International Trade Administration
National Oceanic and Atmospheric Administration
National Telecommunications and Information Administration
Federal Energy Regulatory Commission
Centers for Disease Control and Prevention
Community Living Administration
Food and Drug Administration
Federal Emergency Management Agency
Fish and Wildlife Service
National Park Service
Drug Enforcement Administration
Parole Commission
Federal Aviation Administration
Federal Highway Administration
Federal Transit Administration
National Highway Traffic Safety Administration
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.
To subscribe to the Federal Register Table of Contents LISTSERV electronic mailing list, go to http://listserv.access.gpo.gov and select Online mailing list archives, FEDREGTOC-L, Join or leave the list (or change settings); then follow the instructions.
Small Business Administration.
Notice of amendments to final policy directive.
The U.S. Small Business Administration (SBA) is amending its Small Business Innovation Research (SBIR) Program Policy Directive in response to public comments SBA received on the final SBIR Policy Directive, published on August 6, 2012. SBA is also making several minor clarifying changes to ensure that the SBIR participants clearly understand certain program requirements.
These amendments to the SBIR Policy Directive are effective January 8, 2014.
Edsel Brown, Assistant Director, Office of Innovation, at (202) 401–6365 or
On December 31, 2011, the President signed into law the National Defense Authorization Act for Fiscal Year 2012 (Defense Reauthorization Act), Public Law 112–81, 125–Stat. 1298. Section 5001, Division E of the Defense Reauthorization Act contains the SBIR/STTR Reauthorization Act of 2011 (Reauthorization Act), which amended the Small Business Act and made several amendments to the SBIR Program. The Reauthorization Act required SBA to issue amendments to the SBIR Policy Directive and publish the amendments in the
On August 6, 2012, SBA published a final SBIR Policy Directive implementing the various provisions of the Reauthorization Act at 77 FR 46806. The directive made several key changes to the SBIR Program relating to eligibility, the SBIR award process, SBIR Program administration, and fraud, waste and abuse. Although the SBIR Policy Directive is intended for use by the SBIR participating agencies, SBA believed that public input on the directive from all parties involved in the program would be invaluable. Therefore, SBA sought public comments on the final directive, and stated that it may amend the directive in response to these comments at a later time.
In response to this request, SBA received comments on various parts of the directive. Several comments recommended that SBA strengthen and clarify the Policy Directive language with regard to SBIR data rights and the obligation of federal agencies to give a preference in contracting to SBIR awardees for follow-on Phase III work. SBA agrees that these are areas of the SBIR policy that are vital to the program and require clarification and improvement. SBA continues to evaluate these issues and will address them in a subsequent Policy Directive revision.
SBA also received comments that the definition of Essentially Equivalent Work in section 3(j) of the Policy Directive should be changed to be more in line with the common usage. The concern is that the definition in the Policy Directive is more stringent than the norm for Government contracting and places a higher burden on the small businesses participating in the SBIR program. The commenter, however, did not provide SBA with this commonly used definition and SBA could not find one. Therefore, SBA has not modified the definition at this time. However, SBA has revised the language in section 7(d) of the Directive to further clarify funding of “essentially equivalent work.”
Section 4(a)(3) of the Policy Directive, “Agency benchmarks for progress towards commercialization” sets forth the program policy regarding an eligibility requirement for Phase I awards. SBA received comments requesting clarification of the time periods used to calculate the transition rate and commercialization rate benchmark requirements. Commenters also requested clarification about how agencies determine which firms must comply with the transition rate and commercialization rate benchmarks. In response to these comments, SBA revised and reorganized section 4(a)(3) to clarify several procedural elements about the benchmark determinations and enhance its readability.
Section 4(a)(3) clarifies the time periods used to calculate awardee rates of transition from Phase I to Phase II and provides two examples of the calculation. While the rate is calculated using Phase I awards received in the most recent 5,10, or 15-year period (agencies choose which period they use), excluding the most recently completed fiscal year; the period used when counting the Phase II awards is lagged one year. That is, when calculating the number of Phase I awards received over a particular time period, the time period evaluated does not include the most recently completed fiscal year; however, when calculating the number of Phase II awards received, the time period evaluated does include the most recently completed fiscal year but does not include the first year of the period evaluated for Phase I awards received. The period used to calculate Phase II awards is lagged one-year because it is unlikely that a new Phase I would transition to a Phase II within the same year. SBA also clarified that the Phase II transition benchmark requirement applies only to awardees that have received more than 20 Phase I awards over the applicable time period and that the commercialization benchmark applies only to firms that received more than 15 Phase II awards over the applicable time period.
Based on additional input from the agencies participating in the SBIR program, SBA also revised several procedural elements of the Phase II transition benchmark requirement in section 4(a)(3) to simplify the process for small businesses and reduce the administrative burden on the agencies. Specifically, in section 4(a)(3)(iii), SBA changed the start date for the one-year ineligibility period for firms that do not meet the benchmarks. The date was changed from the date of application submission to June 1st of each year. SBA made this change for several reasons: (1) It is a clearly defined period for affected small businesses; (2) to
Some respondents asked if the provision in section 4(b)(5) allowing one Sequential Phase II award included supplementary awards such as Phase 2.5 or Phase IIb awards in the definition of a Phase II award. SBA relocated the language at section 4(b)(6) to new section 4(b)(8) and added new section 4(b)(6) to clarify SBA's policy on supplemental phase II awards. Section 4(b)(6) now clarifies how Phase II award amounts are calculated when supplemental awards are issued. Furthermore, section 4(b)(6) specifies that all supplementary awards, such as a Phase IIb, must be linked to either an initial Phase II or a sequential Phase II award and is added to the amount of that award for the purpose of determining the size of the Phase II award. This means that all supplementary Phase II awards including options, enhancements, administrative supplements, and Phase IIb-type programs are considered as part of the initial Phase II or sequential Phase II from which they derive and are therefore subject to the Phase II per-award guideline amount of $1 million and limit of $1.5 million.
SBA repeated the language in section 9(d)(2) in new section 4(b)(7), which explains how a Phase I awardee may receive an award from one agency and also may receive a subsequent Phase II award from another agency. SBA also clarified in section 4(b)(7) that the same process applies to a second, sequential Phase II award that follows an initial Phase II award from a different agency. This policy is relevant to interagency actions, which are found at section 9 of the Policy Directive, and also to Phase II awards, which is found at section 4 of the Policy Directive.
SBA received comments concerning section 9 of the Policy Directive, which address measures to prevent fraud, waste and abuse in the program. The respondents commented that the administrative requirements contained in section 9 may be too stringent and may discourage small businesses from applying. SBA notes that it developed these requirements, including the procedures and requirements for certification, in consultation with the Council of Inspectors General on Integrity and Efficiency. SBA believes that these provisions can help reduce fraud, waste and abuse in the program and does not think these provisions should be changed at this time.
SBA received comments on the Department of Defense's (DoD's) Commercialization Readiness Program, outlined in section 12(b) of the SBIR Policy Directive. In response to comments that agency efforts to increase transitions to Phase III could reduce the innovative nature of SBIR awards, SBA has added that when DoD reports on its Phase II insertion incentives, it should note efforts to ensure that such incentives do not act to shift the focus of SBIR Phase II awards away from relatively high-risk innovation projects. SBA also amended the provisions relating to the use of SBIR funds for the DoD Commercialization Readiness Program. According to section 1615 of the National Defense Authorization Act for Fiscal Year 2013 (NDAA), Public Law 112–239, 126 Stat. 1632, DoD has the authority to use 1% of its SBIR funding for purposes of administering the Commercialization Readiness Program.
A number of comments asked us to change features that, because they are required by statute, we were not able to modify.
The inadvertent omission of the term “extramural” before “R/R&D budgets” was corrected in section 2(b), which identifies the source of funds for the program.
Section 3 contains definitions of terms that appear throughout the Policy Directive. SBA made an editorial revision to the definition of “Awardee” in section 3(e). SBA revised the word “receiving” to “that receives.”
Section 4(b)(1), which identifies the objective and nature of a Phase II award, includes a statement regarding the eligibility of successor in interest firms for SBIR awards. Because this statement pertains more generally to eligibility for all SBIR awards, it was removed from section 4(b)(1) and added to section 6(a) which addresses program eligibility requirements.
In Section 6, SBA removed the reference to the STTR program regarding the option to make awards to small businesses that are majority owned by multiple venture capital operating companies, hedge funds or private equity firms. When SBA issued its final size regulations on December 27, 2012 (77 FR 76215), it reviewed this issue and determined that such businesses may not participate in the STTR program. Additionally, SBA added the language previously found at section 4(b)(1) regarding successor in interest firms to section 6(a)(5), because section 6(a) addresses general program eligibility. Sections 6(a)(2) through 6(a)(6) were reorganized and renumbered in order to increase readability.
Section 7 addresses issues related to program funding processes. SBA revised the language in paragraph 7(d) to clarify that while duplicate or similar proposals may be submitted in response to apparently similar solicitation topics, essentially equivalent work may not be funded. In addition, SBA revised paragraph (h)(1), which says that funding agreement modifications should be kept to a minimum, to address only modifications that increase the dollar amount of awards. Paragraph (h)(1) also referred to modifications of periods of performance and scope of work. SBA clarified section 7(h)(1) to specify that the concern regarding the number of modifications made to an award pertains only to changes that increase the dollar amount of awards.
Section 8 of the Directive addresses the terms of agreement under SBIR awards. SBA clarified section 8(a) by removing language stating that agencies should discourage SBCs from submitting proprietary information and revised section 8(d) to clarify that the continued use of agency-owned property applies to property acquired by the awardee under the contract.
In response to concerns regarding the cost and accountability of the continuing study by the National Academy of Sciences, SBA modified section 9(h) to clarify that the agreement required between the agencies and the National Academy of Sciences must be made in consultation with the SBA and must comprehensively address the scope and content of the work to be performed.
Section 10(h) explains the process for agencies to submit their SBIR program annual reports to SBA. Paragraph (h)(4) contains a list of information that must be included in each agency's annual report. SBA clarified section 10(h)(4)(xi) to note that agencies must report all instances in which an agency pursued R/R&D, services, production, or any combination thereof of a technology developed under an SBIR award with an entity other than that SBIR awardee.
Section 10(j) contains information on the other reporting requirements for
Section 12(b) addresses the Commercialization Readiness Program at the Department of Defense (DoD). SBA clarified the source of funding for this program by removing the sentence in paragraph (b)(4)(ii) stating that funds for the program would come from the 3% administrative set-aside, and by clarifying that the funds shall not be subject to the limitations on the use of funds in section 9(e)(3). In addition, in section 12(b)(6)(iii)(C), SBA clarified that the DoD must include, along with its description of the incentives used for this program, information on measures taken to ensure that such incentives do not shift the focus of the SBIR Phase II awards away from the relatively high-risk innovation projects they are intended to promote.
Section 12(b)(5) addresses DoD's Commercialization Readiness Program. The Policy Directive states that DoD may establish transition goals and reporting requirements for awards less than $1,000,000,000. The amount listed in section 12(b)(5) contained a typographical error, which was corrected to $100,000,000.
Appendix I provides instructions for the preparation of program solicitations. In Appendix I, SBA revised the certification check box regarding notification if work is subsequently funded by another Federal agency to clarify that it pertains to work funded and completed under the award rather than to the work proposed for the award.
The updated SBIR Policy Directive, incorporating all changes noted here, will be posted on
To: The Small Business Innovation Research Program Managers.
Subject: Amendments to SBIR Policy Directive Published on August 6, 2012 at 77 FR 46806.
1.
2.
3.
4.
5.
6.
Authorized by:
SBA amends the SBIR Policy Directive as follows:
1. Amend section 2(b) by adding the term “extramural” before “R/R&D budgets” each place it appears.
2. Revise section 3(e) to read as follows:
(e)
3. Revise section 4(a)(3) to read as follows:
(3)
(i) Agencies must apply two benchmark rates addressing an applicant's progress towards commercialization—the Phase II Transition Rate Benchmark and the Commercialization Rate Benchmark.
(A) The Phase II Transition Rate Benchmark sets the minimum required number of Phase II awards the applicant must have received for a given number of Phase I awards received during the specified period. This Transition Rate Benchmark applies only to Phase I applicants that have received more than 20 Phase I awards over the time period used by the agency for the benchmark determination.
(B) The agency Commercialization Rate Benchmark sets the minimum Phase III commercialization results that a Phase I applicant must have realized from its prior Phase II awards in order to be eligible to receive a new Phase I award from that agency. This benchmark requirement applies only to Phase I applicants that have received more than 15 Phase II awards over the time period used by the agency for the benchmark determination.
(ii)
(iii)
(iv)
(A) The agency Phase II Transition Rate Benchmark establishes the number of Phase II awards a small business
On August 1, 2014, an SBC submits an application to an agency using a Transition Rate Benchmark of 0.25 and a 5-year time period. The June 1, 2014 TechNet Company Registry tabulation shows that the SBC received 24 Phase I awards during FY08–FY12. Since this SBC has received 20 or more Phase I awards during the 5-year period, the SBC is required to meet the Transition Rate Benchmark. The SBC received 8 Phase II awards in FY09–FY13 and therefore has a 5-year Phase II transition rate of 8/24 or 0.33 (# of Phase II awards in FY09–FY13/# of Phase I awards in FY08–FY12). Because the SBC meets or exceeds the agency Transition Rate Benchmark, it is considered for award through the usual proposal evaluation process.
On September 1, 2014, an SBC is interested in applying for a Phase I award, knows it has received a number of Phase I awards in recent years, but is unsure if it is meeting the required Phase II transition rate. The company official logs onto the Company Registry at SBIR.gov to check its status and sees a flag saying it did not meet the required benchmark transition rate of 0.25 on June 1, 2014 and is therefore ineligible for a Phase I award through May 31, 2015. The company checks its records and sees that it received 30 Phase I awards during FY08–FY12 and 6 Phase II awards during FY09–FY13. Its transition rate is therefore 6/30 or 0.20 which is under the required rate of 0.25. The SBC does not apply for a new Phase I award through May 31, 2015 because it knows its application would be rejected.
On September 1, 2014, an SBC official interested in applying for a Phase I award logs onto the Company Registry at SBIR.gov and sees the flag saying it did not meet the required benchmark transition rate of 0.25 on June 1, 2014 and is not eligible for a Phase I award through May 31, 2015. However, when the company checks its own records, it sees that it received 8 Phase II awards during FY09–FY13, not the 6 awards showing on the Web site. Its transition rate is therefore 8/30 or 0.26 which is above the required rate of 0.25. The company official therefore goes to SBIR.gov, clicks on the “Dispute Transition Rate” button, and enters the information about the discrepancy. SBA uses the information provided by the company and, working with the relevant agencies, identifies that two Phase II awards from FY09 had been inadvertently omitted. SBA updates and corrects the database and informs the firm that it is indeed eligible to receive SBIR Phase I awards.
(B) An SBC that has received more than 20 Phase I awards in the relevant time period can view its Phase II transition rate on the Company Registry page at SBIR.gov. Generally, the award data used to calculate an SBC's transition rate will be complete by the end of March each year. An SBC may view its SBIR/STTR award information on the Company Registry at any time. If an awardee believes its Phase II transition rate is calculated using incomplete award information, the awardee may dispute the rate using the link provided on the Company Registry, provide the additional award information, and request a reconsideration of its transition rate. Requests for reconsideration of a firm's transition rate received by SBA from April 1st through April 30th of each year will be considered for the June 1st transition rate assessment.
(C) Agencies must set the Phase II Transition Rate Benchmark as appropriate for their programs and industry sectors. When setting the Transition Rate Benchmark, agencies should consider that Phase I is designed and intended to explore high-risk, early-stage research ideas and, as a result, not all Phase I awards are expected to result in a Phase II award.
(v)
(A) in financial terms, such as by using the ratio of the dollar value of revenues and additional investment resulting from prior Phase II awards relative to the dollar value of the Phase II awards received over the time period;
(B) in terms of the share of Phase II awards received over the time period that have resulted in the introduction of a product to market; or
(C) by other means such as using a commercialization scoring system that rates awardees on their past commercialization success.
(vi) Agencies must submit their Transition Rate Benchmark, Commercialization Rate Benchmark, and time periods to SBA for approval. SBA will publish the benchmarks and time periods, seek public comment, and maintain a table of the current requirements on
(vii) SBA maintains a system that records all Phase I, Phase II and Government Phase III awards, and other commercialization information; and calculates the Phase II transition rates for all Phase I awardees and the commercialization rates for all Phase II awardees.
(viii) If an applicant fails to meet an agency's benchmark, its name will appear on the list of companies made available to the agencies on June 1 of each year. An agency may not make a Phase I award to an applicant that does not meet the agency's benchmark.
(ix) If an awardee believes its determination was made in error, it may provide SBA with the pertinent award information and request a reassessment. To do so, awardees may use the link on the Company Registry at
4. Amend section 4(b) by revising paragraph (b)(1) by moving language to 6(a)(4), renumbering paragraph (b)(6) as (b)(8), and inserting paragraphs (b)(6) and (b)(7) to read as follows:
(b)
(1) The object of Phase II is to continue the R/R&D effort from the completed Phase I. Unless an exception set forth in paragraphs (i) or (ii) below applies, only SBIR Phase I awardees are eligible to participate in Phase II.
(i) A Federal agency may issue an SBIR Phase II award to an STTR Phase I awardee to further develop the work performed under the STTR Phase I award. The agency must base its decision upon the results of work performed under the Phase I award and the scientific and technical merit, and commercial potential of the Phase II proposal. The STTR Phase I awardee must meet the eligibility and program requirements of the SBIR Program in order to receive the SBIR Phase II award.
(ii) During fiscal years (FY) 2012 through 2017, the National Institutes of Health (NIH), Department of Defense (DoD) and the Department of Education (DoEd) may issue a Phase II award to a small business concern that did not receive a Phase I award for that R/R&D. Prior to such an award, the heads of those agencies, or designees, must issue a written determination that the small business has demonstrated the scientific and technical merit and feasibility of the ideas that appear to have commercial potential. The determination must be
. . . [paragraphs (2) through (4) are unchanged] . . .
(5) A Phase II awardee may receive one additional, sequential Phase II award to continue the work of an initial Phase II award. The additional, sequential Phase II award has the same guideline amounts and limits as an initial Phase II award.
(6) Agencies may offer special SBIR awards, such as Phase IIB awards, that supplement or extend Phase II awards. For example, some agencies administer Phase IIB awards that differ from the base Phase II in that they require third party matching of the SBIR funds. Each such supplemental award must be linked to a base Phase II award (the initial Phase II, or the second sequential Phase II award). Any SBIR funds used for such special or supplementary awards are aggregated with the amount of the base Phase II to determine the size of that Phase II award. Therefore, while there is no limit on the number of such special/supplementary awards, there is a limit on the total amount of SBIR funds that can be administered through them—the amounts of these awards count towards the size of the initial Phase II or the sequential Phase II, each of which has a guideline amount of $1 million and a limit of $1.5 million. (Note that Phase IIB awards under the NIH SBIR program are administered as second, sequential Phase II awards, not supplemental awards. As such, they are base Phase II awards and subject to the Phase II guideline amounts and limits of $1 million and $1.5 million).
(7) A concern that has received a Phase I award from an agency may receive a subsequent Phase II award from another agency if each agency makes a written determination that the topics of the relevant awards are the same and both agencies report the awards to the SBA including a reference to the related Phase I award and initial Phase II award if applicable.
(8) Agencies may issue Phase II awards for testing and evaluation of products, services, or technologies for use in technical or weapons systems.
5. Revise section 6(a)(2) through § 6(a)(6)to read as follows:
(2) For Phase I, a minimum of two-thirds of the research or analytical effort must be performed by the awardee. For Phase II, a minimum of one-half of the research or analytical effort must be performed by the awardee. Occasionally, deviations from these requirements may occur, and must be approved in writing by the funding agreement officer after consultation with the agency SBIR Program Manager/Coordinator. An agency can measure this research or analytical effort using the total contract dollars or labor hours, and must explain to the small business in the solicitation how it will be measured.
(3) For both Phase I and Phase II, the primary employment of the principal investigator must be with the SBC at the time of award and during the conduct of the proposed project. Primary employment means that more than one-half of the principal investigator's time is spent in the employ of the SBC. This precludes full-time employment with another organization. Occasionally, deviations from this requirement may occur, and must be approved in writing by the funding agreement officer after consultation with the agency SBIR Program Manager/Coordinator. Further, an SBC may replace the principal investigator on an SBIR Phase I or Phase II award, subject to approval in writing by the funding agreement officer. For purposes of the SBIR Program, personnel obtained through a Professional Employer Organization or other similar personnel leasing company may be considered employees of the awardee. This is consistent with SBA's size regulations, 13 CFR 121.106—Small Business Size Regulations.
(4) For both Phase I and Phase II, the R/R&D work must be performed in the United States. However, based on a rare and unique circumstance, agencies may approve a particular portion of the R/R&D work to be performed or obtained in a country outside of the United States, for example, if a supply or material or other item or project requirement is not available in the United States. The funding agreement officer must approve each such specific condition in writing.
(5) An SBIR awardee may include, and SBIR work may be performed by, those identified via a “novated” or “successor in interest” or similarly-revised funding agreement, or those that have reorganized with the same key staff, regardless of whether they have been assigned a different tax identification number. Agencies may require the original awardee to relinquish its rights and interests in an SBIR project in favor of another applicant as a condition for that applicant's eligibility to participate in the SBIR Program for that project.
(6) NIH, Department of Energy and National Science Foundation may award not more than 25% of the agency's SBIR funds to SBCs that are owned in majority part by multiple venture capital operating companies, hedge funds, or private equity firms through competitive, merit-based procedures that are open to all eligible small business concerns. All other SBIR agencies may award not more than 15% of the agency's SBIR funds to such SBCs. SBIR agencies may or may not choose to utilize this funding option. A table listing the agencies that are currently using this authority can be found at
(i) Before permitting participation in the SBIR program by SBCs that are owned in majority part by multiple venture capital operating companies, hedge funds, or private equity firms, the SBIR agency must submit a written determination to SBA, the Senate Committee on Small Business and Entrepreneurship, the House Committee on Small Business and the House Committee on Science, Space, and Technology at least 30 calendar days before it begins making awards to such SBCs. The determination must be made by the head of the Federal agency or designee and explain how awards to such SBCs in the SBIR program will:
(A) induce additional venture capital, hedge fund, or private equity firm funding of small business innovations;
(B) substantially contribute to the mission of the Federal agency;
(C) address a demonstrated need for public research; and
(D) otherwise fulfill the capital needs of small business concerns for additional financing for SBIR projects.
(ii) The SBC that is majority-owned by multiple venture capital operating companies, hedge funds, or private equity firms must register with SBA in the Company Registry Database, at
(iii) The SBC that is majority-owned by multiple venture capital operating companies, hedge funds, or private equity firms must submit a certification with its proposal stating, among other things, that it has registered with SBA.
(iv) Any agency that makes an award under this paragraph during a fiscal year shall collect and submit to SBA data relating to the number and dollar amount of Phase I awards, Phase II awards, and any other category of awards by the Federal agency under the SBIR program during that fiscal year. See section10 of this directive for the specific reporting requirements.
(v) If an agency awards more than the percentage of the funds authorized under section 6(a)(2) of the Policy Directive, the agency shall transfer from its non-SBIR and non-STTR R&D funds to the agency's SBIR funds any amount
(vi) If a Federal agency makes an award under a solicitation more than 9 months after the date on which the period for submitting applications under the solicitation ends, a Covered Small Business Concern is eligible to receive the award, without regard to whether it meets the eligibility requirements of the program for a SBC that is majority-owned by multiple venture capital operating companies, hedge funds, or private equity firms, if the Covered Small Business Concern meets all other requirements for such an award. In addition, the agency must transfer from its non-SBIR and non-STTR R&D funds to the agency's SBIR funds any amount that is so awarded to a Covered Small Business Concern. The funds must be transferred not later than 90 days after the date on which the Federal agency makes the award.
6. Revise section 7(d) to read as follows:
(d)
7. Revise section 7(h)(1) to read as follows:
(h)
(1) In keeping with the legislative intent to make a large number of relatively small awards, modification of funding agreements to increase the dollar amount should be kept to a minimum, except for options in original Phase I or II awards.
8. Revise section 8(a) to read as follows:
(a)
9. Revise section 8(d) to read as follows:
(d)
10. Revise section 9(h) to read as follows:
(h)
(1) Prior to and during the period of study, and to ensure that the concerns of small business are appropriately considered, NAS shall consult with and consider the views of SBA's Office of Investment and Innovation and the Office of Advocacy and other interested parties, including entities, organizations, and individuals actively engaged in enhancing or developing the technological capabilities of small business concerns.
(2) The head of each agency with a budget of more than $50,000,000 for its SBIR Program for fiscal year 1999 shall, in consultation with SBA, and not later than 6 months after December 31, 2011, cooperatively enter into an agreement with NAS regarding the content and performance of the study. SBA and the agencies will work with the Interagency Policy Committee in determining the parameters of the study, including the specific areas of focus and priorities for the broad topics required by statute. The agreement with NAS must set forth these parameters, specific areas of focus and priorities, and comprehensively address the scope and content of the work to be performed. This agreement must also require the NAS to ensure there is participation by and consultation with, the small business community, the SBA, and other interested parties as described in paragraph (1).
(3) NAS shall transmit to SBA, heads of agencies entering into an agreement under this section, the Committee on Science, Space and Technology, the Committee on Small Business of the House of Representatives, and to the Committee on Small Business of the Senate a copy of the report, which includes the results and recommendations, not later than 4 years after December 31, 2011, and every subsequent four years.
11. Revise section 10(h)(4)(xi) to read as follows:
(xi) All instances in which an agency pursued R/R&D, services, production, or any combination thereof of a technology developed under an SBIR award with an entity other than that SBIR awardee.
12. Revise section 10(j)(2) to read as follows:
(2) The system will include a list of any individual or small business concern that has received an SBIR award and that has been convicted of a fraud-related crime involving SBIR funds or found civilly liable for a fraud-related violation involving SBIR funds, of which SBA has been made aware.
13. Revise section 12(b)(4) to read as follows:
(4)
(i) Beginning with FY 2013 and ending in FY 2015, the Secretary of Defense and each Secretary of a military department is authorized to use its SBIR funds for administration of this program in accordance with the procedures and policies set forth in section 9(e)(3) of this directive.
(ii) In addition, the Secretary of Defense and Secretary of each military department is authorized to use not more than an amount equal to 1% of its SBIR funds available to DoD or the military departments for payment of expenses incurred to administer the Commercialization Program. Such funds—
(A) shall not be subject to the limitations on the use of funds in 9(e)(2) or 9(e)(3) of this directive; and
(B) shall not be used to make Phase III awards.
14. Revise section 12(b)(5) to read as follows:
(5)
(i) establish goals for the transition of Phase III technologies in subcontracting plans; and
(ii) require a prime contractor on such a contract to report the number and dollar amount of the contracts entered
15. Revise section 12(b)(6) to read as follows:
(6) The Secretary of Defense shall:
(i) set a goal to increase the number of SBIR Phase II contracts that lead to technology transition into programs of record of fielded systems;
(ii) use incentives in effect as of December 31, 2011 or create new incentives to encourage agency program managers and prime contractors to meet the goal set forth in paragraph (6)(i) above; and
(iii) submit the following to SBA, as part of the annual report:
(A) the number and percentage of Phase II SBIR contracts awarded by DoD that led to technology transition into programs of record or fielded systems;
(B) information on the status of each project that received funding through the Commercialization Program and the efforts to transition these projects into programs of record or fielded systems; and
(C) a description of each incentive that has been used by DoD, the effectiveness of the incentive with respect to meeting DoD's goal to increase the number of SBIR Phase II contracts that lead to technology transition into programs of record of fielded systems, and measures taken to ensure that such incentives do not act to shift the focus of SBIR Phase II awards away from relatively high-risk innovation projects.
16. Revise paragraph 1(a) of the Appendix I: Instructions for Preparation of SBIR Program Solicitation to read as follows:
(a) Summarize in narrative form the request for proposals and the objectives of the SBIR Program.
17. In Appendix I, in the SBIR Funding Agreement Certification and the SBIR Funding Agreement Certification—Life Cycle Certification, revise the checkbox addressing potential duplicative funding to read as follows:
Small Business Administration.
Notice of amendments to final policy directive.
The U.S. Small Business Administration (SBA) is amending its Small Business Technology Transfer (STTR) Program Policy Directive in response to public comments SBA received on the final STTR and Small Business Innovation Research (SBIR) Policy Directives, published on August 6, 2012. SBA is also making several minor clarifying changes to ensure that the STTR participants clearly understand certain program requirements. Additionally, the changes to the STTR Policy Directive are made to maintain concordance with the SBIR program.
These amendments to the STTR Policy Directive are effective January 8, 2014.
Edsel Brown, Assistant Director, Office of Innovation, at (202) 401–6365 or
On December 31, 2011, the President signed into law the National Defense Authorization Act for Fiscal Year 2012 (Defense Reauthorization Act), Public Law 112–81, 125–Stat. 1298. Section 5001, Division E of the Defense Reauthorization Act contains the SBIR/STTR Reauthorization Act of 2011 (Reauthorization Act), which amended the Small Business Act and made several amendments to the STTR Program. The Reauthorization Act required SBA to issue amendments to the STTR Policy Directive and publish the amendments in the
On August 6, 2012, SBA published a final STTR Policy Directive implementing the various provisions of the Reauthorization Act at 77 FR 46855. The directive made several key changes to the STTR Program relating to eligibility, the award process, program administration, and fraud, waste and abuse. Although the STTR Policy Directive is intended for use by the STTR participating agencies, SBA believed that public input on the directive from all parties involved in the program would be invaluable. Therefore, SBA sought public comments on the final directive, and stated that it may amend the directive in response to these comments at a later time.
In response to this request, SBA received comments on various parts of the directive. If SBA received comments on a section of the SBIR Policy Directive that also appears in the STTR Policy Directive, SBA clarified the relevant sections in both the SBIR and STTR Policy Directives, when appropriate, in order to maintain concordance between the programs. Several comments recommended that SBA strengthen and clarify the Policy Directive language with regard to SBIR/STTR data rights and the obligation of federal agencies to give a preference in contracting to SBIR/STTR awardees for follow-on Phase III work. SBA agrees that these areas of SBIR/STTR policy are vital to the programs and require clarification and improvement. The SBA continues to evaluate these issues and will address them in a subsequent Policy Directive revision.
Section 4(a)(3) “Agency benchmarks for progress towards commercialization” sets forth the program policy regarding an eligibility requirement for Phase I awards. SBA received comments requesting clarification of the time periods used to calculate the transition rate and commercialization rate benchmark requirements. Commenters also requested clarification about how agencies determine which firms must comply with the transition rate and commercialization rate benchmarks. In response to these comments, SBA revised and reorganized section 4(a)(3) to clarify several procedural elements about the benchmark determinations and enhance its readability.
Section 4(a)(3) clarifies the time periods used to calculate awardee rates of transition from Phase I to Phase II and provides two examples of the calculation. While the rate is calculated using Phase I awards received in the most recent 5, 10, or 15-year period (agencies choose which period they use), excluding the most recently completed fiscal year; the period used when counting the Phase II awards is lagged one year. That is, when calculating the number of Phase I awards received over a particular time period, the time period evaluated does not include the most recently completed fiscal year; however, when calculating the number of Phase II awards received, the time period evaluated does include the most recently completed fiscal year but does not include the first year of the period evaluated for Phase I awards
Based on additional input from the agencies participating in the SBIR and STTR programs, SBA also revised several procedural elements of the Phase II transition benchmark requirement in section 4(a)(3) to simplify the process for small businesses and reduce the administrative burden on the agencies. Specifically, in section 4(a)(3)(iii), SBA changed the start date for the one-year ineligibility period for firms that do not meet the benchmarks. The date was changed from the date of application submission to June 1st of each year. SBA made this change for several reasons: (1) It is a clearly defined period for affected small businesses; (2) to provide sufficient time for agencies to enter fully verified award data from the prior fiscal year into the TechNet database; and (3) to eliminate the need for agencies to track multiple periods of ineligibility. SBA will use its TechNet Data system to generate the list of companies that do not meet agency Phase II transition benchmarks and provide this list to the agencies each year on June 1. Finally, SBA also added a procedure to notify awardee firms if they are on the ineligible list and to enable firms to provide feedback directly to SBA if they believe their rate was calculated using incomplete award information.
Some respondents asked if the provision in section 4(b)(5) allowing one Sequential Phase II award included supplementary awards such as Phase 2.5 or Phase IIb awards in the definition of a Phase II award. SBA relocated the language at section 4(b)(6) to new section 4(b)(8) and added new section 4(b)(6) to clarify SBA's policy on supplemental phase II awards. Section 4(b)(6) now clarifies how Phase II award amounts are calculated when supplemental awards are issued. Furthermore, section 4(b)(6) specifies that all supplementary awards, such as a Phase IIb, must be linked to either an initial Phase II or a sequential Phase II award and is added to the amount of that award for the purpose of determining the size of the Phase II award. This means that all supplementary Phase II awards including options, enhancements, administrative supplements, and Phase IIb-type programs are considered as part of the initial Phase II or sequential Phase II from which they derive and are therefore subject to the Phase II per-award guideline amount of $1 million and limit of $1.5 million.
SBA repeated the language in section 9(d)(2) in new section 4(b)(7), which explains how a Phase I awardee may receive an award from one agency and also may receive a subsequent Phase II award from another agency. SBA also clarified in section 4(b)(7) that the same process applies to a second, sequential Phase II award that follows an initial Phase II award from a different agency. This policy is relevant to interagency actions, which are found at section 9 of the Policy Directive, and also to Phase II awards, which is found at section 4 of the Policy Directive.
The reauthorization legislation included a provision giving SBIR agencies the option to use a portion of their program funds to make awards to small businesses that are majority owned by multiple venture capital operating companies, hedge funds or private equity firms. SBA applied this option to the STTR program in section 6(a)(2) of the Policy Directive. SBA received comments that the option should not apply to the STTR program because the reauthorization legislation did not extend the participation of these firms to the STTR program. SBA agrees with commenter. When SBA issued the final regulations amending Title 13, Part 121, Small Business Size Regulations, Small Business Innovation Research (SBIR) Program and Small Business Technology Transfer (STTR) Program, on December 27, 2012 (77 FR 76215), it reviewed this issue and concluded that such firms may not participate in the STTR program. SBA has removed paragraph (a)(2) from section 6 and all other sections of the directive where this provision was applied, including section 6(b)(1)(i) and the related certification in Appendix I, Instructions for Preparation of STTR Program Solicitation, section 2(b)(i).
SBA received comments concerning section 9 of the Policy Directives that addressed measures to prevent fraud, waste and abuse in the program. The respondents commented that the administrative requirements contained in section 9 may be too stringent and may discourage small businesses from applying. SBA notes that it developed these requirements, including the procedures and requirements for certification, in consultation with the Council of Inspectors General on Integrity and Efficiency. SBA believes that these provisions can help reduce fraud, waste and abuse in the program and does not think these provisions should be changed at this time.
SBA received comments on the Department of Defense's (DoD's) Commercialization Readiness Program, outlined in section 12(b) of the STTR Policy Directive. In response to comments that agency efforts to increase transitions to Phase III could reduce the innovative nature of SBIR awards, SBA has added that when DoD reports on its Phase II insertion incentives, it should note efforts that the agency has made to ensure that such incentives do not act to shift the focus of SBIR and STTR Phase II awards away from relatively high-risk innovation projects. SBA also amended the provisions relating to the use of SBIR funds for the DoD Commercialization Readiness Program, which is funded from SBIR funds, but may benefit both the SBIR and STTR programs. According to section 1615 of the National Defense Authorization Act for Fiscal Year 2013 (NDAA), Public Law 112–239, 126 Stat. 1632, DoD has the authority to use 1% of its SBIR funding for purposes of administering the Commercialization Readiness Program.
A number of comments asked us to change features that, because they are required by statute, we were not able to modify.
The inadvertent omission of the term “extramural” before “R/R&D budgets” was corrected in section 2(b), which identifies the source of funds for the program.
Section 3 contains definitions of terms that appear throughout the Policy Directive. SBA made an editorial revision to the definition of “Awardee” in section 3(e). SBA revised the word “receiving” to “that receives.”
Section 4(b)(1), which identifies the objective and nature of a Phase II award, includes a statement regarding the eligibility of successor in interest firms for STTR awards. Because this statement pertains more generally to eligibility for all STTR awards, it was removed from section 4(b)(1) and added to section 6(a) which addresses program eligibility requirements.
Section 6(a) addresses general program eligibility. SBA added the language previously found at section 4(b)(1) regarding successor in interest firms to new section 6(a)(5). Sections 6(a)(3) and (4), renumbered as sections 6(a)(2) and (3), state program requirements regarding the percentage of work performed by the SBC and the
Section 7 addresses issues related to program funding processes. SBA revised the language in paragraph 7(d) to clarify that while duplicate or similar proposals may be submitted in response to apparently similar solicitation topics, essentially equivalent work may not be funded. In addition, SBA revised paragraph (i)(1), which says that funding agreement modifications should be kept to a minimum, to address only modifications that increase the dollar amount of awards. Paragraph (i)(1) also referred to modifications of periods of performance and scope of work. SBA clarified section 7(i)(1) to specify that the concern regarding the number of modifications made to an award pertains only to changes that increase the dollar amount of awards.
Section 8 of the Directive addresses the terms of agreement under STTR awards. SBA clarified section 8(a) by removing language stating that agencies should discourage SBCs from submitting proprietary information and revised section 8(e) to clarify that the continued use of agency-owned property applies to property acquired by the awardee under the contract.
In response to concerns regarding the cost and accountability of the continuing study by the National Academy of Sciences, SBA modified section 9(h) to clarify that the agreement required between the agencies and the National Academy of Sciences must be made in consultation with the SBA and must comprehensively address the scope and content of the work to be performed.
Section 10(h) explains the process for agencies to submit their STTR program annual reports to SBA. Paragraph (h)(4) contains a list of information that must be included in each agency's annual report. SBA clarified section 10(h)(4)(xi) to note that agencies must report all instances in which an agency pursued R/R&D, services, production, or any combination thereof of a technology developed under an STTR award with an entity other than that STTR awardee. SBA removed the unnecessary language, “and determined that it was not practicable to enter into a follow-on funding agreement with non-STTR funds with that concern,” because it unintentionally created an additional condition for this reporting requirement.
Section 10(j) contains information on the other reporting requirements for STTR participating agencies. Section 10(j)(2) discusses a system that will list any individual or small business concern that received an STTR award and that has been convicted of a fraud-related crime involving STTR funds or found civilly liable for a fraud-related violation involving STTR funds. SBA clarified this section to note that SBA will list those individuals and small business concerns of which SBA has been made aware.
Section 12(b) addresses the Commercialization Readiness Program at the Department of Defense (DoD). SBA clarified the source of funding for this program by removing the sentence in paragraph (b)(4)(ii) stating that funds for the program would come from the 3% administrative set-aside, and by clarifying that the funds shall not be subject to the limitations on the use of funds in section 9(e)(3). In addition, in section 12(b)(6)(iii)(C), SBA clarified that the DoD must include, along with its description of the incentives used for this program, information on measures taken to ensure that such incentives do not shift the focus of the STTR Phase II awards away from the relatively high-risk innovation projects they are intended to promote.
Section 12(b)(5) addresses DoD's Commercialization Readiness Program. The Policy Directive states that DoD may establish transition goals and reporting requirements for awards less than $1,000,000,000. The amount listed in section 12(b)(5) contained a typographical error, which was corrected to $100,000,000.
Appendix I provides instructions for the preparation of program solicitations. In Appendix I, SBA revised the certification check box regarding notification if work is subsequently funded by another Federal agency to clarify that it pertains to work funded and completed under the award rather than to the work proposed for the award.
The updated STTR Policy Directive, incorporating all changes noted here, will be posted on
To: The Small Business Technology Transfer Program Managers
Subject: Amendments to STTR Policy Directive Published on August 6, 2012 at 77 FR 46855.
1.
2.
3.
4.
5.
6.
SBA amends the STTR Policy Directive as follows:
1. Amend section 2(b) by adding the term “extramural” before “R/R&D budgets” each place it appears.
2. Revise section 3(e) to read as follows:
(e)
3. Revise section 4(a)(3) to read as follows:
(3)
(i) Agencies must apply two benchmark rates addressing an applicant's progress towards commercialization—the Phase II Transition Rate Benchmark and the Commercialization Rate Benchmark.
(A) The Phase II Transition Rate Benchmark sets the minimum required number of Phase II awards the applicant must have received for a given number of Phase I awards received during the specified period. This Transition Rate Benchmark applies only to Phase I applicants that have received more than 20 Phase I awards over the time period used by the agency for the benchmark determination.
(B) The agency Commercialization Rate Benchmark sets the minimum Phase III commercialization results that a Phase I applicant must have realized from its prior Phase II awards in order to be eligible to receive a new Phase I award from that agency. This benchmark requirement applies only to Phase I applicants that have received more than 15 Phase II awards over the time period used by the agency for the benchmark determination.
(ii)
(iii)
(iv)
(A) The agency Phase II Transition Rate Benchmark establishes the number of Phase II awards a small business concern must have received for a given number of Phase I awards received over the past 5, 10 or 15 fiscal years, excluding the most recently completed fiscal year. Each agency selects both the rate to be applied and the length of time that the agency will use to evaluate whether a small business concern has met the Transition Rate Benchmark. The time period over which Phase I awards are counted excludes the most recently completed fiscal year. The time period over which Phase II awards are counted includes the most recently completed fiscal year and excludes the first year of the time period evaluated for Phase I awards.
On August 1, 2014, an SBC submits a Phase I application to an agency using a Transition Rate Benchmark of 0.25 and a 5-year time period. The June 1, 2014 TechNet Company Registry tabulation shows that the SBC received 24 Phase I awards during FY08–FY12. Since this SBC has received 20 or more Phase I awards during the 5-year period, the SBC is required to meet the Transition Rate Benchmark. The SBC received 8 Phase II awards in FY09–FY13 and therefore has a 5-year Phase II transition rate of 8/24 or 0.33 (# of Phase II awards in FY09–FY13/# of Phase I awards in FY08–FY12). Because the SBC meets or exceeds the agency Transition Rate Benchmark, it is considered for award through the usual proposal evaluation process.
On September 1, 2014, an SBC is interested in applying for a Phase I award, knows it has received a number of Phase I awards in recent years, but is unsure if it is meeting the required Phase II transition rate. The company official logs onto the Company Registry at SBIR.gov to check its status and sees a flag saying it did not meet the required benchmark transition rate of 0.25 on June 1, 2014 and is therefore ineligible for a Phase I award through May 31, 2015. The company checks its records and sees that it received 30 Phase I awards during FY08–FY12 and 6 Phase II awards during FY09–FY13. Its transition rate is therefore 6/30 or 0.20 which is under the required rate of 0.25. The SBC does not apply for a new Phase I award through May 31, 2015 because it knows its application would be rejected.
On September 1, 2014, an SBC official interested in applying for a Phase I award logs onto the Company Registry at SBIR.gov and sees the flag saying it did not meet the required benchmark transition rate of 0.25 on June 1, 2014 and is not eligible for a Phase I award through May 31, 2015. However, when the company checks its own records, it sees that it received 8 Phase II awards during FY09–FY13, not the 6 awards showing on the Web site. Its transition rate is therefore 8/30 or 0.26 which is above the required rate of 0.25. The company official therefore goes to SBIR.gov, clicks on the “Dispute Transition Rate” button, and enters the information about the discrepancy. SBA uses the information provided by the company and, working with the relevant agencies, identifies that two Phase II awards from FY09 had been inadvertently omitted. SBA updates and corrects the database and informs the firm that it is indeed eligible to receive Phase I awards.
(B) An SBC that has received more than 20 phase I awards in the relevant time period can view its Phase II transition rate on the Company Registry page at SBIR.gov. Generally, the the award data used to calculate an SBC's transition rate will be complete by the end of March each year. An SBC may view its SBIR/STTR award information on the Company Registry at any time. If an awardee believes its Phase II transition rate is calculated using incomplete award information, the awardee may dispute the rate using the link provided on the Company Registry, provide the additional award information, and request a reconsideration of its transition rate. Requests for reconsideration of a firm's transition rate received by SBA from April 1st through April 30th of each year will be considered for the June 1st transition rate assessment.
(C) Agencies must set the Phase II Transition Rate Benchmark as appropriate for their programs and industry sectors. When setting the Transition Rate Benchmark, agencies should consider that Phase I is designed and intended to explore high-risk, early-stage research ideas and, as a result, not all Phase I awards are expected to result in a Phase II award.
(v)
(A) in financial terms, such as by using the ratio of the dollar value of revenues and additional investment resulting from prior Phase II awards relative to the dollar value of the Phase II awards received over the time period;
(B) in terms of the share of Phase II awards received over the time period that have resulted in the introduction of a product to market; or
(C) by other means such as using a commercialization scoring system that rates awardees on their past commercialization success.
(vi) Agencies must submit their Transition Rate Benchmark, Commercialization Rate Benchmark, and time periods to SBA for approval.
(vii) SBA maintains a system that records all Phase I, Phase II and Government Phase III awards, and other commercialization information; and calculates the Phase II transition rates for all Phase I awardees and the commercialization rates for all Phase II awardees.
(viii) If an applicant fails to meet an agency's benchmark, its name will appear on the list of companies made available to the agencies on June 1 of each year. An agency may not make a Phase I award to an applicant that does not meet the agency's benchmark.
(ix) If an awardee believes its determination was made in error, it may provide SBA with the pertinent award information and request a re-assessment. To do so, awardees may use the link on the Company Registry at
4. Amend section 4(b) by revising paragraph (b)(1), renumbering paragraph (b)(6) as (b)(8), and inserting paragraphs (b)(6) and (b)(7) to read as follows:
(b)
(1) The object of Phase II is to continue the R/R&D effort from the completed Phase I. Unless the exception set forth in paragraph (i) below applies, only STTR Phase I awardees are eligible to participate in Phase II.
(i) A Federal agency may issue an STTR Phase II award to an SBIR Phase I awardee to further develop the work performed under the SBIR Phase I award. The agency must base its decision upon the results of work performed under the Phase I award and the scientific and technical merit, and commercial potential of the Phase II proposal. The SBIR Phase I awardee must meet the eligibility and program requirements of the STTR Program in order to receive the STTR Phase II award.
. . . [paragraphs (2) through (4) are unchanged] . . .
(5) A Phase II awardee may receive one additional, sequential Phase II award to continue the work of an initial Phase II award. The additional, sequential Phase II award has the same guideline amounts and limits as an initial Phase II award.
(6) Agencies may offer special STTR awards, such as Phase IIB awards, that supplement or extend Phase II awards. For example, some agencies administer Phase IIB awards that differ from the base Phase II in that they require third party matching of the SBIR funds. Each such supplemental award must be linked to a base Phase II award (the initial Phase II or the second, sequential Phase II award). Any STTR funds used for such special or supplementary awards are aggregated with the amount of the base Phase II to determine the size of that Phase II award. Therefore, while there is no limit on the number of such special/supplementary awards, there is a limit on the total amount of STTR funds that can be administered through them—the amounts of these awards count towards the size of the initial Phase II or the sequential Phase II, each of which has a guideline amount of $1 million and a limit of $1.5 million. (Note that Phase IIB awards under the NIH STTR program are administered as second, sequential Phase II awards, not supplemental awards. As such, they are base Phase II awards and subject to the Phase II guideline amounts and limits of $1 million and $1.5 million).
(7) An STTR Phase II award may be issued by a Federal agency other than the one that made the Phase I award. Prior to award, the head of the Federal agency that awarded the Phase I and the head of the Federal Agency that plans to issue the Phase II award, or designee, must issue a written determination that the topics of the awards are the same. Both agencies must submit the report to the SBA. The same process applies to a second, subsequent Phase II award that follows an initial Phase II award from a different agency.
(8) Agencies may issue Phase II awards for testing and evaluation of products, services, or technologies for use in technical or weapons systems.
5. Remove section 6(a)(2).
6. Redesignate sections 6(a)(3) and (4) as sections 6(a)(2) and (3) and revise to read as follows:
(2) For both Phase I and Phase II, not less than 40 percent of the R/R&D work must be performed by the SBC, and not less than 30 percent of the R/R&D work must be performed by the single, partnering Research Institution. An agency can measure this research or analytical effort using the total contract dollars or labor hours, and must explain to the small business in the solicitation how it will be measured.
(3) For both Phase I and Phase II, the primary employment of the principal investigator must be with the SBC or the research institution at the time of award and during the conduct of the proposed project. Primary employment means that more than one-half of the principal investigator's time is spent in the employ of the SBC or the research institution. This precludes full-time employment with another organization aside from the SBC or the research institution. An SBC may replace the principal investigator on an STTR Phase I or Phase II award, subject to approval in writing by the funding agreement officer. For purposes of the STTR Program, personnel obtained through a Professional Employer Organization or other similar personnel leasing company may be considered employees of the awardee. This is consistent with SBA's size regulations, 13 CFR 121.106—Small Business Size Regulations.
7. Insert new section 6(a)(5) to read as follows:
(5) An STTR awardee may include, and STTR work may be performed by, those identified via a “novated” or “successor in interest” or similarly-revised funding agreement, or those that have reorganized with the same key staff, regardless of whether they have been assigned a different tax identification number. Agencies may require the original awardee to relinquish its rights and interests in an STTR project in favor of another applicant as a condition for that applicant's eligibility to participate in the STTR Program for that project.
8. Revise section 7(d) to read as follows:
(d)
9. Revise section 7(h)(1) to read as follows:
(h)
(1) In keeping with the legislative intent to make a large number of relatively small awards, modification of funding agreements to increase the dollar amount should be kept to a minimum, except for options in original Phase I or II awards.
10. Revise section 8(a) to read as follows:
(a)
11. Revise section 8(e) to read as follows:
(e)
12. Revise section 9(h) to read as follows:
(h)
(1) Prior to and during the period of study, and to ensure that the concerns of small business are appropriately considered, NAS shall consult with and consider the views of SBA's Office of Investment and Innovation and the Office of Advocacy and other interested parties, including entities, organizations, and individuals actively engaged in enhancing or developing the technological capabilities of small business concerns.
(2) The head of each agency with a budget of more than $50,000,000 for its SBIR Program for fiscal year 1999 shall, in consultation with SBA, and not later than 6 months after December 31, 2011, cooperatively enter into an agreement with NAS regarding the content and performance of the study. SBA and the agencies will work with the Interagency Policy Committee in determining the parameters of the study, including the specific areas of focus and priorities for the broad topics required by statute. The agreement with NAS must set forth these parameters, specific areas of focus and priorities, and comprehensively address the scope and content of the work to be performed. This agreement must also require the NAS to ensure there is participation by and consultation with, the small business community, the SBA, and other interested parties as described in paragraph (1).
(3) NAS shall transmit to SBA, heads of agencies entering into an agreement under this section, the Committee on Science, Space and Technology, the Committee on Small Business of the House of Representatives, and to the Committee on Small Business of the Senate a copy of the report, which includes the results and recommendations, not later than 4 years after December 31, 2011, and every subsequent four years.
13. Revise section 10(h)(4)(xi) to read as follows:
(xi) All instances in which an agency pursued R/R&D, services, production, or any combination thereof of a technology developed under an STTR award with an entity other than that STTR awardee. See section 9(a)(12) for minimum reporting requirements.
14. Revise section 10(j)(2) to read as follows:
(2) The system will include a list of any individual or small business concern that has received an STTR award and that has been convicted of a fraud-related crime involving STTR funds or found civilly liable for a fraud-related violation involving STTR funds, of which SBA has been made aware.
15. Revise section 12(b)(4) to read as follows:
(4)
(i) Beginning with FY 2013 and ending in FY 2015, the Secretary of Defense and each Secretary of a military department is authorized to use its SBIR funds for administration of this program in accordance with the procedures and policies set forth in section 9(e)(3) of this directive.
(ii) In addition, the Secretary of Defense and Secretary of each military department is authorized to use not more than an amount equal to 1% of its SBIR funds available to DoD or the military departments for payment of expenses incurred to administer the Commercialization Readiness Program. Such funds—
(A) shall not be subject to the limitations on the use of funds in 9(e)(2) or 9(e)(3) of this directive; and
(B) shall not be used to make Phase III awards.
16. Revise section 12(b)(5) to read as follows:
(5)
(i) establish goals for the transition of Phase III technologies in subcontracting plans; and
(ii) require a prime contractor on such a contract to report the number and dollar amount of the contracts entered into by the prime contractor for Phase III STTR projects.
17. Revise section 12(b)(6) to read as follows:
(6) The Secretary of Defense shall:
(i) set a goal to increase the number of STTR Phase II contracts that lead to technology transition into programs of record of fielded systems;
(ii) use incentives in effect as of December 31, 2011 or create new incentives to encourage agency program managers and prime contractors to meet the goal set forth in paragraph (6)(i) above; and
(iii) submit the following to SBA, as part of the annual report:
(A) the number and percentage of Phase II STTR contracts awarded by DoD that led to technology transition into programs of record or fielded systems;
(B) information on the status of each project that received funding through the Commercialization Program and the efforts to transition these projects into programs of record or fielded systems; and
(C) a description of each incentive that has been used by DoD, the effectiveness of the incentive with respect to meeting DoD's goal to increase the number of STTR Phase II contracts that lead to technology transition into programs of record of fielded systems, and measures taken to ensure that such incentives do not act to shift the focus of STTR Phase II awards away from relatively high-risk innovation projects.
18. Revise paragraph 1(a) of the Appendix I: Instructions for Preparation of STTR Program Solicitation to read as follows:
(a) Summarize in narrative form the request for proposals and the objectives of the STTR Program.
19. In Appendix I, in the STTR Funding Agreement Certification and the STTR Funding Agreement Certification—Life Cycle Certification, revise the checkbox addressing potential duplicative funding to read as follows:
Federal Aviation Administration (FAA), DOT.
Final rule; request for comments.
We are adopting a new airworthiness directive (AD) for all Rolls-Royce plc (RR) RB211–524G2–19, RB211–524G3–19, RB211–524H–36, and RB211–524H2–19 turbofan engines. This AD requires a one-time reduction in the cyclic life of certain high-pressure (HP) compressor rotor stage 1 and stage 2 discs, and removal of discs that exceed the reduced cycle life. This AD was prompted by a review by RR of the cyclic life of life-limited parts (LLPs) for RB211–524 series engines. We are issuing this AD to prevent the failure of certain LLPs, which could result in uncontained engine damage and damage to the airplane.
This AD becomes effective January 23, 2014.
We must receive comments on this AD by February 24, 2014.
You may send comments by any of the following methods:
•
•
•
•
You may examine the AD docket on the Internet at
Robert Green, Aerospace Engineer, Engine Certification Office, FAA, Engine & Propeller Directorate, 12 New England Executive Park, Burlington, MA 01803; phone: 781–238–7754; fax: 781–238–7199; email:
The European Aviation Safety Agency (EASA), which is the Technical Agent for the Member States of the European Community, has issued EASA Airworthiness Directive 2013–0246, dated October 10, 2013 (referred to herein after as “the MCAI”), to correct an unsafe condition for the specified products. The MCAI states:
Operation of critical parts beyond these reduced cyclic life limits could lead to part failure and consequent release of high-energy debris, possibly resulting in damage to the aeroplane and/or injury to the occupants.
This product has been approved by the aviation authority of the United Kingdom, and is approved for operation in the United States. Pursuant to our bilateral agreement with the European Community, EASA has notified us of the unsafe condition described in the MCAI and service information referenced above. We are issuing this AD because we evaluated all information provided by EASA and determined the unsafe condition exists and is likely to exist or develop on other products of the same type design. This AD requires a one-time reduction in the cyclic life of certain HP compressor stage 1 and stage 2 discs, and removal of discs that exceed the reduced cycle life.
No domestic operators use this product. Therefore, we find that notice and opportunity for prior public comment are unnecessary and that good cause exists for making this amendment effective in less than 30 days.
This AD is a final rule that involves requirements affecting flight safety, and we did not precede it by notice and opportunity for public comment. We invite you to send any written relevant data, views, or arguments about this AD. Send your comments to an address listed under the
We will post all comments we receive, without change, to
We estimate that this AD will affect 0 engines installed on airplanes of U.S. registry. We also estimate that it will take about 0 hours per engine to comply with this AD. The average labor rate is $85 per hour. The prorated cost of the parts, adjusted for lost life, is about $15,940 per engine. Based on these figures, we estimate the total cost of this AD to U.S. operators is $0.
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,
We determined that this AD will not have federalism implications under Executive Order 13132. This AD will not have a substantial direct effect on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government.
For the reasons discussed above, I certify this AD:
(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.
We prepared a regulatory evaluation of the estimated costs to comply with this AD and placed it in the AD docket.
Air transportation, Aircraft, Aviation safety, Incorporation by reference, Safety.
Accordingly, under the authority delegated to me by the Administrator, the FAA amends 14 CFR part 39 as follows:
49 U.S.C. 106(g), 40113, 44701.
This AD is effective January 23, 2014.
None.
This AD applies to all Rolls-Royce plc (RR) RB211–524G2–19, RB211–524G3–19, RB211–524H–36, and RB211–524H2–19 turbofan engines with high-pressure (HP) compressor rotor stage 1 and stage 2 discs, part number LK70608, LK76030, LK86621, UL19877, UL19878, UL19879, or UL24023, installed.
This AD was prompted by a review by RR of the cyclic life of critical-life-limited parts (LLPs) for RB211–524 series engines. We are issuing this AD to prevent the failure of certain LLPs, which could result in uncontained engine damage and damage to the airplane.
Comply with this AD within the compliance times specified, unless already done.
(1) Within 30 days after the effective date of this AD, reduce the cyclic life limit for the affected HP compressor rotor stage 1 and stage 2 discs to 7,390 flight cycles (FC).
(2) After the effective date of this AD, remove each affected HP compressor rotor stage 1 and stage 2 disc from service before the part exceeds 7,390 FC.
(3) After the effective date of this AD, do not return to service any engine that has an HP compressor rotor stage 1 and stage 2 disc installed, if the disc has more than 7,390 FC.
The Manager, Engine Certification Office, FAA, may approve AMOCs to this AD. Use the procedures found in 14 CFR 39.19 to make your request.
(1) For more information about this AD, contact Robert Green, Aerospace Engineer, Engine Certification Office, FAA, Engine & Propeller Directorate, 12 New England Executive Park, Burlington, MA 01803; phone: 781–238–7754; fax: 781–238–7199; email:
(2) Refer to MCAI European Aviation Safety Agency AD 2013–0246, dated October 10, 2013, for more information. You may examine the MCAI in the AD docket on the Internet at
None.
Securities and Exchange Commission.
Final rule.
The Securities and Exchange Commission (“Commission”) is adopting amendments to a rule and three forms under the Investment Company Act of 1940 (“Investment Company Act”) and the Securities Act of 1933 (“Securities Act”) in order to implement a provision of the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”). Specifically, rule 5b–3 under the Investment Company Act contains a reference to credit ratings in determining when an investment company (“fund”) may treat a repurchase agreement as an acquisition of securities collateralizing the repurchase agreement for certain purposes under the Investment Company Act. The amendments we are adopting today replace this reference to credit ratings with an alternative standard designed to retain a similar degree of credit quality to that in current rule 5b–3. The Commission is also adopting amendments to Forms N–1A, N–2, and N–3 under the Investment Company Act and Securities Act to eliminate the required use of NRSRO credit ratings when a fund chooses to depict its portfolio holdings by credit quality.
Adam Bolter, Senior Counsel, Thoreau Bartmann, Branch Chief, or C. Hunter Jones, Assistant Director (202) 551–6792, Office of Investment Company Rulemaking, Division of Investment Management, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549–8549.
The Commission is adopting amendments to rule 5b–3 [17 CFR 270.5b–3] under the Investment Company Act.
The first use of a reference to ratings or rating agencies in Commission rules was in 1975, when the Commission adopted the term “nationally recognized statistical rating organization” (“NRSRO”) as part of amendments to the net capital rule for broker-dealers, rule 15c3–1 under the Securities Exchange Act of 1934 (“Exchange Act”) (the “Net Capital Rule”).
Section 939A of the Dodd-Frank Act requires each Federal agency, including the Commission, to “review any regulation issued by such agency that requires the use of an assessment of the credit-worthiness of a security or money market instrument and any references to or requirements in such regulations regarding credit ratings.”
As a step toward implementing these mandates, in March 2011 the Commission proposed to replace references to ratings issued by NRSROs in two Commission rules and four Commission forms under the Investment Company Act, including rule 5b–3 and Forms N–1A, N–2, and N–3.
We are adopting, largely as proposed, amendments to rule 5b–3 and Forms N–1A, N–2, and N–3 to implement section 939A of the Dodd-Frank Act and effectuate Congressional intent to reduce reliance on NRSRO credit ratings.
In a separate release, the Commission is adopting final amendments to remove references to credit ratings from rules on broker-dealer financial responsibility and confirmations of transactions. These amendments follow the Commission's April 2011 proposed rules in which we proposed to amend rules and one form under the Exchange Act applicable to broker-dealer financial responsibility, distributions of securities, and confirmations of transactions in order to remove references to credit ratings pursuant to section 939A of the Dodd-Frank Act.
As part of our implementation of section 939A, we have reviewed our prior actions and those of other regulators. As discussed below, both the Commission and other regulators have proposed and issued several final rules towards implementation of the mandate under section 939A of the Dodd-Frank Act. In some cases, the references to credit ratings were replaced with an alternative standard of credit quality designed to retain the same degree of credit quality and liquidity as reflected by the use of credit ratings.
The Commission has long been concerned with the use of credit ratings and has taken a variety of actions even before the enactment of the Dodd-Frank Act regarding the use of NRSRO credit ratings in its rules. For example, in 1994, the Commission published a concept release soliciting comment on, among other things, whether the Commission should eliminate references to NRSRO credit ratings from certain rules.
A number of other federal agencies have also taken action to implement section 939A of the Dodd-Frank Act, including regulations proposed or adopted by the Commodity Futures Trading Commission (“CFTC”),
Rule 5b–3 allows funds to treat the acquisition of a repurchase agreement as an acquisition of securities collateralizing the repurchase agreement for certain diversification and broker-dealer counterparty limit purposes under the Investment Company Act
Under current requirements, a repurchase agreement is collateralized fully if, among other things, the collateral for the repurchase agreement consists entirely of (i) cash items, (ii) government securities,
Today we are amending rule 5b–3 to eliminate the requirement that collateral other than cash or government securities be rated in the highest category by the requisite NRSROs or be of comparable quality. In place of this requirement, the amended rule requires that collateral other than cash or government securities consist of securities that the fund's board of directors (or its delegate) determines at the time the repurchase agreement is entered into are: (i) Issued by an issuer that has an exceptionally strong capacity to meet its financial obligations on the securities collateralizing the repurchase agreement; and (ii) sufficiently liquid that they can be sold at approximately their carrying value in the ordinary course of business within seven calendar days.
The new credit quality standard we are adopting is designed to retain a degree of credit quality that is similar to the existing standard under rule 5b–3 and consistent with the two-part approach we have taken in establishing credit quality standards to replace credit rating references in other rules under the federal securities laws.
We proposed that collateral issuers be required to have the “highest capacity” to meet their financial obligations on the collateral securities.
As discussed above, we are adopting the liquidity component of the new standard as proposed. The liquidity standard in the amended rule is similar to the standard used in rule 2a–7 governing money market funds, and is also used in other rules under the Investment Company Act.
We expect that securities that actively trade in a secondary market at the time of the acquisition of the repurchase agreement will satisfy the liquidity component of the standard. We also understand that most securities used to collateralize repurchase agreements generally actively trade in a secondary market.
The final amendments do not, as one commenter suggested, include specific factors or tests that the board or its delegate must apply in performing its credit analysis.
The new credit quality standard is intended to achieve the same objectives that the credit rating requirement was designed to achieve,
Under the final rule, as was proposed, the fund's board will be required to make credit quality determinations for all collateral securities that are not cash items or government securities, rather than just for unrated securities. In addition, as in the current rule, the amended rule continues to permit the board to delegate these credit quality and liquidity determinations.
Under the amended rule, when determining credit quality and liquidity, the board (or its delegate) may incorporate into its analysis ratings, reports, opinions and other assessments issued by third parties, including NRSROs. A board should evaluate the basis for using any third-party assessment, including an NRSRO rating, in determining whether collateral meets the new standard and would not rely on the use of an NRSRO rating as a standard by itself without evaluating the quality of each NRSRO's assessment. In this way, the board could determine which third-party providers are credible and reliable and provide assessments that would be most appropriate to incorporate in making determinations under the amended rule. Delegation of these functions, as well as the use of third-party providers, may help to limit the potential increase in burdens on the board. One commenter suggested that we not allow a fund board to consider credit ratings in determining if a repurchase agreement is fully collateralized, stating that this would conflict with section 939A of the Dodd-Frank Act.
A fund that enters into repurchase agreements and relies on rule 5b–3 must maintain written policies and procedures that are reasonably designed to comply with the conditions of the rule, including the credit quality and liquidity requirements we are adopting today, and funds may therefore have to amend their policies and procedures.
As discussed above, amended rule 5b–3 replaces the requirement that collateral for repurchase agreements consist of securities rated in the highest category by the requisite NRSROs (other than cash and government securities) with a requirement that the collateral other than cash and government securities consist of securities issued by an issuer that has an exceptionally strong capacity to meet its financial obligations and that are sufficiently liquid. Consistent with the protection of investors and as necessary and appropriate in the public interest, we are also amending rule 5b–3 to define an issuer to include an issuer of an unconditional guarantee of the security.
We are also adopting amendments to Forms N–1A, N–2, and N–3 to remove the required use of credit ratings assigned by an NRSRO. Forms N–1A, N–2, and N–3, among other things, contain the requirements for shareholder reports of mutual funds, closed-end funds, and certain insurance company separate accounts that offer variable annuities.
Currently, Forms N–1A, N–2, and N–3 require shareholder reports to include a table, chart, or graph depicting portfolio holdings by reasonably identifiable categories (
In a change from the 2011 Proposing Release, however, under the amended forms, funds that choose to continue to
Four of the five substantive comments we received on the proposed amendments to Forms N–1A, N–2, and N–3, supported eliminating the required use of NRSRO credit ratings to depict credit quality.
Although most commenters supported eliminating the required use of credit ratings to depict credit quality, four commenters opposed the proposed requirement that a fund that chooses to use NRSRO credit ratings must use the credit ratings of a single NRSRO. Instead, these commenters recommended that when a security is split-rated, the fund be permitted to choose which NRSRO rating to use, provided the choice is made consistently pursuant to a disclosed policy.
We agree with commenters and have revised the final form amendments to provide this additional degree of flexibility. Accordingly, the amended forms permit funds to consider alternative approaches to presenting credit quality that accurately and effectively describe the credit quality of the fund's portfolio. For example, under the amended forms, a fund could have a policy of disclosing the median credit quality rating for split-rated securities instead of only using the ratings of a single credit rating agency (when more than two rating agencies rate the security).
Under the amended forms, funds that choose to depict portfolio holdings according to credit quality must include a description of how the credit quality of the holdings was determined.
We recognize that under the final form amendments, a fund has a variety of options when depicting its portfolio holdings using credit quality. For example, a fund might choose not to use credit ratings and could rely instead on internal credit assessments. If a fund does not use credit ratings, we note that it might be misleading for a fund to describe its portfolio holdings quality with similar descriptions as the ratings nomenclature used by rating agencies (
The amended forms are intended to provide funds with the flexibility to present credit ratings in a manner that more clearly explains the credit quality of the fund's portfolio and the method by which the fund determined that quality.
Certain provisions of the amendments we are adopting contain “collections of information” within the meaning of the Paperwork Reduction Act of 1995 (“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. We published notice soliciting comments on the collection of information requirements in the 2011 Proposing Release and submitted the proposed collections of information to the Office of Management and Budget (“OMB”) for review in accordance with 44 U.S.C. 3507(d) and 5 CFR 1320.11 under the control numbers 3235–0025 (rule 30e–1) and 3235–0586 (rule 38a–1). We received no comments on the PRA estimates contained in the 2011 Proposing Release.
Rule 5b–3 under the Investment Company Act allows funds to treat the acquisition of a repurchase agreement as an acquisition of securities collateralizing the repurchase agreement for purposes of sections 5(b)(1) and 12(d)(3) of the Investment Company Act under certain conditions. Rule 5b–3, as amended, requires that the securities collateralizing a repurchase agreement consist of securities that the fund's board of directors, or its delegate, determines are issued (or have unconditional guarantees that are issued) by an issuer that has an exceptionally strong capacity to meet its financial obligations and are highly liquid.
We do not anticipate that the amendments to rule 5b–3 will significantly change collection of information burdens under rule 38a–1 because we believe funds would likely rely significantly on their current policies and procedures to determine the credit quality of collateral securities and comply with amended rule 5b–3. As we indicated above, we understand that credit quality standards for securities collateralizing repurchase agreements typically are contained in the repurchase agreements between funds and counterparties.
The monetized burden hours are calculated as follows: 15,176 hours × $245 per hour = $3,718,120 one-time additional costs. The staff estimates that the internal cost for time spent by a senior business analyst is $245 per hour. This estimate, as well as other internal time cost estimates made in this analysis, is derived from SIFMA's Management and Professional Earnings in the Securities Industry 2012, modified by Commission staff to account for an 1800-hour work week and multiplied by 5.35 to account for bonuses, firm size, employee benefits and overhead.
We anticipate that the fund's board will review the fund manager's recommendation, but that the cost of this review will be incorporated in the fund's overall annual board costs and would not result in any particular additional cost. We received no comments on these estimates and therefore have not modified them.
The amendments to Forms N–1A, N–2, and N–3 eliminate the required use of NRSRO credit ratings by funds that choose to use credit quality categorizations in the table, chart, or graph of portfolio holdings provided in shareholder reports. The collection of information is mandatory for those funds that choose to use credit quality categorizations in these forms. If a fund chooses to depict portfolio holdings according to credit quality, the fund must include a description of how the credit quality of the holdings was determined. If credit ratings assigned by a credit rating agency are used, the fund must disclose how it identified and selected the credit ratings. Responses to the disclosure requirements will not be kept confidential.
Although funds would remain obligated to provide a table, chart, or graph of portfolio holdings by reasonably identifiable categories, the amendments require that certain funds must make new disclosures. Under our proposed amendment, we estimated that there would be no additional collection of information burden as a result of proposing to remove the required use of credit ratings from the forms.
Accordingly, based on staff experience, the staff estimates that it will take, on average, 3 hours of an attorney's time to perform this review and make any technical changes to an individual fund's disclosures, for an estimated burden of 32,049 hours for all funds.
The monetized burden hours are calculated as follows: 32,049 hours × $379 per hour = $12,146,571 one-time additional costs. The staff estimates that the internal cost for time spent by an in-house attorney is $379 per hour. This estimate, as well as other internal time cost estimates made in this analysis, is derived from SIFMA's Management and Professional Earnings in the Securities Industry 2012, modified by Commission staff to account for an 1800-hour work week and multiplied by 5.35 to account for bonuses, firm size, employee benefits and overhead.
As discussed above, we are adopting rule and form amendments to implement section 939A of the Dodd-Frank Act. The amendments to rule 5b–3 replace a NRSRO credit rating standard with alternative credit quality and liquidity criteria that are designed to achieve the same purposes as the NRSRO credit rating standard without imposing unnecessarily burdensome costs. The amendments to Forms N–1A, N–2, and N–3 remove the required use of credit ratings when portraying credit quality in shareholder reports, but require that those funds include a description of how the credit quality of the holdings were determined, and if credit ratings assigned by a credit rating agency are used, how the credit ratings were identified and selected. The regulatory changes adopted today will directly affect investment companies registered under the Investment Company Act and could affect the demand for rating agencies' services by eliminating the required use of NRSRO credit ratings in rule 5b–3 and Forms N–1A, N–2, and N–3. The amendments to
At the outset, the Commission notes that, where possible, we have attempted to quantify the costs and benefits expected to result from adopting the amendments to rule 5b–3 and Forms N–1A, N–2, and N–3. However, wherever the discussion of costs or benefits is not quantified in this section it is because the Commission is unable to quantify the economic effects because it lacks the information necessary to provide a reasonable estimate. For example, as discussed below, the Commission does not have available to it comprehensive information on the exposure of funds to different repurchase agreement market segments, the nature and type of collateral used in repurchase agreements, or the extent to which funds rely on rule 5b–3. Because of this lack of data, including the extent to which funds may rely on rule 5b–3, we are unable to quantify the costs to comply with the amended rule and note that the costs could vary from our estimates. We discuss below the economic baseline, costs and benefits of our final rule and form amendments, alternatives considered, as well as the impact on efficiency, competition, and capital formation.
Rule 5b–3, as amended, permits a fund to treat the acquisition of a repurchase agreement as an acquisition of securities collateralizing the repurchase agreement for purposes of sections 5(b)(1) and 12(d)(3) of the Investment Company Act if the collateral other than cash or government securities consists of securities that the fund's board of directors, or its delegate, determines at the time the repurchase agreement is entered into are: (i) Issued by an issuer that has an exceptionally strong capacity to meet its financial obligations; and (ii) sufficiently liquid that they can be sold at approximately their carrying value in the ordinary course of business within seven calendar days.
The economic baseline against which we measure the economic effects of these amendments is the regulatory framework as it exists immediately before the adoption of today's amendments. Currently, rule 5b–3 allows funds to treat the acquisition of a repurchase agreement as an acquisition of securities collateralizing the repurchase agreement for certain diversification and broker-dealer counterparty limit purposes under the Investment Company Act if the obligation of the seller to repurchase the securities from the fund is “collateralized fully.” In general, under rule 5b–3, a fund investing in a repurchase agreement looks to the value and liquidity of the securities collateralizing the repurchase agreement rather than the creditworthiness of the counterparty for satisfaction of the repurchase agreement. Under current requirements, a repurchase agreement is collateralized fully if, among other things, the collateral for the repurchase agreement consists entirely of (i) cash items, (ii) government securities, (iii) securities that at the time the repurchase agreement is entered into are rated in the highest rating category by the “Requisite NRSROs” or (iv) unrated securities that are of a comparable quality to securities that are rated in the highest rating category by the Requisite NRSROs, as determined by the fund's board of directors or its delegate.
As of the end of 2012, the total repurchase agreement market approximated $3 trillion.
While we believe that many funds invest in tri-party repurchase agreements, comprehensive information about the extent to which funds invest in these agreements is not available to us. Nor are we able to estimate how often funds rely on rule 5b–3 when entering into repurchase agreements, or the extent to which fund repurchase agreements are collateralized with securities other than cash or government securities. However, we are able to estimate the extent of money market fund participation in the tri-party repurchase market using Form N–MFP data, which shows that money market funds held approximately $591 billion in tri-party repurchase agreements as of the end of 2012. While we understand almost all funds rely on rule 5b–3 on occasion (for example when approaching diversification limits or avoiding restrictions on investments in certain entities), we do not have the information necessary to determine how frequently those funds rely on rule 5b–3 in their daily transactions in repurchase agreements. Accordingly, we are largely unable to quantify the benefits and costs discussed below.
Amended rule 5b–3 is intended to establish a similar credit quality standard to the NRSRO credit rating standard we are replacing in order to achieve the same objectives that the NRSRO credit rating reference requirement was designed to achieve in the existing rule,
Some fund boards or their delegates, after independent analysis, might make a determination of credit quality that comports with the analysis of the NRSRO credit ratings and, accordingly, make no substantive changes to the funds' investments in repurchase agreements. Other fund boards might turn to non-NRSRO sources (“third-party providers”) to satisfy the new requirements, which may result in a different pool of assets from which the funds may select for collateralizing
We recognize, as discussed above, that funds typically establish standards for the credit quality of collateral securities (that include credit ratings and additional credit quality criteria required by the fund) in repurchase agreements with counterparties.
