-approved Tariffs, (2) persons who actively participate in the generation, transmission, or distribution of electric energy, and (3) more specific requests to include particular market participants, such as CSPs, LSEs, and
Regarding the scope of Covered Transactions, the Commission considered the costs and benefits of various alternatives posed by commenters, including whether to expand the definition of Covered Transactions to include future products that are the “logical outgrowth” of existing products.
As explained above, the Commission does not foresee that the Final Order will have any negative effect on the protection of market participants and the public. More specifically, the Covered Transactions, in light of the representations of the Petitioners and in the context of their regulation by FERC and PUCT, do not appear to generate significant risks of the nature of those addressed by the CEA. The Commission has attempted to delineate the definitional boundaries for the Covered Transactions in a manner that appropriately ring-fences against the possibility that they could generate such risks, either now or as they may evolve in the future. In addition, the Commission has limited the exemption set forth in the Final Order to persons with resources sufficient to understand and manage the risks of the Covered Transactions. This requirement serves to protect excluded market participants and it minimizes the risk of potential misuse of the exempt transactions.
The Commission foresees little, if any, negative impact from the Final Order on the efficiency, competitiveness, and financial integrity of markets regulated under the CEA. Further, as an exercise of the Commission's CEA section 4(c) authority to provide legal certainty for novel instruments as Congress intended, the Final Order affords entities who partake of the exemption delineated therein transactional flexibility that the Commission understands to be valuable to their ability to efficiently deploy their limited resources.
The Commission does not believe that the Final Order will materially impair price discovery in non-exempt markets subject to the Commission's jurisdiction. As discussed above, the Covered Transactions are used to manage unique electric industry operational risks, which appears to make them ill-suited for exchange trading and/or to serve a useful price discovery function.
The Commission believes that the Final Order will promote the ability of RTOs, ISOs, and their market participants to manage the operational risks posed by unique electric energy market characteristics, including the non-storable nature of electric energy and demand that can and frequently does fluctuate dramatically within a short time-span. As discussed above, the Commission understands that the Covered Transactions are an important tool facilitating the ability of the Requesting Parties to efficiently manage operational risk in fulfillment of their public service mission to provide affordable, reliable electric energy.
In exercising its sections 4(c)(1) and 4(c)(6)(C) exemptive authority in the Final Order, the Commission is acting to promote the broader public interest by facilitating the supply of affordable, reliable electric energy, as contemplated by Congress.
Upon due consideration and consistent with the determinations set forth above, the Commission hereby issues the following Order:
Pursuant to its authority under section 4(c)(6) of the Commodity Exchange Act (“CEA” or “Act”) and in accordance with sections 4(c)(1) and (2) of the Act, the Commodity Futures Trading Commission (“Commission”)
1. Exempts, subject to the conditions and limitations specified herein, the execution of the electric energy-related agreements, contracts, and transactions that are specified in paragraph 2 of this Order and any person or class of persons offering, entering into, rendering advice, or rendering other services with respect thereto, from all provisions of the CEA, except, in each case, the Commission's general anti-fraud and anti-manipulation authority, and scienter-based prohibitions, under CEA sections 2(a)(1)(B), 4(d), 4b, 4c(b), 4
2.
a. The agreement, contract, or transaction is for the purchase and sale of one of the following electric energy-related products:
(1) “Financial Transmission Rights” defined in paragraph 5(a) of this Order, except that the exemption shall only apply to such Financial Transmission Rights where:
(a) Each Financial Transmission Right is linked to, and the aggregate volume of Financial Transmission Rights for any period of time is limited by, the physical capability (after accounting for counterflow) of the electric energy transmission system operated by a Requesting Party, as defined in paragraph 5(h) of this Order, offering the contract, for such period;
(b) The Requesting Party serves as the market administrator for the market on which the Financial Transmission Rights are transacted;
(c) Each party to the transaction is a member of the Requesting Party (or is the Requesting Party itself) and the transaction is executed on a market administered by that Requesting Party; and
(d) The transaction does not require any party to make or take physical delivery of electric energy.
(2) “Energy Transactions” as defined in paragraph 5(b) of this Order.
(3) “Forward Capacity Transactions,” as defined in paragraph 5(c) of this Order.
(4) “Reserve or Regulation Transactions” as defined in paragraph 5(d) of this Order.
b. Each party to the agreement, contract or transaction is:
(1) an “appropriate person,” as defined sections 4(c)(3)(A) through (J) of the CEA;
(2) an “eligible contract participant,” as defined in section 1a(18)(A) of the CEA and in Commission regulation 1.3(m); or
(3) a “person who actively participates in the generation, transmission, or distribution of electric energy,” as defined in paragraph 5(g) of this Order.
c. The agreement, contract, or transaction is offered or sold pursuant to a Requesting Party's Tariff and that Tariff has been approved or permitted to take effect by:
(1) In the case of the Electricity Reliability Council of Texas (“ERCOT”), the Public Utility Commission of Texas (“PUCT”), or
(2) In the case of all other Requesting Parties, the Federal Energy Regulatory Commission (“FERC”).
3.
4.
a. Information sharing:
(1) With respect to all Requesting Parties subject to the jurisdiction of FERC, information sharing arrangements between the Commission and FERC that are acceptable to the Commission continue to be in effect, and those Requesting Parties' compliance with the Commission's requests through FERC to share, on an as-needed basis and in connection with an inquiry consistent with the CEA and Commission regulations, positional and transactional data within the Requesting Parties' possession for products in the Requesting Parties' markets that are related to markets that are subject to the Commission's jurisdiction, including any pertinent information concerning such data.
(2) With respect to ERCOT, the Commission's ability to request, and obtain, on an as-needed basis from ERCOT, concurrently with the provision of written notice to PUCT and in connection with an inquiry consistent with the CEA and Commission regulations, positional and transactional data within ERCOT's possession for products in ERCOT's markets that are related to markets that are subject to the Commission's jurisdiction, including any pertinent information concerning such data, and ERCOT's compliance with such requests by sharing the requested information.
b. Notification of requests for information: With respect to each Requesting Party, neither the Tariffs nor any other governing documents of the particular RTO or ISO pursuant to whose Tariff the agreement, contract or transaction is to be offered or sold, shall include any requirement that the RTO or ISO notify its members prior to providing information to the Commission in response to a subpoena or other request for information or documentation.
5.
a. A “Financial Transmission Right” is a transaction, however named, that entitles one party to receive, and obligates another party to pay, an amount based solely on the difference between the price for electric energy, established on an electric energy market administered by a Requesting Party, at a specified source (
b. “Energy Transactions” are transactions in a “Day-Ahead Market” or “Real-Time Market,” as those terms are defined in paragraphs 5(e) and 5(f) of this Order, for the purchase or sale of a specified quantity of electric energy at a specified location (including virtual and convergence bids and offers), where:
(1) The price of the electric energy is established at the time the transaction is executed;
(2) Performance occurs in the Real-Time Market by either
(a) Delivery or receipt of the specified electric energy, or
(b) A cash payment or receipt at the price established in the Day-Ahead Market or Real-Time Market (as permitted by each Requesting Party in its Tariff); and
(3) The aggregate cleared volume of both physical and cash-settled energy transactions for any period of time is limited by the physical capability of the electric energy transmission system operated by a Requesting Party for that period of time.
c. “Forward Capacity Transactions” are transactions in which a Requesting Party, for the benefit of load-serving entities, purchases any of the rights described in subparagraphs (1), (2), and (3) below. In each case, to be eligible for the exemption, the aggregate cleared volume of all such transactions for any period of time shall be limited to the physical capability of the electric energy transmission system operated by a Requesting Party for that period of time.
(1) “Generation Capacity,” meaning the right of a Requesting Party to:
(a) Require certain sellers to maintain the interconnection of electric generation facilities to specific physical locations in the electric-energy transmission system during a future period of time as specified in the Requesting Party's Tariff;
(b) Require such sellers to offer specified amounts of electric energy into the Day-Ahead or Real-Time Markets for electric energy transactions; and
(c) Require, subject to the terms and conditions of a Requesting Party's Tariff, such sellers to inject electric energy into the electric energy transmission system operated by the Requesting Party;
(2) “Demand Response,” meaning the right of a Requesting Party to require that certain sellers of such rights curtail consumption of electric energy from the electric energy transmission system operated by a Requesting Party during a future period of time as specified in the Requesting Party's Tariff; or
(3) “Energy Efficiency,” meaning the right of a Requesting Party to require specific performance of an action or actions that will reduce the need for Generation Capacity or Demand Response Capacity over the duration of a future period of time as specified in the Requesting Party's Tariff.
d. “Reserve or Regulation Transactions” are transactions:
(1) In which a Requesting Party, for the benefit of load-serving entities and resources, purchases, through auction, the right, during a period of time as specified in the Requesting Party's Tariff, to require the seller of such right to operate electric facilities in a physical state such that the facilities can increase or decrease the rate of injection or withdrawal of a specified quantity of electric energy into or from the electric energy transmission system operated by the Requesting Party with:
(a) physical performance by the seller's facilities within a response time interval specified in a Requesting Party's Tariff (Reserve Transaction); or
(b) prompt physical performance by the seller's facilities (Area Control Error Regulation Transaction);
(2) For which the seller receives, in consideration, one or more of the following:
(a) Payment at the price established in the Requesting Party's Day-Ahead or Real-Time Market, as those terms are defined in paragraphs 5(e) and 5(f) of this Order, price for electric energy applicable whenever the Requesting Party exercises its right that electric energy be delivered (including Demand Response,” as defined in paragraph 5(c)(2) of this Order);
(b) Compensation for the opportunity cost of not supplying or consuming electric energy or other services during any period during which the Requesting Party requires that the seller not supply energy or other services;
(c) An upfront payment determined through the auction administered by the Requesting Party for this service;
(d) An additional amount indexed to the frequency, duration, or other attributes of physical performance as specified in the Requesting Party's Tariff; and
(3) In which the value, quantity, and specifications of such transactions for a Requesting Party for any period of time shall be limited to the physical capability of the electric energy transmission system operated by the Requesting Party for that period of time.
e. “Day-Ahead Market” means an electric energy market administered by a Requesting Party on which the price of electric energy at a specified location is determined, in accordance with the Requesting Party's Tariff, for specified time periods, none of which is later than the second operating day following the day on which the Day-Ahead Market clears.
f. “Real-Time Market” means an electric energy market administered by a Requesting Party on which the price of electric energy at a specified location is determined, in accordance with the Requesting Party's Tariff, for specified time periods within the same 24-hour period.
g. “Person who actively participates in the generation, transmission, or distribution of electric energy” means a person that is in the business of: (1) Generating, transmitting, or distributing electric energy or (2) providing electric energy services that are necessary to support the reliable operation of the transmission system.
h. “Requesting Party” means California Independent Service Operator Corporation (“CAISO”); ERCOT; ISO New England Inc. (“ISO NE”); Midwest Independent Transmission System Operator, Inc. (“MISO”); New York Independent System Operator, Inc. (“NYISO”) or PJM Interconnection, L.L.C. (“PJM”), or any successor in interest to any of the foregoing.
i. “Tariff.” Reference to a Requesting Party's “Tariff” includes a tariff, rate schedule or protocol.
j. “Petition” means the consolidated petition for an exemptive order under 4(c)(6) of the CEA filed by CAISO, ERCOT, ISO NE, MISO, NYISO, and PJM on February 7, 2012, as amended June 11, 2012.
6.
a. For a Requesting Party subject to the jurisdiction of FERC, the exemption set forth in this Order is effective upon satisfaction of all of the following:
(1) Submission and acceptance of a legal opinion or memorandum of outside counsel that is satisfactory to the Commission, in the Commission's sole discretion, and that provides the Commission with assurance that the netting arrangements contained in the approach selected by that Requesting Party to satisfy the obligations contained in FERC regulation 35.47(d) will, in fact, provide the Requesting Party with enforceable rights of set off against any of its market participants under title 11 of the United States Code in the event of the bankruptcy of the market participant; and
(2) Demonstration that the Requesting Party has fully complied with FERC regulation 35.47, as measured by FERC's acceptance and approval of all of the Requesting Party's submissions that are necessary to implement the requirements of FERC regulation 35.47.
b. For ERCOT, which is subject to the jurisdiction of PUCT, the exemption set forth in this Order is effective upon satisfaction of all of the following:
(1) Submission and acceptance of a legal opinion or memorandum of outside counsel that is satisfactory to the Commission, in the Commission's sole discretion, and that provides the Commission with assurance that the netting arrangements contained in the approach selected by ERCOT to satisfy standards that are the same as those contained in FERC regulation 35.47(d) will, in fact, provide the ERCOT with enforceable rights of set off against any of its market participants under title 11 of the United States Code in the event of the bankruptcy of the market participant; and
(2) Demonstration that ERCOT has fully complied with standards that are the same as those set forth in FERC regulation 35.47, as measured by PUCT permitting all of the necessary ERCOT protocol revisions to take effect; provided that the Commission will accept a demonstration that ERCOT has protocols in effect that substantially meet the settlement and billing period standards set forth in FERC regulation 35.47(b).
7.
This Order is based upon the representations made in the consolidated petition for an exemptive order under 4(c) of the CEA filed by the Requesting Parties
On this matter, Chairman Gensler and Commissioners Sommers, Chilton, O'Malia and Wetjen voted in the affirmative. No Commissioner voted in the negative.
I support the final order regarding specified electric energy-related transactions entered into on markets administered by regional transmission organizations (RTOs) or independent system operators (ISOs).
Congress authorized that these transactions be exempt from certain provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act as they are subject to extensive regulatory oversight by the Federal Energy Regulatory Commission (FERC) or, in one instance, the Public Utility Commission of Texas (PUCT).
This final order responds to a petition filed by a group of RTOs and ISOs and has benefitted from public input.
These entities were established for the purpose of providing affordable, reliable electric energy to consumers within their geographic region. In addition, these markets administered by RTOs and ISOs are central to FERC and PUCT's regulatory missions to oversee wholesale sales and transmission of electric energy.
The scope of the final order is carefully tailored to four categories of transactions—financial transmission rights; energy transactions; forward capacity transactions; and reserve or regulation transactions, which are offered or entered into a market administered by one of the requesting RTOs or ISOs. This exemption is conditioned on, among other things, each of these transactions being inextricably linked to the physical delivery of electric energy.
Centers for Medicare & Medicaid Services (CMS), HHS.
Final rule with request for comments.
This final rule implements the provisions of the Patient Protection and Affordable Care Act of 2010 and the Health Care and Education Reconciliation Act of 2010 (collectively referred to as the Affordable Care Act) relating to the availability of increased Federal Medical Assistance Percentage (FMAP) rates for certain adult populations under states' Medicaid programs. This final rule implements and interprets the increased FMAP rates that will be applicable beginning January 1, 2014 and sets forth conditions for states to claim these increased FMAP rates.
In commenting, please refer to file code CMS–2327–FC. Because of staff and resource limitations, we cannot accept comments by facsimile (FAX) transmission.
You may submit comments in one of four ways (please choose only one of the ways listed):
1.
2.
Please allow sufficient time for mailed comments to be received before the close of the comment period.
3.
4.
a. For delivery in Washington, DC—
(Because access to the interior of the Hubert H. Humphrey Building is not readily available to persons without Federal government identification, commenters are encouraged to leave their comments in the CMS drop slots located in the main lobby of the building. A stamp-in clock is available for persons wishing to retain a proof of filing by stamping in and retaining an extra copy of the comments being filed.)
b. For delivery in Baltimore, MD—
If you intend to deliver your comments to the Baltimore address, call telephone number (410) 786–7195 in advance to schedule your arrival with one of our staff members.
Comments erroneously mailed to the addresses indicated as appropriate for hand or courier delivery may be delayed and received after the comment period.
For information on viewing public comments, see the beginning of the
Richard Strauss, (410) 786–2019.
Comments received timely will be also available for public inspection as they are received, generally beginning approximately 3 weeks after publication of a document, at the headquarters of the Centers for Medicare & Medicaid Services, 7500 Security Boulevard, Baltimore, Maryland 21244, Monday through Friday of each week from 8:30 a.m. to 4 p.m. To schedule an appointment to view public comments, phone 1–800–743–3951.
We are providing additional opportunity for comment on the threshold methodology. In order to operationalize the methodology, the final rule contains significantly more detail about various aspects of the threshold methodology than originally included in the August 17, 2011 proposed rule. For example, the proposed rule included basic language regarding the treatment of disability status, resource (or asset) criteria, enrollment caps in states with section 1115 demonstrations, and spend-down eligibility provisions and we solicited public comments on how to account for these factors in assigning the appropriate FMAP. This increased detail in this final rule resulted in large part from our consideration of comments received from the public, including requests for additional clarity with respect to some of these matters. While we believe that this additional detail will assist states in implementing the threshold methodology, we recognize the complexity surrounding these issues. We are seeking additional comment on these provisions so that we can determine whether additional clarification would assist states to implement these aspects of the threshold methodology more effectively.
Although this final rule is effective 60 days from publication, the increased FMAPs authorized by the Affordable Care Act and codified here do not become effective until January 1, 2014. We are proceeding with the issuance of a final rule in light of the time constraints for states to implement system changes to implement the FMAP claiming methodology described in this rule. To the extent that any revisions to the final rule are warranted by new public comment, we will make necessary revisions well before the effective date.
In summary, while we are issuing these rules as final, we are providing the opportunity for further comment on parts of this rule to ensure transparency and allow for further clarifications that might be necessary. We are thus issuing certain provisions as final but are soliciting comments. These provisions
This final rule implements sections 2001(a)(3)(B) and 10201(c) of the Patient Protection and Affordable Care Act (Pub. L. 111–148, enacted on March 23, 2010), as amended by the Health Care and Education Reconciliation Act of 2010 (Pub. L. 111–152, enacted on March 30, 2010), and together referred to as the Affordable Care Act of 2010 (Affordable Care Act).
Specifically, this final rule implements the provisions of the Affordable Care Act related to the availability of increased FMAP rates under the Medicaid program with respect to the new adult eligibility group. The rule also describes a temporary general increase in FMAP rates for certain expansion states that meet required statutory criteria.
Although this rule is being issued in final, we remain interested in considering comments from the public on the following provisions:
In the August 17, 2011
This final rule addresses certain provisions that were included in the August 17, 2011 Medicaid Eligibility proposed rule but not included in the March 23, 2012 final rule. These provisions include implementation of statutory increases in the FMAP rates for state medical assistance expenditures relating to certain individuals described in the new adult eligibility group (new adult group) set forth at section 1902(a)(10)(A)(i)(VIII) of the Social Security Act (the Act), as amended by the Affordable Care Act, and a temporary general increase in FMAP rates in certain states that meet the definition of “expansion states.”
In particular, amendments made by section 2001(a)(3) of the Affordable Care Act added section 1905(y) to the Act effective January 1, 2014 to provide for an increased FMAP rate for expenditures for medical assistance for individuals who are defined as “newly eligible.” The statutory definition of newly eligible individuals at section 1905(y)(2) of the Act requires that such individuals be: (1) described in the new adult eligibility group at section 1902(a)(10)(A)(i)(VIII) of the Act and not under age 19 or such higher age as the state may have elected; (2) not eligible for full benefits, benchmark coverage described in subparagraphs (A), (B) or (C) of section 1937(b)(1) or benchmark-equivalent coverage under section 1937(b)(2) under the provisions of the state plan or under a waiver of the plan as of December 1, 2009; or (3) eligible but not enrolled (or on a waiting list) for such benefits or coverage under a waiver under the plan that has capped or limited enrollment that is full. Therefore, not all individuals enrolled in the eligibility group described in section 1902(a)(10)(A)(i)(VIII) of the Act (and in our corresponding regulation at § 435.119) will be “newly eligible” for FMAP purposes. Note that the newly eligible FMAP is available only for the 50 states and the District of Columbia; the United States territories are not included in the scope of the newly eligible FMAP under section 1905(y)(1) of the Act, which provides that the increased FMAP is at 100 percent for calendar years (CYs 2014, 2015, and 2016) and gradually declines to 90 percent by 2020, where it remains permanently.
Furthermore, amendments made by section 10201(b) of the Affordable Care Act added section 1905(z) to the Act effective January 1, 2014 to provide for an increased FMAP for expenditures for childless nonpregnant individuals in the new adult eligibility group in a defined “expansion state.” The expansion state FMAP is initially lower than the newly eligible FMAP; however it increases to be the same as the newly eligible FMAP effective January 1, 2019. Section 1905(z) also provides for certain expansion states to receive a 2.2 percentage point increase in FMAP rates for the medical assistance expenditures of all individuals who are not considered newly eligible (under the definition at section 1905(y) as summarized above) during the period January 1, 2014 through December 31, 2015. The August 17, 2011 proposed rule included provisions to implement these increased FMAP rates, and set forth options for states to quantify expenditures that would qualify for the increased FMAP rate.
The August 17, 2011 proposed rule included three possible methodologies for states to use in documenting claims for the increased FMAP for medical assistance expenditures for newly eligible individuals. The purpose of these proposed methodologies was to ensure that states would not need to operate dual eligibility determination systems, one to determine Modified Adjusted Gross Income (MAGI)-based financial eligibility, and the other to determine the appropriate FMAP based on the pre-2014 eligibility rules. Each of these three methods was intended to capture the expenditures that would be claimed in accordance with the requirements of the statute. We also solicited comment on whether other methods would accomplish these goals.
In this issuance, we discuss our consideration of public comments on the FMAP calculation issues included in the August 17, 2011 proposed rule, and set forth final rules to define the increased FMAP rates and set out the threshold methodology which states will be required to use to document claims for the increased FMAP rates. As described in more detail below, the threshold methodology begins with a simplified method for determining the individuals who are and are not newly eligible, comparing their MAGI-based income (as calculated for purposes of eligibility determination) to the effective income thresholds for relevant eligibility categories in effect in December 2009, converted to a MAGI-based equivalent. It then describes, and in some cases, offers states options, regarding the treatment of other factors
The following summarizes the FMAP-related provisions that were discussed in more detail in the Medicaid Eligibility proposed rule (76 FR 51172 through 51178):
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We received 813 comments from state Medicaid and CHIP agencies, policy and advocacy organizations, health care providers and associations, Tribes, Tribal organizations, and individual citizens regarding the August 17, 2011 eligibility proposed rule, including 87 comments on the FMAP provisions. In addition, to support the goal of transparency, we conducted a number of webinar and other consultation sessions with states and interested parties in which we presented the FMAP provisions of the proposed rule and participants were afforded an opportunity to ask questions and make comments. At these consultation sessions, the public was reminded to submit written comments before the close of the public comment period that was announced in the August 2011 Medicaid Eligibility proposed rule. In addition, we worked more intensively with 10 pilot states to discuss and test different elements of the proposed regulation, with a particular emphasis on income conversion and application of appropriate FMAP claiming methodologies. Because of the technical aspects of the FMAP provisions related to the new adult group, in addition to evaluating the comments received on the proposed rule, we performed additional research on this topic to better understand which approaches would maximize the accuracy of the increased FMAP and further the simplification goals of the Affordable Care Act. We have revised the proposed regulation to respond to public comments and reflect our final policies.
We received a number of comments concerning the proposed FMAP methodologies for newly eligible individuals and for the expansion state provisions. The majority of comments on the three methodologies described in the proposed rule supported the “threshold methodology,” described in section IV of this final rule, and did not support certain aspects of the other proposed methodologies. Consistent with these comments, as discussed below, this final rule adopts the threshold methodology as the methodology to be used to document claims for the increased FMAPs. Summaries of the public comments that are within the scope of the proposals and our responses to those comments follow; more detailed summaries of the key changes in the final regulation are also included in section IV of this final rule, “Provisions of the Final Rule.” Some of the comments received were outside the scope of the FMAP provisions contained in the Medicaid Eligibility proposed rule and, therefore, are not addressed in this final rule. In some instances, commenters raised policy or operational issues that will be addressed through regulatory and subregulatory guidance subsequent to this final rule.