Amended rule 5b–3 requires the fund's board or its delegate to make a determination about the collateral of each repurchase agreement. This will increase the regulatory burden on the fund's board,
If the fund's board decides to rely primarily on NRSRO ratings as part of the process of evaluating credit quality, the fund may incur some additional costs from today's amendments.
The new methodologies that the fund's board employs may result in a pool of assets from which the fund may select for collateralizing repurchase agreements that is different from a pool based on NRSRO ratings. This may affect the fund relative to the baseline of NRSRO ratings by including or excluding as collateral assets that are different from the collateral permitted under the current rule. In turn, this could increase the credit risk in the pool of collateral assets or decrease the return earned by investing in repurchase agreements. Both of these effects may lead to a less efficient market for repurchase agreement collateral. Issuers' ability to raise capital may also be adversely affected to the extent that issuers of collateral securities lose the regulatory preference that currently exists because of the required use of NRSRO ratings within rule 5b–3. We do not, however, believe that the amended rule is likely to lead to the acceptance of riskier collateral in practice because the standard we are adopting is very similar to the standard articulated by the NRSROs for securities that have received the highest ratings. In addition, we anticipate that fund boards and advisers will retain the credit quality standards in their current repurchase agreements and their existing policies and procedures that address compliance with current rule 5b–3 and include ratings that they believe are credible and reliable.
Although we believe that boards of funds relying on rule 5b–3 have established policies and procedures for complying with the rule,
In adopting today's amendments to rule 5b–3, the Commission considered, as noted by one commenter, including specific factors or tests that a fund board must apply in performing its credit analysis under the rule.
We also considered different standards to replace credit ratings that would help ensure that funds can liquidate collateral quickly in the event of a default. These alternatives included, for example, omitting an explicit liquidity requirement because securities in the “highest rating category” generally are more liquid than lower quality securities. Other liquidity alternatives we considered included limiting collateral securities only to cash and government securities because liquidity may decline between the time of acquisition and the time of default, or prohibiting a fund from relying on rule
Forms N–1A, N–2, and N–3, as amended, eliminate the required use of NRSRO credit ratings by funds that choose to use credit quality categorizations in the required table, chart, or graph of portfolio holdings. If a fund chooses to depict portfolio holdings according to credit quality, the fund must include a description of how the credit quality of the holdings was determined. If a fund uses credit ratings assigned by a credit rating agency to depict credit quality, the fund must disclose how it identified and selected the credit ratings.
As noted above, the economic baseline against which we measure the economic effects is the regulatory framework as it exists immediately before the adoption of today's amendments. Currently, Forms N–1A, N–2, and N–3 require shareholder reports to include a table, chart, or graph depicting portfolio holdings by reasonably identifiable categories (
We believe, based on staff experience, that the majority of funds choose to depict their portfolios using credit quality, and accordingly, report credit ratings from a single NRSRO. As discussed above, we conservatively estimate that 10,683 funds collectively file reports on Forms N–1A, N–2, and N–3 each year and will be affected by the amendments.
The Dodd-Frank Act mandate is designed to reduce potential reliance on NRSRO credit ratings. Under the amendments, funds have greater flexibility to assess and depict credit quality, which may lead to better-informed investors who can, in turn, make better capital allocation decisions. Accordingly, better-informed investors may make more effective investment decisions based on their risk tolerance and may promote increased competition among funds. We note, however, that funds might choose to report credit quality in a more positive light than is possible under the prior requirement to use the credit ratings from a single NRSRO. However, as discussed above, the disclosure requirements we are adopting today should mitigate many of the potential adverse consequences. As a result, today's amendments may have a varied effect on investors' ability to make effective capital allocation choices.
Because we do not anticipate that these amendments will result in large changes in the portfolios held by funds or their investors, we do not believe the amendments would have more than a marginal effect on efficiency or capital formation. A potential benefit may arise by allowing funds to use different credit rating agencies for split-rated securities because that may promote competition between credit rating agencies to provide ratings that are more accurate if funds use the most accurate ratings for each part of their portfolios even if those ratings come from different credit rating agencies. This may foster innovation in the industry, and it may foster the growth of niche credit rating agencies. Although some funds may eliminate the specific use of credit ratings in their depiction of portfolio credit quality, we anticipate that many of those funds are likely to consider some outside analyses in evaluating the credit quality of portfolio securities.
Under the amended forms, funds may continue to depict portfolio holdings as they do today: Funds can continue to depict portfolio holdings without making reference to credit quality, and funds can continue to depict portfolio holdings using credit ratings from one NRSRO. Today's amendments impose no new costs on funds that depict portfolio holdings based on criteria other than credit quality, but they do impose small additional costs on funds that choose to portray portfolio holdings using credit ratings from one NRSRO because they must make new disclosures about how the ratings were identified and selected. We believe that the majority of costs related to today's amendments to Forms N–1A, N–2, and N–3 are the costs described above related to the collections of information under the Paperwork Reduction Act. Accordingly, we estimate that funds on average will incur costs of approximately $1,137 per fund in complying with the amendments.
In adopting the amendments to the forms, the Commission considered replacing the required use of credit ratings with an option to depict a fund's portfolio by credit quality using the credit ratings of only a single credit rating agency. This approach, proposed in 2011, was intended to eliminate the possibility that a fund could choose to use NRSRO credit ratings and then select the most favorable ratings among the credit ratings assigned by multiple NRSROs. As discussed above, a number of commenters suggested that funds be permitted to use the credit ratings assigned by more than one NRSRO for split-rated securities, provided the choice is made consistently, pursuant to a disclosed policy. On balance, we believe that the benefits of this additional flexibility outweigh the potential costs associated with the possibility that funds cherry pick the highest credit rating available. We note that the risks associated with cherry picking ratings are mitigated by the fact that the forms, as amended, require that
The Commission has prepared the following Final Regulatory Flexibility Analysis (“FRFA”) in accordance with section 4(a) of the Regulatory Flexibility Act regarding the rule and form amendments we are adopting today to give effect to provisions of the Dodd-Frank Act.
As described more fully in sections I and III of this Release, to implement section 939A of the Dodd-Frank Act, the Commission is adopting amendments to (i) rule 5b–3 to eliminate references to the credit rating and replace it with an alternative standard of creditworthiness that is intended to achieve the same objectives that the credit rating requirement was designed to achieve and (ii) Forms N–1A, N–2, and N–3 to eliminate the required use of NRSRO credit ratings by funds that choose to use credit quality categorizations in the required table, chart, or graph of portfolio holdings in their shareholder reports, and to permit funds that choose to depict credit quality using credit ratings assigned by a credit rating agency to use different credit rating agencies for split-rated securities.
In the 2011 Proposing Release, we requested comment on the IRFA. In particular, we sought comment on how many small entities would be subject to the proposed rule and form amendments and whether the effect of the proposed rule and form amendments on small entities subject to them would be economically significant. None of the comment letters we received addressed the IRFA. None of the comment letters made comments about the effect of the rule and form amendments on small investment companies.
The amendments to rule 5b–3 and Forms N–1A, N–2, and N–3 under the Investment Company Act would affect funds, including entities that are considered to be a small business or small organization (collectively, “small entity”) for purposes of the Regulatory Flexibility Act.
The Regulatory Flexibility Act directs us to consider significant alternatives that would accomplish our stated objectives, while minimizing any significant adverse effect on small entities. In connection with the rule and form amendments, the Commission considered the following alternatives: (i) Establishing different compliance standards or timetables that take into account the resources available to small
We believe that special compliance or reporting requirements for small entities, or an exemption from coverage for small entities, is not appropriate or consistent with investor protection or the Dodd-Frank Act. We believe that, with respect to rule 5b–3, different credit quality standards, special compliance requirements or timetables for small entities, or an exemption from coverage for small entities, may create a risk that those entities could acquire repurchase agreements with collateral that is less likely to retain its market value or liquidity in the event of a counterparty default. Further consolidation or simplification of the rule and form amendments for funds that are small entities is inconsistent with the Commission's goals of fostering investor protection.
The form amendments apply to all investment companies that use Forms N–1A, N–2, and N–3 to register under the Investment Company Act and to offer their securities under the Securities Act. If the Commission had excluded small entities from the form amendments, small entities would have been required to use NRSRO credit ratings if they chose to depict credit quality, while other entities would not have been subject to that requirement. We believe that special compliance or reporting requirements, or an exemption, for small entities would not be appropriate because the amended requirement—eliminating the required use of credit ratings where a fund chooses to depict the fund's portfolio based on credit quality—is intended to eliminate potential reliance on NRSRO credit ratings resulting from the perception that the Commission endorses the ratings because of their required use in Commission forms.
We have endeavored through the form amendments to minimize regulatory burdens on investment companies, including small entities, while meeting our regulatory objectives. We have endeavored to clarify, consolidate, and simplify the requirements applicable to investment companies, including those that are small entities. Finally, the amendments will use performance rather than design standards for determining the credit quality of specific securities. For these reasons, we have not adopted alternatives to rule 5b–3 and Forms N–1A, N–2, and N–3.
The Commission is adopting amendments to rule 5b–3 under the authority set forth in sections 6(c) and 38(a) of the Investment Company Act [15 U.S.C. 80a–6(c), 80a–37(a)] and section 939A of the Dodd-Frank Act. The Commission is adopting amendments to Form N–1A, Form N–2, and Form N–3 under the authority set forth in sections 5, 6, 7, 10 and 19(a) of the Securities Act [15 U.S.C. 77e, 77f, 77g, 77j, and 77s(a)]; sections 8, 24(a), 30 and 38 of the Investment Company Act [15 U.S.C. 80a–8, 80a–24(a), 80a–29, and 80a–37]; and section 939A of the Dodd-Frank Act.
Reporting and recordkeeping requirements, Securities.
Investment companies, Reporting and recordkeeping requirements, Securities.
For reasons set out in the preamble, Title 17, Chapter II of the Code of Federal Regulations is amended as follows:
15 U.S.C. 77f, 77g, 77h, 77j, 77s, 77z–2, 77z–3, 77sss, 78c, 78
15 U.S.C. 80a–1
The revisions and addition read as follows:
(c) * * *
(1) * * *
(iv) * * *
(C) Securities that the investment company's board of directors, or its delegate, determines at the time the repurchase agreement is entered into:
For a discussion of the phrase “exceptionally strong capacity to meet its financial obligations” see Investment Company Act Release No. 30847, (December 27, 2013).
(4)
15 U.S.C. 77f, 77g, 77h, 77j, 77s, 78c(b), 78l, 78m, 78n, 78o(d), 80a–8, 80a–24, 80a–26, 80a–29, and Pub. L. 111–203, sec. 939A, 124 Stat. 1376 (2010), unless otherwise noted.
The text of Form N–1A does not, and these amendments will not, appear in the Code of Federal Regulations.
(d)
(2)
The text of Form N–2 does not, and these amendments will not, appear in the Code of Federal Regulations.
6. * * *
a. one or more tables, charts, or graphs depicting the portfolio holdings of the Fund by reasonably identifiable categories (
The text of Form N–3 does not, and these amendments will not, appear in the Code of Federal Regulations.
(a) * * *
6. * * *
(i) One or more tables, charts, or graphs depicting the portfolio holdings of the Fund by reasonably identifiable categories (
By the Commission.
Department of Veterans Affairs.
Final rule.
This rule adopts as final, without change, an interim final rule amending the Department of Veterans Affairs (VA) regulations concerning approval of non-VA community residential care (CRC) facilities to allow VA to waive such facilities' compliance with standards that do not jeopardize the health or safety of residents. As amended, the regulation allows VA to grant a waiver of a CRC standard in those limited circumstances where the deficiency cannot be corrected to meet a standard provided for in VA regulation. This rulemaking also makes a certain necessary technical amendment to correct a reference to the section addressing requests for a hearing.
Nancy Quest, Director, Home and Community Based Services (10P4G), Veterans Health Administration, 810 Vermont Avenue NW., Washington, DC 20420, (202) 461–6064. (This is not a toll-free number.)
In an interim final rule published in the
Based on the rationale set forth in the interim final rule, VA is adopting the
In accordance with 5 U.S.C. 553(b)(B) and (d)(3), the Secretary of Veterans Affairs concluded that there was good cause to publish the interim final rule without prior opportunity for public comment and to publish the rule with an immediate effective date. The Secretary found that it was contrary to the public interest to delay this rule for the purpose of soliciting advance public comment or to have a delayed effective date. The interim final rule was necessary to address an immediate need to provide a mechanism that will allow VA to grant a waiver to a CRC facility that cannot obtain full approval because of a minor deviation from regulatory standards that cannot be corrected and does not endanger the lives or safety of the veteran residents. Although approval would be rescinded because of a minor and uncorrectable deviation from standards unrelated to health or safety, veterans may be dissuaded from maintaining their residence in such a facility. Providing a waiver in that circumstance will preclude the need to terminate a CRC facility's approval based on an uncorrectable minor deviation from non-safety related standards. This eliminates the potential that resident veterans will needlessly choose to leave an otherwise healthy, safe, and suitable living arrangement. Regulations in place prior to the effective date of the interim final rule did not provide for any waiver of standards. It is in the public interest for a veteran not to be removed from a stable living situation based solely on a minor deviation from standards that does not threaten life or safety.
To prevent veterans from needlessly choosing to leave affected CRC facilities because the facilities are no longer on the approved list, and in order to ensure timely implementation of the program established by this rule, and for the reasons stated above, the Secretary also found, in accordance with 5 U.S.C. 553(d)(3), good cause for the interim final rule to be effective on the date of publication.
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.
This final rule contains no provisions constituting a collection of information under the Paperwork Reduction Act of 1995 (PRA) (44 U.S.C. 3501–3521). Documentation that a VA safety expert may request from a CRC facility to support a waiver determination, as provided under 38 CFR 17.65(d)(1), would not qualify as “information” under the PRA because collection of this information would be conducted on an individual case-by-case basis and would require individualized information pertaining to the specific deficiency identified by the VA safety expert. We believe that this collection is therefore exempt from the PRA requirements, as provided under 5 CFR 1320.3(h)(6) (excluding from PRA requirements a “request for facts or opinions addressed to a single person).”
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. This final rule will have little, if any, economic impact on a few small entities. VA may waive a standard under this rulemaking provided a VA safety expert certifies that the deficiency does not endanger the life or safety of the residents, the deficiency cannot be corrected, and granting the waiver is in the best interests of the veteran in the facility and VA's CRC program.
In order to reach the above determinations, the VA safety expert may request supporting documentation from the CRC facility. VA believes supplying this information will constitute an inconsequential amount of the operational cost for those CRC facilities. VA believes that, at most, only a few CRC facilities would qualify for a waiver. On this basis, the Secretary certifies that the adoption of 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. 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 the Office of Management and Budget (OMB) unless OMB waives such review, 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. VA's impact analysis can be found as a supporting document at
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 1 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 64.007, Blind Rehabilitation Centers; 64.008, Veterans Domiciliary Care; 64.009, Veterans Medical Care Benefits; 64.010, Veterans Nursing Home Care; 64.011, Veterans Dental Care; 64.012, Veterans Prescription Service; and 64.022, Veterans Home Based Primary Care.
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. Jose D. Riojas, Chief of Staff, Department of Veterans Affairs, approved this document on December 6, 2013, for publication.
Administrative practice and procedure, Alcohol abuse, Alcoholism, Claims, Day care, Dental health, Drug abuse, Foreign relations, Government contracts, Grant programs-health, Government programs-veterans, Health care, Health facilities, Health professions, Health records, Homeless, Medical and dental schools, Medical devices, Medical research, Mental health programs, Nursing homes, Reporting and recordkeeping requirements, Scholarships and fellowships, Travel and transportation expenses, Veterans.
Based on the rationale set forth in the
Department of Veterans Affairs.
Final rule.
The Department of Veterans Affairs (VA) amends its regulations to remove an outdated regulation that stated that a veteran who misses two medical appointments without providing 24 hours' notice and a reasonable excuse is deemed to have refused VA medical care. VA removes this penalty because we believe it is incompatible with regulatory changes implemented after the regulation was promulgated, is not in line with current practice, and is inconsistent with VA's patient-centered approach to medical care.
Ethan Kalett, Director, Office of Regulatory Affairs (10B4), Department of Veterans Affairs, 810 Vermont Ave. NW., Washington, DC 20420; (202) 461–5657. (This is not a toll-free number.)
On April 15, 2013, VA published in the
Interested persons were invited to submit comments to the proposed rule on or before June 14, 2013, and we received six comments. All of the comments were supportive of removing § 17.100, and did not suggest changes to the proposed removal of the rule. However, two commenters raised issues that we believe should be addressed.
One commenter expressed support for removing this regulation, but suggested a different approach to addressing the issue of broken appointments. The commenter suggested that, after two consecutive missed appointments, VA should follow a series of steps to contact the veteran and to place a limit (“moratorium”) on the care available to the veteran on the particular health issue.
VA appreciates the commenter's input. However, VA has determined that the appropriate course of action is to remove the penalty for breaking appointments. In practice, the problem of missed appointments has been adequately addressed through internal VA processes, as well as by using non-punitive measures and maintaining an open channel of communication between VA clinical/administrative staff and veterans. The penalty contemplated by § 17.100 is incompatible with regulatory changes implemented after that regulation was published, is not in line with current practice, and is inconsistent with VA's patient-centered approach to medical care. Even a short break in a course of treatment can interfere with continuity and coordination of care, and the punitive nature of the regulation could have a negative impact on the therapeutic relationship.
Another commenter supported removing the penalty for breaking medical appointments, but stated that the regulation should be removed because it violates due process protections. VA disagrees. The regulation we remove by this final rule did not terminate a benefit; it merely attempted to facilitate efficient delivery of limited health care resources. The veteran remained enrolled to receive health care, and could receive treatment for any emergent condition that may arise. To schedule a non-emergency medical appointment, the veteran merely had to agree to attend the appointment. In any event, this issue is moot because we are removing the penalty.
This commenter also suggested that VA should employ social workers to be responsible for tracking and contacting veterans who habitually miss medical appointments. VA does use various methods to follow up with those veterans in an effort to ensure they receive necessary medical care. Veterans are contacted via mail, phone, or electronic means after a missed appointment, and are encouraged to contact VA to reschedule.
We do not make any changes based on these comments.
Based on the rationale set forth in the proposed rule and in this final rule, VA is adopting the provisions of the
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.
This final rule contains no provisions constituting a collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501–3521).
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. This final rule will directly affect only individuals and will not directly affect small entities. Therefore, pursuant to 5 U.S.C. 605(b), this rulemaking is exempt from the initial and final regulatory flexibility analysis requirements of 5 U.S.C. 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 the Office of Management and Budget (OMB), unless OMB waives such review, 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 final rule have been examined, and it has been determined not to be a significant regulatory action under Executive Order 12866. VA's impact analysis can be found as a supporting document at
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 64.007, Blind Rehabilitation Centers; 64.008, Veterans Domiciliary Care; 64.009, Veterans Medical Care Benefits; 64.010, Veterans Nursing Home Care; 64.011, Veterans Dental Care; 64.012, Veterans Prescription Service; and 64.022, Veterans Home Based Primary Care.
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. Jose D. Riojas, Chief of Staff, Department of Veterans Affairs, approved this document on December 20, 2013, for publication.
Administrative practice and procedure, Alcohol abuse, Alcoholism, Claims, Day care, Dental health, Drug abuse, Foreign relations, Government contracts, Grant programs-health, Government programs-veterans, Health care, Health facilities, Health professions, Health records, Homeless, Medical and dental schools, Medical devices, Medical research, Mental health programs, Nursing homes, Reporting and recordkeeping requirements, Scholarships and fellowships, Travel and transportation expenses, Veterans.
For the reasons stated in the preamble, the Department of Veterans Affairs amends 38 CFR part 17 as follows:
38 U.S.C. 501, and as noted in specific sections.
Federal Aviation Administration (FAA), DOT.
Notice of proposed special conditions.
This action proposes special conditions for Airbus Model A350–900 series airplanes. These airplanes will have a novel or unusual design feature(s) associated with the post-crash fire survivability of composite fuel tanks. The applicable airworthiness regulations do not contain adequate or appropriate safety standards for this design feature. These proposed special conditions contain the additional safety standards that the Administrator considers necessary to establish a level of safety equivalent to that established by the existing airworthiness standards.
Send your comments on or before February 24, 2014.
Send comments identified by docket number FAA–2013–0908 using any of the following methods:
•
•
•
•
Doug Bryant, Propulsion/Mechanical Systems, ANM–112, Transport Airplane Directorate, Aircraft Certification Service, 1601 Lind Avenue SW., Renton, Washington, 98057–3356; telephone (425) 227–2384; facsimile (425) 227–1320.
We invite interested people to take part in this rulemaking by sending written comments, data, or views. The most helpful comments reference a specific portion of the special conditions, explain the reason for any recommended change, and include supporting data.
We will consider all comments we receive on or before the closing date for comments. We may change these proposed special conditions based on the comments we receive.
On August 25, 2008, Airbus applied for a type certificate for their new Model A350–900 series airplane. Later, Airbus requested and the FAA approved an extension to the application for FAA type certification to June 28, 2009. The Model A350–900 series airplane has a conventional layout with twin wing-mounted Rolls-Royce Trent XWB engines. It features a twin aisle 9-abreast economy class layout, and accommodates side-by-side placement of LD–3 containers in the cargo compartment. The basic Model A350–900 series airplane configuration will accommodate 315 passengers in a standard two-class arrangement. The design cruise speed is Mach 0.85 with a maximum take-off weight of 602,000 lbs. Airbus proposes the Model A350–900 series airplane to be certified for extended operations (ETOPS) beyond 180 minutes at entry into service for up to a 420-minute maximum diversion time.
The Model A350–900 series airplane will be the second large transport category airplane certificated with composite wing and fuel tank structure that may be exposed to the direct effects of post-crash ground or under-wing fuel-fed fires. Although the FAA has previously approved fuel tanks made of composite materials located in the horizontal stabilizer of some airplanes, the composite wing structure of the Model A350–900 series airplane will incorporate a new fuel tank construction into service.
Advisory Circular (AC) 20–107A, Composite Aircraft Structure, under the topic of flammability, states: “The existing requirements for flammability and fire protection of aircraft structure attempt to minimize the hazard to the occupants in the event ignition of flammable fluids or vapors occurs. The use of composite structure should not decrease this existing level of safety.” Pertinent to the wing structure, post-crash fire passenger survivability is dependent on the time available for passenger evacuation prior to fuel tank breach or structural failure. Structural failure can be a result of degradation in load-carrying capability in the upper or lower wing surface caused by a fuel-fed ground fire. Structural failure can also be a result of over-pressurization caused by ignition of fuel vapors internal to the fuel tank.
The inherent capability of aluminum to resist fire has been considered by the FAA in development of the current regulations. Title 14 Code of Federal Regulations (14 CFR) part 25 Chapter 1, Section 1.1, General Definitions, defines
The FAA has historically promulgated rules with the assumption that the material of construction for wing and fuselage would be aluminum. As a representative case, § 25.963 was promulgated as a result of a large fuel-fed fire following the failures of fuel tank access doors caused by uncontained engine failures. During the subsequent Aviation Rulemaking Advisory Committee (ARAC) harmonization process, the structures group attempted to harmonize § 25.963 regarding the impact and fire resistance of the fuel tank access panels. Discussions between the FAA and the European Aviation Safety Agency (EASA), formerly the European Joint Aviation Authorities (JAA), ensued regarding the need for fire resistance of the fuel tank access panels. The EASA position was that the FAA requirement for the access panels to be fire resistant when the surrounding wing structure was not required to be fire resistant was inconsistent and that the access panels only needed to be as fire resistant as the surrounding tank structure. The FAA position stated that the fuel tank access panel fire resistance requirement should be retained, and that long term there should be a minimum requirement created for the wing skin itself. Both authorities recognized that existing aluminum wing structure provided an acceptable level of safety. Further rulemaking has not yet been pursued.
As with previous Airbus airplane designs with under-wing mounted engines, the wing tanks and center tanks are located in proximity to the passengers and near the engines. Past experience indicates post-crash survivability is greatly influenced by the size and intensity of any fire that occurs. The ability of aluminum wing surfaces wetted by fuel on their interior surface to withstand post-crash fire conditions has been demonstrated by tests conducted at the FAA William J. Hughes Technical Center.
Results of these tests have verified adequate dissipation of heat across wetted aluminum fuel tank surfaces so that localized hot spots do not occur, thus minimizing the threat of explosion. This inherent capability of aluminum to dissipate heat also allows the wing lower surface to retain its load carrying characteristics during a fuel-fed ground fire and significantly delay wing collapse or burn-through for a time interval that usually exceeds evacuation times. In addition, as an aluminum fuel tank is heated with significant quantities of fuel inside, fuel vapor accumulates in the ullage space, exceeding the upper flammability limit relatively quickly and thus reducing the threat of a fuel tank explosion prior to fuel tank burn-through. Service history of conventional aluminum airplanes has shown that fuel tank explosions caused by ground fires have been rare on airplanes configured with flame arrestors in the fuel tank vent lines. Fuel tanks constructed with composite materials may or may not have equivalent capability.
Due to the inherent properties provided by aluminum skin and structure, current regulations may not be adequate as they were developed and have evolved under the assumption that wing construction would be of aluminum materials. Inherent properties of aluminum with respect to fuel tanks and fuel fed fires are as follows:
• Aluminum is highly thermally conductive and readily transmits the heat of a fuel-fed external fire to fuel in the tank. This has the benefit of rapidly driving the fuel tank ullage to exceed the upper flammability limit prior to burn-through of the fuel tank skin or heating of the wing upper surface above the auto-ignition temperature, thus greatly reducing the threat of fuel tank explosion.
• Aluminum panels at thicknesses previously used in wing lower surfaces of large transport category airplanes have been fire resistant as defined in 14 CFR 14 part 1 and AC 20–135.
• Heat capacity of aluminum and fuel will prevent burn-through or wing collapse for a time interval that will generally exceed the passenger evacuation time.
Under Title 14, Code of Federal Regulations (14 CFR) 21.17, Airbus must show that the Model A350–900 series airplane meets the applicable provisions of 14 CFR part 25, as amended by Amendments 25–1 through 25–129.
If the Administrator finds that the applicable airworthiness regulations (i.e., 14 CFR part 25) do not contain adequate or appropriate safety standards for the Model A350–900 series airplane because of a novel or unusual design feature, special conditions are prescribed under § 21.16.
Special conditions are initially applicable to the model for which they are issued. Should the type certificate for that model be amended later to include any other model that incorporates the same or similar novel or unusual design feature, the proposed special conditions would also apply to the other model under § 21.101.
The FAA issues special conditions, as defined in 14 CFR 11.19, under § 11.38, and they become part of the type-certification basis under § 21.17(a)(2).
In addition to the applicable airworthiness regulations and special conditions, the Model A350–900 series must comply with the fuel vent and exhaust emission requirements of 14 CFR part 34 and the noise certification requirements of 14 CFR part 36 and the FAA must issue a finding of regulatory adequacy under § 611 of Public Law 92–574, the “Noise Control Act of 1972.”
The Airbus Model A350–900 series airplane will incorporate the following novel or unusual design features: composite fuel tanks.
The extensive use of composite materials in the design of the A350 wing and fuel tank structure is considered a major change from conventional and traditional methods of construction, as this will be only the second large transport category airplane to be certificated with this level of composite material for these purposes. The applicable airworthiness regulations do not contain specific standards for post-crash fire safety performance of wing and fuel tank skin or structure.
In order to provide the same level of safety as exists with conventional airplane construction, Airbus must demonstrate that the Model A350–900 series airplane has sufficient post-crash survivability to enable occupants to safely evacuate in the event that the wings are exposed to a large fuel-fed fire. Factors in fuel tank survivability
There is little benefit in requiring the design to prevent wing skin burn-through beyond five minutes, due to the effects of the fuel fire itself on the rest of the airplane. That assessment was carried out based on accidents involving airplanes with conventional fuel tanks, and considering the ability of ground personnel to rescue occupants. In addition, AC 20–135 indicates that, when aluminum is used for fuel tanks, the tank should withstand the effects of fire for 5 minutes without failure. Therefore, to be consistent with existing capability and related requirements, the Model A350–900 series airplane fuel tanks must be capable of resisting a post-crash fire for at least 5 minutes. In demonstrating compliance, Airbus must address a range of fuel loads from minimum to maximum, as well as any other critical fuel load.
As discussed above, these proposed special conditions apply to Airbus Model A350–900 series airplanes. Should Airbus apply later for a change to the type certificate to include another model incorporating the same novel or unusual design feature, the proposed special conditions would apply to that model as well under the provisions of § 21.101.
This action affects only certain novel or unusual design features on the Airbus Model A350–900 series airplanes. It is not a rule of general applicability.
Aircraft, Aviation safety, Reporting and recordkeeping requirements.
The authority citation for these special conditions is as follows:
49 U.S.C. 106(g), 40113, 44701, 44702, 44704.
Accordingly, pursuant to the authority delegated to me by the Administrator, the following special conditions are proposed as part of the type certification basis for the Model A350–900 series airplane:
In addition to complying with 14 CFR part 25 regulations governing the fire-safety performance of the fuel tanks, wings, and nacelle, the Airbus Model A350–900 series airplane must demonstrate acceptable post-crash survivability in the event the wings are exposed to a large fuel-fed ground fire. Airbus must demonstrate that the wing and fuel tank design can endure an external fuel-fed pool fire for at least five minutes. This shall be demonstrated for minimum fuel loads (not less than reserve fuel levels) and maximum fuel loads (maximum range fuel quantities), and other identified critical fuel loads. Considerations shall include fuel tank flammability, burn-through resistance, wing structural strength retention properties, and auto-ignition threats during a ground fire event for the required time duration.
Federal Aviation Administration (FAA), DOT.
Notice of proposed special conditions.
This action proposes special conditions for Airbus Model A350–900 series airplanes. These airplanes will have a novel or unusual design feature associated with high speed limiting. The applicable airworthiness regulations do not contain adequate or appropriate safety standards for this design feature. These proposed special conditions contain the additional safety standards that the Administrator considers necessary to establish a level of safety equivalent to that established by the existing airworthiness standards.
Send your comments on or before February 7, 2014.
Send comments identified by docket number FAA–2013–0901 using any of the following methods:
•
•
•
•
Joe Jacobsen, FAA, Airplane and Flightcrew Interface Branch, ANM–111, Transport Airplane Directorate, Aircraft Certification Service, 1601 Lind Avenue SW., Renton, Washington 98057–3356; telephone (425) 227–2011; facsimile (425) 227–1320.
We invite interested people to take part in this rulemaking by sending
We will consider all comments we receive on or before the closing date for comments. We may change these special conditions based on the comments we receive.
On August 25, 2008, Airbus applied for a type certificate for their new Model A350–900 series airplane. Later, Airbus requested and the FAA approved an extension to the application for FAA type certification to June 28, 2009. The Model A350–900 series has a conventional layout with twin wing-mounted Rolls-Royce Trent engines. It features a twin aisle 9-abreast economy class layout, and accommodates side-by-side placement of LD–3 containers in the cargo compartment. The basic Model A350–900 series configuration will accommodate 315 passengers in a standard two-class arrangement. The design cruise speed is Mach 0.85 with a Maximum Take-Off Weight of 602,000 lbs. Airbus proposes the Model A350–900 series to be certified for extended operations (ETOPS) beyond 180 minutes at entry into service for up to a 420-minute maximum diversion time.
The longitudinal control law design of the Airbus Model A350–900 incorporates an overspeed protection system in the normal mode; this would prevent the pilot from inadvertently or intentionally exceeding a speed approximately equivalent to V
Under Title 14, Code of Federal Regulations (14 CFR) 21.17, Airbus must show that the Model A350–900 series meets the applicable provisions of 14 CFR part 25, as amended by Amendments 25–1 through 25–129.
If the Administrator finds that the applicable airworthiness regulations (i.e., 14 CFR part 25) do not contain adequate or appropriate safety standards for the Airbus Model A350–900 series because of a novel or unusual design feature, special conditions are prescribed under § 21.16.
Special conditions are initially applicable to the model for which they are issued. Should the type certificate for that model be amended later to include any other model that incorporates the same or similar novel or unusual design feature, the special conditions would also apply to the other model under § 21.101.
In addition to the applicable airworthiness regulations and proposed special conditions, the Model A350–900 series must comply with the fuel vent and exhaust emission requirements of 14 CFR part 34 and the noise certification requirements of 14 CFR part 36 and the FAA must issue a finding of regulatory adequacy under section 611 of Public Law 92–574, the “Noise Control Act of 1972.”
The FAA issues special conditions, as defined in 14 CFR 11.19, under § 11.38, and they become part of the type-certification basis under § 21.17(a)(2).
The Model A350–900 series will incorporate the following novel or unusual design features: An overspeed protection system which prevents the pilot from inadvertently or intentionally exceeding a speed approximately equivalent to V
At V
This proposed special condition establishes requirements to ensure that operation of the high speed limiting protection system does not impede normal attainment of speeds up to the overspeed warning. Its main features are:
1. It protects the airplane against high speed/high Mach number flight conditions beyond V
2. It does not interfere with flight at V
3. It still provides load factor limitation through the “pitch limiting” function described below.
4. It restores positive static stability beyond V
As discussed above, these proposed special conditions apply to Airbus Model A350–900 series airplanes. Should Airbus apply later for a change to the type certificate to include another model incorporating the same novel or unusual design feature, the proposed special conditions would apply to that model as well.
This action affects only certain novel or unusual design features on the Airbus Model A350–900 series airplanes. It is not a rule of general applicability.
Aircraft, Aviation safety, Reporting and recordkeeping requirements.
The authority citation for these special conditions is as follows:
49 U.S.C. 106(g), 40113, 44701, 44702, 44704.
Accordingly, the Federal Aviation Administration (FAA) proposes the following special condition as part of the type certification basis for Airbus Model A350–900 series airplanes.
In addition to § 25.143, the following requirements apply: Operation of the high speed limiter during all routine and descent procedure flight must not impede normal attainment of speeds up to overspeed warning
Federal Aviation Administration (FAA), DOT.
Notice of proposed special conditions.
This action proposes special conditions for the Airbus Model A350–900 series airplanes. These airplanes will have a novel or unusual design feature associated with crashworthiness of carbon fiber reinforced plastic used in the construction of the fuselage. The applicable airworthiness regulations do not contain adequate or appropriate safety standards for this design feature. These proposed special conditions contain the additional safety standards that the Administrator considers
Send your comments on or before February 24, 2014.
Send comments identified by docket number FAA–2013–0892 using any of the following methods:
•
•
•
•
Todd Martin, FAA, Airframe/Cabin Safety, ANM–115, Transport Airplane Directorate, Aircraft Certification Service, 1601 Lind Avenue SW., Renton, Washington, 98057–3356; telephone (425) 227–1178; facsimile (425) 227–1320.
We invite interested people to take part in this rulemaking by sending written comments, data, or views. The most helpful comments reference a specific portion of the proposed special conditions, explain the reason for any recommended change, and include supporting data. We ask that you send us two copies of written comments.
We will consider all comments we receive on or before the closing date for comments. We may change these proposed special conditions based on the comments we receive.
On August 25, 2008, Airbus applied for a type certificate for their new Model A350–900 series airplane. Later, Airbus requested and the FAA approved an extension to the application for FAA type certification to June 28, 2009, The Model A350–900 series has a conventional layout with twin wing-mounted Rolls-Royce Trent XWB engines. It features a twin aisle 9-abreast economy class layout, and accommodates side-by-side placement of LD–3 containers in the cargo compartment. The basic Model A350–900 series configuration will accommodate 315 passengers in a standard two-class arrangement. The design cruise speed is Mach 0.85 with a Maximum Take-Off Weight of 602,000 lbs. Airbus proposes the Model A350–900 series to be certified for extended operations (ETOPS) beyond 180 minutes at entry into service for up to a 420-minute maximum diversion time.
Changes in the structural behavior of the Airbus Model A350–900 series airplanes compared to currently certificated designs could degrade the survivability of Model A350–900 series occupants in crash conditions that are within the limits of survivability for other designs.
There is no aircraft-level survivable crash condition specified in the airworthiness regulations, and metallic aircraft have not been specifically designed against survivable impact conditions. However, the structural behavior of previously certificated aircraft in a survivable crash event and the associated limits are considered generally acceptable. It is therefore reasonable to expect that a design using new materials, such as the Model A350–900 series airplanes use, should be assessed to ensure that the material meets the currently accepted level of safety. The FAA and industry have collected a significant amount of experimental data as well as data from crashes of transport category airplanes that show a high occupant survival rate at vertical descent velocities up to 30 ft/sec. Based on this information, the FAA finds it appropriate and necessary for an assessment of the Model A350–900 series airplanes to span a range of airplane vertical descent speeds up to 30 ft/sec.
Under Title 14, Code of Federal Regulations (14 CFR) 21.17, Airbus must show that the Model A350–900 series meets the applicable provisions of 14 CFR part 25, as amended by Amendments 25–1 through 25–129.
If the Administrator finds that the applicable airworthiness regulations (i.e., 14 CFR part 25) do not contain adequate or appropriate safety standards for the Model A350–900 series because of a novel or unusual design feature, special conditions are prescribed under § 21.16.
Special conditions are initially applicable to the model for which they are issued. Should the type certificate for that model be amended later to include any other model that incorporates the same or similar novel or unusual design feature, the special conditions would also apply to the other model under § 21.101.
In addition to the applicable airworthiness regulations and special conditions, the Model A350–900 series must comply with the fuel vent and exhaust emission requirements of 14 CFR part 34 and the noise certification requirements of 14 CFR part 36 and the FAA must issue a finding of regulatory adequacy under § 611 of Public Law 92–574, the “Noise Control Act of 1972.”
The FAA issues special conditions, as defined in 14 CFR 11.19, under § 11.38, and they become part of the type-certification basis under § 21.17(a)(2).
The Airbus Model A350–900 series will incorporate the following novel or unusual design feature: fuselage fabricated with a combination of carbon fiber reinforced plastic (CFRP) and metallic structure. This is a novel and unusual design feature for a large transport airplane. Structure fabricated from CFRP may behave differently than metallic structure in crash conditions because of differences in material ductility, stiffness, failure modes, and energy absorption characteristics. Therefore, the impact response characteristics of the Model A350–900 series airplane must be evaluated to ensure that its survivable crashworthiness characteristics provide at least the same level of safety as those of a similarly sized airplane constructed from traditionally used metallic materials.
There are no existing regulations that adequately address this potential difference in impact response
Factors in crash survivability are retention of items of mass, maintenance of occupant emergency egress paths, maintenance of acceptable acceleration and loads experienced by the occupants, and maintenance of a survivable volume. To provide the same level of safety as exists with conventional airplane construction, Airbus should show that the Model A350–900 series airplanes have sufficient crashworthiness capabilities under foreseeable survivable impact events. To show this, Airbus should evaluate the impact response characteristics of the Model A350–900 series airplane to ensure that its crashworthiness characteristics are not significantly different from those of a similarly sized airplane built from traditionally used metallic materials.
In their evaluation of the Model A350–900 series airplane response to an impact event, Airbus should demonstrate that the structural behavior is similar to that expected from a metallic airframe of similar size to the Model A350–900, or incorporate mitigating design features that provide a similar level of safety.
Airbus should demonstrate either through analysis using validated analytical tools or by direct test evidence that the crash dynamics of the A350 fuselage structure provides a level of occupant protection consistent with previously certificated large transport category airplanes.
As discussed above, these proposed special conditions apply to Airbus Model A350–900 series airplanes. Should Airbus apply later for a change to the type certificate to include another model incorporating the same novel or unusual design feature, the proposed special conditions would apply to that model as well.
This action affects only certain novel or unusual design features on the Airbus Model A350–900 series airplanes. It is not a rule of general applicability.
Aircraft, Aviation safety, Reporting and recordkeeping requirements.
The authority citation for these special conditions is as follows:
49 U.S.C. 106(g), 40113, 44701, 44702, 44704.
Accordingly, the Federal Aviation Administration (FAA) proposes the following special conditions as part of the type certification basis for Airbus Model A350–900 series airplanes.
The Airbus Model A350–900 series airplanes must provide an equivalent level of occupant safety and survivability to that provided by previously certificated wide-body transports of similar size under foreseeable survivable impact events for the following four criteria. In order to demonstrate an equivalent level of occupant safety and survivability, the applicant must demonstrate that Model A350–900 series airplanes meet the following criteria for a range of airplane vertical descent velocities up to 30 ft/sec.
1. Retention of items of mass. The occupants, i.e., passengers, flight attendants, and flightcrew, must be protected during the impact event from release of seats, overhead bins, and other items of mass due to the impact loads and resultant structural deformation of the supporting airframe and floor structures. The applicant must show that loads due to the impact event and resultant structural deformation of the supporting airframe and floor structure at the interface of the airplane structure to seats, overhead bins, and other items of mass are comparable to those of previously certificated wide-body transports of similar size for the range of descent velocities stated above. The attachments of these items need not be designed for static emergency landing loads in excess of those defined in § 25.561 if impact response characteristics of the Airbus Model A350–900 series airplanes yield load factors at the attach points that are comparable to those for a previously certificated wide-body transport category airplane.
2. Maintenance of acceptable acceleration and loads experienced by the occupants. The applicant must show that the impact response characteristics of the Airbus Model A350–900 series airplane, specifically the vertical acceleration levels experienced at the seat/floor interface and loads experienced by the occupants during the impact events, are consistent with those found in § 25.562(b) or with levels expected for a previously certificated wide-body transport category airplane for the conditions stated above.
3. Maintenance of a survivable volume. For the conditions stated above, the applicant must show that all areas of the airplane occupied for takeoff and landing provide a survivable volume comparable to that of previously certificated wide-body transports of similar size during and after the impact event. This means that structural deformation will not result in infringement of the occupants' normal living space so that passenger survivability will not be significantly affected.
4. Maintenance of occupant emergency egress paths. The evacuation of occupants must be comparable to that from a previously certificated wide-body transport of similar size. To show this, the applicant must show that the suitability of the egress paths, as determined following the vertical impact events, is comparable to the suitability of the egress paths of a comparable, certificated wide-body transport, as determined following the same vertical impact events.
Federal Aviation Administration (FAA), DOT.
Notice of proposed special conditions.
This action proposes special conditions for the Airbus Model A350–900 series airplanes. These airplanes will have a novel or unusual design feature associated with a lateral trim function that deploys flaps asymmetrically for airplane lateral trim control. This function replaces the traditional method of providing airplane lateral trim over a small range through flap and aileron mechanical rigging. The applicable airworthiness regulations do not contain adequate or appropriate safety standards for this design feature. These proposed special conditions contain the additional safety standards that the Administrator considers necessary to establish a level of safety
Send your comments on or before February 24, 2014.
Send comments identified by docket number FAA–2013–0911 using any of the following methods:
•
•
•
•
Robert C. Jones, FAA, Propulsion/Mechanical Systems, ANM–112, Transport Airplane Directorate, Aircraft Certification Service, 1601 Lind Avenue SW., Renton, Washington 98057–3356; telephone (425) 227–1234; facsimile (425) 227–1320.
We invite interested people to take part in this rulemaking by sending written comments, data, or views. The most helpful comments reference a specific portion of the special conditions, explain the reason for any recommended change, and include supporting data.
We will consider all comments we receive on or before the closing date for comments. We may change these proposed special conditions based on the comments we receive.
On August 25, 2008, Airbus applied for a type certificate for their new Model A350–900 series airplane. Later, Airbus requested and the FAA approved an extension to the application for FAA type certification to June 28, 2009. The Model A350–900 series has a conventional layout with twin wing-mounted Rolls-Royce Trent XWB engines. It features a twin aisle 9-abreast economy class layout, and accommodates side-by-side placement of LD–3 containers in the cargo compartment. The basic Model A350–900 series configuration will accommodate 315 passengers in a standard two-class arrangement. The design cruise speed is Mach 0.85 with a Maximum Take-Off Weight of 602,000 lbs. Airbus proposes the Model A350–900 series to be certified for extended operations (ETOPS) beyond 180 minutes at entry into service for up to a 420-minute maximum diversion time.
On conventional airplanes, small lateral airplane asymmetries have typically been addressed through flap and aileron rigging (e.g., using shims). On Model A350–900 series airplanes, an order for asymmetric flap deployment will be computed by the primary flight control system as a function of the aileron position. The current airworthiness standards do not contain adequate safety standards for asymmetric use of the flaps as proposed for Airbus Model A350–900 series airplanes. Special conditions are needed to account for the aspects of a function used to command an intended flap asymmetry. The lateral trim function is intended to be performed once during climb and once during cruise to compensate for small airplane lateral asymmetries.
The lateral trim function is not a trim control system in the conventional sense as it has no pilot interface and is not governed by § 25.677. In fact some fly-by-wire airplanes have no pilot operated lateral trim at all. The lateral trim function is simply an additional fly-by-wire flight control function that nulls small roll asymmetries in certain flight phases with small asymmetric flap deployments. Although the function operates under normal conditions within the small range of the traditional rigging, there may be failure cases leading to a significant out of range asymmetric flap condition. An asymmetry threshold will protect the system against excessive flap asymmetry.
Under Title 14, Code of Federal Regulations (14 CFR) 21.17, Airbus must show that the Model A350–900 series meets the applicable provisions of 14 CFR part 25, as amended by Amendments 25–1 through 25–129.
If the Administrator finds that the applicable airworthiness regulations (i.e., 14 CFR part 25) do not contain adequate or appropriate safety standards for the Model A350–900 series because of a novel or unusual design feature, special conditions are prescribed under § 21.16.
Special conditions are initially applicable to the model for which they are issued. Should the type certificate for that model be amended later to include any other model that incorporates the same novel or unusual design feature, the proposed special conditions would also apply to the other model under § 21.101.
In addition to the applicable airworthiness regulations and proposed special conditions, the Model A350–900 series must comply with the fuel vent and exhaust emission requirements of 14 CFR part 34 and the noise certification requirements of 14 CFR part 36 and the FAA must issue a finding of regulatory adequacy under § 611 of Public Law 92–574, the “Noise Control Act of 1972.”
The FAA issues special conditions, as defined in 14 CFR 11.19, under § 11.38, and they become part of the type-certification basis under § 21.17(a)(2).
The Airbus Model A350–900 series will incorporate the following novel or unusual design features: the asymmetric use of flaps to address lateral trim which is not adequately addressed by § 25.701.
Title 14 Code of Federal Regulations (14 CFR) part 25 § 25.701(a) requires that unless the airplane has safe flight characteristics with the flaps or slats retracted on one side and extended on the other, flap and slat surfaces must be synchronized by either a mechanical interconnection or any equivalent means that has the same integrity. Synchronization is interpreted to mean that flap movement is symmetrical throughout the full range of flap motion. Because the lateral trim function
As discussed above, these proposed special conditions apply to Airbus Model A350–900 series airplanes. Should Airbus apply later for a change to the type certificate to include another model incorporating the same novel or unusual design feature, the proposed special conditions would apply to that model as well.
This action affects only certain novel or unusual design features on the Airbus Model A350–900 series airplanes. It is not a rule of general applicability.
Aircraft, Aviation safety, Reporting and recordkeeping requirements.
The authority citation for these special conditions is as follows:
49 U.S.C. 106(g), 40113, 44701, 44702, 44704.
Accordingly, the Federal Aviation Administration (FAA) proposes the following special conditions as part of the type certification basis for Airbus Model A350–900 series airplanes.
1. Lateral Trim Function through Differential Flap Setting.
Current airworthiness standards, specifically § 25.701, do not contain adequate safety standards for the proposed design. In lieu of the requirements of § 25.701(a) and (d) for the lateral trim function, the following special condition is proposed:
a. Airbus must demonstrate that an unsafe condition is not created by using the flaps asymmetrically,
b. The degree of acceptable asymmetry must be defined and justified for all flight phases with respect to:
• § 25.701(b) and (c), with the worst case asymmetric flap configurations, and
• providing equivalent protection against excess asymmetry in the same manner as § 25.701 provides to systems that are synchronized or use another equivalent means to prevent asymmetry.
c. This lateral trim function is a flight control system and therefore must show compliance to both general system requirements as well as general flight control requirements. Therefore, the function must be demonstrated not to embody, where practicable, significant latent failures.
Federal Aviation Administration (FAA), DOT.
Notice of proposed rulemaking (NPRM).
This action proposes to amend Class D and Class E airspace at Traverse City, MI. Additional controlled airspace is necessary to accommodate new Standard Instrument Approach Procedures (SIAP) at Cherry Capital Airport. Geographic coordinates of the airport also would be adjusted. The FAA is taking this action to enhance the safety and management of Instrument Flight Rules (IFR) operations for SIAPs at the airport.
Comments must be received on or before February 24, 2014.
Send comments on this proposal to the U.S. Department of Transportation, Docket Operations, 1200 New Jersey Avenue SE., West Building Ground Floor, Room W12–140, Washington, DC 20590–0001. You must identify the docket number FAA–2013–0175/Airspace Docket No. 13–AGL–12, at the beginning of your comments. You may also submit comments through the Internet at
Scott Enander, Central Service Center, Operations Support Group, Federal Aviation Administration, Southwest Region, 2601 Meacham Blvd., Fort Worth, TX 76137; telephone: (817) 321–7716.
Interested parties are invited to participate in this proposed rulemaking by submitting such written data, views, or arguments, as they may desire. Comments that provide the factual basis supporting the views and suggestions presented are particularly helpful in developing reasoned regulatory decisions on the proposal. Comments are specifically invited on the overall regulatory, aeronautical, economic, environmental, and energy-related aspects of the proposal. Communications should identify both docket numbers and be submitted in triplicate to the address listed above. Commenters wishing the FAA to acknowledge receipt of their comments on this notice must submit with those comments a self-addressed, stamped postcard on which the following statement is made: “Comments to Docket No. FAA–2013–0175/Airspace Docket No. 13–AGL–12.” The postcard will be date/time stamped and returned to the commenter.
An electronic copy of this document may be downloaded through the Internet at
You may review the public docket containing the proposal, any comments received and any final disposition in person in the Dockets Office (see
Persons interested in being placed on a mailing list for future NPRMs should contact the FAA's Office of Rulemaking (202) 267–9677, to request a copy of Advisory Circular No. 11–2A, Notice of Proposed Rulemaking Distribution System, which describes the application procedure.
This action proposes to amend Title 14, Code of Federal Regulations (14 CFR), part 71 by amending Class D airspace, Class E airspace designated as a surface area, and Class E airspace extending upward from 700 feet above the surface to accommodate new standard instrument approach
Class D and Class E airspace areas are published in Paragraphs 5000, 6002 and 6005, respectively, of FAA Order 7400.9X, dated August 7, 2013 and effective September 15, 2013, which is incorporated by reference in 14 CFR 71.1. The Class D and Class E airspace designations listed in this document will be published subsequently in the Order.
The FAA has determined that this proposed regulation only involves an established body of technical regulations for which frequent and routine amendments are necessary to keep them operationally current. It, therefore, (1) is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034; February 26, 1979); and (3) does not warrant preparation of a Regulatory Evaluation as the anticipated impact is so minimal. Since this is a routine matter that will only affect air traffic procedures and air navigation, it is certified that this rule, when promulgated, will not have a significant economic impact on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
The FAA's authority to issue rules regarding aviation safety is found in Title 49 of the U.S. Code. Subtitle 1, Section 106 describes the authority of the FAA Administrator. Subtitle VII, Aviation Programs, describes in more detail the scope of the agency's authority. This rulemaking is promulgated under the authority described in Subtitle VII, Part A, Subpart I, Section 40103. Under that section, the FAA is charged with prescribing regulations to assign the use of airspace necessary to ensure the safety of aircraft and the efficient use of airspace. This regulation is within the scope of that authority as it would amend controlled airspace at Cherry Capital Airport, Traverse City, MI.
This proposal will be subject to an environmental analysis in accordance with FAA Order 1050.1E, “Environmental Impacts: Policies and Procedures” prior to any FAA final regulatory action.
Airspace, Incorporation by reference, Navigation (air).
In consideration of the foregoing, the Federal Aviation Administration proposes to amend 14 CFR part 71 as follows:
49 U.S.C. 106(g); 40103, 40113, 40120; E.O. 10854, 24 FR 9565, 3 CFR, 1959–1963 Comp., p. 389.
Within a 4.4-mile radius of Cherry Capital Airport, and within 1 mile each side of the 180° bearing from the airport extending from the 4.4-mile radius to 5.3 miles south of the airport. This Class E airspace area is effective during the specific dates and times established in advance by a Notice to Airmen. The effective date and time will thereafter be continuously published in the Airport/Facility Directory.
Federal Aviation Administration (FAA), DOT.
Notice of proposed rulemaking (NPRM).
This action proposes to amend Class E airspace at Jefferson City, MO. Decommissioning of the Noah non-directional radio beacon (NDB) at Jefferson City Memorial Airport has made reconfiguration necessary for standard instrument approach procedures and for the safety and management of Instrument Flight Rules (IFR) operations at the airport.
0901 UTC. Comments must be received on or before February 24, 2014.
Send comments on this proposal to the U.S. Department of Transportation, Docket Operations, 1200 New Jersey Avenue SE., West Building Ground Floor, Room W12–140, Washington, DC 20590–0001. You must identify the docket number FAA–2013–0587/Airspace Docket No. 13–ACE–8, at
Scott Enander, Central Service Center, Operations Support Group, Federal Aviation Administration, Southwest Region, 2601 Meacham Blvd., Fort Worth, TX 76137; telephone: (817) 321–7716.
Interested parties are invited to participate in this proposed rulemaking by submitting such written data, views, or arguments, as they may desire. Comments that provide the factual basis supporting the views and suggestions presented are particularly helpful in developing reasoned regulatory decisions on the proposal. Comments are specifically invited on the overall regulatory, aeronautical, economic, environmental, and energy-related aspects of the proposal. Communications should identify both docket numbers and be submitted in triplicate to the address listed above. Commenters wishing the FAA to acknowledge receipt of their comments on this notice must submit with those comments a self-addressed, stamped postcard on which the following statement is made: “Comments to Docket No. FAA–2013–0587/Airspace Docket No. 13–ACE–8.” The postcard will be date/time stamped and returned to the commenter.
An electronic copy of this document may be downloaded through the Internet at
You may review the public docket containing the proposal, any comments received and any final disposition in person in the Dockets Office (see
Persons interested in being placed on a mailing list for future NPRMs should contact the FAA's Office of Rulemaking (202) 267–9677, to request a copy of Advisory Circular No. 11–2A, Notice of Proposed Rulemaking Distribution System, which describes the application procedure.
This action proposes to amend Title 14, Code of Federal Regulations (14 CFR), Part 71 by modifying Class E airspace extending upward from 700 feet above the surface for standard instrument approach procedures at Jefferson City Memorial Airport, Jefferson City, MO. Airspace reconfiguration is necessary due to the decommissioning of the Noah NDB and the cancellation of the NDB approach. The segment northwest of the airport would now be within 3.2 miles each side of the 303° bearing from the airport extending from the 6.6-mile radius to 14.3 miles. Controlled airspace is necessary for the safety and management of IFR operations at the airport.
Class E airspace areas are published in Paragraph 6005 of FAA Order 7400.9X, dated August 7, 2013 and effective September 15, 2013, which is incorporated by reference in 14 CFR 71.1. The Class E airspace designation listed in this document would be published subsequently in the Order.
The FAA has determined that this proposed regulation only involves an established body of technical regulations for which frequent and routine amendments are necessary to keep them operationally current. It, therefore, (1) is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034; February 26, 1979); and (3) does not warrant preparation of a Regulatory Evaluation as the anticipated impact is so minimal. Since this is a routine matter that will only affect air traffic procedures and air navigation, it is certified that this rule, when promulgated, will not have a significant economic impact on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
The FAA's authority to issue rules regarding aviation safety is found in Title 49 of the U.S. Code. Subtitle 1, Section 106 describes the authority of the FAA Administrator. Subtitle VII, Aviation Programs, describes in more detail the scope of the agency's authority. This rulemaking is promulgated under the authority described in Subtitle VII, Part A, Subpart I, Section 40103. Under that section, the FAA is charged with prescribing regulations to assign the use of airspace necessary to ensure the safety of aircraft and the efficient use of airspace. This regulation is within the scope of that authority as it would amend controlled airspace at Jefferson City Memorial Airport, Jefferson City, MO.
This proposal will be subject to an environmental analysis in accordance with FAA Order 1050.1E, “Environmental Impacts: Policies and Procedures” prior to any FAA final regulatory action.
Airspace, Incorporation by reference, Navigation (air).
In consideration of the foregoing, the Federal Aviation Administration proposes to amend 14 CFR part 71 as follows:
49 U.S.C. 106(g); 40103, 40113, 40120; E.O. 10854, 24 FR 9565, 3 CFR, 1959–1963 Comp., p. 389.
That airspace extending upward from 700 feet above the surface within a 6.6-mile radius of Jefferson City Memorial Airport, and within 3.2 miles each side of the 303° bearing from the airport extending from the 6.6-mile radius to 14.3 miles northwest of the airport, and within 4 miles each side of the Jefferson City Memorial Airport ILS localizer course extending from the 6.6-mile radius to 11.8 miles southeast of the airport.
Federal Aviation Administration (FAA), DOT.
Notice of proposed rulemaking (NPRM).
This action proposes to amend Class E airspace at Paragould, AR. Decommissioning of the Paragould non-directional radio beacon (NDB) at Kirk Field has made reconfiguration necessary for standard instrument approach procedures and for the safety and management of Instrument Flight Rules (IFR) operations at the airport. Geographic coordinates also would be updated.
0901 UTC. Comments must be received on or before February 24, 2014.
Send comments on this proposal to the U.S. Department of Transportation, Docket Operations, 1200 New Jersey Avenue SE., West Building Ground Floor, Room W12–140, Washington, DC 20590–0001. You must identify the docket number FAA–2013–0588/Airspace Docket No. 13–ASW–12, at the beginning of your comments. You may also submit comments through the Internet at
Scott Enander, Central Service Center, Operations Support Group, Federal Aviation Administration, Southwest Region, 2601 Meacham Blvd., Fort Worth, TX 76137; telephone: (817) 321–7716.
Interested parties are invited to participate in this proposed rulemaking by submitting such written data, views, or arguments, as they may desire. Comments that provide the factual basis supporting the views and suggestions presented are particularly helpful in developing reasoned regulatory decisions on the proposal. Comments are specifically invited on the overall regulatory, aeronautical, economic, environmental, and energy-related aspects of the proposal. Communications should identify both docket numbers and be submitted in triplicate to the address listed above. Commenters wishing the FAA to acknowledge receipt of their comments on this notice must submit with those comments a self-addressed, stamped postcard on which the following statement is made: “Comments to Docket No. FAA–2013–0588/Airspace Docket No. 13–ASW–12.” The postcard will be date/time stamped and returned to the commenter.
An electronic copy of this document may be downloaded through the Internet at
You may review the public docket containing the proposal, any comments received and any final disposition in person in the Dockets Office (see
Persons interested in being placed on a mailing list for future NPRMs should contact the FAA's Office of Rulemaking (202) 267–9677, to request a copy of Advisory Circular No. 11–2A, Notice of Proposed Rulemaking Distribution System, which describes the application procedure.
This action proposes to amend Title 14, Code of Federal Regulations (14 CFR), Part 71 by modifying Class E airspace extending upward from 700 feet above the surface for standard instrument approach procedures at Kirk Field, Paragould, AR. Airspace reconfiguration is necessary due to the decommissioning of the Paragould NDB and the cancellation of the NDB approach. The segment northeast of the airport would now be within 2.5 miles each side of the 062° bearing from the airport. Controlled airspace is necessary for the safety and management of IFR operations at the airport. Geographic coordinates would also be adjusted to coincide with the FAA's aeronautical database.
Class E airspace areas are published in Paragraph 6005 of FAA Order 7400.9X, dated August 7, 2013 and effective September 15, 2013, which is incorporated by reference in 14 CFR 71.1. The Class E airspace designation listed in this document would be published subsequently in the Order.
The FAA has determined that this proposed regulation only involves an established body of technical regulations for which frequent and routine amendments are necessary to keep them operationally current. It, therefore, (1) is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034; February 26, 1979); and (3) does not warrant preparation of a Regulatory Evaluation as the anticipated impact is so minimal. Since this is a routine matter that will only affect air traffic procedures and air navigation, it is certified that this rule, when promulgated, will not have a significant economic impact on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
The FAA's authority to issue rules regarding aviation safety is found in Title 49 of the U.S. Code. Subtitle 1, Section 106 describes the authority of the FAA Administrator. Subtitle VII, Aviation Programs, describes in more detail the scope of the agency's authority. This rulemaking is promulgated under the authority described in Subtitle VII, Part A, Subpart I, Section 40103. Under that section, the FAA is charged with prescribing regulations to assign the use of airspace necessary to ensure the safety of aircraft and the efficient use of airspace. This regulation is within the scope of that authority as it would amend controlled airspace at Kirk Field, Paragould, AR.
This proposal will be subject to an environmental analysis in accordance with FAA Order 1050.1E, “Environmental Impacts: Policies and Procedures” prior to any FAA final regulatory action.
Airspace, Incorporation by reference, Navigation (air).
In consideration of the foregoing, the Federal Aviation Administration proposes to amend 14 CFR part 71 as follows:
49 U.S.C. 106(g); 40103, 40113, 40120; E.O. 10854, 24 FR 9565, 3 CFR, 1959–1963 Comp., p. 389.
That airspace extending upward from 700 feet above the surface within a 6.4-mile radius of Kirk Field, and within 2.5 miles each side of the 218° bearing from the airport extending from the 6.4-mile radius to 9.5 miles southwest of the airport, and within 2.5 miles each side of the 062° bearing from the airport extending from the 6.4-mile radius to 7.5 miles northeast of the airport.
Federal Aviation Administration (FAA), DOT.
Notice of proposed rulemaking (NPRM).
This action proposes to amend Class E airspace at Holdrege, NE. Decommissioning of the Holdrege non-directional radio beacon (NDB) at Brewster Field Airport has made airspace reconfiguration necessary for standard instrument approach procedures and for the safety and management of Instrument Flight Rules (IFR) operations at the airport. Geographic coordinates also would be adjusted.
0901 UTC. Comments must be received on or before February 24, 2014.
Send comments on this proposal to the U.S. Department of Transportation, Docket Operations, 1200 New Jersey Avenue SE., West Building Ground Floor, Room W12–140, Washington, DC 20590–0001. You must identify the docket number FAA–2013–0596/Airspace Docket No. 13–ACE–11, at the beginning of your comments. You may also submit comments through the Internet at
Scott Enander, Central Service Center, Operations Support Group, Federal Aviation Administration, Southwest Region, 2601 Meacham Blvd., Fort Worth, TX 76137; telephone: (817) 321–7716.
Interested parties are invited to participate in this proposed rulemaking by submitting such written data, views, or arguments, as they may desire. Comments that provide the factual basis supporting the views and suggestions presented are particularly helpful in developing reasoned regulatory decisions on the proposal. Comments are specifically invited on the overall regulatory, aeronautical, economic, environmental, and energy-related aspects of the proposal. Communications should identify both docket numbers and be submitted in triplicate to the address listed above. Commenters wishing the FAA to acknowledge receipt of their comments on this notice must submit with those comments a self-addressed, stamped postcard on which the following statement is made: “Comments to Docket No. FAA–2013–0596/Airspace Docket No. 13–ACE–11.” The postcard will be date/time stamped and returned to the commenter.
An electronic copy of this document may be downloaded through the Internet at
You may review the public docket containing the proposal, any comments received and any final disposition in person in the Dockets Office (see
Persons interested in being placed on a mailing list for future NPRMs should contact the FAA's Office of Rulemaking (202) 267–9677, to request a copy of Advisory Circular No. 11–2A, Notice of Proposed Rulemaking Distribution System, which describes the application procedure.
This action proposes to amend Title 14, Code of Federal Regulations (14 CFR), Part 71 by modifying Class E airspace extending upward from 700 feet above the surface at Brewster Field Airport, Holdrege, NE., for standard instrument approach procedures at the airport. Airspace reconfiguration is necessary due to the decommissioning of the Holdrege NDB and the cancellation of the NDB approach, thereby removing the 7-mile segment extending from the 6.6-mile radius of the airport. Controlled airspace is necessary for the safety and management of IFR operations at the airport. Geographic coordinates would also be adjusted to coincide with the FAA's aeronautical database.
Class E airspace areas are published in Paragraph 6005 of FAA Order 7400.9X, dated August 7, 2013 and effective September 15, 2013, which is incorporated by reference in 14 CFR 71.1. The Class E airspace designation listed in this document would be published subsequently in the Order.
The FAA has determined that this proposed regulation only involves an established body of technical regulations for which frequent and routine amendments are necessary to keep them operationally current. It, therefore, (1) is not a “significant
The FAA's authority to issue rules regarding aviation safety is found in Title 49 of the U.S. Code. Subtitle 1, Section 106 describes the authority of the FAA Administrator. Subtitle VII, Aviation Programs, describes in more detail the scope of the agency's authority. This rulemaking is promulgated under the authority described in Subtitle VII, Part A, Subpart I, Section 40103. Under that section, the FAA is charged with prescribing regulations to assign the use of airspace necessary to ensure the safety of aircraft and the efficient use of airspace. This regulation is within the scope of that authority as it would amend controlled airspace at Brewster Field Airport, Holdrege, NE.
This proposal will be subject to an environmental analysis in accordance with FAA Order 1050.1E, “Environmental Impacts: Policies and Procedures” prior to any FAA final regulatory action.
Airspace, Incorporation by reference, Navigation (air).
In consideration of the foregoing, the Federal Aviation Administration proposes to amend 14 CFR part 71 as follows:
The authority citation for part 71 continues to read as follows:
49 U.S.C. 106(g); 40103, 40113, 40120; E.O. 10854, 24 FR 9565, 3 CFR, 1959–1963 Comp., p. 389.
The incorporation by reference in 14 CFR 71.1 of FAA Order 7400.9X, Airspace Designations and Reporting Points, dated August 7, 2013, and effective September 15, 2013, is amended as follows:
That airspace extending upward from 700 feet above the surface within a 6.6-mile radius of Brewster Field Airport, and within 2.6 miles each side of the Kearney VOR 222° radial extending from the 6.6-mile radius to 11 miles northeast of the airport.
Federal Aviation Administration (FAA), DOT.
Notice of proposed rulemaking (NPRM).
This action proposes to establish Class E airspace at Warsaw, MO. Controlled airspace is necessary to accommodate new Standard Instrument Approach Procedures (SIAP) at Warsaw Municipal Airport. The FAA is taking this action to enhance the safety and management of Instrument Flight Rules (IFR) operations for SIAPs at the airport.
Comments must be received on or before February 24, 2014.
Send comments on this proposal to the U.S. Department of Transportation, Docket Operations, 1200 New Jersey Avenue SE., West Building Ground Floor, Room W12–140, Washington, DC 20590–0001. You must identify the docket number FAA–2013–0606/Airspace Docket No. 13–ACE–12, at the beginning of your comments. You may also submit comments through the Internet at
Scott Enander, Central Service Center, Operations Support Group, Federal Aviation Administration, Southwest Region, 2601 Meacham Blvd., Fort Worth, TX 76137; telephone: (817) 321–7716.
Interested parties are invited to participate in this proposed rulemaking by submitting such written data, views, or arguments, as they may desire. Comments that provide the factual basis supporting the views and suggestions presented are particularly helpful in developing reasoned regulatory decisions on the proposal. Comments are specifically invited on the overall regulatory, aeronautical, economic, environmental, and energy-related aspects of the proposal. Communications should identify both docket numbers and be submitted in triplicate to the address listed above. Commenters wishing the FAA to acknowledge receipt of their comments on this notice must submit with those comments a self-addressed, stamped postcard on which the following statement is made: “Comments to Docket No. FAA–2013–0606/Airspace Docket No. 13–ACE–12.” The postcard will be date/time stamped and returned to the commenter.
An electronic copy of this document may be downloaded through the Internet at
You may review the public docket containing the proposal, any comments received and any final disposition in person in the Dockets Office (see
Persons interested in being placed on a mailing list for future NPRMs should contact the FAA's Office of Rulemaking
This action proposes to amend Title 14, Code of Federal Regulations (14 CFR), Part 71 by establishing Class E airspace extending upward from 700 feet above the surface within a 6.3-mile radius to accommodate new standard instrument approach procedures at Warsaw Municipal Airport, Warsaw, MO. Controlled airspace is needed for the safety and management of IFR operations at the airport.
Class E airspace areas are published in Paragraph 6005 of FAA Order 7400.9X, dated August 7, 2013 and effective September 15, 2013, which is incorporated by reference in 14 CFR 71.1. The Class E airspace designation listed in this document would be published subsequently in the Order.
The FAA has determined that this proposed regulation only involves an established body of technical regulations for which frequent and routine amendments are necessary to keep them operationally current. It, therefore, (1) is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034; February 26, 1979); and (3) does not warrant preparation of a Regulatory Evaluation as the anticipated impact is so minimal. Since this is a routine matter that will only affect air traffic procedures and air navigation, it is certified that this rule, when promulgated, will not have a significant economic impact on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
The FAA's authority to issue rules regarding aviation safety is found in Title 49 of the U.S. Code. Subtitle 1, Section 106 describes the authority of the FAA Administrator. Subtitle VII, Aviation Programs, describes in more detail the scope of the agency's authority. This rulemaking is promulgated under the authority described in Subtitle VII, Part A, Subpart I, Section 40103. Under that section, the FAA is charged with prescribing regulations to assign the use of airspace necessary to ensure the safety of aircraft and the efficient use of airspace. This regulation is within the scope of that authority as it would establish controlled airspace at Warsaw Municipal Airport, Warsaw, MO.
This proposal will be subject to an environmental analysis in accordance with FAA Order 1050.1E, “Environmental Impacts: Policies and Procedures” prior to any FAA final regulatory action.
Airspace, Incorporation by reference, Navigation (air).
In consideration of the foregoing, the Federal Aviation Administration proposes to amend 14 CFR part 71 as follows:
49 U.S.C. 106(g); 40103, 40113, 40120; E.O. 10854, 24 FR 9565, 3 CFR, 1959–1963 Comp., p. 389.
That airspace extending upward from 700 feet above the surface within a 6.3-mile radius of Warsaw Municipal Airport
Commodity Futures Trading Commission.
Request for comment.
The Commodity Futures Trading Commission (“Commission”) is requesting comment on an advisory issued by Commission staff on November 14, 2013 (the “Staff Advisory”), regarding the applicability of certain Commission regulations to the activity in the United States of swap dealers (“SDs”) and major swap participants (“MSPs”) registered with the Commission that are established in jurisdictions other than the United States (whether an affiliate or not of a U.S. person, a “non-U.S. SD” or “non-U.S. MSP”).
Comments must be received on or before March 10, 2014.
You may submit comments by any of the following methods:
• The agency's Web site, at
•
•
•
Please submit your comments using only one method.
All comments must be submitted in English, or if not, accompanied by an English translation. Comments may be posted as received to
The Commission reserves the right, but shall have no obligation, to review,
Gary Barnett, Director, 202–418–5977,
On July 21, 2010, President Obama signed the Dodd-Frank Wall Street Reform and Consumer Protection Act
In the three years since the enactment of Dodd-Frank, the Commission has finalized 68 rules, orders, and guidance statements in the process of implementing Title VII of the Dodd-Frank Act. The finalized rules promulgated under section 4s of the CEA, added by the Dodd-Frank Act, address registration of SDs and MSPs and other substantive requirements applicable to SDs and MSPs, while guidance published by the Commission provided the Commission's general views regarding the scope of the cross-border application of such rules.
With few exceptions, the delayed compliance dates for the Commission's regulations implementing requirements of section 4s of the CEA have passed and SDs and MSPs are now required to be in full compliance with such regulations upon registration with the Commission.
Subsequent to publication of the Guidance, swap market participants have raised questions with Commission staff regarding compliance by non-U.S. SDs with the transactional requirements when using personnel or agents located in the United States to enter into swaps with non-U.S. persons. In other words, swap market participants have asked whether the transactional requirements would apply to these swaps (and if so, whether substituted compliance may be available for these swaps) even though such swaps are between two non-U.S. persons, regardless of whether the activities of the non-U.S. SD that lead to such swaps take place in the United States.
In response to these inquires, the Staff Advisory
The Commission notes that subsequent to the Staff Advisory, the Commission's Divisions of Swap Dealer and Intermediary Oversight, Market Oversight, and Clearing and Risk provided non-U.S. SDs time-limited staff no-action relief from certain transactional requirements for Covered Transactions,
In view of the complex legal and policy issues involved with respect to the Staff Advisory, the Commission is soliciting comment from all interested parties to further inform the Commission's and its staff's deliberations regarding the subjects addressed in the Staff Advisory.
Accordingly, the Commission requests comment on all aspects of the Staff Advisory, including but not limited to the following points. If a comment relates to one of the specific points noted below, please identify the point by number and provide a detailed rationale supporting the response.
1. The Commission invites comment on whether the Commission should adopt the Staff Advisory as Commission policy, in whole or in part.
2. The Commission invites commenters to provide their views on whether transactional requirements should apply to Covered Transactions with non-U.S. persons who are not guaranteed or conduit affiliates of U.S. persons. Please provide a detailed analysis of any such view and its effect on other aspects of the Commission's cross-border policy, if any.
3. The Commission invites comment on whether there should be any differentiation in treatment of swaps with non-U.S. counterparties depending on the nature of the SD (i.e., whether it is a guaranteed affiliate or a conduit affiliate of a U.S. person).
4. To the extent a non-U.S. SD must comply with the transactional requirements when entering a Covered Transaction, should the non-U.S. SD be able to rely on a substituted compliance program for purposes of complying with the relevant transactional requirements? If so, should substituted compliance be available for all transactional requirements or only specific requirements? Which requirements? Would the response be different depending on the nature of the counterparty (i.e., whether the non-U.S. counterparty is a guaranteed affiliate or a conduit affiliate of a U.S. person)?
5. The Commission invites comment on the meaning of “regularly” in the phrase “persons regularly arranging, negotiating, or executing swaps for or on behalf of an SD” and whether such persons are performing core, front-office activities of that SD's swap dealing business. If not, what specific activities would constitute the core, front-office activities of an SD's swap dealing business? What characteristics or factors distinguish a “core, front-office” activity from other activities? Please be exhaustive in describing such activities.
6. The Commission invites comment on the scope and degree of “arranging, negotiating, or executing” swaps as used in this context.
On this matter, Chairman Gensler and Commissioners Chilton and Wetjen voted in the affirmative. Commissioner O'Malia voted in the negative.
If you thought that the Commission's approach last year regarding cross-border issues resulted in an unsound rulemaking process, the start of 2014 is no better.
Today's announcement of the request for comment on a staff Advisory abrogates the Commission's fundamental legal obligations under the Administrative Procedure Act (“APA”) and provides another example of the Commission's unsound rule implementation process.
Making matters worse, today's request for comment is completely outside the scope of the cross-border Guidance and the Exemptive Order as the Commission did not address the issue relating to swaps negotiated between non-U.S. swap dealers (“SDs”) and non-U.S. counterparties acting through agents of the non-U.S. SDs located in the United States. This is simply a strategic move by the Commission to try to duck blame for consistently circumventing the fundamental tenets of the APA and failing to adhere faithfully to the express congressional directive to limit the extraterritorial application of the Dodd-Frank Act to foreign transactions that “have a direct and significant connection with activities in, or effect on, commerce of the United States.”
Moreover, I question why the Commission has decided to request comment on a narrow issue of the extraterritorial application of Dodd-Frank, while essentially ignoring the dozens of comments already filed as part of the Commission's cross-border Exemptive Order.
Additionally, I have serious concerns with the evolving jurisdictional application of the Commission's authority over cross-border trades. It appears based on the staff Advisory, that the Commission is applying a “territorial” jurisdiction test to elements of a trade between non-U.S. entities. To better understand the legal underpinnings of this position, I have included several additional questions to be considered as part of the overall comment file. It is my hope that public comments will provide greater clarity regarding our cross-border authority and identify areas where we must harmonize global rules with our international regulatory partners in the near future. It makes no sense to apply guidance or staff advisories that do not enjoy the full support and authority provided through rulemakings based on the Commodity Exchange Act (“CEA”).
Looking forward into this year, the CFTC needs to do away with the reflexive rule implementation process via staff no-action and advisories that are not voted on by the Commission. It should be the goal of the Commission to develop rules that adhere to the APA and ensure proper regulatory oversight, transparency and promote competition in the derivatives space.
In this regard, I would like to seek additional comment on the following points:
1. Please provide your views on whether Covered Transactions with non-U.S. persons who are not guaranteed or conduit affiliates of U.S. persons meet the direct and significant test under CEA section 2(i).
2. CEA section 2(a)(1)
3. To the extent that Covered Transactions fall within the Commission's jurisdiction, should a non-U.S. SD be required to comply with all, or only certain, Transaction-Level Requirements? Please provide a detailed analysis of any such view and its effect on other aspects of the Commission's cross-border policy, if any. Would your view change depending on the nature of the non-U.S. SD (i.e., whether it is a guaranteed affiliate or a conduit affiliate of a U.S. person)?
4. In the open meeting to consider the cross-border final guidance and cross-border phase-in exemptive order, I asked about the Commission's enforcement and legal authority under the cross-border guidance. The Commission's General Counsel replied, “[T]he guidance itself is not binding strictly. We couldn't go into court and, in a count of the complaint, list a violation of the guidance as an actionable claim.”
Environmental Protection Agency (EPA).
Withdrawal of proposed rule.
On September 10, 2013, the Environmental Protection Agency (EPA)
The proposed rule published on September 10, 2013 (78 FR 55234), is withdrawn as of January 8, 2014.
Ms. Adina Wiley (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) 665–2115. Ms. Wiley can also be reached via electronic mail at
Environmental protection, Air pollution control, Incorporation by reference, Intergovernmental relations, Reporting and recordkeeping requirements.
Environmental Protection Agency (EPA).
Proposed rule.
EPA is proposing to approve a State Implementation Plan (SIP) revision submitted by the State of Missouri to EPA on September 21, 2010, with a supplemental revision submitted on July 3, 2013. The purpose of the SIP revision is to incorporate revisions to a Missouri regulation to control Nitrogen Oxide (NO
Comments must be received on or before February 7, 2014.
Submit your comments identified by Docket ID No. EPA–R07–OAR–2013–0674, by one of the following methods:
1.
2.
3.
4.
Ms. Lachala Kemp, Air Planning and Development Branch U.S. Environmental Protection Agency, Region 7, 11201 Renner Boulevard, Lenexa, KS 66219;
Throughout this document, “we,” “us,” or “our” refer to EPA. This section provides additional information by addressing the following questions:
EPA is proposing to approve a State Implementation Plan (SIP) revision submitted by the State of Missouri to EPA on September 21, 2010, with a supplemental revision submitted on July 3, 2013. The purpose of the SIP revision is to incorporate changes to a Missouri regulation (Title 10 of the Code of State Regulations (CSR) 10–6.390) to control Nitrogen Oxide (NO
Missouri's rule establishes emissions levels for large stationary internal combustion engines of greater than one thousand three hundred horsepower located in the counties of Bollinger, Butler, Cape Girardeau, Carter, Clark, Crawford, Dent, Dunklin, Franklin, Gasconade, Iron, Jefferson, Lewis, Lincoln, Madison, Marion, Mississippi, Montgomery, New Madrid, Oregon, Pemiscot, Perry, Pike, Ralls, Reynolds, Ripley, St. Charles, St. Francois, St. Louis, Ste. Genevieve, Scott, Shannon, Stoddard, Warren, Washington, and Wayne counties, and the City of St. Louis in Missouri. To be subject to this rule, the IC engines must either have emitted greater than one ton per day of NO
EPA's analysis of the State's SIP revision is discussed below. As a result of EPA's analysis, we are proposing to approve this request to revise Missouri's SIP and include this 2010 amendment to the Missouri rule.
The Missouri rule establishes emission rate limits using current reporting requirements for both large stationary diesel engines and dual fuel IC engines and adds a twenty five ton NO
Any compression ignited stationary engine that begins operation after September 30, 1997, and emits twenty-five (25) tons or less of NO
Section 110(l) of the CAA states that EPA shall not approve a revision of a SIP if the revisions would interfere with any applicable requirement concerning attainment and reasonable further progress, or any other applicable requirement of the CAA. The State's SIP revision included a demonstration that this twenty-five ton NO
In this analysis, the State focuses on the eastern one-third of Missouri, which is defined by the Phase II NO
In addition, the State's analysis also demonstrates that for each year since EPA approved its NO
In summary, EPA has reviewed the State's analysis and believes that the twenty-five ton NO
In today's rulemaking, EPA is proposing to approve a revision to the Missouri SIP to control NO
Under the CAA, the Administrator is required to approve a SIP submission that complies with the provisions of the Act and applicable Federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in reviewing SIP submissions, EPA's role is to approve state choices, provided that they meet the criteria of the Clean Air Act. Accordingly, this proposed 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 proposed action:
• Is not a “significant regulatory action” subject to review by the Office of Management and Budget under Executive Order 12866 (58 FR 51735, October 4, 1993);
• Does not impose an information collection burden under the provisions of the Paperwork Reduction Act (44 U.S.C. 3501
• Is certified as not having a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601
• Does not contain any unfunded mandate or significantly or uniquely affect small governments, as described in the Unfunded Mandates Reform Act of 1995 (Pub. L. 104–4);
• Does not have Federalism implications as specified in Executive Order 13132 (64 FR 43255, August 10, 1999);
• Is not an economically significant regulatory action based on health or safety risks subject to Executive Order 13045 (62 FR 19885, April 23, 1997);
• Is not a significant regulatory action subject to Executive Order 13211 (66 FR 28355, May 22, 2001);
• Is not subject to requirements of Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) because application of those requirements would be inconsistent with the CAA; and
• Does not provide 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).
In addition, this rule 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.
Environmental protection, Air pollution control, Incorporation by reference, Intergovernmental relations, Nitrogen oxides, Reporting and recordkeeping requirements.
Environmental Protection Agency (EPA).
Withdrawal of proposed rule.
The United States EPA (EPA) is withdrawing the proposal for new source performance standards for emissions of carbon dioxide (CO
The proposed rule published on April 13, 2012 (78 FR 22392), is withdrawn as of January 8, 2014.
In addition to being available in the docket, an electronic copy of this action will also be available on the Worldwide Web (WWW) through the Technology Transfer Network (TTN). Following signature, a copy of the action will be posted on the TTN's policy and guidance page for newly proposed or promulgated rules at the following address:
Mr. Christian Fellner, Energy Strategies Group, Sector Policies and Programs Division (D243–01), U.S. EPA, Research Triangle Park, NC 27711; telephone number (919) 541–4003, facsimile number (919) 541–5450; email address:
In 2009, the EPA issued a finding that greenhouse gas (GHG) air pollution may reasonably be anticipated to endanger Americans' public health and welfare, now and in the future, by contributing to climate change. In the notice of proposed rulemaking that was published on April 13, 2012 (April 2012 document), the EPA proposed to limit
The April 2012 document proposed federal standards of performance for new fossil fuel-fired power plants that the EPA concluded could be met with existing technology. Specifically, the EPA proposed a single electricity-output-based emission standard of 1,000 pounds of CO
In addition, the EPA identified as “transitional” sources certain coal-fired power plants that had received approval of their PSD preconstruction permits as of the date of the April 2012 proposal (or that had approved PSD permits that expired and were in the process of being extended, if they were participating in a Department of Energy CCS funding program), and that commenced construction within one year of the date of the April proposal. For those sources, the EPA did not propose a standard of performance.
The EPA also stated that it was not proposing standards of performance for simple cycle combustion turbines or for non-continental sources (i.e., those in Hawaii or the U.S. territories).
In a separate notice of proposed rulemaking published in today's
In response to the proposed rule, the EPA received over 2.5 million public comments on all aspects of its proposal. Many commenters were supportive of the Agency's proposed actions, other commenters opposed the proposed actions, and many commenters provided new information and/or recommended significant changes in the EPA's proposed requirements. In addition, the EPA has obtained and analyzed new information that significantly alters its views on important assumptions and which counsel for major changes in some of the requirements proposed in the April 2012 document.
We fully describe the actions we are proposing to take in response to the comments received and the results of our analyses of new information in a notice of proposed rulemaking published elsewhere in today's
Changes to the proposed rule's applicability will impact which sources are potentially covered. By changing the proposed rule's applicability, projects based on NGCC technology that are intended to, and that do, generate less than one-third of their potential electric output on a three year rolling average, which would have been covered by the original proposal, are not covered by today's proposal. Such projects could be beneficial because they are likely to be more efficient and lower emitting and could potentially cost less than natural gas-fired simple cycle combustion turbines in some instances. If we did not withdraw the original proposal, developers might not consider this technology because they may perceive a greater risk that we would finalize the applicability requirements of the original proposal. This could have the unintended effect of potentially stifling development of NGCC technology that can be used to meet peak energy demand.
The Agency is also proposing significant substantive changes from the original proposal in today's new proposal with respect to the standards themselves.
In the April 2012 proposal, although the EPA acknowledged the possibility of a very small amount of construction of new coal-fired generating capacity, the EPA relied primarily on several modeling analyses, including analyses using the EPA's Integrated Planning Model (IPM), which projected that there would be no construction of new coal-fired generation through the year 2030 without CCS even assuming the potential for higher future electric demand or with higher future natural gas prices. Comments received, along with new information, have brought more clearly into focus the possibility that, in fact, there could well be limited new coal-fired generating capacity being constructed within the planning timeframe covered by the proposed rule. This new capacity could be in response to the need for companies to establish or maintain fuel diversity in their generation portfolios or the ability of some companies to combine coal-fired generation of electricity with the profitable sale of by-products from gasification or combustion of coal. As a result, even though our baseline analysis does not project any new coal that would not meet the originally proposed standard, the EPA believes it is appropriate to develop separate standards for coal-fired capacity, which, as it turns out, differ from those for new natural gas-fired EGUs.
The April 2012 proposal set a single standard of performance for all affected fossil fuel-fired EGUs, regardless of generation technology or fuel, based on our proposed findings that the best system of emission reduction adequately demonstrated (BSER) for fossil fuel-fired units is natural gas combined cycle technology. Thus, in the April 2012 proposal, we did not propose a separate BSER for coal- and other solid fossil fuel-fired EGUs, although we identified carbon capture and storage (or sequestration) (CCS) technology as a compliance alternative for those EGUs and we proposed a 30-year averaging compliance option for those EGUs that implemented CCS.
We received significant public comments on this approach. Our evaluation of those comments has led us to modify significantly our conclusions regarding the BSER and the resulting emission limitations for fossil fuel-fired sources, and we no longer consider it appropriate to propose a single standard for all such units.
Instead, we are proposing separate emission standards based on separate BSER determinations for (i) fossil fuel-fired utility boilers and IGCC units and (ii) natural gas-fired stationary combustion turbines. For fossil fuel-fired utility boilers and IGCC units, we are proposing partial-capture CCS as the BSER. Additionally, we now believe that a shorter compliance averaging option than the 30-year scheme proposed in the April 2012 notice may be more appropriate.
These changes are significant. Moreover, they affect at least one unit in advanced stages of project development. As a result, the EPA believes it is important to withdraw the original document, in part to make it clear to the developer of this project—and any other projects in development—that their new source performance standards will be based on a BSER determination that is more closely aligned with technology appropriate to those projects.
As noted, in the new action, the EPA is proposing separate emission standards for fossil fuel-fired utility boilers and IGCC units and for natural gas-fired stationary combustion turbines. In the new proposal, the EPA also is proposing separate emission standards for smaller natural gas-fired stationary combustion turbines and for larger natural gas-fired stationary combustion turbines. This differentiation may be significant to projects under development.
We received numerous comments objecting to our proposed treatment of transitional sources. In light of many of those comments and additional information we have obtained, we have reassessed this issue and are revisiting our proposed treatment of these types of units.
When EPA finalizes CO
The April 2012 document provided estimated air and energy impacts, as well as projected compliance costs, economic and employment impacts, and benefits associated with the proposed rule. This action withdraws the April 2012 proposal, and thus any projected impacts associated with it are being replaced with the results of a new assessment accompanying the notice of proposed rulemaking published elsewhere in today's
Pursuant to CAA section 307(d)(1)(V), the Administrator is determining that this action is subject to the provisions of CAA section 307(d). The statutory authority for this action is provided by sections 111, 301 and 307(d) of the CAA as amended (42 U.S.C. 7411, 7601 and 7607(d)).
Environmental protection, Administrative practice and procedure, Air pollution control.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Proposed rule; proposed specifications; request for comments.
NMFS seeks public comment on two proposed actions. First, NMFS proposes to establish a management framework for specifying catch and fishing effort limits and accountability measures for pelagic fisheries in the U.S. Pacific territories (American Samoa, Guam, and the Northern Mariana Islands). The framework would authorize the government of each territory to allocate a portion of its catch or fishing effort limit to a U.S. fishing vessel or vessels through a specified fishing agreement, and establish the criteria that an agreement would need to satisfy. The proposed framework also includes accountability measures for adhering to catch and fishing effort limits to ensure sustainability.
Second, NMFS proposes an annual limit of 2,000 metric tons (mt) of longline-caught bigeye tuna for each territory, using the framework described in the proposed rule. NMFS would allow a territory to allocate up to 1,000 mt of the 2,000 mt each year to a U.S. longline fishing vessel or vessels in a specified fishing agreement that meets the established criteria. NMFS would monitor, attribute, and restrict catches of longline-caught bigeye tuna, including catches made under a specified fishing agreement, using the procedures and accountability measures described in the proposed rule. The longline bigeye tuna catch limit specifications would be effective in 2014.
NMFS also proposes to make technical administrative changes to certain international fisheries requirements under the Western and Central Pacific Fisheries Convention Implementation Act, to make them consistent with this proposed rule.
NMFS intends the proposed rule and specifications to implement Section 113 of the Consolidated and Further
In order to be considered, NMFS must receive any comments on the proposed rule and proposed specifications by February 24, 2014.
You may submit comments on the proposed rule and proposed specifications, identified by NOAA–NMFS–2012–0178, by either of the following methods:
• Electronic Submission: Submit all electronic public comments via the Federal e-Rulemaking Portal. Go to
• Mail: Send written comments to Michael D. Tosatto, Regional Administrator, NMFS Pacific Islands Region (PIR), 1601 Kapiolani Blvd., Suite 1110, Honolulu, HI 96814–4700.
Instructions: Comments sent by any other method, to any other address or individual, or received after the end of the comment period, may not be considered by NMFS. All comments received are a part of the public record and will generally be posted for public viewing on
The proposed rule and proposed specifications would implement Amendment 7 to the Fishery Ecosystem Plan for Pelagic Fisheries of the Western Pacific Region (Pelagics FEP). Amendment 7, which includes an environmental assessment and regulatory impact review, provides background information on the proposed rule and proposed specifications and is available from
You may submit written comments regarding the burden-hour estimates or other aspects of the collection-of-information requirements contained in this proposed rule to Michael D. Tosatto (see
Adam Bailey, NMFS PIR Sustainable Fisheries Division, 808–944–2248.
NMFS and the Council manage the pelagic fisheries of American Samoa, Guam, the Commonwealth of the Northern Mariana Islands (CNMI), and Hawaii under the Pelagics FEP. Typically, the Council recommends conservation and management measures for NMFS to implement under the authority of the Magnuson-Stevens Fishery Conservation and Management Act (Magnuson-Stevens Act). Certain pelagic fish stocks, including tunas, are also subject to conservation and management measures cooperatively agreed to by the Western and Central Pacific Fisheries Commission (WCPFC), an international regional fisheries management organization that has jurisdiction over fisheries harvesting highly migratory species in the western and central Pacific Ocean (WCPO, generally west of 150° W. longitude). Although NMFS often implements these decisions directly under the authority of the Western and Central Pacific Fisheries Convention Implementation Act, the Council may also recommend conservation and management measures applicable to the U.S. component of internationally-managed fisheries for implementation by NMFS under the Magnuson-Stevens Act.
In 2008, the WCPFC adopted Conservation and Management Measure (CMM) 2008–01 “Conservation and Management Measure for Bigeye and Yellowfin Tuna in the Western and Central Pacific Ocean.” CMM 2008–01 established an annual bigeye tuna catch limit for U.S. longline fisheries operating in the WCPO, and separate longline bigeye tuna catch limits for the U.S. participating territories to the WCPFC, which are American Samoa, Guam, and the CNMI. The U.S. bigeye tuna limit was 3,763 mt, which NMFS implemented in 2009, 2010 and 2011 (December 7, 2009, 74 FR 63999). This limit applied only to Hawaii- and U.S. West Coast-based longline fisheries that fished in the WCPO; the limit did not apply to longline fisheries of the U.S. participating territories. CMM 2008–01 also provided that WCPFC members and Participating Territories of the WCPFC that caught less than 2,000 mt of bigeye tuna in 2004 would be subject to an annual limit of 2,000 mt, except that Small Island Developing States and Participating Territories of the WCPFC undertaking responsible development of their fisheries would not be subject to individual annual limits for bigeye tuna. The three U.S. participating territories fell into this category.
The WCPFC extended the U.S. bigeye tuna limit for 2012 through CMM 2011–01 (August 27, 2012, 77 FR 51709), and for fishing year 2013 through CMM 2012–01 (September 23, 2013, 78 FR 58240). In addition, under CMM 2012–01, Small Island Developing States and Participating Territories of the WCPFC, including American Samoa, Guam, and the CNMI, were not subject to individual longline limits for bigeye tuna for fishing year 2013. Subsequently, in December 2013, the WCPFC adopted a new tropical tuna conservation and management measure, which maintain the U.S. longline bigeye tuna catch limit of 3,763 mt for 2014, and reduces the limit to 3,554 mt in 2015 and 2016, and to 3,345 mt for 2017. CMM 2013–01 further provides that members that caught less than 2,000 mt of bigeye in 2004 are limited to no more than 2,000 mt in each of 2014, 2015, 2016 and 2017. However, this limit does not apply to Small Island Developing States and Participating Territories of the WCPFC. Consistent with previous WCPFC measures, the U.S. participating territories are not subject to individual longline limits for bigeye tuna under CMM 2013–01.
There are two Hawaii longline fisheries: The deep-set fishery that targets bigeye tuna, and the shallow-set fishery that targets swordfish, but also retains other pelagic management unit species (MUS), including bigeye tuna. Therefore, the U.S. bigeye tuna limit applies to both fisheries. NMFS monitors the longline catch and, when NMFS projects the fisheries will reach the U.S. bigeye tuna limit, NMFS prohibits the retention, transshipment, or landing of bigeye tuna by Hawaii longline vessels in the WCPO through the remainder of the year. NMFS restricted the fisheries in this way in 2009 and 2010.
In 2011, Congress passed Public Law 112–55, 125 Stat. 552
In 2012, NMFS forecasted that the U.S. bigeye tuna catch limit of 3,763 mt would be reached on November 27, 2012. In accordance with NMFS regulations at 50 CFR 300.224, from November 20, 2012, through December 31, 2012, NMFS attributed to American Samoa 771 mt of bigeye tuna caught by Hawaii longline vessels in the American Samoa fishing agreement. Consequently, the U.S. bigeye tuna limit was not reached, and Hawaii longline vessels that were not part of that agreement continued to catch bigeye tuna in the WCPO under the remaining amount of the U.S. bigeye tuna limit. In both 2011 and 2012, the United States did not exceed its bigeye tuna limit of 3,763 mt, and the amount of bigeye tuna caught by Hawaii-based longline vessels and attributed to American Samoa was less than 1,000 mt each year.
In 2013, Congress extended the Section 113 provisions through Public Law 113–6, 125 Stat. 603, Section 110, the Department of Commerce Appropriations Act. For 2013, the government of the CNMI entered into a Section 113 agreement with certain Hawaii longline vessels. On December 5, 2013, in accordance with NMFS regulations at 50 CFR 300.224, NMFS began attributing to the CNMI bigeye tuna catches made by vessels identified in the agreement. The attribution is expected to continue through the end of 2013. NMFS does not expect the 2013 U.S. bigeye tuna limit of 3,763 mt to be reached.
As provided in Section 113 of the CFCAA, and based on recommendations from the Council, consistent with the Magnuson-Stevens Act, this proposed rule would implement the following:
• Establish a framework consistent with WPCFC conservation and management measures for specifying catch or fishing effort limits and accountability measures for pelagic fisheries in the U.S. participating territories, which are American Samoa, Guam, and the Northern Mariana Islands;
• Authorize each U.S. participating territory to enter into specified fishing agreements with U.S. fishing vessels permitted under the Pelagic FEP, and allocate to those vessels a specified portion of a territory's catch or fishing effort limit, as determined by NMFS and the Council;
• Establish the criteria that specified fishing agreements must satisfy, and the procedures for reviewing agreements; and
• Establish accountability measures for attributing and restricting catch and fishing effort toward specified limits, including catches and fishing effort made by vessels in the agreements.
Under the proposed rule, the Council would review existing and proposed catch or fishing effort limit specifications and the portion available for allocation at least annually to ensure consistency with the Pelagics FEP, Magnuson-Stevens Act, WCPFC decisions, and other applicable laws. Based on this review, at least annually, the Council would recommend to NMFS whether such catch or fishing effort limit specification or the portion available for allocation should be approved for the next fishing year. NMFS would review any Council recommendation and, if determined to be consistent with the Pelagics FEP, Magnuson-Stevens Act, WCPFC decisions and other applicable laws, would approve such recommendation. If NMFS determines that a recommendation is inconsistent with the Pelagics FEP, Magnuson-Stevens Act, WCPFC decisions and other applicable laws, NMFS would disapprove the recommendation and provide the Council with a written explanation of the reasons. If a catch or fishing effort limit specification or allocation limit is disapproved, or if the Council recommends and NMFS approves no catch or fishing effort limit specification or allocation limit, then no specified fishing agreements would be accepted for the fishing year covered by such action.
In addition to the proposed framework process, NMFS also proposes to apply that process to specify a longline bigeye tuna catch limit of 2,000 mt for each U.S. participating territory. The current WCPFC Conservation and Management Measure for tropical tuna stocks (CMM 2013–01), adopted in December 2013, limits members that harvested less than 2,000 mt of bigeye in 2004 to no more than 2,000 mt for each of the years 2014 through 2017. However, paragraph 7 of CMM 2013–01 does not establish an individual limit on the amount of bigeye tuna that may be harvested annually in the WCPFC Convention Area by Small Island Developing States and Participating Territories of the WCPFC, including American Samoa, Guam, and the CNMI. NMFS and the Council, however, believe it is important that the paragraph 7 exemption not apply to U.S. participating territories, since bigeye tuna is currently subject to overfishing. Therefore, NMFS proposes to establish 2,000-mt limits for the U.S. participating territories. These limits, in conjunction with the 1,000-mt limits that may be allocated under specified fishing agreements (see below), will help ensure stock sustainability under the proposed action.
NMFS would specify that each U.S. participating territory may allocate up to 1,000 mt of its 2,000-mt bigeye tuna limit to a U.S. longline fishing vessel or vessels based in another U.S. participating territory or Hawaii, and identified in a specified fishing agreement. For U.S. fishing vessels identified in a valid specified fishing agreement that are subject to the U.S. bigeye tuna limit and fishing restrictions set forth in 50 CFR 300 Subpart O, NMFS would attribute catch made by such vessels to the applicable territory. The attribution would begin seven days before the date that NMFS projects the limit to be reached, or upon the effective date of the agreement, whichever is later. The effective date is the date upon which NMFS provides written notice to the authorized official or designated representative that the specified fishing agreement meets the requirements of this rule.
For all other U.S. fishing vessels identified in a valid specified fishing agreement, NMFS would attribute catch made by such vessels to the applicable territory beginning seven days before the date NMFS determines the limit is projected to be reached, or upon the effective date of the agreement, whichever is later. NMFS would monitor and restrict, as appropriate, catches of longline-caught bigeye tuna, including catches made under a specified fishing agreement, using the accountability measures described in the proposed rule. The longline bigeye tuna catch limit specifications would be effective for the 2014 fishing year, which is scheduled to begin on January 1, 2014.
In addition to seeking public comments on this proposed rule and associated proposed specifications, NMFS is soliciting comments on proposed Amendment 7 to the Pelagics
Pursuant to section 304(b)(1)(A) of the Magnuson-Stevens Act, the NMFS Assistant Administrator has determined that the proposed action is consistent with the Pelagics FEP, other provisions of the Magnuson-Stevens Act, and other applicable laws, subject to further consideration after public comment.
This proposed rule has been determined to be not significant for purposes of Executive Order 12866.
The Chief Council for Regulation of the Department of Commerce certified to the Chief Council for Advocacy of the Small Business Administration that this proposed action, if adopted, would not have a significant economic impact on a substantial number of small entities. A description of the action, why it is being considered, and the legal basis for this action are contained in the preamble to this proposed rule.
In 2011, the U.S. Congress passed Public Law 112–55, 125 Stat. 552
This proposed action would directly apply to vessels federally permitted under the Pelagics FEP, specifically Hawaii longline limited entry, American Samoa longline limited entry, Western Pacific general longline, Pacific Remote Island Areas (PRIA) troll and handline, and Western Pacific Pelagic squid jig permit holders. As of August 2013, 131 vessels possessed Hawaii longline limited entry permits (out of 164 total permits), 47 possessed American Samoa longline limited entry permits (out of 60 total permits), no vessels held Western Pacific general longline permits, five vessels held Pacific Remote Island Areas (PRIA) troll and handline permits, and one held a Western Pacific pelagic squid jig permit. Among the American Samoa and Hawaii longline vessels with limited entry permits in August 2013, 16 held both American Samoa and Hawaii longline limited entry permits (dual permit holders).
According to landings information provided in the environmental assessment in support of this action and logbook information, Hawaii-based longline vessels landed approximately 25,866,000 lb of pelagic fish valued at $94,901,000 in 2012 (see Tables 7 and 8 of Amendment 7). These vessels made 1,437 trips, caught 159,787 bigeye tuna, and kept 157,502, along with other pelagic fish. With 129 vessels making either a deep- or shallow-set trip that year, the ex-vessel value of pelagic fish caught by Hawaii-based longline fisheries averaged about $736,000 per vessel. In 2012, 25 American Samoa longline vessels turned in logbooks reporting the landing of 255,686 pelagic fish valued at $9,793,153, of which almost $7.7 million came from albacore tuna landings. With 25 active longline vessels, the ex-vessel value of pelagic fish caught by the American Samoa longline fishery averaged about $391,720 per vessel.
With respect to non-longline pelagic fisheries, NMFS requires federal permits only for pelagic troll and handline vessels fishing in the PRIA and squid jig vessels. Assuming average landings of pelagic species by all pelagic troll and handline vessels in the western Pacific reflect landings made by those vessels possessing PRIA troll and handline permits, annual revenues earned from landings of pelagic species are not expected to exceed $10,000 for a typical vessel. Information on catch or revenue from the one federally permitted squid jig vessel is considered confidential and cannot be publicly reported.
On June 20, 2013, the Small Business Administration (SBA) issued a final rule revising the small business size standards for several industries effective July 22, 2013 (78 FR 37398). The rule increased the size standard for Finfish Fishing from $4.0 to 19.0 million, Shellfish Fishing from $4.0 to 5.0 million, and Other Marine Fishing from $4.0 to 7.0 million. Based on available information, NMFS has determined that all vessels federally permitted under Pelagics FEP are small entities under the SBA definition of a small entity, i.e., they are engaged in the business of fish harvesting, are independently owned or operated, are not dominant in their field of operation, and have annual gross receipts not in excess of $19 million. Therefore, there would be no disproportionate economic impacts between large and small entities. Furthermore, there would be no disproportionate economic impacts among the universe of vessels based on gear, home port, or vessel length.
Pursuant to the Regulatory Flexibility Act, NMFS has reviewed the analyses prepared for this action in light of the new size standards. Under the former, lower size standards, all vessels subject to this action were considered small entities, and they all would continue to be considered small under the new standards. NMFS does not think that the new size standards affect analyses prepared for this action and solicits public comments on the analyses in light of the new size standards.
Even though this proposed action would apply to a substantial number of vessels, the implementation of this action would not result in significant adverse economic impact to individual vessels. While the proposed framework would potentially apply to any highly migratory species under the Pelagics FEP that is subject to annual catch or fishing effort limits in the WCPO, in recent years, bigeye tuna has been the only species subject to these limits. Therefore, the discussion on impacts will center on bigeye tuna catch and longline fisheries.
The proposed action would potentially benefit Hawaii-based longline fishery participants, including dual permit holders that possess an American Samoa and Hawaii longline limited entry permit. The benefits to these vessels come through allowing the territorial fishing agreements, similar to those authorized under Section 113, to continue under the Pelagics FEP. In 2011 and 2012, American Samoa entered into a Section 113 agreement with almost all Hawaii longline fishery participants, under a framework that was similar to that proposed here. In both years, NMFS projected that the U.S. bigeye tuna limit of 3,763 mt would
For fishing year 2013, the CNMI entered into a Section 113 agreement with certain Hawaii longline fishery participants. NMFS projected that the U.S. bigeye tuna limit of 3,763 mt would be reached in early December, and on December 5, 2013, began attributing to the CNMI bigeye tuna catches made by vessels identified in the Section 113 agreement. The attribution will continue through the end of December 2013.
Based on catch and fishing effort under the 2011 and 2012 fishing agreement, it is likely that under the proposed action, less than 1,000 mt of bigeye tuna would be harvested by Hawaii vessels identified in a specified fishing agreement for 2014. Providing opportunity to land bigeye tuna in Hawaii in the last quarter of the year when market demand is significant will result in positive economic benefits for fishery participants and net benefits to the nation. In terms of the impacts of reducing the limits of bigeye tuna catch by longline vessels based in the territories from an unlimited amount to 2,000 mt, this is not likely to adversely affect vessels based in the territories.
Historical catch of bigeye tuna attributed to American Samoa has been less than 2,000 mt, even when including catch by vessels based in American Samoa, catch attributed by U.S. vessels (in 2011 and 2012), and dual permitted vessels. There appears to have been little, if any, catch of bigeye tuna by longline vessels in Guam or CNMI in recent years.
Under the proposed action, longline fisheries managed under the Pelagics FEP are not expected to expand substantially nor change the manner in which they are currently conducted, (i.e., area fished, number of vessels longline fishing, number of trips taken per year, number of hooks set per vessel during a trip, depth of hooks, or deployment techniques in setting longline gear), due to existing operational constraints in the fleet, the limited entry permit programs, and protected species mitigation requirements. The likely scenario under the proposed action is expected to result fishing similar to what occurred in 2011 and 2012 under Section 113 fishing agreements.
The proposed rule does not duplicate, overlap, or conflict with other Federal rules and is not expected to have significant impact on small entities (as discussed above), organizations or government jurisdictions. There does not appear to be disproportionate economic impacts from the proposed rule based on home port, gear type, or relative vessel size. The proposed rule also will not place a substantial number of small entities, or any segment of small entities, at a significant competitive disadvantage to large entities.
For the reasons above, NMFS does not expect the proposed action to have a significant economic impact on a substantial number of small entities. As a result, an initial regulatory flexibility analysis is not required and none has been prepared.
This proposed rule contains a collection-of-information requirement subject to review and approval by OMB under the Paperwork Reduction Act (PRA). This requirement has been submitted to OMB for approval. The public reporting burden for a specified fishing agreement is estimated to average six 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 information. NMFS expects to receive up to nine applications for specified fishing agreements each year, for a total maximum reporting burden of 54 hours per year.
Public comment is sought regarding: Whether this proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; the accuracy of the burden estimate; 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, including through the use of automated collection techniques or other forms of information technology. Send comments on these or any other aspects of the collection of information to Michael D. Tosatto (see
Administrative practice and procedure, Fish, Fisheries, Fishing, Marine resources, Reporting and recordkeeping requirements, Treaties.
Administrative practice and procedure, American Samoa, Commercial fishing, Fisheries, Guam, Hawaii, Northern Mariana Islands, Western and Central Pacific Fisheries Commission.
For the reasons set out in the preamble, NMFS proposes to amend 50 CFR parts 300 and 665 as follows:
16 U.S.C. 6901
(d)
(1) The start date specified in § 665.819(c)(9)(i) of this title has occurred or passed; and
(2) NMFS has not made a determination under § 665.819(c)(9)(iii) of this title that the catch of bigeye tuna
(f) * * *
(1) * * *
(iv) Bigeye tuna caught by longline gear may be retained on board, transshipped, and/or landed if they were caught by a vessel that is included in a specified fishing agreement under § 665.819(c) of this title, if the agreement provides for bigeye tuna to be attributed to the longline fishery of American Samoa, Guam, or the Northern Mariana Islands, provided that:
(A) The start date specified in § 665.819(c)(9)(i) of this title has occurred or passed; and
(B) NMFS has not made a determination under § 665.819(c)(9)(iii) of this title that the catch of bigeye tuna exceeds the limit allocated to the territory that is a party to the agreement.
16 U.S.C. 1801
(o) Use a fishing vessel to retain on board, transship, or land pelagic MUS captured by longline gear in the WCPFC Convention Area, as defined in § 300.211 of this title, in violation of any restriction announced in accordance with § 665.819(d)(2).
(a)
(2) If the WCPFC does not agree to a catch or fishing effort limit for a stock of western Pacific pelagic MUS applicable to a U.S. participating territory, the Council may recommend that the Regional Administrator specify such a limit that is consistent with the Pelagics FEP, other provisions of the Magnuson-Stevens Act, and other applicable laws. The Council may also recommend that the Regional Administrator authorize a U.S. participating territory to allocate a portion of a specified catch or fishing effort limit to a fishing vessel or vessels holding valid permits issued under § 665.801 through a specified fishing agreement pursuant to paragraph (c) of this section.
(3) The Council shall review any existing or proposed catch or fishing effort limit specification and portion available for allocation at least annually to ensure consistency with the Pelagics FEP, Magnuson-Stevens Act, WCPFC decisions, and other applicable laws. Based on this review, at least annually, the Council shall recommend to the Regional Administrator whether such catch or fishing effort limit specification or portion available for allocation should be approved for the next fishing year.
(4) The Regional Administrator shall review any Council recommendation pursuant to paragraph (a) of this section and, if determined to be consistent with the Pelagics FEP, Magnuson-Stevens Act, WCPFC decisions, and other applicable laws, shall approve such recommendation. If the Regional Administrator determines that a recommendation is inconsistent with the Pelagics FEP, Magnuson-Stevens Act, WCPFC decisions and other applicable laws, the Regional Administrator would disapprove the recommendation and provide the Council with a written explanation of the reasons for disapproval. If a catch or fishing effort limit specification or allocation limit is disapproved, or if the Council recommends and NMFS approves no catch or fishing effort limit specification or allocation limit, no specified fishing agreements as described in paragraph (c) of this section will be accepted for the fishing year covered by such action.
(b)
(2) The Regional Administrator will publish in the
(3) The Regional Administrator will publish in the
(c)
(1) An authorized official or designated representative of a U.S. participating territory may submit a complete specified fishing agreement to the Council for review. A complete specified fishing agreement must meet the following requirements:
(i) Identify the vessel(s) to which the fishing agreement applies, along with documentation that such vessel(s) possesses a valid permit issued under § 665.801;
(ii) Identify the amount of western Pacific pelagic MUS to which the fishing agreement applies, if applicable;
(iii) Identify the amount of fishing effort to which the fishing agreement applies, if applicable;
(iv) Be signed by an authorized official of the applicable U.S. participating territory, or designated representative;
(v) Be signed by each vessel owner or designated representative; and
(vi) Satisfy either paragraph (c)(1)(vi)(A) or (B) of this section:
(A) Require the identified vessels to land or offload catch in the ports of the U.S. participating territory to which the fishing agreement applies; or
(B) Specify the amount of monetary contributions that each vessel owner in the agreement, or his or her designated representative, will deposit into the Western Pacific Sustainable Fisheries Fund;
(vii) Be consistent with the Pelagics FEP and implementing regulations, the Magnuson-Stevens Act, and other applicable laws; and
(viii) Shall not confer any right of compensation to any party enforceable against the United States should action under such agreement be prohibited or limited by NMFS pursuant to its authority under Magnuson-Stevens Act, or other applicable laws.
(2)
(3)
(ii) Within 30 calendar days of receipt of the fishing agreement from the Council, the Regional Administrator will provide the authorized official or designated representative of the U.S. participating territory to which the agreement applies with written notice of whether the agreement meets the requirements of this section. The Regional Administrator will reject an agreement for any of the following reasons:
(A) The agreement fails to meet the criteria specified in this subpart;
(B) The applicant has failed to disclose material information;
(C) The applicant has made a material false statement related to the specified fishing agreement;
(D) The agreement is inconsistent with the Pelagics FEP, implementing regulations, the Magnuson-Stevens Act, or other applicable laws; or
(E) The agreement includes a vessel identified in another valid specified fishing agreement.
(iii) The Regional Administrator, in consultation with the Council, may recommend that specified fishing agreements include such additional terms and conditions as are necessary to ensure consistency with the Pelagics FEP and implementing regulations, the Magnuson-Stevens Act, and other applicable laws.
(iv) The U.S. participating territory must notify NMFS and the Council in writing of any changes in the identity of fishing vessels to which the specified fishing agreement applies within 72 hours of the change.
(v) Upon written notice that a specified fishing agreement fails to meet the requirements of this section, the Regional Administrator may provide the U.S. participating territory an opportunity to modify the fishing agreement within the time period prescribed in the notice. Such opportunity to modify the agreement may not exceed 30 days following the date of written notice. The U.S. participating territory may resubmit the agreement according to paragraph (c)(1) of this section.
(vi) The absence of the Regional Administrator's written notice within the time period specified in paragraph (c)(3)(ii) of this section or, if applicable, within the extended time period specified in paragraph (c)(3)(v) of this section shall operate as the Regional Administrator's finding that the fishing agreement meets the requirements of this section.
(4)
(5) A vessel shall not be identified in more than one valid specified fishing agreement at a time.
(6)
(7)
(8)
(9)
(ii) For U.S. fishing vessels identified in a valid specified fishing agreement that are subject to catch or fishing effort limits and fishing restrictions set forth in this subpart, NMFS will attribute catch or fishing effort to the applicable U.S. participating territory starting seven days before the date NMFS projects the limit to be reached, or upon the effective date of the agreement, whichever is later.
(iii) If NMFS determines catch or fishing effort made by fishing vessels identified in a specified fishing agreement exceeds the allocated limit, NMFS will attribute any overage of the limit back to the U.S. or Pacific island fishery to which the vessel(s) is registered and permitted in accordance with the regulations set forth in 50 CFR part 300, subpart O and other applicable laws.
(d)
(2) The notice will include an advisement that fishing for the applicable pelagic MUS stock or stock complex, or fishing effort, will be restricted on a specific date. The restriction may include, but is not limited to, a prohibition on retention, closure of a fishery, closure of specific areas, or other catch or fishing effort restrictions. The restriction will remain in effect until the end of the fishing year.
(e)
(i) Project(s) identified in an approved Marine Conservation Plan (16 U.S.C. 1824) of a U.S. participating territory that is a party to a valid specified fishing agreement, pursuant to § 665.819(c); and
(ii) In the case of two or more valid specified fishing agreements in a fishing year, the projects listed in an approved Marine Conservation Plan applicable to the territory with the earliest valid agreement will be funded first.
(2) At least seven calendar days prior to the disbursement of any funds, the Council shall provide in writing to NMFS a list identifying the order of priority of the projects in an approved Marine Conservation Plan that are to be funded. The Council may thereafter revise this list.
Enforcement and Compliance, formerly Import Administration, International Trade Administration, Department of Commerce.
Toni Page, Enforcement and Compliance, AD/CVD Operations, Office VII, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone: (202) 482–1398.
On July 2, 2013, the Department of Commerce (the Department) published a notice of opportunity to request an administrative review of the antidumping duty (AD) order on polyethylene terephthalate film (PET film) from Taiwan covering the period July 1, 2012 through June 30, 2013.
Pursuant to 19 CFR 351.213(d)(1), the Department will rescind an administrative review, in whole or in part, if a party that requested the review withdraws the request within 90 days of the date of publication of the notice of initiation of the requested review. Petitioners timely submitted a withdrawal request within the 90-day period (
The Department will instruct U.S. Customs and Border Protection (CBP) to assess ADs on all appropriate entries. Shinkong shall be assessed ADs at rates equal to the cash deposit of estimated ADs required at the time of entry, or withdrawal from warehouse, for consumption, during the period July 1, 2012, through June 30, 2013, in accordance with 19 CFR 351.212(c)(1)(i). The Department intends to issue appropriate assessment instructions to CBP 15 days after publication of this notice.
This notice also serves as a reminder to parties subject to the administrative protective order (APO) of their responsibility concerning the disposition of proprietary information disclosed under an APO in accordance with 19 CFR 351.305(a)(3), which continues to govern business proprietary information in this segment of the proceeding. Timely written notification of the return or destruction of APO materials, or conversion to judicial protective order, is hereby requested. Failure to comply with the regulations and terms of an APO is a violation which is subject to sanction.
This notice is issued and published in accordance with sections 751(a)(1) and 777(i)(1) of the Tariff Act of 1930, as amended, and 19 CFR 351.213(d)(4).
Enforcement and Compliance, formerly Import Administration, International Trade Administration, Department of Commerce.
The Department of Commerce (“the Department”) is partially rescinding the administrative review of the antidumping duty order on certain polyester staple fiber from the People's Republic of China (“PRC”) for the period June 1, 2012 through May 31, 2013, based on the withdrawal of a certain request for review.
Steven Hampton, AD/CVD Operations,
On June 3, 2013, the Department published a notice of opportunity to request an administrative review of the antidumping duty order on certain polyester staple fiber from the PRC.
On November 14, 2013, Zhaoqing Tifo New Fiber Co., Ltd. (“Zhaoqing Tifo”)
Pursuant to 19 CFR 351.213(d)(1), the Department will rescind an administrative review, in whole or in part, if the parties that requested a review withdraw the request within 90 days of the date of publication of the notice of initiation. Zhaoqing Tifo's withdrawal of its review request was submitted within the deadline set forth under 19 CFR 351.213(d)(1). Therefore, in accordance with 19 CFR 351.213(d)(1) and consistent with our practice,
The Department will instruct U.S. Customs and Border Protection (“CBP”) to assess antidumping duties on all appropriate entries. For Zhaoqing Tifo, antidumping duties shall be assessed at rates equal to the cash deposit of estimated antidumping duties required at the time of entry, or withdrawal from warehouse, for consumption, during the period June 1, 2012, through May 31, 2013, in accordance with 19 CFR 351.212(c)(1)(i). The Department intends to issue appropriate assessment instruction directly to CBP 15 days after publication of this notice.
This notice serves as a final reminder to importers of their responsibility under 19 CFR 351.402(f)(2) to file a certificate regarding the reimbursement of antidumping duties prior to liquidation of the relevant entries during this review period. Failure to comply with this requirement could result in the presumption that reimbursement of antidumping duties occurred and the subsequent assessment of doubled antidumping duties.
This notice also serves as a final reminder to parties subject to the administrative protective order (“APO”) of their responsibility concerning the disposition of proprietary information disclosed under an APO in accordance with 19 CFR 351.305(a)(3). Timely written notification of the return or destruction of APO materials, or conversion to judicial protective order, is hereby requested. Failure to comply with the regulations and terms of an APO is a violation which is subject to sanction.
National Telecommunications and Information Administration, U.S. Department of Commerce.
Notice, Request for Public Comment.
The First Responder Network Authority (FirstNet) publishes this notice to request public comments on its proposed procedures for implementing the National Environmental Policy Act (NEPA). These proposed NEPA implementing procedures are necessary to assist FirstNet in establishing an NEPA compliance program and applying the appropriate level of NEPA review for activities undertaken by FirstNet in the design, construction and operation of the nationwide interoperable public safety broadband network (PSBN).
Comments on the proposed procedures must be received by February 7, 2014.
The public is invited to submit written comments in electronic form. Written comments may be submitted by email to
Eli Veenendaal, National Telecommunications and Information Administration, U.S. Department of Commerce, 1401 Constitution Avenue NW., HCHB Room 4713, Washington, DC 20230; (202) 482–2188; or
The National Environmental Policy Act of 1969 (42 U.S.C. 4321–4347) (NEPA) requires federal agencies to undertake an assessment of environmental effects of their proposed actions prior to making a final decision and implementing the action. NEPA requirements apply to any federal project, decision, or action that may have a significant impact on the quality of the human environment. NEPA also establishes the Council on Environmental Quality (CEQ), which issued regulations implementing the procedural provisions of NEPA. Among other considerations, CEQ regulations require federal agencies at 40 CFR 1507.3 to adopt their own implementing procedures to supplement CEQ's regulations implementing NEPA and to consult with CEQ during their development and prior to publication in the
The Middle Class Tax Relief and Job Creation Act of 2012 (Pub. L. 112–96, 126 Stat. 156 (2012)) (Act) creates and authorizes FirstNet to take all actions necessary to ensure the design, construction, and operation of a nationwide interoperable nationwide, public safety broadband network (PSBN) based on a single, national network architecture. The Act meets a long-standing and critical national infrastructure need to create a single, nationwide interoperable PSBN that will, for the first time, allow police officers, fire fighters, emergency medical service professionals and other public safety officials to effectively communicate with each other across agencies and jurisdictions.
As a newly created entity, FirstNet does not currently have procedures for implementing NEPA. The proposed NEPA implementing procedures are necessary to assist FirstNet in establishing an NEPA compliance program and applying the appropriate level of NEPA review for activities undertaken by FirstNet in the design, construction and operation of the nationwide interoperable PSBN. Accordingly, FirstNet is requesting public comment on its proposed implementing procedures before utilizing them as part of its NEPA review process. The proposed procedures are set forth as an addendum to this notice.
FirstNet is responsible for, at a minimum, ensuring nationwide standards for the use of and access to the network; issuing open, transparent and competitive requests for proposals (RFPs) to build, operate and maintain the network; encouraging these RFPs to leverage, to the maximum extent economically desirable, existing commercial wireless infrastructure to speed deployment of the network; and overseeing contracts with non-federal entities to build, operate and maintain the network.
The specific actions anticipated to be undertaken by FirstNet encompass a variety of activities including the installation of cables, cell towers, antenna colocations, buildings, and power units as defined in the following examples:
(a)
(b)
(c)
(d)
(e)
(f)
FirstNet is also required to leverage, to the maximum extent economically possible, existing commercial infrastructure in its deployment and operation of the PSBN.
The geographic scope of the PSBN encompasses all U.S. states and territories. Thus, FirstNet actions will likely occur in a wide range of environmental settings and require FirstNet to establish a process for analyzing proposed actions and making NEPA determinations based on the specific location and type of proposed project activities.
Therefore, FirstNet seeks to establish NEPA implementing procedures to better follow the letter and spirit of NEPA; comply fully with the CEQ Regulations; and apply the NEPA review process early in the planning stages of the PSBN.
The notice does not contain collection-of-information requirements subject to the Paperwork Reduction Act (PRA) of 1995 (44 U.S.C. 3501
These NEPA procedures are intended to supplement CEQ regulations and provide guidance to FirstNet employees regarding the procedural requirements for the application of NEPA to FirstNet. CEQ does not direct agencies to prepare NEPA analysis or document before establishing agency procedures that supplement the CEQ regulations for implementing NEPA. Agency NEPA procedures are procedural guidance to assist agencies in the fulfillment of their responsibilities under NEPA. The requirements for establishing NEPA procedures are set for at 40 CFR 1505.1 and 1507.3.
The purpose of this Management Directive (Directive) is to establish the First Responder Network Authority (FirstNet) policies, requirements, and procedures for complying with the National Environmental Policy Act, 42 U.S.C. 4321
The provisions of this Directive apply to actions undertaken by FirstNet and specifically apply to any of the following actions undertaken by FirstNet:
(a) Legislative proposals initiated by FirstNet for which FirstNet would have primary action responsibility.
(b) Research, projects, and activities directly undertaken by FirstNet, or the research, projects and activities of a non-Federal entity supported or facilitated by FirstNet, including through grants and other forms of financial assistance, where FirstNet has sufficient involvement to influence, control, direct or affect material aspects of the research, project or activity.
(c) Actions to establish an official policy or adopt a formal plan or program. (40 CFR 1508.18).
FirstNet policies and programs shall be planned, developed, and implemented so as to achieve the goals and to follow the procedures declared by NEPA in order to assure responsible stewardship of the environment for present and future generations. Accordingly, FirstNet shall adhere to the following actions to ensure compliance with NEPA.
(a) FirstNet adopts the CEQ Regulations (40 CFR Parts 1500–1508) for implementing NEPA.
(b) FirstNet shall:
1. Comply with the CEQ Regulations (40 CFR Parts 1500–1508);
2. Report and coordinate its policies and procedures with the Department of Commerce Office of General Counsel, as appropriate;
3. Ensure activities and planning regarding Federal actions consider the environmental consequences of proposed actions in conjunction with mission requirements and objectives;
4. Consider and give weight to environmental factors in making decisions in order to achieve a proper balance between the development and utilization of natural, cultural and human resources, and the protection and enhancement of environmental quality;
5. Consult, coordinate and cooperate with other Federal agencies and, where appropriate, state, local and tribal governments in the development and implementation of FirstNet's plans and programs affecting environmental quality and, in turn, to give consideration to those activities that succeed in best addressing state and local concerns;
6. Identify potential Federal, state, local and tribal cooperating agencies early during the NEPA scoping process;
7. Participate as a lead or cooperative agency, as appropriate, with other federal agencies where FirstNet is involved in the same action as other agencies, or is involved in an action which is related to another agency's action because of their functional interdependence or geographical proximity;
8. As requested, and where resources allow, review and provide comments on draft NEPA documents submitted by other Federal agencies where the action relates to FirstNet's mission or operations;
(c) FirstNet shall ensure appropriate action is taken to comply with NEPA when actions are planned by private applicants or other non-Federal entities before Federal involvement so that:
1. Policies or designated staff is available to advise potential applicants of existing studies or other information foreseeably required for later Federal action.
2. The Federal agency consults early with appropriate state, local and tribal governments and with interested private persons and organizations when its own involvement is reasonable foreseeable.
3. The Federal agency commences its NEPA process at the earliest possible time.
(d) While it is the policy of FirstNet to fully evaluate its actions in accordance with the requirements of NEPA and the CEQ regulations, certain actions may result from statutory requirements involving little or no discretion on the part of FirstNet. In the case of such actions, a determination of non-applicability of NEPA should be made by the FirstNet NEPA Coordinator in coordination with the FirstNet Chief Counsel.
This Directive incorporates all definitions and phrases as defined by CEQ in its regulations at 40 CFR Part 1508. To ensure full compliance, the CEQ regulations should be consulted for comprehensive explanations of the terms. A glossary of words and phrases as used in this Directive is included in Appendix B.
FirstNet will follow a systematic, interdisciplinary approach to planning in order to ensure a reasonable use of environment resources without degradation, risk to health and safety, or other undesirable and unintended consequences. The FirstNet NEPA program is designed to ensure that:
(a) Proposed actions to be undertaken by FirstNet are identified early in the planning process, and brought to the attention of the NEPA Coordinator;
(b) Actions are evaluated to determine the appropriate applicable NEPA review (i.e., CE, Environmental Assessment (EA), or Environmental Impact Study (EIS));
(c) An interdisciplinary approach is taken to proactively consider environmental impacts and identify and consider the full range of viable alternatives at the earliest planning stages of an action and prior to rendering any decision;
(d) The planning process integrates environmental review and consultation requirements;
(e) The impacts of proposed activities, programs, and projects on the quality of the human environment are considered before making an irretrievable and irreversible commitment of resources; and
(f) The public is engaged and involved with the planning process and evaluation of environmental impacts, as appropriate.
FirstNet roles and responsibilities relating to the implementation and compliance with NEPA are as follows:
(a) The Chair of the Board (Chair). The Chair has the ultimate responsibility to fulfill FirstNet's compliance with NEPA. The Chair directs the FirstNet General Manger (GM) to (1) ensure that environmental planning is incorporated into FirstNet decision making processes and (2) coordinate with the designated NEPA Coordinator for advice and guidance on proper and adequate compliance with NEPA requirements.
(b) FirstNet General Manger (GM). The GM shall:
1. Establish and oversee the proper implementation of a FirstNet NEPA compliance program in accordance with the requirements of this Directive;
2. Advise the Chair on NEPA processes that are highly controversial, are nationally significant, or require the establishment of a new FirstNet NEPA-related policy;
3. Inform the Chair of current developments in NEPA policy and implementing procedures;
4. Support early, proactive, and comprehensive coordination and outreach processes across FirstNet;
5. Appoint a NEPA Coordinator to carry out the responsibilities delineated below in paragraph c; and
6. Sign Records of Decision (ROD), Findings of No Significant Impact (FONSIs) and memos citing Categorical Exclusions (CEs), or re-delegate this authority in writing to other FirstNet personnel, as appropriate.
(c) FirstNet NEPA Coordinator (NEPA Coordinator). Responsible for coordinating and overseeing FirstNet's compliance with NEPA. To accomplish this the NEPA Coordinator will:
1. Assist the Chair and GM in implementing FirstNet's compliance with NEPA;
2. Review and provide final clearance on all NEPA documents covered by this Directive;
3. Transmit, with written recommendation, all NEPA documents for action to the GM or authorized designee for signature or other appropriate agency action;
4. Develop and recommend policies, procedures and technical and administrative advice and training to facilitate and improve FirstNet's effective and efficient implementation of NEPA.
5. Provide technical and administrative advice and training to relevant stakeholders so that they are aware of, and comply with, the NEPA process and so that they consider the impacts of their programs, projects, and policies;
6. Act as liaison with the Department, CEQ and U.S. EPA on NEPA-related matters or issues, and coordinate with other federal agencies with respect to significant NEPA matters;
7. Prepare or review, as appropriate, all inter- or intra-agency reports, surveys and comments on NEPA-related matters, including other agency NEPA documentation, or legislative proposals;
8. Consult early and often with relevant stakeholders to identify how the requirements of this Directive will be met. At a minimum:
A. Determine the applicability of NEPA and, if applicable, the appropriate NEPA review procedure (i.e., CE, EA, or EIS) and public involvement, in consultation with the Chief Counsel of FirstNet, as necessary;
B. Review and comment upon draft NEPA documents to ensure that a high-quality analysis is completed, reasonable or appropriate alternatives are identified and discussed, and that all applicable scheduling, scoping, consultation, circulation, and public involvement requirements are met;
C. Assist in consultations with other Federal, state, and local regulatory and/or resource agencies and tribal governments on draft NEPA documents, as appropriate; and
D. Otherwise act as a resource to the relevant stakeholders to ensure that the NEPA document to be prepared identifies reasonably foreseeable significant impacts of the action, sufficiently analyzes the impacts, clearly presents the findings and fairly considers reasonable or appropriate alternatives to the action.
(d) FirstNet Chief Counsel: The Chief Counsel of FirstNet shall provide all legal services regarding NEPA compliance, including:
1. Providing legal sufficiency reviews of NEPA documents, as appropriate;
2. Assisting the Chair, GM, and NEPA Coordinator in determining the applicable NEPA review for a proposed action; and
3. Assisting the Chair, GM, and NEPA Coordinator in establishing or revising this Directive and the FirstNet NEPA compliance program, as necessary.
The environmental review process describes the applicable CE, EA, or EIS process for a proposed FirstNet action and includes actions required by CEQ in 40 CFR parts 1500–1508 for compliance with NEPA. The process involves the following series of actions accomplished by or under the direction of the Chair of FirstNet or a delegate.
FirstNet shall ensure the purpose and need of a proposed action considers the FirstNet mission. FirstNet is authorized and directed by statute to take all actions necessary to ensure the design, construction, and operation of a nationwide interoperable public safety broadband network (PSBN) based on a single, national network architecture. The establishment of the nationwide PSBN meets a long-standing and critical national infrastructure need that will, for the first time, allow police officers, fire fighters, emergency medical service professionals, and other public safety officials to effectively communicate with each other across agencies and jurisdictions.
FirstNet shall integrate the NEPA process with other planning for the nationwide PSBN at the earliest possible time to ensure that planning and decisions reflect environmental values to avoid delays later in the process and head off potential conflicts. Accordingly, FirstNet shall:
(a) Identify environmental impacts and resources in adequate detail so they can be compared and evaluated with economic and technical considerations. Wherever practicable, environmental documents with appropriate analyses should be circulated and reviewed at the same time as other planning documents.
(b) Study, develop, and analyze reasonable alternatives to recommended courses of action. Consider mitigation measures which could avoid, ameliorate, lessen, or compensate identified impacts of the proposed action.
(c) Where the action requiring FirstNet review is by a private applicant or other non-Federal entity:
1. The NEPA Coordinator or an assigned FirstNet Environmental Protection Specialist will advise the applicant of FirstNet's policies and procedures for NEPA compliance, and make available or direct the applicant to resources within FirstNet, the Department or elsewhere in the Federal government to facilitate the applicant's consideration of and explanation of environmental impacts and alternatives.
2. FirstNet will consult with appropriate state, local, and tribal governments and appropriate organizations on environmental impacts and alternatives of the proposed action when its own involvement is reasonably foreseeable.
3. FirstNet will initiate its NEPA review process at the earliest practicable time.
FirstNet shall comply with scoping procedures described in 40 CFR 1501.7 required for proposed actions normally requiring an EA with scoping or an EIS. FirstNet may also require scoping procedures to be followed for other proposed actions where appropriate to achieve the purposes of NEPA. When evaluating the type and extent of the NEPA documents and review appropriate for a proposed action, FirstNet shall:
(a) Define the purpose and need of the proposed action;
(b) Identify reasonably foreseeable impacts of the action to determine if consultation with other federal, state, local or tribal entities is needed;
(c) Determine if other federal agency action is involved in the proposed action so lead and coordinating agencies can be established;
(d) Identify or develop reasonable alternatives to the proposed action;
(e) Consider the context and intensity of the potential direct, indirect, and cumulative environmental effects of the proposed action(s) and any reasonable or appropriate alternatives;
(f) Consider mitigation measures or strategies to minimize, reduce, or eliminate environmental impacts of the proposed action(s), as necessary;
In carrying out its responsibilities under NEPA, FirstNet shall comply with the public involvement requirements described in 40 CFR 1506.6 and make diligent efforts to involve the public in the environmental review process. In addition, FirstNet shall:
(a) Ensure that all public notices relating to environmental matters shall describe the nature, location, and extent of the proposed action and indicate the availability and location of additional information relating to the matter.
(b) Determine the appropriate medium for publishing notices relating to environmental matters on a project-by-project basis.
(c) Assess and consider public comments both individually and collectively and ensure that responses to public comments are appended to the applicable environmental document, as appropriate.
(d) Make available to the public those project-related environmental documents that FirstNet determines will enhance public participation in the environmental process. These materials shall be placed in locations convenient for the public as determined by FirstNet.
(e) Hold public hearings or meetings at reasonable times and locations concerning environmental aspects of a proposed action in all cases where, in the opinion of FirstNet, the need for hearings or meetings is indicated in order to develop adequate information on the environmental implications of the proposed action. Public hearings or meetings conducted by FirstNet will be coordinated to the extent practicable with other meetings, hearings, and environmental reviews which may be held or required by other Federal, state and local agencies.
FirstNet actions that do not individually or cumulatively have a significant effect on the human environment and where no extraordinary circumstances exist may be categorically excluded from further environmental review in an EA or EIS.
(a) The approved list of FirstNet actions that normally qualify for a CE are listed in Appendix C.
(b) FirstNet actions that would normally be categorically excluded from further environmental review but due to the existence of extraordinary circumstances could have substantial environmental effects will require the preparation of an EA or EIS.
(c) This list of extraordinary circumstances that could have substantial environmental effects is listed in Appendix D.
(d) If a proposed action is determined to be a CE and not considered a routine administrative, personnel action, or procurement, FirstNet shall document its determination that a CE applies to a proposed action with a Record of Environmental Consideration.
(e) The list of approved FirstNet CE's is subject to continual review and can be modified by amending/revising this Directive, in consultation with CEQ.
(f) The use of a CE does not relieve FirstNet from compliance with other statutes or consultations under the Endangered Species Act of 1973 (16 U.S.C. 1531
FirstNet shall prepare an EA as defined in 40 CFR 1508.9 for an action which FirstNet determines may have the potential for significant environmental impact. Actions normally requiring an EA include:
(a) When a proposed action is not in a category of actions described in an available categorical exclusion and there is not enough information available to know that the proposed action will have significant environmental impacts, an EA will be prepared. In this situation, an EA process is used to determine, through environmental impact evaluation and opportunity for public involvement, if the impacts on the quality of the human environment are potentially significant.
(b) A proposed action that is included in a category of actions described in a categorical exclusion, but extraordinary circumstances may present the potential for significant environmental impacts precluding the categorical exclusion, and there is a the lack of information to determine that the proposed action will have significant environmental impacts requiring preparation of an EA.
(c) The Chair or a delegate can decide to prepare an EA as a best practice planning tool to inform decision makers on the environmental impacts of its actions.
In preparing an EA, First shall:
(a) Involve environmental agencies, applicants, and the public to the extent practicable.
(b) Ensure the contents of an EA comply with the requirements of 40 CFR 1508.9, and, at minimum, shall include:
1. Sufficient evidence and analysis for FirstNet to determine whether to prepare an EIS or a FONSI, and facilitate preparation of said EIS, if needed;
2. A brief discussion of the need for the action;
3. A brief discussion of the environmental impacts of the proposed action and alternatives; and
4. A listing of agencies and person consulted
(c) Determine, based on an independent review of the EA, whether the proposed action will have a significant environmental impact. If FirstNet determines that the proposed action will not have a significant impact, FirstNet may issue a FONSI as described in 40 CFR 1508.13. However, if, after review of the EA, FirstNet determines that the proposed action will have a significant environmental impact, FirstNet will proceed with the preparation of an EIS.
FirstNet shall prepare an EIS when it determines that a proposed action significantly impacts the quality of the human environment or when the results of an EA indicate the proposed action will have significant impacts. Actions normally requiring the preparation of an EIS include:
(a) Major federal actions found to cause significant effects on the human
(b) Major federal actions occurring in the U.S. known to cause significant environmental effects on the global commons, such as the oceans or Antarctica, as described in EO 12114, Environmental Affects Abroad of Major Federal Actions.
(c) Actions required by statute or treaty to develop an EIS.
In preparing and EIS, FirstNet shall solicit public involvement and commenting as described in 40 CFR 1503.1–1503.4 after preparing a draft EIS and before preparing a final EIS. FirstNet shall also ensure the contents of an EIS contain the elements described in 40 CFR 1502.10–1502.18 and, unless FirstNet determines that there is a compelling reason to do otherwise shall follow the standard EIS format and include:
Finally, FirstNet shall prepare a concise public Record of Decision (ROD) in accordance with 40 CFR 1505.2.
To the fullest extent possible, FirstNet shall prepare NEPA reviews (i.e., CE, EA, EIS) concurrently with and integrated with environmental analyses and related surveys and studies required by the Fish and Wildlife Coordination Act (16 U.S.C. 661
FirstNet NEPA analyses shall assess cumulative effects, which are the impacts on the environment resulting from the incremental impact of the action when added to other past, present, and reasonable foreseeable future actions (40 CFR 1508.7).
FirstNet shall comply with Executive Order 12898, “Federal Actions to Address Environmental Justice in Minority and Low-Income Populations,” and determine whether the proposed action will have a disproportionate impact on minority or low-income communities.
The conclusion of the NEPA review process will result in one of the following environmental determinations or final decisions.
1. If a proposed action is determined to be a CE and not considered a routine administrative or personnel action, FirstNet shall document its determination that a CE applies to a proposed action with a memorandum to the file.
2. A Record of Environmental Consideration is a brief memorandum that is kept in the administrative record and should cite the categorical exclusion used and show that the agency determined: (1) The action fits within the category of actions described in the categorical exclusions; and (2) there are no extraordinary circumstances that would preclude the project or proposed action from qualifying as a categorically excluded action.
1. An EA results in either the issuance of FONSI or a determination to prepare an EIS. A FONSI is a document (40 CFR 1508.13) that briefly states why an action (not otherwise excluded) will not significantly affect the environment.
2. If the Chair or delegate determines, based on an independent review of the EA, that the proposed action will not have significant impact, FirstNet may issue a FONSI and proceed with the proposed action. However, if, after an independent review of the EA, it is determined by the Chair or a delegate that the proposed action will have a significant environmental impact, FirstNet will proceed with the preparation of an EIS.
1. When it is determined that an EIS is required, FirstNet's final decision relating to the proposed action will consider the environmental information provided in the EIS and require the preparation of an ROD. The ROD documents the final decision made and the basis for that decision. An ROD shall be prepared in accordance with 40 CFR 1505.2 for the final decision maker, whether the Chair or a delegate, for approval and signature.
2. FirstNet's implementation of the proposed action may begin immediately after approval of the ROD.
FirstNet, throughout the environmental review process, shall consider mitigation measures, as defined in 40 CFR 1508.20, to avoid or minimize environmental harm, where possible. In addition, the following actions will be taken to ensure proper implementation of mitigation measures:
(a) FirstNet shall ensure a discussion of mitigation measures essential to render the impacts of the proposed action not significant be included in or referenced in the FONSI and the ROD prior to making a final environmental determination or decision relating the significant of the impacts.
(b) FirstNet will not commit to mitigation measures considered or analyzed in environmental documentation if there are insufficient legal authorities, or it is not reasonable to foresee the availability of sufficient resources to perform or ensure the performance of the mitigation.
(c) Prior to and during the implementation of the action, FirstNet shall monitor project activities to ensure the proper execution of any mitigation measures or other conditions established and committed to in environmental documentation, as appropriate.
(d) If mitigation commitments made in NEPA and decision documents fail to achieve projected environmental outcomes and there is remaining federal action, FirstNet may utilize an adaptive management approach and take corrective actions to identify alternatives that could take the place of original mitigation commitments and provided the intended environmental result.
FirstNet shall tier environmental documents to eliminate repetitive discussions of the same issues and to focus on the actual issues ripe for decision at each level of environmental
FirstNet may prepare supplements to either the draft or final environmental documentation if:
(a) FirstNet makes substantial changes in the proposed action that are relevant to environmental concerns; or
(b) There are significant new circumstances or information relevant to environmental concerns and bearing on the proposed action or its impacts.
(c) FirstNet is relying upon an environmental review previously performed by another federal agency, with authority over the action or related activity of an applicant and (I) additional analysis is needed to address the reasonably foreseeable impacts of the action under consideration by FirstNet or (II) it adequately addresses the reasonably foreseeable impacts of the action under consideration by FirstNet.
FirstNet may implement an emergency NEPA process after determining there is a need for taking action that does not allow for time for the regular NEPA process and complying with NEPA. This section applies only if the NEPA Coordinator, in consultation with FirstNet General Counsel, determines that an emergency exists that makes it necessary to take urgently needed actions before preparing a NEPA analysis and documentation in accordance with the provisions in subparts D and E of this part.
(a) The NEPA Coordinator may take those actions necessary to control the immediate impacts of the emergency that are urgently needed to mitigate imminent harm to life, property, or important natural, cultural, or historic resources. When taking such actions, the Responsible Official shall take into account the probable environmental consequences of these actions and mitigate foreseeable adverse environmental effects to the extent practical.
(b) The NEPA Coordinator or designee shall document in writing the determination that an emergency exists and describe the responsive action(s) taken at the time the emergency exists. The form of that documentation is within the discretion of the Responsible Official.
(c) If the NEPA Coordinator determines that proposed actions taken in response to an emergency, beyond actions noted in paragraph (a) of this section, are not likely to have significant environmental impacts, the NEPA Coordinator or designee shall document that determination in an environmental assessment and a FONSI prepared in accordance with this part, unless categorically excluded. If the NEPA Coordinator finds that the nature and scope of the subsequent actions related to the emergency require taking such proposed actions prior to completing an EA and a FONSI, the NEPA Coordinator shall consult with the General Counsel about alternative arrangements for NEPA compliance. The NEPA Coordinator or designee may grant an alternative arrangement. Any alternative arrangement must be documented and notice of its use provided to CEQ.
(d) The NEPA Coordinator shall consult with CEQ about alternative arrangements as soon as possible if the Responsible Official determines that proposed actions taken in response to an emergency are likely to have significant environmental impacts. Such alternative arrangements will apply only to the proposed actions necessary to control the immediate impacts of the emergency. Other proposed actions remain subject to NEPA analysis and documentation in accordance with this part.
The effective date for the FirstNet NEPA implementation procedures is to be determined after the comment period.
(a) Statutes and Regulations that should be considered during the development of a NEPA review should include, but not be limited to:
1. National Environmental Policy Act (NEPA) of 1969, 42 U.S.C. 4321
2. CEQ Regulations for Implementing the Procedural Provisions of the National Environmental Policy Act, as codified at 40 CFR Parts 1500—1508.
3. Endangered Species Act of 1973, 16 U.S.C. 1531
4. Fish and Wildlife Coordination Act, 16 U.S.C. 661
5. National Historic Preservation Act of 1966, 16 U.S.C. 470
6. Migratory Bird Treaty Act of 1918, 16 U.S.C. 703
7. Clean Air Act of 1970, 42 U.S.C. 7401
8. Clean Water Act, 33 U.S.C. 1251
9. Coastal Zone Management Act of 1972, 16 U.S.C. 1451
10. Wild and Scenic Rivers Act of 1968, 16 U.S.C. 1271
11. Marine Mammal Protection Act of 1972, 16 U.S.C. 31
12. River and Harbors Act of 1899, 33 U.S.C. 401 and 403.
(b) Executive Orders that should be considered during the development of a NEPA review should include, but not be limited to:
1. E.O. No. 11988, Floodplain Management.
2. E.O. No. 12114, Environmental Effects Abroad of Major Federal Actions.
3. E.O. No. 11990, Protection of Wetlands.
4. E.O. No. 12898, Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations.
5. E.O. No. 13112, Invasive Species.
6. E.O. No. 13175, Consultation and Coordination with Indian Tribal Governments.
7. E.O. No. 13186, Responsibilities of Federal Agencies to Protect Migratory Birds.
(c) CEQ Guidance Documents that should be considered during the development of a NEPA review should include, but not be limited to:
1. “Memorandum for Heads of Federal Departments and Agencies: Improving the Process for Preparing Efficient and Timely Environmental Reviews Under the National Environmental Policy Act” (CEQ, 2012).
2. “Memorandum for Heads of Federal Departments and Agencies: Appropriate Use of Mitigation and Monitoring and Clarifying the Appropriate Use of Mitigated Findings of No Significant Impact” (CEQ, 2011).
3. “Memorandum for Heads of Federal Departments and Agencies: Establishing, Applying, and Revising Categorical Exclusions Under the National Environmental Policy Act” (CEQ, 2010).
4. “Memorandum for Heads of Federal Departments and Agencies: Emergencies and the National Environmental Policy Act” (CEQ, 2010).
5. “Aligning National Environmental Policy Act Processes with Environmental Management Systems” (CEQ/NEPA Task Force, 2007).
6. “Collaboration in NEPA: A Handbook for NEPA Practitioners” (CEQ/NEPA Task Force, 2007).
7. “Memorandum for Federal NEPA Contacts: Emergency Actions and NEPA” (CEQ, 2005).
8. “Memorandum for Federal NEPA Contacts: Emergency Actions and NEPA, Appendix 2: Preparing Focused, Concise and Timely Environmental Assessments” (CEQ, 2005).
9. “Guidance on the Consideration of Past Actions in Cumulative Effects Analysis” (CEQ, 2005).
10. “Modernizing NEPA Implementation” (CEQ/NEPA Task Force, 2003).
11. “CEQ Memorandum for Deputy/Assistant Heads of Federal Agencies: Identifying Non-Federal Cooperating Agencies in Implementing the Procedural Requirements of the National Environmental Policy Act” (CEQ, 2000).
12. “CEQ Memorandum for Heads of Federal Agencies: Designation of Non-
13. “Considering Cumulative Effects Under the National Environmental Policy Act” (CEQ, 1997).
14. “Environmental Justice: Guidance Under the National Environmental Policy Act” (CEQ, 1997).
15. “CEQ Guidance on NEPA Analyses for Transboundary Impacts” (CEQ, 1997).
16. “Memorandum to Heads of Federal Departments and Agencies Regarding Pollution Prevention and the National Environmental Policy Act” (CEQ, 1993).
17. “Incorporating Biodiversity Considerations into Environmental Impact Analysis Under the National Environmental Policy Act” (CEQ, 1993).
18. “CEQ Guidance Regarding NEPA Regulations” (CEQ, 1983).
19. “Forty Most Asked Questions Concerning CEQ's NEPA Regulations” (CEQ, 1981).
20. “Guidance on Applying Section 404(r) of the Clean Water Act to Federal Projects Which Involve the Discharge of Dredged or Fill Materials into Waters of the U.S., Including Wetlands” (CEQ, 1980).
21. “Environmental Effects Abroad of Major Federal Actions, Executive Order 12114; Implementing and Explanatory Documents” (CEQ, 1979).
22. “CEQ Memorandum for Heads of Agencies: Implementation of Executive Order 11988 on Floodplain Management and Executive Order 11990 on Protection of Wetlands” (CEQ, 1978).
23. “Environmental Review Pursuant to Section 1424(e) of the Safe Drinking Water Act of 1974 and its Relationship to NEPA” (CEQ, 1976).
All terminology and definitions contained in 40 CFR Parts 1500–1508 are incorporated into this Directive. The following definitions are provided for other terms and phrases used.
(a)
(b)
(c)
(d)
(e)
(f)
(g)
(h)
(i)
(j)
(k)
(l)
(m)
A.1: The issuance of bulletins and information publications that do not concern environmental matters or substantial facility design, construction, or maintenance practices.
A.2: Procurement activities related to the operation of FirstNet.
A.3: Personnel and Administrative Actions.
A.4: Purchase of existing facilities or a portion thereof where use or operation will remain unchanged.
A.5: Internal modifications or equipment additions (
A.6: Construction of buried and aerial telecommunications lines, cables, and related facilities.
A.7: Construction of microwave facilities involving no more than five acres (2 hectares) of physical disturbance at any single site.
A.8: Construction of cooperative or company headquarters, maintenance facilities, or other buildings involving no more than 10 acres (4 hectares) of physical disturbance or fenced property.
A.9: Changes to existing transmission lines that involve less than 20 percent pole replacement, or the complete rebuilding of existing distribution lines within the same right of way. Changes to existing transmission lines that require 20 percent or greater pole replacement will be considered the same as new construction.
A.10: Changes or additions to existing substations, switching stations, telecommunications switching or multiplexing centers, or external changes to buildings or small structures requiring one acre (0.4 hectare) or more but no more than five acres (2 hectares) of new physically disturbed land or fenced property.