Some commenters addressed items of a general nature in their comments, as described below. Numerous commenters requested clarification about whether expenditures for certain categories of individuals will be matched at the increased newly eligible or expansion state FMAP. We reiterate in the preamble and in the provisions of this final rule that under the statute the increased newly eligible and expansion state FMAPs are only available to individuals enrolled in the new adult group described at § 435.119. Therefore, for example, former foster care children enrolled in the new group described in proposed regulation at § 435.150 (78 FR 4687) are not eligible for the newly eligible FMAP because they will not be enrolled under § 435.119. As our proposed regulation explains (78 FR
The August 17, 2011 proposed rule would have amended part 433 to add new provisions at § 433.10(c) to indicate the increases to the FMAPs available to states under the Affordable Care Act. We received numerous comments on these provisions and are revising the final rule to account for many of the comments.
In § 433.10(c)(6), we proposed to add a new paragraph to indicate the increased FMAP rates available to states beginning January 1, 2014 for the medical assistance expenditures of individuals determined eligible under the new adult group who are considered
CMS proposed new regulatory text to indicate the availability of additional FMAP rates for states that expanded eligibility prior to enactment of the Affordable Care Act. CMS did not receive any comments about the temporary increased FMAP reflected in proposed § 433.10(c)(7), which describes a 2.2 percentage point increase available only to a state that meets very specific criteria established in section 1905(z)(1) of the Act. CMS received numerous comments regarding the definition and methodology to apply the expansion state FMAP set forth in § 433.10(c)(8), which seeks to codify section 1905(z)(2) of the Act. The expansion state FMAP is available for expansion states for the expenditures of certain nonpregnant childless adults who are determined eligible under the adult group, and who are not considered to be newly eligible, as defined in section 1905(y)(2)(A) of the Act. For this purpose, in this final rule, we define a nonpregnant, childless adult as an individual who is not determined eligible for Medicaid on the basis of pregnancy and who does not meet the definition of a parent caretaker relative in § 435.4.
In the August 17, 2011 proposed rule, CMS proposed only one new FMAP-related definition, that of “newly eligible.” We proposed to define “newly eligible” to mean an “individual eligible for Medicaid in accordance with the requirements of the new adult group and who would not have been eligible for Medicaid under the state's eligibility standards and methodologies for the Medicaid state plan, waiver or demonstration programs in effect in the state as of December 1, 2009.” Numerous commenters suggested revisions to our proposed definition to more accurately reflect the statutory definition and to avoid improperly denying certain states the increased FMAP. In this final rule, we are revising the proposed definition and providing other related definitions in final § 433.204 as described below.
If effective January 1, 2014 the state lowers the eligibility income standards used to determine eligibility for the parent and caretaker relative group below the levels in effect on December 1, 2009 for that group, resulting in certain individuals who would have been eligible for the group as of December 1, 2009, having income greater than the revised standard, such individuals may become eligible under the new adult group and some could potentially be newly eligible. For example, if the state's eligibility category for parent/caretaker relatives had a resource test in December 2009, and such individuals would have failed that test, the state could factor such individuals into its claim for newly eligible FMAP in accordance with § 433.206(d).
In addition, if the state had raised its income standard for its mandatory eligibility category for parents and other caretaker relatives after December 2009, the individuals now covered in the new adult group whose incomes are above the December 2009 standards would be newly eligible.
The August 17, 2011 proposed rule (76 FR 51148) provided for three possible methodologies that could potentially be available to states to claim expenditures at the appropriate FMAP for individuals determined eligible in the new adult group. As proposed, § 433.206 set out principles for these methodologies; enumerated the methodologies described in more detail in proposed § 433.208, § 433.210, and § 433.212; proposed to permit states to select any of these methodologies; and set out a process for states to make their initial and subsequent selections of methodology. The proposed rule indicated the possibility that these three approaches could be modified, narrowed, or combined based on comments received and the results of a feasibility study, including site visits to, and discussions with, 10 pilot states. We requested comment on the methodologies themselves, whether other options should be considered, and whether states should be able to choose from such alternatives or different methods, or whether a single method should be used by all states. We received numerous comments on these issues. After assessment of the comments received, we are continuing to apply the following principles as expressed in the proposed rule:
• Any methodology must provide as accurate and valid application of the applicable FMAPs to actual expenditures as possible in the determination of the appropriate amounts of federal payments for such expenditures. The methodology must not include a systemic bias in favor of either the states or the federal government.
• Any allowable methodology should minimize administrative burdens and costs to states, the federal government, individuals, and the health care system.
• Any methodology must be developed and applied transparently by both the federal government and states.
• Any methodology must take into consideration the practical, programmatic and operational goals of the Medicaid program.
• To ensure that the states claim expenditures at the correct FMAP, any methodologies should include sufficient data to identify, associate and reconcile expenditures with the related eligibility group to which the FMAPs apply. The increased newly eligible and expansion state FMAPs are only available for individuals enrolled under § 435.119 of this chapter.
On the basis of the comments received and the analysis of the feasibility of each of the alternatives, including input from pilot states and analyses of pilot states' information, we believe that the threshold methodology best addresses these principles and is the method identified in this final rule as the one that shall be used by states for purposes of claiming expenditures at the appropriate FMAP for individuals determined eligible in the new adult group.
As described briefly above and in more detail in section IV of this rule, in general, under the threshold methodology, states will compare income levels of individuals eligible for the new adult group to equivalent December 2009 standards to determine if that individual could have qualified for Medicaid under the State's December 2009 income standards. More specifically, the threshold methodology proposed using MAGI-converted income thresholds (as described in CMS' December 28, 2012 letter to State Medicaid Directors and Health Officials (SHO #12–003, available at:
Since we are finalizing only one methodology, some of the provisions of the proposed § 433.206 are inapplicable. Below is a summary of the public comments that we received with respect to proposed § 433.206 through § 433.212. The discussion begins with the general comments about the choice of methodology, focusing on the threshold methodology since that is the methodology being finalized and is relevant to our responses to other comments discussed throughout this section.
Proposed § 433.208, which is being redesignated as § 433.206 in this final rule, described the first of three proposed approaches to identify newly eligible individuals for purposes of applying the correct enhanced FMAP rate. We sought comment on the methodology as proposed and on the use of proxies of eligibility criteria in place prior to CY 2014 that are not related to income, such as disability status and resource value.
In the proposed rule, CMS articulated several principles that would drive our selection of a methodology (or methodologies) to accurately reflect the appropriate FMAP. One principle was to minimize the administrative burdens and costs to states, the federal government, individuals, and the health care system. We also noted that requiring states to run two distinct eligibility systems—one for purposes of eligibility using new MAGI methodologies and one that would exactly retain all of the eligibility requirements of states' Medicaid programs as in effect on December 1, 2009 for purposes of determining which individuals are newly and not newly eligible—would pose challenges and create unnecessary burdens, inefficiencies, and administrative costs to applicants, states, and the federal government. Because retaining and applying two different sets of eligibility rules is burdensome and costly to states and the federal government, a barrier to enrollment for eligible individuals and families, and would likely lead to inaccurate determinations, we identified possible alternative approaches for determining the appropriate FMAP rate. We proposed not to permit FFP for the costs of maintaining dual eligibility systems for the adult group and instead proposed methodologies to enable states to determine FMAP without needing to run dual eligibility systems. We remain committed to that principle in this final rule, which establishes the threshold methodology as a simplified approach to apply the eligibility criteria effective on December 1, 2009.
As described below, this rule provides states with the option to develop one-time sampling data to help determine the proportion of individuals enrolled under the new adult group who would qualify as newly eligible because they would have been found ineligible for Medicaid in 2009 due to excess resources. To the extent that states take advantage of a time-limited opportunity (described below) to gather sampling data to develop an accurate resource proxy, those questions will not be permissible as part of the application, cannot affect the application, and cannot delay determinations of eligibility. Effective January 1, 2014,
In the proposed rule (76 FR 51148, 51175), we indicated we were considering using either a disability proxy methodology or using only actual disability determinations under the threshold methodology to determine if an individual may have been eligible under the state's December 1, 2009 standards based on disability. The disability status of an individual may be relevant in two ways. First, a disabled individual may be eligible under section 1902(a)(10)(A)(i)(II) of the Act for Medicaid based on receipt of supplemental security income (SSI) or such more stringent standards that a state may have under the election at section 1902(f) of the Act (the “209(b)” option), in which case the individual would not be eligible under the new adult group and should be excluded from the universe to which the threshold methodology applies. Second, a disabled individual may have been eligible in an optional eligibility category in effect under a state's December 1, 2009 Medicaid program at higher income levels than adults without disabilities, which would mean that they would not be considered newly eligible.
We received numerous comments in response to our request for feedback on this issue. In general, commenters encouraged CMS to avoid asking applicants additional questions and urged CMS to clarify expectations in the regulation. Based on comments received, we are not finalizing a disability proxy. Rather, only an actual disability determination will be used for purposes of determining whether an individual enrolled in the new adult group will be newly eligible. This approach is described in more detail in section IV and is reflected in § 433.206(c)(4).
In general, the threshold methodology is designed to properly assign the applicable FMAP to the expenditures of individuals eligible in the new adult group under § 435.119. The threshold methodology provides for states to use the applicable state plan or demonstration eligibility income standard converted to a MAGI-equivalent for each eligibility group as in effect in the state on December 1, 2009 to determine whether an individual is considered to be newly eligible for purposes of assigning a federal matching rate. Although the threshold methodology is individualized, we are finalizing this rule to include certain population-based adjustments, or proxies, to account for resource standards and, as applicable, enrollment caps or limits.
In the proposed eligibility rule, we proposed several ways in which the threshold methodology could account for a resource (or asset) test that was applied to the applicants' coverage category as of December 2009, since resources will no longer be part of the eligibility determination for populations whose income will be determined using MAGI rules. We solicited comments on these various alternatives, as well as on the feasibility of using the Asset Verification System (AVS) as a tool to obtain resource information, as necessary. We received a variety of comments on these varied approaches.
The August 17, 2011 proposed rule stated that CMS does not believe that, for FMAP determination purposes, states need to consider whether an individual enrolled in the new adult group would have been eligible under a spend-down for a medically needy category under section 1902(a)(10)(C) of the Act in considering whether someone would have been eligible under standards in effect in December 1, 2009. We explained that this is because we believe there is an inherent uncertainty in determining whether and when a spend-down would have been met. An individual who is eligible for the new adult group and whose income is above the December 1, 2009 medically needy income standard would be considered newly eligible. If an individual would have qualified by meeting the medically needy income standard without a spend-down, the state could not claim newly eligible FMAP for that individual. We requested comment on this analysis and received numerous responses, which we have used to add more detail to the final threshold methodology regulation at § 433.206(f).
In light of the proposed rules that identified potential alternate FMAP claiming methodologies, § 433.206(b) of the August 2011 proposed rule proposed that a state provide notice to CMS of which methodology it plans to use at least two calendar years prior to the first day of the calendar year in which the state would have used the particular method. For 2014, we proposed that states would give notice to CMS no later than one year prior to the beginning of the CY, which is January 1, 2013.
Supplemental payments made by a state under its Medicaid state plan that are based on the upper payment limit (UPL) are always identifiable with specific services furnished to individuals not enrolled in managed care. Accordingly, a state could claim the new increased FMAPs for such supplemental payments when identified with a service furnished to a newly eligible individual (or a qualified nonpregnant childless adult in expansion states). We note that a state may need to work with CMS to develop such a UPL demonstration.
As originally proposed in § 433.210, one methodology to assign FMAP would
Other commenters noted that the sampling methodology would be administratively burdensome to develop and would place additional burdens on enrollees, including requests for information not required for eligibility. Other commenters noted that the proposed regulation appropriately required verification of the sampling results, but it is not clear how results can be verified without states retaining December 1, 2009 standards. Commenters also noted that if enrollees refused to undergo a full eligibility determination for purposes of FMAP, states would face additional administrative burdens in creating the statistically valid sample. Furthermore, other commenters noted that, at least for states that had not previously expanded Medicaid using section 1115 demonstrations, the statistically valid sampling methodology would not be applicable during the initial years of the Medicaid expansion (2014 through 2019) because states would not have applicable data for sampling purposes. Another commenter noted that the level of accuracy of the sampling method would depend on whether or not “newly eligibles” are more or less expensive than other adults.
One commenter noted that the sampling methodology would require a highly complex system to create a readily reviewable audit trail between the individual claim transaction and corresponding disposition on the CMS–64. Another commenter also noted that use of data sources like the Medical Expenditure Panel Survey (MEPS) or Medicaid Statistical Information Statistics (MSIS) will take some time to establish as reliable data elements.
As originally proposed in § 433.212, the proportion methodology would have used an extrapolation from available data sources to determine the proportion of individuals covered under the new adult group who would not have been eligible under the eligibility category in effect under the state plan or applicable waiver as of December 1, 2009, validating and adjusting the estimate, based on sampling or some other mechanism going forward.
Some commenters further qualified their support for the proportion methodology by noting some data concerns. They noted that while they support the use of Medical Expenditure Panel Survey (MEPS), MSIS and Current Population Survey (CPS) data as the foundation for the implementation of the proportion method, they had concerns, especially for smaller states, with MEPS and CPS data. One commenter warned about survey margins of error and noted that the MEPS does not provide individual estimates for the 50 states, thus requiring additional imputation of the survey.
This final rule incorporates certain provisions set forth in the Medicaid Eligibility proposed rule and reflects revisions made based on comments received on the proposed rule. The following describes the provisions of this final rule:
The provisions of § 433.10(c)(6) describe the availability and amounts of the increased FMAP for newly eligible adults, as defined in § 433.204(a)(i), who are enrolled in the new adult group described in § 435.119 of this chapter. In response to comments and questions from the public about whether states that meet the definition of expansion states (which this rule redesignates from § 433.10(c)(8)(iii) in the proposed rule and codifies at § 433.204(b)) may receive the newly eligible FMAP, we revised § 433.10(c)(6)(i) to clarify that the increased FMAP for newly eligible individuals can be applied in states that meet the definition of expansion state. As discussed in the proposed rule (76 FR 51147, 51173 (August 17, 2011)), if a population covered by a state that qualifies as an expansion state meets the criteria for the newly eligible matching rate, the state will receive the newly eligible matching rate for expenditures for that population. The expansion state match is designed to help states that expanded coverage to adults prior to enactment of the Affordable Care Act to the extent that a particular expansion population does not qualify as newly eligible.
In accordance with section 1905(z)(1)(A) of the Act, § 433.10(c)(7) describes the availability of a temporary 2.2 percentage point increase in the regular FMAP for a state that meets three conditions specified in the regulation:
• The state meets the definition of expansion state in § 433.204(b);
• The state does not qualify for any payments for the medical assistance expenditures of newly eligible individuals under the newly eligible FMAP in § 433.10(c)(6); and
• The state has not been approved to divert a portion of its disproportionate share hospital allotment under a demonstration in effect on July 1, 2009.
Although in this final rule we are not making any substantive revisions to § 433.10(c)(7) as was contained in the proposed rule, the following provides clarification regarding this provision. If a state meets the three indicated conditions, then the regular FMAP in § 433.10(b) is increased as follows:
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In response to comments and for purposes of clarification, proposed § 433.10(c)(8)(iv) was deleted as redundant. As discussed above, § 433.10(c)(6)(i) as revised clarifies that the newly eligible FMAP is available for newly eligible individuals in an expansion state. However, § 433.10(c)(8)(iv), as contained in the proposed rule, also referred to the availability of the newly eligible FMAP for certain individuals in an expansion state. We believe the reference in the revised § 433.10(c)(6)(i) makes clear that the newly eligible FMAP is available for newly eligible individuals in expansion states.
Section 433.202, which sets out the scope of the FMAP provisions for the new adult eligibility category in § 435.119, is revised to indicate explicitly in regulation the increased or regular FMAP rates that are potentially available, as applicable, for the medical assistance expenditures associated with individuals in the new adult eligibility group: the regular FMAP, the increased newly eligible FMAP, or the increased expansion state FMAP, as indicated in § 433.10(b) and (c).
Section 433.204 is revised to include the definition of newly eligible individual in the renumbered § 433.204(a)(1), which now indicates that the determination of an individual as newly eligible is in accordance with the requirements of § 433.206, the revised and renumbered threshold methodology.
• The definition of newly eligible individual in § 433.204(a)(1) is clarified to follow the statutory definition in section 1905(y)(2)(A) of the Act and, in particular, to refer to individuals who would not have been eligible for full benefits, benchmark coverage, or benchmark equivalent coverage as of December 1, 2009. Section 433.204(a)(1) as revised refers to the regulations in § 440.330 and § 440.335, referring to benchmark and benchmark equivalent coverage, respectively. These changes were necessary to more accurately reflect the statutory language of the Affordable Care Act, which was not included in the proposed rule. Individuals enrolled in § 435.119 who could have previously received full
As described in § 433.204(a)(3), states with section 1115 demonstrations that provided benefits to adult populations that are more limited than standard state plan benefits will need to analyze the benefit package that was offered so that CMS can determine the appropriate FMAP to apply to specific populations who were enrolled in Medicaid as of December 1, 2009. As CMS explained in FAQ guidance issued in February 2013 at
• The definition of newly eligible at § 433.204(a)(1) has also been clarified to include the provision in statute that describes as newly eligible those individuals in the new adult group who, as of December 1, 2009, would have been eligible but not enrolled (or could have been on a waiting list) for benefits or coverage through a waiver under the plan that has a capped or limited enrollment that is full.
Section 433.204 is revised to add a new § 433.204(a)(2) to include the statutory definition of “full benefits” from section 1905(y)(2)(B) of the Act, which describes “full benefits” to mean those benefits required to be provided to mandatory adult populations under the state plan, or such benefits that are not less in amount, duration, or scope than the benefits offered to the mandatory populations, or benefits that are determined by the Secretary to be substantially equivalent to the medical assistance available for the mandatory populations. Adult populations covered by a state under a section 1115 demonstration under which any associated waivers of state plan requirements did not provide for any reduction of the benefits relative to those offered to the mandatory populations under the state plan are presumed to have received full benefits under the demonstration; that is, full benefits are presumed unless approved terms and conditions of the demonstration explicitly provided for a lesser benefit package.
A new § 433.204(b)(1) is added to include the definition of “expansion state,” moving the definition from the proposed § 433.10(c)(8)(iii). We also clarified in a new § 433.204(b)(2), for purposes of applying the expansion state FMAP in § 433.10(c)(8) that a “nonpregnant childless adult” is an individual who is not eligible based on pregnancy and who does not meet the definition of a caretaker relative in § 435.4.
In the proposed rule § 433.206 referred to the “Choice of Methodology.” This regulatory provision is deleted in this final rule and the remaining sections are renumbered accordingly.
Previously numbered as § 433.208 “Threshold Methodology” in the proposed rule, this final rule redesignates this section of the regulation as § 433.206. Under the threshold methodology, for individuals enrolled under § 435.119, the applicability of the newly eligible FMAP is determined, in part, by comparing individuals' MAGI-based income to converted MAGI-based income eligibility levels for each appropriate eligibility group as in effect on December 1, 2009 (this conversion process was described in a State Health Official letter #12–003, dated December 28, 2012).
The following highlights, by section, revisions to provisions of the proposed rule and, as appropriate, provides further description of revised provisions. The following provisions are being issued as final with an opportunity for comment: § 433.206(c)(4), § 433.206(d), § 433.206(e), § 433.206(f), and § 433.206(g).
This paragraph specifies that the threshold methodology must be used by states to document claims for the newly eligible FMAP specified in § 433.10(b) and (c). The threshold methodology encompasses an individualized analysis of whether individuals determined eligible under § 435.119 are newly or not newly eligible individuals for purposes of determining the appropriate federal share of medical assistance expenditures. We note that for certain aspects of the threshold methodology, such as the treatment of resources and enrollment caps, states have options in applying the methodology, which may be based on either population or total medical assistance expenditures. Such options are addressed in the related regulation sections.
In general, this rule clarifies that the threshold methodology is designed to assign the applicable FMAP to the medical assistance expenditures only for individuals determined eligible under § 435.119. The methodology begins with a simplified method for determining the individuals who are and are not newly eligible based on MAGI-based income (as already determined for purposes of establishing eligibility under § 435.119) and disability status, and then offers states options for how they will adjust the results to take into account other factors that may be relevant to assess the appropriate FMAP; in particular, resources, and enrollment caps and limits to the extent that a cap or limit was in effect in a state for an applicable eligibility group in December 2009. These factors will not be accounted for in MAGI-converted income standards but have bearing on determining whether claims for individuals enrolled under § 435.119 can be matched at the
This section of the threshold methodology regulation indicates general principles underlying the establishment and application of the threshold methodology. In accordance with these principles, the threshold methodology: must not affect the timing of any individual's eligibility determination; must not be biased; must provide for a valid and accurate accounting of medical assistance expenditures and claims for federal funding for Medicaid claims; and operate efficiently, without further review, once an individual has been determined not to be newly eligible based on the December 1, 2009 standards for any eligibility category.
To clarify the threshold methodology, the final § 433.206(c) now indicates the basic components of the methodology. This section references the use of individuals' MAGI-based income determinations as established under the 2014 eligibility requirements; the threshold methodology does not require determining individuals' income under the income rules in effect as of December 1, 2009:
• The threshold methodology applies for individuals determined eligible and enrolled under § 435.119; the regulation clarifies that the threshold methodology is not applicable for individuals who have been determined eligible and enrolled under any other mandatory or optional Medicaid eligibility category.
• Under the threshold methodology, the individuals' MAGI-based income (as determined under the rules in effect as of January 1, 2014) is compared to converted MAGI-based income eligibility levels for each appropriate eligibility group as in effect on December 1, 2009. Appropriate eligibility groups include, for example, parent/caretaker relative groups, section 1115 demonstration expansion populations, and optional disabled groups. CMS is currently working with states to convert those standards. If an individual in the new adult group would only have qualified for a December 1, 2009 eligibility group which did not offer full benefits, benchmark coverage, or benchmark equivalent coverage, they will be considered newly eligible for FMAP determination purposes regardless of income;
• Finally, states must ensure that for purposes of the availability and applicability of the applicable FMAPs for individuals, the determination of such individuals' status as newly or not newly eligible continues until a new determination of MAGI-based income has been made, in accordance with § 435.916, or until the individual has been otherwise determined not to be covered under the adult group set forth at § 435.119 of this chapter. Section 433.206(c)(4) describes, for example, the treatment of individuals for whom a determination of disability alters the applicable FMAP.
Under this process, an individual enrolled in the new adult group with income at or below the converted MAGI-based income eligibility standard for a relevant December 1, 2009 eligibility group related to that individual's characteristics and who would have been eligible to receive full benefits, benchmark benefits, or benchmark-equivalent benefits as of December 1, 2009 would be considered as not newly eligible and the FMAP applicable to such individuals would apply; this would be the regular FMAP or the expansion FMAP for applicable individuals, in expansion states. An individual in the new adult group whose income is greater than the converted income eligibility standard for December 1, 2009 for the relevant eligibility group related to that individual's characteristics would be considered as newly eligible and the newly eligible FMAP applicable to such individuals may apply.
The disability status of an individual may be relevant with respect to establishing whether the individual would have been eligible under an eligibility category that was in effect on December 1, 2009 for which disability is a criteria. In that case, if the individual could be determined eligible based on disability and the financial criteria applicable for such December 1, 2009 eligibility category, the individual would not be considered to be newly eligible for purposes of applying the appropriate FMAP for the expenditures associated with such individual. For this reason, to establish the applicable FMAP, it is necessary to establish whether the individual met the appropriate definition of disability applicable for a state.
For purposes of establishing disability status with respect to determining whether an individual meets the definition of newly eligible, in the proposed rule we indicated we were considering using either a disability proxy methodology or using actual disability determinations under the threshold methodology. In recognition of the disability determination process currently used by states and the Social Security Administration, we have concluded that for purposes of applying the appropriate FMAP under the threshold methodology, only an actual disability determination can be used to establish whether an individual should be considered to be disabled as relates to meeting the definition of newly eligible. That is, absent an actual determination of disability made in accordance with the disability definition applicable for the state under Title XIX of the Act, an individual enrolled in the new adult group should be considered not disabled for any FMAP determination purpose, regardless of any indication of disability provided by the individual. Therefore, in general, with respect to any eligibility categories in effect on December 1, 2009 for which a disability determination was required, individuals eligible for the new adult group who do not have an actual determination of disability would be considered newly eligible.
Individuals who are disabled have an incentive to seek a disability determination to receive financial support based on disability; therefore, an actual disability determination under the established disability determination process may be initiated by and for such individuals. In circumstances in which a disability determination process is initiated, the individual will be considered not to be disabled for FMAP determination purposes while the disability determination is pending.
In determining which expenditures can be claimed under the newly eligible matching rate relative to expenses for an individual who eventually is determined disabled, the application of the FMAP methodology is not intended to revise existing claiming rules. In particular, the FMAP applicable for provider claims paid by a state is generally determined based on when the state made the payment to the service provider; the application of the appropriate FMAP is not generally based on the date the service is provided. Therefore, the FMAP applicable for payments made by a state subsequent to the date of the disability determination would reflect any change in the individual's status as newly eligible and/or the individual's actual eligibility status; for example, if receiving a disability determination results in the individual becoming eligible under an eligibility category other than the new adult group, any FMAPs associated with the new adult group would not be applicable to claims paid after the change in status.
We developed this approach to support our general principle of providing states with certainty and avoiding retroactive recoupment of dollars from states. Numerous commenters also reinforced the concept that any selected methodology should minimize the need for retroactive financial adjustments to avoid subjecting states to financial uncertainty; this approach is consistent with those comments. While current practice requires states to adjust claiming back to the date of onset of the disability determination, we think creation of the new adult group gives us an alternative because individuals have a way to receive services during the period of the pending disability determination.
Finally, although we recognize that under normal circumstances the disability process may take a significant period of time to be completed, we do not wish to incentivize states to prolong this process—to the extent they play a role in conjunction with the Social Security Administration in determining disability—by providing the increased newly eligible FMAP during the period when the disability determination is pending. Therefore, to ensure timely determinations of disability status, we will closely monitor state implementation of the threshold methodology and develop safeguards, such as performance standards related to timeliness of disability determinations and work with states to ensure that such performance standards are satisfied. We will work with the Social Security Administration to continue to consider ways to expedite such determinations.
In this final rule, a new § 433.206(d) is added to indicate how resource criteria may be applied for purposes of determining the availability of an increased FMAP for the expenditures of newly eligible individuals (as described in § 433.204(a)(1)).
For the new adult group under § 435.119, which is effective beginning January 1, 2014, there is no resource test (sometimes called an “asset test”) applied in determining individuals' eligibility. However, some individuals in the new adult group might have had income below the applicable income standards in effect in December 2009 but would not have been eligible due to resources. Under the threshold methodology, for FMAP purposes a state can account for the effect of resource standards in effect in December 2009.
To promote simplification and flexibility, in this final rule CMS is providing states the option of not applying a resource proxy. A number of states have indicated that resources did not keep many individuals from qualifying for Medicaid, and imposing a resource proxy for purposes of determining the applicable FMAP might be administratively burdensome and yet not yield a very different result than if no resource proxy were used. Therefore, § 433.206(d)(1) allows states to choose whether to apply a resource proxy methodology under the threshold methodology. For a state that elects not to impose a resource proxy methodology, the increased FMAP under § 433.10(c)(6)(i) would not apply to the medical assistance expenditures of individuals determined eligible under the adult group whose incomes are at or below the applicable income levels for the eligibility categories in effect on December 1, 2009.
For states that elect to apply a resource proxy methodology, as described in greater detail below, this rule also provides for two options for states to address the application of resource criteria which were applied to applicable eligibility groups under a state's Medicaid program as in effect on December 1, 2009:
• A state could elect to collect and use existing state data prior to January 1, 2014 related to denials of eligibility explicitly due to excess resources; or
• A state could elect to obtain similar data through sampling of beneficiaries in eligibility categories relevant to the adult group (for periods prior to January 1, 2014), or eligible and enrolled in the new adult group (for periods on or after January 1, 2014).
A state may elect to apply a resource proxy methodology under the threshold methodology with respect to a particular eligibility category that had a resource test in effect on December 1, 2009, or the state could apply the resource proxy methodology to all relevant eligibility categories that had a resource test in effect on December 1, 2009.
Consistent with previously issued regulations, the development of a resource proxy methodology must not delay or interfere with the eligibility determination for an individual nor rely on information from applicants or beneficiaries if such information is available electronically. Particularly for states that undertake a resource proxy sample on or after January 1, 2014, when new MAGI methodologies are in effect and resources are no longer a criteria for eligibility determinations, states may not require individuals to provide information that is not necessary for the determination of eligibility, such as resource information for purposes of determining FMAP. However, states are not precluded from asking for such information, if it is not available electronically through an accessible data base or through electronic means, for example, after an applicant has completed an application. Such requests may not be part of the formal application process, and states must provide applicants or beneficiaries with clear notice that the information solicited is not required for purposes of
Section 433.206(d)(2) describes the standards for the resource proxy methodology. In particular, the resource proxy methodology must be based on state-level data, which would be used to identify the percentage of denials of Medicaid eligibility over a period of time due to excess resources. The state data must either be existing data from and for periods before January 1, 2014 related to denials of eligibility explicitly due to excess resources, or data obtained through a statistically valid sample of beneficiaries in eligibility categories relevant to the new adult group (for periods prior to January 1, 2014) or eligible and enrolled in the new adult group (for periods on or after January 1, 2014).
Whether the state data is based on actual resource criteria determinations prior to January 1, 2014 or based on statistically valid post-eligibility sampling (whether prior to or on or after January 1, 2014), the data that will be used for the resource criteria proxy must represent sampling results for a period of sufficient length to be statistically valid. States who use data based on actual resource criteria determinations prior to January 1, 2014 must ensure the data validly reflects eligibility denials explicitly due to excess resources. Eligibility denials that were not explicitly related to excess resources, such as denials based on failure to return paperwork or other administrative issues, shall not be included as they would inappropriately inflate the number of people for whom the resource requirement was a bar to eligibility.
States that have not changed their resource eligibility criteria since December 1, 2009, that have valid state data, as described above, available from and for a statistically valid period prior to January 1, 2014 or that can collect such state data before January 1, 2014 (when resource tests will no longer be permissible), may rely on that data for the resource proxy. Alternatively, for states that do not have such data or cannot collect it before January 1, 2014, this rule permits states to develop a resource proxy based on data derived through a post-eligibility review of the resource information for a one-time sample of beneficiaries. Such sample would be with respect to applicable resources as assessed against standards for eligibility groups in effect on December 1, 2009, collected through a statistically valid sample obtained during the one year period that begins on the first day of the quarter in which eligibility for individuals under the new adult group is initially effective for the state (for example, by December 31, 2014, for states that adopt the new adult group effective January 1, 2014), and ends on the last day of the one year period. For example, denial data for a determined statistically valid period January to March 2014 could be used for claims beginning with January 1, 2014, subject to CMS approval of an amendment to the state plan submitted during the first calendar quarter of 2014, retroactive to the beginning of such quarter in which the SPA was submitted.
Because we believe that it is important to have consistent processes, we would provide for a one-time opportunity to elect to implement a resource proxy methodology. States may elect to implement a resource proxy methodology through submission of a state plan amendment no later than one year from the first day of the quarter in which eligibility for individuals under the new adult group under § 435.119 is initially effective for the state. For example, for states choosing to adopt the new adult group effective January 1, 2014, this would be by December 31, 2014. State claims for federal funding in accordance with the resource proxy could be allowable no earlier than the beginning of the quarter in which the state plan was submitted, subject to CMS approval. The state plan amendment would describe the data upon which the resource proxy is based. CMS will review such amendments to ensure all requirements both methodological and related to data are met.
Under the resource proxy, states would apply the proportion of denials with respect to the expenditures of individuals in the new adult group who would otherwise be considered not to be newly eligible based only on their income being at or below the applicable converted MAGI standard; this would allow such expenditures to be claimed at the increased newly eligible FMAP. To illustrate this approach, if based on the state data there was a 5 percent denial rate due to excess resources for an applicable eligibility group or groups in effect on December 1, 2009 for which resource criteria was applicable, then 5 percent of the new adult eligibility group expenditures related to such applicable group or groups, which would otherwise have been claimed at the FMAP for individuals who were not newly eligible, would be claimed at the newly eligible FMAP rate. That is, the amounts of such expenditures would be considered to be newly eligible expenditures. CMS will work with the states to ensure that the resource proxy methodology is appropriately determined and applied.
Under section 1905(y)(2)(A) of the Act, the definition of a newly eligible individual includes individuals who would be eligible for full benefits, benchmark coverage, or benchmark equivalent coverage provided through a demonstration under the authority of section 1115 of the Act (1115 demonstration) as in effect on December 1, 2009 but would not have been enrolled (or would have been placed on a waiting list) based on the application of an enrollment cap or limit determined in accordance with such demonstration. As discussed above, the definition of newly eligible individual in § 433.204(a)(1) is clarified in this final rule to include a reference to this enrollment cap provision. For purposes of applying an enrollment cap, limit, or waiting list provision under the threshold methodology, individuals who would have been on a waiting list are considered as not enrolled under the demonstration. Proposed § 433.208(a)(2) of the August 17, 2011 proposed rule required the threshold methodology to incorporate any enrollment caps under section 1115 demonstrations programs that were in place in the state on December 1, 2009. In this final rule, § 433.206(e) is added to more fully describe the treatment of enrollment caps under the threshold methodology.
Section 433.206(e) indicates the underlying principles for applying an enrollment cap provision under the threshold methodology and describes how these principles are used for calculating the amount of federal funding to be claimed by states that had an enrollment cap or limit in effect on December 1, 2009, subject to the definition of newly eligible individual in § 433.204(a)(1). The main objective of the enrollment cap provision, added here to reflect the previously described revision to the definition of “newly eligible” contained in § 433.204(a)(1), is to establish the appropriate amount of federal funding available for the medical assistance expenditures that would be claimed at the FMAP applicable for individuals enrolled in the new adult group who are newly eligible individuals due to enrollment caps, and the amount of such expenditures that would be claimed at the FMAP applicable for individuals who are not newly eligible. Recognizing that enrollment limits or caps were designed differently in different section 1115 demonstrations, § 433.206(e) includes flexibility for states to reflect enrollment
In accordance with the goal of administrative simplicity, and as described below, for purposes of determining the applicable FMAP and appropriate level of federal funding for the medical assistance expenditures of the new adult group, under the threshold methodology the treatment of enrollment caps is based on the following three elements associated with the eligibility categories of individuals for which an enrollment cap/limit provision was applicable on December 1, 2009:
• Beginning in quarters ending after January 1, 2014, the total unduplicated number of individuals eligible and enrolled under the adult eligibility group for the applicable claiming period, that is, the period for which expenditures are being made.
• Beginning in quarters ending after January 1, 2014, the total state medical assistance expenditures for the new adult group for the applicable claiming period.
• The enrollment cap or limit in effect on December 1, 2009.
For purposes of the third element above, this final rule indicates that the enrollment cap/limit would be the level of such enrollment cap/limit as authorized under the approved demonstration in effect on December 1, 2009; or, if the state had affirmatively set the cap at a lower level consistent with flexibility provided by the demonstration terms and conditions, the state may elect to apply the lower cap as in effect in the state on December 1, 2009. To the extent that states imposed enrollment limits in accordance with the approved terms and conditions, this regulation seeks to assure that the newly eligible FMAP will be available to states for enrollment above such defined limits, as verified by CMS. Whether the state uses the enrollment cap specifically authorized in the demonstration or a lower, verifiable cap as in effect in the state that was consistent with the demonstration special terms and conditions, under the methodology described here, the amount of expenditures multiplied by the proportion of the 2009 enrollment cap to the total number of currently enrolled people in the group would be claimed at the regular FMAP (or, if applicable, at the expansion state FMAP); and the amount of expenditures multiplied by 100 percent minus the proportion (expressed as a percentage) would be claimed at the newly eligible FMAP.
In § 433.206(e)(2), under the threshold methodology, states may simplify application of enrollment caps/limits by electing to combine such enrollment caps as were in effect on December 1, 2009, unless such treatment would preclude claiming of federal funding at the applicable FMAP rates required under § 433.10(b) or (c). Combining enrollment caps would be precluded in certain circumstances when separate treatment of enrollment caps is necessary to distinguish claims for which different FMAP rates apply. For example, in an expansion state the applicable FMAP for childless adults who are not newly eligible is the expansion state FMAP, and the applicable FMAP for parents who are not newly eligible is the regular FMAP. This difference in the FMAP rates for individual who are not newly eligible in an expansion state necessitates separately capturing the number of parents and childless adults to whom the expansion state FMAP would apply. In all cases, all states can elect to apply the enrollment caps separately, even when combining such caps/limits is not precluded.
Whether the treatment is to combine or separate the applicable enrollment caps, for states that had enrollment caps in effect on December 1, 2009, using the three elements listed above, federal funding will be determined based on the proportion of the enrollment cap to the total number of individuals in the applicable demonstration coverage group who are eligible under the adult eligibility group. In particular, the total expenditures multiplied by the proportion would be claimed at the FMAP for individuals who are not newly eligible individuals; and the total expenditures multiplied by the difference between 100 percent and the proportion would be claimed at the increased newly eligible FMAP.
Section 433.206(e)(4)specifies that each state for which the enrollment cap/limit provision applies will be required to indicate the treatment of such provisions in the state plan amendment submission required by new § 433.206(h), described below.
States' Medicaid programs as in effect on December 1, 2009 may have included eligibility categories for which deduction of incurred medical expenses from income (referred to as spend-down) under the provisions of sections 1902(a)(10)(C) and/or 1902(f) of the Act was applied in determining individuals' Medicaid eligibility. Under the provisions of section 1902(a)(10(C) of the Act, and in regulations at part 435, subparts D and I, states had and continue to have the option of establishing a “medically needy” program under which the income of an individual above the spend-down income eligibility standard (referred to as the medically needy income level) could become eligible for Medicaid by applying incurred medical expenses to reduce the excess income to the medically needy income level. States could choose the categories of individuals who would be covered by the medically needy program. Under the authority of section 1902(f) of the Act, and in regulations at § 435.121, a similar eligibility spend-down process is also applied under which certain states (referred to as “209(b) states”), in determining the Medicaid eligibility of aged, blind and disabled individuals, may apply certain more restrictive requirements than are applied under the Supplemental Security Income program to provide mandatory categorically needy coverage to such individuals. In certain circumstances, 209(b) states must use a spend-down process to determine eligibility of such affected individuals whose income is in excess of the applicable 209(b) mandatory categorically needy income level. 209(b) states may also elect to have a medically needy program in addition to covering the mandatory categorically needy aged, blind, and disabled individuals.
In general, the medically needy spend-down process and the 209(b) state spend-down process are the same with respect to the application of incurred medical expenses to reduce the excess income of individuals to the respective income eligibility levels. In that regard, as indicated in the August 17, 2011 proposed rule, for purposes of the determination of the applicable FMAP for individuals in the new adult group, individuals whose income is greater than the applicable respective medically needy or 209(b) spend-down levels as in effect on December 1, 2009 would be considered to be newly eligible individuals. Essentially, a state will only consider the income level of individuals in the new adult group, and not their potential spend-down amounts, in determining if they are newly eligible or not. However, based on comments received on the proposed rule on this issue, there continues to be confusion about the application of the spend-down provision in determining the appropriate FMAP for the adult group. Accordingly, to clarify the application of the spend-down provision under the threshold methodology, a new § 433.206(f) is being added in this final rule.
Section 433.206(f)(1) generally describes the spend-down process as applied in determining eligibility. Section 433.206(f)(2) and (3) describe the determination under the threshold methodology of an individual as not newly eligible or newly eligible, respectively, under the definition indicated in § 433.204 and the availability of the appropriate FMAP under § 433.10(b) or (c) for the medical assistance expenditures of such individual for which a spend-down eligibility category of a state effective on December 1, 2009 is applicable. As indicated in § 433.206(f)(2), if an individual's income before any deductions for incurred medical expenses are made is less than or equal to the applicable spend-down income level in the state, whether a medically needy or 209(b) spend-down level, the individual would be considered as not newly eligible and the medical assistance expenditures related to such individual would be claimed at the FMAP applicable to not newly eligible individuals in the state. As indicated in § 433.206(f)(3), if an individual's income before any deductions for incurred medical expenses is greater than the applicable spend-down income level in the state, whether a medically needy or 209(b) spend-down level, the individual would be considered as newly eligible, and the medical assistance expenditures related to such individual would be claimed at the newly eligible FMAP.
As states implement the threshold methodology, we recognize and anticipate that special circumstances may necessitate the potential need to consider additional adjustments to provide a basis for states to properly claim federal funding for the expenditures of individuals enrolled in the new adult group at the appropriate FMAP. The final rule provides a basis at new § 433.206(g) for addressing such circumstances and to assure efficient transitions to the new eligibility and FMAP provisions. Subject to CMS approval, this provision will apply such as in the case of the operation of a waiver authorized under section 1902(e)(14)(A) of the Act or, to the extent that a section 1115 demonstration in effect as of December 1, 2009 applied non-financial eligibility criteria for demonstration eligibility that are otherwise not accounted for in the general rule. To the extent that such criteria are difficult to verify or unknowable in 2014 and beyond, this approach is intended to provide a basis for states to claim federal funding for the expenditures of individuals enrolled in the adult group at the appropriate FMAP. CMS will work with states to develop an appropriate proxy methodology, process, and the appropriate documentation for submission to and approval by CMS.
The proposed rule generally indicated that states would submit a threshold methodology plan to CMS for approval. In this final rule, states are directed to submit a threshold methodology state plan amendment to their Medicaid state plan for approval by CMS. The threshold methodology plan, which will be included as an attachment to the state plan, would indicate that the state will implement such methodology in accordance with the provisions of this section and include details about the methodology. The threshold methodology attachment to the state plan will include any options or alternatives the state elects with respect to:
• Treatment of resources, in accordance with (§ 433.206(d));
• Treatment of enrollment caps or waiting lists, in accordance with (§ 433.206(e));
• Any applicable special circumstances, as approved by CMS ((§ 433.206(g)); and
• Treatment of other aspects of the threshold methodology as approved by the CMS.
The process for submission and the format of the threshold methodology plan will be provided through guidance issued by CMS.
In the proposed rule, § 433.210 referred to the statistically valid sampling methodology. This regulatory provision is deleted in this final rule.
In the proposed rule, § 433.212 referred to the CMS established FMAP proportion. This regulatory provision is deleted in this final rule.
In the Medicaid Eligibility proposed rule (RIN 0938–AQ62, 76 FR 51148), we solicited public comments for 60 days on the rule's information collection requirements but none were received. As described in this final rule, we are clarifying and finalizing the provisions of the threshold methodology for states to use in the claiming of federal funding at the appropriate FMAP rates for expenditures related to the new adult eligibility group. In that regard, and as previously explained, states will need to submit state plan amendments to reflect their implementation of the threshold methodology. States will also need to submit expenditure and other information in their submissions of their quarterly Medicaid expenditure reports. Any information collection requirements for states related to the state plan amendment or expenditure report submission will be described separately.
This final rule implements provisions of the Affordable Care Act that relate to the availability of increased FMAP rates under states' Medicaid programs. This final rule codifies the increased FMAP rates and the related conditions and requirements that will be applicable beginning January 1, 2014, for the expenditures of certain individuals determined eligible under the new adult eligibility group. In particular, with respect to the new adult eligibility group, increased FMAP rates will be available for state Medicaid expenditures associated with medical assistance for two groups of adults: certain individuals who are “newly eligible” and certain individuals who are in defined “expansion states” and are not “newly eligible.” This final rule selected one of the three methodologies described in the proposed rule and finalizes it as the methodology that states will use to determine the appropriate FMAP in claiming federal funding for the expenditures related to individuals determined eligible in the new adult group. In general, the threshold methodology offers a simplified approach that compares individuals' MAGI-based income, as already established through the basic eligibility process, to the income levels as were in effect under states' Medicaid programs on December 1, 2009. To further ease and simplify administration, the threshold methodology also provides for potential population-based adjustments in the federal claims to account for resources and enrollment caps that may have applied in the states' December 1, 2009, Medicaid programs. As specified in § 433.206(h), states must amend their state plans to reflect the threshold methodology the states will implement.
Although there are short-term burdens associated with implementation of these provisions, over time the Medicaid program will be made substantially easier for states to administer by simplifying the determinations of the applicable FMAP. The policies finalized in this final rule are intended to reduce or eliminate the burden on states seeking to determine the appropriate FMAP for claims as well as on individuals applying for Medicaid. The regulation makes clear that any additional information potentially requested from individuals for FMAP purposes cannot delay or otherwise affect the eligibility determination; nor can any individual be required to provide such information needed solely for FMAP purposes.
We recognize that there are information collection requirements related to the implementation of this regulation, particularly with respect to the state plan amendments required by § 433.206(h). CMS will seek OMB approval of those amendments at a later time under OCN 0938–1148. In addition, CMS will be making changes to its quarterly financial reporting form (CMS–64) to facilitate claiming under this final rule. CMS will seek public comment and OMB approval of those changes at a later time under OCN 0938–0067.
We have examined the impact of this final rule as required by Executive Order 12866 on Regulatory Planning and Review (September 30, 1993), Executive Order 13563 on Improving Regulation and Regulatory Review (January 18, 2011), the Regulatory Flexibility Act (RFA) (September 19, 1980, Pub. L. 96–354), section 1102(b) of the Act, section 202 of the Unfunded Mandates Reform Act of 1995 (March 22, 1995; Pub. L. 104–4), and the Congressional Review Act (5 U.S.C. 804(2)).
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.
A regulatory impact analysis (RIA) must be prepared for major rules with economically significant effects ($100 million or more in any 1 year). This final rule does not reach the economic threshold and thus is not considered a major rule. In accordance with the provisions of Executive Order 12866, this regulation was reviewed by the Office of Management and Budget.
This final rule concerns the technical aspects of applying the appropriate FMAP to the expenditures of individuals in the new adult group (described at § 435.119) who are either newly eligible or, if not, meet the criteria for the increased expansion state FMAP. This final rule simply provides guidelines and a process by which states can claim the appropriate FMAP in a streamlined manner. The economic impacts of the Medicaid expansion are entirely attributable to the Affordable Care Act; the economic impact of this rule concerns the additional costs of the methodology described in § 433.206, but not the costs of the expansion or the IT costs of the systems, which are contained in other implementation rules. As such, the costs of this rule are not economically significant, particularly when considered relative to the alternatives CMS considered in developing this rule; the process described here is less costly and more equitable than the alternatives described below.