A.11: Construction of substations, switching stations, or telecommunications switching or multiplexing centers requiring no more than five acres (2 hectares) of new physically disturbed land or fenced property.
A.12: Changes or additions to microwave sites, substations, switching stations, telecommunications switching or multiplexing centers, buildings, or small structures requiring new physical disturbance or fencing of less than one acre (0.4 hectare).
A.13: Ordinary maintenance or replacement of equipment or small structures (
A.14: The construction of telecommunications facilities within the
A.15: Testing or monitoring work (
A.16: Studies and engineering undertaken to define proposed actions or alternatives sufficiently so that environmental effects can be assessed.
A.17: Rebuilding of power lines or telecommunications cables where road or highway reconstruction requires the applicant to relocate the lines either within or adjacent to the new road or highway easement or right-of-way.
A.18: Phase or voltage conversions, reconductoring or upgrading of existing electric distribution lines, or telecommunication facilities.
A.19: Construction of standby diesel electric generators (one megawatt or less total capacity) and associated facilities, for the primary purpose of providing emergency power, at an existing applicant headquarters or district office, telecommunications switching or multiplexing site, or at an industrial, commercial, or agricultural facility served by the applicant.
Extraordinary circumstances that preclude the use of a CE include:
(a) Reasonable likelihood of significant impact on public health or safety.
(b) Reasonable likelihood of significant environmental effects (direct, indirect, and cumulative).
(c) Reasonable likelihood of effects on the environment that are highly uncertain, unique, or are scientifically controversial.
(d) Reasonable likelihood of violating any federal, state, or local law or requirements imposed for the protection of the environment.
(e) Reasonable likelihood of adversely affecting “environmentally sensitive” resources, unless the impact has been resolved through another environmental process (
Environmentally sensitive resources include:
1. Proposed federally listed, threatened, or endangered species or their designated critical habitat.
2. Properties listed or eligible for listing on the National Register of Historic Places.
3. Areas having special designation or recognition such as prime or unique or agricultural lands; designated wilderness or wilderness study areas; wild and scenic rivers; National Historic Landmarks (designated by the Secretary of the Interior); 100-year floodplains; wetlands; sole source aquifers (potential sources of drinking water); National Wildlife Refuges; National Parks; areas of critical environmental concern; or other areas of high environmental sensitivity.
(f) Reasonable likelihood of adversely impacting water quality, sole source aquifers, public water supply systems or state, local, or tribal water quality standards established under the Clean Water Act and the Safe Drinking Water Act.
(g) Reasonable likelihood of effects on the quality of the environment that is highly controversial on environmental grounds. The term “controversial” means a substantial dispute exists as to the size, nature, or effect of the proposed action rather than to the existence of opposition to a proposed action, the effect of which is relatively undisputed.
(h) Reasonable likelihood of a disproportionately high and adverse effect on low income or minority populations (
(i) Limited access to and ceremonial use of Indian sacred sites on Federal lands by Indian religious practitioners or significantly adversely affect the physical integrity of such sacred sites.
(j) A greater scope or size than is normal for this category of action.
(k) Reasonable likelihood of degrading already existing poor environmental conditions. Also, initiation of a degrading influence, activity, or effect in areas not already significantly modified from their natural condition.
(l) Introduction or employment of unproven technology.
Office of the Assistant Secretary of Defense for Health Affairs, DoD.
Notice.
In compliance with Section 3506(c)(2)(A) of the
Consideration will be given to all comments received by March 10, 2014.
You may submit comments, identified by docket number and title, by any of the following methods:
•
•
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to Naval Health Research Center, DoD Center for Deployment Health Research, Department 164, ATTN: Martin White, MPH, 140 Sylvester Rd., San Diego, CA 92106–3521, or call (619) 553–9292.
Persons eligible to respond to this survey are those civilians now separated from military service who initially enrolled, gave consent, and participated in the Millennium Cohort Study while on active duty in the Army, Navy, Air Force, Marine Corps or US Coast Guard during the first, second, third, or fourth panel enrollment periods in 2001–2003, 2004–2006, 2007–2008, or 2011–2012 respectively, as well as civilians that choose to participate in the Millennium Cohort Family Study.
Office of Special Education and Rehabilitative Services; Department of Education.
Notice.
The Secretary is publishing the following list of correspondence from the U.S. Department of Education (Department) to individuals during the previous quarter. The correspondence describes the Department's interpretations of the Individuals with Disabilities Education Act (IDEA) or the regulations that implement the IDEA. This list and the letters or other documents described in this list, with personally identifiable information redacted, as appropriate, can be found at:
Jessica Spataro or Mary Louise Dirrigl. Telephone: (202) 245–7605.
If you use a telecommunications device for the deaf (TDD) or a text telephone (TTY), you can call the Federal Relay Service (FRS), toll free, at 1–800–877–8339.
Individuals with disabilities can obtain a copy of this list and the letters or other documents described in this list in an accessible format (e.g., braille, large print, audiotape, or compact disc) by contacting Jessica Spataro or Mary Louise Dirrigl at (202) 245–7605.
The following list identifies correspondence from the Department issued from January 1, 2013, through March 31, 2013. Under section 607(f) of the IDEA, the Secretary is required to publish this list quarterly in the
○ Letter dated February 4, 2013, to New Jersey Catholic Conference Education Director George Corwell, regarding children with disabilities from other countries who are enrolled in private schools by their parents.
○ Letter dated January 30, 2013, to Minnesota Department of Education Funding and Data Manager Carol Hokenson, regarding coordinated early intervening services and local educational agency (LEA) maintenance of effort requirements in Part B of the IDEA.
○ Letter dated March 7, 2013, to Wisconsin Department of Public Instruction Assistant Director of Special Education Troy Couillard, regarding the circumstances under which an LEA may use Part B funds for services for nondisabled children.
○ Letter dated March 27, 2013, to North Carolina attorney K. Dean Shatley, regarding court-appointed surrogate parents.
○ Letter dated March 27, 2013, to New York attorney William J. Casey, regarding the purpose of resolution sessions.
○ Letter dated March 27, 2013, to District of Columbia Office of the State Superintendent of Education Assistant Superintendent Amy Maisterra, regarding the requirements in Part B of the IDEA that apply to children with disabilities educated at the Laurent Clerc National Deaf Education Center, as specified in the Education of the Deaf Act of 1986, as amended.
You may also access documents of the Department published in the
Take notice that the Commission received the following electric rate filings:
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
Take notice that the Commission received the following electric rate filings:
Take notice that the Commission received the following electric securities 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 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
Take notice that the Commission has received the following Natural Gas Pipeline Rate and Refund Report filings:
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 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
Any person desiring to protest in any of the above proceedings must file in accordance with Rule 211 of the Commission's Regulations (18 CFR 385.211) on or before 5 p.m. Eastern time on the specified comment date.
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
This is a supplemental notice in the above-referenced proceeding of ALLETE Clean Energy, Inc.'s application for market-based rate authority, with an accompanying rate tariff, noting that such application includes a request for blanket authorization, under 18 CFR Part 34, of future issuances of securities and assumptions of liability.
Any person desiring to intervene or to protest should file with the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214). Anyone filing a motion to intervene or protest must serve a copy of that document on the Applicant.
Notice is hereby given that the deadline for filing protests with regard to the applicant's request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability, is January 22, 2014.
The Commission encourages electronic submission of protests and interventions in lieu of paper, using the FERC Online links at
Persons unable to file electronically should submit an original and 5 copies of the intervention or protest to the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426.
The filings in the above-referenced proceeding are accessible in the Commission's eLibrary system by clicking on the appropriate link in the above list. They are also available for review in the Commission's Public Reference Room in Washington, DC. There is an eSubscription link on the Web site that enables subscribers to receive email notification when a document is added to a subscribed docket(s). For assistance with any FERC Online service, please email
Environmental Protection Agency (EPA).
Notice of Public Advisory Committee Teleconference.
Pursuant to the Federal Advisory Committee Act, Public Law 92–463, notice is hereby given that the Good Neighbor Environmental Board (GNEB) will hold a public teleconference on Friday, January 31, 2014. The meeting will take place from 12 p.m. to 4 p.m. Eastern Standard Time. The meeting is open to the public. For further information regarding the teleconference and background materials, please contact Ann-Marie Gantner at the number listed below.
Friday, January 31, 2014. The meeting will take place from 12 p.m. to 4 p.m. Eastern Standard Time.
If you wish to make oral comments or submit written comments to the Board, please contact Ann-Marie Gantner at least five days prior to the meeting. Written comments should be submitted at
Environmental Protection Agency (EPA).
Notice.
This notice announces EPA's order for the cancellations, voluntarily requested by the registrants and accepted by the Agency, of the products listed in Table 1 of Unit II., pursuant to the Federal Insecticide, Fungicide, and Rodenticide Act (FIFRA). This cancellation order follows a June 12, 2013,
The cancellations are effective January 8, 2014.
John W. Pates, Jr., Pesticide Re-Evaluation Division (7508P), Office of Pesticide Programs, Environmental Protection Agency, 1200 Pennsylvania Ave. NW.,
This action is directed to the public in general, and may be of interest to a wide range of stakeholders including environmental, human health, and agricultural advocates; the chemical industry; pesticide users; and members of the public interested in the sale, distribution, or use of pesticides. Since others also may be interested, the Agency has not attempted to describe all the specific entities that may be affected by this action.
The docket for this action, identified by docket identification (ID) number EPA–HQ–OPP–2010–0014, is available at
This notice announces the cancellation, as requested by registrants, of products registered under FIFRA section 3. These registrations are listed in sequence by registration number in Table 1 of this unit.
Table 2 of this unit includes the names and addresses of record for all registrants of the products in Table 1 of this unit, in sequence by EPA company number. This number corresponds to the first part of the EPA registration numbers of the products listed in Table 1 of this unit.
During the public comment period provided, EPA received no comments in response to the June 12, 2013,
Pursuant to FIFRA section 6(f), EPA hereby approves the requested cancellations of the registrations identified in Table 1 of Unit II. Accordingly, the Agency hereby orders that the product registrations identified in Table 1 of Unit II. are canceled. The effective date of the cancellations that are the subject of this notice is January 8, 2014. Any distribution, sale, or use of existing stocks of the products identified in Table 1 of Unit II. in a manner inconsistent with any of the provisions for disposition of existing stocks set forth in Unit VI. will be a violation of FIFRA.
Section 6(f)(1) of FIFRA provides that a registrant of a pesticide product may at any time request that any of its pesticide registrations be canceled or amended to terminate one or more uses. FIFRA further provides that, before acting on the request, EPA must publish a notice of receipt of any such request in the
Existing stocks are those stocks of registered pesticide products which are currently in the United States and which were packaged, labeled, and released for shipment prior to the effective date of the cancellation action. The existing stocks provisions for the products subject to this order are as follows.
The registrants may continue to sell and distribute existing stocks of products listed in Table 1 of Unit II. until January 8, 2015, which is 1 year after the publication of the Cancellation Order in the
Environmental protection, Pesticides and pests.
In accordance with section 10(a)(2) of the Federal Advisory Committee Act (Pub. L. 92–463), the Centers for Disease Control and Prevention (CDC) announces the following meeting of the aforementioned subcommittee:
The agenda is subject to change as priorities dictate.
The Director, Management Analysis and Services Office, has been delegated the authority to sign
In accordance with section 10(a)(2) of the Federal Advisory Committee Act (Pub. L. 92–463), and pursuant to the requirements of 42 CFR 83.15(a), the Centers for Disease Control and Prevention (CDC), announces the following meeting of the Advisory Board on Radiation and Worker Health (ABRWH or Advisory Board), National Institute for Occupational Safety and Health (NIOSH):
*
In December 2000, the President delegated responsibility for funding, staffing, and operating the Advisory Board to HHS, which subsequently delegated this authority to the CDC. NIOSH implements this responsibility for CDC. The charter was issued on August 3, 2001, renewed at appropriate intervals, and will expire on August 3, 2015.
The agenda is subject to change as priorities dictate.
In the event an individual cannot attend, written comments may be submitted in accordance with the redaction policy provided below. Any written comments received will be provided at the meeting and should be submitted to the contact person below well in advance of the meeting.
Policy on Redaction of Board Meeting Transcripts (Public Comment): (1) If a person making a comment gives his or her personal information, no attempt will be made to redact the name; however, NIOSH will redact other personally identifiable information, such as contact information, social security numbers, case numbers, etc., of the commenter.
(2) If an individual in making a statement reveals personal information (e.g., medical or employment information) about themselves that information will not usually be redacted. The NIOSH Freedom of Information Act (FOIA) coordinator will, however, review such revelations in accordance with the Federal Advisory Committee Act and if deemed appropriate, will redact such information.
(3) If a commenter reveals personal information concerning a living third party, that information will be reviewed by the NIOSH FOIA coordinator, and upon determination, if deemed appropriate, such information will be redacted, unless the disclosure is made by the third party's authorized representative under the Energy Employees Occupational Illness Compensation Program Act (EEOICPA) program.
(4) In general, information concerning a deceased third party may be disclosed; however, such information will be redacted if (a) the disclosure is made by an individual other than the survivor claimant, a parent, spouse, or child, or the authorized representative of the deceased third party; (b)
The Board will take reasonable steps to ensure that individuals making public comment are aware of the fact that their comments (including their name, if provided) will appear in a transcript of the meeting posted on a public Web site. Such reasonable steps include: (a) A statement read at the start of each public comment period stating that transcripts will be posted and names of speakers will not be redacted; (b) A printed copy of the statement mentioned in (a) above will be displayed on the table where individuals sign up to make public comments; (c) A statement such as outlined in (a) above will also appear with the agenda for a Board Meeting when it is posted on the NIOSH Web site; (d) A statement such as in (a) above will appear in the
The Director, Management Analysis and Services Office, has been delegated the authority to sign
The Centers for Disease Control and Prevention (CDC) is soliciting nominations for possible membership on the CDC/HRSA Advisory Committee on HIV, Viral Hepatitis and STD Prevention and Treatment (CHACHSPT).
The CHACHSPT provides advice to the Secretary, HHS; the Director, CDC; and the Administrator, Health Resources and Services Administration (HRSA), on objectives, strategies, policies, and priorities for HIV, Viral Hepatitis, and STD prevention and treatment efforts including surveillance of HIV infection, AIDS, Viral Hepatitis, other STDs, and related behaviors; epidemiologic, behavioral, health services, and laboratory research on HIV/AIDS, Viral Hepatitis, and other STDs; identification of policy issues related to HIV/Viral Hepatitis/STD professional education, patient healthcare delivery, and prevention services; agency policies about prevention of HIV/AIDS, Viral Hepatitis and other STDs, treatment, healthcare delivery, and research and training; strategic issues influencing the ability of CDC and HRSA to fulfill their missions of providing prevention and treatment services; programmatic efforts to prevent and treat HIV, Viral Hepatitis, and other STDs; and support to the agencies in their development of responses to emerging health needs related to HIV, Viral Hepatitis and other STDs.
The CHACHSPT consists of 18 experts knowledgeable in the fields of public health, epidemiology, laboratory practices, immunology, infectious diseases, drug abuse, behavioral science, health education, healthcare delivery, state health programs, clinical care, preventive health, medical education, health services and clinical research, and healthcare financing, who are selected by the Secretary of the U.S. Department of Health and Human Services (HHS).
Nominations are being sought for individuals who have expertise and qualifications necessary to contribute to the accomplishments of the Committee's objectives.
Nominees will be selected from experts having experience in HIV/AIDS, Viral Hepatitis and STD prevention, control and treatment. Experts in the disciplines of epidemiology, laboratory practice, immunology, infectious diseases, drug abuse, behavioral science, health education, healthcare delivery, state health programs, clinical care, preventive health, medical education, health services and clinical research, healthcare financing and other related disciplines will be considered. The committee shall have at least four members who shall be persons living with HIV/AIDS.
Members may be invited to serve for terms of up to four years. The HHS policy stipulates that committee membership be balanced in terms of professional training and background, points of view represented and the committee's function. Consideration is given to a broad representation of geographic areas within the U.S., with equitable representation of the sexes, ethnic and racial minorities, and persons with disabilities. Nominees must be U.S. citizens, and cannot be full-time employees of the U.S. Government.
Candidates should submit the following items:
• Current
• A letter of recommendation from person(s) not employed by the U.S. Department of Health and Human Services
• A statement indicating the nominee's willingness to serve as a potential member of the Committee.
Nominations should be submitted electronically to
The Director, Management Analysis and Services Office, has been delegated the authority to sign
The Centers for Disease Control and Prevention (CDC) is soliciting nominations for possible membership on the Advisory Council for the Elimination of Tuberculosis (ACET).
ACET provides advice and recommendations to the Secretary, Department of Health and Human Services (HHS); the Assistant Secretary of Health; and the Director, CDC, regarding program policies, strategies, objectives, and priorities; address the development and application of new
ACET consists of 10 experts knowledgeable in the fields of public Health, epidemiology, immunology, infectious diseases, pulmonary disease, pediatrics, tuberculosis, microbiology, or preventive health care delivery, who are selected by the Secretary of the United State Department of Health and Human Services.
Nominations are being sought for individuals who have expertise and qualifications necessary to contribute to the accomplishments of the Council's objectives.
Nominees will be selected from experts having experience in tuberculosis prevention and control.
Experts in the disciplines of epidemiology, immunology, infectious diseases, pulmonary disease, pediatrics, tuberculosis, microbiology, preventive health care delivery, and experts in public health and other related disciplines will be considered. Members may be invited to serve up to four-year terms. The HHS policy stipulates that committee membership be balanced in terms of professional training and background, points of view represented and the council's function. Consideration is given to a broad representation of geographic areas within the U.S., with equitable representation of the sexes, ethnic and racial minorities, and persons with disabilities. Nominees must be U.S. citizens, and cannot be full-time employees of the U.S. Government.
Candidates should submit the following items:
• Current curriculum vitae, including complete contact information (telephone numbers, mailing address, email address)
• A letter of recommendation from person(s) not employed by the U.S. Department of Health and Human Services
• A statement indicating the nominee's willingness to serve as a potential member of the Council.
Nominations should be submitted electronically or in writing, and must be postmarked by September 30, 2014, to: Margie Scott-Cseh, Committee Management Specialist, NCHHSTP, CDC, 1600 Clifton Road NE., Mailstop: E07, Atlanta, GA 30333, Email address:
The Director, Management Analysis and Services Office, has been delegated the authority to sign
Administration for Community Living, HHS.
Notice.
The Administration for Community Living (ACL) is announcing that the proposed collection of information listed below has been submitted to the Office of Management and Budget (OMB) for review and clearance under the Paperwork Reduction Act of 1995.
Submit written comments on the collection of information by February 7, 2014.
Submit written comments on the collection of information by fax 202.395.6974 or by mail to the Office of Information and Regulatory Affairs, OMB, New Executive Office Bldg., 725 17th St. NW., Rm. 10235, Washington, DC 20503, Attn: Carolyn Lovett, Desk Officer for ACL.
Lori Stalbaum, (202) 357–3452 or
In compliance with 44 U.S.C. 3507, ACL has submitted the following proposed collection of information to OMB for review and clearance.
ACL is requesting an extension of the currently approved Administration on Aging (AoA) Funding Opportunity Announcement and Application Instructions Template for use for all ACL Discretionary Grant Programs, of which AoA is now a program center. This template provides the requirements and instructions for the submission of an application for discretionary grants funding opportunities. The template may be found on the ACL Web site at
Food and Drug Administration, HHS.
Notice.
This notice announces a forthcoming meeting of a public advisory committee of the Food and Drug Administration (FDA). The meeting will be open to the public.
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
Persons attending FDA's advisory committee meetings are advised that the Agency is not responsible for providing access to electrical outlets.
FDA welcomes the attendance of the public at its advisory committee meetings and will make every effort to accommodate persons with physical disabilities or special needs. If you require special accommodations due to a disability, please contact Glendolynn S. Johnson at least 7 days in advance of the meeting.
FDA is committed to the orderly conduct of its advisory committee meetings. Please visit our Web site at
Notice of this meeting is given under the Federal Advisory Committee Act (5 U.S.C. app. 2).
Food and Drug Administration, HHS.
Notice.
This notice announces a forthcoming meeting of a public advisory committee of the Food and Drug Administration (FDA). The meeting will be open to the public.
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
Persons attending FDA's advisory committee meetings are advised that the Agency is not responsible for providing access to electrical outlets.
FDA welcomes the attendance of the public at its advisory committee meetings and will make every effort to accommodate persons with physical disabilities or special needs. If you require special accommodations due to a disability, please contact James Clark, Committee Management Staff,
FDA is committed to the orderly conduct of its advisory committee meetings. Please visit our Web site at
Notice of this meeting is given under the Federal Advisory Committee Act (5 U.S.C. app. 2).
Food and Drug Administration, HHS.
Notice.
This notice announces a forthcoming meeting of public advisory committees of the Food and Drug Administration (FDA). The meeting will be open to the public.
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
Persons attending FDA's advisory committee meetings are advised that the Agency is not responsible for providing access to electrical outlets.
FDA welcomes the attendance of the public at its advisory committee meetings and will make every effort to accommodate persons with physical disabilities or special needs. If you require special accommodations due to a disability, please contact Glendolynn S. Johnson at least 7 days in advance of the meeting.
FDA is committed to the orderly conduct of its advisory committee meetings. Please visit our Web site at
Notice of this meeting is given under the Federal Advisory Committee Act (5 U.S.C. app. 2).
Food and Drug Administration, HHS.
Notice.
This notice announces a forthcoming meeting of a public advisory committee of the Food and Drug Administration (FDA). The meeting will be open to the public.
A notice in the
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
Persons attending FDA's advisory committee meetings are advised that the Agency is not responsible for providing access to electrical outlets.
FDA welcomes the attendance of the public at its advisory committee meetings and will make every effort to accommodate persons with physical disabilities or special needs. If you require special accommodations due to a disability, please contact Kristina Toliver at least 7 days in advance of the meeting.
FDA is committed to the orderly conduct of its advisory committee meetings. Please visit our Web site at
Notice of this meeting is given under the Federal Advisory Committee Act (5 U.S.C. app. 2).
Food and Drug Administration, HHS.
Notice.
This notice announces a forthcoming meeting of public advisory committees of the Food and Drug Administration
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
Persons attending FDA's advisory committee meetings are advised that the Agency is not responsible for providing access to electrical outlets.
FDA welcomes the attendance of the public at its advisory committee meetings and will make every effort to accommodate persons with physical disabilities or special needs. If you require special accommodations due to a disability, please contact Stephanie L. Begansky at least 7 days in advance of the meeting.
FDA is committed to the orderly conduct of its advisory committee meetings. Please visit our Web site at
Notice of this meeting is given under the Federal Advisory Committee Act (5 U.S.C. app. 2).
Federal Emergency Management Agency, DHS.
Notice.
The Federal Emergency Management Agency, 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 a revision of a currently approved information collection. In accordance with the Paperwork Reduction Act of 1995, this notice seeks comments concerning FEMA grant administration forms used in disaster and non-disaster grant programs.
Comments must be submitted on or before March 10, 2014.
To avoid duplicate submissions to the docket, please use only one of the following means to submit comments:
(1)
(2)
(3)
All submissions received must include the agency name and Docket ID. Regardless of the method used for submitting comments or material, all submissions will be posted, without change, to the Federal eRulemaking Portal at
Pamela Greene, Assistance Officer, Protection and National Preparedness, Grant Program Directorate, (202) 786–9519. You may contact the Records Management Division for copies of the proposed collection of information at facsimile number (202) 646–3347 or
Title 44 CFR, Part 13, Uniform Administrative Requirements for Grants and Cooperative Agreements to State and Local Government establishes uniform administrative rules for Federal grants and cooperative agreements and sub-awards to State, local and Indian tribal governments. FEMA, in coordination with the Department of Homeland Security (DHS), has determined that in order to have consistent implementation of FEMA grant administration policies and to minimize the administrative disruption for State and local partners, it is necessary to standardize FEMA grant administration forms used in FEMA grant programs. FEMA in close consultation with DHS Grants Policy and Oversight office will maintain its current grant forms. The forms are designed to collect information of an administrative or financial nature. Other supplementary grant program information used to determine issues related to eligibility and program management are collected separately with an approved OMB clearance.
OMB Circular A–133 requires recipients that expend a specified amount in a year in Federal funds must have an independent auditor perform a single or program-specific audit for that year. Executive Order 12372 established that States which have established a review and comment procedure be given opportunity to evaluate all applications submitted.
The American Recovery and Reinvestment Act of 2009, Public Law 111–5, was created to promote financial stimulus throughout the United States. Opportunities include funding for port security and bus and rail projects. Funds from this Act can be in the form of grant opportunities or outright purchases, depending upon the program and the funding allocation.
Comments may be submitted as indicated in the
Federal Emergency Management Agency, DHS.
Notice.
This is a notice of the Presidential declaration of a major disaster for the State of Texas (FEMA–4159–DR), dated December 20, 2013, and related determinations.
Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW., Washington, DC 20472, (202) 646–2833.
Notice is hereby given that, in a letter dated December 20, 2013, the President issued a major disaster declaration under the authority of the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121
I have determined that the damage in certain areas of the State of Texas resulting from severe storms and flooding during the period of October 30–31, 2013, is of sufficient severity and magnitude to warrant a major disaster declaration under the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121 et seq. (the “Stafford Act”). Therefore, I declare that such a major disaster exists in the State of Texas.
In order to provide Federal assistance, you are hereby authorized to allocate from funds available for these purposes such amounts as you find necessary for Federal disaster assistance and administrative expenses.
You are authorized to provide Public Assistance in the designated areas and Hazard Mitigation throughout the State. Consistent with the requirement that Federal assistance be supplemental, any Federal funds provided under the Stafford Act for Hazard Mitigation will be limited to 75 percent of the total eligible costs. Federal funds provided under the Stafford Act for Public Assistance also will be limited to 75 percent of the total eligible costs, with the
Further, you are authorized to make changes to this declaration for the approved assistance to the extent allowable under the Stafford Act.
The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, William J. Doran III, of FEMA is appointed to act as the Federal Coordinating Officer for this major disaster.
The following areas of the State of Texas have been designated as adversely affected by this major disaster:
Caldwell, Hays, and Travis Counties for Public Assistance.
All counties within the State of Texas are eligible to apply for assistance under the Hazard Mitigation Grant Program.
(The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households in Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.)
Fish and Wildlife Service, Interior.
Notice of availability of the low-effect screening form supporting a categorical exclusion, draft low-effect habitat conservation plan, incidental take permit application, and request for comments.
We, the U.S. Fish and Wildlife Service (Service), announce the availability of the low-effect screening form (LESF) under the National Environmental Policy Act (NEPA) of 1969, that supports a categorical exclusion for the draft Low-Effect Habitat Conservation Plan (dHCP), and the incidental take permit application for the Bosque Canyon Ranch in Bosque County, TX. The Bosque Canyon Ranch (Applicant), has applied for an incidental take permit (ITP) under Section 10(a)(1)(B) of the Endangered Species Act (Act) of 1973, as amended. The requested permit, which would be in effect for a period of 50 years, if granted, would authorize incidental take of the golden-cheeked warbler (
•
•
•
○ Department of the Interior, Natural Resources Library, 1849 C. St. NW., Washington, DC 20240.
○ U.S. Fish and Wildlife Service, 500 Gold Avenue SW., Room 6034, Albuquerque, NM 87102.
○ U.S. Fish and Wildlife Service, 2005 NE. Green Oaks Blvd., Suite 140, TX 76006; calling 817–277–1100.; or faxing 817–277–1129.
Persons wishing to review the application may obtain a copy by writing to the Regional Director, U.S. Fish and Wildlife Service, P.O. Box 1306, Room 4012, Albuquerque, NM 87103, Attention: Branch Chief, Environmental Review.
•
•
We request that you send comments by only the methods described above. We will post all information received on
Debra Bills, Field Supervisor, U.S. Fish and Wildlife Service, 2005 NE. Green Oaks Blvd., Suite 140, TX 76006; or by telephone at 817–277–1100.
In accordance with the requirements of the National Environmental Policy Act of 1969 (NEPA) (42 U.S.C. 4321
1. We have gathered the information necessary to determine impacts related to potential issuance of an incidental take permit (ITP) and have determined the proposed action qualifies as a low-effect HCP and is categorically excluded from the NEPA process; and,
2. The applicant has developed and proposes to implement its dHCP, as part of the application for an ITP, which describes the measures the applicant has agreed to take to minimize and mitigate the effects of incidental take of golden-cheeked warblers to the maximum extent practicable pursuant to section 10(a)(1)(B) of the Endangered Species Act of 1973 (Act), as amended (16 U.S.C. 1531
The requested permit, which would be in effect for a period of 50 years, if granted, would authorize incidental take of the golden-cheeked warbler (
Section 9 of the Act and its implementing regulations prohibit “take” of fish and wildlife species listed as threatened or endangered under section 4 of the Act. However, section 10(a) of the Act authorizes us to issue permits to take listed wildlife species where such take is incidental to, and not the purpose of, otherwise lawful activities and where the applicant meets certain statutory requirements.
Written comments we receive become part of the public record associated with this action. 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 request in your comment that we withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so. We will not consider anonymous comments. All submissions from organizations or businesses, and from individuals identifying themselves as representatives or officials of organizations or businesses, will be made available for public disclosure in their entirety.
We provide this notice under section 10(c) of the Act (16 U.S.C. 1531
National Park Service, Interior.
Notice of renewal.
The Secretary of the Interior is giving notice of the renewal of the Denali National Park and Preserve Aircraft Overflights Advisory Council. The Council provides advice and recommendations on mitigation of impacts from aircraft overflights at Denali National Park and Preserve.
Miriam Valentine, Chief of Planning and Environmental Compliance, Denali Park and Preserve, 240 W. 5th Avenue, Anchorage, Alaska 99501, (907) 733–9102.
The Denali National Park and Preserve Aircraft Overflights Advisory Council has been established in accordance with the Denali National Park and Preserve's
United States International Trade Commission.
Notice.
The Commission hereby gives notice of the institution of investigations and commencement of preliminary phase antidumping and countervailing duty investigations Nos. 701–TA–511 and 731–TA–1246–1247 (Preliminary) under sections 703(a) and 733(a) of the Tariff Act of 1930 (19 U.S.C. 1671b(a) and 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 China and Taiwan of certain crystalline silicon photovoltaic products, provided for in subheading 8541.40.60 (statistical reporting numbers 8541.40.60.20 or 8541.40.60.30 of the Harmonized Tariff Schedule of the United States, that are alleged to be sold in the United States at less than fair value and alleged to be subsidized by the Government of China. Unless the Department of Commerce extends the time for initiation pursuant to sections 702(c)(1)(B) or 732(c)(1)(B) of the Act (19 U.S.C. 1671a(c)(1)(B) or 1673a(c)(1)(B)), the Commission must
Effective December 31, 2013.
Chris Cassise (202–708–5408), Office of Investigations, U.S. International Trade Commission, 500 E Street SW., Washington, DC 20436. Hearing-impaired persons can obtain information on this matter by contacting the Commission's TDD terminal on 202–205–1810. Persons with mobility impairments who will need special assistance in gaining access to the Commission should contact the Office of the Secretary at 202–205–2000. General information concerning the Commission may also be obtained by accessing its internet server (
For further information concerning the conduct of these investigations and rules of general application, consult the Commission's Rules of Practice and Procedure, part 201, subparts A through E (19 CFR part 201), and part 207, subparts A and B (19 CFR part 207).
In accordance with sections 201.16(c) and 207.3 of the rules, each document filed by a party to the investigations must be served on all other parties to the investigations (as identified by either the public or BPI service list), and a certificate of service must be timely filed. The Secretary will not accept a document for filing without a certificate of service.
These investigations are being conducted under authority of title VII of the Tariff Act of 1930; this notice is published pursuant to section 207.12 of the Commission's rules.
By order of the Commission.
Judicial Conference of the United States, Advisory Committee on Rules of Bankruptcy Procedure.
Notice of Cancellation of Open Hearing.
The following public hearing on proposed amendments to the Federal Rules of Bankruptcy Procedure has been canceled: Bankruptcy Rules Hearing, January 31, 2014, Washington, DC
Jonathan C. Rose, Secretary and Chief Rules Officer, Rules Committee Support Office, Administrative Office of the United States Courts, Washington, DC 20544, telephone (202) 502–1820.
By Notice dated September 9, 2013, and published in the
The company plans to import small quantities of the listed controlled substances for the manufacture of analytical reference standards.
In reference to drug codes 7360 and 7370, the company plans to import a synthetic cannabidiol and a synthetic tetrahydrocannabinol. No other activities for these drug codes are authorized for this registration.
Comments and requests for hearings on applications to import narcotic raw material are not appropriate. 72 FR 3417(2007)
DEA has considered the factors in 21 U.S.C. 823(a) and 952(a) and determined that the registration of Cerilliant Corporation to import the basic classes of controlled substances is consistent with the public interest and with United States obligations under international treaties, conventions, or protocols in effect on May 1, 1971. DEA has investigated Cerilliant Corporation to ensure that the company's registration is consistent with the public interest. The investigation has included inspection and testing of the company's physical security systems, verification of the company's compliance with state and local laws, and a review of the company's background and history. Therefore, pursuant to 21 U.S.C. 952(a) and 958(a), and in accordance with 21 CFR 1301.34, the above named company is granted registration as an importer of the basic classes of controlled substances listed.
Pursuant to 21 CFR 1301.33(a), this is notice that on July 4, 2013, Noramco, Inc., 1440 Olympic Drive, Athens, Georgia 30601, made application by renewal to the Drug Enforcement Administration (DEA) to be registered as a bulk manufacturer of the following basic classes of controlled substances:
The company plans to manufacture the listed controlled substances in bulk for distribution to its customers.
Any other such applicant, and any person who is presently registered with DEA to manufacture such substance, may file comments or objections to the issuance of the proposed registration pursuant to 21 CFR 1301.33(a).
Any such written comments or objections should be addressed, in quintuplicate, to the Drug Enforcement Administrator, Office of Diversion Control, Federal Register Representative (ODW), 8701 Morrissette Drive, Springfield, Virginia 22152; and must be filed no later than March 10, 2014.
Pursuant to 21 CFR 1301.33(a), this is notice that on November 13, 2013, Siegfried (USA), LLC, 33 Industrial Park Road, Pennsville, New Jersey 08070, made application by renewal to the Drug Enforcement Administration (DEA) to be registered as a bulk manufacturer of the following basic classes of controlled substances:
The company plans to manufacture the listed controlled substances in bulk for distribution to its customers.
Any other such applicant, and any person who is presently registered with DEA to manufacture such substance, may file comments or objections to the issuance of the proposed registration pursuant to 21 CFR 1301.33(a).
Any such written comments or objections should be addressed, in quintuplicate, to the Drug Enforcement Administration, Office of Diversion Control, Federal Register Representative (ODW), 8701 Morrissette Drive, Springfield, Virginia 22152; and must be filed no later than March 10, 2014.
12:00 p.m., Tuesday, January 14, 2014.
U.S. Parole Commission, 90 K Street NE., 3rd Floor, Washington, DC
Closed.
Determination on four original jurisdiction cases.
Patricia W. Moore, Staff Assistant to the Chairman, U.S. Parole Commission, 90 K Street NE., 3rd Floor, Washington, DC 20530, (202) 346–7001.
10:00 a.m., Tuesday, January 14, 2014.
U.S. Parole Commission, 90 K Street NE., 3rd Floor, Washington, DC
Open.
Approval of August 8, 2013 minutes; reports from the Chairman, the Commissioners, and senior staff; Short Intervention For Success Program; Proposed Rulemaking Revising Conditions of Release update.
Patricia W. Moore, Staff Assistant to the Chairman, U.S. Parole Commission, 90 K Street NE., 3rd Floor, Washington, DC 20530, (202) 346–7001.
Nuclear Regulatory Commission.
Order; modification.
The U.S. Nuclear Regulatory Commission (NRC) has issued a general license to Ameren Missouri (AmerenUE), authorizing the operation of an Independent Spent Fuel Storage Installation (ISFSI), in accordance with its regulations. This Order is being issued to AmerenUE because AmerenUE has identified near-term plans to store spent fuel in an ISFSI under the general license provisions of the NRC's regulations.
Please refer to Docket ID NRC–2013–0292 when contacting the NRC about the availability of information regarding this document. You may access publicly-available information related to this action by the following methods:
•
•
•
L. Raynard Wharton, Office of Nuclear
Pursuant to § 2.106 of Title 10 of the
The NRC has issued a general license to Ameren Missouri (AmerenUE), authorizing the operation of an ISFSI, in accordance with the Atomic Energy Act of 1954, as amended, and Part 72 of Title 10 of the
Inasmuch as an insider has an opportunity equal to, or greater than, any other person, to commit radiological sabotage, the Commission has determined these measures to be prudent. Comparable Orders have been issued to all licensees that currently store spent fuel or have identified near-term plans to store spent fuel in an ISFSI.
On September 11, 2001, terrorists simultaneously attacked targets in New York, NY, and near Washington, DC, using large commercial aircraft as weapons. In response to the attacks and intelligence information subsequently obtained, the Commission issued a number of Safeguards and Threat Advisories to its licensees to strengthen licensees' capabilities and readiness to respond to a potential attack on a nuclear facility. On October 16, 2002, the Commission issued Orders to the licensees of operating ISFSIs, to place the actions taken in response to the Advisories into the established regulatory framework and to implement additional security enhancements that emerged from NRC's ongoing comprehensive review. The Commission has also communicated with other Federal, State, and local government agencies and industry representatives to discuss and evaluate the current threat environment in order to assess the adequacy of security measures at licensed facilities. In addition, the Commission has conducted a comprehensive review of its safeguards and security programs and requirements.
As a result of its consideration of current safeguards and security requirements, as well as a review of information provided by the intelligence community, the Commission has determined that certain additional security measures (ASMs) are required to address the current threat environment, in a consistent manner throughout the nuclear ISFSI community. Therefore, the Commission is imposing requirements, as set forth in Attachments 1 and 2 of this Order, on all licensees of these facilities. These requirements, which supplement existing regulatory requirements, will provide the Commission with reasonable assurance that the public health and safety, the environment, and common defense and security continue to be adequately protected in the current threat environment. These requirements will remain in effect until the Commission determines otherwise.
The Commission recognizes that licensees may have already initiated many of the measures set forth in Attachments 1 and 2 to this Order, in response to previously issued Advisories, or on their own. It also recognizes that some measures may not be possible or necessary at some sites, or may need to be tailored to accommodate the specific circumstances existing at AmerenUE's facility, to achieve the intended objectives and avoid any unforeseen effect on the safe storage of spent fuel.
Although the ASMs implemented by licensees in response to the Safeguards and Threat Advisories have been sufficient to provide reasonable assurance of adequate protection of public health and safety, in light of the continuing threat environment, the Commission concludes that these actions should be embodied in an Order, consistent with the established regulatory framework.
To provide assurance that licensees are implementing prudent measures to achieve a consistent level of protection to address the current threat environment, licenses issued pursuant to 10 CFR 72.210 shall be modified to include the requirements identified in Attachments 1 and 2 to this Order. In addition, pursuant to 10 CFR 2.202, I find that, in light of the common defense and security circumstances described above, the public health, safety, and interest require that this Order be effective immediately.
Accordingly, pursuant to Sections 53, 103, 104, 147, 149, 161b, 161i, 161o, 182, and 186 of the Atomic Energy Act of 1954, as amended, and the Commission's regulations in 10 CFR 2.202 and 10 CFR Parts 50, 72, and 73,
A. AmerenUE shall comply with the requirements described in Attachments 1 and 2 to this Order, except to the extent that a more stringent requirement is set forth in the Callaway Plant's physical security plan. AmerenUE shall demonstrate its ability to comply with the requirements in Attachments 1 and 2 to the Order no later than 365 days from the date of this Order or 90 days before the first day that spent fuel is initially placed in the ISFSI, whichever is earlier. AmerenUE must implement these requirements before initially placing spent fuel in the ISFSI. Additionally, AmerenUE must receive written verification from the NRC (Office of Nuclear Material Safety and Safeguards) that it has adequately demonstrated compliance with these requirements before initially placing spent fuel in the ISFSI.
B. 1. AmerenUE shall, within twenty (20) days of the date of this Order, notify the Commission: (1) If it is unable to comply with any of the requirements described in Attachments 1 and 2; (2) if compliance with any of the requirements is unnecessary, in its specific circumstances; or (3) if implementation of any of the requirements would cause AmerenUE to be in violation of the provisions of any Commission regulation or the facility license. The notification shall provide AmerenUE's justification for seeking relief from, or variation of, any specific requirement.
2. If AmerenUE considers that implementation of any of the requirements described in Attachments 1 and 2 to this Order would adversely impact the safe storage of spent fuel, AmerenUE must notify the Commission, within twenty (20) days of this Order, of the adverse safety impact, the basis for its determination that the requirement has an adverse safety impact, and either
C. 1. AmerenUE shall, within twenty (20) days of this Order, submit to the Commission, a schedule for achieving compliance with each requirement described in Attachments 1 and 2.
2. AmerenUE shall report to the Commission when it has achieved full compliance with the requirements described in Attachments 1 and 2.
D. All measures implemented or actions taken in response to this Order shall be maintained until the Commission determines otherwise.
AmerenUE's response to Conditions B.1, B.2, C.1, and C.2, above, shall be submitted in accordance with 10 CFR 72.4. In addition, submittals and documents produced by AmerenUE as a result of this Order, that contain Safeguards Information as defined by 10 CFR 73.22, shall be properly marked and handled, in accordance with 10 CFR 73.21 and 73.22.
The Director, Office of Nuclear Material Safety and Safeguards, may, in writing, relax or rescind any of the above conditions, for good cause.
In accordance with 10 CFR 2.202, AmerenUE must, and any other person adversely affected by this Order may, submit an answer to this Order within 20 days of its publication in the
The answer may consent to this Order. If the answer includes a request for a hearing, it shall, under oath or affirmation, specifically set forth the matters of fact and law on which AmerenUE relies and the reasons as to why the Order should not have been issued. If a person other than AmerenUE requests a hearing, that person shall set forth with particularity the manner in which his/her interest is adversely affected by this Order and shall address the criteria set forth in 10 CFR 2.309(d).
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 electronically, or in some cases to mail copies on electronic storage media. Participants may not submit paper copies of their filings unless they seek an exemption in accordance with the procedures described below.
To comply with the procedural requirements of E-Filing, at least 10 days prior to the filing deadline, the participant should contact the Office of the Secretary by email at
Information about applying for a digital ID certificate is available on 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's 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
Documents submitted in adjudicatory proceedings will appear in NRC's electronic hearing docket which is available to the public at
If a hearing is requested by AmerenUE or a person whose interest is adversely affected, the Commission will issue an Order designating the time and place of any hearing. If a hearing is held, the issue to be considered at such hearing shall be whether this Order should be sustained.
Pursuant to 10 CFR 2.202(c)(2)(i), AmerenUE may, in addition to requesting a hearing, at the time the answer is filed or sooner, move the presiding officer to set aside the immediate effectiveness of the Order on the grounds that the Order, including the need for immediate effectiveness, is not based on adequate evidence, but on mere suspicion, unfounded allegations, or error.
In the absence of any request for hearing, or written approval of an extension of time in which to request a hearing, the provisions as specified in Section III shall be final twenty (20) days from the date this Order is published in the
For the nuclear regulatory commission.
1. These additional security measures (ASMs) are established to delineate an independent spent fuel storage installation (ISFSI) licensee's responsibility to enhance security measures related to authorization for unescorted access to the protected area of an ISFSI in response to the current threat environment.
2. Licensees whose ISFSI is collocated with a power reactor may choose to comply with the U.S. Nuclear Regulatory Commission (NRC)-approved reactor access authorization program for the associated reactor as an alternative means to satisfy the provisions of sections B through G below. Otherwise, licensees shall comply with the access authorization and fingerprinting requirements of section B through G of these ASMs.
3. Licensees shall clearly distinguish in their 20-day response which method they intend to use in order to comply with these ASMs.
1. The licensee shall develop, implement and maintain a program, or enhance its existing program, designed to ensure that persons granted unescorted access to the protected area of an ISFSI are trustworthy and reliable and do not constitute an unreasonable risk to the public health and safety for the common defense and security, including a potential to commit radiological sabotage.
a. To establish trustworthiness and reliability, the licensee shall develop, implement, and maintain procedures for conducting and completing background investigations, prior to granting access. The scope of background investigations must address at least the past three years and, as a minimum, must include:
i. Fingerprinting and a Federal Bureau of Investigation (FBI) identification and criminal history records check (CHRC). Where an applicant for unescorted access has been previously fingerprinted with a favorably completed CHRC, (such as a CHRC pursuant to compliance with orders for access to safeguards information) the licensee may accept the results of that CHRC, and need not submit another set of fingerprints, provided the CHRC was completed not more than three years from the date of the application for unescorted access.
ii. Verification of employment with each previous employer for the most recent year from the date of application.
iii. Verification of employment with an employer of the longest duration during any calendar month for the remaining next most recent two years.
iv. A full credit history review.
v. An interview with not less than two character references, developed by the investigator.
vi. A review of official identification (e.g., driver's license; passport; government identification; state-, province-, or country-of-birth issued certificate of birth) to allow comparison of personal information data provided by the applicant. The licensee shall maintain a photocopy of the identifying document(s) on file, in accordance with “Protection of Information,” in Section G of these ASMs.
vii. Licensees shall confirm eligibility for employment through the regulations of the U.S. Department of Homeland Security, U.S. Citizenship and Immigration Services, and shall verify and ensure, to the extent possible, the accuracy of the provided social security number and alien registration number, as applicable.
b. The procedures developed or enhanced shall include measures for
c. Licensees need not conduct an independent investigation for individuals employed at a facility who possess active “Q” or “L” clearances or possess another active U.S. Government-granted security clearance (
d. A review of the applicant's criminal history, obtained from local criminal justice resources, may be included in addition to the FBI CHRC, and is encouraged if the results of the FBI CHRC, employment check, or credit check disclose derogatory information. The scope of the applicant's local criminal history check shall cover all residences of record for the past three years from the date of the application for unescorted access.
2. The licensee shall use any information obtained as part of a CHRC solely for the purpose of determining an individual's suitability for unescorted access to the protected area of an ISFSI.
3. The licensee shall document the basis for its determination for granting or denying access to the protected area of an ISFSI.
4. The licensee shall develop, implement, and maintain procedures for updating background investigations for persons who are applying for reinstatement of unescorted access. Licensees need not conduct an independent reinvestigation for individuals who possess active “Q” or “L” clearances or possess another active U.S. Government granted security clearance, i.e., Top Secret, Secret or Confidential.
5. The licensee shall develop, implement, and maintain procedures for reinvestigations of persons granted unescorted access, at intervals not to exceed 5 years. Licensees need not conduct an independent reinvestigation for individuals employed at a facility who possess active “Q” or “L” clearances or possess another active U.S. Government granted security clearance, i.e., Top Secret, Secret or Confidential.
6. The licensee shall develop, implement, and maintain procedures designed to ensure that persons who have been denied unescorted access authorization to the facility are not allowed access to the facility, even under escort.
7. The licensee shall develop, implement, and maintain an audit program for licensee and contractor/vendor access authorization programs that evaluate all program elements and include a person knowledgeable and practiced in access authorization program performance objectives to assist in the overall assessment of the site's program effectiveness.
1. In a letter to the NRC, the licensee must nominate an individual who will review the results of the FBI CHRCs to make trustworthiness and reliability determinations for unescorted access to an ISFSI. This individual, referred to as the “reviewing official,” must be someone who requires unescorted access to the ISFSI. The NRC will review the CHRC of any individual nominated to perform the reviewing official function. Based on the results of the CHRC, the NRC staff will determine whether this individual may have access. If the NRC determines that the nominee may not be granted such access, that individual will be prohibited from obtaining access.
2. No person may have access to Safeguards Information (SGI) or unescorted access to any facility subject to NRC regulation, if the NRC has determined, in accordance with its administrative review process based on fingerprinting and an FBI identification and CHRC, that the person may not have access to SGI or unescorted access to any facility subject to NRC regulation.
3. All fingerprints obtained by the licensee under this Order, must be submitted to the Commission for transmission to the FBI.
4. The licensee shall notify each affected individual that the fingerprints will be used to conduct a review of his/her criminal history record and inform the individual of the procedures for revising the record or including an explanation in the record, as specified in the “Right to Correct and Complete Information,” in section F of these ASMs.
5. Fingerprints need not be taken if the employed individual (e.g., a licensee employee, contractor, manufacturer, or supplier) is relieved from the fingerprinting requirement by 10 CFR 73.61, has a favorably adjudicated U.S. Government CHRC within the last 5 years, or has an active Federal security clearance. Written confirmation from the Agency/employer who granted the Federal security clearance or reviewed the CHRC must be provided to the licensee. The licensee must retain this documentation for a period of three years from the date the individual no longer requires access to the facility.
1. A licensee shall not base a final determination to deny an individual unescorted access to the protected area of an ISFSI solely on the basis of information received from the FBI involving: an arrest more than 1 year old for which there is no information of the disposition of the case, or an arrest that resulted in dismissal of the charge, or an acquittal.
2. A licensee shall not use information received from a CHRC obtained pursuant to this Order in a manner that would infringe upon the rights of any individual under the First Amendment to the Constitution of the United States, nor shall the licensee use the information in any way that would discriminate among individuals on the basis of race, religion, national origin, sex, or age.
1. For the purpose of complying with this Order, licensees shall, using an appropriate method listed in 10 CFR 73.4, submit to the NRC's Division of Facilities and Security, Mail Stop T–03B46M, one completed, legible standard fingerprint card (Form FD–258, ORIMDNRCOOOZ) or, where practicable, other fingerprint records for each individual seeking unescorted access to an ISFSI, to the Director of the Division of Facilities and Security, marked for the attention of the Division's Criminal History Check Section. Copies of these forms may be obtained by writing the Office of Information Services, U.S. Nuclear Regulatory Commission, Washington, DC 20555–0001, by calling 301–415–5877, or by email to
2. The NRC will review submitted fingerprint cards for completeness. Any Form FD–258 fingerprint record containing omissions or evident errors will be returned to the licensee for corrections. The fee for processing fingerprint checks includes one re-submission if the initial submission is returned by the FBI because the fingerprint impressions cannot be classified. The one free re-submission must have the FBI Transaction Control Number reflected on the re-submission. If additional submissions are necessary, they will be treated as initial submittals and will require a second payment of the processing fee.
3. Fees for processing fingerprint checks are due upon application. The licensee shall submit payment of the processing fees electronically. To be able to submit secure electronic payments, licensees will need to establish an account with Pay.Gov (
4. The Commission will forward to the submitting licensee all data received from the FBI as a result of the licensee's application(s) for CHRCs, including the FBI fingerprint record.
1. Prior to any final adverse determination, the licensee shall make available to the individual the contents of any criminal history records obtained from the FBI for the purpose of assuring correct and complete information. Written confirmation by the individual of receipt of this notification must be maintained by the licensee for a period of one (1) year from the date of notification.
2. If, after reviewing the record, an individual believes that it is incorrect or incomplete in any respect and wishes to change, correct, or update the alleged deficiency, or to explain any matter in the record, the individual may initiate challenge procedures. These procedures include either direct application by the individual challenging the record to the agency (i.e., law enforcement agency) that contributed the questioned information, or direct challenge as to the accuracy or completeness of any entry on the criminal history record to the Assistant Director, Federal Bureau of Investigation Identification Division, Washington, DC 20537–9700 (as set forth in 28 CFR 16.30 through 16.34). In the latter case, the FBI forwards the challenge to the agency that submitted the data and requests that agency to verify or correct the challenged entry. Upon receipt of an official communication directly from the agency that contributed the original information, the FBI Identification Division makes any changes necessary in accordance with the information supplied by that agency. The licensee must provide at least 10 days for an individual to initiate an action challenging the results of a FBI CHRC after the record is made available for his/her review. The licensee may make a final access determination based on the criminal history record only upon receipt of the FBI's ultimate confirmation or correction of the record. Upon a final adverse determination on access to an ISFSI, the licensee shall provide the individual its documented basis for denial. Access to an ISFSI shall not be granted to an individual during the review process.
1. The licensee shall develop, implement, and maintain a system for personnel information management with appropriate procedures for the protection of personal, confidential information. This system shall be designed to prohibit unauthorized access to sensitive information and to prohibit modification of the information without authorization.
2. Each licensee who obtains a criminal history record on an individual pursuant to this Order shall establish and maintain a system of files and procedures, for protecting the record and the personal information from unauthorized disclosure.
3. The licensee may not disclose the record or personal information collected and maintained to persons other than the subject individual, his/her representative, or to those who have a need to access the information in performing assigned duties in the process of determining suitability for unescorted access to the protected area of an ISFSI. No individual authorized to have access to the information may re-disseminate the information to any other individual who does not have the appropriate need to know.
4. The personal information obtained on an individual from a CHRC may be transferred to another licensee if the gaining licensee receives the individual's written request to re-disseminate the information contained in his/her file, and the gaining licensee verifies information such as the individual's name, date of birth, social security number, sex, and other applicable physical characteristics for identification purposes.
5. The licensee shall make criminal history records, obtained under this section, available for examination by an authorized representative of the NRC to determine compliance with the regulations and laws.
On October 28, 2013, NYSE MKT LLC (the “Exchange” or “NYSE MKT”) filed with the Securities and Exchange Commission (“Commission”), pursuant
The Exchange currently ranks and tracks Electronic Complex Orders in the Consolidated Book in a “complex order table.” Although the Exchange stated that the complex order table has sufficient capacity to accept all Complex Orders submitted by all ATP Holders under normal operating conditions, the Exchange also noted that that capacity is not unlimited.
The Exchange will announce the implementation date of the proposed rule change by Trader Update to be published no later than 60 days following approval by the Commission. The implementation date will be no later than 60 days following the issuance of the Trader Update.
After careful review, the Commission finds that the proposed rule change is consistent with the requirements of the Act and rules and regulations thereunder applicable to a national securities exchange.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether Amendment No. 2 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.
As proposed, the proposed rule change provided that, unless determined otherwise by the Exchange and announced to ATP Holders via Trader Update, the specified percentage (
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
On November 1, 2013, Chicago Board Options Exchange, Incorporated (the “Exchange” or “CBOE”) filed with the Securities and Exchange Commission (“Commission”) pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The Exchange proposes to eliminate the e-DPM Program by deleting Exchange rules that exclusively govern the Program and by removing all references to either the Program or e-DPMs throughout the remainder of its rulebook. Originally adopted in 2004, the e-DPM Program allows Trading Permit Holders (“TPHs”) to remotely function as a Designated Primary Market-Maker (“DPM”).
The Exchange proposes to eliminate the Program because it believes the Program is no longer competitively necessary given the growing prevalence of Preferred Market-Maker
The Exchange stated that it does not believe that the elimination of the e-DPM Program will affect CBOE's market quality because the Exchange does not expect any Market-Makers to cease doing business on the Exchange due to
In support of its proposal to discontinue the e-DPM program, the Exchange further represented that it believes that the Program adds an unnecessary layer of complexity to CBOE rules, system processes, matching algorithms, and trading procedures.
In its filing, the Exchange represented that, if its proposal is approved by the Commission, CBOE would announce the elimination of the Program via a Regulatory Circular, which will include an end date for the Program that will be at least two weeks in advance in order for current e-DPMs to determine their course of action following elimination of the Program.
After careful review of the proposal, the Commission finds that the proposed rule change is consistent with the requirements of the Act and the rules and regulations thereunder that are applicable to a national securities exchange.
As noted above, CBOE represents that all e-DPMs are also registered as PMMs. Accordingly, CBOE does not believe that elimination of the Program will harm CBOE's market quality as it anticipates current e-DPMs will continue to serve as market-makers on the Exchange and as PMMs on orders that are preferred to them.
Further, because such a high percentage of CBOE's order-flow is preferenced (85% as indicated by CBOE), and because PMM status provides a comparably larger entitlement for preferred orders compared to e-DPM status, CBOE believes that the e-DPM program does not provide an incentive great enough to warrant the complexity the e-DPM program brings to the Exchange's rules, systems, and processes. CBOE also noted that other options exchanges do not have programs similar to the e-DPM program.
Based on CBOE's representations, discussed above, the Commission believes that elimination of the e-DPM Program should not hinder the Exchange's capacity to carry out the purposes of the Act nor should it impede CBOE's ability to remove impediments to and perfect the mechanism of a free and open market and a national market system.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”),
The Exchange proposes a rule change to further describe the application of fees assessed pursuant to subparagraph (d) of “Testing Facilities” under Chapter VIII of the Exchange's Pricing Schedule. The Exchange is also eliminating outdated text relating to the applicability of the fees assessed for use and connectivity to the Testing Facilities.
The text of the proposed rule change is below. Proposed new language is italicized. Proposed deletions are in brackets.
ALL BILLING DISPUTES MUST BE SUBMITTED TO THE EXCHANGE IN WRITING AND MUST BE ACCOMPANIED BY SUPPORTING DOCUMENTATION. ALL DISPUTES MUST BE SUBMITTED NO LATER THAN SIXTY (60) DAYS AFTER RECEIPT OF A BILLING INVOICE, EXCEPT FOR DISPUTES CONCERNING NASDAQ OMX PSX FEES, PROPRIETARY DATA FEED FEES AND CO-LOCATION SERVICES FEES. AS OF JANUARY 3, 2011, THE EXCHANGE
The Exchange operates two test environments. One is located in Ashburn, Virginia and the other in Carteret, New Jersey. Unless otherwise noted, reference to the “Testing Facility” applies to both environments.
(a)–(c) No change.
(d) Subscribers to the Testing Facility located in Carteret, New Jersey shall pay a fee of $1,000 per hand-off, per month for connection to the Testing Facility. The hand-off fee includes either a 1Gb or 10Gb switch port and a cross connect to the Testing Facility. Subscribers shall also pay a one-time installation fee of $1,000 per hand-off, which is waived for all installations ordered prior to March 31, 2014.
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 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 is proposing to amend the Phlx Pricing Schedule to more fully describe the application of the newly-adopted fee
The Exchange is proposing to add language to subparagraph (d) of “Testing Facilities” under Chapter VIII of the Exchange's Pricing Schedule that was erroneously omitted when the fee was originally adopted.
The Exchange is also eliminating text from the Testing Facilities rule that relates to a general waiver of fees under the rule, which was effective with the launch of PSX and ended six months thereafter. PSX launched in October 2010,
The Exchange believes that its proposal is consistent with Section 6(b) of the Act
The Exchange 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. The proposed rule change clarifies how fees will be assessed to a firm that is a member of more than one of the Equity Markets and makes clear that a member organization may gain access to the test environments of the other Equity Markets through a subscription under the rule. Members of multiple Equity Markets are assessed the same fee for Carteret connectivity and must pay the port fees of each of the Equity Markets to gain access to such markets' test environments. In addition, the proposed change eliminates rule text that relates to a fee waiver that has since expired. As a consequence, the Exchange does not believe that the proposed rule change is impactful to competition in any respect.
Written comments were neither solicited nor received.
The Exchange has filed the proposed rule change pursuant to Section 19(b)(3)(A) of the Act
A proposed rule change filed under Rule 19b–4(f)(6)
The Exchange has asked the Commission to waive the 30-day operative delay. The Exchange notes that such waiver will allow the Exchange to immediately add language to its rule text that was incorrectly omitted from a previous rule change, thereby clarifying its rules and avoiding potential market participant confusion.
At any time within 60 days of the filing of the proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings to determine whether the proposed rule change should be approved or disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to 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) of the Securities Exchange Act of 1934 (“Act”)
FINRA is proposing to amend FINRA Rule 2360 (Options) to: (1) Specify that position limits for standardized equity options shall be the highest position limit established by an options exchange on which the option trades, which has the effect of eliminating position limits on standardized options on Standard and Poor's Depositary Receipts Trust (“SPY”) and increasing the position limit for standardized options on iShares MSCI Emerging Markets Index Fund (“EEM”) to 500,000 contracts; and (2) increase the position limit for conventional options on EEM to 500,000 contracts.
The text of the proposed rule change is available on FINRA's Web site at
In its filing with the Commission, FINRA 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. FINRA has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
FINRA Rule 2360(b)(3)(A) imposes a position limit on the number of equity options contracts in each class on the same side of the market that can be held or written by a member, a person associated with a member, or a customer or a group of customers acting in concert. Position limits are intended to prevent the establishment of options positions that can be used to manipulate or disrupt the underlying market or might create incentives to manipulate or disrupt the underlying market so as to benefit the options position. In addition, position limits serve to reduce the potential for disruption of the options market itself, especially in illiquid options classes. FINRA understands that the Commission, when considering the appropriate level at which to set options position and exercise limits, seeks to prevent investors from disrupting the market in the security underlying the option.
Currently, Rule 2360(b)(3)(A) establishes position limits for equity options according to a five-tiered system in which options on more actively traded stocks with larger public floats are subject to higher position limits. Rule 2360 does not specifically govern how a particular equity option falls within one of the tiers. Rather, the position limit established by the rules of an options exchange for a particular equity option is the applicable position limit for purposes of Rule 2360.
As noted above, Rule 2360 provides that the five-tiered position limits established by the rules of an options exchange governs standardized equity options position limits. However, at times the options exchanges have increased position limits beyond the highest tier (currently 250,000 contracts) for certain exchange-traded funds (“ETF”) options. For example, the options exchanges raised the position limit for standardized options on 'SPY [sic] options to 900,000 contracts.
The proposed rule change would allow members to immediately take advantage of any increased standardized equity option position limit that may be set by an options exchange as approved by the SEC without waiting for FINRA to file a corresponding rule change.
As noted above, currently position limits for conventional options are the same as the limits for standardized options for which the underlying security qualifies or would be able to qualify.
In support of the increased position limit on conventional EEM options, below are the trading statistics comparing EEM to IWM and SPY. As shown in the following table, the average daily volume in 2012 for EEM was 49.4 million shares compared to 45.7 million shares for IWM and 143.3 million shares for SPY. The total shares outstanding for EEM were 911.7 million compared to 243.7 million shares for IWM and 837.5 million shares for SPY. Further, the fund market cap for EEM was $34.1 billion compared to $24.6 billion for IWM and $137.2 billion for SPY.
In further support of this proposal, as noted by CBOE, EEM tracks the performance of the MSCI Emerging Markets Index, which has approximately 800 component securities.
FINRA believes that the liquidity in the underlying ETF and the liquidity in EEM options support its request to increase the position limits for conventional EEM options as similar to the standardized EEM options. Through November 29, 2013, the year-to-date average daily trading volume in the ETF for EEM across all exchanges was 62 million shares. The year-to-date average daily trading for EEM options across all exchanges was 327,347 contracts.
FINRA believes that increasing position limits for EEM conventional options will lead to a more liquid and competitive market environment for EEM options that will benefit customers interested in this product.
Further, FINRA believes that the modified position limits provisions are appropriate in light of the existing surveillance procedures and reporting requirements at FINRA,
In addition, large stock holdings must be disclosed to the Commission by way of Schedules 13D or 13G.
Finally, FINRA believes that the current financial requirements imposed by FINRA and by the Commission adequately address financial responsibility concerns that a member or its customer will maintain an inordinately large unhedged position in any option with a higher position limit. Current margin and risk-based haircut methodologies serve to limit the size of positions maintained by any one account by increasing the margin or capital that a member must maintain for a large position. Under Rule 4210(f)(8)(A), FINRA also may impose a higher margin requirement upon a member when FINRA determines a higher requirement is warranted. In addition, the Commission's net capital rule
FINRA has filed the proposed rule change for immediate effectiveness and has requested that the SEC waive the requirement that the proposed rule change not become operative for 30 days after the date of the filing, so FINRA can implement the proposed rule change immediately.
FINRA believes that the proposed rule change is consistent with the provisions of Section 15A(b)(6) of the Act,
FINRA 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 noted above, the proposed rule change would amend Rule 2360 to harmonize FINRA's position limits on standardized options with those of the options exchange (which are subject to approval by the SEC), and to harmonize position limits for conventional EEM options with the position limit for standardized EEM options.
Written comments were neither solicited nor received.
Because the foregoing proposed rule change does not: (i) Significantly affect the protection of investors or the public interest; (ii) impose any significant burden on competition; and (iii) become operative for 30 days from the date on
A proposed rule change filed under Rule 19b–4(f)(6)
At any time within 60 days of the filing of the proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings to determine whether the proposed rule should be approved or disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to 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) of the Securities Exchange Act of 1934 (“Act”)
The ISE proposes to amend its Schedule of Fees to extend its Managed Data Access Service Pilot for the sale of a number of real-time market data products. The text of the proposed rule change is available on the Exchange's Web site (
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 these statements may be examined at the places specified in Item IV below. The self-regulatory organization has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
On June 6, 2013 the ISE implemented a Managed Data Access Service Pilot that established a new pricing and distribution model for the sale of a number of real-time market data products.
The current fees for the Managed Data Access Service, which are proposed to be extended for another 6 month pilot period, are as follows:
The Exchange charges a fee to each Managed Data Access Distributor of $2,500 per month for the Depth Feed, $1,500 for each of the Top Quote Feed and Spread Feed, and $1,000 per month for the Order Feed. The Exchange also charges a fee for each IP address at Managed Data Access Recipients that receive market data redistributed by a Managed Data Access Distributor, which is $750 per month for the Depth Feed, $500 per month for each of the Top Quote Feed and Spread Feed, and $350 per month for the Order Feed.
The Exchange is not proposing to make any changes to the fees currently charged under the Managed Data Access Service program.
The Exchange believes that the proposed rule change is consistent with the provisions of Section 6 of the Act,
In accordance with Section 6(b)(8) of the Act,
The Exchange has not solicited, and does not intend to solicit, comments on this proposed rule change. The Exchange has not received any
The foregoing rule change has become effective pursuant to Section 19(b)(3)(A)(ii) of the Act
At any time within 60 days of the filing of the proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings to determine whether the proposed rule should be approved or disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to 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 October 28, 2013, NYSE Arca, Inc. (the “Exchange” or “NYSE Arca”) filed with the Securities and Exchange Commission (“Commission”), pursuant to Section 19(b)(1)
The Exchange currently ranks and tracks Electronic Complex Orders in the Consolidated Book in a “complex order table.” Although the Exchange stated that the complex order table has sufficient capacity to accept all Complex Orders submitted by all OTPs under normal operating conditions, the Exchange also noted that that capacity is not unlimited.
The Exchange will announce the implementation date of the proposed rule change by Trader Update to be published no later than 60 days following approval by the Commission. The implementation date will be no later than 60 days following the issuance of the Trader Update.
After careful review, the Commission finds that the proposed rule change is consistent with the requirements of the Act and rules and regulations thereunder applicable to a national securities exchange.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether Amendment No. 2 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.
As proposed, the proposed rule change provided that, unless determined otherwise by the Exchange and announced to OTPs via Trader Update, the specified percentage (
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (the “Act”)
The Exchange proposes to amend the Options Regulatory Fee. The text of the proposed rule change is available on the Exchange's Web site (
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 Exchange has reevaluated the current amount of the Options Regulatory Fee (“ORF”) in connection with its annual budget review. In light of a recent reevaluation of regulatory costs and the expected volume levels for 2014, the Exchange proposes to decrease the ORF from $.0017 (effective January 1, 2014) to $.0012 per contract. This proposed fee change would be operative on February 1, 2014.
The ORF is assessed by the Exchange to each Permit Holder for all options transactions executed or cleared by the Permit Holder that are cleared by The Options Clearing Corporation (“OCC”) in the customer range (i.e., transactions that clear in a customer account at OCC) regardless of the marketplace of execution. In other words, the Exchange imposes the ORF on all customer-range transactions executed by a Permit Holder, even if the transactions do not take place on the Exchange.
The ORF is designed to recover a material portion of the costs to the Exchange of the supervision and regulation of Permit Holder customer options business, including performing routine surveillances, investigations, examinations, financial monitoring, as well as policy, rulemaking, interpretive and enforcement activities. The Exchange believes that revenue generated from the ORF, when combined with all of the Exchange's other regulatory fees and fines, will cover a material portion, but not all, of the Exchange's regulatory costs. The Exchange notes that its regulatory responsibilities with respect to Permit Holder compliance with options sales practice rules have largely been allocated to FINRA under a 17d–2 agreement. The ORF is not designed to cover the cost of that options sales practice regulation.
The Exchange will monitor the amount of revenue collected from the ORF to ensure that it, in combination with its other regulatory fees and fines, does not exceed the Exchange's total regulatory costs. If the Exchange determines regulatory revenues exceed regulatory costs, the Exchange will adjust the ORF by submitting a fee change filing to the Commission. The Exchange notifies Permit Holders of adjustments to the ORF via regulatory circular.
The Exchange believes the proposed rule change is consistent with the Securities Exchange Act of 1934 (the “Act”) and the rules and regulations thereunder applicable to the Exchange and, in particular, the requirements of Section 6(b) of the Act.
The Exchange believes the proposed fee change is reasonable because it would more effectively help the Exchange offset regulatory expenses and would not result in total regulatory revenue exceeding total regulatory costs. The Exchange believes the ORF is equitable and not unfairly discriminatory in that it is charged to all Permit Holders on all their transactions that clear in the customer range at the OCC. Moreover, the Exchange believes the ORF ensures fairness by assessing higher fees to those Permit Holders that require more Exchange regulatory services based on the amount of customer options business they conduct. Regulating customer trading activity is much more labor intensive and requires greater expenditure of human and technical resources than regulating non-customer trading activity, which tends to be more automated and less labor-intensive. As a result, the costs associated with administering the customer component of the Exchange's overall regulatory
C2 does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. The proposed rule change is not designed to address any competitive issues. Rather, the proposed rule change is designed to help the Exchange to adequately fund its regulatory activities while seeking to ensure that total regulatory revenues do not exceed total regulatory costs.
The Exchange neither solicited nor received comments on the proposed rule change.
The foregoing rule change has become effective pursuant to Section 19(b)(3)(A) of the Act
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to 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) of the Securities Exchange Act of 1934 (“Act”),
The Exchange proposes a proposed rule change to further describe the application of fees assessed pursuant to Rule 7030(d)(1)(C).
The text of the proposed rule change is below. Proposed new language is italicized. Proposed deletions are in brackets.
(a)–(c) No change.
(d) Nasdaq Testing Facilities
Nasdaq operates two testing environments. One is located in Ashburn, Virginia and the other in Carteret, New Jersey. Unless otherwise noted, reference to the “Nasdaq Testing Facility” or “NTF” applies to both environments.
(1) The following fees are assessed for access to the Nasdaq Testing Facility:
(A) Subscribers that conduct tests of the computer-to-computer interface (CTCI) and the Financial Information Exchange (FIX) interface to ACT and ACES access protocols through the Nasdaq Testing Facility (NTF) shall pay the following charges:
(B) Subscribers that conduct tests of all Nasdaq access protocol connections not included in paragraph (A) above or of market data vendor feeds through the Nasdaq Testing Facility shall pay $300 per port, per month.
(C) Subscribers to the Nasdaq Testing Facility located in Carteret, New Jersey shall pay a fee of $1,000 per hand-off, per month for connection to the NTF. The hand-off fee includes either a 1Gb or 10Gb switch port and a cross connect to the NTF. Subscribers shall also pay a one-time installation fee of $1,000 per hand-off, which is waived for all installations ordered prior to March 31, 2014.
(2)–(6) No change.
In its filing with the Commission, NASDAQ 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 is proposing to amend the Rule 7030(d) to more fully describe the application of the newly-adopted fee
The Exchange is proposing to add language to Rule 7030(d)(1)(C) that was erroneously omitted when the fee was originally adopted.
The Exchange believes that its proposal is consistent with Section 6(b) of the Act
The Exchange 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. The proposed rule change clarifies how fees will be assessed to a firm that is a member of more than one of the Equity Markets and makes clear that a member firm may gain access to the test environments of the other Equity Markets through a subscription under the rule. Members of multiple Equity Markets are assessed the same fee for Carteret connectivity and must pay the port fees of each of the Equity Markets to gain access to such markets' test environments. As a consequence, the Exchange does not believe that the proposed rule change is impactful to competition in any respect.
Written comments were neither solicited nor received.
The Exchange has filed the proposed rule change pursuant to Section 19(b)(3)(A) of the Act
A proposed rule change filed under Rule 19b–4(f)(6)
The Exchange has asked the Commission to waive the 30-day operative delay. The Exchange notes that such waiver will allow the Exchange to immediately add language to its rule text that was incorrectly omitted from a previous rule change, thereby clarifying its rules and avoiding potential market participant confusion.
At any time within 60 days of the filing of the proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings to determine whether the proposed rule change should be approved or disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to 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 November 1, 2013, Chicago Board Options Exchange, Incorporated (“Exchange” or “CBOE”) filed with the Securities and Exchange Commission (“Commission”), pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The Exchange is proposing to amend its rules regarding Market-Maker appointment cost rebalances. According to the Exchange, appointments to act as a Market-Maker “cost” different
Currently, on a quarterly basis, the Exchange may rebalance the tiers into which different classes fall, meaning that the Exchange can elect to move a class from one tier to another (with that class' corresponding appointment cost changing). The Exchange proposes to memorialize in proposed CBOE Rule 8.3(c)(iv) that the Exchange will announce any rebalances at least ten business days before the rebalance takes effect.
When the Exchange effects a rebalancing (
The Exchange proposes to add language to CBOE Rule 8.3(c)(iv) to address situations in which a Market-Maker fails to adjust his or her appointments and, as a result, the sum of the Market-Maker's appointment costs otherwise would exceed the available appointment credits based on the number of Trading Permits the Market-Maker holds. The proposed new language states: “[i]f a Market-Maker with a VTC appointment holds a combination of appointments whose aggregate revised appointment cost is greater than the number of Trading Permits that Market-Maker holds, the Market-Maker will be assigned as many Trading Permits as necessary to ensure that the Market-Maker no longer holds a combination of appointments whose aggregate revised appointment cost is greater than the number of Trading Permits that Market-Maker holds.” In the event that a Market-Maker's appointment costs exceed his or her available assignment credits as the result of a reassignment of appointment costs by the Exchange, and the Exchange needs to allocate another trading permit or permits to the Market-Maker, then the Exchange also will assess the Market-Maker the corresponding Trading Permit fees for the additional Trading Permit(s).
After careful review, the Commission finds that the proposed rule change is consistent with the requirements of the Act and the rules and regulations thereunder applicable to a national securities exchange.
The proposed rule change is designed to allow the Exchange to avoid a situation where a Market-Maker has an aggregate appointment cost that exceeds the available appointment credits that the Market-Maker holds based on the trading permits that he or she possesses. The Exchange argues that such a situation would constitute an unfair advantage in favor of that Market-Maker.
In addition, the revised rule would codify the Exchange's current practice of notifying TPHs at least ten business days before effecting Market-Maker class tier rebalances, which could potentially affect their fees if they are required to purchase additional trading permits. It also would enable the Exchange to adjust the VTC appointments of a Market-Maker whose aggregate appointment cost exceeds the number of trading permits that the Market-Maker holds and charge the Market-Maker for
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
FINRA is proposing to adopt a new FINRA Capacity Management Plan (“Plan”) for the Alternative Display Facility (“ADF”) and amend the ADF Trading Center Certification Record (“Certification”) to, among other things, require ADF Trading Centers to comply with the Plan.