This final rule sets out a simplified methodology and process for determining the applicable FMAP, which will lessen the burden on states implementing the provisions described in the Affordable Care Act. In the absence of the threshold methodology being finalized by this regulation, states would have to conduct an individualized determination based on the eligibility rules in effect in 2009, or would be subject to uncertainty (and potentially ongoing and costly disputes) in their efforts to claim the increased FMAP. Instead, under this final rule, the threshold methodology simply requires a basic comparison of an individual's current income against converted MAGI income thresholds for applicable categories of eligibility, subject to a limited number of adjustments that states may elect to increase the accuracy of the methodology. Therefore, the approach being finalized in this rule provides relief from the burden that would otherwise accrue to states seeking to determine the applicable FMAP. Indeed, the key objective of this final rule, as described in the preamble to the proposed rule and as reaffirmed
This final rule will implement provisions of the Affordable Care Act related to Medicaid, specifically provisions about the increased FMAPs and related provisions. It provides states with a simplified, less burdensome approach by which to identify the appropriate FMAP and alleviates the need for states to maintain a shadow eligibility system based on eligibility rules in effect in 2009. Instead, the regulation sets out a fair and accurate methodology by which to assess whether individuals seeking coverage in 2014 and beyond could have qualified for coverage under the state's eligibility standards as of December 1, 2009. Applying this methodology, individuals for whom it is determined could not have been eligible for specified coverage as of December 1, 2009 will be deemed newly eligible and the higher FMAP will apply.
The final rule sets out standards for claiming the increased FMAPs created by the Affordable Care Act. Following the process and methodology outlined in this final rule will provide states that elect to expand coverage to the new adult group access to the increased FMAPs, resulting in a significant economic benefit to states. The threshold methodology approach will require minimal incremental increases in states' spending relative to the alternatives we considered in finalizing this rule, as described below.
Although state Medicaid programs will have to invest in administrative costs to implement the threshold methodology described in this rule, they will ultimately receive significant federal matching payments for the costs of new Medicaid beneficiaries. As described elsewhere in this section, the threshold methodology will minimize the costs to state Medicaid agencies relative to the costs that they would otherwise bear in claiming the increased Affordable Care Act FMAPs. For example, this rule provides a transparent and uniform process for states to use, eliminating the uncertainty they would experience with respect to federal funds claiming in the absence of this guidance. Most significantly, the threshold methodology provides an efficient and streamlined alternative to avoid indefinitely applying 2009 eligibility standards to every applicant (in addition to current standards) simply for the purposes of determining the applicable FMAP. Numerous state and other commenters wrote to express particular concern about the burden that any methodology might impose on states and on applicants if additional information is requested for FMAP purposes.
We considered various alternative methodologies to determine the applicable FMAP in developing the proposed rule and in finalizing the provisions of this regulation, ultimately revising our approach from the proposed rule to finalize the threshold methodology. First, with regard to the increased FMAP rates available for state medical assistance expenditures relating to “newly eligible” individuals, in developing the proposed rule we considered requiring all states to complete a second, full eligibility determination on all Medicaid eligibles using the state's December 2009 eligibility standards to determine the appropriate FMAP rate based upon whether or not each individual was newly eligible. We determined that such a requirement would be overly burdensome to states and to beneficiaries and would likely lead to errors and unnecessary costs. We do not believe such an approach would result in an economic and efficient outcome in administering the program; rather, it would be significantly more burdensome than the approach we are adopting. In addition, such a requirement would directly contradict the principles of the Affordable Care Act to streamline and simplify eligibility and enrollment into health care programs. We did not propose this approach in the proposed rule and are not revisiting that decision in this final rule to avoid imposing unnecessary and unwarranted burdens on states or beneficiaries.
Second, we considered as an alternative approach the statistically valid sampling methodology (originally proposed in § 433.210). This alternative approach would use a sampling methodology across individuals in the adult group and related Medicaid expenditures to derive a statistically valid extrapolation of who is newly eligible and their related expenditures. We received numerous comments about the potential burdens associated with this methodology and concluded that it could require states to make actual eligibility determinations under 2009 rules and therefore maintain precisely the type of shadow eligibility system that the rule seeks to avoid. We also shared commenters' concerns that this alternative could place additional burdens on enrollees, including requests for information not required for eligibility. Such a result would not only be burdensome to beneficiaries but also inconsistent with standards established in the March 23, 2012 final rule that prevent states from asking applicants additional questions, when they apply for Medicaid, that are not related to the eligibility determination. Furthermore, we concluded that addressing concerns about burden on applicants could compromise the accuracy of the statistical sampling methodology.
We also determined that the statistically valid sampling methodology would not produce accurate results in states that had not expanded coverage through section 1115 demonstrations prior to 2014 because those states would not have applicable data for sampling purposes. Finally, we agreed with commenters' concerns that, because the sampling results would apply retroactively, this methodology would create the potential for sizeable retroactively adjusted federal payments, which would make it difficult for states to budget accurately and would introduce financial uncertainty for states. Given all of these concerns, we determined that the statistically valid sampling methodology would be more burdensome, less administratively feasible, and less accurate than the approach we elected, the threshold methodology.
A third alternative methodology considered was the CMS-established
Finally, numerous commenters provided comments with respect to the provision (included in the proposed rule at § 433.206) regarding the choice of FMAP methodologies. Some commenters urged us to select one methodology for nationwide use while other commenters urged flexibility. In response to the various comments, particularly those noting concerns with the accuracy, equity, burden, and lack of certainty related to the statistically valid sampling methodology and the proportion methodology, we are finalizing one methodology, the threshold methodology. Our view is that the threshold methodology (originally proposed in § 433.208 and being finalized in § 433.206), particularly as modified in this final rule, is the least burdensome, most transparent, and most accurate approach relative to the other alternatives. We have worked and continue to work extensively with states to develop the converted MAGI income thresholds that will be the basis of this methodology. As noted above, we published a letter to State and Health Officials on December 28, 2012 (SHO #12–003, available at:
In finalizing the threshold methodology, we accounted for various comments about specific elements of the threshold methodology, including how the methodology should account for past denials based on resources and how the methodology should treat individuals eligible for Medicaid based on disability status and/or spend-down rules. We revised this final rule to provide states with various options to account for these adjustments to the threshold methodology to enable accurate FMAP claiming. With respect to resources, for example, states may—but are not required to—undertake additional data analysis to develop a resource proxy to help determine additional expenditures eligible for the increased newly eligible FMAP. Rather than require all states adopting the new adult group to develop and apply a resource proxy, only states wishing to claim additional FMAP for populations that might not appear to be newly eligible in the absence of the consideration of resources will pursue the additional (but time-limited and minimal) administrative costs of doing so. We believe this approach strikes an appropriate balance that avoids increasing the burden on all states.
Section 202 of the Unfunded Mandates Reform Act of 1995 (UMRA) requires that agencies assess anticipated costs and benefits before issuing any rule whose mandates require spending in any 1 year of $100 million in 1995 dollars, updated annually for inflation. In 2013, that threshold is approximately $141 million. However, it is important to understand that the UMRA does not address the total cost of a rule. Rather, it focuses on certain categories of cost, mainly costs resulting from (A) imposing enforceable duties on state, local, or Tribal governments, or on the private sector, or (B) increasing the stringency of conditions in, or decreasing the funding of, state, local, or Tribal governments under entitlement programs.
Because of the favorable Affordable Care Act increased FMAPs and the availability of 90 percent federal match for systems improvements to facilitate upgrades to accommodate the Affordable Care Act eligibility changes, we believe that states can take actions that will have limited effects on state costs. The extensive consultation with states we describe below was aimed at the requirements of both UMRA and Executive Order 13132 on Federalism.
As noted previously, the Affordable Care Act creates a new mandatory eligibility group to cover adults with incomes below 133 percent of the FPL. The recent Supreme Court decision gives states the option not to cover this eligibility group but, for states that elect to provide such coverage, Title XIX now provides substantial new federal support to nearly offset the costs of covering that population. States will have to undertake some work to properly apply the threshold methodology, including developing procedures to properly identify and claim the appropriate FMAP for newly eligible and/or certain non-newly eligible populations in expansion states, but this work builds on existing work they are already undertaking as part of the conversion of income standards to MAGI-based standards. Furthermore, claiming expenditures will be done in accordance with current claiming requirements.
The Affordable Care Act changes the Medicaid and CHIP programs to improve coordination between programs and reduce the administrative burden on states by simplifying and streamlining systems. Following publication of the August 17, 2011 proposed eligibility rule, we received input from states about the FMAP provisions in that rule. In addition to analyzing the feasibility of each of the proposed alternatives, we solicited input from a group of states working intensively to prepare to implement the new Medicaid adult group, including the transition to MAGI, and analyzed the data from these states.
We have received input from states on how the various Affordable Care Act provisions codified in this final rule will affect them. We have participated in a number of conference calls and in person meetings with state officials since the law was enacted. These discussions have enabled the states to share their thinking and questions about how the Medicaid changes in the legislation would be implemented. The conference calls and meetings also furnished opportunities for State Medicaid Directors to comment informally on implementation issues and plans (although to be considered comments on the Medicaid Eligibility proposed rule, written comments using
We do not believe this final rule will impose any unfunded mandates on the private sector. As we explain in more detail in the Regulatory Flexibility Act analysis, the provisions of the Affordable Care Act implemented by this final rule deal with FMAP rates for individuals in the new adult group, and as such are directed toward state governments rather than toward the private sector. Since the final rule will impose no mandates on the private sector, we conclude that the cost of any possible unfunded mandates would not meet the threshold amounts discussed previously that would otherwise require an unfunded mandate analysis for the private sector. We also conclude that an unfunded mandate analysis is not needed for Tribal governments since the final rules will not impose mandates on Tribal governments.
The RFA requires agencies to analyze options for regulatory relief of small entities if a final rule will have a significant economic impact on a substantial number of small entities. We are not preparing an RFA because the Secretary has determined that this final rule would not have a significant economic impact on a substantial number of small entities. Few of the entities that meet the definition of a small entity as that term is used in the RFA (for example, small businesses, nonprofit organization, and small governmental jurisdictions with a population of less than 50,000) will be impacted directly by this final rule. Individuals and states are not included in the definition of a small entity. There are some states in which counties or cities share in the costs of Medicaid. To the extent that states require counties to share in these costs, some small jurisdictions could be affected by the requirements of this final rule, especially beginning in 2017 when the newly eligible FMAP is no longer 100 percent. However, nothing in this rule will constrain states from making changes to alleviate any adverse effects on small jurisdictions.
Because this final rule is focused on the appropriate FMAP to reimburse the expenditures of individuals enrolled in Medicaid, it does not contain provisions that would have a significant direct impact on hospitals, and other health care providers that are designated as small entities under the RFA. However, the provisions in this final rule, like the provisions in the final March 23, 2012 eligibility rule, may have a substantial, positive indirect effect on hospitals and other health care providers due to the substantial increase in the prevalence of health coverage among, and Medicaid reimbursement for, populations who are currently unable to pay for needed health care, leading to lower rates of uncompensated care at hospitals.
Section 1102(b) of the Act requires us to prepare a regulatory impact analysis if a final rule may have a significant economic impact on the operations of a substantial number of small rural hospitals. This analysis must conform to the provisions of section 604. For purposes of section 1102(b) of the Act, we define a small rural hospital as a hospital that is located outside of a metropolitan statistical area and has fewer than 100 beds. We are not preparing an analysis for section 1102(b) of the Act because the Secretary has determined that this final rule will not have a direct economic impact on the operations of a substantial number of small rural hospitals. As indicated in the preceding discussion, there may be indirect positive effects from reductions in uncompensated care.
In conclusion, we are not preparing analysis for either the RFA or section 1102(b) of the Act, because we have determined that this final rule will not have a direct significant economic impact on states, small entities, or small rural hospitals. Relative to the alternatives considered, we determined the threshold methodology to be less burdensome to states and beneficiaries, more equitable, and more transparent than other approaches considered. The threshold methodology provides a uniform, streamlined process for states that adopt to extend Medicaid to the new adult group to claim the higher FMAPs provided by the Affordable Care Act. Finalizing this methodology thereby eliminates the comparatively more burdensome approaches of either uncertainty about federal claiming standards or requiring states to indefinitely determine new applicants' eligibility using new standards as well as the eligibility rules in effect in 2009 simply for the purposes of assigning the FMAP. The incremental costs of implementing the threshold methodology process are therefore relatively small compared to the alternatives considered. This analysis, together with the remainder final rule, provides a final Regulatory Impact Analysis.
Executive Order 13132 establishes certain requirements that an agency must meet when it promulgates a final rule that imposes substantial direct effects on states, preempts state law, or otherwise has Federalism implications. We have reviewed this rule under the threshold criteria of Executive Order 13132, Federalism, and have determined it will not have substantial direct effects on the rights, rules, and responsibilities of states, local or tribal governments.
Administrative practice and procedure, Child support Claims, Grant programs-health, Medicaid, Reporting and recordkeeping requirements.
For the reasons set forth in the preamble, the Centers for Medicare & Medicaid Services amend 42 CFR chapter IV as set forth below:
Section 1102 of the Social Security Act (42 U.S.C. 1302).
The additions read as follows:
(c) * * *
(6)(i)
(A) 100 percent, for calendar quarters in calendar years (CYs) 2014 through 2016;
(B) 95 percent, for calendar quarters in CY 2017;
(C) 94 percent, for calendar quarters in CY 2018;
(D) 93 percent, for calendar quarters in CY 2019;
(E) 90 percent, for calendar quarters in CY 2020 and all subsequent calendar years.
(ii) The FMAP specified in paragraph (c)(6)(i) of this section will apply to amounts expended by a State for medical assistance for newly eligible individuals in accordance with the requirements of the methodology applied by the State under § 433.206.
(7)(i)
(ii) A State qualifies for the targeted increase in the FMAP under paragraph (c)(7)(i) of this section, if the State:
(A) Is an expansion State, as described in § 433.204(b) of this section;
(B) Does not qualify for any payments on the basis of the increased FMAP under paragraph (c)(6) of this section, as determined by the Secretary; and
(C) Has not been approved by the Secretary to divert a portion of the disproportionate share hospital allotment for the State under section 1923(f) of the Act to the costs of providing medical assistance or other health benefits coverage under a demonstration that is in effect on July 1, 2009.
(iii) The increased FMAP under paragraph (c)(7)(i) of this section is available for amounts expended by the State for medical assistance for individuals that are not newly eligible as defined in § 433.204(a)(1).
(8)
(i)
(ii)
(A) 50 percent, for calendar quarters in CY 2014;
(B) 60 percent, for calendar quarters in CY 2015;
(C) 70 percent, for calendar quarters in CY 2016;
(D) 80 percent, for calendar quarters in CY 2017;
(E) 90 percent, for calendar quarters in CY 2018; and
(F) 100 percent, for calendar quarters in CY 2019 and all subsequent calendar years.
This subpart sets forth the requirements and procedures that are applicable to support State claims for the increased FMAP specified at § 433.10(c)(6) for the medical assistance expenditures for individuals determined eligible as specified in § 435.119 of this chapter who meet the definition of newly eligible individual specified in § 433.204(a)(1). These procedures will also identify individuals determined eligible as specified in § 435.119 of this chapter for whom the State may claim the regular FMAP rate specified at § 433.10(b) or the increased FMAP rate specified at § 433.10(c)(7) or (8), as applicable.
(a)(1)
(2)
(3) For purposes of establishing under paragraphs (a)(1) and (2) of this section whether an individual would not have been eligible for full benefits, benchmark coverage, or benchmark equivalent coverage under a waiver or demonstration program in effect on December 1, 2009, the State must provide CMS with its analysis, in accordance with guidance issued by CMS, about whether the benefits available under such waiver or demonstration constituted full benefits, benchmark coverage, or benchmark equivalent coverage. CMS will review such analysis and confirm the applicable FMAP. Individuals for whom such benefits or coverage would have been available under such waiver or demonstration are not newly eligible individuals.
(b)(1)
(i) Have included inpatient hospital services;
(ii) Not have been dependent on access to employer coverage, employer contribution, or employment; and
(iii) Not have been limited to premium assistance, hospital-only benefits, a high deductible health plan, or benefits under a demonstration program authorized under section 1938 of the Act.
(2) For purposes of paragraph (b)(1) of this section and for § 433.10(c)(8), a nonpregnant childless adult means an individual who is not eligible based on pregnancy and does not meet the definition of a caretaker relative in § 435.4 of this chapter.
(a)
(b)
(1) Not impact the timing or approval of an individual's eligibility for Medicaid.
(2) Not be biased in such a manner as to inappropriately establish the numbers of, or medical assistance expenditures for, individuals determined to be newly or not newly eligible.
(3) Provide a valid and accurate accounting of individuals who would have been eligible in accordance with the December 1, 2009 eligibility standards and applicable eligibility categories for the benefits described in § 433.204(a)(1), and subject to paragraphs (d), (e), and (g) of this section, by incorporating simplified assessments of resources, enrollment cap requirements in place at that time, and other special circumstances as approved by CMS, respectively.
(4) Operate efficiently, without further review once an individual has been determined not to be newly eligible based on the December 1, 2009 standards for any eligibility category.
(c)
(1)
(2)
(3)
(i) The amount of an individual's income under the threshold methodology is the MAGI-based income determined in accordance with § 435.603 of this chapter.
(ii) For each individual, the equivalent MAGI-based income eligibility standard is the applicable income eligibility standard for the applicable category of eligibility as in effect on December 1, 2009 that is converted to an equivalent MAGI-based income standard. For example, as applicable, a separate MAGI-based income standard will be applied for individuals determined to be disabled who would have been eligible under an optional eligibility category in effect on December 1, 2009 that was based on disability. For these purposes, the applicable equivalent MAGI-based standard is the standard as submitted by the State and approved by CMS in accordance with CMS guidance.
(iii) With respect to income eligibility criteria, if the individual's MAGI-based income is at or below the applicable converted MAGI-based income standard for the relevant eligibility category or group, then the individual is included in the population that is not newly eligible;
(iv) With respect to income eligibility criteria, if the individual's MAGI-based income is greater than the applicable converted MAGI-based income standard for the relevant eligibility category or group, then the individual is included in the population that is newly eligible;
(v)
(vi) For purposes of comparing the individual's MAGI-based income to the applicable converted MAGI-based income standard in effect on December 1, 2009, an individual will not be considered disabled absent an actual
(4)
(i)
(ii)
(5)
(i) The State may elect a resource criteria proxy adjustment described in paragraph (d) of this section.
(ii) States that had a waiver or demonstration program with an enrollment cap in effect as of December 1, 2009 must apply an adjustment based on enrollment caps, subject to the definition of newly eligible individual in § 433.204(a)(1) and paragraph (e) of this section.
(iii) States that have special circumstances may need to submit associated proxy methodologies to CMS for approval by CMS as described in paragraph (g) of this section.
(6)
(i) The newly eligible FMAP under § 433.10(c)(6) is applicable for the medical assistance expenditures for individuals determined to be newly eligible, as defined in § 433.204(a)(1).
(ii) The applicable FMAP under § 433.10(b) or § 433.10(c)(7) or (8) is applicable for the medical assistance expenditures for individuals determined not to be newly eligible.
(7)
(d)
(2) A State's resource proxy methodology must:
(i) Describe each eligibility group or groups for which an individual eligible under § 435.119 would have been eligible on December 1, 2009, subject to resource criteria, and a methodology to apply those resource criteria as an adjustment to the total expenditures to adjust determinations of the newly eligible population under paragraph (c) of this section.
(ii) Be auditable.
(iii) Be based on statistically valid data, which is either:
(A) Existing State data from and for periods before January 1, 2014 on the resources of individuals who had applied and received a determination with respect to Medicaid eligibility, including resource eligibility under the State's applicable December 1, 2009 eligibility criteria. The existing State data must be specifically related to resource eligibility determinations, indicate the number and types of individuals for whom resource determinations were made, and establish the denial rates specifically identified as due to excess resources; or
(B) Post-eligibility State data on the resources of individuals described in paragraph (d)(2)(iii)(B)(
(
(
(iv) Describe the State data on individuals' resources used and the application of such data. Whether such State data is based on data described in paragraph (d)(2)(iii)(A) or (B) of this section, such State data must represent sampling results for a period of sufficient length to be statistically valid.
(v) Provide that the resource proxy methodology will account for the treatment of resources in a statistically valid manner when there is a lack of sufficient information to make a resource determination for a particular individual in a sampled population.
(vi) Describe the application of the resource proxy methodology in establishing the amount and submission of claims for Federal funding by the State for the medical assistance expenditures of the applicable eligibility group(s). Such claims submitted under
(vii) As appropriate, describe and demonstrate the statistical validity of the resource proxy methodology and the use of data under such methodology.
(3)
(4)
(e)
(2) A State for which multiple enrollment caps or limits were in effect under its December 1, 2009 Medicaid program may elect to combine such enrollment caps or limits, unless such treatment would preclude claiming of Federal funding at the applicable FMAP rate required under § 433.10(b) or (c) (for example, to distinguish claims for childless adults and parents in an expansion State) for the medical assistance expenditures of individuals determined eligible and enrolled under § 435.119 of this chapter; a State with enrollment cap or limit provisions that would preclude combining enrollment caps or limit provisions must use separate caps; or, the State, at its option, may elect to use separate caps.
(3) For purposes of claiming Federal funding, with respect to each claiming period for which the State claims Federal funding for an eligibility category for which an enrollment cap or limit is applicable and in effect on December 1, 2009, the State must account for:
(i) The total unduplicated number of individuals eligible and enrolled under § 435.119 of this chapter for the applicable claiming period.
(ii) The total State medical assistance expenditures for individuals eligible and enrolled under § 435.119 of this chapter for the applicable claiming period.
(iii) The enrollment cap or limit in effect on December 1, 2009 for the eligibility category, determined in accordance with the approved demonstration as in effect on December 1, 2009.
(A) For States that elect under paragraph (e)(2) of this section to combine the enrollment caps, the enrollment cap is the sum of the enrollment caps for each eligibility group which is being combined.
(B) For States that elect to treat the enrollment caps separately under paragraph (e)(2) of this section, each enrollment cap will be accounted for separately.
(C) The level of the enrollment cap will be as authorized under the demonstration in effect on December 1, 2009; or, if the State had affirmatively set the cap at a lower level consistent with flexibility provided by the demonstration terms and conditions, the State may elect to apply the lower cap as in effect in the State on December 1, 2009. If a State elects to use such an alternate State-specified enrollment cap, the State will provide CMS with evidence, in its State plan amendment submitted to CMS under paragraph (h) of this section, that it had affirmatively implemented such a cap. Whether the State uses the authorized cap or a lower, verifiable cap as in effect in the State consistent with the demonstration special terms and conditions, the amount of expenditures up to the proportion of the 2009 enrollment cap to the total number of currently enrolled people in the group would not be claimed at the newly eligible FMAP.
(4) States for which an enrollment cap, limit, or waiting list was applicable under their Medicaid programs as in effect on December 1, 2009, must describe the treatment of such provision or provisions in the submission to CMS for approval by CMS in accordance with the State plan requirements outlined in § 433.206(h).
(f)
(2)
(3)
(g)
(h)
(1) Specify that the threshold methodology the State implements is in accordance with this section;
(2) Specify that the threshold methodology the State implements accounts for the individuals determined eligible under the adult group in § 435.119 of this chapter as a newly eligible individual or not newly eligible individual; and, on that basis, the State implements appropriate tracking for purpose of claiming Federal Medicaid funding for the associated medical assistance expenditures.
(3) Reference the converted MAGI-based December 1, 2009 income eligibility standards and the associated eligibility groups, describe how the State will apply such standards and methodologies, and include other relevant criteria in the assignment of FMAP.