A copy of the Plan was filed as Exhibit 3a. A copy of the revised Certification was filed as Exhibit 3b. The text of the proposed rule change is available on FINRA's Web site at
In its filing with the Commission, FINRA 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. FINRA has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
The ADF is a quotation collection and trade reporting facility that provides ADF Market Participants (i.e., ADF-registered market makers or electronic communications networks (“ECNs”))
To become an ADF Market Participant, a member must apply to FINRA, which includes certifying the member's good standing with FINRA and demonstrating compliance with the net capital and other financial responsibility provisions of the Act.
Regulatory developments, such as the SEC's adoption of Regulation NMS in 2005, have resulted in a dramatic increase in quote and trade volume in the National Market System. The securities markets have experienced significant changes, evolving to a larger number and variety of trading centers that are almost completely automated, with sophisticated, rapid and interconnected systems. As a result of this increase in volume, self-regulatory organizations (“SROs”) and trading centers generally have sought to adopt increasingly robust capacity management plans to ensure that they are capable of processing quote and trade data during volume peaks.
In addition, SROs have found it necessary to develop capacity management plans to mitigate the potential of being penalized for overrunning their volume projections submitted to the consolidated data plans. For example, the Consolidated Tape Association Plan (“CTA Plan”) and the Consolidated Quotation Plan (“CQ Plan”; together, “CTA/CQ Plans”), which serve as the consolidated data plans for securities listed on the New York Stock Exchange, BATS, NYSE Arca, NYSE MKT and other regional exchange-listed securities,
Similar to the approach of the CTA/CQ Plans to capacity planning, FINRA is proposing to adopt the Plan for those FINRA members that opt to utilize the ADF for quoting and trade reporting. ADF Trading Centers would be required to agree to abide by the Plan as part of the Certification that ADF Trading Centers are required to execute and comply with to quote on and report trades to the ADF.
The Plan defines “CTA Securities” as securities subject to the Consolidated Tape Association Plan (i.e., securities listed on the New York Stock Exchange, BATS Exchange Inc., NYSE MKT LLC or NYSE Arca LLC). The Plan defines “UTP Securities” as securities subject to the Unlisted Trading Privileges Plan (i.e., securities listed on the Nasdaq Stock Market, LLC).
Prior to commencing quoting or trade reporting through the ADF, the Plan requires that each ADF Trading Center complete an initial ADF Trading Center Capacity Certification process.
The Plan also requires each ADF Trading Center to submit volume projections for current and future peak data reporting levels on a quarterly basis, and on demand from FINRA. ADF Trading Centers must submit volume projections separately for CTA Securities and UTP Securities, and they must project their volume for quotations, media trade reports, total trade reports, and order reports. An ADF Trading Center is not certified to submit quote, trade or order reporting data at its requested level simply because it has submitted its initial or final volume projections. Rather, prior to submitting quote, trade and order reporting data at its projected volume levels, FINRA staff may require an ADF Trading Center to successfully complete a test at the projected volume levels.
As part of both the initial certification process, and as part of its ongoing utilization of the ADF, an ADF Trading Center is required to provide quarterly volume projections that accurately reflect its anticipated capacity requirements for the next two quarters in order for FINRA to assess ADF system infrastructure requirements. Such anticipated capacity requirements must be submitted on the ADF Trading Center Volume Projections Form (“Form”)
As set forth in the Plan, an ADF Trading Center submits its projections for the next two calendar quarters. Once an ADF Trading Center has submitted its projections for the following quarter, it may not adjust those projections; however, an ADF Trading Center will not be locked into its second quarter projections until the commencement of the planning process for that quarter, e.g., 60 calendar days before the end of the first quarter. FINRA will allow each ADF Trading Center to increase its projections for the second quarter, if necessary. An ADF Trading Center may also lower its projections by up to 10% for the second calendar quarter. Each ADF Trading Center will be subject to an Excess Capacity Usage Fee schedule (“Excess Fee”) and a Shortfall Capacity Usage Fee schedule (“Shortfall Fee”), which are discussed in greater detail below.
The reason for limiting the extent to which an ADF Trading Center may lower its capacity projection for the second calendar quarter for quote and trade data is attributable to the manner in which FINRA incurs costs related to the NMS data plans, including the direct purchase of capacity pursuant to the CTA/CQ Plans.
The Plan sets forth a schedule to ensure that ADF Trading Centers provide timely and accurate volume projections which will enable FINRA to make an accurate assessment of system and capacity requirements. For example, on the first trading day of the second month of the planning cycle, FINRA will notify ADF Trading Centers via email that initial volume projections on the ADF Trading Center Volume Projections Form are due. ADF Trading Centers have ten business days following the initial FINRA notification to provide initial volume projections via email on the ADF Trading Center Volume Projections Form. Between the tenth and twentieth business day following the initial FINRA notification, FINRA advises ADF Trading Centers of the respective ADF Trading Center's Available Capacity based on the ADF Trading Center's projections and requests final volume projections. FINRA will also advise ADF Trading Centers of any necessary ADF system upgrades required to accommodate their volume requests. Between the twentieth and twenty-fifth business day following the initial FINRA notification, ADF Trading Centers are required to give their final volume projections to FINRA via email on the ADF Trading Center Volume Projections Form. To the extent that a capacity increase is required, the system test will be completed between the twentieth and fortieth business days following the initial FINRA request for projections.
As set forth in the Plan, if an ADF Trading Center requests a certain amount of capacity, FINRA will honor such request and will build out capacity to support the ADF Trading Center's peak projected capacity requirements. Once an ADF Trading Center has formally requested capacity, the Plan provides that such request may not be rescinded. A request does not mean, however, that the ADF Trading Center is entitled to submit to the projected level; rather, each ADF Trading Center must still partake in quarterly volume tests before it is certified to its requested volume level.
The Plan also provides that an ADF Trading Center is only authorized to submit increased volume after conducting a capacity test and receiving written notice from FINRA that the ADF Trading Center is certified for operation at the specified level.
Finally, if an ADF Trading Center ceases posting quotes on the ADF or stops reporting trades to the ADF and becomes inactive (either under Rule 6250(g) or by voluntary withdrawal), the Plan provides that such Trading Center will be deemed to have surrendered any capacity to which it was previously certified. The ADF Trading Center is still liable for any Capacity Usage Fees it may have incurred while active.
To the extent that an ADF Trading Center's volume overrun (either in message volume by category or in message per second throughput) threatens, in FINRA's sole discretion, its ability to meet its regulatory obligations, the Plan provides that FINRA has the right to make mid-quarter extraordinary system upgrades to accommodate higher message volume or higher message per second throughput. The costs for such new infrastructure investment will be borne by the ADF Trading Center that has exceeded its Certified Capacity, or, if multiple ADF Trading Centers have exceeded their Certified Capacity, will be allocated among such ADF Trading Centers. In all such instances, FINRA will provide notice to the affected ADF Trading Center(s) that FINRA is taking such actions.
Notwithstanding FINRA's ability to implement a mid-quarter extraordinary system upgrade, to the extent that ADF message volume materially exceeds certified levels of operation, as determined by FINRA staff, the Plan provides that FINRA technical staff may reconfigure the ADF connection to ensure that data levels stay at or below reasonable levels of operation. Such reconfiguration may occur on an intra-day basis in proportion to the extent to which the higher ADF message volume threatens FINRA's system stability and/or the ability of FINRA to meet its regulatory obligations with respect to the operation of the ADF.
The Plan provides that the costs associated with building and implementing the capacity and environments (including, but not limited to, labor, hardware, software, installation, testing, etc., as well as associated on-going operational costs) will be borne by FINRA (except in the event of an Extraordinary Upgrade).
Should FINRA need to add capacity in order to accommodate additional capacity requests, the Plan provides that FINRA will notify the requesting ADF Trading Centers as to the maximum volumes they are permitted to submit until such time as the upgrades have been installed and tested and the ADF Trading Centers have been recertified at the requested level. Until such time that the upgrades are made, FINRA will suspend the application of all Capacity Usage Fees, as described in greater detail below.
If an ADF Trading Center exceeds its Certified Peak Transaction Volume (which is equivalent to the request on the ADF Trading Center Volume Projections Form for “Transactions per Day” for Projected Peak Days) in one or more categories on one or more days in a given calendar month, the Plan sets forth the following Excess Fees that will apply:
All incidents for a calendar month will be assessed at the highest level rate that any incident in that month achieved and at the highest dollar amount based on the number of days.
In this and the following examples, each incident refers to a discrete time when the ADF Trading Center exceeded its capacity. In this example, three different incidents are treated as three days. Since one of these incidents was a Level 3 incident, the fee to be assessed would be for three days at Level 3, or $750.
The Plan provides that, in assessing the Excess Fee, FINRA will (1) use its own metrics to determine if an ADF Trading Center has exceeded its Certified Capacity; (2) notify each ADF Trading Center as soon as possible after it has exceeded its Certified Capacity; and (3) notify each ADF Trading Center when it has incurred an Excess Fee. Any Excess Fee incurred during a month will appear on that month's invoice.
As set forth in the Plan, FINRA will not assess the Excess Fee for the first quarter during which an ADF Trading Center begins operating on the ADF. If an ADF Trading Center begins operations mid-quarter, FINRA will waive the Excess Fee only for the remainder of that quarter.
If an ADF Trading Center does not achieve certain thresholds of both their Projected Average Transaction Volumes and their Certified Peak Transaction Volume in one or more categories on one or more days in a given calendar month, the Plan sets forth the following Shortfall Fees that will apply:
For Projected Average Transaction Volume:
For Certified Peak Transaction Volume:
All incidents for a calendar month will be assessed at the highest level rate that any incident in that month achieved and at the highest dollar amount based on the number of days.
In assessing Shortfall Fees, FINRA will (1) use its own metrics to determine if an ADF Trading Center has fallen below the minimum threshold of activity; (2) provide weekly updates to each ADF Trading Center on their capacity usage; and (3) notify each ADF Trading Center when it has incurred a Shortfall Fee. Any Shortfall Fees incurred during a month will appear on that month's invoice.
As set forth in the Plan, FINRA will not assess the Shortfall Fee for the first quarter during which an ADF Trading Center begins operating on the ADF. If an ADF Trading Center begins operations mid-quarter, FINRA will waive the Shortfall Fee only for the remainder of that quarter.
In addition to making sure that the ADF platform has sufficient infrastructure capacity to handle an ADF Trading Center's message traffic, the Plan provides that FINRA is also responsible for purchasing appropriate levels of capacity in accordance with the NMS data plans. FINRA makes the capacity purchases based on the needs
As set forth in the Plan, FINRA will not assess any SIP penalties for the first quarter during which an ADF Trading Center begins operating on the ADF if it exceeds its projected message traffic during this time. If an ADF Trading Center begins operations mid-quarter, FINRA will waive any SIP capacity penalties only for the remainder of that quarter.
FINRA is proposing to codify the Excess Fees set forth in the Plan as new FINRA Rule 7581, and the Shortfall Fees as new FINRA Rule 7582. FINRA also proposes to codify the provision in the Plan providing for the pass-through of any SIP penalties as new FINRA Rule 7583.
To the extent that an ADF Trading Center's data usage, in the sole discretion of FINRA staff, materially exceeds the ADF Trading Center's Certified Capacity, the Plan provides that FINRA Product Management may incrementally reduce the ADF Trading Center's data port sessions to ensure that data levels stay at or below reasonable levels. Such termination may occur on an intra-day basis and will be proportionate to the extent to which the data overage threatens the ADF system's stability and/or the ability of FINRA to meet its regulatory obligations with respect to the operation of the ADF.
As noted above, an ADF Trading Center also must execute and comply with a Certification, which certifies the ADF Trading Center's compliance efforts with its obligations under Regulation NMS.
FINRA is also making other minor changes to the Certification. Specifically, for purposes in Item 10 of requiring that an ADF Trading Center provide sufficient public notice prior to displaying quotations through the ADF, FINRA is revising the means through which an ADF Trading Center may provide the requisite information to allow for reasonable means such as ADF Trading Center press releases, the FINRA Web site, and through other FINRA-sponsored information publication channels. FINRA also proposes to clarify that the information to be provided pursuant to this Item consists of relevant connectivity and access specifications. FINRA also proposes to delete the parenthetical language in Item 11 to better clarify the scope of that provision, which addresses instances where an ADF Trading Center ceases quoting and order reporting on the same day. FINRA also proposes to delete a reference in Item 4 to “other ADF Trading Centers”, as that reference is duplicative of the reference in that Item to “other FINRA members,” as ADF Trading Centers are, by definition, FINRA members. FINRA is also changing obsolete references and provisions, including replacing references to “NASD” with “FINRA”; changing references from “ADF Operations” to “FINRA Market Operations,” changing a reference from TRACS to the ADF, and deleting a provision relating to ADF Trading Centers that display quotations prior to the implementation of Regulation NMS that also seek to display quotations following the implementation of Regulation NMS. FINRA also proposes to make minor grammatical and stylistic changes, including changing “Web site” to “Web site”, changing “with the respect” to “with respect” in Item 13, and denoting that certain rule references are to SEC rules. Finally, FINRA also proposes to add a signature block to the bottom of the Certification.
The proposed rule change will be effective upon Commission approval.
FINRA believes that the proposed rule change is consistent with the provisions of Section 15A(b)(6) of the Act,
FINRA believes that the Plan, and the proposed amendment to the Certification, are consistent with the Act because they provide an objective and transparent process for administering the capacity usage of the ADF in a manner that helps ensure that FINRA is able to maintain a high level of operability for the ADF, thereby meeting its regulatory obligations, while enhancing FINRA's ability to submit accurate volume projections to the consolidated data plans.
Specifically, the Plan provides a timeframe by which ADF Trading Centers submit initial and final volume projections for the next two calendar quarters, with final volume projections tested and certified by FINRA in the event of a capacity upgrade. The Plan also provides ADF Trading Centers with the ability to increase and decrease their capacity projections for the second quarter in the event that their actual capacity usage deviates from their projected capacity usage. The Plan also sets forth fees for excess capacity usage and shortfall capacity usage, and provides that FINRA will pass through any penalties incurred under the NMS data plans, and will allocate those penalties among the ADF Trading Centers that exceed their projected message traffic. Finally, ADF Trading Centers must sign the Certification,
The Plan also contains provisions that enable FINRA to meet its regulatory obligations to maintain a high level of operability for the ADF. For example, the Plan allows FINRA to make mid-quarter extraordinary system upgrades, and assess ADF Trading Centers for those costs accordingly, in the event that the ADF Trading Center's volume overrun threatens FINRA's ability to meet its regulatory obligations. The Plan also allows FINRA to incrementally terminate an ADF Trading Center's data port sessions in the event that the ADF Trading Center's data usage materially exceeds the ADF Trading Center's Certified Capacity, to the extent such overage threatens the ADF system's stability or the ability of FINRA to meet its regulatory obligations with respect to the operation of the ADF.
Similarly, FINRA believes that the new requirement in the Certification that an ADF Trading Center certify that it will comply with the terms of the Plan will facilitate FINRA's ability to administer the ADF in a manner consistent with its regulatory obligations. The change to the Certification relating to the manner in which an ADF Trading Center will provide public notice of certain information will increase the means through which such notice may be provided, potentially reaching more market participants. FINRA believes that the remaining changes to the Certification will result in a more current, and therefore more accurate, document.
With respect to the proposed Excess and Shortfall Fees, FINRA believes such fees provide for the equitable allocation of fees and other charges among ADF Trading Centers, and do not impose a burden on competition that it is not necessary or appropriate. FINRA notes that the methodology for calculating both the Excess and Shortfall Fees will apply equally to all ADF Trading Centers. Moreover, FINRA believes that the concept of an Excess Fee is reasonable and appropriate given the potential consequences of overrunning volume projections (e.g., the ADF is unable to process the message traffic and FINRA could incur increased costs by purchasing additional capacity to support the increased message traffic to the NMS data plans). FINRA also believes that the concept of the Shortfall Fee is reasonable and appropriate, as it provides incentives for ADF Trading Centers to furnish FINRA with meaningful capacity projections and minimizes the likelihood of FINRA “overbuilding” capacity in response to unreasonably high and unrealistic capacity projections.
FINRA also believes that it is reasonable and appropriate to assess the Excess and Shortfall Fees on quote, trade and order reporting activity. FINRA proposes to assess the Excess and Shortfall Fees both for quote and trade reporting activity because FINRA pays money under both the CTA/CQ and the UTP Plans for quote and trade reporting
FINRA also believes that the methodology for assessing the Excess and Shortfall Fees is consistent with the Act. Similar to the CTA Plan, FINRA will calculate the Excess Fee by evaluating whether peak message volume in the three message categories (quotes, trade reporting, and order reporting) has exceeded its Certified Peak Transaction Volume, with the amount of the Excess Fee determined by the extent and duration of the ADF Trading Center's excess usage.
FINRA also believes that the Excess Fees and Shortfall Fees are consistent with the Act because the methodology for assessing those fees will provide an element of certainty to ADF Trading Centers in calculating their potential Excess and Shortfall Fees. Excess and Capacity Fees will be charged for each message category (quotes, trade reporting, and order reporting) for both the CTA/CQ and UTP Plans. All incidents in the same category (e.g., trade reporting) will be assessed at the highest level rate that any incident in that category achieved in that month, and at the highest dollar amount based on the number of days. Accruals of incidents will apply separately for the three message categories, and for the CTA/CQ and UTP plans. As such, the maximum Excess Fee that an ADF Trading Center could be charged in any given calendar month would be $12,000 (3 categories of messages x 2 plans x $2,000 maximum day/level fee). Using the same calculation, the maximum Shortfall Fee that an ADF Trading Center could be charged in any given calendar month would be $12,000 (3 categories of messages x 2 plans x 2 Shortfall Fees x $1,000 maximum day/level fee).
FINRA also notes that it will not assess the Excess or Shortfall Fees on an
FINRA 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. FINRA notes that the Plan is designed to assist FINRA in meeting its regulatory obligations and maintaining the stability of the ADF while enhancing FINRA's ability to submit accurate volume projections to the consolidated data plans and minimizing the need for FINRA to expend unnecessary resources to maintain data capacity that will not be used. Given that the terms of the Plan, including the Excess and Shortfall Fees, are reasonably designed, in part, to assist FINRA in minimizing unnecessary expenditures in connection with ADF data capacity, FINRA does not believe that the Plan imposes an undue burden on competition on potential ADF Trading Centers or other FINRA members. In this regard, FINRA also notes that the proposed change would apply only to those members that choose to become ADF Trading Centers and use the ADF, and that the terms of the Plan, including the Excess and Shortfall Fees, would not apply to members that are not ADF Trading Centers. Additionally, following discussions with potential ADF Trading Centers, FINRA does not believe that the proposed rule change will impose a significant operational burden on such participants. Indeed, FINRA believes that certain aspects of the proposal, such as the methodology for assessing the Excess and Shortfall Fees, will provide ADF Trading Centers with an element of certainty in calculating the potential costs they might incur in connection with the ADF. In addition, while the Plan requires that ADF Trading Centers provide reasonable capacity estimates, it generally does not restrict ADF Trading Centers' ongoing activities if they exceed such estimates, except where the ADF system's stability or the ability of FINRA to meet its regulatory obligations with respect to the ADF are threatened.
Written comments were neither solicited nor received.
Within 45 days of the date of publication of this notice in the
(A) By order approve or disapprove such proposed rule change, or
(B) institute proceedings to determine whether the proposed rule change should be disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to 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) of the Securities Exchange Act of 1934 (the “Act”),
The Exchange proposes a number of non-controversial and technical changes to its rules. Examples of such
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 these statements may be examined at the places specified in Item IV below. The self-regulatory organization has prepared summaries, set forth in sections A, B and C below, of the most significant aspects of such statements.
The Exchange is proposing to make a number of non-controversial changes and technical corrections to its rules. Examples of such corrections include updating rule number citations and cross-references, correcting typographical errors, and deleting obsolete rule text. Following is a narrative description of each of the corrections:
Topaz Rule 701 (Trading Rotations) is being amended to make a non-substantive change to correct a typographical error in paragraph (b)(2) and to remove the first sentence in paragraph (c), which states that trading in options will close 2 minutes after the primary market on which the underlying stock trades closes for trading. This reference to a 4:02 p.m. closing was imported from the International Securities Exchange (“ISE”) rule book, but should have been removed when the hours of trading on the ISE were amended,
Topaz Rule 705 (Limitation of Liability) is being amended to change a non-substantive word to update the sentence structure of paragraph (a).
Topaz Rule 715 (Types of Orders) is being amended to add the defined terms of “Day Order” and “Good-Till-Cancelled Order (GTC Order).” The addition of these two order types qualify for non-controversial treatment as there is nothing new or novel with respect to these types of orders. Additionally, the Chicago Board Options Exchange has identical order types.
Topaz Rules 803(c) is being amended to remove underlining that does not belong. Topaz Rules 803, 810 and 811 are being amended to remove cross-references to Rule 803(c)(2) and replace them with the correct cross-references, where applicable. These cross-references were imported from the ISE rule book, which were inadvertently missed when paragraph 803(c)(2) was deleted from the ISE rules.
Topaz Rule 804(d)(3) is being deleted as this provision is obsolete and no longer applicable, but was imported from the ISE rule book and (e)(2)(ii) is being amended to delete rule text that was incorrectly imported from the ISE rule book.
The basis under the Act for this proposed rule change is the requirement under Section 6(b)(5)
Most of the proposed rule changes are non-substantive corrections to the Exchange's rules and therefore do not implicate the competition analysis. The change proposing to adopt two new order types is non-controversial as they already exist on another exchange and merely address the time-in-force of an order, and will therefore not impact competition because these order types already exist. The proposed rule changes will serve to promote regulatory clarity and consistency, thereby reducing burdens on the marketplace and facilitating investor protection.
The Exchange has not solicited, and does not intend to solicit, comments on this proposed rule change. The Exchange has not received any unsolicited written comments from members or other interested parties.
Because the foregoing proposed rule change does not significantly affect the protection of investors or the public interest, does not impose any significant burden on competition, and, by its terms, does not become operative for 30 days from the date on which it was filed, or such shorter time as the Commission may designate, it has become effective pursuant to Section 19(b)(3)(A)
At any time within 60 days of the filing of the proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act.
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.
Federal Highway Administration (FHWA), DOT.
Notice.
This notice is a Request for Information (RFI) and comments will be used to help FHWA identify innovative, market-ready technologies that may be considered under the Every Day Counts (EDC) initiative.
Responses to this RFI should be submitted by February 15, 2014. The FHWA will consider late-filed responses to the extent practicable.
Submit responses by electronic mail to
For questions about the program discussed herein, contact Julie Zirlin, FHWA Office of Accelerating Innovation (202) 366–9105,
The FHWA requests information from all sources regarding innovations that have the potential to transform the way we do business by shortening project delivery time, enhancing the safety of our roadways, and protecting the environment. The purpose of this RFI is to obtain information from State, local, and industry partners and the public regarding proven processes or technologies that have the potential to provide efficiencies in the transportation system. This RFI is issued under the FHWA Every Day Counts Initiative.
This is not a solicitation for proposals, applications, proposal abstracts, or quotations. The purpose of this RFI notice is to conduct market research to identify proven innovations. This RFI must not be construed as a commitment by the Government to make an award, nor does the Government intend to directly or indirectly pay for any information or responses submitted as a result of this RFI. Responses to this notice are not offers and cannot be accepted by the Government to form a binding contract or issue a grant. Information obtained as a result of this RFI may be used by the Government for program planning on a non-attribution basis. Respondents should not include any information that might be considered proprietary or confidential.
The FHWA has long been a leader in innovation deployment. The FHWA Administrator Victor Mendez advocates deploying innovation to: (1) Shorten project delivery time, (2) accelerate the use of new technologies to make Government more efficient, and (3) construct highways faster, safer, and to a higher quality. To that end, in 2010, FHWA launched EDC—a broad initiative aimed at shortening project delivery and speeding the deployment of proven, underutilized technologies. The EDC initiative has had a significant impact on the transportation system.
The FHWA believes that the EDC initiative is a foundational part of making innovation a cornerstone of our business and that we can identify rapidly deployable innovations to achieve the goal of better, faster, and smarter project delivery. Society and the highway industry face an unprecedented list of challenges. The public wants greater accountability in how its money is spent. Users and industry want to find ways to make roads safer. We want to preserve the environment for future generations.
The EDC initiative focuses on two pillars for innovation:
•
•
The EDC initiative is designed to focus on a finite set of innovations. Teams consisting of FHWA, State, local, and industry partners and State Transportation Innovation Councils work to deploy the innovations and develop performance measures to gauge their success. The following innovations were promoted in the first two rounds of EDC:
Details of these innovations can be found at
The FHWA invites all sources to respond to this RFI. The FHWA seeks suggestions on innovative, market-ready technologies that meet the criteria described below and may be considered for EDC3. In addition, FHWA seeks comments on user experiences with ten specific high-value innovations that may be considered for accelerated deployment under EDC3. These innovations are described below under “Innovations of Interest.”
Respondents should not submit unique, proprietary, or patented products. The FHWA will only review suggestions of broad categories of innovations.
Responses should provide the following information for each innovation and should not exceed 10 pages for each innovation. There is no limit to the number of innovations that may be recommended.
1. Organization name.
2. Point(s) of contact, email address, and telephone number.
3. Brief description of a proven process or innovation and how it meets the following four criteria:
•
•
•
•
4. Location and date when the innovation was successfully applied in a transportation application and a description of the quantifiable performance benefits of the innovation in those applications.
5. List of supporting specifications, guidelines, and/or procedures are available to support successful national deployment.
6. List of agencies that are the champions of this innovation.
While the Fiscal Year 2013 Traffic Incident Management (TIM) Self-Assessment (SA) effort reflected a positive overall jump in the national SA score, the TIM SA report pointed to a problem that has the potential to impact further advances in this national indicator and threaten individual TIM program institutionalization efforts. The scores on Performance Management—especially collection time of lane closure, time responders remain at the incident scene, and the number of secondary crashes—have declined. The TIM program professionals and associations identify the inability to establish a systematic collection of performance metrics to be a significant inhibitor to the ability to institutionalize TIM. There is a need to help jurisdictions establish an integrated, multidisciplinary and ongoing TIM Performance Management program in order to institutionalize programs and measure results.
Many TIM partners may not realize that the tools to help collect and transmit performance data exist and make the task immediate and uncomplicated. For example, smartphone technology and systems such as the Traffic and Criminal Software (TraCS), funded by DOT and maintained by the Iowa DOT, make data collection easy to capture. Mobile computing devices, like tablets and smartphones, loaded with Web-based, secure software like TraCS can also be used in the field and make data collection easy for the responder with instantaneous transmission and automated analysis.
Some States, cities, and regions recognized benefits from coordinating projects between transportation agencies, utilities, and other agencies that need to do construction in the public ROW. These benefits include cost savings, earlier identification of project impacts, greater ability to reduce and manage traffic disruptions from road work, better quality road surfaces, and reduced exposure for workers. Better coordination of projects can be a “win-win” for public agencies, road users, and citizens by reducing the need for additional work zones. For example:
• San Francisco, California, reduced street cuts by 27 percent by coordinating ROW projects.
• Oregon corridor-level transportation management plans ensure that at least one major north-south corridor and one major east-west corridor are left unrestricted for freight and passenger travel at all times.
• Covington, Kentucky, reduced traffic disruptions and saved nearly $18,000 over several months by coordinating planned paving with water main replacement.
Project coordination can be accomplished using different methods and scopes. Coordination may be done within a single urban area, across a corridor, for a whole State, or across a region that includes neighboring States. Using a combination of methods is the most effective way to get the best results. Coordination methods include:
•
•
•
•
One key new tool that will enhance the ability to coordinate projects is the Workzone Impact and Strategy Estimator software, a product of Strategic Highway Research Program 2 (SHRP2) project R11. The tool will help reduce disruption to the transportation network by assisting agencies sequencing and phasing of road projects both during the programming of projects and later during more detailed project planning and design.
Poor traffic signal performance contributes to 5–10 percent of all traffic delay on the National Highway System (NHS), which contains a fraction of the estimated 311,000 traffic signals in the U.S., valued at $82.7 billion. Best practices for traffic signal operation suggest retiming signals every 3–5 years with ongoing performance monitoring. Several surveys identify phone calls or “complaints” as the primary performance measure for traffic signal operations and maintenance. The 2012 Traffic Signal Report Card assigned a grade of “F” nationally to agency monitoring and performance measurement practices. The lack of performance measurement adversely effects safety and wastes the time and money of both operating agencies and the traveling public by reducing quality and efficiency.
Traffic Signal Automated Performance Measures allow agencies to maximize the effectiveness of signal systems and improve the management of traffic signal assets by proactively monitoring performance and making low cost modifications to the detection, communications, and control systems of intersections.
Monitoring and evaluation of traffic signal systems is critical to improving safety and efficiency. The measures that are currently available enable the effectiveness of signal progression along a given corridor to be monitored using six metrics: Delay, Speed, Approach Volumes, the Purdue Phase Termination Chart, Split Monitor, and Turning Movement Volume Counts. Other measures will be incorporated in the near future.
Adaptive Signal Control Technology (ASCT), included in EDC1, provided the ability to monitor and improve traffic signal performance. Implementing performance measurement before installing ASCT reduces the risks and improves the likelihood of successful implementation. But Traffic Signal Automated Performance Measures would be applicable to all signalized intersections, not just the most challenging locations that are difficult to operate with traditional approaches, where ASCT is typically implemented.
Travel through and around work zones can be frustrating and hazardous to the traveling public and highway workers. Unexpected congestion can have serious consequences for road users. Delays can significantly affect freight shipments and other types of travel. Serious crashes happen at congested approaches to work zones, often resulting in catastrophic loss of life. There have been several recent catastrophic crashes involving commercial vehicles where the commercial vehicle operator did not react soon enough and rear ended stopped vehicles at the end of a queue caused by a work zone, or conversely, where passenger vehicles rear ended a stopped commercial vehicle.
Several Intelligent Transportation Systems (ITS) have been developed in the last few years to address safety and mobility issues that often occur in work zones. Systems are available to do the following: determine travel time through the work zone and advise the public of travel conditions in real time; alert vehicles to a slow moving or stopped queue of vehicles so they can be prepared to stop safely (especially beneficial for commercial motor vehicles); adjust speed limits or merging in response to current traffic conditions; and provide early detection of incidents, reducing the likelihood of secondary crashes.
Several deployments of the various systems demonstrate that they provide both safety and operational benefits. The technologies have advanced to a point where they are accurate and the results are dependable. Options are available that allow systems to be scaled to the project and to make use of permanent ITS when available.
From EDC to the recent Presidential Memorandum
The e-NEPA, a real-time electronic collaboration tool, provides an online workspace and collaboration forum for EIS and environmental assessment projects. It will reduce administrative workloads required to collaborate, maintain records, and create an administrative record. In addition, e-NEPA will allow State DOTs to share documents, track comments, schedule tasks with participating agencies and perform concurrent reviews for their EIS and EA projects.
Each year construction of hundreds of public agency highway projects cross over, under, or parallel to railroad ROWs, requiring extended coordination between these public agencies and railroads. Although most go smoothly, delays in development or construction do occur. Railroads must carefully evaluate public transportation agency projects in terms of safety, engineering, and operational impacts both during construction and for decades later. For public agencies, delays while waiting on railroad reviews and agreements can increase project costs and extend renewal needs for users.
The collection of model agreements, sample contracts, training materials, and standardized best practices developed through SHRP2 will allow public agencies and railroads to identify and circumvent sources of conflict. The tools reflect research that takes into account the perspectives, processes, budgets and funding, and acknowledged best practices of both railroads and public agencies. The report,
With railroad volumes projected to continue to grow, pressures for more project coordination activity will
The administration of a project through the design and construction process requires significant communications and documentation of events. This has traditionally required writing and mailing letters through a Post Office or an internal mail system, keeping project journals, maintaining large file cabinets and file rooms, using physical signatures on paper, and taking notes at in-person meetings. With the advent of enhanced electronic project management tools, different modes of meeting, communicating, and assuring a secure version approval process, we are now accelerating the decisionmaking process. Some additional benefits noted by State DOTs using this technology are improved communications and partnering, decreased cost of printing and mailing services, opportunity to perform parallel work activities.
The Geotechnical Solutions are a Technology Catalog with detailed information on 46 geoconstruction and ground improvement techniques. In addition, the product contains a Technology Selection system to aid in identifying potential technologies for ground modification based on user-defined project conditions. The geotechnical solutions are on a Web site developed as part of the research under the SHRP2 R02 project. The scope was aimed at identifying design and construction solutions for risk elements that may be encountered in project delivery related to: (a) Construction of new embankments and roadways over unstable soils, (b) widening and expansion of existing roadways and embankments and (c) stabilization of geotechnical pavement components and of working platforms. The R02 research team is deploying the product world-wide by promoting it to subject matter experts. Deployment efforts have been targeted at experienced users of the geotechnologies. While the technologies are mature, the Web sites' technology selection system and technology catalog provide a significant resource for critically important information that assists in the design and construction of ground improvement techniques.
Ultra-High Performance Concrete (UHPC) has proven to be a technology that can facilitate simplified, effective-use prefabricated bridge elements and systems (PBES). The proliferation of PBES concepts over the past 4 years has led to recognition among owners and specifiers that robust connection systems are a key part of any successful bridge construction project. The UHPC is a steel fiber reinforced cementitious composite possessing exceptionally high mechanical strengths and durability properties. Field casting of UHPC into the interstitial spaces between prefabricate components engages a strong connection concept, freeing the owner from concerns regarding the short- and long-term performance of the connection. Research and development on this topic over the past 5 years addressed specific connection concepts that are most relevant to the highway bridge community.
The classic roadway reconfiguration, commonly referred to as a “road diet,” involves converting an undivided four-lane roadway into three lanes, made up of two through lanes and a center two-way left-turn lane. The reduction of lanes allows the roadway to be reallocated for other uses such as bike lanes, pedestrian crossing islands and parking. Road diets have multiple safety and operational benefits for drivers as well as nonmotorists. Midblock locations can benefit from road diets because they tend to experience higher travel speeds, contributing to increased injury and fatality rates. More than 80 percent of pedestrians hit by vehicles traveling at 40 mph or faster die, while less than 10 percent die when hit by a vehicle traveling 20 mph or less. When appropriately applied, road diets generated benefits to users of all modes of transportation, including bicyclists, pedestrians and motorists. The resulting benefits include reduced vehicle speeds, improved mobility and access, reduced collisions and injuries and improved livability and quality of life. When modified from four travel lanes to two travel lanes with a two-way left-turn lane, roadways experienced a 29 percent reduction in all roadway crashes. The benefits to pedestrians include reduced crossing distance and fewer midblock crossing locations, which account for more than 70 percent of pedestrian fatalities.
Road diets can be low cost if planned in conjunction with reconstruction or simple overlay projects, since a road diet mostly consists of restriping. The reduction of lanes allows the roadway to be reallocated for other uses such as bike lanes, pedestrian crossing islands, and parking. Road diets have multiple safety and operational benefits for vehicles as well as pedestrians, such as:
• Decreasing vehicle travel lanes for pedestrians to cross, therefore, reducing the multiple-threat crash for pedestrians (when one vehicle stops for a pedestrian in a travel lane on a multilane road, but the motorist in the next lane does not, resulting in a crash),
• Providing room for a pedestrian crossing island,
• Improving safety for bicyclists when bike lanes are added (such lanes also create a buffer space between pedestrians and vehicles),
• Providing the opportunity for on-street parking (also a buffer between pedestrians and vehicles),
• Reducing rear-end and side-swipe crashes, and
• Improving speed limit compliance and decreasing crash severity when crashes do occur.
Federal Transit Administration (FTA), Department of Transportation (DOT).
Notice of Safety Advisory.
On December 31, 2013, the Federal Transit Administration (FTA) issued Safety Advisory 14–1 to provide guidance to State Safety Oversight Agencies (SSOAs) and rail fixed guideway public transportation agencies on redundant protections for roadway workers in the rail transit industry, and review and revision of rules and procedures to protect roadway workers from trains and moving equipment. FTA
For program matters, Thomas Littleton, Associate Administrator for Safety and Oversight, telephone (202) 366–9239 or
On December 19, 2013, the NTSB issued two urgent safety recommendations to FTA. The first, R–13–39, recommends that all rail transit agencies be required to provide redundant protection for their roadway workers, such as positive train control, secondary warning devices, or shunting devices on track. The second, R–13–40, recommends that all rail transit agencies be required to review their rules and procedures for wayside workers and revise them, as necessary, to eliminate any authorization for worker access to transit rights-of-way in which the workers are dependent solely upon themselves to provide protection from trains and moving equipment. These two NTSB recommendations follow an October 19, 2013 accident in which two workers inspecting a dip in track on the Bay Area Rapid Transit (BART) system were killed when both their backs were turned to a train traveling more than sixty miles per hour. The workers had access to the BART right-of-way under a procedure called “simple approval,” which required mere notification to the agency's operations control center—there were no other protections in place for their safety.
The two recommendations are not limited to the BART accident, however. R–13–39 and R–13–40 reflect the results of recent NTSB investigations into fatalities and serious injuries to track workers on the rail transit systems in Boston, Chicago, Houston, Miami, New York, Sacramento, and Washington, DC. October 2013 was one of the deadliest months on record for the nation's rail transit workers. Three workers were killed and two were seriously injured in two separate accidents on the rail transit right-of-way (ROW). Since 2002, 28 rail transit workers have lost their lives while working to maintain the nation's rail transit infrastructure.
We at the FTA and the U.S. Department of Transportation appreciate the urgency of the NTSB's findings, and the critical safety challenge in front of us. Over the last decade, 28 workers have been killed in accidents on the rail transit right-of-way and the systems, rules and procedures put in place to protect transit workers failed each time. We agree, wholeheartedly, with the NTSB's observation that “all rail transit systems are at risk for roadway worker fatalities and injuries.” In response, specifically, to R–13–39 and R–13–40, FTA is issuing Safety Advisory 14–1: Right-of-Way Worker Protection, to both the agencies that own and operate rail fixed guideway systems and the SSOAs that oversee the safety of those systems. Safety Advisory 14–1 is designed to support a comprehensive review of the Right-of-Way Worker Protection (“RWP”) programs already in place at rail transit agencies. It offers options and tools to enhance those programs. The guidance identifies available resources, current industry activities to improve RWPs, and a compilation of lessons learned from right-of-way worker accidents over the last decade, all of which are framed to help rail transit agencies assess their programs within the context of the broader national experience. Safety Advisory 14–1 is available in full on the Transit Safety and Oversight Web page of the FTA public Web site at
Additionally, FTA has asked each SSOA, in coordination with every rail transit agency within its jurisdiction, to complete and submit Appendix 1 to Safety Advisory 14–1, the “Right-of-Way Worker Protection Assessment Checklist,” no later than February 28, 2014, and to oblige every rail transit agency to conduct a formal hazard analysis for the presence of workers on its rail transit right-of-way, no later than May 16, 2014. FTA will use the data and information from the assessment checklists in conducting a broader analysis for a response to NTSB recommendation R–13–39. FTA will use the results of the formal hazard analyses in developing a full response to NTSB recommendation R–13–40. FTA has asked that the formal hazard analyses address the “simple approval” procedure at issue in the BART accident, as appropriate, as well as emergency and scheduled access in work zones and procedures for moving crews, both under traffic and in exclusive occupancy. Also, FTA has stated its interest in how SSOAs and rail transit agencies view the benefits of “lock outs” and various other redundant protections, such as positive train control, secondary warning devices, and shunting devices attached to track. Please see the summaries at
FTA's issuance of Safety Advisory 14–1 is in accordance with the Federal Transit Administrator's authority to “investigate public transportation accidents and incidents and provide guidance to recipients regarding prevention of accidents and incidents.” 49 U.S.C. 5329(f)(5). The requests for information and data from the SSOAs and the rail transit agencies within their jurisdiction are based on FTA's authority to request program information pertinent to rail transit safety under the State Safety Oversight rule, 49 CFR 659.39(d).
National Highway Traffic Safety Administration (NHTSA), U.S. Department of Transportation.
Request for public comment on extension of a currently approved collection of information.
Before a Federal agency can collect certain information from the public, it must receive approval from the Office of Management and Budget (OMB). Under procedures established by the Paperwork Reduction Act of 1995, before seeking OMB approval, Federal agencies must solicit public comment on proposed collections of
This document describes a collection of information for which NHTSA intends to seek OMB approval.
Comments must be received on or before March 10, 2014.
You may submit comments identified by DOT Docket No. NHTSA–2013–0138 by any of the following methods:
• Federal eRulemaking Portal: Go to
• Mail: Docket Management Facility: U.S. Department of Transportation, 1200 New Jersey Avenue SE., West Building Ground Floor, Room W12–140, Washington, DC 20590–0001.
• Hand Delivery or Courier: West Building Ground Floor, Room W12–140, 1200 New Jersey Avenue SE., between 9 a.m. and 5 p.m. ET, Monday through Friday, except Federal holidays. Telephone: 1–800–647–5527.
• Fax: 202–493–2251.
Alex Ansley, Recall Management Division (NVS–215), Room W46–412, NHTSA, 1200 New Jersey Ave., Washington, DC 20590. Telephone: (202) 493–0481.
Under the Paperwork Reduction Act of 1995, before an agency submits a proposed collection of information to OMB for approval, it must first publish a document in the
(i) Whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
(ii) 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;
(iii) how to enhance the quality, utility, and clarity of the information to be collected; and
(iv) how 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, e.g. permitting electronic submission of responses.
In compliance with these requirements, NHTSA asks for public comments on the following collection of information:
Vehicle manufacturers presently collect and maintain purchaser information for business reasons, such as for warranty claims processing and marketing, and experience with this statutory requirement has shown that manufacturers have retained this information in a manner sufficient to enable them to expeditiously notify vehicle purchasers in the case of a safety recall. Based on industry custom and this experience, NHTSA therefore determined that the regulation mentioned in 49 U.S.C. 30117(b) was unnecessary as to vehicle manufacturers. As an aside, the requirement for maintaining tire purchaser information are contained in 49 CFR part 574, Tire Identification and Recordkeeping, and the burden of that information collection is not part of this information collection.
Environmental Protection Agency (EPA).
Proposed rule.
On April 13, 2012, the EPA proposed a new source performance standard for emissions of carbon dioxide for new affected fossil fuel-fired electric utility generating units. The EPA received more than 2.5 million comments on the proposed rule. After consideration of information provided in those comments, as well as consideration of continuing changes in the electricity sector, the EPA determined that revisions in its proposed approach are warranted. Thus, in a separate action, the EPA is withdrawing the April 13, 2012, proposal, and, in this action, the EPA is proposing new standards of performance for new affected fossil fuel-fired electric utility steam generating units and stationary combustion turbines. This action proposes a separate standard of performance for fossil fuel-fired electric utility steam generating units and integrated gasification combined cycle units that burn coal, petroleum coke and other fossil fuels that is based on partial implementation of carbon capture and storage as the best system of emission reduction. This action also proposes standards for natural gas-fired stationary combustion turbines based on modern, efficient natural gas combined cycle technology as the best system of emission reduction. This action also includes related proposals concerning permitting fees under Clean Air Act Title V, the Greenhouse Gas Reporting Program, and the definition of the pollutant covered under the prevention of significant deterioration program.
The hearing will provide interested parties the opportunity to present data, views or arguments concerning the proposed action. The EPA will make every effort to accommodate all speakers who arrive and register. Because this hearing is being held at U.S. government facilities, individuals planning to attend the hearing should be prepared to show valid picture identification to the security staff in order to gain access to the meeting room. In addition, you will need to obtain a property pass for any personal belongings you bring with you. Upon leaving the building, you will be required to return this property pass to the security desk. No large signs will be allowed in the building, cameras may only be used outside of the building and demonstrations will not be allowed on federal property for security reasons.
The EPA may ask clarifying questions during the oral presentations but will not respond to the presentations at that time. Written statements and supporting information submitted during the comment period will be considered with the same weight as oral comments and supporting information presented at the public hearing. Commenters should notify Ms. Garrett if they will need specific equipment, or if there are other special needs related to providing comments at the hearing. The EPA will provide equipment for commenters to show overhead slides or make computerized slide presentations if we receive special requests in advance. Oral testimony will be limited to 5 minutes for each commenter. The EPA encourages commenters to provide the EPA with a copy of their oral testimony electronically (via email or CD) or in hard copy form. Verbatim transcripts of the hearings and written statements will be included in the docket for the rulemaking. The EPA will make every effort to follow the schedule as closely as possible on the day of the hearing; however, please plan for the hearing to run either ahead of schedule or behind schedule. Information regarding the hearing (including information as to whether or not one will be held) will be available at:
The EPA requests that you also submit a separate copy of your comments to the contact person identified below (see
The
In addition to being available in the docket, an electronic copy of this proposed rule will be available on the Worldwide Web (WWW) through the Technology Transfer Network (TTN). Following signature, a copy of the proposed rule will be posted on the TTN's policy and guidance page for newly proposed or promulgated rules at the following address:
Dr. Nick Hutson, Energy Strategies Group, Sector Policies and Programs Division (D243–01), U.S. EPA, Research Triangle Park, NC 27711; telephone number (919) 541–2968, facsimile number (919) 541–5450; email address:
On April 13, 2012, under the authority of Clean Air Act (CAA) section 111, the EPA proposed a new source performance standard (NSPS) to limit emissions of carbon dioxide (CO
This action proposes a standard of performance for utility boilers and IGCC units based on partial implementation of carbon capture and storage (CCS) as the BSER. The proposed emission limit for those sources is 1,100 lb CO
As explained in the Regulatory Impact Analysis (RIA) for this proposed rule, available data—including utility announcements and EIA modeling—indicate that, even in the absence of this rule, (i) existing and anticipated economic conditions mean that few, if any, solid fossil fuel-fired EGUs will be built in the foreseeable future; and (ii) electricity generators are expected to choose new generation technologies (primarily natural gas combined cycle) that would meet the proposed standards. Therefore, based on the analysis presented in Chapter 5 of the RIA, the EPA projects that this proposed rule will result in negligible CO
Greenhouse gas (GHG) pollution
The U.S. Supreme Court ruled that GHGs meet the definition of “air pollutant” in the CAA, and this decision clarified that the CAA's authorities and requirements apply to GHG emissions. Unlike most other air pollutants, GHGs may persist in the atmosphere from decades to millennia, depending on the specific greenhouse gas. This special characteristic makes it crucial to take initial steps now to limit GHG emissions from fossil fuel-fired power plants, specifically emissions of CO
On April 13, 2012, the EPA issued a proposed rule to limit GHG emissions from fossil fuel-fired power plants by establishing a single standard applicable to all new fossil fuel-fired EGUs serving intermediate and base load power demand. After consideration of the information provided in more than 2.5 million comments on the proposal, as well as consideration of continuing changes in the electricity sector,
Congress established requirements under section 111 of the 1970 CAA to control air pollution from new stationary sources through NSPS. Specifically, section 111 requires the EPA to set technology-based standards for new stationary sources to minimize emissions of air pollution to the environment. For more than four decades, the EPA has used its authority under section 111 to set cost-effective emission standards that ensure newly constructed sources use the best performing technologies to limit emissions of harmful air pollutants. In this proposal, the EPA is following the same well-established, customary interpretation and application of the law under section 111 to address GHG emissions from new fossil fuel-fired power plants.
Before determining the appropriate technologies and levels of control that represent BSER for GHG emissions, the EPA must first identify the appropriate sources to control.
The starting point is to consider whether, given current trends concerning coal-fired and natural gas-fired power plants and the nature of GHGs, the EPA should regulate CO
For sources covered under subpart Da, the original proposal relied on analyses,
The EPA notes that, since the original April 2012 proposal, a few coal-fired units have reached the advanced stages of construction and development, which suggests that proposing a separate standard for coal-fired units is appropriate. Since the original proposal, progress on Southern Company's Kemper County Energy Facility, an IGCC facility that will implement partial CCS, has continued, and the project is now over 75 percent complete. Similarly, SaskPower's Boundary Dam CCS Project in Estevan, Saskatchewan, a project that will fully integrate the rebuilt 110 MW coal-fired Unit #3 with available CCS technology to capture 90 percent of its CO
Additionally, two other IGCC projects, Summit Power's Texas Clean Energy Project (TCEP) and the Hydrogen Energy California Project (HECA)—both of which are IGCC units with CCS—continue to move forward. Further, NRG Energy is developing a commercial-scale post-combustion carbon capture project at the company's W.A. Parish generating station southwest of Houston, Texas. The facility is expected to be operational in 2015. Continued progress on these projects is consistent with the EIA modeling which projects that few, if any, new coal-fired EGUs would be built in this decade and that those that are built would include CCS.
In addition to these projects, a number of commenters (on the April 2012 proposal) noted that, if natural gas prices increase, there could be greater interest in the construction of additional coal-fired generation capacity. This, too, is consistent with the EIA analysis, which also suggests that, in a limited number of potential scenarios generally associated with both significantly higher than anticipated electric demand and significantly higher than expected natural gas prices, some additional new coal-fired generation capacity may be built beyond 2020. It is also consistent with publicly available electric utility Integrated Resource Plans (IRPs).
Many of those IRPs indicated the utilities' interest in developing some amount of generating capacity using other intermediate-load and base load technologies, in addition to new NGCC capacity, to meet future demand (albeit, almost always at a higher cost than NGCC technology). Only a few utilities' IRPs indicated that new coal-fired generation without CCS was a technology option that was being considered to meet future demand. Finally, a number of commenters suggested that it was important to set standards that preserve options for fuel diversity, particularly if natural gas prices exceed projected levels. Given this information, the EPA believes that it is appropriate to set a separate standard for solid fossil fuel-fired EGUs, both to address the small number of coal plants that evidence suggests might get built and to set a standard that is robust across a full range of possible futures in the energy and electricity sectors.
Utility announcements about the status of coal projects, IRPs, and EIA projections suggest that, by far, the largest sources of new fossil fuel-fired electricity generation are likely to be NGCC units. The EPA believes, therefore, that it is also appropriate to set a standard for stationary combustion turbines used as EGUs. These units are currently covered under subpart KKKK (stationary combustion turbines).
The EPA also proposes to maintain the definition of EGUs under the NSPS that differentiates between EGUs (sources used primarily for generating electricity for sale to the grid) and non-EGUs (turbines primarily used to generate steam and/or electricity for on-site use). That definition defines EGUs as units that sell more than one-third of their potential electric output to the grid. Under this definition, most simple cycle “peaking” stationary combustion turbines, which typically sell significantly less than one-third of their potential electric output to the grid, would not be affected by today's proposal.
Finally, the EPA is not proposing standards today for one conventional coal-fired EGU project which, based on current information, appears to be the only such project under development that has an active air permit and that has not already commenced construction for NSPS purposes. If the EPA observes that the project is truly proceeding, it may propose a new source performance standard specifically for that source at the time the EPA finalizes today's proposed rule.
Section 111(b) requires the EPA to identify the “best system of emission reduction … adequately demonstrated” (BSER) available to limit pollution. The CAA and subsequent court decisions (detailed later in this notice) identify the factors for the EPA to consider in a BSER determination. For this rulemaking, the following factors are key: feasibility, costs, size of emission reductions and technology.
After considering these four factors, we propose that efficient generation technology implementing partial CCS is the BSER for new affected fossil fuel-fired boilers and IGCC units (subpart Da sources) and modern, efficient NGCC technology is the BSER for new affected combustion turbines (subpart KKKK sources). The foundations for these determinations are described in Sections VII and VIII.
Power generated from the combustion or gasification of coal emits more CO
The three alternatives the EPA considered in the BSER analysis for new fossil fuel-fired utility boilers and IGCC units are: (1) highly efficient new generation that does not include CCS technology, (2) highly efficient new generation with “full capture” CCS and (3) highly efficient new generation with “partial capture” CCS.
Generation technologies representing enhancements in operational efficiency (e.g., supercritical or ultra-supercritical coal-fired boilers or IGCC units) are clearly technically feasible and present little or no incremental cost compared to the types of technologies that some companies are considering for new coal-fired generation capacity. However, they do not provide meaningful reductions in CO
An assessment of the technical feasibility and availability of CCS indicates that nearly all of the coal-fired power plants that are currently under development are designed to use some type of CCS. In most cases, the projects will sell or use the captured CO
Southern Company's Kemper County Energy Facility, a 582 MW IGCC power plant that is currently under construction in Kemper County, Mississippi. The plant will include a CCS system designed to capture approximately 65 percent of the produced CO
SaskPower's Boundary Dam CCS Project, in Estevan, Saskatchewan, Canada, is a commercial-scale CCS project that will fully integrate the rebuilt 110 MW coal-fired Unit #3 with available CCS technology to capture 90 percent of its CO
Texas Clean Energy Project (TCEP), an IGCC plant near Odessa, Texas, that is under development by the Summit Power Group, Inc. (Summit). TCEP is a 400 MW IGCC plant that expects to capture approximately 90 percent of the produced CO
Hydrogen Energy California, LLC (HECA), is proposing to build a plant similar to TCEP in western Kern County, California. The HECA plant is an IGCC plant fueled by coal and petroleum coke that will produce 300 MW of power and will capture CO
The above examples suggest that project developers who are incorporating CCS generally considered two variants: either a partial CCS system or a full CCS system (i.e., usually 90 percent capture or greater). Therefore, the EPA considered both options.
In assessing whether the cost of a certain option is reasonable, the EPA first considered the appropriate frame of reference. Power companies often choose the lowest cost form of generation when determining what type of new generation to build. Based on both the EIA modeling and utility IRPs, there appears to be a general acceptance that the lowest cost form of new power generation is NGCC.
Many states find value in coal investments and have policies and incentives to encourage coal energy generation. Utility IRPs (as well as comments on the April 2012 proposal) suggest that many companies also find value in other factors, such as fuel diversity, and are often willing to pay a premium for it. Utility IRPs suggest that a range of technologies can meet the preference for fuel diversity from a dispatchable form of generation that can provide intermediate or base-load power, including coal without CCS, coal with CCS and nuclear. Biomass-fired power generation
The EPA believes the cost of “full capture” CCS without EOR is outside the range of costs that companies are considering for comparable generation and therefore should not be considered BSER for CO
Finally, the EPA considered whether implementation of “partial capture” CCS should be proposed to be BSER for new fossil fuel-fired utility boilers and IGCC units.
Partial capture CCS has been implemented successfully in a number of facilities over many years. The Great
The EPA analysis shows that the costs of partial CCS are comparable to costs of other non-NGCC generation. The EPA projects LCOE generation ranging from $92/MWh to $110/MWh, depending upon assumptions about technology choices and the amount, if any, of revenue from sale of CO
The projects in development for new coal-fired generation are few in number, and most would already meet an emission limit based on implementation of CCS.
Partial CCS designed to meet an emission standard of 1,100 lb CO
After conducting a BSER analysis of the three options described above, the EPA proposes that new fossil fuel-fired utility boilers and IGCC units implementing partial CCS best meets the requirements for BSER. It ensures that any new fossil fuel-fired utility boiler or IGCC unit will achieve meaningful emission reductions in CO
We considered two alternatives in evaluating the BSER for new fossil fuel-fired stationary combustion turbines: (1) modern, efficient NGCC units and (2) modern, efficient NGCC units with CCS.
NGCC units are the most common type of new fossil fuel-fired units being planned and built today. The technology is in wide use. Nearly all new fossil fuel-fired EGUs being constructed today are using this advanced, efficient system for generating intermediate and base load power. Importantly, NGCC is an inherently lower CO
By contrast, NGCC with CCS is not a configuration that is being built today. The EPA considered whether NGCC with CCS could be identified as the BSER adequately demonstrated for new stationary combustion turbines, and we decided that it could not. At this time, CCS has not been implemented for NGCC units, and we believe there is insufficient information to make a determination regarding the technical feasibility of implementing CCS at these types of units. The EPA is aware of only one NGCC unit that has implemented CCS on a portion of its exhaust stream. This contrasts with coal units where, in addition to demonstration projects, there are several full-scale projects under construction and a coal gasification plant which has been demonstrating much of the technology needed for an IGCC to capture CO
After considering both technology options, the EPA is proposing to find modern, efficient NGCC technology to be the BSER for stationary combustion turbines, and we are basing the proposed standards on the performance of recently constructed NGCC units. The EPA is proposing that larger units be required to meet a standard of 1,000 lb CO
The EPA is considering two options for codifying the requirements. Under the first option EPA is proposing to codify the standards of performance for the respective sources within existing 40 CFR Part 60 subparts. Applicable
This action presents the EPA's proposed approach for setting standards of performance for new affected fossil fuel-fired electric utility steam generating units (utility boilers) and stationary combustion turbines. The rationale for regulating GHG emissions from the utility power sector, including related regulatory and litigation background and relationship to other rulemakings, is presented below in Section II. The specific proposed requirements for new sources are described in detail in Section III. The rationale for reliance on a rational basis to regulate GHG emissions from fossil fuel-fired EGUs is presented in Section IV, followed by the rationale for applicability requirements in Section V. The legal requirements for establishing emission standards are discussed in detail in Section VI. Sections VII and VIII describe the rationale for each of the proposed emission standards, including an explanation of the determination of BSER for new fossil fuel-fired utility boilers and IGCC units and for natural gas-fired stationary combustion turbines, respectively. Implications for Prevention of Significant Deterioration (PSD) and title V programs are described in Section IX, and impacts of the proposed action are described in Section X. In Section XI, the agency specifically requests comments on the proposal. A discussion of statutory and executive order reviews is provided in Section XII, and the statutory authority for this action is provided in Section XIII. Also published today in the
Today's proposal outlines an approach for setting standards of performance for emissions of carbon dioxide for new affected fossil fuel-fired electric utility steam generating units (utility boilers) and stationary combustion turbines.
The entities potentially affected by the proposed standards are shown in Table 1 below.
This table is not intended to be exhaustive, but rather to provide a guide for readers regarding entities likely to be affected by this proposed action. To determine whether your facility, company, business, organization, etc., would be regulated by this proposed action, you should examine the applicability criteria in 40 CFR 60.1. If you have any questions regarding the applicability of this action to a particular entity, consult either the air permitting authority for the entity or your EPA regional representative as listed in 40 CFR 60.4 or 40 CFR 63.13 (General Provisions).
In this section we discuss climate change impacts from GHG emissions, both on public health and public welfare, and the science behind the agency's conclusions. We present information about GHG emissions from fossil-fuel fired EGUs, and we describe the utility power sector and its changing structure. We then provide the statutory, regulatory, and litigation background for this proposed rule. We close this section by discussing how this proposed rule coordinates with other rulemakings and describing actions to obtain stakeholder input on this topic and the original proposed rule.
In 2009, the EPA Administrator issued the document we refer to as the Endangerment Finding under CAA section 202(a)(1).
Anthropogenic emissions of GHGs and consequent climate change threaten public health in multiple aspects. By raising average temperatures, climate change increases the likelihood of heat waves, which are associated with increased deaths and illnesses. While climate change also leads to reductions in cold-related mortality, evidence indicates that the increases in heat mortality will be larger than the decreases in cold mortality. Climate change is expected to increase ozone pollution over broad areas of the country, including large population areas with already unhealthy surface ozone levels, and thereby increase morbidity and mortality. Other public health threats also stem from increases in intensity or frequency of extreme weather associated with climate change, such as increased hurricane intensity, increased frequency of intense storms and heavy precipitation. Increased coastal storms and storm surges due to rising sea levels are expected to cause increased drownings and other health
Anthropogenic emissions of GHGs and consequent climate change also threaten public welfare in multiple aspects. Climate changes are expected to place large areas of the country at serious risk of reduced water supplies, increased water pollution, and increased occurrence of extreme events such as floods and droughts. Coastal areas are expected to face increased risks from storm and flooding damage to property, as well as adverse impacts from rising sea level, such as land loss due to inundation, erosion, wetland submergence and habitat loss. Climate change is expected to result in an increase in peak electricity demand, and extreme weather from climate change threatens energy, transportation, and water resource infrastructure. Climate change may exacerbate ongoing environmental pressures in certain settlements, particularly in Alaskan indigenous communities. Climate change also is very likely to fundamentally rearrange U.S. ecosystems over the 21st century. Though some benefits may balance adverse effects on agriculture and forestry in the next few decades, the body of evidence points towards increasing risks of net adverse impacts on U.S. food production, agriculture and forest productivity as temperature continues to rise. These impacts are global and may exacerbate problems outside the U.S. that raise humanitarian, trade, and national security issues for the U.S.
The EPA received comments in response to the April 2012 proposed NSPS rule (77 FR 22392) that addressed the scientific underpinnings of the EPA's 2009 Endangerment Finding and hence the proposed rule. The EPA carefully reviewed all of those comments. It is important to place these comments in the context of the history and associated voluminous record on this subject that has been compiled over the last few years, including: (1) the process by which the Administrator reached the Endangerment Finding in 2009; (2) the EPA's response in 2010 to ten administrative petitions for reconsideration of the Endangerment Finding (the Reconsideration Denial)
As outlined in Section VIII.A. of the 2009 Endangerment Finding, the EPA's approach to providing the technical and scientific information to inform the Administrator's judgment regarding the question of whether GHGs endanger public health and welfare was to rely primarily upon the recent, major assessments by the U.S. Global Change Research Program (USGCRP), the Intergovernmental Panel on Climate Change (IPCC), and the National Research Council (NRC) of the National Academies. These assessments addressed the scientific issues that the EPA was required to examine, were comprehensive in their coverage of the GHG and climate change issues, and underwent rigorous and exacting peer review by the expert community, as well as rigorous levels of U.S. government review. The EPA received thousands of comments on the proposed Endangerment Finding and responded to them in depth in an 11-volume Response to Comments (RTC) document.
The EPA then reviewed ten administrative petitions for reconsideration of the Endangerment Finding in 2010. In the Reconsideration Denial, the Administrator denied those petitions on the basis that the Petitioners failed to provide substantial support for the argument that the EPA should revise the Endangerment Finding and therefore their objections were not of “central relevance” to the Finding. The EPA prepared an accompanying three-volume Response to Petitions (RTP) document to provide additional information, often more technical in nature, in response to the arguments, claims, and assertions by the petitioners to reconsider the Endangerment Finding.
The 2009 Endangerment Finding and the 2010 Reconsideration Denial were challenged in a lawsuit before the D.C. Circuit. On June 26, 2012, the Court upheld the Endangerment Finding and the Reconsideration Denial, ruling that the Finding (including the Reconsideration Denial) was not arbitrary or capricious, was consistent with the U.S. Supreme Court's decision in
The EPA evaluated the processes used to develop the various assessment reports, reviewed their contents, and considered the depth of the scientific consensus the reports represented. Based on these evaluations, the EPA determined the assessments represented the best source material to use in deciding whether GHG emissions may be reasonably anticipated to endanger public health or welfare.
As the Court stated—
It makes no difference that much of the scientific evidence in large part consisted of `syntheses' of individual studies and research. Even individual studies and research papers often synthesize past work in an area and then build upon it. This is how science works. The EPA is not required to re-prove the existence of the atom every time it approaches a scientific question.
In the context of this extensive record and the recent affirmation of the Endangerment Finding by the Court, the EPA considered all of the submitted comments and reports for the April 2012 proposed NSPS rule. As it did in the Endangerment Finding, the EPA gave careful consideration to all of the scientific and technical comments and information in the record. The major peer-reviewed scientific assessments, however, continue to be the primary scientific and technical basis for the Administrator's judgment regarding the threats to public health and welfare posed by GHGs.
Commenters submitted two major peer-reviewed scientific assessments released after the administrative record concerning the Endangerment Finding closed following the EPA's 2010 Reconsideration Denial: the IPCC's 2012 “Special Report on Managing the Risks of Extreme Events and Disasters to Advance Climate Change Adaptation” (SREX) and the NRC's 2011 “Report on Climate Stabilization Targets: Emissions, Concentrations, and Impacts over Decades to Millennia” (Climate Stabilization Targets).
According to the IPCC in the SREX, “A changing climate leads to changes in the frequency, intensity, spatial extent, duration, and timing of extreme weather and climate events, and can result in unprecedented extreme weather and climate events.
In the Climate Stabilization Targets assessment, the NRC states:
Emissions of carbon dioxide from the burning of fossil fuels have ushered in a new epoch where human activities will largely determine the evolution of Earth's climate. Because carbon dioxide in the atmosphere is long lived, it can effectively lock Earth and future generations into a range of impacts, some of which could become very severe.
The assessment concludes that carbon dioxide emissions will alter the atmosphere's composition and therefore the climate for thousands of years; and attempts to quantify the results of stabilizing GHG concentrations at different levels. The report also projects the occurrence of several specific climate change impacts, finding warming could lead to increases in heavy rainfall and decreases in crop yields and Arctic sea ice extent, along with other significant changes in precipitation and stream flow. For an increase in global average temperature of 1 to 2 °C above pre-industrial levels, the assessment found that the area burnt by wildfires in western North America will likely more than double and coral bleaching and erosion will increase due both to warming and ocean acidification. An increase of 3 °C will lead to a sea level rise of 0.5 to 1 meter by 2100. With an increase of 4 °C, the average summer in the United States would be as warm as the warmest summers of the past century. The assessment notes that although many important aspects of climate change are difficult to quantify, the risk of adverse impacts is likely to increase with increasing temperature, and the risk of surprises can be expected to increase with the duration and magnitude of the warming.
Several other National Academy assessments regarding climate have also been released recently. The EPA has reviewed these assessments and finds that in general, the improved understanding of the climate system they and the two assessments described above present strengthens the case that GHGs are endangering public health and welfare. Three of the new NRC assessments provide estimates of projected global sea level rise that are larger than, and in some cases more than twice as large as, the rise estimated in a 2007 IPCC assessment of between 0.18 and 0.59 meters by the end of the century, relative to 1990. (It should be noted that in 2007, the IPCC stated that including poorly understood ice sheet processes could lead to an increase in the projections.)
One of these assessments projects a global sea level rise of 0.5 to 1.4 meters by 2100, which is sufficient to lead to rising relative sea level even in the northern states.
Another NRC assessment finds that “the magnitude and rate of the present greenhouse gas increase place the climate system in what could be one of the most severe increases in radiative forcing of the global climate system in
Similarly, another NRC assessment finds that “[t]he chemistry of the ocean is changing at an unprecedented rate and magnitude due to anthropogenic carbon dioxide emissions; the rate of change exceeds any known to have occurred for at least the past hundreds of thousands of years.”
Comments were submitted in support of the Endangerment Finding, which provided additional documentation showing that climate change is a threat to public health and welfare. Commenters provided several individual studies and documentation of observed or projected climate changes of local importance or concern to commenters. The EPA appreciates these comments, but as previously stated, we place lesser weight on individual studies than on major scientific assessments. Local observed changes must be assessed in the context of the broader scientific picture, as it is more difficult to draw robust conclusions regarding climate change over short time scales and in small geographic regions.
The EPA plans to continue relying on the major assessments by the USGCRP, the IPCC, and the NRC. Studies from these bodies address the scientific issues that the Administrator must examine, represent the current state of knowledge on the key elements for the endangerment analysis, comprehensively cover and synthesize thousands of individual studies to obtain the majority conclusions from the body of scientific literature and undergo a rigorous and exacting standard of review by the peer expert community and U.S. government.
Several commenters argued that the Endangerment Finding should be reconsidered or overturned based on those commenters' reviews of specific climate science literature, including publications that have appeared since the EPA's 2010 Reconsideration Denial. Some commenters presented their own compilations of individual studies and other documents to support their assertions that climate change will have beneficial effects in many cases and that climate impacts will not be as severe or adverse as the EPA, and the assessment reports upon which the EPA relied, have stated. Some commenters also concluded that U.S. society will easily adapt to climate change and that it therefore does not threaten public health and welfare, and some commenters questioned the Endangerment Finding based on a 2011 EPA Inspector General's report.
The EPA reviewed the submitted information and found that overall, the commenters' critiques of the rule's scientific basis were addressed in the EPA's response to comments for the 2009 Endangerment Finding, the EPA's responses in the 2010 Reconsideration Denial, or the D.C. Circuit's 2012 decision upholding the EPA's 2009 Endangerment Finding. The EPA nonetheless carefully reviewed these comments and associated documents and found that nothing in them would change the conclusions reached in the Endangerment Finding. These recent publications submitted by commenters, and any new issues they may present, do not undermine either the significant body of scientific evidence that has accumulated over the years or the conclusions presented in the substantial peer-reviewed assessments of the USGCRP, NRC, and IPCC.
One commenter submitted emails between climate change researchers from the period 1999 to 2009 that were surreptitiously obtained from a University of East Anglia server in 2009 and publicly released in 2011. According to the commenter, these emails showed that the climatologists distorted their research results to prove that climate change causes adverse effects. The EPA reviewed these emails and found that they raised no issues that Petitioners had not already raised concerning other emails from the same incident, released in 2009. The commenter's unsubstantiated assumptions and subjective assertions regarding what the emails purport to show about the state of climate change science is not adequate evidence to challenge the voluminous and well-documented body of science that underpins the Administrator's Endangerment Finding.
Some commenters argued for reconsideration based on uncertainty regarding climate science. However, the EPA made the decision to find endangerment with full and explicit recognition of the uncertainty involved, stating that “[t]he Administrator acknowledges that some aspects of climate change science and the projected impacts are more certain than others.”
Some commenters also argued that the U.S. will adapt to climate change impacts and that therefore climate change impacts pose no threat. However, the D.C. Circuit, in
Some commenters raised issues regarding the EPA Inspector General's report,
In addition, some commenters argued that the Endangerment Finding should be overturned because of the carbon dioxide fertilization effect, that is, the proposition that increased amounts of carbon dioxide can spur growth of vegetation. However, these commenters did not show how the science they provide on the subject differs from the carbon dioxide fertilization science already considered by the Administrator in the Endangerment Finding or how the existence of some benefits from the carbon dioxide fertilization effect could outweigh the numerous negative impacts of climate change.
In sum, the EPA reviewed all of the comments purporting to refute the Endangerment Finding to determine whether they provide evidence that the Administrator's judgment that climate change endangers public health and welfare was flawed, because the Administrator misinterpreted the underlying assessments, because the science in new peer reviewed assessments differs from that in previous assessments, or because new individual studies provide compelling reasons for the EPA to change its interpretation of, or place less weight on, the major findings reflected in the assessment reports. In all cases, the commenters failed to demonstrate that the science that the Administrator relied on was inaccurate or that the additional information from the commenter is of central relevance to the Administrator's judgment regarding endangerment. For these reasons, the commenters on the original proposal that criticized the Endangerment Finding have not provided a sufficient basis to cast doubt on the Finding.
Fossil fuel-fired electric utility generating units are by far the largest emitters of GHGs, primarily in the form of CO
The EPA prepares the official U.S. Inventory of Greenhouse Gas Emissions and Sinks
Total fossil energy-related CO
We are aware that nitrous oxide (N
The majority of power in the U.S. is generated from the combustion of coal, natural gas and other fossil fuels.
Natural gas-fired EGUs typically use one of two technologies: NGCC and simple cycle combustion turbines. NGCC units first generate power from a combustion turbine (the combustion cycle). The unused heat from the combustion turbine is then routed to a Heat Recovery Steam Generator (HRSG) which generates steam which is used to generate power using a steam turbine (the steam cycle). The combining of these generation cycles increases the overall efficiency of the system.
Simple cycle combustion turbines only use a single combustion turbine to produce electricity (i.e., there is no heat recovery). The power output from these simple cycle combustion turbines can be easily ramped up and down making them ideal for “peaking” operations.
Coal-fired utility boilers are primarily either pulverized coal (PC) boilers or fluidized bed (FB) boilers. At a PC boiler, the coal is crushed (pulverized) into a powder in order to increase its surface area. The coal powder is then blown into a boiler and burned. In a coal-fired boiler using fluidized bed combustion, the coal is burned in a layer of heated particles suspended in flowing air.
Power can also be generated using gasification technology. An IGCC unit gasifies coal to form a syngas composed of carbon monoxide (CO) and hydrogen (H
Since the April 2012 proposal, a few coal-fired units have reached the advanced stages of construction and development, which suggests that setting a separate standard for new fossil fuel-fired boilers and IGCC units is appropriate. Progress on Southern Company's Kemper County Energy Facility, which will deploy IGCC with partial CCS, has continued, and the project is now over 75 percent complete. Additionally, two other projects, Summit Power's Texas Clean Energy Project (TCEP) and the Hydrogen Energy California Project (HECA)—both of which will deploy IGCC with CCS—continue to move forward. The EIA modeling projects that coal-fired power generation will remain the single largest portion of the electricity sector beyond 2030. The EIA modeling also projects that few, if any, new coal-fired EGUs would be built in this decade and that those that are built would have CCS.
Natural gas prices have decreased dramatically and generally stabilized in recent years, as new drilling techniques have brought additional supply to the marketplace and greatly increased the domestic resource base. As a result, natural gas prices are expected to be competitive for the foreseeable future and EIA modeling and utility announcements confirm that utilities are likely to rely heavily on natural gas to meet new demand for electricity generation. On average, as discussed below, the cost of generation from a new natural-gas fired power plant (a NGCC unit) is expected to be significantly lower than the cost of generation from a new coal-fired power plant.
Other drivers that may influence decisions to build new power plants are increases in renewable energy supplies, often due to state and federal energy policies. Many states have adopted renewable portfolio standards (RPS), which require a certain portion of electricity to come from renewable energy sources such as solar or wind. The federal government has also adopted incentives for electric generation from renewable energy sources and loan guarantees for new nuclear power plants.
Due to these factors, the EIA projections from the last several years show that natural gas is likely to be the most widely-used fossil fuel for new construction of electric generating capacity through 2020, along with renewable energy, nuclear power, and a limited amount of coal with CCS.
Various energy sector modeling efforts, including projections from the EIA and the EPA, forecast trends in new power plant construction and utilization of existing power plants that are consistent with the above-described technological developments and costs. The EIA forecasts the structure and developments in the power sector in its annual report, the Annual Energy Outlook (AEO). These reports are based on economic modeling that reflects existing policy and regulations, such as state RPS programs and federal tax credits for renewables.
Specifically, the AEO 2013 projects the need for 25.9 GW of additional base load or intermediate load generation capacity through 2020 (this includes projects that are under development—i.e., being constructed or in advance planning—and model-projected nuclear, coal, and NGCC projects). The vast majority of this new electric capacity (22.5 GW) is already under development (under construction or in advanced planning); it includes about 6.1 GW of new coal-fired capacity, 5.5 GW of new nuclear capacity, and 10.9 GW of new NGCC capacity. The EPA believes that most current fossil fuel-fired projects are already designed to meet limits consistent with today's proposal (or they have already commenced construction and are thus not impacted by today's notice). The AEO 2013 also projects an additional 3.4 GW of new base load capacity additions, which are model-projected (unplanned). This consists of 3.1 GW of new NGCC capacity, and 0.3 GW of new coal equipped with CCS (incentivized with some government funding). Therefore, the AEO 2013 projection suggests that this proposal would only impact small amounts of new power generating capacity through 2020, all of which is expected to already meet the proposed emissions standards without incurring further control costs. In AEO 2013, this is also true during the period from 2020 through 2034, where new model-projected (unplanned) intermediate and base load capacity is expected to be compliant with the proposed standard without incurring further control costs (i.e., an additional 45.1 GW of NGCC and no additional coal, for a total, from 2013 through 2030, of 48.2 GW of NGCC and 0.3 GW of coal with CCS).
It should be noted that under the EIA projections, existing coal-fired generation will remain an important part of the mix for power generation. Modeling from both the EIA and the EPA predict that coal-fired generation will remain the largest single source of electricity in the U.S. through 2040. Specifically, in the EIA's AEO 2013, coal will supply approximately 40 percent of all electricity in both 2020 and 2025.
The EPA modeling using the Integrated Planning Model (IPM), a detailed power sector model that the EPA uses to support power sector regulations, also shows limited future construction of new coal-fired power plants under the base case.