(4) Indicate any required provisions, or options and alternatives the State elects, with respect to:
(i) Treatment of resources, in accordance with paragraph (d) of this section;
(ii) Treatment of enrollment caps or waiting lists, in accordance with paragraph (e) of this section; and
(iii) Special circumstances as approved by CMS in accordance with paragraph (g) of this section.
Internal Revenue Service (IRS), Treasury.
Notice of proposed rulemaking.
This document contains proposed regulations on the application of the $500,000 deduction limitation for remuneration provided by certain health insurance providers under section 162(m)(6) of the Internal Revenue Code (Code). These regulations affect health insurance providers that pay such remuneration.
Written or electronic comments and requests for a hearing must be received by July 1, 2013.
Send submissions to CC:PA:LPD:PR (REG–106796–12), Internal Revenue Service, PO Box 7604, Ben Franklin Station, Washington DC 20044. Submissions may be hand-delivered Monday through Friday between the hours of 8 a.m. and 4 p.m. to CC:PA:LPD:PR (REG–106796–12), Courier's Desk Internal Revenue Service, 1111 Constitution Avenue NW., Washington, DC, or sent electronically via the IRS Internet site via the Federal eRulemaking Portal at
Concerning these proposed regulations, Ilya Enkishev at (202) 622–6030; concerning the submission of comments or to request a public hearing, Oluwafunmilayo (Funmi) Taylor at (202) 622–7180 (not toll-free numbers).
This document contains a proposed amendment to 26 CFR part 1 under section 162(m)(6) of the Code. Section 162(m)(6) limits the allowable deduction for remuneration attributable to services provided by applicable individuals to certain health insurance providers that receive premiums from providing health insurance coverage. Section 162(m)(6) was added to the Code by section 9014 of the Patient Protection and Affordable Care Act (ACA) (Pub. L. 111–148, 124 Stat. 119, 868 (2010)).
On December 23, 2010, the Treasury Department and the IRS released Notice 2011–2 (2011–1 CB 260), which provides guidance on certain issues under section 162(m)(6). Specifically, the notice provides guidance on the application of the $500,000 deduction limitation to deferred deduction remuneration that is earned during taxable years beginning after December 31, 2009 and before January 1, 2013 and deductible in a taxable year beginning after December 31, 2012. The notice also provides a
Notice 2011–2 requested comments on the following issues:
• Application of the term
• How deferred deduction remuneration should be attributed to a taxable year of an employer;
• Application of the term
• Application of the deduction limitation to remuneration for services performed for insurers who are captive insurance companies or that provide reinsurance or stop loss insurance.
In drafting these proposed regulations, the Treasury Department and the IRS have considered all comments received, many of which are discussed in this preamble. See § 601.601(d)(2)(ii)(b).
For taxable years beginning after December 31, 2012, section 162(m)(6) limits to $500,000 the allowable deduction for the aggregate applicable individual remuneration and deferred deduction remuneration attributable to services performed by an applicable individual for a covered health insurance provider in a disqualified taxable year beginning after December 31, 2012 that (but for section 162(m)(6)) is otherwise deductible under chapter 1 of the Code (referred to in this preamble as remuneration that is otherwise deductible). Deferred deduction remuneration attributable to services performed in a disqualified taxable year beginning after December 31, 2009 and before January 1, 2013 that becomes otherwise deductible in taxable years beginning after December 31, 2012 is also subject to the $500,000 deduction limitation, determined as if the deduction limitation applied to disqualified taxable years beginning after December 31, 2009.
Accordingly, if applicable individual remuneration, deferred deduction remuneration, or a combination of applicable individual remuneration and deferred deduction remuneration that is attributable to services performed by an applicable individual for a covered health insurance provider in a disqualified taxable year exceeds $500,000, the amount of the remuneration that exceeds $500,000 is not allowable as a deduction in any taxable year. To the extent that the aggregate applicable individual remuneration and deferred deduction remuneration attributable to services performed by an applicable individual for a covered health insurance provider in a disqualified taxable year is less than $500,000, the remuneration generally may be deducted by the covered health insurance provider in the taxable year or years in which the amount is otherwise deductible.
The following example illustrates the application of the section 162(m)(6) deduction limitation. In Year 1, a covered health insurance provider pays $400,000 in salary (applicable individual remuneration) to an applicable individual and also credits $300,000 to an account for the applicable individual under a nonqualified deferred compensation plan, which is payable in Year 5 (deferred deduction remuneration). The $300,000 credit is fully vested in Year 1 and is attributable to services provided by the applicable individual in that year. In Year 1, the covered health insurance provider may deduct the $400,000 of applicable individual remuneration paid to the applicable individual for services provided during that year because the amount of this payment is less than the $500,000 deduction limit. In Year 5, the covered health insurance provider pays the $300,000 that was credited under the nonqualified deferred compensation
Section 162(m)(6)(C) provides that a covered health insurance provider is any health insurance issuer described in section 162(m)(6)(C)(i) and certain persons that are treated as a single employer with that health insurance issuer, as described in section 162(m)(6)(C)(ii). These proposed regulations include rules for determining whether a health insurance issuer is a covered health insurance provider for any taxable year and whether a person is treated as a single employer with a health insurance issuer that is a covered health insurance provider for any taxable year. A person may be treated as a covered health insurance provider for one taxable year, but not be treated as a covered health insurance provider for another taxable year, depending on whether that person meets the requirements to be a covered health insurance provider under section 162(m)(6)(C) for a particular taxable year.
For taxable years beginning after December 31, 2009 and before January 1, 2013, section 162(m)(6)(C)(i)(I) provides that a health insurance issuer (as defined in section 9832(b)(2)) is a covered health insurance provider for a taxable year if that health insurance issuer receives premiums from providing health insurance coverage (as defined in section 9832(b)(1)) during the taxable year. For taxable years beginning after December 31, 2012, section 162(m)(6)(C)(i)(II) provides that a health insurance issuer (as defined in section 9832(b)(2)) is a covered health insurance provider for a taxable year if not less than 25 percent of the gross premiums that the provider receives from providing health insurance coverage (as defined in section 9832(b)(1)) during the taxable year are from minimum essential coverage (as defined in section 5000A(f)).
Section 162(m)(6)(C)(ii) provides that two or more persons that are treated as a single employer under sections 414(b), (c), (m), or (o) are treated as a single employer for purposes of determining whether a person is a covered health insurance provider, except that in applying section 1563(a) for purposes of these subsections of section 414, sections 1563(a)(2) and (3) (which provide for brother-sister groups and combined groups) are disregarded. Accordingly, these proposed regulations provide that each member of an aggregated group (as described in the final sentence of this paragraph) that includes a health insurance issuer described in section 162(m)(6)(C)(i) at any time during a taxable year is also a covered health insurance provider for purposes of section 162(m)(6), even if the member is not a health insurance issuer and does not provide health insurance coverage. (An exception for certain corporate transactions is provided in the transition rules described in section IX of this preamble.) For this purpose, these proposed regulations define the term
For members of an aggregated group that have different taxable years, these proposed regulations provide rules to determine whether a member of an aggregated group that is not a health insurance issuer is a covered health insurance provider for a particular taxable year. Under these rules, the parent entity (as defined in the following paragraph of this preamble) of an aggregated group is a covered health insurance provider for its taxable year with which, or in which, ends the taxable year of the health insurance issuer that is a covered health insurance provider in the aggregated group of which the parent entity is a member. Each other member of an aggregated group is a covered health insurance provider for its taxable year that ends with, or within, the taxable year of the parent entity during which the parent entity is a covered health insurance provider. For purposes of these proposed regulations, the term
In response to a request for comments in Notice 2011–2, commenters suggested that an employer that sponsors a self-insured medical reimbursement plan should not be treated as a covered health insurance provider because benefits under this type of plan should not be treated as health insurance coverage for purposes of section 162(m)(6) if the employer assumes the financial risk of providing health benefits to its employees and limits the availability of benefits only to employees (which may include former employees). The Treasury Department and the IRS agree that an employer should not be treated as a covered health insurance provider under these circumstances. Accordingly, these proposed regulations provide that an employer is not a covered health
After section 162(m)(6) was enacted, some commenters observed that the aggregation rule in section 162(m)(6)(C)(ii) could result in unintended consequences in situations in which a health insurance issuer's activities and revenue constitute an insignificant portion of the activities and revenue of persons that are treated as a single employer with the health insurance issuer under the aggregation rules. Commenters also suggested that employers that maintain only legacy policies (policies that are no longer sold but for which current policyholders have automatic renewal rights) should not be considered covered health insurance providers because those employers are no longer accepting new policyholders and may find it difficult to transfer the legacy policies for regulatory and other reasons.
In response to these concerns, Notice 2011–2 provides a
Commenters generally reacted favorably to the
The commenter also suggested that if an individual provides services for a member of an aggregated group, but does not provide any services to the health insurance issuer within the group, then the remuneration for those services should not be subject to the section 162(m)(6) deduction limitation. These proposed regulations do not adopt this suggestion because that rule would be inconsistent with section 162(m)(6)(C)(ii), which treats all members of an aggregated group that includes a health insurance issuer described in section 162(m)(6)(C)(i) as covered health insurance providers subject to the section 162(m)(6) deduction limitation.
One commenter requested that the two-percent threshold for the
To accommodate unexpected changes in the revenue sources of an aggregated group and other events that could affect application of the
Commenters asked how the
Section 162(m)(6)(C)(i) provides that a health insurance issuer is a covered health insurance provider for a taxable year only if it receives premiums from providing health insurance coverage (as defined in section 9832(b)(1)). These proposed regulations include rules specifying that amounts received under an indemnity reinsurance contract and amounts that are direct service payments are not treated as premiums from providing health insurance coverage for purposes of section 162(m)(6)(C)(i).
Health insurance issuers may reinsure a portion of their risks by entering into an indemnity reinsurance contract with a reinsurer. After Congress enacted section 162(m)(6), commenters suggested that premiums received under an indemnity reinsurance contract should not be treated as premiums from providing health insurance coverage. An indemnity reinsurance contract is a contract between a health insurance issuer and a reinsurer under which a reinsurance claim is payable only after the health insurance issuer has paid an amount for health benefits under its own insurance agreement with the policy holder. Thus, commenters reasoned, premiums for reinsurance coverage should not be treated as premiums from providing health insurance coverage for purposes of section 162(m)(6). In response to these comments, Notice 2011–2 provides that, solely for purposes of determining whether a taxpayer is a covered health insurance provider, premiums received under an indemnity reinsurance contract are not treated as premiums from providing health insurance coverage.
Consistent with Notice 2011–2, these proposed regulations provide that, solely for purposes of determining whether a person is a covered health insurance provider, premiums received under an indemnity reinsurance contract are not treated as premiums from providing health insurance coverage, provided that under the reinsurance contract (1) the reinsuring company agrees to indemnify the health insurance issuer for all or part of the risk of loss under policies specified in the agreement, and (2) the health insurance issuer retains its liability to, and its contractual relationship with, the individual insured.
A health insurance issuer or other person that receives premiums from providing health insurance coverage may enter into an arrangement with a third party to provide, manage, or arrange for the provision of services by physicians, hospitals, or other healthcare providers. In connection with this arrangement, the health insurance issuer or other person that receives premiums from providing health insurance coverage may pay compensation to the third party in the form of capitated, prepaid, periodic, or other payments, and the third party may bear some or all of the risk that the compensation is insufficient to pay the full cost of providing, managing, or arranging for the provision of services by physicians, hospitals, or other healthcare providers as required under the arrangement. In addition, the third party may be subject to healthcare provider, health insurance, licensing, financial solvency, or other regulation under state insurance law. Commenters suggested that compensation payments to these third parties under these types of arrangements should not be treated as premiums from providing health insurance coverage for purposes of section 162(m)(6) because, while the third party bears some risk in connection with providing, managing, or arranging for the provision of healthcare services, a health insurance issuer or other entity that receives premiums from providing health insurance coverage is ultimately responsible for providing health insurance coverage to the insureds. The commenters explained that these risk shifting arrangements are simply methods by which health insurance issuers and other entities that provide health insurance coverage diversify and manage their risk, in a manner similar to reinsurance. The Treasury Department and the IRS agree with this comment. Accordingly, these proposed regulations provide that capitated, prepaid, periodic, or other payments (referred to as direct service payments) made by a health insurance issuer or other person that receives premiums from providing health insurance coverage to a third party as compensation for providing, managing, or arranging for the provision of healthcare services by physicians, hospitals, or other healthcare providers are not treated as premiums for purposes of section 162(m)(6), regardless of whether the third party is subject to healthcare provider, health insurance, licensing, financial solvency, or other similar regulatory requirements under state law.
The Treasury Department and the IRS also understand that certain government entities may make similar capitated, prepaid, or periodic payments to third parties to provide, manage, or arrange for the provision of services by physicians, hospitals, or other healthcare providers and that these third parties may also bear some or all of the risk that the payments are insufficient to pay the full cost of providing, managing, or arranging for the provision of services subject to the arrangement. Under certain circumstances, it may be inappropriate to treat these payments made by government entities as premiums for purposes of section 162(m)(6). However, because these payments are not made by an entity that has received premiums from providing health insurance, it may be difficult to distinguish between payments made to third parties that should be treated as premiums from providing health insurance and payments that should not be treated as premiums from providing health insurance. The Treasury Department and the IRS request comments on when such payments should be treated as premiums from providing health insurance coverage for purposes of section 162(m)(6) and when they should not be treated as premiums for these purposes.
Section 162(m)(6)(B) provides that a disqualified taxable year is, with respect to any employer, any taxable year for which the employer is a covered health insurance provider. Consistent with the statutory language, these proposed regulations provide that a disqualified taxable year is, with respect to any person, any taxable year for which that
Section 162(m)(6)(F) provides that with respect to a covered health insurance provider for a disqualified taxable year, an applicable individual is any individual (i) who is an officer, director, or employee in such taxable year, or (ii) who provides services for, or on behalf of, the covered health insurance provider during the taxable year. As noted in the Background section of this preamble, Notice 2011–2 provides that the term
These proposed regulations adopt this rule. The proposed regulations provide that remuneration for services provided by an independent contractor to a covered health insurance provider will not be subject to the deduction limitation under section 162(m)(6) if each of the following conditions are met. First, the independent contractor is actively engaged in the trade or business of providing services to recipients, other than as an employee or as a member of the board of directors of a corporation (or in a similar position with respect to an entity that is not a corporation). Second, the independent contractor provides significant services (as defined in § 1.409A–1(f)(2)(iii)) to two or more persons to which the independent contractor is not related and that are not related to one another (as defined in § 1.409A–1(f)(2)(ii)). Third, the independent contractor is not related to the covered health insurance provider or any member of its aggregated group, applying the definition of related person contained in § 1.409A–1(f)(2)(ii), except that for purposes of applying the references to sections 267(b) and 707(b)(1), the language “20 percent” is not substituted for “50 percent” in each place “50 percent” appears in sections 267(b) and 707(b)(1).
Commenters also suggested that future guidance clarify that the section 162(m)(6) deduction limitation applies to services provided by individuals that are natural persons and not services provided pursuant to a contract or arrangement with a corporation or partnership. For example, commenters were concerned that remuneration paid to doctors working for practice groups that provide services to a covered health insurance provider would be subject to the deduction limitation under section 162(m)(6). In general, a corporation or a partnership (for federal tax purposes) would not be treated as an applicable individual. However, the Treasury Department and the IRS remain concerned that covered health insurance providers may attempt to avoid the application of the deduction limitation under section 162(m)(6) by encouraging employees and independent contractors who are natural persons to form small or single-member personal service corporations or other similar entities to provide services that are historically provided by natural persons. The Treasury Department and the IRS invite comments regarding how the final regulations might address this potential abuse.
Section 162(m)(6)(D) and these proposed regulations provide that applicable individual remuneration is the aggregate amount that is allowable as a deduction with respect to an applicable individual for a disqualified taxable year (determined without regard to section 162(m)) for remuneration for services performed by that individual (whether or not during the taxable year), except that applicable individual remuneration does not include any amount that is deferred deduction remuneration. Unlike the definition of remuneration in section 162(m)(1), the definition of applicable individual remuneration in section 162(m)(6)(D) includes remuneration that is performance-based compensation, remuneration payable on a commission basis, and remuneration payable under existing binding contracts. Whether remuneration is applicable individual remuneration is determined without regard to when the services for the remuneration are performed. For example, a discretionary bonus first granted and paid to an applicable individual in a disqualified taxable year solely in recognition of services provided in prior years is applicable individual remuneration for the disqualified taxable year even though the bonus does not relate to services provided in the disqualified taxable year. In addition, a grant of restricted stock in a disqualified taxable year for which an applicable individual makes an election under section 83(b) is applicable individual remuneration for the disqualified taxable year of the covered health insurance provider in which the grant of the restricted stock is made.
Section 162(m)(6)(E) and these regulations provide that deferred deduction remuneration is remuneration that would be applicable individual remuneration for services that an applicable individual performs during a disqualified taxable year, but for the fact that it is not deductible until a later taxable year (such as generally occurs, for example, with nonqualified deferred compensation). Whether remuneration is deferred deduction remuneration is determined based on when the remuneration is deductible, regardless of when the remuneration is paid. For example, a bonus that is paid within 2
The $500,000 deduction limitation under section 162(m)(6) applies to the applicable individual remuneration and deferred deduction remuneration that is attributable to services performed by an applicable individual for a covered health insurance provider in a disqualified taxable year. Accordingly, at the time that an amount of applicable individual remuneration or deferred deduction remuneration for an applicable individual becomes otherwise deductible (and not before that time), the remuneration must be attributed to services provided by the applicable individual during a particular taxable year or years of a covered health insurance provider.
In response to a request for comments in Notice 2011–2, some commenters asked that taxpayers be permitted to use any reasonable method to attribute remuneration to taxable years of a covered health insurance provider, as long as the method is applied consistently. Commenters observed that the allocation methods for purposes of section 162(m)(5) set forth in Notice 2008–94 (relating to recipients of payments under the Troubled Asset Relief Program) may not be appropriate
These proposed regulations provide that remuneration is attributable to services performed by an applicable individual in the taxable year of the covered health insurance provider in which the applicable individual obtains a legally binding right to the remuneration, unless the remuneration is attributable to a different taxable year under another provision of these regulations.
In addition, these proposed regulations provide that deferred deduction remuneration is not attributable to a taxable year ending before the later of the date that (i) an applicable individual begins providing services to a covered health insurance provider, or (ii) an applicable individual obtains a legally binding right to the remuneration. If any amount of remuneration that becomes otherwise deductible would be attributable under the rules provided in these proposed regulations to a taxable year ending before the applicable individual begins providing services to a covered health insurance provider or obtains a legally binding right to the remuneration, these proposed regulations provide that this remuneration is attributed to services performed by the applicable individual in the taxable year in which the latter of these two dates occurs.
These proposed regulations further provide that remuneration is not attributable to periods when an applicable individual is not a service provider. Solely for purposes of these proposed regulations, an individual is treated as a service provider for any period during which the individual is an officer, director, or employee of, or providing services for, or on behalf of, a covered health insurance provider or any member of its aggregated group. An amount of remuneration that otherwise would be attributable under the rules set forth in these proposed regulations to a period when an applicable individual is not a service provider must be reattributed to a period during which the applicable individual is a service provider in accordance with the rules set forth in these proposed regulations.
If an amount of remuneration that becomes otherwise deductible may be attributed to services performed by an applicable individual in two or more taxable years of a covered health insurance provider in accordance with the rules for attributing remuneration set forth in the immediately following sections of this preamble for attributing remuneration under an account balance plan or a nonaccount balance plan, the amount must be attributed first to services performed by the applicable individual in the earliest taxable year to which the amount could be attributed under the applicable attribution rules, and then to the next subsequent taxable year to which the amount could be attributed under those attribution rules, until the entire amount has been attributed to one or more taxable years of the covered health insurance provider.
To minimize the administrative burden on taxpayers in applying the remuneration attribution rules for account balance plans (as described in § 1.409A–1(c)(2)(i)(A) and (B)), these proposed regulations provide that remuneration for an account balance plan may be attributed to a taxable year based on the increase in the account balance during the taxable year, taking into account adjustments for the amount of any payments from that account during the taxable year. This method of attributing remuneration is referred to in the proposed regulations as the standard attribution method. Under the standard attribution method, the amount of remuneration attributable to services performed in a taxable year of a covered health insurance provider is equal to the excess of the account balance as of the last day of the taxable year, plus any payments made from that account during the taxable year, over the account balance as of the last day of the immediately preceding taxable year. Any net decrease in an account balance during a taxable year (again after adding back payments made under the plan during the taxable year) is treated as a reduction to deferred deduction remuneration for that taxable year and may offset other deferred deduction remuneration (but not applicable individual remuneration) attributable to services performed by the applicable individual in that year. If there is not sufficient other deferred deduction remuneration for that taxable year to offset the entire reduction, the excess may offset deferred deduction remuneration in the first subsequent taxable year or years in which the applicable individual has deferred deduction remuneration to be offset by the loss.
Under the standard attribution method, any increases or decreases in an account balance that occur in taxable years in which an applicable individual is not a service provider must be attributed to taxable years of the covered health insurance provider (i) during which the applicable individual is a service provider, and (ii) on one or more days of which the applicable individual retains an account balance under the plan. The Treasury Department and the IRS request comments on the appropriate method for attributing this remuneration to these taxable years. For taxable years beginning in 2013, and thereafter until the Treasury Department and the IRS issue further guidance prescribing the method for attributing this remuneration to these taxable years, this remuneration may be attributed
These proposed regulations provide an alternative method for attributing increases and decreases in account balance plans to services performed during a taxable year of a covered health insurance provider. Under the alternative attribution method, earnings and losses on a principal addition (including earnings and losses that occur in taxable years during which an applicable individual is not a service provider) are attributed to the taxable year in which an applicable individual is credited with the principal addition under the plan. For example, if a principal addition is credited to the account balance of an applicable individual for the 2014 taxable year, earnings (or losses) on that principal addition in 2028 are treated as additional deferred deduction remuneration (or reductions to deferred deduction remuneration) for the 2014 taxable year, and not the 2028 taxable year.
After an amount of remuneration has been attributed to a taxable year under a particular attribution method (for example, because a payment has been made and the amount of the payment becomes otherwise deductible), it is administratively difficult for the attribution method to be changed for future years. In addition, the Treasury Department and the IRS are concerned that the ability to change attribution methods may lead to selective use of methods to maximize deductions. Therefore, these proposed regulations provide that a covered health insurance provider must use the method chosen to attribute remuneration under all of its account balance plans consistently for all taxable years. However, the Treasury Department and the IRS understand that there may be valid business reasons for changing attribution methods, such as a merger or acquisition, change in compensation structure, or change in accounting method. Accordingly, the Treasury Department and the IRS request comments on the standards that should be applied to determine whether and when a method may be changed, and how that change would apply if deductions for some portion of the deferred deduction remuneration have already been taken.
These proposed regulations provide that remuneration under a nonaccount balance plan (as described in § 1.409A–1(c)(2)(i)(C)) is attributable to services performed by an applicable individual in a taxable year based on the increase (or decrease) in the present value of the applicable individual's benefit under the plan during the taxable year. Under this method, the amount of remuneration attributable to services performed in a taxable year of a covered health insurance provider is equal to the increase (or decrease) in the present value of the future payment or payments due under the plan as of the last day of the taxable year of the covered health insurance provider, increased by any payments made during that year, over (or under) the present value of the future payment or payments as of the last day of the covered health insurance provider's preceding taxable year. For purposes of determining the increase (or decrease) in the present value of a future payment or payments, the rules of § 31.3121(v)(2)–1(c)(2) apply. Like losses under account balance plans, losses attributable to any taxable year under a nonaccount balance plan may offset other deferred deduction remuneration attributable to services performed by the applicable individual in that year (or, if there is not sufficient other deferred deduction remuneration for that taxable year to offset the entire reduction, the excess may offset deferred deduction remuneration in the first subsequent taxable year or years in which the applicable individual has deferred deduction remuneration to be offset by the loss).
Any increase (or decrease) in the present value of a future payment or payments under a nonaccount balance plan that occurs in a taxable year when an applicable individual is not a service provider must be attributed to taxable years of the covered health insurance provider during which the applicable individual (i) is a service provider and (ii) has a legally binding right to a future payment or payments under the nonaccount balance plan. The Treasury Department and IRS request comments on the appropriate method for attributing this remuneration to these taxable years. For taxable years beginning in 2013, and thereafter until the Treasury Department and the IRS issue further guidance prescribing the method for attributing this remuneration to these taxable years, this remuneration may be attributed using any reasonable method to taxable years during which the applicable individual (i) is a service provider and (ii) has a legally binding right to the future payment or payments. For this purpose, a method is reasonable only if it is consistent with a reasonable, good faith interpretation of section 162(m)(6) and is applied consistently for all remuneration provided by the covered health insurance provider under substantially similar plans or arrangements.
These proposed regulations provide specific rules for the attribution of equity-based remuneration to services performed in specific taxable years. They provide that remuneration resulting from the exercise of stock options and stock appreciation rights (SARs) generally is attributable, on a daily
These proposed regulations further provide that remuneration resulting from the vesting or transfer (or transferability) of restricted stock for which an election under section 83(b) has not been made generally is attributable, on a daily
These proposed regulations provide that remuneration resulting from restricted stock units (RSUs) is generally attributable, on a daily
These proposed regulations provide that involuntary separation pay is attributable to services performed by an applicable individual during the taxable year of the covered health insurance provider in which the involuntary
An applicable individual's right to remuneration may be subject to a substantial risk of forfeiture. In response to Notice 2011–2, commenters suggested that remuneration be attributed to services performed over the period during which amounts are subject to a substantial risk of forfeiture (the vesting period). Consistent with this suggestion, these proposed regulations provide that in the case of remuneration that is subject to a substantial risk of forfeiture and that would otherwise be attributed to taxable years of a covered health insurance provider in accordance with (i) the general rule that attributes remuneration to the taxable year in which an applicable individual obtains a legally binding right to the remuneration, (ii) the attribution rules applicable to account balance plans, or (iii) the attribution rules applicable to nonaccount balance plans, the remuneration is attributed to taxable years of the covered health insurance provider using a two-step process. First, the remuneration is attributed to taxable years of the covered health insurance provider pursuant to the legally-binding-right rule or the rules applicable to account balance or nonaccount balance plans, as applicable. Second, the remuneration that was subject to a substantial risk of forfeiture is reattributed on a daily
If a vesting period ends on a day other than the last day of the covered health insurance provider's taxable year, the remuneration attributable to that taxable year under the first step of the attribution process is divided between the portion of the taxable year that includes the vesting period and the portion of the taxable year that does not include the vesting period. The amount attributed to the portion of the taxable year that includes the vesting period is equal to the total amount of remuneration that would be attributable to the taxable year under the first step of the attribution process, multiplied by a fraction, the numerator of which is the number of days during the taxable year that the amount is subject to a substantial risk of forfeiture and the denominator of which is the number of days in such taxable year. The remaining amount is attributed to the portion of the taxable year that does not include the vesting period and, therefore, is not reattributed over the vesting period under the second step of the attribution process.
For purposes of these proposed regulations, a substantial risk of forfeiture means a substantial risk of forfeiture under § 1.409A–1(d). If an individual makes an election pursuant to section 83(b), then the remuneration included in the individual's gross income is applicable individual remuneration that is attributed to the year in which the transfer of the property occurs.
The section 162(m)(6) deduction limitation applies to the aggregate applicable individual remuneration and deferred deduction remuneration attributable to services performed by an applicable individual for a covered health insurance provider in a disqualified taxable year. Accordingly, if the applicable individual remuneration and deferred deduction remuneration attributable to services performed by an applicable individual for a covered health insurance provider in a disqualified taxable year exceed $500,000, the amount of the remuneration that exceeds $500,000 is not allowable as a deduction in any taxable year.
The $500,000 deduction limitation with respect to the applicable individual remuneration and deferred deduction remuneration attributable to services performed by an applicable individual in a disqualified taxable year is applied to that remuneration at the time that the remuneration otherwise becomes deductible. The deduction limitation with respect to an applicable individual for any particular disqualified taxable year is applied first to any applicable individual remuneration attributable to services performed by the applicable individual in that disqualified taxable year. If the amount of the applicable individual remuneration is less than the $500,000 deduction limitation, all of the applicable individual remuneration is deductible by the covered health insurance provider in that disqualified taxable year. To the extent the applicable individual remuneration exceeds the $500,000 deduction limitation, the covered health insurance provider's deduction for the applicable individual remuneration is limited to $500,000, and the amount of the applicable individual remuneration that exceeds $500,000 and, if applicable, any deferred deduction remuneration attributable to services performed by the applicable individual in that disqualified taxable year, cannot be deducted in any taxable year.
When the $500,000 deduction limitation is applied to an amount of applicable individual remuneration attributable to services performed by an applicable individual in a disqualified taxable year, the deduction limitation with respect to that applicable individual for that disqualified taxable year is reduced by the amount of the applicable individual remuneration against which it is applied, but not below zero. If the applicable individual also has an amount of deferred deduction remuneration attributable to services performed in that disqualified taxable year that becomes otherwise deductible in a subsequent taxable year, the deduction limitation, as reduced, is applied to that amount of deferred deduction remuneration in the first taxable year in which it becomes otherwise deductible. If the amount of the deferred deduction remuneration that becomes otherwise deductible is less than the reduced deduction limitation, then the full amount of the deferred deduction remuneration is deductible in that taxable year. To the extent that the amount of the deferred deduction remuneration exceeds the reduced deduction limitation, the covered health insurance provider's deduction for the deferred deduction remuneration is limited to the amount
After the deduction limitation with respect to an applicable individual for a disqualified taxable year (the original disqualified taxable year) is applied to an amount of deferred deduction remuneration, the deduction limitation with respect to that applicable individual for the original disqualified taxable year is further reduced by the amount of the deferred deduction remuneration against which it is applied, but not below zero. If the applicable individual has an additional amount of deferred deduction remuneration attributable to services performed in the original disqualified taxable year that becomes otherwise deductible in a subsequent taxable year, the deduction limitation, as further reduced, is applied to that amount of deferred deduction remuneration in the taxable year in which it is otherwise deductible. This process continues for future taxable years in which deferred deduction remuneration attributable to services performed by the applicable individual in the original disqualified taxable year is otherwise deductible. No deduction is allowed for any applicable individual remuneration or deferred deduction remuneration to the extent that remuneration exceeds the deduction limitation in effect at the time it is applied to the remuneration.
Any payment of deferred deduction remuneration may include remuneration that is attributable to services performed by an applicable individual in one or more taxable years of a covered health insurance provider under the rules set out in these proposed regulations. For example, remuneration resulting from the vesting of restricted stock that is subject to a substantial risk of forfeiture for three full taxable years of a covered health insurance provider is attributable to services performed in each of the three years during which the restricted stock was subject to a substantial risk of forfeiture. In that case, a separate deduction limitation applies to each portion of the payment that is attributed to services performed in a different disqualified taxable year of the covered health insurance provider. Any portion of the payment that is attributed to a disqualified taxable year will be deductible only to the extent that it does not exceed the deduction limit that applies to the applicable individual for that disqualified taxable year, as that deduction limit may have been previously reduced by the amount of any applicable individual remuneration or deferred deduction remuneration attributable to services performed in that disqualified taxable year that was previously deductible. If payments of deferred deduction remuneration under an account balance plan or a nonaccount balance plan are paid in installments (rather than a single lump-sum), the payments are deemed to be made from the deferred deduction remuneration to which they are attributable under the applicable attribution rules, with payments deemed to be made first with respect to the earliest taxable years to which they could be attributed. The proposed regulations contain numerous examples to illustrate how these rules apply to services performed and compensation payments made over multiple taxable years.
For purposes of applying the section 162(m)(6) deduction limitation, all members of an aggregated group are treated as a single employer. Accordingly, one $500,000 deduction limitation applies to the aggregate applicable individual remuneration and deferred deduction remuneration attributable to services performed by an applicable individual during a disqualified taxable year for any member of the aggregated group. Each time this deduction limitation is applied to an amount of applicable individual remuneration or deferred deduction remuneration otherwise deductible by any member of the aggregated group, the deduction limitation is reduced by the amount of the remuneration against which it is applied, and the reduced deduction limitation is then applied to other remuneration attributable to services performed by the applicable individual in the original disqualified taxable year that is otherwise deductible by any member of the aggregated group, in the manner previously described.
In the case of two or more members of an aggregated group that are otherwise entitled to deduct in any taxable year applicable individual remuneration or deferred deduction remuneration attributable to services performed by an applicable individual in a disqualified taxable year that exceeds the applicable deduction limitation for that disqualified taxable year, the deduction limitation is prorated and allocated to the members of the aggregated group in proportion to the applicable individual remuneration or deferred deduction remuneration that each otherwise would be entitled to deduct in the taxable year (but for section 162(m)(6)).
A corporation or other person may become a covered health insurance provider as a result of a merger, acquisition of assets or stock, disposition, reorganization, consolidation, or separation, or any other transaction (including a purchase or sale of stock or other equity interest) resulting in a change in the composition of its aggregated group (generally referred to in these proposed regulations as a corporate transaction). For example, as a result of the aggregation rules, members of a controlled group of corporations may become covered health insurance providers if a health insurance issuer that is a covered health insurance provider becomes a member of the controlled group. In response to Notice 2011–2, commenters suggested that if a person becomes a covered health insurance provider as a result of a corporate transaction, the person should not be treated as a covered health insurance provider for the taxable year in which the corporate transaction occurs. These proposed regulations adopt this suggestion by providing transition period relief to ease the administrative burden on persons that become covered health insurance providers solely as a result of a corporate transaction. Specifically, these proposed regulations provide that if a person that is not otherwise a covered health insurance provider would become a covered health insurance provider solely as a result of a corporate transaction, the person generally is not treated as a covered health insurance provider for the taxable year in which the transaction occurs (referred to as the transition period). The corporation or other person, however, is treated as a covered health insurance provider for any subsequent taxable year for which it qualifies as a covered health insurance provider under the general rules for determining whether a person is a covered health insurance provider. A person that was a covered health insurance provider immediately before a corporate transaction is not eligible for this transition period relief because the person did not become a covered health insurance provider solely as a result of a corporate transaction.
However, these proposed regulations provide that in certain circumstances the deduction limitation under section 162(m)(6) may apply to a person that is not treated as a covered health
These proposed regulations also provide rules for covered health insurance providers that have short taxable years as a result of a corporate transaction. See proposed § 1.162–31(f).
The section 162(m)(6) deduction limitation only applies to applicable individual remuneration attributable to services performed by an applicable individual during taxable years beginning after December 31, 2012 and to deferred deduction remuneration attributable to services performed by an applicable individual during taxable years beginning after December 31, 2009. It does not apply to remuneration attributable to services performed during taxable years beginning before January 1, 2010. These proposed regulations provide rules for determining whether remuneration is attributable to services performed in taxable years beginning before January 1, 2010 that are in some ways different from the general attribution rules.
Commenters suggested that deferred deduction remuneration earned or granted in taxable years beginning before January 1, 2010, be attributed to services performed before that time, regardless of whether the remuneration was subject to a substantial risk of forfeiture after that time. Commenters reasoned that Congress did not intend for the deduction limitation to apply to remuneration attributable to taxable years starting before January 1, 2010 (even if such remuneration was not vested as of the first day of the taxable year beginning after December 31, 2009), because Congress enacted section 162(m)(6) to encourage the use of health insurance coverage premiums to lower insurance rates for taxable years beginning after December 31, 2012 (when health insurance issuers would begin to benefit from a substantial increase in new customers). Commenters also asserted that the statute should not apply to arrangements that existed before the statute was enacted because covered health insurance providers could not change those arrangements unilaterally in response to the statute.
In response to these comments, these proposed regulations provide that the section 162(m)(6) deduction limitation does not apply to deferred deduction remuneration attributable to services performed during taxable years beginning before January 1, 2010, regardless of whether the remuneration was subject to a substantial risk of forfeiture after that time. These proposed regulations provide special rules for determining the amount of remuneration attributable to services performed in taxable years beginning before January 1, 2010 with respect to account balance plans, nonaccount balance plans, and equity-based remuneration. For account balance plans and nonaccount balance plans, these proposed regulations provide that amounts are attributed based on the general attribution rules, except that any substantial risk of forfeiture is disregarded. For equity-based compensation, any remuneration resulting from equity-based compensation granted in a taxable year beginning before January 1, 2010, is not subject to the deduction limitation. Earnings on these grandfathered amounts, including earnings accruing in taxable years beginning after December 31, 2009, are also generally treated as remuneration attributable to services performed in taxable years beginning before January 1, 2010.
Section 162(m)(6) applies to deferred deduction remuneration attributable to services performed in a disqualified taxable year beginning after December 31, 2009 that is otherwise deductible in a taxable year beginning after December 31, 2012. As described in section I.B of this preamble, for taxable years beginning before January 1, 2013, a covered health insurance provider is any health insurance issuer (as defined in section 9832(b)(2)) that receives premiums from providing health insurance coverage (as defined in section 9832(b)(1)) (a pre-2013 covered health insurance provider). For taxable years beginning after December 31, 2012, a covered health insurance provider is any health insurance issuer (as defined in section 9832(b)(2)) that receives at least 25 percent of its gross premiums from providing minimum essential coverage (as defined in section 5000A(f)) (a post-2012 covered health insurance provider). Thus, the definition of the term
After the enactment of section 162(m)(6), commenters suggested that if a pre-2013 covered health insurance provider does not qualify as a post-2012 covered health insurance provider, the section 162(m)(6) deduction limitation should not apply to deferred deduction remuneration attributable to services performed during taxable years when the health insurance issuer was a pre-2013 covered health insurance provider. These commenters cited legislative history suggesting that section 162(m)(6) was enacted to encourage health insurance issuers to use premiums from new customers to lower health insurance rates. 155 Cong. Rec. S12,540 (Dec. 6, 2009) (statement of Sen. Lincoln). These commenters reasoned that if a pre-2013 covered health insurance is not also a post-2012 covered health insurance provider, the health insurance issuer is not benefiting from new customers who are paying premiums for minimum essential coverage, and the health insurance issuer should not be subject to the deduction limitation.
In response to these comments, Notice 2011–2 provides that the section 162(m)(6) deduction limitation applies to deferred deduction remuneration attributable to services performed in a taxable year beginning after December 31, 2009 and before January 1, 2013 only if the covered health insurance provider is a pre-2013 covered health insurance provider for the taxable year to which the deferred deduction remuneration is attributable and a post-2012 covered health insurance provider for the taxable year in which that deferred deduction remuneration is otherwise deductible. These proposed regulations adopt this transition rule.
In response to Notice 2011–2, some commenters requested that the transition rule be applied more broadly, so that the section 162(m)(6) deduction limitation would not apply to deferred deduction remuneration for services attributable to taxable years beginning before January 1, 2013 if the employer is not a covered health insurance provider in 2013, regardless of whether the employer is a covered health insurance provider for the year the deferred deduction remuneration becomes otherwise deductible. The Treasury Department and the IRS have concluded that the standard set forth in Notice 2011–2 appropriately limits the transition rule to circumstances in which the deferred deduction remuneration is otherwise deductible in a taxable year for which the covered health insurance provider is not a post-2013 covered health insurance provider, and therefore these proposed regulations do not adopt this suggestion.
These proposed regulations do not affect the applicability of Notice 2011–2, (2011–1 CB 260). However, upon the effective date of the final regulations, the Treasury Department and the IRS anticipate that Notice 2011–2 will become obsolete for periods after the effective date of the final regulations.
These proposed regulations are proposed to be effective upon publication in the
It has been determined that this notice of proposed rulemaking is not a significant regulatory action as defined in Executive Order 12866. Therefore, a regulatory assessment is not required. It also has been determined that section 553(b) of the Administrative Procedure Act (5 U.S.C. chapter 5) does not apply to these regulations, and because the regulations do not impose a collection of information on small entities, the Regulatory Flexibility Act (5 U.S.C. chapter 6) does not apply. Pursuant to section 7805(f) of the Code, this regulation has been submitted to the Chief Counsel for Advocacy of the Small Business Administration for comment on its impact on small business.
Before these proposed regulations are adopted as final regulations, consideration will be given to any written (a signed original and eight (8) copies) or electronic comments that are timely submitted to the IRS. Treasury and the IRS request comments on all aspects of the proposed rules. All comments will be available for public inspection and copying. A public hearing will be scheduled if requested in writing by any person that timely submits written comments. If a public hearing is scheduled, notice of the date, time, and place for the public hearing will be published in the
The principal author of these proposed regulations is Ilya Enkishev, Office of the Division Counsel/Associate Chief Counsel (Tax Exempt and Government Entities). However, other personnel from Treasury Department and the IRS participated in their development.
Income taxes, Reporting and recordkeeping requirements.
Accordingly, 26 CFR part 1 is proposed to be amended as follows:
26 U.S.C. 7805.
(a)
(b)
(2)
(3)
(A) The common parent of a parent-subsidiary controlled group of corporations (within the meaning of section 414(b)) or a parent-subsidiary group of trades or businesses under common control (within the meaning of section 414(c)) that includes a health insurance issuer, or
(B) The health insurance issuer in an aggregated group that is an affiliated service group (within the meaning of section 414(m)) or a group described in section 414(o).
(ii)
(4)
(A) A health insurance issuer for any of its taxable years beginning after December 31, 2009 and before January 1, 2013 in which it receives premiums from providing health insurance coverage (as defined in section 9832(b)(1)),
(B) A health insurance issuer for any of its taxable years beginning after December 31, 2012 in which at least 25 percent of the gross premiums it receives from providing health insurance coverage (as defined in section 9832(b)(1)) are from providing minimum essential coverage (as defined in section 5000A(f)),
(C) The parent entity of an aggregated group of which one or more health insurance issuers described in paragraphs (b)(4)(i)(A) or (B) of this section are members for the taxable year of the parent entity with which, or in which, ends the taxable year of any such health insurance issuer, and
(D) Each other member of an aggregated group of which one or more health insurance issuers described in paragraphs (b)(4)(i)(A) or (B) of this section are members for the taxable year of the other member ending with, or within, the parent entity's taxable year.
(ii)
(iii)
(B)
(C)
(i) Corporations Y and Z are members of an aggregated group under paragraph (b)(2) of this section. Y is a health insurance issuer that is a covered health insurance provider pursuant to paragraph (b)(4)(i)(B) of this section and receives premiums from providing health insurance coverage that is minimum essential coverage during its 2015 taxable year in an amount that is less than two percent of the combined gross revenues of Y and Z for their 2015
(ii) Y and Z are not treated as covered health insurance providers within the meaning of paragraph (b)(4) of this section for their 2015 taxable years because they meet the requirements of the
(i) Corporations V, W, and X are members of an aggregated group under paragraph (b)(2) of this section. V is a health insurance issuer that is a covered health insurance provider pursuant to paragraph (b)(4)(i)(B) of this section, but neither W nor X is a health insurance issuer. W is the parent entity of the aggregated group. V's taxable year ends on December 31, W's taxable year ends on June 30, and X's taxable year ends on September 30. For its taxable year ending December 31, 2016, V receives $3x of premiums from providing minimum essential coverage and has no other revenue. For its taxable year ending June 30, 2017, W has $100x in gross revenue. For its taxable year ending September 30, 2016, X has $60x in gross revenue.
(ii) In the absence of the
(i) The facts are the same as
(ii) Although the premiums received by the members of the aggregated group from providing minimum essential coverage are more than two percent of the gross revenues of the aggregated group for the taxable years during which the members would otherwise be treated as covered health insurance providers under paragraph (b)(4)(i) of this section ($4x is greater than two percent of $164x), they were not treated as covered health insurance providers for their immediately preceding taxable years solely by reason of the
(5)
(A) Amounts received under an indemnity reinsurance contract described in paragraph (b)(5)(ii) of this section, or
(B) Direct service payments described in paragraph (b)(5)(iii) of this section.
(ii)
(A) The reinsuring company agrees to indemnify the health insurance issuer for all or part of the risk of loss under policies specified in the agreement, and
(B) The health insurance issuer retains its liability to provide health insurance coverage (as defined in section 9832(b)(1)) to, and its contractual relationship with, the insured.
(iii)
(6)
(7)
(A) Who is an officer, director, or employee in that taxable year, or
(B) Who provides services for or on behalf of the covered health insurance provider during that taxable year.
(ii)
(A) The independent contractor is actively engaged in the trade or business of providing services to recipients, other than as an employee or as a member of the board of directors of a corporation (or similar position with respect to an entity that is not a corporation);
(B) The independent contractor provides significant services (as defined in § 1.409A–1(f)(2)(iii)) to two or more persons to which the independent contractor is not related and that are not related to one another (as defined in § 1.409A–1(f)(2)(ii)); and
(C) The independent contractor is not related to the covered health insurance provider or any member of its aggregated group, applying the definition of related person contained in § 1.409A–1(f)(2)(ii), subject to the modification that for purposes of applying the references to sections 267(b) and 707(b)(1), the language “20 percent” is not used instead of “50 percent” each place “50 percent” appears in sections 267(b) and 707(b)(1).
(8)
(9)
(ii)
(A) A payment made to, or for the benefit of, an applicable individual from or to a trust described in section 401(a) within the meaning of section 3121(a)(5)(A),
(B) A payment made under an annuity plan described in section 403(a) within the meaning of section 3121(a)(5)(B),
(C) A payment made under a simplified employee pension plan described in section 408(k)(1) within the meaning of section 3121(a)(5)(C),
(D) A payment made under an annuity contract described in section 403(b) within the meaning of section 3121(a)(5)(D),
(E) Salary reduction contributions described in section 3121(v)(1), and
(F) Remuneration consisting of any benefit provided to, or on behalf of, an employee if, at the time the benefit is provided, it is reasonable to believe that the employee will be able to exclude the value of the benefit from gross income.
(10)
(11)
(12)
(c)
(2)
(i) The applicable individual remuneration for that applicable individual for that disqualified taxable year; and
(ii) The portion of the deferred deduction remuneration for those services that was deductible under section 162(m)(6)(A)(ii) and this paragraph (c)(2) in a preceding taxable year, or would have been deductible under section 162(m)(6)(A)(ii) and this paragraph (c)(2) in a preceding taxable year if section 162(m)(6) was effective for taxable years beginning after December 31, 2009 and before January 1, 2013.
(d)
(ii)
(iii)
(i) A is an employee of corporation Z, which has a taxable year that is the calendar year and is a covered health insurance provider for all relevant taxable years. A participates in a nonqualified deferred compensation plan that is an account balance plan maintained by Z. A's account balances under the plan on the last day of all relevant taxable years are as follows: $10,000 for 2014, $13,000 for 2015, $17,000 for 2016, and $24,000 for 2017. A's account balance is fully vested at all times. In accordance with the terms of the plan, Z pays $15,000 to A in 2018 and $9,000 to A in 2019. These amounts are otherwise deductible by Z in the year in which they are paid.