The trends in the power sector described above are also apparent in publicly available long-term resource plans, known as IRPs.
The EPA has reviewed publicly available IRPs from a range of companies (e.g., varying in size, location, current fuel mix), and these plans are generally consistent with both EIA and EPA modeling projections. Companies seem focused on demand-side management programs to lower future electricity demand and mostly reliant on a mix of new natural gas-fired generation and renewable energy to meet increased load demand and to replace retired generation capacity.
Notwithstanding this clear trend towards natural gas-fired generation and renewables, many of the IRPs raise fuel diversity concerns and include options to diversify new generation capacity beyond natural gas and renewable energy. Several IRPs indicate that companies are considering new nuclear generation, including either traditional nuclear power plants or small modular reactors, and new coal-fired generation capacity with and without CCS technology. Based on these IRPs, the EPA acknowledges that a small number of new coal-fired power plants may be built in the near future. While this is contrary to the economic modeling predictions, the Agency understands that economic modeling may not fully reflect the range of factors that a particular company may consider when evaluating new generation options, such as fuel diversification. By the same token, as discussed below, it is possible that some of this potential new coal-fired construction may occur because developers are able to design projects that can provide competitively priced electricity for a specific geographic region.
Section 111 of the Clean Air Act sets forth the standards of performance for new sources (NSPS) program, and with this program, establishes mechanisms for regulating emissions of air pollutants from stationary sources that are key in this rulemaking.
Once the EPA has listed a source category, the EPA proposes and then promulgates “standards of performance” for “new sources” in the category.
Clean Air Act section 111(a)(1) defines a “standard of performance” as a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated.
This definition makes clear that the standard of performance must be based on controls that constitute “the best system of emission reduction . . . adequately demonstrated” (BSER).
Regarding other titles in the CAA, this rulemaking has implications for EGUs and other stationary sources in the CAA PSD program under Title I, part C, and the operating permits program under Title V. We discuss these implications in section IX of this preamble.
The EPA initially included fossil fuel-fired EGUs (which includes EGUs that burn fossil fuel including coal, gas, oil and petroleum coke and that use different technologies, including boilers and combustion turbines) in a category that it listed under section 111(b)(1)(A), and the EPA promulgated the first set of standards of performance for EGUs in 1971, codified in subpart D.
In 1979, the EPA revised subpart D of 40 CFR part 60; as part of this revision, the EPA formed subpart Da and promulgated NSPS for electric utility steam generating units.
The EPA promulgated amendments to subpart Da in 2006, resulting in new criteria pollutant limitations for EGUs (the 2006 Final Rule).
The Court severed portions of the petitions for review of the 2006 Final Rule that related to GHG emissions. Following the U.S. Supreme Court's 2007 decision in
In June 2012, the D.C. Circuit, in
In June 2012, several companies filed petitions for review of the original proposal for this rulemaking action in the D.C. Circuit. In December 2012, the D.C. Circuit dismissed these petitions on grounds that the challenged proposed rule is not final agency action subject to judicial review.
In April 2013, EPA completed rulemaking to regulate power plants in the Mercury and Air Toxics rule (“MATS”).
EGUs are the subject of several recent CAA rulemakings.
We note that the EPA recently finalized revisions to the MATS rule as related to new sources.
The EPA recognizes that it is important that each of these regulatory efforts achieves its intended environmental objectives in a common-sense, cost-effective manner consistent with the underlying statutory requirements and assures a reliable power system. Executive Order (EO) 13563 states that “[i]n developing regulatory actions and identifying appropriate approaches, each agency shall attempt to promote . . . coordination, simplification, and harmonization. Each agency shall also seek to identify, as appropriate, means to achieve regulatory goals that are designed to promote innovation.” Recent guidance from the Office of Management and Budget's Office of Information and Regulatory Affairs has emphasized the importance of, where appropriate and feasible, the consideration of cumulative effects in regulated industries and the harmonization of rules in terms of both content and timing. We believe that these recent finalized and proposed rules will allow industry to comply with its obligations as efficiently as possible, by making coordinated investment decisions and, to the greatest extent possible, adopting integrated compliance strategies.
The EPA has extensively interacted with many different stakeholders regarding climate change, source contributions, and emission reduction opportunities. These stakeholders included industry entities, environmental organizations and many regional, state, and local air quality management agencies, as well as the general public. As part of developing the original proposed rule, the EPA held five listening sessions in February and March 2011 to obtain additional information and input from key stakeholders and the public. Each of the five sessions had a particular target audience; these were the electric power industry, environmental and environmental justice organizations, states and Tribes, coalition groups and the petroleum refinery industry. Each session lasted two hours and featured a facilitated roundtable discussion among stakeholder representatives. The EPA asked key stakeholder groups to identify these roundtable participants in advance of the listening sessions. The EPA accepted comments from the public at the end of each session and via the electronic docket system.
On May 3, 2012, the EPA announced that it would hold two public hearings on the original proposed rule. The hearings were both held on May 24, 2012, in Washington, DC and Chicago, IL. Also on May 3, 2012, the EPA announced an extension of the public comment period for the original proposed rule, until June 25, 2012. The EPA received more than 2.5 million public comments on the original proposed rule.
This section describes the proposed requirements in this rulemaking for new sources. We describe our rationale for several of these proposed requirements—the applicability requirements, the basis for the standards of performance for fossil-fuel fired boilers, and the basis for the standards of performance for combustion turbines—in Sections V–VIII of this preamble.
We generally refer to sources that would be subject to the standards of performance in this rulemaking as “affected” or “covered” sources, units, facilities, or simply as EGUs. These sources meet both the definition of “affected” and “covered” EGUs subject to an emission standard as provided by this rule, and the requirements for “new” sources as defined under the provisions of CAA section 111.
Subpart Da currently defines an EGU as a boiler that is: (1) “capable of combusting” more than 250 MMBtu/h heat input of fossil fuel,
For the purposes of this rule, we are proposing several additional changes to the way applicability is currently determined under subpart Da. First, the proposed definition of potential electric output includes “or the design net electric output efficiency” as an alternative to the default one-third efficiency value for determining the value of the potential electric output. Next, we are proposing to add “of the thermal host facility or facilities” to the definition of net-electric output for determining electric sales with respect to the NSPS. Finally, consistent with our approach in the NSPS part of the MATS rule and the original proposal for this rulemaking, we are proposing to amend the definition of a steam generating unit to include “plus any integrated equipment that provides electricity or useful thermal output to either the affected facility or auxiliary equipment” instead of the existing language “plus any integrated combustion turbines and fuel cells”. We are also proposing to add the additional language to the definition of IGCC and stationary combustion turbine.
This action proposes to regulate covered EGU emissions of CO
The proposed CO
Issues related to accounting for biogenic CO
We are not proposing standards for certain types of sources. These include new steam generating units and stationary combustion turbines that sell one-third or less of their potential output to the grid; new non-natural gas-fired stationary combustion turbines;
In this rulemaking, the EPA is proposing NSPS for CO
The proposed standard of performance for each subcategory is in the form of a gross energy output-based CO
The subcategories, for which the EPA is proposing separate standards of performance, are (1) natural gas-fired stationary combustion turbines with a heat input rating that is greater than 850 MMBtu/h;
We are proposing that all affected new fossil fuel-fired EGUs are required to meet an output-based emission rate of a specific mass of CO
While the EPA is proposing specific standards of performance for each subcategory, we are also taking comment on a range of potential emission limitations. We solicit comment on a range of 950–1,100 lb CO
The proposed method to calculate compliance is to sum the emissions for all operating hours and to divide that value by the sum of the useful energy output over a rolling 12-operating-month period. In the alternative, we solicit comment on requiring calculation of compliance on an annual (calendar year) period.
Subpart Da currently defines “gross energy output” from new units as the “gross electrical or mechanical output from the affected facility minus any electricity used to power the feedwater pumps and any associated gas compressors (air separation unit main compressor, oxygen compressor, and nitrogen compressor) plus 75 percent of the useful thermal output measured relative to ISO conditions”
In contrast, in the April 2012 proposal, we proposed a definition of gross output as “the gross electrical or mechanical output from the unit plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit
After further consideration and because many of the proposed IGCC facilities are actually co-production facilities (i.e., they produce useful byproducts and chemicals along with electricity), we have concluded that measuring the electricity used by the primary gas compressors associated with electricity production at IGCC facilities could be more challenging to implement.
Therefore, we are proposing to define the gross energy output for traditional steam generating units to include the electricity measured at the generator terminals minus electric power used to run the feedwater pumps, and to define the gross electric output for IGCC and subpart KKKK affected facilities to include the electricity measured at the generator terminals. We are considering and requesting comment on (1) whether the definition of “gross energy output” in subpart Da for GHGs should be consistent with the current definition in subpart Da for criteria pollutants, (2) whether we should adopt the proposed definition of “gross energy output”, and (3) whether the definition should be the same for both traditional and IGCC facilities. We seek comment on how to account for energy consumption associated with products other than electricity and useful thermal output created at a poly-generation facility and the impact of that energy use on the numerical emissions standard, all of which is relevant to possible adoption of an adjusted gross output definition.
We are also considering and requesting comment on using net-output based standards either as a compliance alternative for, or in lieu of, gross-output based standards, including whether we should have a different approach for different subcategories. In the compliance alternative approach, owners/operators would elect to comply with either a gross-output based standard or an alternate net-output based standard. As described in the original proposal for this rulemaking, net output is the combination of the gross electrical output of the electric generating unit minus the parasitic (i.e., auxiliary) power requirements. A parasitic load for an electric generating unit is any of the loads or devices powered by electricity, steam, hot water, or directly by the gross output of the electric generating unit that does not contribute electrical, mechanical, or thermal output. In general, less than 7.5 percent of non-IGCC and non-CCS coal-fired station power output, approximately 15 percent of non-CCS IGCC-based coal-fired station power output and about 2.5 percent of non-CCS combined cycle station power output is used internally by parasitic energy demands, but the amount of these parasitic loads vary from source to source. Reasons for using net output include (1) recognizing the efficiency gains of selecting EGU designs and control equipment that require less auxiliary power, (2) selecting fuels that require less emissions control equipment, and (3) recognizing the environmental benefit of higher efficiency motors, pumps, and fans.
Requiring
In addition, we are proposing that with respect to CO
We also propose an 84-operating-month rolling average compliance option that would be available for affected subpart Da boilers and IGCC facilities. The EPA suggests that this 84-operating-month rolling average compliance option will offer operational flexibility and will tend to dampen short-term emission excursions, which may be warranted especially at the initial startup of the facility and the CCS system.
Thus, under our proposed approach, new fossil fuel-fired boilers and IGCC units would be required, based on the performance of currently available CCS technology, to meet a standard of 1,100 lb CO
We have concluded that this alternative compliance option is not necessary for new stationary combustion turbine EGUs, as they should be able to meet the proposed performance standard with no need for add-on technology. We seek comment on all other aspects of this 84-operating-month rolling averaging compliance option.
To recognize the environmental benefit of reduced electric transmission and distribution losses of CHP, we are proposing that CHP facilities where at least 20.0 percent of the total gross useful energy output consists of electric or direct mechanical output and 20.0 percent of the total gross useful energy output consists of useful thermal output on a rolling three calendar year basis receive similar credit as currently in subpart Da and the proposed amendments to subpart KKKK (77 FR 52554). Specifically, the measured electric output would be divided by 0.95 to account for a five percent avoided energy loss in the transmission of electricity. The minimal electric and thermal output requirements are to avoid owners/operators from selling trivial amounts of thermal output and claiming a line loss benefit when in reality they are similar to a central power station.
Actual transmission and distribution losses vary from location to location, but we propose that this 5 percent of actual MWh represents a reasonable average amount for the avoided transmission and distribution losses for CHP facilities. Note that we propose to limit this 5 percent adjustment to facilities for which the useful thermal output is at least 20 percent of the total output.
Consistent with
We solicit comment on any alternative to our proposal that the periods of startup and shutdown be included as periods of partial load in the 12- and 84-operating-month rolling averaging compliance option.
Periods of startup, normal operations, and shutdown are all predictable and routine aspects of a source's operations. However, by contrast, malfunction is defined as a sudden, infrequent, and not reasonably preventable failure of air pollution control and monitoring equipment, process equipment or a process to operate in a normal or usual manner. Failures that are caused in part by poor maintenance or careless operations are not malfunctions.(40 CFR 60.2). The EPA has determined that CAA section 111 does not require that emissions that occur during periods of malfunction be factored into development of CAA section 111 standards. Nothing in CAA section 111 or in case law requires that the EPA anticipate and account for the innumerable types of potential malfunction events in setting emission standards. CAA section 111 provides that the EPA set standards of performance which reflect the degree of emission limitation achievable through “the application of the best system of emission reduction” that the EPA determines is adequately demonstrated. Applying the concept of “the application of the best system of emission reduction” to periods during which a source is malfunctioning presents difficulties. The “application of the best system of emission reduction” is more appropriately understood to include operating units in such a way as to avoid malfunctions.
Further, accounting for malfunctions would be difficult, if not impossible, given the myriad different types of malfunctions that can occur across all sources in the category and given the difficulties associated with predicting or accounting for the frequency, degree, and duration of various malfunctions that might occur. As such, the performance of units that are malfunctioning is not “reasonably” foreseeable.
In the event that a source fails to comply with the applicable CAA section 111 standards as a result of a malfunction event, the EPA would determine an appropriate response based on, among other things, the good faith efforts of the source to minimize emissions during malfunction periods, including preventative and corrective actions, as well as root cause analyses to ascertain and rectify excess emissions. The EPA would also consider whether the source's failure to comply with the CAA section 111 standard was, in fact, “sudden, infrequent, not reasonably preventable” and was not instead “caused in part by poor maintenance or careless operation.” 40 CFR 60.2 (definition of malfunction).
Finally, the EPA recognizes that even equipment that is properly designed and maintained can sometimes fail and that such failure can sometimes cause a violation of the relevant emission standard. (
The EPA included an affirmative defense in the proposed rule in an attempt to balance a tension, inherent in many types of air regulation, to ensure adequate compliance while simultaneously recognizing that despite the most diligent of efforts, emission standards may be violated under circumstances beyond the control of the source. The EPA must establish emission standards that “limit the quantity, rate, or concentration of emissions of air pollutants on a continuous basis.” 42 U.S.C. 7602(k) (defining “emission limitation” and “emission standard”).
We propose that these same requirements, an affirmative defense to civil penalties for violations of emission limits that are caused by malfunctions, would apply to both the 12-operating-month standard and the 84-operating-month rolling average compliance option; however, we will take comment on whether it is appropriate to have an affirmative defense for the 84-operating-month rolling average portion of that compliance option, given that we would expect malfunctions to only impact shorter averaging periods, and the longer the compliance period, the less likely malfunction events are to impact a source's ability to meet the standard.
Today's proposed rule would require owners or operators of EGUs that combust solid fuel to install, certify, maintain, and operate continuous emission monitoring systems (CEMS) to measure CO
The proposed rule would allow owners or operators of EGUs that burn exclusively gaseous or liquid fuels to install fuel flow meters as an alternative to CEMS and to calculate the hourly CO
In addition to requiring monitoring of the CO
The proposed rule would require EGU owners or operators to prepare and submit a monitoring plan that includes both electronic and hard copy components, in accordance with §§ 75.53(g) and (h). The electronic portion of the monitoring plan would be submitted to the EPA's Clean Air Markets Division (CAMD) using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool. The hard copy portion of the plan would be sent to the applicable State and EPA Regional office. Further, all monitoring systems used to determine the CO
The proposed rule would require all valid data collected and recorded by the monitoring systems (including data recorded during startup, shutdown, and malfunction) to be used in assessing compliance. Failure to collect and record required data is a violation of the monitoring requirements, except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, and required monitoring system quality assurance or quality control activities that temporarily interrupt the measurement of stack emissions (e.g., calibration error tests, linearity checks, and required zero and span
The proposed rule would require only those operating hours in which valid data are collected and recorded for all of the parameters in the CO
The following variations from and additions to the basic part 75 monitoring would be required:
• If you determine compliance using CEMS, you would be required to use a laser device to measure the stack diameter at the flow monitor and the reference method sampling locations prior to the initial setup (characterization) of the flow monitor. For circular stacks, you would need to make measurements of the diameter at 3 or more distinct locations and average the results. For rectangular stacks or ducts, you would need to make measurements of each dimension (i.e., depth and width) at 3 or more distinct locations and average the results. If the flow rate monitor or reference method sampling site is relocated, you would repeat these measurements at the new location.
• If you elect to use Method 2 in Appendix A–1 of part 60 to perform the required relative accuracy test audits (RATAs) of the part 75 flow rate monitoring system, you would have to use a calibrated Type-S pitot tube or pitot tube assembly. Use of the default Type-S pitot tube coefficient would not be permitted.
• If your EGU combusts natural gas and/or fuel oil and you elect to measure the CO
Today's proposed rule includes the following special compliance provisions for units with common stack or multiple stack configurations; these provisions are consistent with § 60.13(g):
• If two or more of your EGUs share a common exhaust stack, are subject to the same emission limit, and you are required to (or elect to) determine compliance using CEMS, you would be allowed to monitor the hourly CO
• If you are required to (or elect to) determine compliance using CEMS and the effluent from your EGU discharges to the atmosphere through multiple stacks (or, if the effluent is fed to a stack through multiple ducts and you choose to monitor in the ducts), you would be required to monitor the hourly CO
The proposed rule would require 95 percent of the operating hours in each compliance period (including the compliance periods for the intermediate emission limits) to be valid hours, i.e., operating hours in which quality-assured data are collected and recorded for all of the parameters used to calculate CO
In accordance with § 75.64(a), the proposed rule would require an EGU owner or operator to begin reporting emissions data when monitoring system certification is completed or when the 180-day window in § 75.4(b) allotted for initial certification of the monitoring systems expires (whichever date is earlier). For EGUs subject to the 450 kg/MWh (1,000 lb/MWh) standard or the 500 kg/MWh (1,100 lb/MWh) emission standard, the initial performance test would consist of the first 12-operating-months of data, starting with the month in which emissions are first required to be reported. The initial 12-operating-month compliance period would begin with the first month of the first calendar year of EGU operation in which the facility exceeds the capacity factor applicability threshold.
The traditional 3-run performance tests (i.e., stack tests) described in § 60.8 would not be required for this rule. Following the initial compliance determination, the emission standard would be met on a 12-operating-month rolling average basis. For EGUs that combust coal and/or petroleum coke and whose owners or operators elect to comply with the alternative 84-operating-month rolling average emissions standard, the first month in the compliance period would be the month in which emissions reporting is required to begin under § 75.64(a).
Today's proposed rule specifies that compliance with the 1,000 lb/MWh (450 kg/MWh) and 1,100 lb/MWh (500 kg/MWh) CO
The proposed rule specifies that the first operating month included in either the initial 12- or 84-operating-month compliance period would be the month in which reporting of emissions data is required to begin under § 75.64(a), i.e., either the month in which monitoring system certification is completed or the month in which the 180-day window allotted to finish certification testing expires (whichever month is earlier).
We are proposing that initial compliance with the applicable emissions limit in kg/MWh be calculated by dividing the sum of the hourly CO
Today's proposed rule would require an EGU owner or operator to comply with the applicable notification requirements in §§ 75.61, 60.7(a)(1) and (a)(3) and 60.19. The proposed rule would also require the applicable recordkeeping requirements in subpart
The proposed rule would require EGU owners or operators to keep records of the calculations performed to determine the total CO
For EGU owners or operators who would elect to comply with the 84-operating-month rolling average emissions standard, records must be kept for 10 years. All other records would be kept for a period of three years. All required records would be kept on-site for a minimum of two years, after which the records could be maintained off-site.
The proposed rule would require all affected EGU owners/operators to submit quarterly electronic emissions reports in accordance with subpart G of part 75. The proposed rule would require these reports to be submitted using the ECMPS Client Tool. Except for a few EGUs that may be exempt from the Acid Rain Program (e.g., oil-fired units), this is not a new reporting requirement. Sources subject to the Acid Rain Program are already required to report the hourly CO
Additionally, in the proposed rule and as part of an Agency-wide effort to streamline and facilitate the reporting of environmental data, the rule would require selected data elements that pertain to compliance under this rule, and that serve the purpose of traditional excess emissions reports, to be reported periodically using ECMPS.
Specifically, for EGU owners/operators who would comply with a 12-operating-month rolling average standard, quarterly electronic “excess emissions” reports must be submitted, within 30 days after the end of each quarter. The first report would be for the quarter that includes the final (12th) operating month of the initial 12-operating-month compliance period. For that initial report and any subsequent report in which the twelfth operating month of a compliance period (or periods) occurs during the calendar quarter, the average CO
For EGU owners or operators that would comply with an 84-operating-month rolling average basis, quarterly electronic “excess emissions” reports would be submitted, within 30 days after the end of each quarter. The first report would be for the quarter that includes the final (60th) operating month of the initial 84-operating-month compliance period. For that initial report and any subsequent report in which the sixtieth operating month of a compliance period (or periods) occurs during the calendar quarter, the average CO
Currently, ECMPS is not programmed to receive excess emission report information from EGUs. However, we will make the necessary modifications to the system in order to fully implement the reporting requirements of this rule upon promulgation.
For EGU owners or operators that would assert an affirmative defense for a failure to meet a standard due to malfunction, the owner or operator must follow the reporting requirements for affirmative defense. Those requirements are found in 40 CFR 60.5530. The report to the Administrator, with all necessary supporting documentation, explains how the source has met the requirements set forth in subparts Da, KKKK, and TTTT to assert affirmative defense. This report must be submitted on the same schedule as the next quarterly report required after the initial occurrence of the violation of the relevant standard (which may be the end of any applicable averaging period). If the quarterly report is due less than 45 days after the initial occurrence of the violation, the affirmative defense report may be included in the second quarterly report due after the initial occurrence of the violation of the relevant standard.
In our original proposal, we proposed and solicited comment on what basis we are required to have concerning the health and welfare impacts of GHG emissions from fossil-fuel fired power plants in order to regulate those emissions under CAA section 111. However, we took the position that we are not required to make findings that GHGs from fossil-fired power plants “cause [ ], or contribute [ ] significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare,” under CAA section 111(b)(1)(A).
We have reconsidered that proposal in light of the numerous comments we received. In today's document, we propose that under section 111, the EPA is required to have a rational basis for
As related matters, in this notice, we are proposing to establish regulatory requirements for CO
In 2009, the EPA Administrator issued the Endangerment Finding under CAA section 202(a)(1). With the Endangerment Finding, the Administrator found that elevated concentrations of GHGs in the atmosphere may reasonably be anticipated to endanger public health and welfare of current and future generations, and focused on public health and public welfare impacts within the United States. Fossil fuel-fired EGUs are by far the largest emitters of GHGs, primarily in the form of CO
To review the key CAA section 111 requirements: CAA section 111(b)(1)(A), by its terms, requires that the Administrator publish (and from time to time thereafter shall revise) a list of categories of stationary sources. He shall include a category of sources in such list if in his judgment it causes, or contributes significantly to air pollution which may reasonably be anticipated to endanger public health or welfare.
CAA section 111(b)(1)(B) goes on to provide that after listing the source category, the EPA must promulgate regulations “establishing federal standards of performance for new sources within such category.” In turn, CAA section 111(a)(1) defines a “standard of performance” as a “standard for emissions of air pollutants which reflects the degree of emission reduction which (taking into account * * * cost * * * and any nonair quality health and environmental impact and energy requirements) . . . has been adequately demonstrated.” CAA section 111(b)(2) provides that “The Administrator may distinguish among classes, types, and sizes within categories of new sources for the purpose of establishing such standards.”
CAA section 111(b)(1)(A) requires the EPA to list a source category if it contributes significantly to air pollution that endangers public health or welfare. The EPA must necessarily conduct this listing by making determinations as to the health or welfare impacts of the pollution to which the source category's pollutants contribute, and as to the significance of the amount of such contribution. However, by the terms of CAA section 111(b)(1)(A), the EPA may make these determinations on the basis of the impacts of the air pollution as a whole to which the source category's pollutants, taken as a whole, contribute. Nothing in CAA section 111(b)(1)(A) requires that the EPA make separate determinations for each type of pollution or each pollutant.
After listing a source category, the EPA must proceed to promulgate standards of performance for the source category's pollutants under CAA section 111(b)(1)(B) and 111(a)(1). However, nothing in those provisions requires that, at the time when the EPA promulgates the standards of performance for the individual pollutants, the EPA must make a determination as to the health or welfare effects of those particular pollutants or as to the significance of the amount of the source category's emissions of those pollutants. Clearly, CAA section 111 does not by its terms require that as a prerequisite for the EPA to promulgate a standard of performance for a particular pollutant, the EPA must first find that the pollutant causes or contributes significantly to air pollution that endangers public health or welfare. The lack of any such requirement contrasts with other CAA provisions that do require the EPA to make endangerment and cause-or-contribute findings for the particular pollutant that the EPA regulates under those provisions.
The lack of any express requirement in CAA section 111 addressing whether and how the EPA is to evaluate emissions of a particular pollutant from the listed source category as a prerequisite for promulgation of a standard of performance is properly viewed as a statutory gap that requires the EPA to make what we refer to as a
Our interpretation is that in order to promulgate a section 111 standard of performance for a particular pollutant, we do not need to make a pollutant-specific endangerment finding, but instead must demonstrate a rational basis for controlling the emissions of the pollutant. That rational basis may be based on information concerning the health and welfare impacts of the air pollution at issue, and the amount of contribution that the source category's emissions make to that air pollution.
Commenters on the April 2012 proposal stated that the EPA is required to make an endangerment finding for CO
Commenters on the April 2012 proposal stated that the EPA was required to make an endangerment finding because by creating the new subpart TTTT in 40 CFR Part 60, the EPA was listing a new source category that included the affected units. However, in neither the original April 2012 proposal nor this new proposal has EPA proposed to list a new source category. The EPA initially included fossil fuel-fired electric steam generating units (which included boilers) in a category that it listed under section 111(b)(1)(A)
The EPA has revised those regulations, and in some instances, has revised the codifications (that is, the subparts), several times over the ensuing decades. In 1979, the EPA divided subpart D into 3 subparts—Da (“Standards of Performance for Electric Utility Steam Generating Units for Which Construction is Commenced After September 18, 1978”), Db (“Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units”) and Dc (“Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units”)—in order to codify separate requirements that it established for these subcategories.
In today's rulemaking, the EPA is promulgating new standards of performance for CO
In today's rulemaking, we are including a proposal and, in the alternative, a co-proposal, which take two different approaches to the source categories and their codification.
In the alternative, we co-propose to combine the two source categories—again, steam-generating boilers and combustion turbines—for purposes of regulating CO
We solicit comment on the relative merits of each approach. In particular we seek comment on whether the co-proposal to combine the categories and codify the GHG standards for all new affected sources in subpart TTTT will offer any additional flexibility for any future emission guidelines for existing sources, for example, by facilitating a system-wide approach, such as emission rate averaging, that covers fossil-fuel
In this rulemaking, the EPA has a rational basis for concluding that emissions of CO
Our conclusion is consistent with the case law handed down by the D.C. Circuit. In its 1980 decision in
We think the danger of particulate emissions' effect on health has been sufficiently supported in the Agency's (and its predecessor's) previous determinations to provide a rational basis for the Administrator's finding in this case.
These cases support our relying primarily on the analysis and conclusions in our previous Endangerment Finding, and the subsequent assessments, as providing a rational basis for our decision to impose standards of performance on GHG emissions from fossil-fuel fired EGUs.
In comments on the original proposal, commenters state that because the proposed rulemaking limits emissions of only CO
Further, the fact that affected EGUs emit almost one-third of all U.S. GHGs and comprise by far the largest stationary source category of GHG emissions, along with the fact that the CO
EPA . . . focused . . . on the sheer quantity of dust generated by lime plants.
Even if CAA section 111 is interpreted to require that the EPA make endangerment and cause-or-contribute significantly findings as prerequisites for today's rulemaking, then our rational
As noted above, the EPA's rational basis for regulating under section 111 GHGs is based primarily on the analysis and conclusions in the EPA's 2009 Endangerment Finding and 2010 denial of petitions to reconsider that Finding, coupled with the 2010, 2011, and 2012 assessments from the IPCC and NRC that describe scientific developments since those EPA actions. In addition, as noted above, we would review comments presenting other scientific information to determine whether that information has any meaningful impact on our primary basis.
This rational basis approach is substantially similar to the approach the EPA took in the 2009 Endangerment Finding and the 2010 denial of petitions to reconsider. As noted, the D.C. Circuit upheld that approach in the
By the same token, if the EPA were required to make a cause-or-contribute-significantly finding for CO
The EPA received a number of comments in response to the original proposed NSPS rule addressing the scientific underpinnings of the EPA's 2009 Endangerment Finding and, in essence, the scientific justification for this rule. Because this action is not a final action, we are not required to respond to those comments. Even so, we have carefully reviewed all of those comments, and we do provide some responses in this action. It is important to place these comments in the context of the voluminous record on this subject that has been compiled over the last few years. This includes: (1) The process by which the Administrator reached the 2009 finding that GHGs are reasonably anticipated to endanger the public health and welfare of current and future generations; (2) the EPA's response in 2010 to ten administrative petitions for reconsideration of the Endangerment Finding, the “Reconsideration Denial”; and, (3) the decision by the United States Court of Appeals for the D.C. Circuit (D.C. Circuit) in 2012 to uphold the Endangerment Finding and the Reconsideration Denial.
As outlined in Section VIII.A. of the 2009 Endangerment Finding, the EPA's approach to providing the technical and scientific information to inform the Administrator's judgment regarding the question of whether GHGs endanger human health and welfare was to rely primarily upon the recent, major assessments by the U.S. Global Change Research Program (USGCRP), the Intergovernmental Panel on Climate Change (IPCC), and the National Research Council (NRC) of the National Academies. In brief, these assessments addressed the scientific issues that the EPA was required to examine, were comprehensive in their coverage of the GHG and climate change problem, and underwent rigorous and exacting peer review by the expert community, as well as rigorous levels of U.S. government review and acceptance, in which the EPA took part. The EPA received thousands of comments on the proposed Endangerment Finding and responded to them in depth in an 11-volume RTC document. While the EPA gave careful consideration to
The EPA then reviewed ten administrative petitions for reconsideration of the Endangerment Finding in 2010. The Administrator denied those petitions in the “Reconsideration Denial” on the basis that the Petitioners failed to provide substantial support for the argument that the Endangerment Finding should be revised and therefore their objections were not of “central relevance” to the Finding.
The 2009 Endangerment Finding and the 2010 Reconsideration Denial were challenged in a lawsuit, and on June 26, 2012, the D.C. Circuit upheld them, ruling that they were neither arbitrary nor capricious, were consistent with
EPA evaluated the processes used to develop the various assessment reports, reviewed their contents, and considered the depth of the scientific consensus the reports represented. Based on these evaluations, the EPA determined the assessments represented the best source material to use in deciding whether GHG emissions may be reasonably anticipated to endanger public health or welfare.
As the Court stated,
It makes no difference that much of the scientific evidence in large part consisted of `syntheses' of individual studies and research. Even individual studies and research papers often synthesize past work in an area and then build upon it. This is how science works. The EPA is not required to re-prove the existence of the atom every time it approaches a scientific question.
It is within the context of this extensive record, and recent affirmation of the Endangerment Finding by the Court, that the EPA has considered all of the submitted science-related comments and reports for the April 2012 proposed rule, and will consider any further comments in response to today's proposed rule. As we did in the original Endangerment Finding, the EPA is giving careful consideration to all of the scientific and technical information in the record. However, the major peer-reviewed scientific assessments continue to provide the primary scientific and technical basis upon which the Administrator's judgment relies regarding the threat to public health and welfare posed by GHGs.
Commenters on the April 2012 proposed rule submitted two major peer-reviewed scientific assessments that were released since the administrative record concerning the Endangerment Finding was closed after the EPA's 2010 Reconsideration Denial: the IPCC Special Report on Managing the Risks of Extreme Events and Disasters to Advance Climate Change Adaptation (2012) (SREX) and the NRC Report on Climate Stabilization Targets: Emissions, Concentrations, and Impacts over Decades to Millennia (2011) (Climate Stabilization Targets). The EPA has reviewed these assessments and they are briefly characterized here:
A number of other National Academy assessments regarding climate have also been released recently. The EPA has reviewed these assessments, and finds that the improved understanding of the climate system resulting from the two assessments described above and the National Academy assessments strengthens the case that GHGs are endangering public health and welfare. Perhaps the most dramatic change relative to the prior assessments concern sea level rise. The previous 2007 IPCC AR4 assessment projected a rise in global sea level of between 7 and 23 inches by the end of the century relative to 1990 (with an acknowledgment that inclusion of ice sheet processes that were poorly understood would likely increase those projections). Three new NRC assessments have provided estimates of projected sea level rise that are much larger, in some cases more than twice as large as the previous IPCC estimates. Climate Stabilization Targets; National Security Implications for U.S. Naval Forces (2011); Sea Level Rise for the Coasts of California, Oregon, and Washington: Past, Present, and Future (2012). While the three NRC assessments continue to recognize and characterize the uncertainty inherent in accounting for ice sheet processes, these revised estimates strongly support and strengthen the existing finding that GHGs are reasonably anticipated to endanger human health and welfare. Other key findings of the recent assessments are described briefly below:
The
Several commenters on the April 2012 proposed rule argue that the Endangerment Finding should be reconsidered or overturned based on those commenters' reviews of specific climate science literature, particularly newer publications that have appeared since the EPA's 2010 Denial of Petitions. Some commenters have presented their own compilations of individual studies as support for their assertions that climate change will have beneficial effects in many cases and that climate impacts will not be as severe or adverse as the EPA and assessments like the USGCRP (2009) report have stated. These commenters conclude that U.S. society will continue to easily adapt to climate change and that climate change therefore does not pose a threat to human health and welfare.
The EPA has reviewed the information submitted and finds that, the fundamental issues raised in the comments that critique the scientific justification for the rule have been addressed by the EPA's 11-volume response to comments for the 2009 Endangerment Finding, the EPA's responses to all issues raised by Petitioners in the Reconsideration Denial, or the D.C. Circuit in its 2012 decision to uphold the EPA's 2009 Endangerment Finding. These comments do not change the various conclusions or judgments that the EPA would draw based on the assessment reports relied upon in the recent 2009 Finding.
These comments often highlight uncertainty regarding climate science as an argument for reconsideration. However, uncertainty was explicitly recognized in the 2009 Endangerment Finding: “The Administrator acknowledges that some aspects of climate change science and the projected impacts are more certain than others”,
Regarding the contentions that the U.S. will adapt to climate change impacts and that therefore climate change impacts pose no threat, the EPA stated in the 2009 Endangerment Finding,
Risk reduction through adaptation and GHG mitigation measures is of course a strong focal area of scientists and policy makers, including the EPA; however, the EPA considers adaptation and mitigation to be potential
Some commenters raise issues regarding the EPA Inspector General's report,
One commenter submitted a number of emails from the period 1999 to 2009 that were obtained from a University of East Anglia server in 2009 and publicly released in 2011. After reviewing these emails, the EPA finds that they raise no issues that were not previously raised by Petitioners in regard to an earlier group of emails from the same incident, released in 2009. The commenter makes unsubstantiated assumptions and subjective assertions regarding what the emails purport to show about the state of climate change science; this provides inadequate evidence to challenge the voluminous and well documented body of science that is the technical foundation of the Administrator's Endangerment Finding.
A number of comments were also submitted in support of the Endangerment Finding and/or providing further evidence that climate change is a threat to human health and welfare. A number of individual studies were submitted and a number of observed or projected climate changes of local importance or concern to commenters were documented. Again, the EPA places lesser weight on individual studies than on the major scientific assessments. Local observed changes can be of great concern to individuals
The original proposal was designed to apply to new intermediate and base load EGUs, specifically, (1) fossil fuel-fired utility boilers and IGCC EGUs subject to subpart Da for criteria pollutant emissions, and (2) natural gas combined cycle EGUs subject to subpart KKKK for criteria pollutant emissions. The original proposal explicitly did not apply to simple cycle turbines because we concluded that they were operated infrequently and therefore only contributed small amounts to total GHG emissions. (For convenience, we occasionally refer to this explicit statement that the original proposed NSPS did not apply to a type of source as an exclusion.)
We received comments that supported the simple cycle exclusion and others that opposed it. Commenters in support stated that a new simple cycle power plant serves a different purpose than a new combined cycle plant and that economics will drive the use of combined cycle facilities over simple cycle plants. They also stated that the original proposed standard is not achievable by, and therefore is not BSER for, simple cycle turbines. Commenters opposing the exclusion stated that it creates an opportunity to evade the standard and could thereby increase GHG emissions. According to these commenters, any applicability distinctions should be based on utilization and function rather than purpose or technology.
After considering these comments, we are proposing a different approach to the applicability provisions with respect to simple cycle turbines.
In today's rulemaking, we propose that standards of performance apply to a facility if the facility supplies more than one-third of its potential electric output and more than 219,000 MWh net electric output to the grid per year. (We refer to a facility's sale of more than one-third of its potential electric output as the one-third sales criterion, and we refer to the amount of potential electric output supplied to a utility power distribution system, expressed in MWh, as the capacity factor.) This proposed definition does not explicitly exclude simple cycle combustion turbines, but as a practical matter, it would exclude most of them because the vast majority of simple cycle turbines sell less than one-third of their potential electric output. The few simple-cycle combustion turbines that sell more than one-third of their potential electric output to the grid would be subject to the proposed standards of performance. As explained below, we have concluded that at this level of output, there are less expensive and lower emitting technologies that could be constructed consistent with today's proposed standards. Although, as noted, today's proposal does not explicitly exclude simple cycle combustion turbines, we solicit comment on whether to provide an explicit exclusion.
We are proposing to apply the one-third sales criterion on a rolling three year basis instead of an annual basis for stationary combustion turbines for multiple reasons. First, extending the period to three years would ensure that the CO
The 2013 AEO cost and performance characteristics for new generation technologies include costs for advanced and conventional combined cycle facilities and advanced simple cycle turbines. According to the AEO 2013 values, advanced combined cycle facilities have a lower cost of electricity than advanced simple cycle turbine facilities above approximately a 20 percent capacity factor. Therefore, the use of a combined cycle technology would be BSER for higher capacity factor stationary combustion turbines. However, advanced combined cycle facilities do not have a lower cost of electricity than less capital intensive conventional combined cycle facilities until above approximately a 40 percent capacity factor. Between approximately 20 to 40 percent capacity factors, conventional combined cycle facilities offer the lowest cost of electricity, and below approximately 20 percent capacity factors advanced simple cycle turbines offer the lowest cost of electricity. A capacity factor exemption at 40 percent (i.e., sales of less than two-fifths of potential electric output per year) would allow conventional combined cycle facilities built with the intent to operate at relatively low capacity factors as an alternative technology to simple cycle turbines because neither would be subject to the NSPS requirements. Based on these cost considerations, we are specifically requesting comment on a range of 20 to 40 percent of potential electric output sales on a three-year basis for the capacity factor exemption. The 20 percent applicability limit is consistent with generating the lowest cost of electricity for advanced combined cycle turbines compared to advanced simple cycle turbines, and based on historical capacity factors would impact the operation of only approximately two percent of simple cycle turbines. The 40 percent applicability limit would be more consistent with the annual run hour limitations currently contained in many simple cycle operating permits.
We are also requesting comments on whether applicability for stationary combustion turbines should be defined on a single calendar year basis, similar to the current subpart Da applicability provisions for criteria pollutants, instead of a three-year basis. With a single year basis, we are considering an applicability level of up to 40 (instead of 33 and one-third) percent sales. Only 0.4 percent of existing simple cycle turbines had an annual capacity factor of greater than 40 percent between 2000 and 2012. Assuming the average hourly output of a simple cycle turbine is 80 percent of the maximum rated output, a simple cycle turbine could operate up to 4,400 hours annually before exceeding the capacity factor threshold. This is consistent with the operation hour limitation in many permits. Therefore, with this 40 percent sales criterion on a single-year basis, as a practical matter, it is anticipated that few new simple cycle turbines would be subject to the proposed standards of performance. Thus, we are specifically requesting comment on a range of one-third to two-fifths of potential electric output annual sales. The lower range would be consistent with how an EGU is currently defined in the EPA rules, and would mean that the proposed standards of performance would impact approximately one percent of new simple cycle turbines.
We are also proposing a different definition of potential electric output from the current definition that determines the potential electric output (in MWh on an annual basis) considering only the design heat input capacity of the facility and does not account for efficiency. It assumes a 33 percent net electric efficiency, regardless of the actual efficiency of the facility and could discourage the installation of more efficient facilities. For example, a 33 percent efficient 100 MW facility would have a heat input of 1,034 MMBtu/h and a 40 percent efficient 100 MW facility would have a heat input of 853 MMBtu/h.
The April 2012 proposal would have applied to facilities that primarily burn non-fossil fuels but also co-fire a fossil fuel. We have concluded that it is not appropriate to subject these facilities to the standards in today's proposal. This is because these types of units more closely resemble the non-fossil fuel-fired boilers and stationary combustion turbines that are not covered by today's proposed rule, than they do the fossil fuel-fired boilers and stationary combustion turbines that are covered by this rule. This approach is similar to the approach used in the Mercury and Air Toxics Standards, another CAA regulatory effort focused on fossil fuel-fired power plants. Therefore, we are proposing to limit the applicability of the standard to facilities where the heat input is comprised of more than 10.0 percent fossil fuel on a three-year rolling average basis. To simplify determining applicability with the CO
In the original proposal, we requested comment on the applicability of the GHG NSPS to combined heat and power (CHP) facilities and if applicability should be changed from how it is currently determined in subpart Da. In today's action, we propose that if CHP facilities meet the general applicability criteria they should be subject to the same requirements as electric-only generators. However, one potential issue that we have identified is inequitable applicability to third-party CHP developers compared to CHP facilities owned by the facility using the thermal output from the CHP facility. As noted above, we propose that the proposed CO
This proposal includes within the definition of a steam electric generating unit, IGCC, and stationary combustion turbine that are subject to the proposed requirements, any integrated device that provides electricity or useful thermal output to the boiler, the stationary combustion turbine or to power auxiliary equipment. The rationale behind including integrated equipment recognizes that the integrated equipment may be a type of combustion unit that emits GHGs, and that it is important to assure that those GHG emissions are included as part of the overall GHG emissions from the affected source. Including integrated equipment avoids circumvention of the requirements by having a boiler not subject to the standard supplying useful energy input (e.g., an industrial boiler supplying steam for amine regeneration in a CCS system) without accounting for the GHG emissions when determining compliance with the NSPS. In addition, the proposed definition would provide additional compliance flexibility similar to when the HRSG was included in the combustion turbine NSPS by recognizing the environmental benefit of integrated equipment that lowers the overall emissions rate of the affected facility. Even without this specific language, the original 1979 steam electric generating unit definition in subpart Da allows the use of solar thermal equipment for feedwater heating as an approach to integrating non-emitting generation to reduce environmental impact and lower the overall emissions rate. The current definition expands the flexibility to include combustion turbines, fuel cells, or other combustion technology for reheating or preheating boiler feedwater, preheating combustion air, producing steam for use in the steam turbine or to power the boiler feedpumps, or using the exhaust directly in the boiler to generate steam. This in theory could lower generation costs as well as lower the GHG emissions rate for an EGU.
We solicit comment on various issues concerning, and different approaches to, the applicability requirements for steam generating units and combustion turbines. In particular, we recognize that several of the requirements proposed today are based on the source's operations. These include, for both steam generating units and combustion turbines, the requirement that the source supply more than one-third of its potential electric output and more than 219,000 MWh net-electric output to the grid for sale on an annual or tri-annual basis (the one-third and 219,000 MWh sales requirement), as well as the requirement that the source burn fossil fuel for more than 10 percent of the heat input during three years; and for
We solicit comment on whether these requirements raise implementation issues because they are based on source operation after construction has occurred. We also solicit comment on whether, to avoid any such implementation issues, these requirements should be recast to be based on the source's purpose at the time of construction. For example, should we recast the 10% percent requirement so that it would be met if the source was constructed for the purpose of burning fossil fuel for more than 10 percent of its heat input over any three-year period?
In addition, we solicit comment on whether we should include these requirements not as applicability requirements for whether the source is subject to the standard of performance, but rather as criteria for which part of the standard of performance the source is subject to. Under this approach, at least for combustion turbines, the EPA would promulgate applicability requirements or a definition of utility unit designed to assure that combustion turbine utility units—but not combustion turbine industrial units or other types of non-utility units—would be subject to the standard of performance. For example, under this approach, all combustion turbine units that meet such applicability requirements or definition of utility units and that have a design heat input to the turbine engine greater than 250 MMBtu/h, would be subject to the standard of performance for CO
Under this approach, as noted, in order to be consistent with today's proposal to apply the standard of performance for CO
We solicit comment on all aspects of this approach, including the extent to which it would achieve the policy objectives of assuring that a simple cycle turbine and a combined cycle turbine are subject to the same standard if they sell more than one-third of their capacity and more than 219,000 KWh net electric output to the grid, and are subject to the same standard if they sell less than those amounts to the grid. We also solicit comment on how to implement the three-year requirements described above during the period within three years after an affected EGU begins operations. For example, under the approach where operational criteria that entail a three-year compliance period are used to determine to which standard of performance the facility is subject, the owner or operator and permitting authority would not know for certain what standard applies to the facility until three years after initial startup. For this scenario, we request comment on how to implement the three year operational requirements and what documentation should be collected and reported to the EPA during the period up to the end of the third year after a source begins operation.
This proposal does not apply to the proposed Wolverine EGU project in Rogers City, Michigan. Based on current information, the Wolverine project appears to be the only fossil fuel-fired boiler or IGCC EGU project presently under development that may be capable of “commencing construction” for NSPS purposes
There are two other fossil fuel-fired boiler or IGCC EGU projects without CCS—the Washington County project in Georgia and the Holcomb project in Kansas—that appear to remain under development but whose developers have recently represented that the projects have commenced construction for NSPS purposes. Based solely on the developers' representations, the projects would be existing sources, and thus not subject to this proposal. However, neither developer has sought a formal EPA determination of NSPS applicability; and, if upon review it was determined that the projects have not commenced constructions, the projects should be situated similarly to the Wolverine project. Accordingly, if it is determined in the future that either of these projects has not commenced construction as of the date of this proposal, then that project will be addressed in the same manner as the Wolverine project.
We invite comment on all aspects of this approach for addressing the Wolverine project (and the Washington County and Holcomb projects, if applicable).
In this section, we describe the principal legal requirement for the standards of performance under CAA section 111 that we propose in this rulemaking, which is that the standards must consist of emission limits that are based on the “best system of emission reduction . . . adequately demonstrated,” taking into account cost and other factors (BSER). In this manner, CAA section 111 provides that the EPA's central task is to identify the BSER. The D.C. Circuit has handed down case law, which we review in detail, that interprets this CAA provision, including its component elements. The Court's interpretation indicates the technical, economic, and energy-related factors that are relevant for determining the BSER, and provides the framework for analyzing those factors.
According to the D.C. Circuit, EPA determines the best demonstrated system based on the following key considerations, among others:
• The system of emission reduction must be technically feasible.
• EPA must consider the amount of emissions reductions that the system would generate.
• The costs of the system must be reasonable. EPA may consider the costs on the source level, the industry-wide level, and, at least in the case of the power sector, on the national level in terms of the overall costs of electricity and the impact on the national economy over time.
• EPA must also consider that CAA section 111 is designed to promote the development and implementation of technology.
Other considerations are also important, including that EPA must also consider energy impacts, and, as with costs, may consider them on the source level and on the nationwide structure of the power sector over time. Importantly, EPA has discretion to weigh these various considerations, may determine that some merit greater weight than others, and may vary the weighting depending on the source category.
The EPA's basis for proposing that partial capture CCS is the BSER for new fossil fuel-fired utility boilers and IGCC units, and that NGCC is the BSER for natural gas-fired stationary combustion turbines, is rooted in the provisions of CAA section 111 requirements, as interpreted by the United States Court of Appeals for the D.C. Circuit (“D.C. Circuit” or “Court”), which is the federal Court of Appeals with jurisdiction over the EPA's CAA rulemaking.
As the first step towards establishing standards of performance, the EPA “shall publish . . . a list of categories of stationary sources . . . [that] cause[], or contribute[ ] significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.” section 111(b)(1)(A). Following that listing, the EPA “shall publish proposed regulations, establishing federal standards of performance for new sources within such category” and then “promulgate . . . such standards” within a year after proposal. section 111(b)(1)(B). The EPA “may distinguish among classes, types, and sizes within categories of new sources for the purpose of establishing such standards.” section 111(b)(2). The term “standard of performance” is defined to “mean[ ] a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated.” section 111(a)(1).
For present purposes, the key section 111 provisions are the definition of “standard of performance,” under CAA section 111(a)(1), and, in particular, the “best system of emission reduction which (taking into account . . . cost . . . nonair quality health and environmental impact and energy requirements) . . . has been adequately demonstrated.” The D.C. Circuit has reviewed rulemakings under section 111 on numerous occasions during the past 40 years, handing down decisions dated from 1973 to 2011,
At the outset, it should be noted that Congress first included the definition of “standard of performance” when enacting CAA section 111 in the 1970 Clean Air Act Amendments (CAAA), and then amended it in the 1977 CAAA, and then amended it again in the 1990 CAAA, generally repealing the amendments in the 1977 CAAA and, therefore, reverting to the version as it read after the 1970 CAAA. The legislative history for the 1970 and 1977 CAAAs explained various aspects of the definition as it read at those times. Moreover, the various decisions of the D.C. Circuit interpreted the definition that was applicable to the rulemakings before the Court. Notwithstanding the amendments to the definition, the D.C. Circuit's interpretations discussed below remain applicable to the current definition.
In the 1977 CAAA, Congress revised the definition to distinguish among different types of sources, and to require that for fossil fuel-fired sources, the standard (i) be based on, in lieu of the “best system of emission reduction . . . adequately
In the 1990 CAAA, Congress again revised the definition, this time repealing the requirements that the standard of performance be based on the best technological system and achieve a percentage reduction in emissions, and replacing those provisions with the terms used in the 1970 CAAA version of section 111(a)(1) that the standard of performance be based on the “best system of emission reduction . . . adequately demonstrated.” This 1990 CAAA version is the current definition, which is applicable at present. Even so, because parts of the definition as it read under the 1977 CAAA were retained in the 1990 CAAA, the explanation in the 1977 CAAA legislative history, and the interpretation in the case law, of those parts of the definition remain relevant to the definition as it reads today.
By its terms, the definition of “standard of performance” under CAA section 111(a)(1) provides that the emission limit that the EPA promulgates must be “achievable” and must be based on a system of emission reduction—generally, but not required to be always, a technological control—that the EPA determines to be the “best system” that is “adequately demonstrated,” “taking into account . . . cost . . . nonair quality health and environmental impact and energy requirements.” The D.C. Circuit has stated that in determining the “best” system, the EPA must also take into account “the amount of air pollution”
As discussed below, the D.C. Circuit has elaborated on the criteria and process for determining whether a standard is “achievable,” based on an “adequately demonstrated” technology or system. In addition, the Court has identified limits on the costs and other factors that are acceptable for the technology or system to qualify as the “best.” The Court has also held that the EPA may consider the costs and other factors on a regional or national level (e.g., the EPA may consider impacts on the national economy and the affected industry as a whole) and over time, and not just on a plant-specific level at the time of the rulemaking.
We next discuss in more detail each of these components of the interpretation of “standard of performance.”
The D.C. Circuit's first decision under section 111,
The Court explained that a standard of performance is “achievable” if a technology can reasonably be projected to be available to new sources at the time they are constructed that will allow them to meet the standard. Specifically, the D.C. Circuit explained:
Section 111 looks toward what may fairly be projected for the regulated future, rather than the state of the art at present, since it is addressed to standards for new plants. . . .—It is the “achievability” of the proposed standard that is in issue . . . .
The Senate Report made clear that it did not intend that the technology “must be in actual routine use somewhere.” The essential question was rather whether the technology would be available for installation in new plants. . . . The Administrator may make a projection based on existing technology, though that projection is subject to the restraints of reasonableness and cannot be based on “crystal ball” inquiry.
It should be noted that in another of the early cases,
Although the definition of “standard of performance” does not by its terms identify the amount of emissions from the category of sources and the amount of emission reductions achieved as factors the EPA must consider in determining the “best system of emission reduction,” the D.C. Circuit has stated that the EPA must do so.
In several cases, the D.C. Circuit has elaborated on the cost factor that the EPA is required to consider under CAA section 111(a)(1), and has identified limits to how costly a control technology may be before it no longer qualifies as the “best system of emission reduction . . . adequately demonstrated.” As a related matter, although no D.C. Circuit case addresses how to account for revenue generated from the byproducts of pollution control, it is logical and a reasonable interpretation of the statute that any expected revenues from the sale of pollutants or pollution control byproducts associated with those controls may be considered when determining the overall costs of implementation of the control technology. Clearly, such a sale would offset regulatory costs and so must be included to accurately assess the costs of the standard.
In
In the [1970] Congress [
1977 House Committee Report at 184. Similarly, the 1970 Senate Committee Report stated:
The implicit consideration of economic factors in determining whether technology is “available” should not affect the usefulness of this section. The overriding purpose of this section would be to prevent new air pollution problems, and toward that end, maximum feasible control of new sources at the time of their construction is seen by the committee as the most effective and, in the long run, the least expensive approach.
S. Comm. Rep. No. 91–1196 at 16.
In
In the case law under CAA section 111, the D.C. Circuit has never invalidated a standard of performance on grounds that it was too costly. In several cases, the Court upheld standards that entailed high costs. In
In
The importance of the challenged standards arises not only from the magnitude of the environmental and health interests involved, but also from the critical implications the new pollution controls have for the economy at the local and national levels.
Coal is the dominant fuel used for generating electricity in the United States. . . . In 1976 power plant emissions accounted for 64 percent of the total estimated sulfur dioxide emissions and 24 percent of the total estimated particulate matter emissions in the entire country.
EPA's revised NSPS are designed to curtail these emissions. EPA predicts that the new standards would reduce national sulfur dioxide emissions from new plants by 50 percent and national particulate matter emissions by 70 percent by 1995. The cost of the new controls, however, is
In determining the costs of pollution control technology, it is reasonable to take into account any revenues generated by the sale of any by-products of the control process. Many types of pollution control technology generate byproducts that must be disposed, and the costs of that disposal are considered part of the costs of the control technology. For example, CCS generates a stream of CO
In some instances, however, the by-products of pollution control have marketable value. In these cases, revenues from selling the by-products would defray the costs of pollution control. For example, in a recent rulemaking under the CAA regional haze program that entailed determining the “best available retrofit technology” (BART) for power plants, revenue from fly ash generated during boiler combustion and sold for use in concrete production factored into the State's selection of BART).
In
Our interpretation of section 111(a) is that the mandated balancing of cost, energy, and nonair quality health and environmental factors embraces consideration of technological innovation as part of that balance. The statutory factors which EPA must weigh are broadly defined and include within their ambit subfactors such as technological innovation.
The Court's interpretation finds firm grounding in the legislative history. For example, the 1970 Senate Committee Report stated:
Standards of performance should provide an incentive for industries to work toward constant improvement in techniques for preventing and controlling emissions from stationary sources, since more effective emission control will provide greater latitude in the selection of sites for new facilities.
These five sets of requirements will be difficult to meet. But the committee is convinced that industry can make compliance with them possible or impossible. It is completely within their control. Industry has been presented with challenges in the past that seemed impossible to meet, but has been made possible.
116 Cong. Rec. 32902 (Sept. 21, 1970) (statement of Sen. Muskie).
Similarly, the 1977 Senate Committee Report stated:
In passing the Clean Air Amendments of 1970, the Congress for the first time imposed a requirement for specified levels of control technology. The section 111 Standards of Performance for New Stationary Sources required the use of the “best system of emission reduction which (taking into account the cost of achieving such reduction) the Administrator determines has been adequately demonstrated.” This requirement sought to assure the use of available technology and to stimulate the development of new technology.
The legislative history just quoted identifies three different ways that Congress designed section 111 to authorize standards of performance that promote technological improvement: (i) the development of technology that may be treated as the “best system of emission reduction . . . adequately demonstrated;” under section 111(a)(1)
Another component of the D.C. Circuit's interpretations of section 111 is that the EPA may consider the various factors it is required to balance on a national or regional level and over time, and not only on a plant-specific level at the time of the rulemaking.
The language of [the definition of `standard of performance' in] section 111 . . . gives EPA authority when determining the best . . . system to weigh cost, energy, and environmental impacts in the broadest sense at the national and regional levels and over time as opposed to simply at the plant level in the immediate present.
In that case, in upholding the EPA's variable standard for SO
The Court first recited the terms of the definition of “standard of performance,” as it read following the 1977 CAA Amendments:
The pertinent portion of section 111 reads:
A standard of performance shall reflect the degree of emission limitation . . . achievable through application of the best . . . system of . . . emission reduction which (taking into consideration the cost of achieving such emission reduction, any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated.
The Court then stated that these terms could reasonably be read to authorize the EPA to establish the standard of performance based on environmental, economic, and energy considerations “on the grand scale:”
Parsed, section 111 most reasonably seems to require that EPA identify the emission levels that are “achievable” with “adequately demonstrated technology.” After EPA makes this determination, it must exercise its discretion to choose an achievable emission level which represents the best balance of economic, environmental, and energy considerations. It follows that to exercise this discretion EPA must examine the effects of technology on the grand scale in order to decide which level of control is best. For example, an efficient water intensive technology capable of 95 percent removal efficiency might be “best” in the East where water is plentiful, but environmentally disastrous in the water-scarce West where a different technology, capable of only 80 percent reduction efficiency might be “best.” . . . The standard is, after all, a national standard with long-term effects.
The Court then justified its “reading of . . . section 111 as authorizing the EPA to balance long-term national and regional impacts of alternative standards” on the 1977 CAAA legislative history:
The Conferees defined the best technology in terms of “long-term growth,” “long-term cost savings,” effects on the “coal market,” including prices and utilization of coal reserves, and “incentives for improved technology.” Indeed, the Reports from both Houses on the Senate and House bills illustrate very clearly that Congress itself was using a long-term lens with a broad focus on future costs, environmental and energy effects of different technological systems when it discussed section 111.
The Court then examined the EPA's justification for the variable standard, and held that the justification was reasonable.
The standard reflects a balance in environmental, economic, and energy consideration by being sufficiently stringent to bring about substantial reductions in SO
By substantially reducing SO
Above, we discuss how in
In
As noted, under CAA section 111(a)(1), a standard of performance must be based on the “best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) . . . has been adequately demonstrated.” The terms “best system of emission reduction,” “cost,” and “energy requirements,” on their face, can be interpreted to apply on a regionwide or nationwide basis, and are not limited to the individual source. Thus, this interpretation is supportable under
The D.C. Circuit has made clear that the EPA has broad discretion in determining the appropriate standard of performance under the definition in CAA section 111(a)(1), quoted above. Specifically, in
Because section 111 does not set forth the weight that should be assigned to each of these factors, we have granted the agency a great degree of discretion in balancing them. . . . EPA's choice [of the “best system”] will be sustained unless the environmental or economic costs of using the technology are exorbitant. . . . EPA [has] considerable discretion under section 111.
The important point is that Courts acknowledge that there are several factors to be considered and what is “best” depends on how much weight to give the factors. In promulgating certain standards of performance, EPA may give greater weight to particular factors than it may do so in promulgating other standards of performance. Thus, the determination of what is “best” is complex and necessarily requires an exercise of judgment. By analogy, the question of who is the “best” sprinter in the 100-meter dash primarily depends on only one criterion—speed—and therefore is relatively straightforward, while the question of who is the “best” baseball player depends on a more complex weighing of several criteria and therefore requires a greater exercise of judgment.
Under CAA section 111, an emissions standard may meet the requirements of a “standard of performance” even if it cannot be met by every new source in the source category that would have constructed in the absence of that standard. As discussed below, this is clear in light of (i) the legislative history of CAA section 111, read in conjunction with the legislative history of the CAA as a whole; (ii) case law under analogous CAA provisions; and (iii) long-standing precedent in the EPA rulemakings under CAA section 111.
As noted, Congress, in enacting section 111 in the 1970 CAAA, intended that the EPA promulgate uniform, nationwide controls. Congress was explicit that this meant that large industrial sources, including electric generating power plants, would be required to implement controls meeting the requirements regardless of their location. According to the 1970 Senate Committee Report:
Major new facilities such as electric generating plants, kraft pulp mills, petroleum refineries, steel mills, primary smelting plants, and various other commercial and industrial operations must be controlled to the maximum practicable degree regardless of their location and industrial operations * * *.
Congress's purposes in designing a standard that called for uniform national controls were to prevent pollution havens—caused by some states seeking competitive advantage by limiting their pollution control requirements—and to assure that areas that had good air quality would be able to maintain good air quality even after new industrial sources located there, which, in turn, would allow more sources to locate there as well.
At the same time, Congress recognized that in light of the attainment provisions of the CAAA of 1970, sources—particularly large industrial sources, again, including electric generating plants—may not be
Land use planning and control should be used by State, local, and regional agencies as a method of minimizing air pollution. Large industries and power generating facilities should be located in places where their adverse effect on the air is minimal. There is a need for State or regional agencies to revise proposed power plant sites to assure that a number of environmental values, including air pollution, are considered.
Thus, in 1970, Congress designed section 111 to require uniform national controls for large industrial facilities, while recognizing that those facilities could not necessarily construct in every place in the country. Although at the time, Congress expected that the reason why some sources would not be able to locate in certain places was related to local air quality concerns, if the reason turns out to be related to the emission limits that the EPA promulgates under section 111, that should not be viewed as inconsistent with congressional intent for section 111. For example, if the EPA promulgates section 111 emission limits based on a particular type of technology, and for economic or technical reasons, sources are able to utilize that technology in only certain parts of the country and not other parts, that result should not be viewed as inconsistent with congressional intent for CAA section 111. Rather, that result is consistent with Congress's recognition that certain sources may be precluded from locating in certain areas.
Under analogous CAA provisions, the D.C. Circuit has recognized that the EPA may promulgate uniform standards that apply to new sources in a group or category of sources, even though some types of those new sources that would otherwise construct would no longer be able to construct because they could not meet the standard. One of these cases was
Although the Court remanded the EPA's decision not to grant the one-year extension, it agreed with the EPA on this point, stating:
We are inclined to agree with the Administrator that as long as feasible technology permits the demand for new passenger automobiles to be generally met, the basic requirements of the Act would be satisfied, even though this might occasion fewer models and a more limited choice of engine types. The driving preferences of hot rodders are not to outweigh the goal of a clean environment.
Similarly, in a 2007 decision under CAA section 112,
Thus, these decisions supported EPA's emissions requirements, even though certain types of sources could meet those requirements more readily than others, on grounds that the requirements would not impede the manufacture of products that would satisfy overall consumer demand. By the same token, the inability of some coal-fired sources to locate in certain areas would not create reliability problems or prevent the satisfaction of overall demand for electricity.
Through long-standing rulemaking precedent, the EPA has taken the position that section 111 authorizes a standard of performance for a source category that may not be feasible for all types of new sources in the category, as long as there are other types of sources in the category that can serve the same function and meet the standard. Specifically, in a 1976 rulemaking under section 111 covering primary copper, zinc, and lead smelters, the EPA established, as the standard of performance, a single standard for SO
[T]he Agency believes that section 111 authorizes the promulgation of one standard applicable to all processes used by a class of sources, in order that the standard may reflect the maximum feasible control for that class. When the application of a standard to a given process would effectively ban the process, however, a separate standard must be prescribed for it unless some other process(es) is available to perform the function at reasonable cost. . . .
The Administrator has determined that the flash copper smelting process is available and will perform the function of the reverberatory copper smelting process at reasonable cost. . . .
In this section we explain our rationale for emission standards for new fossil fuel-fired boiler and IGCC EGUs,
As noted, CAA section 111 and subsequent court decisions establish a set of factors for the EPA to consider in a BSER determination, including criteria listed in CAA section 111 or identified in the court decisions and the underlying purposes of section 111. Key factors include: emission reductions, technical feasibility, costs, and encouragement of technology. Other factors, such as energy impacts, may also be important. As also noted, the EPA has discretion in balancing those factors, and may balance them differently in promulgating standards for different source categories.
The EPA considered three alternative control technology configurations as potentially representing the BSER for new fossil fuel-fired boilers and IGCC units. Power company announcements indicate that the few new coal-fired projects that may occur will likely consider one or more of these three configurations. The three alternatives are: (1) Highly efficient new generation technology that does not include any level of CCS, (2) highly efficient new generation technology with “full capture” CCS (that is, CCS with capture of at least 90 percent CO
We discuss each of these alternatives below, and explain why we propose that partial capture CCS qualifies as the BSER. We first discuss the technical systems that we considered for the BSER, our evaluations of them, and our reasons for determining that only partial CCS meets the criteria to qualify as the BSER. We include in this discussion our rationale for selecting 1,100 lb CO
Some commenters on the April 2012 proposal suggested that the emission limitation for new coal-fired EGUs should be based on the performance of highly efficient generation technology that does not include CCS, such as (i) a supercritical
These options are technically feasible. However, we do not consider them to qualify as the BSER for the following reasons:
Because of the large amount of CO
New power sector projects using coal as a primary fuel that have been proposed or are currently under construction are generally SCPC or IGCC projects. For example, since 2007, almost all coal-fired EGUs that have broken ground have been high performing versions of SCPC or IGCC projects.
Under these circumstances, in this rule, identifying a new supercritical unit as the BSER and requiring the associated emission limitation, would provide little meaningful CO
As a result, emission reductions in the amount that would result from an emission standard based on SCPC/USCPC or even IGCC as the BSER would not be consistent with the purpose of CAA section 111 to achieve “as much [emission reduction] as practicable.”
Identifying highly efficient generation technology as the BSER would not achieve another purpose of CAA section 111, to encourage the development and implementation of control technology.
On the contrary, such a standard could impede the advancement of CCS technology by creating regulatory disincentives for such technology. In 2011, AEP deferred construction of a large-scale CCS retrofit demonstration project on one of their coal-fired power plants because the state's utility regulators would not approve cost recovery for CCS investments without a regulatory requirement to reduce CO
We are placing the project on hold until economic and policy conditions create a viable path forward . . . We are clearly in a classic `which comes first?' situation. The commercialization of this technology is vital if owners of coal-fueled generation are to comply with potential future climate regulations without prematurely retiring efficient, cost-effective generating capacity. But as a regulated utility, it is impossible to gain regulatory approval to recover our share of the costs for validating and deploying the technology without federal requirements to reduce greenhouse gas emissions already in place. The uncertainty also makes it difficult to attract partners to help fund the industry's share.
As we discuss below, regulatory requirements for CO
We have also considered whether the emission limitation for new coal-fired EGUs should be based on the performance of CCS, including either “full capture” CCS that treats the entire flue gas or syngas stream to achieve on the order of 90 percent reduction in CO
We propose that implementation of partial capture CCS technology is the BSER for new fossil fuel-fired boilers and IGCC units because it fulfills the criteria established under CAA section 111. In the sections that follow, we explain the technical configurations that facilitate full and partial capture, describe the operational flexibilities that partial capture offers, and then identify and justify the emission rate that we propose based on partial capture. After that, we discuss the criteria for BSER, and describe why partial capture meets those criteria and why full capture does not. Among other things, partial capture provides meaningful emission reductions, it has been adequately demonstrated to be technically feasible, it can be implemented at a reasonable cost, and it promotes deployment and further development of the technology.
The DOE's National Energy Technology Laboratory (NETL) performed a study to establish the cost and performance for a range of CO
For the new SCPC case, the study assumed a new SCPC boiler with a combination of low-NO
The study's authors identified two options for achieving partial capture (i.e., less than 90 percent CO
For a new IGCC unit, the product syngas would contain primarily H
For a new IGCC EGU, the study's authors assumed the use of the GE gasifier coupled with a variety of potential configurations (i.e., no WGS reactor, single-stage WGS, two-stage WGS, varying WGS bypass ratios, and CO
To achieve moderate levels of partial CO
To achieve higher CO
The water-gas shift involves the catalytic reaction of carbon monoxide and steam. Since the syngas initially contains primarily CO and H
An unshifted or partially shifted syngas can be combusted using a typical combustion turbine. However, as the level of H
To this point, most of the studies involving research, development and demonstration of carbon capture technology, along with most of the studies that have modeled the costs and implementation of such technology have assumed capture requirements of 90 percent for fossil fuel-fired power plants (“full capture”). However, the EPA believes that partial capture provides significant benefits because an emission limit based on partial capture offers operators considerable operational flexibility. With such emission limits, project developers would have the option of designing and installing CO
In addition, an emission standard that can be met with partial capture offers the opportunity for design flexibility. A project developer of a new conventional coal-fired plant (i.e., a new supercritical PC or CFB) could install post-combustion CO
For a new IGCC unit, as noted, an emission standard that requires partial capture of CO
Once the EPA has determined that a technology has been adequately demonstrated based on cost and other factors, including the impact a standard will have on further technology development, and therefore represents BSER, the EPA must establish an emission standard. In this case, for new fossil fuel-fired boiler and IGCC EGUs, the EPA proposes to find that the level of partial capture of CO
First, both a new IGCC and a conventional coal-fired boiler (PC or CFB), can achieve this emission standard at a reasonable cost and the standard is based on technology that has been adequately demonstrated.
The partial capture requirement and standard of performance will allow new IGCC project developers to minimize the need for multi-stage water-gas shift reactors (and the associated steam requirement) and will allow for the continued use of conventional syngas combustion turbines (rather than requiring the use of advanced hydrogen turbines). Second, this partial capture configuration will provide operators with operational flexibility. Third, this level of the standard best promotes further enhancement of the performance of existing technology and promotes continued development of new, better performing technology. Because the proposed emission standard would require only partial implementation of CCS, it will provide developers with the opportunity to investigate new emerging technologies that may achieve deeper reductions at lower or comparable cost. For instance, developers could build plants with the capacity to achieve deeper CO
While the EPA is proposing an emission rate of 1,100 lb CO
We are not currently considering a standard below 1,000 lb CO
We are not currently considering a standard above 1,200 lb CO
The next several sections review the factors for determining BSER and explain why partial capture at the level we are proposing meets those requirements, as well as why full capture does not meet some of them.
The proposed standard of 1,100 lb CO
The EPA proposes to find that partial CCS is feasible because each step in the process has been demonstrated to be feasible through an extensive literature record, fossil fuel-fired industrial plants currently in commercial operation and pilot-scale fossil fuel-fired EGUs currently in operation, the progress towards completion of construction of fossil fuel-fired EGUs implementing CCS at commercial scale. This literature record and experience demonstrate that partial CCS is achievable for all types of new boiler and IGCC configurations. Although much of this information also serves to demonstrate the technical feasibility of full capture, we note that several of the CCS projects that are the furthest along are partial capture projects, which further supports our view that partial capture is BSER.
The current status of CCS technology was described and analyzed by the 2010 Interagency Task Force on CCS, established by President Obama on February 3, 2010, co-chaired by the DOE and the EPA, and composed of 14 executive departments and federal agencies. The Task Force was charged with proposing a plan to overcome the barriers to the widespread, cost-effective deployment of CCS within 10 years, with a goal of bringing five to ten commercial demonstration projects online by 2016. The Task Force found that, although early CCS projects face economic challenges related to climate policy uncertainty, first-of-a-kind technology risks, and the current cost of CCS relative to other technologies, there are no insurmountable technological, legal, institutional, regulatory or other barriers that prevent CCS from playing a role in reducing GHG emissions.
The Pacific Northwest National Laboratory (PNNL) recently prepared a study that evaluated the development status of various CCS technologies for the DOE.
In addition, DOE/NETL has prepared other reports—in particular their “Cost and Performance Baseline” reports,
Each of the core components of CCS—CO
Capture of CO
Although current capture technologies are feasible, the costs of CO
In general, CO
• Pre-combustion systems that are designed to separate CO
• Post-combustion systems that are designed to separate CO
• Oxy-combustion that uses high-purity O
Each of these three carbon capture approaches (pre-combustion, post-combustion, and oxy-combustion) is technologically feasible. However, each results in increased capital and operating costs and decreased electricity output (that is, an energy penalty), with a resulting increase in the cost of electricity. The energy penalty occurs because the CO
Carbon dioxide has been transported via pipelines in the U.S. for nearly 40 years. Approximately 50 million metric tons of CO
(i) Current availability of geologic sequestration
Existing project and regulatory experience (including EOR), research, and analogs (e.g. naturally existing CO
The viability of geologic sequestration of CO
Project and research experience continues to add to the confidence in geologic sequestration as a viable CO
Numerous other field studies, for example those conducted by the DOE/
• Midwest Regional Carbon Sequestration Partnership Michigan Basin Phase II Validation Test, which injected approximately 60,000 metric tons of CO
• Midwest Geologic Sequestration Consortium Loudon, Mumford Hills, and Sugar Creek Phase II Validation Test, which consisted of injecting over 14,000 tons of CO
• Southwest Regional Partnership on Carbon Sequestration (SWP) San Juan Basin Phase II Validation Test, which injected 16,700 metric tons into the coal layers of the Fruitland Formation.
Geologic storage potential for CO
Further evidence of the widespread availability CO
Nearly every state in the U.S. has or is in close proximity to formations with carbon storage potential including vast areas offshore.
(ii) Current availability of enhanced oil and gas recovery
Geologic storage options also include use of CO
CO
Monitoring CO
• At the SACROC field in the Permian Basin, the Texas Bureau of Economic Geology conducted an extensive groundwater sampling program to look for evidence of CO
• An extensive CO
• The Texas Bureau of Economic Geology has also been testing a wide range of surface and subsurface monitoring tools and approaches to document storage efficiency and storage permanence at a CO
The Department of Energy has conducted numerous evaluations of CO
The EPA anticipates that many early geologic sequestration projects may be sited in active or depleted oil and gas reservoirs because these formations have been previously well characterized for hydrocarbon recovery, likely already have suitable infrastructure (e.g., wells, pipelines, etc.), and have an associated economic benefit of oil production. EOR sites including those that inject CO
CO
Potential sources of CO
Based on a recent resource assessment by the DOE, the application of next generation CO
The use of CO
The following is a brief summary of some examples of currently operating or planned CO
AES's coal-fired Warrior Run (Cumberland, MD) and Shady Point (Panama, OK) power plants are equipped with amine scrubbers developed by ABB/Lummus. They were designed to process a slip stream of each plant's flue gas. At Warrior Run, approximately 110,000 metric tons of CO
At the Searles Valley Minerals soda ash plant in Trona, CA, approximately 270,000 metric tons of CO
A pre-combustion Rectisol® system is used for CO
In September 2009, AEP began a pilot-scale CCS demonstration at its Mountaineer Plant in New Haven, WV. The Mountaineer Plant is a 1,300 MWe coal-fired unit that was retrofitted with Alstom's patented chilled ammonia CO
AEP, with assistance from the DOE, had planned to expand the slip stream demonstration to a commercial scale, fully integrated demonstration at the Mountaineer facility. The commercial-scale system was designed to capture at least 90 percent of the CO
Oxy-combustion of coal is being demonstrated in a 10 MWe facility in Germany. The Vattenfall plant in eastern Germany (Schwarze Pumpe) has been operating since September 2008. It is designed to capture 70,000 metric tons of CO
In June 2011, Mitsubishi Heavy Industries, an equipment manufacturer, announced the successful launch of operations at a 25 MW coal-fired carbon capture facility at Southern Company's Alabama Power Plant Barry. The demonstration captures approximately 165,000 metric tons of CO
Southern Company has begun construction of Mississippi Power Kemper County Energy Facility. This is a 582 MW IGCC plant that will utilize local Mississippi lignite and include pre-combustion carbon capture to reduce CO
SaskPower's Boundary Dam CCS Project in Estevan, a city in Saskatchewan, Canada, is the world's largest commercial-scale CCS project of its kind. The project will fully integrate the rebuilt 110 MW coal-fired Unit #3 with available CCS technology to capture 90 percent of its CO
The Texas Clean Energy Project, a 400 MW IGCC facility located near Odessa, Texas will capture 90 percent of its CO
There are other CCS projects—domestic and worldwide—that are helping to further develop the CCS technology. They are noted in the DOE/NETL's Carbon Capture, Utilization, and Storage (CCUS) Database.