(ii) Because the nonqualified deferred compensation plan is an account balance plan, deferred deduction remuneration provided under the plan is attributable to services provided by A in accordance with paragraph (d)(3)(i) of this section. Z does not use the alternate method of allocating earnings and losses permitted under paragraph (d)(3)(ii) of this section. Accordingly, the deferred deduction remuneration under the plan attributable to services provided by A in a taxable year is generally equal to the increase in the account balance on the last day of each taxable year over the account balance on the last day of the immediately preceding taxable year, increased by the amount of any payments made during the taxable year. The increases in A's account balances are $10,000 for 2014, $3,000 for 2015, $4,000 for 2016, and $7,000 for 2017. Therefore, pursuant to paragraph (d)(1)(ii), Z must attribute $10,000 of the $15,000 payment to services performed by A in 2014, $3,000 of the $15,000 payment to services performed by A in 2015, and $2,000 of the $15,000 payment to services performed by A in 2016 (leaving $2,000 remaining to be attributed to 2016). Similarly, Z must attribute $2,000 of the $9,000 payment to services performed by A in 2016, and the remaining $7,000 of the $9,000 payment to services performed by A in 2017.
(iv)
(
(
(B)
(v)
(vi)
(2)
(3)
(B)
(ii)
(
(B)
(C)
(D)
(4)
(ii)
(5)
(ii)
(A) the date the substantial risk of forfeiture lapses with respect to the restricted stock, or
(B) the date the restricted stock is transferred by the applicable individual (or becomes transferable as defined in § 1.83–3(d)).
(iii)
(iv)
(6)
(7)
(8)
(9)
(i) B is an applicable individual of corporation Y for all relevant taxable years. On January 1, 2016, B begins participating in a nonqualified deferred compensation plan of Y that is an account balance plan. Under the terms of the plan, all amounts are fully vested at all times, and Y will pay B's entire account balance on January 1, 2019. Y credits $10,000 to B under the plan annually on January 1 for three years beginning on January 1, 2016. The account earns interest at a fixed rate of five percent per year, compounded annually under the terms of the
(ii) Under the standard attribution method for account balance plans described in paragraph (d)(3)(i) of this section, any increase in B's account balance as of the last day of Y's taxable year over the account balance as of the last day of the immediately preceding taxable year, increased by any payments made during the taxable year, is remuneration that is attributable to services provided by B in that taxable year. Accordingly, $10,500 of deferred deduction remuneration is attributable to services performed by B in Y's 2016 taxable year (the difference between the $10,500 account balance on December 31, 2016 and the zero account balance on December 31, 2015); $11,025 of deferred deduction remuneration is attributable to services performed in Y's 2017 taxable year (the difference between the $21,525 account balance on December 31, 2017 and the $10,500 account balance on December 31, 2016); and $11,576 of deferred deduction remuneration is attributable services performed in Y's 2018 taxable year (the difference between the $33,101 account balance on December 31, 2018 and the $21,525 account balance on December 31, 2017).
(i) The facts are the same as in
(ii) Under the alternative attribution method described in paragraph (d)(3)(ii) of this section, each principal addition of $10,000 is attributed to the taxable year of Y as of which the addition is credited, and earnings and losses on each principal addition are attributed to the same taxable year to which the principal addition is attributed. Therefore, $1,576 of earnings are attributable to Y's 2016 taxable year (interest on the 2016 $10,000 principal addition at five percent for three years compounded annually); $1,025 of earnings are attributable to Y's 2017 taxable year (interest on the 2017 $10,000 principal addition at five percent for two years compounded annually); and $500 of earnings are attributable to Y's 2018 taxable year (interest on the 2018 $10,000 principal addition at five percent for one year).
(i) The facts are the same as in
(ii) Under the standard attribution method for account balance plans described in paragraph (d)(3)(i) of this section, increases (or decreases) in B's account balance as of the last day of Y's taxable year over (or under) the account balance as of the last day of the immediately preceding taxable year, increased by any payments made during the taxable year, are attributable to services provided by B in that taxable year.
(iii) Accordingly, $10,500 of deferred deduction remuneration is attributable to services performed by B in Y's 2016 taxable year (the difference between the $10,500 account balance on December 31, 2016 and the zero account balance on December 31, 2015); $8,975 of deferred deduction remuneration is attributable to services performed in Y's 2017 taxable year (the difference between the $19,475 account balance on December 31, 2017 and the $10,500 account balance on December 31, 2016); and $11,474 of deferred deduction remuneration is attributable to services performed in Y's 2018 taxable year (the difference between the $30,949 account balance on December 31, 2018 and the $19,475 account balance on December 31, 2017).
(i) The facts are the same as in
(ii) Under the alternative attribution method for account balance plans described in paragraph (d)(3)(ii) of this section, each $10,000 principal addition is attributed to the taxable year of Y as of which the addition is made, and earnings and losses on each principal addition are attributed to the same taxable year of Y to which the principal addition is attributed. With respect to the $10,000 principal addition to B's account for 2016, the account balance is $10,500 on December 1, 2016 ($500 of earnings), $9,975 on December 31, 2017 ($525 of losses), and $10,474 on December 31, 2018 ($499 of earnings). Accordingly, $474 ($500 − $525 + $499) of net earnings is attributable to Y's 2016 taxable year. With respect to the $10,000 principal addition to B's account for 2017, the account balance is $9,500 on December 31, 2017 ($500 of losses), and $9,975 on December 31, 2018 ($475 of earnings). Accordingly, $25 in net losses are attributable to Y's 2017 taxable year ($500 losses for 2017 and $475 earnings for 2018). Because losses attributable to a taxable year may reduce deferred deduction remuneration attributable to that taxable year (but not applicable individual remuneration), the $25 loss reduces the $10,000 principal addition to B's account in 2017 for purposes of applying the section 162(m)(6) deduction limitation. With respect to the $10,000 principal addition to B's account in 2018, the account balance is $10,500 on December 31, 2018. Therefore, the $500 of earnings is attributable to Y's 2018 taxable year.
(i) C is an applicable individual of corporation X for all relevant taxable years. On January 1, 2015, X grants C a vested right to a $100,000 payment on January 1, 2020.
(ii) Under the attribution method for nonaccount balance plans described in paragraph (d)(4) of this section, any increase (or decrease) in the present value of the future payment that C is entitled to receive under the nonaccount balance plan as of the last day of X's taxable year, over (or under) the present value of the future payment as of the last day of the preceding taxable year, increased by any payments made during the taxable year, is attributable to services provided by C in that taxable year. X determines the present value of the payment using an interest rate of five percent for all years, which, solely for purposes of this example, is assumed to be a reasonable actuarial assumption. The present value of $100,000 payable on January 1, 2020, determined using a five percent interest rate, is $82,300 as of December 31, 2015; $86,400 as of December 31, 2016; $90,700 as of December 31, 2017; and $95,200 as of December 31, 2018. Accordingly, $82,300 of deferred deduction remuneration is attributable to services performed by C in X's 2015 taxable year; $4,100 ($86,400 − $82,300) of deferred deduction remuneration is attributable to services performed by C in X's 2016 taxable year; $4,300 ($90,700 − $86,400) of deferred deduction remuneration is attributable to services performed by C in X's 2017 taxable year; $4,500 ($95,200 − $90,700) of deferred deduction remuneration is attributable to services performed by C in X's 2018 taxable year; and $4,800 ($100,000 − $95,200) of remuneration is attributable to services performed by C in X's 2019 taxable year.
(i) D is an applicable individual of corporation W for all relevant taxable years. D begins employment with W on January 1, 2016. On December 31, 2020, D obtains the right to a payment from W equal to 10 percent of D's highest annual salary multiplied by D's years of service commencing on January 1 of the year following D's separation from service. In 2020, D has an annual salary of $375,000, which increases by $25,000 on January 1 of each subsequent calendar year. D separates from service with W on December 31, 2023, and W pays $360,000 to D on January 1, 2024. W determines the present value of amounts to be paid under the plan using an interest rate of five percent for all years, which, solely for purposes of this example, is assumed to be a reasonable actuarial assumption.
(ii) Under the attribution method for nonaccount balance plans described in paragraph (d)(4) of this section, the increase (or decrease) in the present value of the future payment to which D is entitled under the nonaccount balance plan as of the last day of W's taxable year, over (or under) the
(iii) As of December 31, 2022, D has the right to a payment of $297,500 on January 1, 2023 ($425,000 × 10% × 7 years of service). The present value as of December 31, 2022 of $297,500 payable on January 1, 2023 is $283,333. Therefore, the deferred deduction remuneration attributable to services performed by D in W's 2022 taxable year is $65,546 ($283,333 − $217,680).
(iv) As of December 31, 2023, D has the right to a payment of $360,000 on January 1, 2024 ($450,000 × 10% × 8 years of service). The present value as of December 31, 2023 of $360,000 payable on January 1, 2024 is $360,000. Therefore, the deferred deduction remuneration attributable to services performed by D in W's 2023 taxable year is $76,767 ($360,000 − $283,333).
(i) E is an applicable individual of corporation V for all relevant taxable years. On January 1, 2016, V grants E an option to purchase 100 shares of V common stock at an exercise price of $50 per share (the fair market value of V common stock on the date of grant). On December 31, 2017, E ceases to be a service provider of V or any member of V's aggregated group. On January 1, 2019, E resumes providing services for V and again becomes both a service provider and an applicable individual of V. On December 31, 2020, when the fair market value of V common stock is $196 per share, E exercises the stock option. The remuneration resulting from the stock option exercise is $14,600 (($196 − $50) × 100).
(ii) Pursuant to paragraph (d)(5)(i) of this section, the remuneration resulting from the exercise of a stock option is attributable to services performed by E over the period beginning on the date of grant of the stock option and ending on the date that the stock right is exercised, excluding any days on which E is not a service provider of V. Therefore, the $14,600 is attributed
(i) F is an applicable individual of corporation U for all relevant taxable years. On January 1, 2017, U grants F 100 shares of restricted U common stock. Under the terms of the grant, the shares will be forfeited if F voluntarily terminates employment before December 31, 2019 (so that the shares are subject to a substantial risk of forfeiture through that date) and are nontransferable until the substantial risk of forfeiture lapses. F does not make an election under section 83(b) and continues in employment with U through December 31, 2019, at which time F's rights in the stock become substantially vested within the meaning of § 1.83–3(b) and the fair market value of a share of the stock is $109.50. The deferred deduction remuneration resulting from the vesting of the restricted stock is $10,950 ($109.50 × 100).
(ii) Pursuant to paragraph (d)(5)(ii) of this section, the remuneration resulting from the vesting of restricted stock is attributable to services performed by F on a daily
(i) G is an applicable individual of corporation T for all relevant taxable years. On January 1, 2018, T grants G 100 RSUs. Under the terms of the grant, T will pay G an amount on December 31, 2020 equal to the fair market value of 100 shares of T common stock on that date, but only if G continues to provide substantial services to T (so that the RSU is subject to a substantial risk of forfeiture) through December 31, 2020. G remains employed by T through December 31, 2020, at which time the fair market value of a share of the stock is $219, and T pays G $21,900 ($219 × 100).
(ii) Pursuant to paragraph (d)(5)(iii) of this section, remuneration from the payment under the RSUs is attributed on a daily
(i) H is an applicable individual of corporation S. On January 1, 2015, H and S enter into an employment contract providing that S will make two payments of $150,000 each to H if H has an involuntary separation from service. Under the terms of the contract, the first payment is due on January 1 following the involuntary separation from service, and the second payment is due on January 1 of the following year. On December 31, 2016, H has an involuntary separation from service. S pays H $150,000 on January 1, 2017 and $150,000 on January 1, 2018.
(ii) Pursuant to paragraph (d)(6) of this section, involuntary separation pay may be attributed to services performed by H in the taxable year of S in which the involuntary separation from service occurs. Alternatively, involuntary separation pay may be attributed to services performed by H on a daily
(i) I is an applicable individual of corporation R. On January 1, 2018, I enters into an agreement with R under which R will reimburse I's country club dues for two years following I's separation from service. On December 31, 2020, I ceases to be a service provider of R. I pays $50,000 in country club dues on January 1, 2021 and $50,000 on January 2, 2022. Pursuant to the agreement, R reimburses I $50,000 for the country club dues in 2021and $50,000 in 2022.
(ii) Pursuant to paragraph (d)(7) of this section, remuneration provided in the form of a reimbursement or in-kind benefit after I ceases to be a service provider of R is attributed to services provided by I in R's taxable year in which I ceases to be an officer, director, or employee of R and ceases performing services for, or on behalf of, R. Therefore, $100,000 is attributed to services performed in R's 2020 taxable year.
(10)
(11)
(i) J is an applicable individual of corporation Q for all relevant taxable years. On January 1, 2016, J begins participating in a nonqualified deferred compensation plan that is an account balance plan. Under the terms of the plan, Q will pay J's account balance on January 1, 2021, but only if J continues to provide substantial services to Q through December 31, 2018 (so that the amount credited to J's account is subject to a substantial risk of forfeiture through that date). Q credits $10,000 to J's account annually for five years on January 1 of each year beginning on January 1, 2016. The account earns interest at a fixed rate of five percent per year, compounded annually, which solely for the purposes of this example, is assumed to be a reasonable rate of interest. Therefore, J's account balance is $10,500 ($10,000 + ($10,000 × 5%)) on December 31, 2016; $21,525 ($10,500 + $10,000 + ($20,500 × 5%)) on December 31, 2017; $33,101 ($21,525 + $10,000 + ($31,525 × 5%)) on December 31, 2018; $45,256 ($33,101 + $10,000 + ($43,101 × 5%)) on December 31, 2019; and $58,019 ($45,256 + $10,000 + ($55,256 × 5%)) on December 31, 2020. Q attributes increases and decreases in account balances under the plan using the standard attribution method described in paragraph (d)(3)(i) of this section.
(ii) Under the standard attribution method for account balance plans described in paragraph (d)(3)(i) of this section, any increases in J's account balance as of the last day of Q's taxable year over the account balance as of the last day of the immediately preceding taxable year, increased by any payments made during the taxable year, is attributable to services provided by J in that taxable year. Accordingly, $10,500 of deferred deduction remuneration is initially attributable to services performed by J in Q's 2016 taxable year (the difference between the $10,500 account balance on December 31, 2016 and the zero account balance on December 31, 2015); $11,025 of deferred deduction remuneration is initially attributable to services performed by J in Q's 2017 taxable year (the difference between the $21,525 account balance on December 31, 2017 and the $10,500 account balance on December 31, 2016); $11,576 of deferred deduction remuneration is initially attributable to services performed by J in Q's 2018 taxable year (the difference between the $33,101 account balance on December 31, 2018 and the $21,525 account balance on December 31, 2017); $12,155 of deferred deduction remuneration is attributable to services performed by J in Q's 2019 taxable year (the difference between the $45,256 account balance on December 31, 2019 and the $33,101 account balance on December 31, 2018); and $12,763 of deferred deduction remuneration is attributable to services performed by J in Q's 2020 taxable year (the difference between the $58,019 account balance on December 31, 2020 and the $45,256 account balance on December 31, 2018).
(iii) Under the attribution method described in paragraph (d)(10) of this section, deferred deduction remuneration that is attributable to services performed in a period that includes two or more taxable years of Q during which the deferred deduction remuneration is subject to a substantial risk of forfeiture must be reattributed on a daily
(i) The facts are the same as in
(ii) Under the alternative attribution method for account balance plans described in paragraph (d)(3)(ii) of this section, earnings and losses on a principal addition are attributed to the same disqualified taxable year of Q to which the principal addition is attributed. Therefore, the amount initially attributable to Q's 2016 taxable year is $12,763 (the $10,000 principal addition in 2016 at five percent interest for five years); the amount initially attributable to Q's 2017 taxable year is $12,155 (the $10,000 principal addition in 2017 at five percent interest for four years); the amount initially attributable to Q's 2018 taxable year is $11,576 (the $10,000 principal addition in 2018 at five percent interest for three years); the amount attributable to Q's 2019 taxable year is $11,025 (the $10,000 principal addition in 2019 at five percent interest for two years), and the amount attributable to Q's 2020 taxable year is $10,500 (the $10,000 principal addition in 2020 at five percent interest for one year).
(iii) Under the attribution method described in paragraph (d)(10) of this section, deferred deduction remuneration that is attributable to two or more taxable years of Q during which the deferred deduction remuneration is subject to a substantial risk of forfeiture must be reattributed on a daily
(i) K is an applicable individual of corporation J for all relevant taxable years. K begins employment with J on January 1, 2016 and begins participating in a nonqualified deferred compensation plan that is a defined benefit plan. Under the terms of the plan, J will pay K an amount equal to ten percent of K's highest annual salary multiplied by K's years of service as of K's separation from service, but only if K remains employed through December 31, 2020 (so that the right to the remuneration is subject to a substantial risk of forfeiture through that date). In 2016, K has annual salary of $275,000, which increases by $25,000 on January 1 of each subsequent calendar year. K has a separation from service from J on December 31, 2025, and J pays $500,000 to K on January 1, 2026 pursuant to the terms of the plan. J determines the present value of amounts to be paid under the plan using an interest rate of five percent for all years, which, solely for purposes of this example, is assumed to be a reasonable actuarial assumption.
(ii) As of December 31, 2016, K has a right to a payment of $27,500 on January 1, 2026 ($275,000 × 10% × 1 years of service). The present value as of December 31, 2021, of a $27,500 payment to be made on January 1, 2026, is $17,727. Therefore, the remuneration initially attributable to services performed by K in J's 2021 taxable year is $17,727 ($17,727−$0).
(iii) As of December 31, 2017, K has a right to a payment of $60,000 on January 1, 2026 ($300,000 × 10% × 2 years of service). The present value as of December 31, 2021, of a $60,000 payment to be made on January 1, 2026, is $40,610. Therefore, the remuneration initially attributable to services performed by K in J's 2021 taxable year is $22,884 ($40,610−$17,727).
(iv) As of December 31, 2018, K has a right to a payment of $97,500 on January 1, 2026 ($325,000 × 10% × 3 years of service). The present value as of December 31, 2021, of a $97,500 payment to be made on January 1, 2026, is $69,291. Therefore, the remuneration initially attributable to services performed by K in J's 2021 taxable year is $28,681 ($69,291−$40,610).
(v) As of December 31, 2019, K has a right to a payment of $140,000 on January 1, 2026 ($350,000 × 10% × 4 years of service). The present value as of December 31, 2021, of a $140,000 payment to be made on January 1, 2026, is $104,470. Therefore, the remuneration initially attributable to services performed by K in J's 2021 taxable year is $35,179 ($104,470−$69,291).
(vi) As of December 31, 2020, K has a right to a payment of $187,500 on January 1, 2026 ($375,000 × 10% × 5 years of service). The present value as of December 31, 2021, of a $187,500 payment to be made on January 1, 2026, is $146,911. Therefore, the remuneration initially attributable to services performed by K in J's 2021 taxable year is $42,441 ($146,911−$104,470).
(vii) As of December 31, 2021, K has a right to a payment of $240,000 on January 1, 2026 ($400,000 × 10% × 6 years of service). The present value as of December 31, 2021, of a $240,000 payment to be made on January 1, 2026, is $197,449. Therefore, the remuneration attributable to services performed by K in J's 2021 taxable year is $50,537 ($197,449−$146,911).
(viii) As of December 31, 2022, K has a right to a $297,500 payment on January 1, 2026 ($425,000 × 10% × 7 years of service). The present value as of December 31, 2022, of a $297,500 payment to be made on January 1, 2026, is $256,992. Therefore, the remuneration attributable to services performed by K in J's 2022 taxable year is $59,543 ($256,992−$197,449).
(ix) As of December 31, 2023, K has a right to a $360,000 payment on January 1, 2026 ($450,000 × 10% × 8 years of service). The present value as of December 31, 2023 of a $360,000 payment to be made on January 1, 2026 is $326,532. Therefore, the remuneration attributable to services performed by K in J's 2023 taxable year is $69,539 ($326,531−$256,992).
(x) As of December 31, 2024, K has a right to a $427,500 payment on January 1, 2026 ($475,000 × 10% × 9 years of service). The present value as of December 31, 2024 of a $427,500 payment to be made on January 1, 2026 is $407,143. Therefore, the remuneration attributable to services performed by K in J's 2024 taxable year is $80,612 ($407,143−$326,531).
(xi) As of December 31, 2025, K has a right to a $500,000 payment on January 1, 2026 ($500,000 × 10% × 10 years of service). The present value as of December 31, 2025 of a $500,000 payment to be made on January 1, 2026 is $500,000. Therefore, the applicable individual remuneration attributable to services performed by K in J's 2025 taxable year is $92,857 ($500,000−$407,143).
(xii) Under the attribution method described in paragraph (d)(10) of this section, deferred deduction remuneration that is attributable to two or more taxable years of a covered health insurance provider during which the deferred deduction remuneration is subject to a substantial risk of forfeiture must be reattributed on a daily
(e)
(2)
(ii)
(B)
(3)
(i) L is an applicable individual of corporation O. During O's 2015 taxable year, O pays L $550,000 in salary, which is applicable individual remuneration, and grants L a right to $50,000 of deferred deduction remuneration payable upon L's separation from service from O. L has a separation from service in 2020, at which time O pays L the $50,000 of deferred deduction remuneration attributable to services performed by L in O's 2015 taxable year.
(ii) The $500,000 deduction limitation for 2015 is applied first to L's $550,000 of applicable individual remuneration for 2015. Because the $550,000 otherwise deductible by O in 2015 is greater than the deduction limitation, O may deduct only $500,000 of the applicable individual remuneration for 2015, and $50,000 of the $550,000 of applicable individual remuneration is not deductible for any taxable year. The deduction limitation for remuneration attributable to services provided by L in O's 2015 taxable year is then reduced to zero. Because the $50,000 in deferred deduction remuneration attributable to services performed by L in 2015 exceeds the reduced deduction limitation of zero, that $50,000 is not deductible for any taxable year.
(ii) The $500,000 deduction limitation for 2016 is applied first to M's $300,000 of applicable individual remuneration for 2016. Because the deduction limitation is greater than the applicable individual remuneration, N may deduct the entire $300,000 of applicable individual remuneration paid in 2016. The $500,000 deduction limitation is then reduced to $200,000 by the amount of the applicable individual remuneration ($500,000−$300,000). The reduced deduction limitation is applied to M's $120,000 of deferred deduction remuneration attributable to services performed by M in N's 2016 taxable year that is paid in 2020. Because the reduced deduction limitation of $200,000 is greater than the $120,000 of deferred deduction remuneration, for N's 2020 taxable year, N may deduct the entire $120,000 of deferred deduction remuneration paid in 2020. The $200,000 deduction limitation is reduced to $80,000 by the $120,000 in deferred deduction remuneration against which it was applied ($200,000−$120,000). The reduced deduction limitation of $80,000 is then applied to the remaining $100,000 payment of deferred deduction remuneration attributable to services performed by M in N's 2016 taxable year. Because the $100,000 in deferred deduction remuneration otherwise deductible by N for 2021 exceeds the reduced deduction limitation of $80,000, N may deduct only $80,000 of the deferred deduction remuneration for the 2021 taxable year, and $20,000 of the $100,000 payment is not deductible by N for any taxable year.
(i) N is an applicable individual of corporation M for all relevant taxable years. On January 1, 2013, N begins participating in a nonqualified deferred compensation plan sponsored by M that is an account balance plan. Under the plan, all amounts are fully vested at all times. The balances in N's account (including principal additions and earnings) are $50,000 on December 31, 2013, $100,000 on December 31, 2014, and $200,000 on December 2015. N's applicable individual remuneration from M is $425,000 for 2013, $450,000 for 2014, and $500,000 for 2015. On January 1, 2016, in accordance with the plan terms, M pays $200,000 to N, which is a payment of N's entire account balance under the plan.
(ii) To determine the extent to which M is entitled to a deduction for any portion of the $200,000 payment under the plan, the payment must first be attributed to services performed by N in M's taxable years in accordance with the attribution rules set forth in paragraph (d) of this section. Under the standard attribution method for account balance plans in paragraph (d)(3)(i) of this section, remuneration under an account balance plan is attributed to services performed by N in M's taxable years in an amount equal to the increase (or decrease) in the account balance as of the last day of M's taxable year over the account balance as of the last day of the immediately preceding taxable year, increased by any payments made during that year. Therefore, N's remuneration under the account balance plan is attributed to services performed by N in M's taxable years as follows: $50,000 ($50,000−$0) in 2013, $50,000 ($100,000−$50,000) in 2014, and $100,000 ($200,000−$100,000) in 2015.
(iii) Under the rules in paragraphs (d)(1)(ii) and (e)(2)(ii)(B) of this section, the January 1, 2016 payment of $200,000 is deemed a payment of remuneration attributed to services performed by N in the earliest year that the amount could be attributed under
(iv) The portion of the deferred deduction remuneration attributed to services performed in a disqualified taxable year under paragraph (d) of this section that exceeds the deduction limitation for that disqualified taxable year, as reduced through the date of payment, is not deductible in any taxable year. For M's 2013 taxable year, the deduction limitation is reduced to $75,000 by the $425,000 of applicable individual remuneration for that year. Because $50,000 does not exceed that reduced deduction limitation, all $50,000 of the deferred deduction remuneration attributed to services performed by N in M's 2013 taxable year is deductible for 2016, the year of payment. The deduction limitation for remuneration attributable to services performed by N that are attributable to 2013 is then reduced to $25,000, and this reduced limitation is applied to any future payment of deferred deduction remuneration attributable to services performed by N in 2013. For M's 2014 taxable year, the deduction limitation is reduced to $50,000 by N's $450,000 of applicable individual remuneration for that year. Because $50,000 does not exceed that reduced deduction limitation, all $50,000 of the deferred deduction remuneration attributed to M's 2014 taxable year is deductible for 2016, the year of payment. The deduction limitation for remuneration attributable to services performed by N in 2014 is then reduced to zero, and this reduced limitation is applied to any future payment of deferred deduction remuneration attributable to services performed by N in 2014. For M's 2015 taxable year, the deduction limitation is reduced to zero during 2015 by N's $500,000 of applicable individual remuneration for that year. Because $100,000 exceeds the reduced limit of zero, the $100,000 of the deferred deduction remuneration attributed to services performed by N in M's 2015 taxable year is not deductible for the year of payment (or any other taxable year). As a result, $100,000 of the $200,000 payment ($50,000 + $50,000 + $0) is deductible by M for M's 2016 taxable year, and the remaining $100,000 is not deductible by M for any taxable year.
(i) O is an applicable individual of corporation L for all relevant taxable years. On January 1, 2016, O begins participating in a nonqualified deferred compensation plan sponsored by L that is an account balance plan. Under the plan, all amounts are fully vested at all times. L credits principal additions to O's account each year, and credits earnings based on a predetermined actual investment within the meaning of § 31.3121(v)(2)–1(d)(2)(i)(B). The balances in O's account (including principal additions and earnings) are $100,000 on December 31, 2016, $250,000 on December 31, 2017, and $450,000 on December 2018. O's applicable individual remuneration from L is $500,000 for 2016, $300,000 for 2017, and $450,000 for 2018. On January 1, 2019, L pays O $400,000 in accordance with the plan terms. As a result of the payment, O's remaining account balance is $50,000 ($450,000 − $400,000). On December 31, 2019, O's account balance is increased to $200,000 by additional credits made during the year. O's applicable remuneration from L is $200,000 for 2019. On January 1, 2020, L pays O $200,000 in accordance with the plan terms.
(ii) To determine the extent to which L is entitled to a deduction for any portion of either of the payments under the plan, O's payments under the plan must first be attributed to services performed by O in L's taxable years in accordance with the attribution rules set forth in paragraph (d) of this section. Under the standard attribution method for account balance plans described in paragraph (d)(3)(i) of this section, remuneration is attributed to services performed by O in L's taxable years in an amount equal to the increase in O's account balance as of the last day of L's taxable year over the account balance as of the last day of the immediately preceding taxable year, increased by any payments made during that year. Therefore, O's deferred deduction remuneration under the plan is attributed to L's taxable years as follows: $100,000 ($100,000 − $0) in 2016, $150,000 ($250,000 − $100,000) in 2017, $200,000 ($450,000 − $250,000) in 2018, and $150,000 ($200,000 − $450,000 + $400,000) in 2019.
(iii) Under the rules in paragraphs (d)(1)(ii) and (e)(2)(ii)(B) of this section, the January 1, 2019 payment of $400,000 is deemed a payment of remuneration attributed to services performed by O in the earliest taxable year that the amount could be attributed under paragraph (d)(3)(i) of this section. L's first taxable year to which any portion of the payment could be attributed is L's 2016 taxable year. Accordingly, $100,000 of the $400,000 payment is attributed to services performed by O in L's 2016 taxable year. L's next earliest taxable year to which any portion of the payment could be attributed is L's 2017 taxable year. Accordingly, $150,000 of the $400,000 payment is attributed to services performed by O in L's 2017 taxable year. L's next earliest taxable year to which any portion of the payment could be attributed is L's 2018 taxable year. Accordingly, the remaining $150,000 of the $400,000 payment is attributed to services performed by O in L's 2018 taxable year. Because the portion of the $400,000 payment attributed to L's 2018 taxable year is less than the total deferred deduction remuneration attributed to L's 2018 taxable year, the excess deferred deduction remuneration ($50,000) is treated as paid in a subsequent taxable year.
(iv) The portion of the deferred deduction remuneration attributed to services performed in a disqualified taxable year under paragraph (d) of this section that exceeds the deduction limitation for that disqualified taxable year, as reduced, is not deductible for any taxable year. For L's 2016 taxable year, the deduction limitation is reduced to zero by the $500,000 of applicable individual remuneration for that year. Because $100,000 exceeds the reduced deduction limitation of zero, the $100,000 of the deferred deduction remuneration is not deductible for L's 2019 taxable year, the year of payment, or any other taxable year. For L's 2017 taxable year, the deduction limitation is reduced to $200,000 by the $300,000 of applicable individual remuneration for that year. Because $150,000 does not exceed that reduced deduction limitation, the $150,000 of the deferred deduction remuneration is deductible for 2019, the year of payment. The deduction limitation for remuneration attributable to services performed by O in 2017 is then reduced to $50,000, and this reduced limitation is applied to any future payment of deferred deduction remuneration attributable to services performed by O in 2017. For L's 2018 taxable year, the deduction limitation is reduced to $50,000 by the $450,000 of applicable individual remuneration for that year. Because the $150,000 of deferred deduction remuneration exceeds the reduced deduction limitation of $50,000, $100,000 of the $150,000 attributable to services performed by O in L's 2018 taxable year is not deductible for L's 2019 taxable year, the year of payment, or any other taxable year. As a result, $200,000 of the $400,000 payment ($0 + $150,000 + $50,000) is deductible by L for L's 2019 taxable year, and the remaining $200,000 is not deductible by L for any taxable year.
(v) Applying the rules in paragraphs (d)(1)(ii) and (e)(2)(ii)(B) of this section to the January 1, 2020 payment of $200,000, the payment is deemed a payment of deferred deduction remuneration attributed to services performed by O in the earliest taxable year that the amount could be attributed under paragraph (d)(3)(i) of this section. L's first taxable year to which any portion of the payment could be attributed is L's 2018 taxable year because all of the deferred deduction remuneration attributed to earlier taxable years was deemed paid as part of the January 1, 2019 payment. Accordingly, $50,000 of the $200,000 payment is attributed to services performed by O in L's 2018 taxable year (because the remaining portion of the deferred deduction remuneration under the plan originally attributed to services performed by O in L's 2018 taxable year was deemed paid as part of the January 1, 2019 payment). L's next earliest taxable year to which any portion of the payment is attributed is L's 2019 taxable year. Accordingly, $150,000 of the $200,000 payment is attributed to services performed by O in L's 2019 taxable year.
(vi) The portion of the deferred deduction remuneration attributed to a disqualified taxable year under paragraph (d) of this section that exceeds the deduction limitation
(i) The facts are the same as set forth in
(ii) To determine the extent to which L is entitled to a deduction for any portion of either payment under the plan, the payments to O under the plan must first be attributed to services performed by O in F's taxable years in accordance with the attribution rules set forth in paragraph (d) of this section. Under the alternative attribution method for account balance plans in paragraph (d)(3)(ii) of this section, the amount of remuneration under an account balance plan attributed to services performed in a taxable year is equal to the sum of the principal additions credited to the plan for that taxable year plus (or minus) the earnings (or losses) credited on those principal additions.
(iii) Under the rule in paragraphs (d)(1)(ii) and (e)(2)(ii)(B) of this section, the $400,000 payment on January 1, 2019, is deemed to constitute a payment of remuneration attributed to services performed by O in the earliest taxable year that the amount could be attributed under paragraph (d)(3)(ii) of this section. L's first taxable year to which any portion of the payment could be attributed is L's 2016 taxable year. Accordingly, $175,000 of the $400,000 payment is attributed to services performed by O in L's 2016 taxable year. The next earliest taxable year of L to which any portion of the payment could be attributed is L's 2017 taxable year. Accordingly, $125,000 of the $400,000 payment is attributed to services performed by O in L's 2017 taxable year. L's next earliest taxable year to which any portion of the payment could be attributed is L's 2018 taxable year. Accordingly, the remaining $100,000 of the $400,000 payment is attributed to services performed by O in L's 2018 taxable year. Because the portion of the $400,000 payment attributed to L's 2018 taxable year is less than the total deferred deduction remuneration attributable to services performed by O in L's 2018 taxable year, the excess deferred deduction remuneration ($50,000) is treated as paid in a subsequent taxable year.
(iv) The portion of the deferred deduction remuneration attributable to services performed in a disqualified taxable year under paragraph (d) of this section that exceeds the deduction limitation for that disqualified taxable year, as reduced, is not deductible for any taxable year. For L's 2016 taxable year, the deduction limitation is reduced to zero by the $500,000 of applicable individual remuneration for that year. Because $175,000 exceeds the reduced deduction limitation of zero, the $175,000 is not deductible for L's 2019 taxable year, the year of payment, or any other taxable year. For L's 2017 taxable year, the deduction limitation is reduced to $200,000 by the $300,000 of applicable individual remuneration for that year. Because $125,000 does not exceed the reduced deduction limitation, the $125,000 payment is deductible for 2019. For L's 2018 taxable year, the deduction limitation is reduced to $50,000 by the $450,000 of applicable individual remuneration for that year. Because $100,000 exceeds the reduced limitation of $50,000, $50,000 of the $100,000 attributable to L's 2018 taxable year is not deductible for 2019, the year of payment, or any other taxable year. As a result, $175,000 of the $400,000 payment ($0 + $125,000 + $50,000) is deductible by L for L's 2019 taxable year, and the remaining $225,000 is not deductible by L for any taxable year.
(v) Earnings through January 1, 2020 on the excess deferred deduction remuneration attributable to L's 2018 taxable year ($50,000) that was not paid as part of the January 1, 2019 payment are $10,000. Earnings through January 1, 2020 on the $100,000 in principal credited to O's account on January 1, 2019 are $15,000. Therefore, as of January 1, 2020, O's remaining deferred deduction remuneration under the plan is attributed to L's taxable years as follows: $60,000 ($50,000 + $10,000) to 2018 and $140,000 ($125,000 + $15,000) to 2019. Applying the rules in paragraphs (d)(1)(ii) and (e)(2)(ii)(B) to the January 1, 2020 payment of $200,000, the payment is deemed a payment of deferred deduction remuneration attributed to services performed by O in the earliest taxable year that the amount could be attributed under paragraph (d)(3)(ii) of this section. L's first taxable year to which any portion of the payment could be attributed is L's 2018 taxable year because all of the deferred deduction remuneration attributed to earlier taxable years was deemed paid as part of the January 1, 2019 payment. Accordingly, $60,000 of the $200,000 payment is attributed to services performed by O in L's 2018 taxable year. L's next taxable earliest taxable year to which any portion of the payment could be attributed is F's 2019 taxable year. Accordingly, $140,000 of the $200,000 payment is attributed to services performed by O in L's 2019 taxable year.
(vi) The portion of the deferred deduction remuneration attributed to a disqualified taxable year under paragraph (d) of this section that exceeds the deduction limitation for that disqualified taxable year, as reduced, is not deductible for any taxable year. For L's 2018 taxable year, the deductible limitation is reduced to zero by the $450,000 of applicable individual remuneration for that year and the payment of $50,000 of deferred deduction remuneration attributable to that year. Because $60,000 exceeds the reduced deduction limitation of zero, the $60,000 is not deductible for the year of payment (or any other taxable year). For L's 2019 taxable year, the deduction limitation is not reduced because there is no applicable individual remuneration for that year. Because $140,000 does not exceed the unreduced $500,000 limitation, the $140,000 is deductible for 2020, the year of payment. As a result, $140,000 of the $200,000 payment ($0 + $140,000) is deductible for L's 2020 taxable year, and the remaining $60,000 is not deductible by L for any taxable year.
(4)
(ii)
(5)
(i) Corporations I, J, and K are members of the same aggregated group under paragraph (b)(3) of this section. In 2016, C is an employee of, and performs services for, I, J, and K. C's total applicable individual remuneration for 2016 is $1,500,000, which consists of $750,000 of applicable individual remuneration for services provided to K; $450,000 of applicable individual remuneration for services provided to J; and $300,000 of applicable individual remuneration for services to I.
(ii) Because I, J, and K are members of the same aggregated group, the applicable individual remuneration otherwise deductible by them is aggregated for purposes of applying the deduction limitation. Further, because the aggregate applicable individual remuneration otherwise deductible by I, J, and K for 2016 exceeds the deduction limitation for C for that taxable year, the deduction limitation is prorated and allocated to the members of the aggregated group in proportion to the applicable individual remuneration otherwise deductible by each member of the aggregated group for that taxable year. Therefore, the deduction limitation that applies to the applicable individual remuneration otherwise deductible by K is $250,000 ($500,000 × ($750,000/$1,500,000)); the deduction limitation that applies to the applicable individual remuneration otherwise deductible by J is $150,000 ($500,000 × ($450,000/$1,500,000)); and the deduction limitation that applies to applicable individual remuneration otherwise deductible by I is $100,000 ($500,000 × ($300,000/$1,500,000)). Therefore, for the 2016 taxable year, K may not deduct $500,000 of the $750,000 of applicable individual remuneration paid to C ($750,000 − $250,000); J may not deduct $300,000 of the $450,000 of applicable individual remuneration paid to C ($450,000 − $150,000); and I may not deduct $200,000 of the $300,000 of applicable individual remuneration paid to C ($300,000 − $100,000).
(i) The facts are the same as
(ii) Because C's total applicable individual remuneration of $400,000 for 2016 for services provided to K, J, and I does not exceed the $500,000 limitation, K, J, and I may deduct $75,000, $150,000, and $175,000, respectively, for 2016. The deduction limitation is then reduced to $100,000 by the total applicable individual remuneration deductible by all members of the aggregated group ($500,000 − $400,000). The deduction limitation, as reduced, is then applied to any deferred deduction remuneration attributable to services provided by C in 2016 in the first subsequent taxable year that it becomes deductible, which is the $60,000 payment made on April 1, 2018. Because the $60,000 of deferred deduction remuneration otherwise deductible by K does not exceed the $100,000 deduction limitation, K may deduct the entire $60,000 for its 2018 taxable year. The $100,000 deduction limitation is then reduced by the $60,000 of deferred deduction remuneration deductible by K for 2018, and the reduced deduction limitation of $40,000 ($100,000 − $60,000) is applied to the $75,000 of deferred deduction remuneration that is otherwise deductible for 2019. Because the deferred deduction remuneration of $75,000 otherwise deductible by J exceeds the reduced deduction limitation of $40,000, J may deduct only $40,000, and the remaining $35,000 ($75,000 − $40,000) is not deductible by J for that taxable year or any other taxable year.
(i) The facts are the same as
(ii) The results are the same as
(f)
(ii)
(B)
(iii)
(B)
(C)
(2)
(3)
(i) Corporation J merges with and into corporation H on June 30, 2015, such that H is the surviving entity. As a result of the merger, J's taxable year ends on June 30, 2015. For its taxable year ending June 30, 2015, J is a covered health insurance provider. For all taxable years before the taxable year of the merger, H is not a covered health insurance provider. However, solely as a result of the merger, H becomes a covered health insurance provider for its 2015 taxable year.
(ii) Corporation J is a covered health insurance provider for its short taxable year ending June 30, 2015. Corporation H is not treated as a covered health insurance provider for its 2015 taxable year by reason of the transition period relief in paragraph (d)(1)(ii)(A) of this section. However, H will be a covered health insurance provider for its 2016 taxable year and all subsequent taxable years for which it is a covered health insurance provider under paragraph (b)(4) of this section.
(i) On January 1, 2016, corporations D, E, and F are members of a controlled group within the meaning of section 414(b). F is a health insurance issuer that is a covered health insurance provider under paragraph (b)(4)(i)(B) of this section. D and E are not health insurance issuers (but are treated as covered health insurance providers pursuant to paragraph (b)(4)(i)(C) and (D) of this section). F's taxable year is a fiscal year ending on September 30. P is an applicable individual of F for all taxable years. On May 1, 2016, a controlled group within the meaning of section 414(b) consisting of corporations C and B purchases all of the stock of corporation F, resulting in a controlled group within the meaning of section 414(b) consisting of corporations C, B, and F. C and B are not health insurance issuers. The C, B, and F controlled group is a consolidated group within the meaning of § 1.1502–1(h). Thus, F's taxable year ends on May 1, 2016 by reason of § 1.1502–76(b)(1)(ii)(A)(
(ii) D and E are covered health insurance providers for the taxable year ending December 31, 2016 because they were in an aggregated group with F for a portion of their taxable year. Accordingly, D and E are subject to the deduction limitation under section 162(m)(6) for their taxable years ending December 31, 2016. C and B are not treated as covered health insurance providers for their taxable year ending December 31, 2016, by reason of the transition period relief of paragraph (d)(1)(ii)(A) of this section. F, however, is a covered health insurance provider for its taxable year ending May 1, 2016, and for its taxable year ending December 31, 2016.
(iii) P is an applicable individual whose remuneration is subject to the deduction limitation under section 162(m)(6) for F's short taxable year ending May 1, 2016. In addition, remuneration for services by P for C, B or F after May 1, 2016, during the taxable year of the consolidated group ending December 31, 2016, is subject to the deduction limitation under section 162(m)(6), even though C and B are not
(i) The same facts as
(ii) F is a covered health insurance provider for its short taxable year ending May 1, 2016. However, because F is not a health insurance issuer that is a covered health insurance provider, F is not treated as a covered health insurance provider for its short, post-acquisition taxable year ending December 31, 2016, during which it is a member of the consolidated group comprised of C, B, and F.
(iii) P is an applicable individual whose remuneration is subject to the deduction limitation under section 162(m)(6) and paragraph (c) of this section for F's short taxable year ending May 1, 2016. However, because F is not a health insurance issuer, remuneration for P's services for C, B or F after May 1, 2016, during the taxable year of the consolidated group ending December 31, 2016, are not subject to the deduction limitation under section 162(m)(6).
(g)
(2)
(ii)
Corporation A, a covered health insurance provider, pays $750,000 of applicable individual remuneration to P, an applicable individual, during A's disqualified taxable year ending December 31, 2016. Of the $750,000, $300,000 is an excess parachute payment as defined in section 280G(b)(1), the deduction for which is disallowed by reason of that section. The excess parachute payment reduces the $500,000 deduction limitation to $200,000 ($500,000—$300,000). Therefore, A may deduct only $200,000 of the $750,000 in applicable individual remuneration, and $250,000 of the payment is not deductible by reason of section 162(m)(6).
(h)
(2)
(ii)
(iii)
(i)
(2)
(i) Q is an applicable individual of corporation Z. Z's 2010, 2011, and 2012 taxable years are disqualified taxable years. Z's 2013, 2014, and 2015 taxable years are not disqualified taxable years. However, Z's 2016 taxable year and all subsequent taxable years are disqualified taxable years. Q receives $200,000 of applicable individual remuneration from Z for 2012, and becomes entitled to $800,000 of deferred deduction remuneration that is attributable to services performed by Q in 2012. Z pays Q $350,000 of the deferred deduction remuneration in 2015, and the remaining $450,000 of the deferred deduction remuneration in 2016. These payments are otherwise deductible by Z in 2015 and 2016, respectively.
(ii) Deferred deduction remuneration attributable to services performed by Q in Z's 2010, 2011, and 2012 taxable years that is otherwise deductible in Z's 2013, 2014, or 2015 taxable years is not subject to the deduction limitation under section 162(m)(6) by reason of the transition rule under paragraph (i)(1) of this section. However, deferred deduction remuneration attributable to services performed in Z's 2010, 2011, and 2012 taxable years that is otherwise deductible in a later taxable year that is a disqualified taxable year (in this case, Z's 2016 and subsequent taxable years) is subject to the deduction limitation under section 162(m)(6). Accordingly, the deduction limitation with respect to applicable individual remuneration and deferred deduction remuneration attributable to services performed by Q in 2012 is determined by reducing the $500,000 deduction limitation by the $200,000 of applicable individual remuneration paid to Q by Z for 2012 ($500,000–$200,000). Under the transition rule of paragraph (i)(1) of this section, no portion of the reduced deduction limitation of $300,000 for the 2012 taxable year is applied against the $350,000 payment made in 2015, and accordingly, the deduction limitation is not reduced by the amount of that payment. The reduced deduction limitation is then applied to Q's $450,000 of deferred deduction remuneration attributable to services performed by Q in 2012 that is paid to Q and becomes otherwise deductible in 2016. Because the reduced deduction limitation of $300,000 is less than the $450,000 otherwise deductible by Z in 2016, Z may deduct only $300,000 of the deferred deduction remuneration, and $150,000 of the $450,000 payment is not deductible by Z in that taxable year or any taxable year.
(i) R is an applicable individual of corporation Y, which is a covered health insurance provider for all relevant taxable years. During 2010, Y pays R $400,000 in salary and grants R a right to $200,000 in deferred deduction remuneration payable on a fixed schedule in 2011, 2012, and 2013. Pursuant to the fixed schedule, Y pays R $50,000 of deferred deduction remuneration in 2011, $50,000 of deferred deduction remuneration in 2012, and the remaining $100,000 of deferred deduction remuneration in 2013.
(ii) Because the deduction limitation for deferred deduction remuneration under section 162(m)(6)(A)(ii) is effective for deferred deduction remuneration that is attributable to services performed by an applicable individual during any disqualified taxable year beginning after December 31, 2009 that would otherwise be deductible in a taxable year beginning after December 31, 2012, only the deferred deduction remuneration paid by Y in 2013 is subject to the deduction limitation. However, the limitation is applied as if section 162(m)(6) and paragraph (c)(2) of this section were effective for taxable years beginning after December 31, 2009 and before January 1, 2013. Accordingly, the deduction limitation with respect to remuneration for services performed by R in 2010 is determined by reducing the $500,000 deduction limitation by the $400,000 of applicable individual remuneration paid to R for 2010 ($500,000–$400,000). The reduced deduction limitation of $100,000 is further reduced to zero by the $50,000 of deferred deduction remuneration attributable to services performed by R in Y's 2010 taxable year that is deductible in each of 2011 and 2012 (($100,000–$50,000–$50,000). Because the deduction limitation is reduced to zero, none of the $100,000 of deferred deduction remuneration attributable to services performed by R in Y's 2010 taxable year and paid to R in 2013 is deductible.
(j)