Information in the database regarding technologies being developed for capture, evaluation of sites for carbon dioxide (CO
As noted, according to the D.C. Circuit case law, control costs are considered acceptable as long as they are reasonable, meaning that they can be accommodated by the industry.
At the outset, it should be noted that even though the costs of coal-fired electricity generation—even when not incorporating CCS technology—are high when compared to the current costs of new NGCC generation, some utilities and other project developers have indicated a willingness to proceed with new fossil fuel-fired boilers and IGCC units. They have indicated the need for energy and fuel diversity. They have also indicated a skepticism regarding long-term projections for low natural gas prices and high availability. And there may be other reasons why developers have indicated a willingness to build new coal-fired plants, even if they currently do not appear to be the most economic choice.
The EPA has examined costs of new fossil fueled power generation options. These options are shown in Table 6 below. The costs in Table 6 are projected for new fossil generation with and without various carbon capture options. The costs for new NGCC technology are provided at two different natural gas prices: at $6.11/MMBtu, which is reasonably consistent with current and projected prices; and at $10/MMBtu, which would be well above current and projected natural gas prices. We also show projected costs for SCPC and IGCC units with no CCS (i.e., units that would not meet the proposed emission standard) and for those units with partial capture CCS installed such that their emissions would meet the proposed 1,100 lb CO
The DOE/NETL
For an emerging technology like CCS, costs can be estimated for a “first-of-a-kind” (FOAK) plant or an “nth-of-a-kind” (NOAK) plant, the latter of which has lower costs due to the “learning by doing” and risk reduction benefits that result from serial deployments as well as from continuing research, development and demonstration projects.
Because there are a number of projects currently under development, the EPA believes it is reasonable to focus on the next-of-a-kind costs provided in Table 6. The lessons learned from design, construction and operation of those projects, as well as for that of Duke Energy's Edwardsport IGCC (which does not include CCS) will help lower costs for future gasification facilities implementing CCS. The TCEP project and the HECA project are both in advanced stages of design and development. Summit Power, the developer of TCEP, is also pursuing a number of additional projects that would benefit from lessons learned from TCEP. These include the Captain Clean Energy Project in the United Kingdom (UK) and another poly-generation project in Texas.
Further, as discussed elsewhere in this preamble, many of the individual components of a new generation project with CCS have been previously demonstrated. For example, capturing CO
For all these reasons, the next IGCC and SCPC facilities with CCS can be expected to be less expensive than the current FOAK projects, but more expensive than the NOAK facilities with CCS that construct when CCS has become a fully mature technology. The costs in Table 6 reflect those next-of-a-kind costs.
The EPA has also examined costs of new non-fossil fueled power generation options. These options are shown in Table 7 below.
It is
The CUA reflects the additional planning cost typically assigned by project developers and utilities to GHG-intensive projects in a context of climate uncertainty. The EPA believes the CUA is consistent with the industry's planning and evaluation framework (demonstrable through IRPs and PUC orders) and is therefore necessary to adopt in evaluating the cost competitiveness of alternative generating technologies.
EPA believes the CUA is relevant in considering the range of costs that power companies are willing to pay for generation alternatives to natural gas. To the extent that a handful of project developers are still considering coal without CCS, EPA believes, based both on the analysis the EIA undertook in developing the CUA approach and the EPA's review of IRPs,
The EPA is requesting comment on all aspects of the CUA, including its magnitude and technology-specific application, to ensure that the EPA's supporting analysis best reflects the current standards and practices of the power sector's long-term planning process.
As Tables 6 and 7 above show, while new coal-fired generation that includes CCS is more expensive than either new coal-fired generation without CCS or new NGCC generation, it is competitive with new nuclear power, which, besides natural gas combustion turbines, is the principal other option often considered for providing new base load power. It is also competitive with biomass-fired generation, which is another generation technology often considered for base load power.
As noted in Table 6, above, and discussed in the RIA
As noted, the current costs of coal, natural gas, and construction of coal-fired or natural gas-fired EGUs have led to little currently announced or projected new coal-fired generating capacity. This very likely reflects the large price differential between the cost of a new NGCC (cost of electricity: $59/MWh at a natural gas price of $6.11/MMBtu) and SCPC without CCS (cost of electricity: $92/MWh) and IGCC without CCS (cost of electricity: $97/MWh), coupled with a leveling of demand for electricity and the recent increase in renewable sources.
We observe that most of the industry appears to take the view that the price of natural gas will remain sufficiently low for at least a long enough period into the future that new natural-gas fired electricity generation will be less expensive than new coal-fired generation. As a result, in most cases, customers or utilities that contract for
As shown in Table 6, we estimate that a new SCPC plant costs $92/MWh, which is $33/MWh, or about 56 percent higher than the new NGCC cost of $59/MWh. Limiting the emission rate to 1,100 lb CO
We are aware of another segment of the industry, which includes electricity suppliers who have indicated a preference for new coal-fired generation to establish or maintain fuel diversity in their generation portfolio because their customers have expressed a willingness to pay a premium for that diversity. It appears these utilities and project developers see lower risks to long-term reliance on coal-fired generation and greater risks to long-term reliance on natural gas-fired generation, compared to the rest of the industry.
We consider the costs of CCS to be reasonable for this segment of the industry as well. The additional costs of CCS for new SCPC of $18/MWh LCOE ($110/MWh for SCPC with partial CCS compared to $92/MWh for SCPC without CCS) are only about half as much as the additional costs that are already needed to be incurred to develop coal-fired electricity as compared to new NGCC generation ($92/MWh for SCPC without CCS compared to $59 MWh for NGCC at a natural gas price of $6.11/MMBtu). Moreover, it is possible that under these circumstances, the demand for the electricity would be inelastic with respect to the price because it may not depend on cost as much as on a demand for energy diversity. These circumstances would be similar to the
In addition, we consider the costs of partial CCS to be reasonable because a segment of the industry is already accommodating them. As noted, a segment of the industry consists of the several coal-fired EGU projects that already incorporate at least partial CCS. These projects, which are each progressing, include Kemper, TCEP, and HECA. Each is an IGCC plant that expects to generate profits from the sale of products that result from coal gasification, in addition to the sale of electricity. It is true that each of these projects has received DOE grants to encourage the development of CCS technology, but we do not consider such government subsidies to mean that the costs of CCS would otherwise be unreasonable. As we noted in the original proposal for this rulemaking,
While the reasons noted above are sufficient to justify the reasonableness of the costs of partial CCS, in most cases, we believe that the actual costs will be less. One reason is the availability of EOR. As noted, EOR is being actively used in various counties in the U.S., and CO
We recognize that, at present, certain locations are far enough away from either oilfields with EOR availability or pipelines to those oil fields that any coal-fired power plants that build in those locations would incur costs to build pipeline extensions that may render EOR non-economical. Those locations are relatively limited when legal or practical limits on building coal-fired power plants are taken into account. For example, some states with locations that are not located near EOR availability are not expected to have new coal-fired builds without CCS in any event, for legal or practical reasons. A number of States, at least in the short term, already have high reserve margins and/or have large renewable targets which push new decisions towards renewables and quick starting natural gas to provide backup to renewables over coal-fired generation.
In addition, it is important to note that coal-fired power plants that build in any particular location may serve demand in a wide area. There are many examples where coal-fired power generated in one state is used to supply electricity in other states. For instance, historically, nearly 40 percent of the power for the City of Los Angeles was provided from two coal-fired power plants located in Arizona and Utah. In another example, Idaho Power, which serves customers in Idaho and Eastern Oregon, meets its demand in part from coal-fired power plants located in Wyoming and Nevada.
As a result, the geographic scope of areas in which EOR is available to defray the costs of CCS should be considered to be large. The costs provided in Table 6 show how the ability to sell CO
We also considered how the opportunity to sell captured CO
In some instances, the costs of CCS can be defrayed by grants or other benefits provided by the DOE or the states. Although, for the reasons noted earlier, we consider the current costs of partial-capture CCS even without subsidization to be reasonable, the availability of these governmental subsidies supports the reasonableness of the costs.
The 2010 Interagency Task Force Report on CCS report described the DOE program as follows:
The DOE is currently pursuing multiple demonstration projects using $3.4 billion of available budgetary resources from the American Recovery and Reinvestment Act in addition to prior year appropriations. Up to ten integrated CCS demonstration projects supported by DOE are intended to begin operation by 2016 in the United States. These demonstrations will integrate current CCS technologies with commercial-scale power and industrial plants to prove that they can be permitted and operated safely and reliably. New power plant applications will focus on integrating pre-combustion CO
DOE allocated some $3.4 billion for 5–10 projects, and has committed $2.2 billion for 5 projects to date. In addition, various other federal and state incentives are also available to many projects. The 2010 Interagency Task Force on CCS, in surveying all of the federal and state benefits available, concluded that the DOE grants, “plus . . . federal loan guarantees, tax incentives, and state-level drivers, cover a large group of potential CCS options.”
In addition, regulatory programs may serve to defray the costs of CCS, including, for example, Clean Energy Standards or guaranteed electricity purchase price agreements.
As noted above and in the April 2012 proposal, the need for subsidies to support emerging energy systems and new control technologies is not unusual. Each of the major types of energy used to generate electricity has been or is currently being supported by some type of government subsidy such as tax benefits, loan guarantees, low-cost leases, or direct expenditures for some aspect of development and utilization, ranging from exploration to control installation. This is true for fossil fuel-fired; as well as nuclear-, geothermal-, wind-, and solar-generated electricity.
The EPA reasonably projects that the costs of CCS will decrease over time as the technology becomes more widely used. Although, for the reasons noted earlier, we consider the current costs of CCS to be reasonable, the projected decrease in those costs further supports their reasonableness. The D.C. Circuit case law that authorizes determining the “best” available technology on the basis of reasonable future projections supports taking into account projected cost reductions as a way to support the reasonableness of the costs.
As noted above, the D.C. Circuit, in the 1973
Of course, where data are unavailable, EPA may not base its determination that a technology is adequately demonstrated or that a standard is achievable on mere speculation or conjecture . . . but EPA may compensate for a shortage of data through the use of other qualitative methods, including the reasonable extrapolation of a technology's performance in other industries.
We expect the costs of CCS technologies to decrease for several reasons. We expect that significant additional knowledge will be gained from deployment and operation of at least two new coal-fired generation projects that include CCS. These projects are the Southern Company's Kemper County Energy Facility IGCC with CCS and the Boundary Dam CCS project on a conventional coal-fired power plant in Canada. They are currently under construction and are expected to commence operation next year. In addition there are several other CCS projects in advanced stages of development in the U.S. (e.g., the Texas Clean Energy Project, the Hydrogen Energy California Project, and the Future Gen project in Illinois) that may also provide additional information. In addition, research is underway to reduce CO
Gas absorption processes using chemical solvents, such as amines, to separate CO
Significant reductions in the cost of CO
In addition, we note that the 2010 Interagency Task Force on CCS report recognized that CCS would not become more widely available without a regulatory framework that promoted CCS or a strong price signal for CO
It is clear that identifying partial CCS as the BSER promotes the utilization of CCS because any new fossil fuel-fired utility boiler or IGCC unit will need to install partial capture CCS in order to meet the emission standard. Particularly because the technology is relatively new, additional utilization is expected to result in improvements in the performance technology and in cost reductions. Moreover, identifying partial capture CCS as the BSER will encourage continued research and development efforts, such as those sponsored by the DOE/NETL. In contrast, not identifying partial CCS as the BSER could potentially impede further utilization and development of CCS. It is important to promote deployment and further development of CCS technologies because they are the only technologies that are currently available or are expected to be available in the foreseeable future that can make meaningful reductions in CO
Identifying partial CCS as the BSER also promotes further use of EOR because, as a practical matter, we expect that new fossil fuel-fired EGUs that install CCS will generally make the captured CO
As noted, the D.C. Circuit in
Considering on “the national and regional levels and over time” the criteria that go into determining the “best system of emission reduction . . . adequately demonstrated” also supports identifying partial CCS as that best system because doing so would not have adverse impacts on the power sector, national electricity prices, or the energy sector.
Identifying partial CCS as the BSER for new fossil fuel-fired utility boilers and IGCC units is consistent with the current and projected future structure of the power sector. As noted, we project that in light of the current and projected trends in coal and natural gas costs, virtually all new electric generating capacity will employ NGCC technology or renewable energy, and very little new capacity will be coal-fired.
As noted above, the recent history of solid fossil fuel-fired projects suggest that these new coal-fired builds, if they occur, may (i) consist of an IGCC unit, including features such as sale of additional byproducts (e.g., plants such as the Texas Clean Energy Project, which intends to manufacture fertilizer products for sale and sell captured CO
Projects in the first category would by definition already include at least partial CCS and, as a result, would be affected by this rule to only a limited extent. Projects in the second category would be more affected, but developers of these projects would nevertheless have several options. They could pursue coal with CCS and possibly rely on cost savings from EOR or on their customers' willingness to pay a higher premium. Alternatively, they could choose a different generation technology (most likely natural gas). Even if they chose a different generation technology, the small number of these sources and the fact that the basic demand for electricity would still be met would limit the impact of this rule on the power sector.
Identifying partial CCS as the BSER for fossil fuel-fired utility boilers and IGCC units will not have significant impacts on nationwide electricity prices. The reason is that the additional costs of partial CCS will, on a nationwide basis, be small because no more than a few new coal-fired projects are expected, and because, as noted, at least some of these can be expected to incorporate CCS technology in any event. It should be noted that the computerized model the EPA relies on to assess energy sector and nationwide impacts—the Integrated Planing Model (IPM)—does not forecast any new coal-fired EGUs through 2020. Based on these IPM analyses, the RIA for this
Identifying partial CCS as the BSER for new fossil fuel-fired utility boilers and IGCC units is consistent with nationwide energy considerations because it will not have adverse effects on the structure of the power sector, will promote fuel diversity over the long term, and will not have adverse effects on the supply of electricity.
Identifying partial CCS as the BSER will not have adverse impacts on the structure of the power sector because, as noted, for reasons related to the cost differential between natural gas-fired and coal-fired electricity, very little, if any, new coal-fired EGUs are projected to be built, and at least some of those that may be built would be expected to include CCS technology in any event.
In addition, identifying partial CCS as the BSER for coal will be beneficial to coal-fired electric generation, and therefore fuel diversity, over the long term. This is because identifying partial CCS as BSER eliminates uncertainty as to future control obligations for coal-fired capacity. Currently, any new coal-fired source that constructs without CCS faces the risk that future state or federal controls may require carbon capture, which would require the source to retrofit to CCS, which, in turn, is a more expensive proposition. This risk is heightened because power plants have expected lives of 30 to 40 years and the likelihood of future carbon limitations can be expected to remain throughout that period. Any new coal-fired source that constructs with partial-capture CCS will achieve some level of CO
Moreover, even if requiring CCS adds sufficient costs to prevent a new coal-fired plant from constructing in a particular part of the country due to lack of available EOR to defray the costs, or, in fact, from constructing at all, a new NGCC plant can be built to serve the electricity demand that the coal-fired plant would otherwise serve. Thus, the present rulemaking does not prevent basic electricity demand from being met, and thus does not have an adverse effect on the supply of electricity. As noted above, the EPA is authorized to promulgate standards of performance under CAA section 111 that may have the effect of precluding construction of sources in certain geographic locations.
Identifying partial CCS as the BSER for coal-fired power plants protects the environment by preventing large amounts of CO
As noted above, the D.C. Circuit has held that it will grant a high degree of deference to the EPA in determining the appropriate standard of performance. Because determining the BSER for coal-fired power plants requires balancing several factors, including on a nationwide basis and over time, the EPA's determination that partial CCS is the BSER should be granted a high degree of deference.
As noted above, under CAA section 111, an emissions standard may meet the requirements of a “standard of performance” even if it cannot be met by every new source in the source category that would have constructed in the absence of that standard. As also noted above, the EPA's analysis for this proposal indicates that coal-fired power plants that would otherwise construct in the absence of the standards in this proposal may still do so.
However, we recognize that there may be some geographic locations where EOR is not practicably available, so that in those locations, the higher costs of CCS may tilt the economics against new coal-fired construction. Even in this case, the standard would remain valid under CAA section 111, particularly because the basic demand for electricity could still be served by NGCC, which this rulemaking determines to be the “best system” for natural gas-fired power plants.
Under today's proposal, sources must meet the 1,100 lb CO
EGU efficiency has a significant impact on the source's GHG emission rate. By comparison, efficiency has a smaller impact on the emissions rate for criteria or hazardous air pollutants (HAPs). This is because control of criteria pollutants and HAPs often involves the use of a pollution control device that results in significant reductions, often greater than 90 percent. In this situation, the performance of the specific pollution control device impacts the emissions rate much more than the EGU efficiency.
EGU efficiency can vary from month to month throughout the year. For example, high ambient temperature can negatively impact the efficiency of combustion turbine engines and steam generating units. As a result, an averaging period shorter than 12 operating-months would require us to set a standard that could be achieved under these conditions. This standard could potentially be high enough that it would not be a meaningful constraint during other parts of the year. In addition, operation at low load conditions can also negatively impact efficiency. It is likely that for some short period of time an EGU will operate at an unusually low load. A short averaging period that accounts for this operation would again not produce a meaningful constraint for typical loads.
On the other hand, a 12-operating-month rolling average explicitly accounts for variable operating conditions, allows for a more protective standard and decreased compliance burden, allows EGUs to have and use a consistent basis for calculating compliance (i.e., ensuring that 12 operating months of data would be used to calculate compliance irrespective of the number of long-term outages), and simplifies compliance for state permitting authorities. Because the 12-operating-month rolling average can be calculated each month, this form of the standard makes it possible to assess compliance and take any needed corrective action on a monthly basis. The EPA proposes that it is not necessary to have a shorter averaging period for CO
We solicit comment on, in the alternative, basing compliance requirements on an annual (calendar year) average basis.
Under today's proposal, new fossil fuel-fired boilers and IGCC units will have the option to alternatively meet an emission standard on an 84-operating-month rolling basis.
The EPA has previously offered sources optional, longer-term emission standards that are stricter than the primary emissions standard in combination with a longer averaging period. We are proposing that this alternative emission limit should be between 1,000–1,050 lb CO
We are also requesting comment on an appropriate 12-operating-month standard that owners/operators electing to comply with the 84-operating-month standard would have to comply with. This standard would be numerically between the alternate 12-operating-month standard and an emissions rate of a coal-fired EGU without CCS (e.g., 1,800 lb CO
This 84-operating-month period offers increased operational flexibility and will tend to compensate for short-term emission excursions, which may especially occur at the initial startup of the facility and the CCS system.
We expect that for the immediate future, virtually all of the CO
In addition, we recognize that types of CO
As noted, the EPA expects that for the immediate future, captured CO
The EPA has promulgated, or recently proposed, several rules to protect underground sources of drinking water and track the total amount of CO
UIC Class II wells inject fluids associated with oil and natural gas production and the storage of liquid hydrocarbons. Most of the injected fluid is salt water, which is brought to the surface in the process of producing (extracting) oil and gas and subsequently re-injected. In addition, other fluids, including CO
Second, the GHG Reporting Program covers sources that generate electricity (40 CFR part 98, subpart D), sources that supply CO
Subpart PP provides requirements for quantifying CO
Subpart RR requires facilities meeting the source category definition (40 CFR 98.440) for any well or group of wells to report basic information on the amount of CO
• A delineation of the maximum monitoring area (MMA) and the active monitoring area (AMA).
• An identification and evaluation of the potential surface leakage pathways and an assessment of the likelihood, magnitude, and timing, of surface leakage of CO
• A strategy for detecting and quantifying any surface leakage of CO
• An approach for establishing the expected baselines for monitoring CO
• A summary of considerations made to calculate site-specific variables for the mass balance equation.
More information on the MRV plan is available in the Technical Support Document for the subpart RR final rule (75 FR 75065).
If an enhanced oil and gas recovery project holds a UIC Class VI permit, it is required to report under subpart RR. If the project holds a UIC Class II permit and is injecting a CO
As stated in the preamble to the final subpart RR rule:
The Internal Revenue Service relies on the existing regulatory framework to verify geologic sequestration when determining eligibility of taxpayers claiming the 45Q tax credit. As stated in the preamble to the final subpart RR rule:
“EPA notes that the Internal Revenue Service (IRS) published IRS Notice 2009–83 7 to provide guidance regarding eligibility for the Internal Revenue Code section 45Q credit for CO
Third, the EPA proposed a rule that would conditionally exclude CO
To provide certainty and verify that CO
First, the EPA is proposing that any affected unit that employs CCS technology which captures enough CO
In order to use the GHG Reporting Program to ensure that the affected unit is sending its captured CO
The EPA notes that compliance with the standard of 1,100 lb CO
The EPA acknowledges that there can be downstream losses of CO
We also emphasize that today's proposal does not involve regulation of any downstream recipients of captured CO
The approach proposed today relies on the existing GHG Reporting framework to ensure that CO
In the development of this proposal, the EPA has identified some potential alternatives to geologic sequestration, including but not limited to CO
In most cases, sources that are subject to this NSPS will also be a major source or major modification under PSD and required to obtain a PSD permit prior to commencing construction. A permit is the legal tool used to establish all the source limitations deemed necessary by the reviewing agency during review of the permit application, and is the primary basis for enforcement of PSD requirements. A well written permit reflects the outcome of the permit review process and clearly defines what is expected of the source. The permit must be a “stand-alone” document that: (1) Identifies the emissions units to be regulated; (2) establishes emissions standards or other operational limits to be met; (3) specifies methods for determining compliance and/or excess emissions, including reporting and recordkeeping requirements; and (4) outlines the procedures necessary to maintain continuous compliance with the emission limits.
One of the criteria that must be met to obtain a PSD permit is that the owner or operator of the facility must demonstrate that emissions from construction or operation of the facility will not cause or contribute to air pollution in excess of “any other applicable emissions standard or standard of performance under this chapter.” 42 U.S.C. 7475(a)(3)(C); see also 42 U.S.C. 7410(j). Accordingly, PSD permits for EGU sources that are subject to this NSPS will need to reflect that, at a minimum, the source will meet the requirements of this NSPS. Compliance with the NSPS emissions standard is determined exclusively by evaluating emissions of CO
As noted in the “Implications for PSD and Title V programs” section of this preamble, some states have authority to issue PSD permits. In other cases, the EPA issues the permit. States with EPA-approved permitting programs have some discretion in making permit decisions and including the necessary conditions in the permit to ensure the enforceability of the requirements. Additionally, some states may have additional state-specific requirements (e.g., a renewable portfolio standard adopted by a state) that may affect the stringency of the emission limits for the permits issued in their states. Thus, permits for similar source types may vary from state to state depending on the permitting program of the state, and the case-specific PSD evaluation of the source under review. However, the permits for similar sources should generally contain the same basic information.
Thus, while EPA recognizes that permit conditions may vary from state to state, the EPA believes it is important to clarify the key components that should be included in a PSD permit for sources subject to the NSPS, as proposed here, and that intend to comply with the standard using geologic storage. We believe the following general condition areas of a PSD permit would adequately show that the source will not cause or contribute to air pollution in excess of this NSPS:
• A BACT emissions limit that applies to the EGU (or EGUs) at the stationary source (“EGU facility”) that does not exceed the NSPS emission limit standard using the 12-operating-month rolling average or the NSPS alternative compliance method.
• Procedures for how the EGU will demonstrate compliance with the permitted emissions limit, which, at a minimum, meet the monitoring and recordkeeping requirements defined in § 60.5355.
• A requirement that CO
• A requirement that all CO
• A requirement that the captured CO
We specifically request comment on this basic framework for PSD permits that are issued for affected EGU sources that use geologic sequestration.
The EPA evaluated several different control technology configurations as potentially representing the “best system of emissions reductions . . . adequately demonstrated” (BSER) for new natural gas-fired stationary combustion turbines: (i) The use of full or partial capture CCS; and two types of efficient generation without any CCS, including (ii) high efficiency simple cycle aeroderivative turbines; and (iii) natural gas combined cycle (NGCC) technology. We do not consider full or partial capture CCS to be BSER because of insufficient information to determine technical feasibility and because of adverse impact on electricity prices and the structure of the electric power sector. In addition, we do not consider simple cycle turbines to be BSER because they have a higher emission rate and a higher cost than NGCC technology. We do find NGCC technology to be the BSER because it is technically feasible and relatively inexpensive, its emission profile is acceptably low, and it would not adversely affect the structure of the electric power sector.
We note at the outset that currently, virtually all new sources in this category are using NGCC technology. That technology is considered to be the state of the art for this source category. Because, in this rulemaking, we are considering, and selecting, NGCC as the BSER for this category, as a matter of terminology, to avoid confusion, we generally refer to the affected sources as natural gas-fired combustion turbines, and not as NGCC sources.
To determine the BSER for natural-gas-fired stationary source combustion turbines, we evaluated full and partial CCS against the criteria. We propose to reject CCS technology as the BSER because we cannot conclude that it meets several of the key criteria.
First, it is not clear that full or partial capture CCS is technically feasible for this source category. There are significant differences between natural gas-fired combustion turbines and solid fossil fuel-fired EGUs that lead us to this conclusion. First, while some of these turbines are used to serve base load power demand, many cycle their operation much more frequently than coal-fired power plants. It is unclear how part-load operation and frequent startup and shutdown events would impact the efficiency and reliability of CCS. We are not aware that any of the pilot-scale CCS projects have operated in a cycling mode. Similarly, none of the larger CCS projects being constructed, or under development, are designed to operate in a cycling mode. Furthermore, the CO
Additional factors that make CCS more challenging for a natural gas combustion turbine compared to coal-fired EGUs include the time it would take to complete the CCS project and the water use requirements. Requiring CCS at a natural gas combustion turbine facility would potentially delay the project more than at a coal-fired EGU. Natural gas combustion turbine facilities can be constructed in about half the time required to construct a coal-fired EGU. Therefore, the time necessary to construct the carbon capture equipment and any associated pipelines to transport the CO
Moreover, identifying partial or full CCS as the BSER for new stationary combustion turbines would have significant adverse effects on national electricity prices, electricity supply, and the structure of the power sector. Because virtually all new fossil fuel-fired power is projected to use NGCC technology, requiring CCS would have more of an impact on the price of electricity than the few projected coal plants with CCS and the number of projects would make it difficult to implement in the short term. In addition, requiring CCS could lead some operators and developers to forego retiring older coal-fired plants and replacing them with new NGCC projects, and instead keep the older plants on line longer, which could have adverse emission impacts. Identifying CCS and BSER for combustion turbines would likely result in higher nationwide electricity prices and could adversely affect the supply of electricity, since virtually all new fossil fuel-fired power is projected to use NGCC technology.
We recognize that identifying full or partial CCS as the BSER for this source category would result in significant emissions reductions, but at present, we already consider natural gas to be a low-GHG-emitting fuel and NGCC to be a low-emitting technology. Although identifying CCS as the BSER would promote the development and implementation of emission control technology, for the reasons described, the EPA does not believe that CCS represents BSER for natural gas combustion turbines at this time.
To determine the BSER, the EPA also evaluated the use of energy efficient generation technology, including high efficiency simple cycle aeroderivative turbines.
The use of high efficiency simple cycle aeroderivative turbines does not provide emission reductions from the current state-of-the-art technology, is more expensive than the current state-of-the-art technology, and does not develop emission control technology. For these reasons, we do not consider it BSER. According to the AEO 2013 emissions rate information, advanced simple cycle combustion turbines have a base load rating CO
In the April 2012 proposal, we identified NGCC as the BSER for this source category, and proposed a standard of 1,000 lb/MWh. We stated:
[A] NGCC facility is the best system of emission reduction for new base load and intermediate load EGUs. To establish an appropriate, natural gas-based standard, we reviewed the emissions rate of natural gas-fired (non-CHP) combined cycle facilities
The same information supports our current proposal. As described above, NGCC has a lower cost of electricity than simple cycle turbines at intermediate and high capacity factors. In addition, NGCC has an emissions rate that is approximately 25 percent lower than the most efficient simple cycle facilities. Therefore, the use of a heat recovery steam generator in combination with a steam turbine to generate additional electricity is a cost effective control for intermediate and high capacity factor stationary combustion turbines. Therefore, BSER for intermediate and high capacity factor stationary combustion turbines is the use of modern high efficiency NGCC technology.
Multiple commenters on the April 2012 proposal stated the proposed standard of 1,000 lb CO
In light of these comments, we have reviewed the CO
This subcategorization has a basis in differences in several types of equipment used in the differently sized units, which affect the efficiency of the units. Large-size combustion turbines use industrial frame type combustion turbines and may use multiple pressure or steam reheat turbines in the heat recovery steam generator (HRSG) portion of a combined cycle facility. Multiple pressure HRSGs employ two or three steam drums that produce steam at multiple pressures. The availability of multiple pressure steam allows the use of a more efficient multiple pressure steam turbine, compared to a single pressure steam turbine. A steam reheat turbine is used to improve the overall efficiency of the generation of electricity. In a steam reheat turbine, steam is withdrawn after the high pressure section of the turbine and returned to the boiler for additional heating. The superheated steam is then returned to the intermediate section of the turbine, where it is further expanded to create electricity. Although HRSGs with steam reheat turbines are more expensive and complex than HRSGs without them, steam reheat turbines offer significant reductions in CO
Because of these differences in equipment and inherent efficiencies of scale, the smaller capacity NGCC units (850 MMBtu/h and smaller) available on the market today are less efficient than the larger units (larger than 850 MMBtu/h). According to the data in the EPA's Clean Air Markets Division database, which contains information on 307 NGCC facilities, there is a 7 percent difference in average CO
To further evaluate the impact of the proposed rule we reviewed the GHG BACT permits for eight recently permitted NGCC facilities. Of these facilities, seven are larger than 850 MMBtu/h, and one is smaller. The seven larger facilities all have emission rates below 1,000 lb/MWh, and as low as 880 lb/MWh. The single smaller facility, which is 400 MMBtu/h, has a permitted emissions rate of 1,100 lb CO
We are requesting comment on a range of 950 to 1,100 lb CO
The proposal in this rulemaking would, for the first time, regulate GHGs under CAA section 111. Commenters have raised questions regarding whether this rule will have implications for regulations and permits written under the CAA PSD preconstruction permit program and the CAA Title V operating permit program.
Today's proposal should not require any additional SIP revisions to make clear that the Tailoring Rule thresholds—described below—continue to apply to the PSD program. Likewise, today's rulemaking does not have implications for the Tailoring Rule thresholds established with respect to sources subject to title V requirements. Furthermore, this proposal does not have any direct applicability on the determination of Best Available Control Technology (BACT) for existing EGUs that require PSD permits to authorize a major modification of the EGU. Finally, this proposal does have some implications for Title V fees, but EPA is proposing action to address those implications as discussed below.
States with approved PSD programs in their state implementation plans (SIPs) implement PSD, and most of these States have recently revised their SIPs to incorporate the higher thresholds for PSD applicability to GHGs that the EPA promulgated under what we call the Tailoring Rule.
However, if a state with an approved PSD SIP program that applies to GHGs believes that were the EPA to finalize the rulemaking proposed today, the state would be required to revise its SIP to make clear that the Tailoring Rule thresholds continue to apply, then (i) the EPA encourages the state to do so as soon as possible, and (ii) if the State cannot do so promptly, the EPA will assess whether to proceed with a separate rulemaking action to narrow its approval of that state's SIP so as to assure that for federal purposes, the Tailoring Rule thresholds will continue to apply as of the effective date of the final rule that the EPA is proposing today.
In the alternative, if the Tailoring Rule thresholds would not continue to apply when the EPA promulgates requirements under CAA section 111, then the EPA would assess whether to proceed with a separate rulemaking action to narrow its approval of all of the State's approved SIP PSD programs to assure that for federal purposes, the Tailoring Rule thresholds will continue to apply as of the effective date of the final rule that EPA is proposing today.
Under the PSD program in part C of title I of the CAA, in areas that are classified as attainment or unclassifiable for NAAQS pollutants, a new or modified source that emits any air pollutant subject to regulation at or above specified thresholds is required to obtain a preconstruction permit. This permit assures that the source meets specified requirements, including application of BACT. States that are authorized by the EPA to administer the PSD program may issue PSD permits. If a state is not authorized, then the EPA issues the PSD permits.
Regulation of GHG emissions in the Light Duty Vehicle Rule (75 FR 25324) triggered applicability of stationary sources to regulations for GHGs under the PSD and title V provisions of the CAA. Hence, on June 3, 2010 (75 FR 31514), the EPA issued the “Tailoring Rule,” which establishes thresholds for GHG emissions in order to define and limit when new and modified industrial facilities must have permits under the PSD and title V programs. The rule addresses emissions of six GHGs: CO
Commenters have queried whether, because of the way that the EPA's PSD regulations are written, promulgating the rule we propose today may raise questions as to whether the EPA must revise its PSD regulations—and, by the same token, whether states must revise their SIPs—to assure that the Tailoring Rule thresholds will continue to apply to sources subject to PSD. That is, under the EPA's regulations, PSD applies to a “major stationary source” that undertakes construction and to a “major modification.” 40 CFR 51.166(a)(7)(i) and (iii). A “major modification” is defined as “any physical change in or change in the method of operation of a major stationary source that would result in a significant emissions increase . . . and a significant net emissions increase. . . .” Thus, for present purposes, the key component of these
The EPA's regulations define the term “major stationary source” as a “stationary source of air pollutants which emits, or has the potential to emit, 100 [or, depending on the source category, 250] tons per year or more of any regulated NSR pollutant.” 40 CFR 51.166(b)(1)(i)(
The Tailoring Rule, on the face of its regulatory provisions, incorporated the revised thresholds it promulgated into only the fourth prong (“[a]ny pollutant that otherwise is subject to regulation under the Act”), and not the NSPS trigger provision in the second prong (“[a]ny pollutant that is subject to any standard promulgated under section 111 of the Act”). For this reason, a question may arise as to whether the Tailoring Rule thresholds apply to the PSD requirement as triggered by the NSPS that the EPA is promulgating in this rulemaking.
However, although the Tailoring Rule thresholds on their face apply to only the term, “subject to regulation” in the definition of “regulated NSR pollutant,” the EPA stated in the Tailoring Rule preamble that the thresholds should be interpreted to apply to other terms in the definition of “major stationary source” and in the statutory provision, “major emitting facility.” Specifically, the EPA stated:
As just described, we selected the “subject to regulation” mechanism because it most readily accommodated the needs of States to expeditiously revise—through interpretation or otherwise—their state rules. Even so, it is important to recognize that this mechanism has the same substantive effect as the mechanism we considered in the proposed rule, which was revising numerical thresholds in the definitions of major stationary source and major modification. Most importantly, although we are codifying the “subject to regulation” mechanism, that approach is driven by the needs of the states, and our action in this rulemaking should be interpreted to rely on any of several legal mechanisms to accomplish this result. Thus, our action in this rule should be understood as revising the meaning of several terms in these definitions, including: (1) The numerical thresholds, as we proposed; (2) the term, “any source,” which some commenters identified as the most relevant term for purposes of our proposal; (3) the term, “any air pollutant; or (4) the term, “subject to regulation.” The specific choice of which of these constitutes the nominal mechanism does not have a substantive legal effect because each mechanism involves one or another of the components of the terms “major stationary source”—which embodies the statutory term, “major emitting facility”—and “major modification,” which embodies the statutory term, “modification,” and it is those statutory and regulatory terms that we are defining to exclude the indicated GHG-emitting sources.
[Footnote: We also think that this approach better clarifies our long standing practice of interpreting open-ended SIP regulations to automatically adjust for changes in the regulatory status of an air pollutant, because it appropriately assures that the Tailoring Rule applies to both the definition of “major stationary source” and “regulated NSR pollutant.” ]
Thus, according to the preamble of the final Tailoring Rule, the definition of “major stationary source” itself already incorporates the Tailoring Rule thresholds, and not just through one component (the “subject to regulation” prong of the term “regulated NSR pollutant”) of that definition. For this reason, it is the EPA's position that the Tailoring Rule thresholds continue to apply even when the EPA promulgates the first NSPS for GHGs (which, as noted above, triggers the PSD requirement under the NSPS trigger provision in the definition of “regulated NSR pollutant”).
As a result, the EPA believes that states that incorporated the Tailoring Rule thresholds into their SIPs may take the position that they also incorporated the EPA's interpretation in the preamble that the thresholds apply to the definition “major stationary source.”
Even so, to clarify and confirm that the Tailoring Rule thresholds apply to the section 111 prong of the definition of regulated NSR pollutant, in this proposed rulemaking, the EPA is proposing to add new provisions to the NSPS regulations, although not the PSD regulations, to make explicit that the NSPS trigger provision in the PSD regulations incorporates the Tailoring Rule thresholds.
The EPA requests that all States with approved SIP PSD programs that apply to GHGs indicate during the comment period on this rule whether, (i) in light of EPA's interpretation that the Tailoring Rule thresholds continue to apply even when the EPA promulgates the first NSPS for GHGs, and (ii) assuming that EPA finalizes the added provisions to the section 111 regulations proposed today, they can interpret their SIPs already to apply the Tailoring Rule thresholds to the NSPS prong or whether they must revise their SIPs. For any State that says it must revise its SIP (or that does not respond), the EPA will assess whether to propose a rule shortly after the close of the comment period, to narrow its approval of that state's SIP so as to assure that for federal purposes, the Tailoring Rule thresholds will continue to apply as of the effective date of the final rule that the EPA is proposing today. Such a rule would be comparable to what we call the SIP PSD Narrowing Rule that EPA promulgated in December, 2010.
New major stationary sources and major modifications at existing major stationary sources are required by the CAA to, among other things, obtain a permit under the PSD program before commencing construction. A source is subject to PSD by way of its proposed construction and the effect of the construction and operation of the new equipment on emissions. The emission thresholds that define PSD applicability can be found in 40 CFR parts 51 and 52 and are discussed briefly in the above section.
As mentioned above, sources that are subject to PSD must obtain a
Furthermore, this definition in the CAA specifies that “[i]n no event shall application of [BACT] result in emissions of any pollutants which will exceed the emissions allowed by any applicable standard established pursuant to section 111 or 112 of the Act.” This has historically been interpreted to mean that BACT cannot be less stringent than any applicable standard of performance under the NSPS. See e.g. EPA, PSD and Title V Permitting Guidance for Greenhouse Gases, p. 20–21 (March 2011). Thus, upon completion of an NSPS, EPA reads the CAA to mean that the NSPS establishes a “BACT Floor” for PSD permits issued to affected facilities covered by an NSPS. It is important to note that a proposed NSPS does not establish the BACT Floor for affected facilities seeking a PSD permit. This is explained on page 25 of EPA's PSD and Title V Permitting Guidance for Greenhouse Gases (March 2011):
However, once an NSPS is finalized, then the standard applies to any new source or modification that meets the applicability of the NSPS and has not commenced construction as of the date of the proposed NSPS.
It is also important to keep in mind that BACT is a case-by-case review that considers a number of factors, and the fact that a minimum control requirement is established by EPA through an NSPS does not mean that a more stringent control cannot be chosen by the permitting agency. The EPA's PSD and Title V Permitting Guidance for Greenhouse Gases (March 2011) discusses considerations (e.g., technical feasibility, economic impacts and other costs, and environmental and energy impacts) when evaluating BACT for CO
Under this proposed NSPS, an affected facility is a new EGU. In this rule we are not proposing standards for modified or reconstructed sources. However, since both a new and existing power plant can add new EGUs to increase generating capacity, this NSPS will apply to both a new, greenfield EGU facility or an existing facility that adds EGU capacity by adding a new EGU that is an affected facility under this NSPS. While this latter scenario can be considered the modification of existing sources under PSD, this proposed NSPS will not apply to modified or reconstructed sources as those terms are defined under part 60. Thus, this NSPS would not establish a BACT floor for sources that are modifying an existing EGU, for example, by adding new steam tubes in an existing boiler or replacing blades in their existing combustion turbine with a more efficient design.
Furthermore, our analysis for this proposed NSPS considers only the extent to which particular pollution control techniques are BSER for new units, and does not evaluate whether such techniques also qualify as BSER for modified or reconstructed sources under Part 60 or are otherwise achievable methods for reducing GHG emission from such sources considering economic, environmental, and energy impacts. Therefore, we do not believe that the content of this rule has any direct applicability on the determination of BACT for any part 60 modified or reconstructed sources obtaining a PSD permit.
Under the title V program, a source that emits any air pollutant subject to regulation at or above specified thresholds (along with certain other sources) is required to obtain an operating permit. This permit includes all of the CAA requirements applicable to the source. These permits are generally issued through EPA-approved State title V programs.
As the EPA explained in the Tailoring Rule preamble, title V applies to a “major source,” CAA section 502(a), which is defined to include, among other things, certain sources, including any “major stationary source,” CAA section 501(2)(B), which, in turn, is defined to include a stationary source of “any air pollutant” at or above 100 tpy. CAA section 302(j). The EPA's regulations under title V define the term “major source,” and in the Tailoring Rule, the EPA revised that definition to make clear that the term is limited to stationary sources that emit any air pollutant “subject to regulation.” The EPA incorporated the Tailoring Rule threshold within the definition of “subject to regulation.” The EPA described its action as follows in the preamble to the Tailoring Rule:
Thus, EPA is adding the phrase “subject to regulation” to the definition of “major source” under 40 CFR 70.2 and 71.2. The EPA is also adding to these regulations a definition of “subject to regulation.” Under the part 70 and part 71 regulatory changes adopted, the term “subject to regulation,” for purposes of the definition of “major source,” has two components. The first component codifies the general approach EPA recently articulated in the “Reconsideration of Interpretation of Regulations That Determine Pollutants Covered by Clean Air Act Permitting.” 75 FR 17704. Under this first component, a pollutant “subject to regulation” is defined to mean a pollutant subject to either a provision in the CAA or regulation adopted by EPA under the CAA that requires actual control of emissions of that pollutant and that has taken effect under the CAA.
Unlike the PSD regulations described above, the title V definition of “major source”, as revised by the Tailoring Rule, does not on its face distinguish among types of regulatory triggers for title V. Because title V has already been triggered for GHG-emitting sources, the
Note that we propose to move the definition of “Greenhouse gases” currently within the definitions of “Subject to regulation” in 40 CFR 70.2 and 71.2 to a definition within 70.2 and 71.2 to promote clarity in the regulations.
The issuance of the final EGU GHG NSPS will trigger certain requirements related to title V fees for GHG emissions under 40 CFR parts 70 and 71. States (and approved local and tribal permitting authorities) will be required to include GHG emissions in determining whether they collect adequate fees, if the state relies on the “presumptive minimum” approach to demonstrating fee adequacy. In addition, sources subject to federal permitting under part 71 will be required to include GHG emissions in calculating their annual permit fee.
These requirements would be triggered because the regulation of GHGs under section 111 for the first time through the issuance of the EGU GHG NSPS would make GHGs a “regulated air pollutant,” as defined under 40 CFR parts 70 and 71, a “regulated pollutant (for presumptive fee calculation)” as defined under part 70 and a “regulated pollutant (for fee calculation)” as defined under part 71.
Under the current part 70, regulation of GHGs under section 111 through the issuance of any NSPS would result in GHGs being added to the list of air pollutants used in “presumptive minimum” fee calculations. Also, in EPA's part 71 permit program, and possibly in certain state part 70 programs, issuance of a NSPS standard would result in GHGs being added to the list of air pollutants that are subject to fee payment by sources. This effect of adding GHGs to certain title V fee requirements was not discussed in the original proposal for the EGU GHG NSPS; however, several public comments were raised on this issue, and a number of related issues, during the public comment period on the original proposal for the EGU GHG NSPS.
In this re-proposal of the EGU GHG NSPS, we discuss this issue for GHGs related to title V fees and propose rule amendments that will enable permitting authorities to collect fees as needed to support their programs, and to avoid excessive and unnecessary fees. We also respond to and clarify some related issues raised by commenters on the original proposal.
In summary, we are proposing to exempt GHGs from the presumptive fee calculation, yet account for the costs of GHG permitting program costs through a cost adjustment to ensure that fees will be collected that are sufficient to cover the program costs. We are also proposing that permitting agencies that do not use the presumptive fee approach can continue to demonstrate that their fee structures are adequate to implement their title V programs.
Prior to explaining our proposal in more detail, the following discussion provides background on the fee requirements of the title V rules, what those fees cover in terms of agencies' program implementation, what additional activities agencies might be expected to have to undertake as a result of GHGs becoming “regulated pollutants” under the NSPS, what the GHG Tailoring Rule said about title V fees, background on title V fees in the context of the original proposal for the EGU GHG NSPS, and existing limitations on the collection of GHG fees.
Title V is implemented through 40 CFR parts 70 and 71. Part 70 defines the minimum requirements for state, local and tribal (state) agencies to develop, implement and enforce a title V operating permit program; these programs are developed by the state and the state submits a program to EPA for a review of consistency with part 70. There are about 112 approved part 70 programs in effect, with about 15,000 part 70 permits currently in effect. (See Appendix A of 40 CFR part 70 for the approval status of each state program). Part 71 is a federal permit program run by the EPA, primarily where there is no part 70 program in effect (e.g., in Indian country, the federal Outer Continental Shelf and for offshore Liquified Natural Gas terminals).
Section 502(b)(3)(A) of the Act requires owners or operators of all sources subject to permitting to “pay an annual fee, or the equivalent over some other period, sufficient to cover all reasonable (direct and indirect) costs required to develop and administer the permit program.” Section 502(b)(3)(B) of the Act generally sets forth the methods for determining whether a permitting authority is collecting sufficient fees in total to cover the costs of the program. First, under the “presumptive minimum” approach set forth in section 502(b)(3)(B)(i), a state can satisfy the requirement by showing that “the program will result in the collection, in the aggregate, from all sources subject to [the program] of an amount not less than $25 per ton of each regulated pollutant, or such other amount as the Administrator may determine adequately reflects the reasonable costs of the permit program.” The statute further provides that emissions in excess of 4,000 tpy for any one pollutant need not be included in the calculation, and that the initial fee rate ($25 per ton) shall be adjusted for inflation.
Alternatively, if a state does not wish to show it collects an amount of fees at least equal to the presumptive minimum amount, section 502(b)(3)(B)(iv) provides that a program may be approved if the state demonstrates that it collects sufficient fees to cover the costs of the program, even if that amount is below the presumptive minimum.
The presumptive fee approach of the statute is reflected in the part 70 regulations for those states that wish to use it for fee adequacy purposes. In addition, for the federal part 71 permitting program, which the EPA implements directly, the EPA has adopted rules to ensure that it collects adequate fees, consistent with the statute. These statutory requirements for fees are reflected in 40 CFR 70.9 and 71.9, respectively.
Although the Clean Air Act and part 70 require that a title V permit program must collect sufficient fees to cover the costs of the program, neither the Act nor part 70 specifies the details of how those fees must be charged to particular sources in their fee schedules. The part 70 regulations specifically provide, at 40 CFR 70.9(b)(3), that a “state program's fee schedule may include emission fees, application fees, service fees or other types of fees, or any combination thereof.” Many states use emission fees and other types of fees in combination in their fee schedules and we understand that some state fee schedules are structured such that they would result in GHG fees being required when GHGs are regulated under any NSPS. For example, states may have chosen for convenience sake to use the “regulated pollutant (for presumptive fee calculation)” definition of part 70, or a similar state definition, to identify the pollutants subject to fees as part of their fee schedule. For part 71, the EPA chose to promulgate an emissions-based fee schedule that uses the definition of “regulated pollutants (for fee calculation)” to identify the pollutants subject to fees, and thus, part 71 is structured such that GHG fees would be required when GHGs are regulated under any NSPS.
State fee schedules charge emissions-based fees that range from about $15 to $100 or more per ton for each air pollutant for which they charge a fee, while part 71 charges about $48 per ton,
Section 502(b)(3)(A) of the CAA broadly requires permit fees “sufficient to cover all reasonable (direct and indirect) costs required to develop and administer the permit program” including the reasonable costs of: “(i) reviewing and acting upon any application for such a permit, (ii) implementing and enforcing the terms and conditions of any such permit (not including any court costs or other costs associated with any enforcement action), (iii) emissions and ambient monitoring, (iv) preparing generally applicable regulations, or guidance, (v) modeling, analyses, and demonstrations, and (vi) preparing inventories and tracking emissions.” These statutory requirements were incorporated into the regulations at 40 CFR 70.9(b)(1) and 71.9(b), EPA has provided detailed guidance on EPA's interpretation of this list of activities in several memoranda,
The GHG Tailoring Rule concerned when sources are required to obtain permits under prevention of significant deterioration (PSD) and title V due to emissions of GHGs. (
The GHG Tailoring Rule addressed the possible need for states and the EPA to charge fees for GHG emissions based on the burdens imposed under the Tailoring Rule for states to incorporate GHGs into permits or to issue permits to sources based on GHG emissions. We did not revise the part 70 rules to require fees for GHGs, although we did clarify that states have the option of charging fees to recover the costs of permitting related to GHGs. Also, we did not revise part 71 to require GHG fees, and we stated that we would review the need for additional fees to cover program costs for GHGs over time. (See 75 FR 31526 and 31584.) We retained this approach in last year's Step 3 Tailoring Rule. (See Prevention of Significant Deterioration and Title V Greenhouse Tailoring Rule Step 3, GHG Plantwide Applicability Limitations and GHG Synthetic Minor Limitations, (Step 3 of the Tailoring Rule), 77 FR 41051, July 12, 2012).
The previous EGU GHG NSPS proposal did not discuss any title V fee issues related to regulating GHGs under a section 111 standard; however, several public commenters (two state agencies and one industry group) raised several concerns or asked for clarification on a number of issues related to title V fees during the public comment period. Two of these commenters requested clarification as to whether the issuance of the EGU GHG NSPS would make either GHGs or CO
There are a number of provisions in part 70 and part 71 and characteristics of GHGs that are relevant to any discussion related to charging fees for GHGs. First, it should be noted that GHG are emitted in extremely high quantities relative to other air pollutants, such as the criteria pollutants, which are typically emitted by combustion sources that also emit GHGs. A review of emission factors in EPA's AP–42 shows that GHGs are typically emitted in quantities as much as one thousand or more times higher than CO or NO
Second, unlike other pollutants, GHGs can be estimated in two ways: by mass or by CO
In response to concerns raised by commenters, and because response to certain of these issues will help to provide a better proposal, we respond to several of these comments at this time. In response to the question as to whether CO
In response to the comment inquiring whether the rationale of the Tailoring Rule remains relevant for deferring action on fees, we are proposing several revisions to the part 70 and part 71 regulations in response to the proposed regulation of GHGs under section 111, while retaining the general approach that we described in the Tailoring Rule. At the time of the promulgation of the Tailoring Rule, there were no section 111 standards (or other standards) that had been promulgated that would have resulted in title V fee requirements being triggered for GHGs. Thus, the rationale we use now is necessarily different than the rationale we used for the Tailoring Rule fee discussion. If the commenter is referring to the requests of certain state agencies in their comments on the Tailoring Rule for the EPA to set a presumptive fee of GHGs, we are responding to that request in this proposal by proposing to set a presumptive fee cost adjustment. If the commenter is referring to the fee flexibility afforded by 40 CFR 70.9(b)(3), we respond that we are not proposing to revise that regulatory provision. A state commenter generally asked us if it could refrain from requiring a fee for CO
In this part of the preamble we explain and solicit comment on options to address the title V fee issues raised by the proposed regulation of GHGs under this NSPS. In sum, we propose to exempt GHGs from the presumptive fee calculation, yet account for the costs of GHG permitting through a cost adjustment to ensure that fees will be collected that are sufficient to cover the program costs. We request comment on these proposals, particularly from state, local, and tribal permitting agencies, and particularly with respect to which approach would be most appropriate, feasible, and workable and result in fees that would be adequate to cover the direct and indirect costs of permitting GHGs. We also invite comments on ways to improve this proposal and/or address this issue in other ways consistent with the same principles, concerns, and statutory authority that we have described for this proposal.
For the reasons discussed earlier in this proposal, we propose to exempt GHGs from the definition of “regulated pollutant (for presumptive fee calculation)” in 40 CFR 70.2 in order to exclude GHGs from being subject to the statutory fee rate set for the presumptive minimum fee calculation of 40 CFR 70.9(b)(2)(i). Pursuant to the authority of section 502(b)(3)(B)(i), we are proposing to determine that utilizing the statutory fee rate for GHGs would be inappropriate because it would result in excessive fees, far above the reasonable costs of a program. We are proposing a significantly smaller cost adjustment for GHGs to reflect the program costs related to GHGs.
We have estimated the cost of permitting GHGs associated with the Tailoring Rule thresholds in an economic analysis performed for the Tailoring Rule and in several documents related to Information Collection Request (ICR) requirements for part 70 and 71, and we believe these analyses provide a basis for estimating the costs related to GHG permitting for the typical permitting authority. Thus, we propose to revise 40 CFR 70.9(b)(2)(i) to add a GHG cost adjustment to account for the GHG permitting program costs.
We propose to revise the presumptive minimum fee provisions of part 70 to add a GHG cost adjustment to account for the typical GHG permitting program costs that may not already be covered by the existing presumptive minimum fee provisions of parts 70 and 71. The current presumptive minimum fee provisions of the title V rules implements the statutory mandate to collect fees that are sufficient to cover the direct and indirect GHG program costs. Since we are not proposing to charge fees for GHGs at the statutory rate ($25 per ton, adjusted for inflation) due to concerns raised by permitting authorities and others about this resulting in excessive fees, we may need an alternative presumptive minimum fee to recover any costs related to GHGs that would not otherwise be covered by the presumptive minimum fee that is calculated based on emissions of regulated air pollutants, excluding GHGs. We estimated certain incremental GHG program costs that would not be covered under the context of the Tailoring Rule, but we did not revise our permit rule to reflect those costs at that time. We are aware that the EGU NSPS may further increase permitting authority costs above the levels that would be covered by presumptive minimum fee provisions that exclude GHGs, but we are also concerned that accounting for GHGs using the statutory rate would result in excessive calculation of costs. Thus, to address these concerns, we are proposing two alternative options to adjust the presumptive minimum fee provisions of the regulations, including a modest additional cost for each GHG-related activity of certain types that a permitting authority would process over the period covered by the presumptive minimum fee calculation, and a modest additional increase in the per ton rate used in the presumptive minimum calculation. We are also soliciting comment on an option that would calculate no additional costs for GHGs.
When we promulgate step 4 of the Tailoring Rule, and depending on EPA's proposal(s) and final action(s) there, we may revisit the GHG cost adjustment and potentially revise it, taking into account any changes in permitting authority costs for GHGs related to the obligations for permitting authorities under that rulemaking.
In addition, as a general matter, the presumptive minimum adjustments for part 70 we propose for GHGs are based, in part, on information concerning permitting authority burden (in hours) and cost (in dollars) contained in the Information Collection Request (ICR) renewal for part 70
First, we are proposing to adjust the presumptive minimum fee to account for GHG costs by adding a cost for each GHG-related activity of certain types that a permitting authority may perform over the period covered by a presumptive minimum fee calculation. Additional information supporting this approach may be found in part in Table 12 of the supporting statement (in the ICR) summarizing the permitting authority burden for particular GHG-related permitting activities. Table 12 in the ICR shows certain incremental burden assumptions for certain activities related to GHG permitting program costs in the form of an hourly burden for each activity that a permitting authority may process. Based on observations regarding permitting activities since the Tailoring Rule, we have adapted these assumptions for the purposes of this option and included certain activities with a somewhat different description than we used in the table in the ICR in an attempt to more accurately reflect the types of permitting activities that have occurred in the GHG permit program. In addition, by making these clarifying changes, we are trying to more closely track the language in the CAA and parts 70 and 71 regarding the specific of the permit process. We are proposing to include three general activities in this proposed option: (1) “GHG completeness determination (for initial permits or for updated applications)” at 43 hours, (2) “GHG evaluation for a modification or related permit action” at 7 hours, and (3) “GHG evaluation at permit renewal” at 10 burden hours.
We are also co-proposing an alternative option under which we would increase the fee rate used in the presumptive minimum calculation for each regulated air pollutant, excluding GHGs. This option would rely primarily on data concerning the state burdens of permitting GHGs through step 3 of the tailoring rule found in the Information Collection Request (ICR) for part 70. This suggests that when looking at Tailoring Rule burden in isolation, that GHG permitting increases permitting authority burden by about 7 percent above the baseline burden,
The two options we co-propose for adjusting the presumptive minimum fee to account for the costs of GHG permitting are similar in that we believe they would both result in about the same amount of additional fee revenue being collected. For the first option, we took the assumptions approved into the ICR and adapted them somewhat so that they more accurately reflect the actual implementation experience of permitting authorities related to GHGs. On the second, alternative option, we used the ICR estimate to determine the relative contribution of GHG tailoring rule costs to the total costs of title V permitting and we assume these relative costs will hold true in any particular state that uses the presumptive minimum fee approach to demonstrating fee adequacy. The two options differ in that the first option calculates the GHG adjustment to the presumptive fee minimum by determining the number of actual GHG-related activities they have performed for a period, while the second option calculates the GHG adjustment by increasing the presumptive fee rate for non-GHG pollutants by a set ratio to reflect average expected costs. The first approach requires a state to track the number of activities of these types it is performing and is thus more burdensome to calculate, although it may more accurately reflect the actual costs. The second approach is simpler to calculate and predictable but is less directly tied to actual implementation experience in a particular state.
We also solicit comment on whether we need to revise the presumptive minimum calculation provisions to account for GHGs costs if we exempt GHGs from the calculation of the presumptive minimum fee. The basis for this option would be that because most GHG sources that would be subject to title V permitting, whether due to GHGs or due for other reasons under the proposed NSPS and applicability provisions of the permitting rules (see 40 CFR 70.3 and 71.3) would have actual emissions of other regulated air
This proposal does not directly affect those states that do not rely on the presumptive minimum fee approach to show fee adequacy; however, non-presumptive fee states are still required to charge sufficient fees to recover all reasonable direct and indirect program costs. Part 70 allows the EPA to review state fee programs at any time to determine if they are collecting fees sufficient to cover their costs, whether or not states rely on the presumptively minimum fee approach. We are not requiring any additional detailed fee submittals from states at this time based on these proposed changes.
Some states may conclude that they wish to revise their part 70 programs in response to this proposal either to revise their state fee schedules to prevent any possible collection of excessive fees (e.g., if they require any regulated pollutant subject to a section 111 standard to pay a fee) or to charge additional fees to sources because their presumptive minimum fee target has increased. We solicit comment on the most expeditious means for EPA to approve title V program revisions across the states once this proposal is finalized.
There may be other viable options consistent with statutory and regulatory authority, principles, and concerns, in addition to those we have described in this proposal. For example, states have previously commented on establishing a separate, lower presumptive fee per ton of GHG emissions). The EPA invites states, local, and/or Tribal authorities to provide more refined data and/or information surrounding the unique costs associated with permitting GHG sources under this proposed rule, and other fee options such data supports. Notably, the regulatory text included today represents only one option on which comments are solicited. The EPA is providing full regulatory text only for this option because it represents the most novel approach. The EPA is also soliciting comment on other viable approaches described herein, but considers the discussion provided herein to provide an adequate basis for public comment. The EPA notes that the final rule may be based on any of the approaches described in the preamble.
As part of the promulgation of the final part 71 rule, the EPA performed a detailed analysis of the costs of developing and implementing the program and reviewed the inventory of emissions of regulated pollutants (for fee calculation) to determine the appropriate emission fee that would be sufficient to recover all direct and indirect programs costs—we set the fee at $32 per ton, adjusted for inflation, times the emissions of regulated pollutant (for fee calculation). (
For part 71, we also propose to exempt GHGs from the definition of regulated pollutant (for fee calculation), which is similar to the definition of regulated pollutants (for presumptive fee calculation) used in part 70, for the same reasons we have explained for part 70. In addition, for the same reasons we explained for part 70, we are proposing two options for revising the fee schedule of 40 CFR 71.9(c) to ensure that we continue to recover sufficient fees to fully fund the part 71 GHG permitting program. The bases for the options were described in more detail earlier in this proposal with respect to part 70 proposals and those also apply here to part 71.
First, the EPA (or delegate agency) burden hour assumptions we propose for each GHG-related permitting activity under part 71 are the same as we are proposing for states under the presumptive minimum fee provisions of part 70.
The second option we propose for part 71 is to increase the emission fee by a modest amount for each regulated air pollutant, excluding GHGs. For simplicity sake, we propose to charge the same adjustment under this option that we propose for part 70, or 7 percent, which would be multiplied by annual part 71 fee in effect to calculate the revise fee rate.
We also solicit comment on whether we could exclude GHG emissions from the calculation of the annual part 71 fee for reasons similar to those we explained for part 70 (e.g., because permitting costs can be covered by the existing part 71 permit fee).
As explained in the Regulatory Impact Analysis (RIA) for this proposed rule, available data indicate that, even in the absence of this rule, existing and anticipated economic conditions will lead electricity generators to choose new generation technologies that would meet the proposed standard without installation of additional controls. Therefore, based on the analysis presented in Chapter 5 of the RIA, the EPA projects that this proposed rule will result in negligible CO
This proposed rule is not anticipated to have a notable effect on the supply, distribution, or use of energy. As previously stated, the EPA believes that electric power companies would choose to build new EGUs that comply with the regulatory requirements of this proposal even in its absence, because of existing and expected market conditions. In addition, the EPA does not project any new coal-fired EGUs without CCS to be built in the absence of this proposal.
The EPA believes this proposed rule will have no notable compliance costs associated with it, because electric power companies would be expected to build new EGUs that comply with the regulatory requirements of this proposal even in the absence of the proposal, due to existing and expected market conditions. The EPA does not project any new coal-fired EGUs without CCS to be built in the absence of the proposal. However, because some companies may choose to construct coal or other fossil fuel-fired units, the RIA also analyzes project-level costs of a unit with and without CCS, to quantify the potential cost for a fossil fuel-fired unit with CCS.
As previously explained, the special characteristics of GHGs make it important to take initial steps to control the largest emissions categories without delay. Unlike most traditional air pollutants, GHGs persist in the atmosphere for time periods ranging from decades to millennia, depending on the gas. Fossil-fueled power plants emit more GHG emissions than any other stationary source category in the United States, and among new GHG emissions sources, the largest individual sources are in this source category.
This proposed rule will limit GHG emissions from new sources in this source category to levels consistent with current projections for new fossil fuel-fired generating units. The proposed rule will also serve as a necessary predicate for the regulation of existing sources within this source category under CAA section 111(d). In these ways, the proposed rule will contribute to the actions required to slow or reverse the accumulation of GHG concentrations in the atmosphere, which is necessary to protect against projected climate change impacts and risks.
The EPA does not anticipate that this proposed rule will result in notable CO
As previously stated, the EPA does not anticipate that the power industry will incur compliance costs as a result of this proposal and we do not anticipate any notable CO
We request comments on all aspects of the proposed rulemaking including the RIA. All significant comments received will be considered in the development and selection of the final rule. We specifically solicit comments on additional issues under consideration as described below.
a. EPA Method 2F of 40 CFR part 60 for flow rate measurement during the relative accuracy test audit and performance testing. Method 2F provides velocity data for three dimensions and provides measurements more representative of actual gas flow rates than EPA Method 2 or 2G of 40 CFR part 60.
b. EPA Method 2H of 40 CFR part 60 or Conditional Test Method (CTM)-041 (see:
c. EPA Method 4 of 40 CFR part 60 to determine moisture for flow rate during CEMS relative accuracy determinations and for performance test calculations.
d. EPA Method 3A of 40 CFR part 60 for CO
e. An ambient air argon concentration of 0.93 percent
f. A value for pi of 3.14159 when calculating the effective area for circular stacks.
g. A daily calibration drift cap no greater than 0.3 percent CO
h. A maximum relative accuracy specification of 2.5 percent for both CO
i. Method 3B of 40 CFR part 60 in addition to Method 3A, for CO
Under Executive Order (EO) 12866 (58 FR 51735, October 4, 1993), this action is a “significant regulatory action” because it “raises novel legal or policy issues arising out of legal mandates”. Accordingly, the EPA submitted this action to the Office of Management and Budget (OMB) for review under Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any changes made in response to OMB recommendations have been documented in the docket for this action. In addition, the EPA prepared an analysis of the potential costs and benefits associated with this action. This analysis is contained in the Regulatory Impact Analysis for the Standards of Performance for Greenhouse Gas Emissions for New Fossil Fuel-Fired Electric Utility Steam Generating Units and Stationary Combustion Turbines.
The EPA believes this rule will have no notable compliance costs associated with it over a range of likely sensitivity conditions because electric power companies would choose to build new EGUs that comply with the regulatory requirements of this proposal even in the absence of the proposal, because of existing and expected market conditions. (See the RIA for further discussion of sensitivities). The EPA does not project any new coal-fired EGUs without CCS to be built in the absence of this proposal. However, because some companies may choose to construct coal or other fossil fuel-fired units, the RIA also analyzes project-level costs of a unit with and without CCS, to quantify the potential cost for a fossil fuel-fired unit with CCS.
The information collection requirements in this proposed rule have been submitted for approval to the Office of Management and Budget (OMB) under the
This proposed action would impose minimal new information collection burden on affected sources beyond what those sources would already be subject to under the authorities of CAA parts 75 and 98. OMB has previously approved the information collection requirements contained in the existing part 75 and 98 regulations (40 CFR part 75 and 40 CFR part 98) under the provisions of the
The EPA believes that electric power companies will choose to build new EGUs that comply with the regulatory requirements of this proposal because of existing and expected market conditions. The EPA does not project any new coal-fired EGUs that commence construction after this proposal to commence operation over the 3-year period covered by this ICR. We estimate that 17 new affected NGCC units would commence operation during that time period. As a result of this proposal, those units would be required to prepare a summary report, which includes reporting of emissions and downtime, every 3 months.
When a malfunction occurs, sources must report them according to the applicable reporting requirements of 40 CFR part 60, subparts Da and KKKK or subpart TTTT 60.5530. An affirmative defense to civil penalties for exceedances of emission limits that are caused by malfunctions is available to a source if it can demonstrate that certain criteria and requirements are satisfied. The criteria ensure that the affirmative defense is available only where the event that causes an exceedance of the emission limit meets the narrow definition of malfunction (sudden, infrequent, not reasonably preventable, and not caused by poor maintenance or careless operation) and where the source took necessary actions to minimize emissions. In addition, the source must meet certain notification and reporting requirements. For example, the source must prepare a written root cause analysis and submit a written report to the Administrator documenting that it has met the conditions and requirements for assertion of the affirmative defense.
To provide the public with an estimate of the relative magnitude of the burden associated with an assertion of affirmative defense, the EPA has estimated what the notification, recordkeeping, and reporting requirements associated with the assertion of the affirmative defense might entail. The EPA's estimate for the required notification, reports, and records, including the root cause analysis, associated with a single incident totals approximately totals $3,141, and is based on the time and effort required of a source to review relevant data, interview plant employees, and document the events surrounding a malfunction that has caused an exceedance of an emission limit. The estimate also includes time to produce and retain the record and reports for submission to the EPA. The EPA provides this illustrative estimate of this burden, because these costs are only incurred if there has been a violation, and a source chooses to take advantage of the affirmative defense.
Given the variety of circumstances under which malfunctions could occur, as well as differences among sources' operation and maintenance practices, we cannot reliably predict the severity and frequency of malfunction-related excess emissions events for a particular source. It is important to note that the EPA has no basis currently for estimating the number of malfunctions that would qualify for an affirmative defense. Current historical records would be an inappropriate basis, as this rule applies only to sources built in the future. Of the number of excess emissions events that may be reported by source operators, only a small number would be expected to result from a malfunction, and only a subset of excess emissions caused by malfunctions would result in the source choosing to assert an affirmative defense. Thus, we believe the number of instances in which source operators might be expected to avail themselves of the affirmative defense will be extremely small. In fact, we estimate that there will be no such occurrences for any new sources subject to 40 CFR part 60, subpart Da and subpart KKKK or subpart TTTT over the 3-year period covered by this ICR. We expect to gather information on such events in the future, and will revise this estimate as better information becomes available.
The annual information collection burden for this collection consists only of reporting burden as explained above. The reporting burden for this collection (averaged over the first 3 years after the effective date of the standards) is estimated to be $15,570 and 396 labor hours. This estimate includes quarterly summary reports which include reporting of emissions and downtime. All burden estimates are in 2010 dollars. Average burden hours per response are estimated to be 8 hours. The total number of respondents over the 3-year ICR period is estimated to be 36. Burden is defined at 5 CFR 1320.3(b).
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for the EPA's regulations in 40 CFR are listed in 40 CFR part 9.
To comment on the Agency's need for this information, the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden, the EPA has established a public docket for this rule, which includes this ICR, under Docket ID number EPA–HQ–OAR–2013–0495. Submit any comments related to the ICR to the EPA and OMB. See
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 rule on small entities, small entity is defined as:
(1) A small business that is defined by the SBA's regulations at 13 CFR 121.201 (for the electric power generation industry, the small business size standard is an ultimate parent entity defined as having a total electric output of 4 million MWh or less in the previous fiscal year. The NAICS codes for the affected industry are in Table 8 below);
(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 this proposed rule on small entities, I certify that this action will not have a significant economic impact on a substantial number of small entities.
We do not include an analysis of the illustrative impacts on small entities that may result from implementation of this proposed rule because we do not anticipate any compliance costs over a range of likely sensitivity conditions as a result of this proposal. Thus the cost-to-sales ratios for any affected small entity would be zero costs as compared to annual sales revenue for the entity. The EPA believes that electric power companies will choose to build new EGUs that comply with the regulatory requirements of this proposal because of existing and expected market conditions. (See the RIA for further discussion of sensitivities). The EPA does not project any new coal-fired EGUs without CCS to be built. Accordingly, there are no anticipated economic impacts as a result of this proposal.
Nevertheless, the EPA is aware that there is substantial interest in this rule among small entities (municipal and rural electric cooperatives). In light of this interest, prior to the April 13, 2012 proposal (77 FR 22392), the EPA determined to seek early input from representatives of small entities while formulating the provisions of the proposed regulation. Such outreach is also consistent with the President's January 18, 2011 Memorandum on Regulatory Flexibility, Small Business, and Job Creation, which emphasizes the important role small businesses play in the American economy. This process has enabled the EPA to hear directly from these representatives, at a very preliminary stage, about how it should approach the complex question of how to apply Section 111 of the CAA to the regulation of GHGs from these source categories. The EPA's outreach regarded planned actions for new and existing sources, but only new sources would be affected by this proposed action.
The EPA conducted an initial outreach meeting with small entity representatives on April 6, 2011. The purpose of the meeting was to provide an overview of recent EPA proposals impacting the power sector. Specifically, overviews of the Transport Rule, the Mercury and Air Toxics Standards, and the Clean Water Act 316(b) Rule proposals were presented.
The EPA conducted outreach with representatives from 20 various small entities that potentially would be affected by this rule. The representatives included small entity municipalities, cooperatives, and private investors. We distributed outreach materials to the small entity representatives; these materials included background, an overview of affected sources and GHG emissions from the power sector, an overview of CAA section 111, an assessment of CO
A second outreach meeting was conducted on July 13, 2011. We met with nine of the small entity representatives, as well as three participants from organizations representing power producers. During the second outreach meeting, various small entity representatives and participants from organizations representing power producers presented information regarding issues of concern with respect to development of standards for GHG emissions. Specifically, topics suggested by the small entity representatives and discussed included: boilers with limited opportunities for efficiency improvements due to NSR complications for conventional pollutants; variances per kilowatt-hour and in heat rates over monthly and annual operations; significance of plant age; legal issues; importance of future determination of carbon neutrality of biomass; and differences between municipal government electric utilities and other utilities.
While formulating the provisions of this proposed regulation, the EPA also considered the input provided in the over 2.5 million public comments on the April 13, 2012 proposed rule (77 FR 22392). We invite comments on all aspects of the proposal and its impacts, including potential adverse impacts, on small entities.
This proposed rule does 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. The EPA believes this proposed rule will have no compliance costs associated with it over a range of likely sensitivity conditions because electric power companies will choose to build new EGUs that comply with the regulatory requirements of this proposal because of existing and expected market conditions. (See the RIA for further discussion of sensitivities). The EPA does not project any new coal-fired EGUs without CCS to be built. Thus, this proposed rule is not subject to the requirements of sections 202 or 205 of UMRA.
This proposed 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.
In light of the interest in this rule among governmental entities, the EPA initiated consultations with governmental entities prior to the April 13, 2012 proposal (77 FR 22392). The EPA invited the following 10 national organizations representing state and local elected officials to a meeting held on April 12, 2011, in Washington DC: (1) National Governors Association; (2) National Conference of State Legislatures, (3) Council of State Governments, (4) National League of Cities, (5) U.S. Conference of Mayors, (6) National Association of Counties, (7) International City/County Management Association, (8) National Association of Towns and Townships, (9) County Executives of America, and (10) Environmental Council of States. These 10 organizations representing elected state and local officials have been identified by the EPA as the “Big 10” organizations appropriate to contact for
During the meeting, officials asked clarifying questions regarding CAA section 111 requirements and efficiency improvements that would reduce CO
While formulating the provisions of this proposed regulation, the EPA also considered the input provided in the over 2.5 million public comments on the April 13, 2012 proposed rule (77 FR 22392).
This proposed action does not have federalism implications. It would 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 EO 13132. This proposed action would not impose substantial direct compliance costs on state or local governments, nor would it preempt state law. Thus, Executive Order 13132 does not apply to this action. Prior to the April 13, 2012 proposal (77 FR 22392), the EPA consulted with state and local officials in the process of developing the proposed rule to permit them to have meaningful and timely input into its development. The EPA's consultation regarded planned actions for new and existing sources, but only new sources would be affected by this proposed action. The EPA met with 10 national organizations representing state and local elected officials to provide general background on the proposal, answer questions, and solicit input from state/local governments. The UMRA discussion in this preamble includes a description of the consultation. While formulating the provisions of this proposed regulation, the EPA also considered the input provided in the over 2.5 million public comments on the April 13, 2012 proposed rule (77 FR 22392). In the spirit of EO 13132, and consistent with the EPA policy to promote communications between the EPA and state and local governments, the EPA specifically solicits 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). It would neither impose substantial direct compliance costs on tribal governments, nor preempt Tribal law. This proposed rule would impose requirements on owners and operators of new EGUs. The EPA is aware of three coal-fired EGUs located in Indian Country but is not aware of any EGUs owned or operated by tribal entities. The EPA notes that this proposal does not affect existing sources such as the three coal-fired EGUs located in Indian Country, but addresses CO
Although Executive Order 13175 does not apply to this action, EPA consulted with tribal officials in developing this action. Because the EPA is aware of Tribal interest in this proposed rule, prior to the April 13, 2012 proposal (77 FR 22392), the EPA offered consultation with tribal officials early in the process of developing the proposed regulation to permit them to have meaningful and timely input into its development. The EPA's consultation regarded planned actions for new and existing sources, but only new sources would be affected by this proposed action.
Consultation letters were sent to 584 tribal leaders. The letters provided information regarding the EPA's development of NSPS and emission guidelines for EGUs and offered consultation. A consultation/outreach meeting was held on May 23, 2011, with the Forest County Potawatomi Community, the Fond du Lac Band of Lake Superior Chippewa Reservation, and the Leech Lake Band of Ojibwe. Other tribes participated in the call for information gathering purposes. In this meeting, the EPA provided background information on the GHG emission standards to be developed and a summary of issues being explored by the Agency. Tribes suggested that the EPA consider expanding coverage of the GHG standards to include combustion turbines, lowering the 250 MMBtu per hour heat input threshold so as to capture more EGUs, and including credit for use of renewables. The tribes were also interested in the scope of the emissions averaging being considered by the Agency (e.g., over what time period, across what units). In addition, the EPA held a series of listening sessions on this proposed action. Tribes participated in a session on February 17, 2011 with the state agencies, as well as in a separate session with tribes on April 20, 2011.
While formulating the provisions of this proposed regulation, the EPA also considered the input provided in the over 2.5 million public comments on the April 13, 2012 proposed rule (77 FR 22392).
The EPA will also hold additional meetings with tribal environmental staff to inform them of the content of this proposal as well as provide additional consultation with tribal elected officials where it is appropriate. We specifically solicit additional comment on this proposed rule from tribal officials.
The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying to those regulatory actions that concern health or safety risks, such that the analysis required under section 5–501 of the Order has the potential to influence the regulation. This action is not subject to EO 13045 because it is based solely on technology performance.
This proposed action is not a “significant energy action” as defined in EO 13211 (66 FR 28355 (May 22, 2001)) because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. This proposed action is not anticipated to have notable impacts on emissions, costs or energy supply decisions for the affected electric utility industry.
Section 12(d) of the NTTAA of 1995 (Pub. L. 104–113; 15 U.S.C. 272 note) directs the EPA to use Voluntary Census Standards in their regulatory and procurement 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, business practices) developed or adopted by one or more voluntary consensus bodies. The NTTAA directs the EPA to provide Congress, through annual reports to the OMB, with explanations when an agency does not use available and applicable VCS.
This proposed rulemaking involves technical standards. The EPA proposes to use the following standards in this proposed rule: D5287–08 (Standard Practice for Automatic Sampling of Gaseous Fuels), D4057–06 (Standard Practice for Manual Sampling of Petroleum and Petroleum Products), and D4177–95(2010) (Standard Practice for Automatic Sampling of Petroleum and Petroleum Products). The EPA is proposing use of Appendices B, D, F, and G to 40 CFR part 75; these Appendices contain standards that have already been reviewed under the NTTAA.
The EPA welcomes comments on this aspect of the proposed rulemaking and, specifically, invites the public to identify potentially-applicable VCS and to explain why such standards should be used in this action.
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 U.S.
This proposed rule limits GHG emissions from new fossil fuel-fired EGUs by establishing national emission standards for CO
The statutory authority for this action is provided by sections 111, 301, 302, and 307(d)(1)(C) of the CAA as amended (42 U.S.C. 7411, 7601, 7602, 7607(d)(1)(C)). This action is also subject to section 307(d) of the CAA (42 U.S.C. 7607(d)).
Environmental protection, Administrative practice and procedure, Air pollution control, Intergovernmental relations, Reporting and recordkeeping requirements.
Environmental protection, Administrative practice and procedure, Air pollution control, Intergovernmental relations, Reporting and recordkeeping requirements.
Environmental Protection, Administrative practice and procedure, Air pollution control, Reporting and recordkeeping requirements.
Environmental protection, Greenhouse gases and monitoring, Reporting and recordkeeping requirements.
For the reasons stated in the preamble, title 40, chapter I, part 60, 70, 71, and 98 of the Code of the Federal Regulations is proposed to be amended as follows:
42 U.S.C. 7401
(a) Your affected facility is subject to this section if construction commenced after [DATE OF PUBLICATION IN THE
(1) The affected facility combusts fossil fuel for more than 10.0 percent of the heat input during any 3 consecutive calendar years.
(2) The affected facility supplies more than one-third of its potential electric output and more than 219,000 MWh net-electric output to a utility power distribution system for sale on an annual basis.
(b) The following EGUs are not subject to this section:
(1) The proposed Wolverine EGU project described in Permit to Install No. 317–07 issued by the Michigan Department of Environmental Quality, Air Quality Division, effective June 29, 2011 (as revised July 12, 2011).
(2) The proposed Washington County EGU project described in Air Quality Permit No. 4911–303–0051–P–01–0 issued by the Georgia Department of Natural Resources, Environmental Protection Division, Air Protection Branch, effective April 8, 2010, provided that construction had not commenced for NSPS purposes as of [DATE OF PUBLICATION IN THE
(3) The proposed Holcomb EGU project described in Air Emission Source Construction Permit 0550023 issued by the Kansas Department of Health and Environment, Division of Environment, effective December 16, 2010, provided that construction had not commenced for NSPS purposes as of [DATE OF PUBLICATION IN THE
(c) As owner or operator of an affected facility subject to this section, you shall not cause to be discharged into the atmosphere from the affected facility any gases that contain CO
(1) 500 kilograms (kg) of CO
(2) 480 kg of CO
(d) You must make compliance determinations at the end of each operating month, as provided in
(1) If you elect to comply with the CO
(2) If you elect to comply with the CO
(e) You must conduct an initial compliance determination with the CO
(f) You must monitor and collect data to demonstrate compliance with the CO
(1) You must prepare a monitoring plan in accordance with the applicable provisions in § 75.53(g) and (h) of this chapter.
(2) You must measure the hourly CO
(i) You must install, certify, operate, maintain, and calibrate a CO
(ii) For each monitoring system used to determine the CO
(iii) You must use a laser device to measure the dimensions of each exhaust gas stack or duct at the flow monitor and the reference method sampling locations prior to the initial setup (characterization) of the flow monitor. For circular stacks, you must make measurements of the diameter at three or more distinct locations and average the results. For rectangular stacks or ducts, you must make measurements of each dimension (i.e., depth and width) at three or more distinct locations and average the results. If the flow rate monitor or reference method sampling site is relocated, you must repeat these measurements at the new location.
(iv) You can only use unadjusted exhaust gas volumetric flow rates to determine the hourly CO
(v) If you choose to use Method 2 in Appendix A–1 to this part to perform the required relative accuracy test audits (RATAs) of the part 75 flow rate monitoring system, you must use a calibrated Type-S pitot tube or pitot tube assembly. You must not use the default Type-S pitot tube coefficient.
(vi) If two or more affected facilities share a common exhaust gas stack and are subject to the same CO
(vii) If the exhaust gases from the affected facilities are emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you choose to monitor in the ducts), you must monitor the hourly CO
(3) As an alternative to complying with paragraph (f)(2) of this section, for affected facilities that do not combust any solid fuel, you may determine the hourly CO
(i) You must implement the applicable procedures in Appendix D to part 75 of this chapter to determine hourly unit heat input rates (MMBtu/h), based on hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel combusted.
(ii) You may determine site-specific carbon-based F-factors (F
(4) You must install, calibrate, maintain, and operate a sufficient number of watt meters to continuously measure and record the gross electric output from the affected facility, and you must meet the requirements specified in paragraphs (f)(4)(i) and (ii) of this section, as applicable.
(i) If your affected facility is a combined heat and power unit as defined in § 60.42Da, you must also install, calibrate, maintain, and operate meters to continuously determine and record the total useful recovered thermal energy. For process steam applications, you must install, calibrate, maintain, and operate meters to continuously determine and record steam flow rate, temperature, and pressure. If your affected facility has a direct mechanical drive application, you must submit a plan to the Administrator or delegated authority for approval of how gross energy output will be determined. Your plan shall ensure that you install, calibrate, maintain, and operate meters to continuously determine and record each component of the determination.
(ii) If two or more affected facilities have steam generating units that serve a common electric generator, you must apportion the combined hourly gross electric output to each individual affected facility using a plan approved by the Administrator (e.g., using steam load or heat input to each affected facility). Your plan shall ensure that you install, calibrate, maintain, and operate meters to continuously determine and record each component of the determination.
(g) You must demonstrate compliance with the CO
(1) You must calculate the CO
(i) You must only use operating hours in the compliance period for which you have valid data for all the parameters you use to determine the hourly CO
(ii) You must calculate the total CO
(iii) For each operating hour of the compliance period used in paragraph (g)(1)(ii) of this section to calculate the total CO
(A) Calculate P
(B) If applicable to your affected facility, calculate (Pt)
(C) For an operating hour in which there is no gross electric load, but there is mechanical or useful thermal output, you must still determine the gross energy output for that hour. In addition, for an operating hour in which there is no useful output, you must still determine the hourly gross CO
(D) If hourly CO
(iv) You must calculate the total gross energy output by summing the hourly gross energy output values for the affected facility determined from paragraph (g)(1)(iii) of this section for all of the operating hours in the applicable compliance period.
(v) You must calculate the CO
(2) You must determine compliance with the CO
(i) If the CO
(ii) If the CO
(h) You must prepare and submit notifications and reports according to paragraphs (h)(1) through (4) of this section.
(1) You must prepare and submit the notifications in §§ 60.7(a)(1) and (a)(3) and 60.19, as applicable to your affected facility.
(2) You must prepare and submit notifications in § 75.61 of this chapter, as applicable to your affected facility.
(3) You must submit electronic quarterly reports according to the requirements specified in paragraphs (h)(3)(i) through (iii) of this section.
(i) Initially, after you have accumulated the required number of operating months for the CO
(ii) In each quarterly report you must include the information in paragraphs (h)(3)(ii)(A) through (E) of this section.
(A) The CO
(B) Any months in the calendar quarter that you are not counting as operating months.
(C) For each operating month in the calendar quarter, the corresponding average CO
(D) The percentage of valid CO
(E) Any operating months in the calendar quarter with excess CO
(iii) In the final quarterly report of each calendar year you must include the following:
(A) Net electric output sold to an electric grid over the calendar year; and
(B) The potential electric output of the facility.
(iv) You must submit each electronic report using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool provided by the Clean Air Markets Division in the EPA Office of Atmospheric Programs.
(4) You must meet all applicable reporting requirements and submit reports as required under subpart G of part 75 of this chapter.
(5) If your affected unit uses geologic sequestration to meet the applicable emissions limit, you must report in accordance with the requirements of 40 CFR Part 98, subpart PP and either:
(i) if injection occurs onsite, report in accordance with the requirements of 40 CFR Part 98, subpart RR, or
(ii) if injection occurs offsite, transfer the captured CO
(i) For each affected electric utility stream generating unit, you must maintain records according to paragraphs (i)(1) through (i)(8) of this section.
(1) You must comply with the applicable recordkeeping requirements and maintain records as required under subpart F of part 75 of this chapter.
(2) You must maintain records of the calculations you performed to determine the total CO
(3) You must maintain records of the applicable data recorded and calculations performed that you used to determine the gross energy output for each operating month.
(4) You must maintain records of the calculations you performed to determine the percentage of valid CO
(5) You must maintain records of the calculations you performed to assess compliance with each applicable CO
(6) Your records must be in a form suitable and readily available for expeditious review.
(7) You must maintain each record for 5 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record except those records required to demonstrate compliance with an 84-operating month compliance period. You must maintain records required to demonstrate compliance with an 84-operating month compliance period for at least 10 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record.
(8) You must maintain each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to § 60.7. You may maintain the records off site and electronically for the remaining year(s) as required by this subpart.
(j)
(1) For purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG emissions from new affected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 51.166(b)(48) and in any SIP approved by the EPA that is interpreted to incorporate, or specifically incorporates, 40 CFR 51.166(b)(48).
(2) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from new affected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 52.21(b)(49).
(3) For purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from new affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is “subject to regulation” as defined in 40 CFR 70.2.
(4) For purposes of 40 CFR 71.2, with respect to greenhouse gas emissions from new affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is “subject to regulation” as defined in 40 CFR 71.2.
(k) For purposes of this section, the following definitions apply:
(i) Except as provided under paragraph (ii) of this definition, for electric utility steam generating units, the gross electric or mechanical output from the affected facility (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expanders) minus any electricity used to power the feedwater pumps plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application);
(ii) For electric utility steam generating unit combined heat and power facilities where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross energy output consists of thermal output on a rolling 3 year basis, the gross electric or mechanical output from the affected facility (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expanders) minus any electricity used to power the feedwater pumps, that difference divided by 0.95, plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application);
(iii) Except as provided under paragraph (ii) of this definition, for a IGCC electric utility generating unit, the gross electric or mechanical output from the affected facility (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expanders) plus 75 percent of the useful
(iv) For IGCC electric utility generating unit combined heat and power facilities where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross energy output consists of thermal output on a rolling 3 year basis, the gross electric or mechanical output from the affected facility (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expanders) divided by 0.95, plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application);
(i) Except as provided under paragraph (ii) of this definition, the gross electric sales to the utility power distribution system minus purchased power on a calendar year basis, or
(ii) For combined heat and power facilities where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross energy output consists of thermal output, the gross electric sales to the utility power distribution system minus purchased power of the thermal host facility or facilities on a calendar year basis.
(i) Either 33 percent or the design net electric output efficiency, at the election of the owner/operator of the affected facility,
(ii) Multiplied by the maximum design heat input capacity of the steam generating unit,
(iii) Divided by 3,413 Btu/KWh,
(iv) Divided by 1,000 kWh/MWh, and
(v) Multiplied by 8,760 h/yr.
(vi) For example, a 35 percent efficient steam generating unit with a 100 MW (341 MMBtu/h) fossil-fuel heat input capacity would have a 310,000 MWh 12 month potential electric output capacity.
(c) For purposes of regulation of greenhouse gases, the applicable provisions of this subpart affect your stationary combustion turbine if it meets the applicability conditions in paragraphs (c)(1) through (c)(5) of this section.
(1) Commenced construction after [DATE OF PUBLICATION IN THE
(2) Has a design heat input to the turbine engine greater than 73 MW (250 MMBtu/h);
(3) Combusts fossil fuel for more than 10.0 percent of the heat input during any 3 consecutive calendar years.
(4) Combusts over 90% natural gas on a heat input basis on a 3 year rolling average basis; and
(5) Was constructed for the purpose of supplying, and supplies, one-third or more of its potential electric output and more than 219,000 MWh net-electrical output to a utility distribution system on a 3 year rolling average basis.
(a) The pollutants regulated by this subpart are nitrogen oxides (NO
(b)(1) The greenhouse gases regulated by this subpart consist of carbon dioxide (CO
(2)
(i) For purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG emissions from affected stationary combustion turbine, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 51.166(b)(48) and in any SIP approved by the EPA that is interpreted to incorporate, or specifically incorporates, 40 CFR 51.166(b)(48).
(ii) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from affected stationary combustion turbines, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 52.21(b)(49).
(iii) For purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from affected stationary combustion turbines, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is “subject to regulation” as defined in 40 CFR 70.2.
(iv) For purposes of 40 CFR 71.2, with respect to greenhouse gas emissions from affected stationary combustion turbines, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is “subject to regulation” as defined in 40 CFR 71.2.
You must not discharge from your affected stationary combustion turbine into the atmosphere any gases that contain CO
(c) If you own or operate an affected stationary combustion turbine subject to a CO
(a) You must prepare a monitoring plan in accordance with the applicable provisions in § 75.53(g) and (h) of this chapter.
(b) You must measure the hourly CO
(1) You must install, certify, operate, maintain, and calibrate a CO
(2) For each monitoring system that you use to determine the CO
(3) You must use a laser device to measure the dimensions of each exhaust gas stack or duct at the flow monitor and the reference method sampling locations prior to the initial setup (characterization) of the flow monitor. For circular stacks, you must make measure of the diameter at three or more distinct locations and average the results. For rectangular stacks or ducts, you must measure each dimension (i.e., depth and width) at three or more distinct locations and average the results. If the flow rate monitor or reference method sampling site is relocated, you must repeat these measurements at the new location.
(4) You must use unadjusted exhaust gas volumetric flow rates only to determine the hourly CO
(5) If you chose to use Method 2 in Appendix A–1 to this part to perform the required relative accuracy test audits (RATAs) of the part 75 flow rate monitoring system, you must use a calibrated Type-S pitot tube or pitot tube assembly. You must not use the default Type-S pitot tube coefficient.
(c) As an alternative to complying with paragraph (b) of this section, you may determine the hourly CO
(1) You must implement the applicable procedures in appendix D to part 75 of this chapter to determine hourly unit heat input rates (MMBtu/h), based on hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel combusted.
(2) You may determine site-specific carbon-based F-factors (F
(d) You must install, calibrate, maintain, and operate a sufficient number of watt meters to continuously measure and record the gross electric output from the affected stationary combustion turbine. If the affected stationary combustion turbine is a CHP stationary combustion turbine, you must also install, calibrate, maintain, and operate meters to continuously determine and record the total useful recovered thermal energy. For process steam applications, you will need to install, calibrate, maintain, and operate meters to continuously determine and record steam flow rate, temperature, and pressure. If the affected stationary combustion turbine has a direct mechanical drive application, you must submit a plan to the Administrator or delegated authority for approval of how gross energy output will be determined. Your plan shall ensure that you install, calibrate, maintain, and operate meters to continuously determine and record each component of the determination.
(e) If two or more affected stationary combustion turbines serve a common electric generator, you must apportion the combined hourly gross output to the individual stationary combustion turbines using a plan approved by the Administrator (e.g., using steam load or heat input to each affected stationary combustion turbine). Your plan shall ensure that you install, calibrate, maintain, and operate meters to continuously determine and record each component of the determination.
(f) In accordance with § 60.13(g), if two or more stationary combustion turbines that implement the continuous emission monitoring provisions in paragraph (b) of this section share a common exhaust gas stack and are subject to the same emissions standard under § 60.4326, you may monitor the hourly CO
(g) In accordance with § 60.13(g), if the exhaust gases from a stationary combustion turbine that implements the continuous emission monitoring provisions in paragraph (b) of this section are emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you chose to monitor in the ducts), you must monitor the hourly CO
(a) You must calculate the CO
(1) You must only use operating hours in the compliance period for the compliance determination calculation for which you obtained valid data for all
(2) You must calculate the total CO
(3) For each operating hour of the compliance period used in paragraph (a)(2) of this section to calculate the total CO
(i) Calculate P
Where:
(ii) If applicable to your affected stationary combustion turbine, calculate (Pt)
(iii) You must determine the hourly gross energy output for each operating hour in which there is no electric output, but there is mechanical output or useful thermal output. In addition you must determine the hourly gross CO
(iv) In the case for which compliance is demonstrated according to § 60.4373(f) for affected stationary combustion turbines that vent to a common stack, then you must calculate the hourly gross energy output (electric, mechanical, and/or thermal, as applicable) by summing the hourly gross energy output you determined for each of your individual affected stationary combustion turbines that vent to the common stack; and you must express the operating time as “stack operating hours” (as defined in § 72.2 of this chapter).
(4) You must calculate the total gross output for the affected stationary combustion turbine's compliance period by summing the hourly gross output values for the affected stationary combustion turbine determined from paragraph (a)(2) of this section for all of the operating hours in the applicable compliance period.
(5) You must calculate the CO
(b) If the CO
(a)(1) You must prepare and submit the notifications specified in §§ 60.7(a)(1) and (a)(3) and 60.19, as applicable to your affected stationary combustion turbine.
(2) You must prepare and submit notifications specified in § 75.61 of this chapter, as applicable to your affected stationary combustion turbine.
(b) You must prepare and submit reports according to paragraphs (b)(1) through (d) of this section, as applicable.
(1) For stationary combustion turbines that are required, by § 60.4333(c), to conduct initial and on-going compliance determinations on a 12-operating month rolling average basis for the standard in § 60.4326, you must submit electronic quarterly reports as follows. After you
(2) In each quarterly report, you must include the following information, as applicable:
(i) Each rolling average CO
(ii) If one or more compliance periods end in the quarter, you must identify each operating month in the calendar quarter with excess CO
(iii) The percentage of valid CO
(iv) The CO
(3) The final quarterly report of each calendar year must contain the following:
(i) Net electric output sold to an electric grid over the 4 quarters of the calendar year; and
(ii) The potential electric output of the stationary combustion turbine.
(c) You must submit all electronic reports required under paragraph (b) of this section using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool provided by the Clean Air Markets Division in the Office of Atmospheric Programs of the EPA.
(d) You must meet all applicable reporting requirements and submit reports as required under subpart G of part 75 of this chapter.
(a) You must maintain records of the information you used to demonstrate compliance with this subpart as specified in § 60.7(b) and (f).
(b) You must follow the applicable recordkeeping requirements and maintain records as required under subpart F of part 75 of this chapter.
(c) You must keep records of the calculations you performed to determine the total CO
(1) Each operating month (for all affected units);
(2) Each compliance period, including, as applicable, each 12-operating month compliance period.
(d) You must keep records of the applicable data recorded and calculations performed that you used to determine your affected stationary combustion turbine's gross output for each operating month.
(e) You must keep records of the calculations you performed to determine the percentage of valid CO
(f) You must keep records of the calculations you performed to assess compliance with each applicable CO
(g) You must keep records of the calculations you performed to determine any site-specific carbon-based F-factors you used in the emissions calculations (if applicable).
(h)(1) Your records must be in a form suitable and readily available for expeditious review.
(2) You must keep each record for 5 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record to demonstrate compliance with a 12-operating month emissions standard.
(3) You must keep each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to § 60.7. You may keep the records off site and electronically for the remaining year(s) as required by this subpart.
All of your reports required under § 60.7(c) must be postmarked by the 30th day after the end of each 6-month period, except as specified in § 60.4376
(1) The CO
(2) The recorded value of a particular monitored parameter is outside the acceptable range specified in the parameter monitoring plan for the affected unit.
(1) The gross electric or direct mechanical output from both the combustion turbine engine and any associated steam turbine(s) or integrated equipment plus any useful thermal output measured relative to ISO conditions (except for GHG calculations in § 60.4374 as only 75 percent credit is given) that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application).
(2) For a CHP stationary combustion turbine where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross energy output consists of useful thermal output on a rolling 3-year basis, the sum of the gross electric or direct mechanical output from both the combustion turbine engine and any associated steam turbine(s) divided by 0.95 plus any useful thermal output measured relative to ISO conditions (except for GHG calculations in § 60.4374 as only 75 percent credit is given) that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application).
(1) The gross electric sales to the utility power distribution system minus purchased power on a 3 calendar year rolling average basis; or
(2) For combined heat and power facilities where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross energy output consists of useful thermal output on a 3 calendar year rolling average basis, the gross electric sales to the utility power distribution system minus purchased power of the thermal
This subpart establishes emission standards and compliance schedules for the control of greenhouse gas (GHG) emissions from a steam generating unit, IGCC, or a stationary combustion turbine that commences construction after [DATE OF PUBLICATION IN THE
(a) Except as provided for in paragraph (b) of this section, the subpart applies to any steam generating unit, IGCC, or stationary combustion turbine that commences construction after [DATE OF PUBLICATION IN THE
(1) A steam generating unit or IGCC that has a design heat input greater than 73 MW (250MMBtu/h) heat input of fossil fuel (either alone or in combination with any other fuel), combusts fossil fuel for more than 10.0 percent of the average annual heat input during a 3 year rolling average basis, and was constructed for the purpose of supplying, and supplies, one-third or more of its potential electric output and more than 219,000 MWh net-electric output to a utility distribution system on an annual basis.
(2) A stationary combustion turbine that has a design heat input to the turbine engine greater than 73 MW (250 MMBtu/h), combusts fossil fuel for more than 10.0 percent of the average annual heat input during a 3 year rolling average basis, combusts over 90% natural gas on a heat input basis on a 3 year rolling average basis, and was constructed for the purpose of supplying, and supplies, one-third or more of its potential electric output and more than 219,000 MWh net-electrical output to a utility distribution system on a 3 year rolling average basis.
(b) You are not subject to the requirements of this subpart if your affected facility meets any one of the conditions specified in paragraphs (b)(1) through (b)(5) of this section.
(1) The proposed Wolverine EGU project described in Permit to Install No. 317–07 issued by the Michigan Department of Environmental Quality, Air Quality Division, effective June 29, 2011 (as revised July 12, 2011).
(2) The proposed Washington County EGU project described in Air Quality Permit No. 4911–303–0051–P–01–0 issued by the Georgia Department of Natural Resources, Environmental Protection Division, Air Protection Branch, effective April 8, 2010, provided that construction had not commenced for NSPS purposes as of [DATE OF PUBLICATION IN THE
(3) The proposed Holcomb EGU project described in Air Emission Source Construction Permit 0550023 issued by the Kansas Department of Health and Environment, Division of Environment, effective December 16, 2010, provided that construction had not commenced for NSPS purposes as of [DATE OF PUBLICATION IN THE
(4) Your affected facility is a municipal waste combustor unit that is subject to subpart Eb of this part.
(5) Your affected facility is a commercial or industrial solid waste incineration unit that is subject to subpart CCCC of this part.
(a) The greenhouse gas regulated by this subpart is carbon dioxide (CO
(b)
(1) For purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG emissions from affected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 51.166(b)(48) and in any SIP approved by the EPA that is interpreted to incorporate, or specifically incorporates, 40 CFR 51.166(b)(48).
(2) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from affected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 52.21(b)(49).
(3) For purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is “subject to regulation” as defined in 40 CFR 70.2.
(4) For purposes of 40 CFR 71.2, with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is “subject to regulation” as defined in 40 CFR 71.2.
For each affected facility subject to this subpart, you must not discharge from the affected facility stack into the atmosphere any gases that contain CO
(a) You must be in compliance with the emission standards in this subpart that apply to your affected facility at all times. However, you must make a compliance determination only at the end of the applicable operating month, as provided in paragraphs (a)(1) and (2) of this section.
(1) For each affected facility subject to a CO
(2) For each affected facility subject to a CO
(b) At all times you must operate and maintain each affected facility, including associated equipment and monitoring equipment, in a manner consistent with safety and good air pollution control practice. The Administrator will determine if you are using consistent operation and maintenance procedures based on information available to the Administrator that may include, but is not limited to, fuel use records, monitoring results, review of operation and maintenance procedures and
(c) You must conduct an initial compliance determination for your affected facility for the applicable emissions standard in § 60.5520, according to the requirements in this subpart, within 30 days after the end of the initial compliance period for the CO
In response to an action to enforce the standards set forth in § 60.5520, you may assert an affirmative defense to a claim for civil penalties for violations of such standards that are caused by malfunction, as defined at 40 CFR 60.2. Appropriate penalties may be assessed if you fail to meet your burden of proving all of the requirements in the affirmative defense. The affirmative defense shall not be available for claims for injunctive relief.
(a)
(1) The violation:
(i) Was caused by a sudden, infrequent, and unavoidable failure of air pollution control equipment, process equipment, or a process to operate in a normal or usual manner; and
(ii) Could not have been prevented through careful planning, proper design or better operation and maintenance practices;
(iii) Did not stem from any activity or event that could have been foreseen and avoided, or planned for;
(iv) Was not part of a recurring pattern indicative of inadequate design, operation, or maintenance;
(2) Repairs were made as expeditiously as possible when the violation occurred;
(3) The frequency, amount and duration of the violation (including any bypass) were minimized to the maximum extent practicable;
(4) If the violation resulted from a bypass of control equipment or a process, then the bypass was unavoidable to prevent loss of life, personal injury, or severe property damage;
(5) All possible steps were taken to minimize the impact of the violation on ambient air quality, the environment, and human health;
(6) All emissions monitoring and control systems were kept in operation if at all possible, consistent with safety and good air pollution control practices;
(7) All of the actions in response to the violation were documented by properly signed, contemporaneous operating logs;
(8) At all times, the affected source was operated in a manner consistent with good practices for minimizing emissions; and
(9) A written root cause analysis has been prepared, the purpose of which is to determine, correct, and eliminate the primary causes of the malfunction and the violation resulting from the malfunction event at issue. The analysis shall also specify, using best monitoring methods and engineering judgment, the amount of any emissions that were the result of the malfunction.
(b)
(a) You must prepare a monitoring plan in accordance with the applicable provisions in § 75.53(g) and (h) of this chapter.
(b) You must measure the hourly CO
(1) You must install, certify, operate, maintain, and calibrate a CO
(2) For each monitoring system you use to determine the CO
(3) You must use a laser device to measure the dimensions of each exhaust gas stack or duct at the flow monitor and the reference method sampling locations prior to the initial setup (characterization) of the flow monitor. For circular stacks, you must measure the diameter at three or more distinct locations and average the results. For rectangular stacks or ducts, you must measure each dimension (i.e., depth and width) at three or more distinct locations and average the results. If the flow rate monitor or reference method sampling site is relocated, you must repeat these measurements at the new location.
(4) You must use only unadjusted exhaust gas volumetric flow rates to determine the hourly CO
(5) If you choose to use Method 2 in Appendix A–1 to this part to perform the required relative accuracy test audits (RATAs) of the part 75 flow rate monitoring system, you must use a calibrated Type-S pitot tube or pitot tube assembly. You must not use the default Type-S pitot tube coefficient.
(c) If your affected facility exclusively combusts liquid fuel and/or gaseous fuel as an alternative to complying with paragraph (b) of this section, you may determine the hourly CO
(1) You must implement the applicable procedures in appendix D to part 75 of this chapter to determine hourly unit heat input rates (MMBtu/h), based on hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel combusted.
(2) You may determine site-specific carbon-based F-factors (F
(d) You must install, calibrate, maintain, and operate a sufficient number of watt meters to continuously measure and record the gross electric output from the affected facility. If the affected facility is a CHP facility, you must also install, calibrate, maintain, and operate meters to continuously determine and record the total useful recovered thermal energy. For process steam applications, you will need to install, calibrate, maintain, and operate meters to continuously determine and record steam flow rate, temperature, and pressure. If the affected facility has a direct mechanical drive application, you must submit a plan to the Administrator or delegated authority for approval of how gross energy output will be determined. Your plan shall ensure that you install, calibrate, maintain, and operate meters to continuously determine and record each component of the determination.
(e) If two or more affected facilities serve a common electric generator, you must apportion the combined hourly gross output to the individual affected facilities using a plan approved by the Administrator (e.g., using steam load or heat input to each affected EGU). Your plan shall ensure that you install, calibrate, maintain, and operate meters to continuously determine and record each component of the determination.
(f) In accordance with § 60.13(g), if two or more affected facilities that implement the continuous emission monitoring provisions in paragraph (b) of this section share a common exhaust gas stack and are subject to the same emissions standard under § 60.5520, you may monitor the hourly CO
(g) In accordance with § 60.13(g), if the exhaust gases from an affected facility that implements the continuous emission monitoring provisions in paragraph (b) of this section are emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you elect to monitor in the ducts), you must monitor the hourly CO
(a) You must calculate the CO
(1) You can only use operating hours in the compliance period for the compliance determination calculation if valid data are obtained for all parameters you used to determine the hourly CO
(2) You must calculate the total CO
(3) For each operating hour of the compliance period that you used in paragraph (a)(2) of this section to calculate the total CO
(i) Calculate P
(ii) If applicable to your affected facility, you must calculate (Pt)
(4) You must calculate the total gross output for the affected facility's compliance period by summing the hourly gross output values for the affected facility that you determined from paragraph (a)(2) of this section for all of the operating hours in the applicable compliance period.
(5) You must calculate the CO
(b) If the CO
(a) You must prepare and submit the notifications specified in §§ 60.7(a)(1) and (a)(3) and 60.19, as applicable to your affected facility.
(b) You must prepare and submit notifications specified in § 75.61 of this chapter, as applicable to your affected facility.
(a) You must prepare and submit reports according to paragraphs (a) through (d) of this section, as applicable.
(1) For affected facilities that are required by § 60.5525 to conduct initial and on-going compliance determinations on a 12- or 84-operating month rolling average basis for the standard in § 60.5520 you must submit electronic quarterly reports as follows. After you have accumulated the first 12-operating months for the affected facility (or, the first 84-operating months for an affected facility electing to comply with the 84-operating month standard), you must submit a report for the calendar quarter that includes the twelfth (or eighty-fourth) operating month no later than 30 days after the end of that quarter. Thereafter, you must submit a report for each subsequent calendar quarter, no later than 30 days after the end of the quarter.
(2) In each quarterly report you must include the following information, as applicable:
(i) Each rolling average CO
(ii) If one or more compliance periods end in the quarter you must identify each operating month in the calendar quarter with excess CO
(iii) The percentage of valid CO
(iv) The CO
(3) In the final quarterly report of each calendar year, you must include the following:
(i) Gross electric output sold to an electric grid over the 4 quarters of the calendar year; and
(ii) The potential electric output of the facility.
(b) You must submit all electronic reports required under paragraph (a) of this section using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool provided by the Clean Air Markets Division in the Office of Atmospheric Programs of EPA.
(c) You must meet all applicable reporting requirements and submit reports as required under subpart G of part 75 of this chapter.
(d) If your affected unit employs geologic sequestration to meet the applicable emission limit, you must report in accordance with the requirements of 40 CFR part 98, subpart PP and either:
(1) if injection occurs onsite, report in accordance with the requirements of 40 CFR part 98, subpart RR, or
(2) if injection occurs offsite, transfer the captured CO
(a) You must maintain records of the information you used to demonstrate compliance with this subpart as specified in § 60.7(b) and (f).
(b) You must follow the applicable recordkeeping requirements and maintain records as required under subpart F of part 75 of this chapter.
(c) You must keep records of the calculations you performed to determine the total CO
(1) Each operating month (for all affected units);
(2) Each compliance period, including, as applicable, each 12-operating month compliance period and the 84-operating month compliance period.
(d) You must keep records of the applicable data recorded and calculations performed that you used to determine your affected facility's gross output for each operating month.
(e) You must keep records of the calculations you performed to determine the percentage of valid CO
(f) You must keep records of the calculations you performed to assess compliance with each applicable CO
(g) You must keep records of the calculations you performed to determine any site-specific carbon-based F-factors you used in the emissions calculations (if applicable).
(a) Your records must be in a form suitable and readily available for expeditious review.
(b) You must maintain each record for 5 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record except those records required to demonstrate
(c) You must maintain each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to § 60.7. You may maintain the records off site and electronically for the remaining year(s) as required by this subpart.
Notwithstanding any other provision of this chapter, certain parts of the General Provisions in §§ 60.1 through 60.19, listed in Table 2 of this subpart, do not apply to your affected facility.
(a) This subpart can be implemented and enforced by the EPA, or a delegated authority such as your state, local, or tribal agency. If the Administrator has delegated authority to your state, local, or tribal agency, then that agency (as well as the EPA) has the authority to implement and enforce this subpart. You should contact your EPA Regional Office to find out if this subpart is delegated to your state, local, or tribal agency.
(b) In delegating implementation and enforcement authority of this subpart to a state, local, or tribal agency, the Administrator retains the authorities listed in paragraphs (b)(1) through (5) of this section and does not transfer them to the state, local, or tribal agency. In addition, the EPA retains oversight of this subpart and can take enforcement actions, as appropriate.
(1) Approval of alternatives to the emission standards.
(2) Approval of major alternatives to test methods.
(3) Approval of major alternatives to monitoring.
(4) Approval of major alternatives to recordkeeping and reporting.
(5) Performance test and data reduction waivers under § 60.8(b).
As used in this subpart, all terms not defined herein will have the meaning given them in the Clean Air Act and in subpart A (General Provisions of this part).
(1) For stationary combustion turbines and IGCC facilities, the gross electric or direct mechanical output from both the unit (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application).
(2) For electric utility steam generating units, the gross electric or mechanical output from the affected facility (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) minus any electricity used to power the feedwater pumps plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application);
(3) For combined heat and power facilities where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and 20.0 percent of the total gross energy output consists of thermal output on a rolling 3 year basis, the gross electric or mechanical output from the affected facility (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) minus any electricity used to power the feedwater pumps (the electric auxiliary load of boiler feedwater pumps is not applicable to
(1) The gross electric sales to the utility power distribution system minus purchased power on a three calendar year rolling average basis; or
(2) For combined heat and power facilities where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross energy output consists of useful thermal output on a 3 calendar year rolling average basis, the gross electric sales to the utility power distribution system minus purchased power of the thermal host facility or facilities on a three calendar year rolling average basis.
42 U.S.C. 7401,
The revision and additions read as follows:
(4) Greenhouse gases.
(1) Greenhouse gases shall not be subject to regulation unless, as of July 1, 2011, the GHG emissions are at a stationary source emitting or having the potential to emit 100,000 tpy CO
(b) * * *
(2)(i) The Administrator will presume that the fee schedule meets the requirements of paragraph (b)(1) of this section if it would result in the collection and retention of an amount not less than $25 per year [as adjusted pursuant to the criteria set forth in paragraph (b)(2)(iv) of this section] times the total tons of the actual emissions of each regulated pollutant (for presumptive fee calculation) emitted from part 70 sources and any GHG cost adjustment required under paragraph (b)(2)(v) of this section.
(v)
42 U.S.C. 7401,
The revisions and additions read as follows:
(4) Greenhouse gases.
(1) Greenhouse gases shall not be subject to regulation unless, as of July 1, 2011, the GHG emissions are at a stationary source emitting or having the potential to emit 100,000 tpy CO
The revisions and additions read as follows:
(c) * * *
(1) For part 71 programs that are administered by EPA, each part 71 source shall pay an annual fee which is the sum of:
(i) $32 per ton (as adjusted pursuant to the criteria set forth in paragraph (n)(1) of this section) times the total tons of the actual emissions of each regulated pollutant (for fee calculation) emitted from the source, including fugitive emissions; and
(ii) Any GHG fee adjustment required under paragraph (c)(8) of this section.
(2) * * *
(i) Where the EPA has not suspended its part 71 fee collection pursuant to paragraph (c)(2)(ii) of this section, the annual fee for each part 71 source shall be the sum of:
(A) $24 per ton (as adjusted pursuant to the criteria set forth in paragraph (n)(1) of this section) times the total tons of the actual emissions of each regulated pollutant (for fee calculation) emitted from the source, including fugitive emissions; and
(B) Any GHG fee adjustment required under paragraph (c)(8) of this section.
(3) For part 71 programs that are administered by EPA with contractor assistance, the per ton fee shall vary depending on the extent of contractor involvement and the cost to EPA of contractor assistance. The EPA shall establish a per ton fee that is based on the contractor costs for the specific part 71 program that is being administered, using the following formula: Cost per ton = (
Where
Where
(4) For programs that are delegated in part, the fee shall be computed using the following formula: Cost per ton = (
Where
(8)
42 U.S.C. 7401–7671q.
(h) If you capture a CO
(1) Report the facility identification number associated with the annual GHG report for the facility that is subject to subpart D of this part,
(2) Report each facility identification number associated with the annual GHG
(3) Report the annual quantity of CO
(d) Facilities subject to § 98.426(h) must retain records of CO
Securities and Exchange Commission.
Final rule.
The Securities and Exchange Commission (the “Commission”) is adopting amendments that remove references to credit ratings in certain rules and one form under the Securities Exchange Act of 1934 (the “Exchange Act”) relating to broker-dealer financial responsibility and confirmations of securities transactions. This action implements a provision of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”).
The amendments will become effective on July 7, 2014.
Michael A. Macchiaroli, Associate Director, at (202) 551–5525; Thomas K. McGowan, Deputy Associate Director, at (202) 551–5521; Randall W. Roy, Assistant Director, at (202) 551–5522; Mark M. Attar, Branch Chief, at (202) 551–5889; Carrie A. O'Brien, Special Counsel, at (202) 551–5640; and Rachel B. Yura, Attorney, at (202) 551–5729, Office of Financial Responsibility (Net Capital, Customer Protection, and Books and Records Requirements); and Joseph M. Furey, Assistant Chief Counsel; and Brice D. Prince, Special Counsel, Office of the Chief Counsel, at (202) 551–5550 (Confirmations of Securities Transactions); Division of Trading and Markets, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549–7010.
The Commission is adopting amendments to Rules 10b–10,
On July 21, 2010, the President signed the Dodd-Frank Act into law.
Prior to and after enactment of the Dodd-Frank Act, the Commission has taken a number of steps toward removing references to credit ratings from its regulations under the federal securities laws.
A number of other federal agencies have also taken action to implement section 939A of the Dodd-Frank Act, including regulations proposed or adopted by the Commodity Futures Trading Commission,
The following discussion summarizes the Commission's proposals with respect to the broker-dealer financial responsibility and confirmations of transaction rules, the comments received by the Commission in response to each of the proposals, and the amendments the Commission is adopting today.
In 1975, the Commission adopted the term
In computing net capital, a broker-dealer must, among other things, make certain adjustments to net worth, including deducting illiquid assets, taking other net capital charges, and adding qualifying subordinated loans.
Rule 15c3–1 prescribes differing haircut amounts for a variety of classes of securities.
Prior to today's amendments, commercial paper, nonconvertible debt, and preferred stock rated in higher rating categories by at least two NRSROs were included in the classes of securities that had lower haircuts than securities subject to the catchall provisions.
The Commission proposed to remove references to credit ratings in the provisions of Rule 15c3–1 establishing lower haircuts for higher rated commercial paper, nonconvertible debt, and preferred stock and to substitute an alternative standard of creditworthiness as a condition for qualifying for the lower haircut treatment.
In the proposing release, the Commission identified the following factors a broker-dealer could consider, to the extent appropriate, when assessing credit risk for purposes of determining whether an issuance of commercial paper, nonconvertible debt, or preferred stock was of minimal credit risk: (1) Credit spreads; (2) securities-related research; (3) internal or external credit risk assessments; (4) default statistics; (5) inclusion in an index; (6) priorities and enhancements; (7) price, yield and/or volume; and (8) asset class-specific factors.
In addition, each broker-dealer would have been required to preserve for a period of not less than three years (the first two years in an easily accessible place) the written policies and procedures that the broker-dealer established, maintained, and enforced for assessing credit risk for commercial paper, nonconvertible debt, and preferred stock.
Five commenters responded to the Commission's request for comment on the amendments to Rule 15c3–1.
Among commenters raising concerns about the Commission replacing credit ratings with a more subjective approach for determining haircuts, one commenter stated that the proposal contains an inherent conflict of interest, is complicated, and would disproportionately burden smaller
The second commenter expressed concern that Commission and self-regulatory organization (“SRO”) examiners would “second guess” a broker-dealer's policies and procedures and analysis under the new standard and that examiners should, instead, focus on the reasonableness of the policies and procedures.
Regarding the Commission's proposed list of factors that broker-dealers could consider when assessing creditworthiness under the minimal amount of credit risk standard, one commenter recommended that the Commission require broker-dealers to consider certain mandatory factors and suggested they be codified in the final rule.
One commenter requested that “term to maturity” and “concentration of credit risk” be included as factors that a broker-dealer could consider in assessing whether a position is of minimal credit risk.
One commenter suggested that a broker-dealer be allowed to rely on a parent's or an affiliate's credit determination.
Commenters generally supported the Commission's proposal that broker-dealers document their policies and procedures for determining creditworthiness under the minimal amount of credit risk standard.
The Commission is amending Rule 15c3–1 to remove references to NRSRO credit ratings in the provisions establishing lower haircuts for commercial paper, nonconvertible debt, and preferred stock. The Commission is adopting amendments to these provisions with modifications from the proposal, discussed below, to address issues raised by commenters.
Under the final amendments and consistent with the proposal, when a broker-dealer applies haircuts for commercial paper, nonconvertible debt, and preferred stock that have a ready market for purposes of its net capital computation, it will have the option of: (1) Using the firm's own written policies and procedures to determine whether the security has only a minimal amount credit risk and, if so, applying the appropriate lower haircut if it meets the other conditions prescribed in Rule 15c3–1; or (2) applying the greater deduction applicable to the position, such as the 15% haircut under the catchall provision in paragraph (c)(2)(vi)(J) of Rule 15c3–1.
Unlike the objective approach of using NRSRO credit ratings, the minimal amount of credit risk standard is a subjective approach because it allows broker-dealers in the first instance to determine through their credit assessments whether a lower haircut is applicable to a given position. Further, whereas the rule prior to today's amendments required that commercial paper, nonconvertible debt, and preferred stock be given high credit ratings by an NRSRO before a reduced haircut is permitted, the minimal amount of credit risk standard provides flexibility to broker-dealers by allowing them to rely on a variety of factors, both objective and subjective, in assessing the credit and liquidity risks associated with their proprietary commercial paper, nonconvertible debt, and preferred stock positions. However, the Commission does not intend for the new standard to result in a more liberal requirement that broadens the scope of
The Commission is amending paragraph (c)(2)(vi)(E) of Rule 15c3–1 (relating to commercial paper haircuts), paragraphs (c)(2)(vi)(F)(
The Commission has made several modifications to its proposed rule text. First, the Commission has re-structured the rule by adding new paragraph (c)(2)(vi)(I) to specify requirements for the policies and procedures a broker-dealer must establish, document, maintain, and enforce for purposes of assessing whether a position has only a minimal amount credit risk under paragraphs (c)(2)(vi)(E), (c)(2)(vi)(F)(
Under the final rule, new paragraph (c)(2)(vi)(I) of Rule 15c3–1 provides that in order to apply a deduction under paragraphs (c)(2)(vi)(E), (c)(2)(vi)(F)(
In the proposing release, the Commission requested comment on how often a broker-dealer should be required to update its assessments.
The Commission also modified the proposed rule text relating to policies and procedures by including in new paragraph (c)(2)(vi)(I) of Rule 15c3–1 the qualifier that the policies and procedures must be “reasonably designed” for the purpose of assessing creditworthiness.
However, the Commission also modified the final rule to add new text that provides that policies and procedures that are reasonably designed “should result in assessments of creditworthiness that typically are consistent with market data.”
Notwithstanding the reasonableness of a broker-dealer's policies and procedures, examiners may still question a broker-dealer's credit risk determination, and are particularly likely to question a determination related to large concentrated positions or that is not consistent with market data. In addition, if a broker-dealer incorrectly determines pursuant to paragraph (c)(2)(vi)(I) of Rule 15c3–1 that a security has only a minimal amount of credit risk, the broker-dealer could be in violation of Rule 15c3–1 to the extent the appropriate larger haircut would put the broker-dealer below the required minimum amount of net capital.
When assessing whether a security or money market instrument has only a minimal amount of credit risk for purposes of Rule 15c3–1, a broker-dealer could consider pursuant to the policies and procedures it establishes, documents, maintains, and enforces the following factors, to the extent appropriate:
• Credit spreads (
• Securities-related research (
• Internal or external credit risk assessments (
• Default statistics (
• Inclusion in an index (
• Enhancements and priorities (
• Price, yield and/or volume (
• Asset class-specific factors (
The Commission does not intend this list of factors to be exhaustive or mutually exclusive. For example, other factors may be appropriate for assessing creditworthiness and, in particular, whether a position has only a minimal amount of credit risk.
As noted above, several commenters identified additional factors that they believe would be appropriate for purposes of assessing whether a security or money market instrument has only a minimal amount of credit risk and one commenter suggested making certain factors mandatory.
Under the amendments, a broker-dealer must apply a higher deduction, such as the 15% “catchall” haircut, on a proprietary position in commercial paper, nonconvertible debt, and preferred stock if the firm determines the security has more than a minimal amount of credit risk or the firm opts not to have policies and procedures to assess the creditworthiness of the class of security or money market instrument.
Under today's amendments, and consistent with the proposed amendments, a broker-dealer must preserve for a period of not less than three years, the first two years in an easily accessible place, the policies and procedures that the broker-dealer establishes, documents, maintains, and enforces for assessing and monitoring the credit risk of commercial paper, nonconvertible debt, and preferred stock. This requirement is codified in new paragraph (b)(13) of Rule 17a–4.
The amendments do not require a broker-dealer to maintain a record of each of its credit risk determinations for purposes of Rule 15c3–1.
The Commission recognizes that requiring a broker-dealer to make and maintain a record of each credit risk determination, as suggested by one commenter,
The Commission is cognizant of the potential conflict of interest inherent in a requirement that relies to some extent on the subjective judgment of the broker-dealer to determine whether a lower haircut should apply to a commercial paper, nonconvertible debt, or preferred stock position, as noted by some commenters.
The Commission also is aware of the likelihood that broker-dealers may reach different conclusions when assessing whether a particular position has only a minimal amount of credit risk,
The Commission understands, as noted by commenters, that the amount of resources broker-dealers can allocate toward making assessments of creditworthiness for purposes of Rule 15c3–1 will differ across broker-dealers and expects that this difference will be reflected in the policies and procedures for assessing creditworthiness established by the firms.
Finally, as discussed above, a broker-dealer (rather than its parent or an affiliate) must establish, document, maintain, and enforce the policies and procedures for assessing whether a position has only a minimal amount of credit risk.
Appendix A to Rule 15c3–1 permits broker-dealers to employ a standardized theoretical option pricing model to determine a potential loss for a portfolio of listed options positions and related positions to compute a single haircut for the group of positions.
Prior to today's amendments, the rule defined the term
With respect to the definition of
The Commission received two comment letters in response to its request for comment.
For the reasons described below, the Commission is adopting the amendments to Appendix A as proposed.
In order to retain a degree of flexibility, the Commission is not codifying in the rule a list of currencies that meet the definition of
Certain broker-dealers (“ANC broker-dealers”) are approved by the Commission to use internal value-at-risk (“VaR”) models to determine market risk charges for proprietary securities and derivatives positions and to take a credit risk charge in lieu of a 100% charge for unsecured receivables related to OTC derivatives transactions.
Under Appendix E, the credit risk charge is the sum of three calculated amounts: (1) A counterparty exposure charge; (2) a concentration charge if the current exposure to a single counterparty exceeds certain thresholds; and (3) a portfolio concentration charge if aggregate current exposure to all counterparties exceeds certain thresholds.
The Commission proposed removing paragraphs (c)(4)(vi)(A) through (c)(4)(vi)(D) of Appendix E, which specify the appropriate risk weight factor of counterparties based on NRSRO credit ratings.
The Commission received two comments in response to its request for comment.
Another commenter suggested that the factors listed in the proposing release with respect to determining creditworthiness under Rule 15c3–1 should become part of Appendix E.
The Commission is adopting the amendments to Appendix E to Rule 15c3–1 as proposed.
All ANC broker-dealers calculate credit risk charges using internal credit ratings (rather than using NRSRO credit ratings approach) or take a 100% capital charge with respect to the exposure to the counterparty risk.
In taking this action, the Commission has considered the views of commenters
In addition, as stated throughout this release, the Commission has determined not to mandate that a broker-dealer use any specific factor in its credit analysis. Consequently, the Commission does not believe it would be appropriate to codify the list of factors in the rule as suggested by one commenter.
Similar to ANC broker-dealers, a type of limited purpose broker-dealer that deals solely in OTC derivatives (an “OTC derivatives dealer”) is permitted, with Commission approval, to calculate net capital using internal models as the basis for taking market risk and credit risk charges in lieu of the standardized haircuts for classes of positions for which they have been approved to use VaR models.
Under Appendix F to Rule 15c3–1, OTC derivatives dealers are required to deduct from their net capital credit risk charges that take counterparty risk into consideration.
The second part of the credit risk charge consists of a concentration charge that applies when the net replacement value in the account of any one counterparty exceeds 25% of the OTC derivatives dealer's tentative net capital.
The Commission proposed to amend paragraphs (d)(2), (d)(3)(i), (d)(3)(ii), (d)(3)(iii), and (d)(4) of Appendix F to Rule 15c3–1, which permit the use of NRSRO ratings (as an alternative to internal credit ratings) to determine an OTC derivatives dealer's counterparty factors and concentration charges. Because the proposal would eliminate the option to use NRSRO credit ratings, a broker-dealer that applies to become an OTC derivatives dealer and operate under Appendix F will need, as part of its initial application, to request Commission approval to use internal credit ratings (as the option to use NRSRO credit ratings is being eliminated). The OTC derivatives dealer would need to describe how it will determine the applicable counterparty factors and concentration charges as part of its initial application to the Commission.
As part of its proposal, the Commission also proposed conforming amendments to the General Instructions to Form X–17A–5, Part IIB. This form constitutes the basic financial and operational report OTC derivatives dealers are required to file with the Commission. Under the heading “Computation of Net Capital and Required Net Capital,” the Commission proposed making conforming changes to the section “Credit risk exposure.” This section instructs an OTC derivatives dealer on how to compute the counterparty credit risk charges for purposes of the dealer's net capital computation. The proposed amendments to the instructions would eliminate references to NRSRO credit ratings for purposes of determining these charges.
The Commission received two comments in response to its request for comment.
The second commenter suggested that the Commission “supply an appropriate alternative standard of creditworthiness that derivatives dealers must apply” such as “an explicit set of factors that will appropriately gauge the credit risk associated with counterparties in derivatives transactions.”
The Commission is adopting the amendments to Appendix F to Rule 15c3–1 as proposed.
The Commission also is adopting the conforming amendments to the General Instructions to Form X–17A–5, Part IIB as proposed.
Consistent with the discussion above relating to Appendix E to Rule 15c3–1, the Commission has determined that whether a model adequately considers concentration risk with a specific counterparty is a concern that is best addressed during the initial review of, or an amendment to, an OTC derivatives dealer's model as well as during the monitoring and examination of the OTC derivatives dealer.
The Commission is not adopting an alternative standard in the rule, such as the minimal amount of credit risk standard. As discussed above, the minimal amount of credit risk standard is replacing a binary NRSRO credit rating standard under which the application of a lower or higher haircut amount depends on whether the commercial paper is rated in the top three rating categories and the nonconvertible debt and preferred stock is rated in the top four rating categories. Consequently, a given instrument either meets the requirement to apply a lower haircut amount or is subject to the higher amount. The NRSRO credit rating standard in Appendix F to Rule 15c3–1 is not binary in that there are three ranges of credit ratings to determine the applicable risk weight factors and concentration charges: The two highest rating categories; the third and fourth highest rating categories; and below the fourth highest rating category. Thus, the minimal amount of credit risk standard would not be a suitable replacement for the credit risk charges required under Appendix F to Rule 15c3–1 because the minimal amount of credit risk standard, as drafted for Rule 15c3–1, would apply only to the second
In addition, as stated throughout this release, the Commission has determined not to mandate that a broker-dealer use any specific factor in its credit analysis; instead, each firm will need to tailor its procedures for determining credit risk to the broker-dealer's business model.
Appendix G to Rule 15c3–1 provides that broker-dealers may use the ANC computation only if their ultimate holding companies agree to provide the Commission with additional information about the financial condition of the holding company and its affiliates.
The Commission received no comments addressing these changes.
Rule 15c3–3 (the “Customer Protection Rule”) under the Exchange Act is designed to protect customer funds and securities held by broker-dealers.
The first step to safeguard customer assets under Rule 15c3–3 requires a carrying broker-dealer to maintain possession or control of all fully paid and excess margin securities of its customers.
The second step covers customer funds and requires that a carrying broker-dealer must maintain a reserve of cash or qualified securities in one or more accounts at a bank that is at least equal in value to the net cash owed to customers and the amount of cash obtained from the use of customer securities.
Under Note G to Exhibit A, a carrying broker-dealer may include margin collateral for transactions in security futures products as a debit in its reserve formula computation if that margin collateral is required and on deposit at a clearing agency or derivatives clearing organization that meets at least one of four conditions: (1) The clearing agency or derivatives clearing organization maintains the highest investment-grade rating from an NRSRO; (2) the clearing agency or derivatives clearing organization maintains security deposits from clearing members in connection with regulated options or futures transactions and assessment power over member firms that equal a combined total of at least $2 billion, at least $500 million of which must be in the form of security deposits; (3) the clearing agency or derivatives clearing organization maintains at least $3 billion in margin deposits; or (4) the clearing agency or derivatives clearing organization obtains an exemption from the Commission.
Margin collateral that is posted for customer positions in security futures products constitutes an unsecured receivable from the clearing agency or derivatives clearing organization. Therefore, requiring a clearing agency or a derivatives clearing organization to meet certain minimum creditworthiness criteria before margin collateral deposited with that entity may be included as a debit in a broker-dealer's customer reserve formula is consistent with the customer protection function of Rule 15c3–3 because the debit offsets any credits when computing the customer reserve deposit requirement.
The Commission proposed to remove the first criterion described above (
The Commission received no comments on the proposed amendment to Rule 15c3–3. The Commission is adopting the amendment to Note G to Exhibit A to Rule 15c3–3 as proposed by removing paragraph (b)(1)(i).
Rule 10b–10 under the Exchange Act, the Commission's customer confirmation rule, generally requires broker-dealers effecting transactions for customers in securities, other than U.S. savings bonds or municipal securities, to provide those customers with a written notification, at or before completion of the securities transaction, disclosing certain information about the terms of the transaction.
The Commission proposed to delete paragraph (a)(8) from Rule 10b–10.
The Commission had previously proposed, and re-proposed, the deletion of paragraph (a)(8) from Rule 10b–10.
The Commission received four comments regarding the proposed removal of paragraph (a)(8) from Rule 10b–10. One commenter was supportive of the deletion, without providing any additional comment.
After careful consideration of the received comments, the Commission has decided to delete paragraph (a)(8) from Rule 10b–10, as proposed. The Commission acknowledges that, to some extent, the paragraph may have served the purpose for which it was added to the rule in 1994 by prompting investors to investigate or question a broker-dealer about the quality of certain securities. Based on the comments received in response to the proposing release, however, the Commission believes it is likely that the paragraph's disclosure requirement has to a greater extent added to investors' undue reliance on credit ratings, and that the deletion of the paragraph is consistent with the intent of section 939A of the Dodd-Frank Act to reduce reliance on NRSRO credit ratings. In addition, requiring broker-dealers to use customer confirmations as a means of providing investors with general information related to credit risk and debt securities as suggested by commenters would not further paragraph (a)(8)'s purpose of flagging unrated securities for more careful investor scrutiny. The paragraph was added to the rule to require disclosure of information suggesting that investors may want to obtain more information about certain unrated securities, not to “require that confirmations alert customers to the importance of understanding the credit quality of a debt security and the impact of credit quality on the value, resale, and price of such securities.”
The Commission further notes, as it did in the proposing release, that after the deletion of paragraph (a)(8), broker-dealers will not be prohibited from continuing to provide the information currently required by paragraph (a)(8) on a voluntary basis.
After consideration of the comments received, the Commission is removing paragraph (a)(8) and believes that it is unnecessary to replace the paragraph with any other disclosure requirement. Although the Commission recognizes the potential benefit of requiring broker-dealers to remind investors of the varying creditworthiness of debt securities, the Commission believes that such a requirement would be unnecessary given the other security-specific disclosures currently required by Rule 10b–10.
Certain provisions of the amendments to the rules and form contain “collection of information requirements” within the meaning of the Paperwork Reduction Act of 1995 (“PRA”).
As discussed above, the Commission received eleven comment letters on the proposed amendments. Some of the comments in these letters relate indirectly to the PRA and are addressed below. The estimates contained in this section do not include any other possible costs or economic effects beyond the costs required for PRA purposes.
As discussed above, the Commission is adopting amendments to Rule 15c3–1, Appendices A, E, F, and G to Rule 15c3–1, Exhibit A to Rule 15c3–3, Rule 17a–4, the General Instructions to Form X–17A–5, Part IIB, and Rule 10b–10. These amendments are consistent with section 939A of the Dodd-Frank Act.
The amendments to Rule 15c3–1, and Rule 17a–4 establish a new standard of creditworthiness that will allow broker-dealers to establish their own policies and procedures to determine whether a security has only a minimal amount of credit risk. If a broker-dealer chooses to establish these policies and procedures, it would create a new “collection of information” burden for those broker-dealers, as explained below. The amendments to Appendices A, E, F, and G to Rule 15c3–1 and the General Instructions to Form X–17A–5, Part IIB remove provisions permitting reliance
The Commission does not believe that the amendment to Rule 10b–10, which eliminates a requirement that broker-dealers inform customers in transaction confirmations for debt securities (other than government securities) if a security is unrated by an NRSRO, would change the existing paperwork burden for Rule 10b–10.
The written policies and procedures required by the amendments to Rule 15c3–1, and the retention of these policies and procedures required by the amendment to Rule 17a–4, will assist Commission and SRO examination staff in evaluating whether the broker-dealer has a reasonable basis for determining if a security has only a minimal amount of credit risk. It also will assist examination staff and the broker-dealer in evaluating whether the broker-dealer has followed those policies and procedures when acquiring positions in commercial paper, nonconvertible debt, and preferred stock. In addition, written policies and procedures will provide a broker-dealer's personnel with consistent guidance on how to determine if a security has a minimal amount of credit risk for the purposes of complying with Rule 15c3–1.
The amendment to Rule 10b–10 will eliminate a requirement for transaction confirmations for debt securities (other than government securities) to inform customers if a security is unrated by an NRSRO. This amendment will alter neither the general requirement that broker-dealers generate transaction confirmations and send those confirmations to customers, nor the potential use of information contained in confirmations by the Commission, SROs, and other securities regulatory authorities in the course of examinations, investigations and enforcement proceedings.
The Commission estimates that the collections of information would apply to the number of respondents as indicated in the following table.
The amendments to Rule 15c3–1 and Rule 17a–4 modify broker-dealers' existing practices to impose additional voluntary recordkeeping burdens. The amendments to Rule 15c3–1 replace NRSRO ratings-based criteria for evaluating creditworthiness with an option for a broker-dealer to apply a new standard based on the broker-dealer's own evaluation of creditworthiness. A broker-dealer that chooses not to make such an evaluation could instead take the higher haircuts as specified in Rule 15c3–1. A broker-dealer that chooses to evaluate the creditworthiness of securities will have to establish, document, maintain, and enforce policies and procedures that are reasonably designed to determine whether a security has a minimal amount of credit risk. Broker-dealers will be required to develop (if they have not already) criteria for assessing creditworthiness and apply those criteria to commercial paper, nonconvertible debt, and preferred stock included in their net capital calculations.
The Commission requested comment on the PRA burden associated with its proposed amendments to Rule 15c3–1 and Rule 17a–4. Two commenters discussed costs, although the comments did not explicitly address the PRA.
According to data collected by the Commission, of the approximately 4,462 broker-dealers registered with the Commission as of year-end 2012, approximately 434 broker-dealers maintained proprietary positions in debt securities and took haircuts on these securities pursuant to paragraphs (c)(2)(vi)(E), (c)(2)(vi)(F)(
The Commission also estimated in the proposing release that, on average, each broker-dealer will spend an additional 10 hours a year reviewing and adjusting its own standards for evaluating creditworthiness for purposes of the amendments to Rule 15c3–1.
The Commission received no comments on the estimated burdens associated with the record retention requirements arising from the proposed amendments to Rule 17a–4. The Commission continues to believe that the requirement to retain the policies and procedures for three years pursuant to Rule 17a–4 would result in de minimis incremental costs beyond those already incurred under Rule 17a–4. The three-year preservation requirement in Rule 17a–4 will only be applicable once a broker-dealer changes its policies and procedures as the operative policies and procedures must be documented and maintained under the amendments to Rule 15c3–1. In addition, all broker-dealers are currently required to comply with the three-year preservation period in Rule 17a–4 for other records and should have procedures in place to satisfy such preservation requirements.
The amendments to the appendices to Rule 15c3–1 include amendments to certain recordkeeping and disclosure requirements that are subject to the PRA. The amendment to Appendix A to Rule 15c3–1 removes the NRSRO reference from the definition of the term
The amendments to Appendices E and F to Rule 15c3–1 and conforming amendments to Appendix G would remove the provisions permitting reliance on NRSRO ratings for the purposes of determining counterparty risk. As a result of these deletions, an entity that wishes to use the approach set forth in these appendices to determine counterparty risks would need, as part of its initial application to use the alternative approach or in an amendment, to request Commission
The Commission does not believe that the removal of the option permitting reliance on NRSRO ratings would affect the small number of entities that currently elect to compute their net capital deductions pursuant to the alternative methods set forth in Appendices E or F. Although the collections of information obligations imposed by the amendments are mandatory, applying for approval to use the alternative capital calculation is voluntary.
The staff estimates that three additional firms may apply for permission to use Appendix E and one additional firm may apply to use Appendix F. However, the Commission believes, and commenters did not contest, that there should be no additional paperwork burden on these firms based on the amendments. Any firm that applies to use Appendices E or F to Rule 15c3–1 must submit its internal models to the Commission for approval as part of that process. These models will calculate market risk and credit risk, including the counterparty charge, which is not a change from the previous approval process for a firm that is applying to use Appendix E or Appendix F. Thus, the Commission does not believe the amendments to Appendices E and F will alter the existing paperwork burden estimates for these collections.
The instructions to Form X–17A–5, Part IIB currently include a summary of the credit risk calculation in paragraph (d) of Rule 15c3–1f. Paragraph (d) of Rule 15c3–1f is amended to remove that part of the credit risk calculation that is summarized in Form X–17A–5, Part IIB. Accordingly, the Commission is adopting a conforming amendment to the form that would remove the summary of the credit risk calculation. The Commission received no comments on its estimate in the proposing release that there would be no change in the burden for the collection of information related to the instructions to Form X–17A–5, Part IIB in the proposing release. The summary in the instructions provides additional information for the benefit of the filer and is not related to the information reported on the forms. Accordingly, the Commission does not believe the amendment would result in a substantive revision to these collections of information.
The amendment to Note G to Exhibit A to Rule 15c3–3 imposes additional recordkeeping burdens on certain broker-dealers that are mandatory. Note G allows a broker-dealer to include, as a debit in its customer reserve formula, the amount of customer margin related to customer positions in security futures products posted to a registered clearing or derivatives clearing organization that meets certain minimum standards that are indicia of long-term financial strength. Prior to this amendment, clearing organizations that maintained the highest investment grade rating from an NRSRO qualified under Note G.
The Commission estimated in the proposing release that firms would spend one hour changing their methods of determining whether a clearing or derivatives clearing organization meets the remaining four requirements of Note G. The Commission received no comments on this estimate and believes it is still accurate. The result is an aggregate, one-time initial burden of 72 hours.
In the proposing release, the Commission stated that the proposed amendment to Rule 10b–10 was not expected to result in any significant change to the cost of providing confirmations to customers in connection with those transactions covered by paragraph (a)(8) of the rule.
The Commission is sensitive to the costs and benefits of its rules. When engaging in rulemaking that requires the Commission to consider or determine whether an action is necessary or appropriate in the public interest, section 3(f) of the Exchange Act requires that the Commission consider, in addition to the protection of investors, whether the action will promote efficiency, competition, and capital formation.
In the proposing release, the Commission solicited comment on the costs and benefits of the proposed amendments, including whether estimates of the costs and benefits were accurate and comprehensive.
The Commission received two comment letters addressing the Commission's estimates of the costs associated with the proposed amendments.
As discussed above, the amendments to Rule 15c3–1, Appendices A, E, F, and G to Rule 15c3–1, Exhibit A to Rule 15c3–3, Rule 17a–4, the General Instructions to Form X–17A–5, Part IIB, and Rule 10b–10 implement section 939A of the Dodd-Frank Act by eliminating the reference to and requirement for the use of NRSRO ratings in these rules. The Commission recognizes that there are additional costs associated with adopting the amendments that are separate from the costs associated with the hour and cost burdens discussed in the PRA. The discussion below focuses on the Commission's reasons for adopting these amendments, the affected parties, the impact on efficiency, competition, and capital formation, and the costs and benefits of the amendments as compared to the baseline, described below, and to alternative courses of action.
The regulatory changes adopted today amend requirements that apply to broker-dealers registered with the Commission. However, security issuers, NRSROs, non-NRSRO credit rating agencies, and other providers of credit risk analysis as well as a broker-dealer's customers and counterparties could all be affected by the amendments. The discussion below characterizes the economic baseline against which the costs and benefits, as well as the impact on efficiency, competition, and capital formation, of today's amendments are measured. It includes the approximate numbers of broker-dealers that would be directly affected by today's amendments and a description of the relevant features of the economic and regulatory environment in which the various impacted parties operate. The economic baseline being used for this analysis is the economic and regulatory framework
The regulations that are affected by today's amendments include Rule 15c3–1, which provided prior to today's amendments, among other things, that a broker-dealer could apply a lesser capital charge (
The broker-dealers registered with the Commission vary significantly in terms of their size, business activities, and the complexity of their operations. For example, carrying broker-dealers hold customer securities and funds.
A broker-dealer that claims an exemption from Rule 15c3–3 is generally referred to as “non-carrying broker-dealer.” Non-carrying broker-dealers include “introducing brokers.”
The broker-dealer industry is the primary industry affected by the rule amendments, although the amendments impose different requirements on different types of broker-dealers. For example, only those broker-dealers that hold proprietary positions in commercial paper, nonconvertible debt, and preferred stock will be affected by the amendments to Rules 15c3–1 and 17a–4, only those broker-dealers that trade in foreign currency options will be affected by the amendments to Appendix A to Rule 15c3–1, and only those broker-dealers that clear and carry positions in security futures products for customers will be affected by the amendment to Exhibit A to Rule 15c3–3. The amendments to Appendices E and F to Rule 15c3–1 and the conforming amendments to Appendix G to Rule 15c3–1 and the General Instructions to Form X–17A–5, Part IIB will affect only ANC broker-dealers and OTC derivatives dealers. The amendment to Rule 10b–10 eliminates a disclosure requirement for broker-dealers that currently produce transaction confirmations for debt securities other than government securities.
To establish a baseline for competition among broker-dealers, the Commission looks at the status of the broker-dealer industry detailed below. In terms of size, the following tables illustrate the variance among broker-dealers with respect to total capital. The information in the tables is based on FOCUS Report data for calendar year 2012.
According to FOCUS Report data, as of December 31, 2012, there were approximately 4,462 broker-dealers registered with the Commission. Nine broker-dealers account for more than half of all capital held by broker-dealers. Of the 4,462 registered broker-dealers, 434 firms reported holding proprietary debt positions on their FOCUS Reports.
The Commission also believes other parties could be affected by today's amendments. Under the economic baseline, issuers of securities who obtain favorable ratings from two or more NRSROs enjoy the benefit of greater access to the capital markets because such securities are—holding other things constant—more attractive to broker-dealers who can take lower haircuts on such securities for the purposes of compliance with Rule 15c3–1. While the Commission does not intend the amendments to Rule 15c3–1 to alter the scope of securities and money market instruments that qualify for the lower haircuts, eliminating preferential regulatory treatment of NRSRO-rated securities could affect security issuers by altering the portfolio preferences of broker-dealers if, for example, broker-dealers establish policies and procedures for assessing creditworthiness that produce more conservative results than the NRSRO credit rating standard. These conservative results could cause broker-dealers to avoid holding positions that they would have held under the NRSRO credit rating standard. Alternatively, if the policies and procedures produce less conservative results, the amendments could alter the risk of broker-dealers' portfolios by causing them to hold positions that they would not have held when applying the NRSRO credit rating standard. Altering the risk of broker-dealers' portfolios could affect broker-dealers' customers, counterparties, and investors, all of whom are protected by Rule 15c3–1.
Finally, today's amendments could have a significant effect on the credit ratings industry. Currently there are ten NRSROs with the three largest accounting for the majority of all credit ratings.
As discussed above, Rule 15c3–1 prescribes minimum regulatory capital requirements for broker-dealers.
Appendix A to Rule 15c3–1 permits broker-dealers to employ a standardized theoretical option pricing model to determine a potential loss for a portfolio of listed options positions and related positions to compute a single haircut for the group of positions.
Under Appendix E to Rule 15c3–1, ANC broker-dealers are permitted to add back to net worth uncollateralized receivables from counterparties arising from OTC derivatives transactions (
Under Appendix F to Rule 15c3–1, OTC derivatives dealers are required to deduct from their net capital credit risk charges that take counterparty risk into consideration.
Appendix G to Rule 15c3–1 provides that broker-dealers may use the ANC computation only if their ultimate holding companies agree to provide the Commission with additional information about the financial condition of the holding company and its affiliates.
Rule 15c3–3 is designed to protect customer funds and securities held by broker-dealers.
Exhibit A to Rule 15c3–3 prescribes the formula that a broker-dealer must use to determine its reserve requirement. Under the economic baseline, Note G to Exhibit A provided that a broker-dealer could include margin required for customer transactions in security futures products as a debit in its reserve formula computation if that margin is on deposit
Rule 10b–10, the Commission's customer confirmation rule, generally requires broker-dealers effecting transactions for customers in securities, other than U.S. savings bonds or municipal securities, to provide those customers with a written notification, at or before completion of the securities transaction, disclosing certain information about the terms of the transaction.
The amendments adopted today have the potential to affect competition, efficiency, and capital formation. This section discusses what the Commission believes to be potential effects across three groups of market participants: (1) Broker-dealers, (2) security issuers, and (3) issuers of credit ratings.
Under the economic baseline, all broker-dealers employ a uniform standard—an NRSRO credit rating—to determine whether a position in commercial paper, nonconvertible debt, or preferred stock is entitled to a lower haircut for purposes of Rule 15c3–1. Today's amendments eliminate this uniform standard and require that broker-dealers develop internal policies and procedures for determining whether these types of positions have only a minimal amount of credit risk and, therefore, are entitled to the lower haircut. As one commenter noted, “the cost and complexity of developing a credit evaluation infrastructure covering many issuers and securities may be beyond the means of many broker-dealers.”
However, the Commission does not intend or expect broker-dealers to individually duplicate the function of credit rating agencies. To do so would require broker-dealers, particularly small and medium sized broker-dealers, to incur significant expense, potentially reducing competition in the broker-dealer industry and harming economic efficiency through duplication of effort.
Based on these considerations, the Commission does not believe that the burden of complying with today's amendments will result in significant changes to the competitive structure of the broker-dealer industry in general, nor to the small subset of broker-dealers with positions in commercial paper, nonconvertible debt, and preferred stock that are directly affected by today's amendments.
In addition to the aforementioned potential direct effects on efficiency and competition, today's amendments may affect economic efficiency indirectly by altering the net capital levels in the broker-dealer industry. A broker-dealer that elects to take a higher haircut rather than make a credit risk determination or one that overestimates the credit risk in its position will reserve more net capital than is required by Rule 15c3–1. This could affect the broker-dealer's ability to hold (or add to) its positions. Conversely, some broker-dealers may underestimate the credit risk of their positions. Indeed, broker-dealers have an incentive to underestimate credit risk in order to apply the lower capital charge. Such a determination could have a potential impact on the firm's ability, if it experiences financial difficulties, to be in a position to meet its obligations to customers, investors, and other counterparties and generate resources to wind-down its operations in an orderly manner without the need of a formal liquidation proceeding, with attendant costs. Increasing discretion in assessing creditworthiness for purposes of Rule 15c3–1 can facilitate such underestimation of credit risk. The Commission believes that this represents a significant risk in today's amendments. Broker-dealers whose internal evaluations typically are inconsistent with market data likely will
Today's amendments could impact capital formation by altering the set of securities that qualify for preferential treatment under Rule 15c3–1. Under the economic baseline, issuers of commercial paper, nonconvertible debt securities, and preferred stock who obtain favorable ratings from two or more NRSROs benefit from having lower haircuts apply to their issuances. Consequently, these issuers may have greater access to the capital markets, while issuers without such a rating may have more limited access. The regulatory preference for NRSRO-rated securities also benefits issuers who can afford to have their securities rated by NRSROs, and discourages broker-dealers from considering all the relevant credit risk factors when making portfolio decisions. By eliminating the regulatory preference for NRSRO-rated securities, today's amendments could alter the set of securities qualifying for lower net capital charges, which would affect broker-dealers' portfolio preferences. For example, the amendments could increase access to capital markets for smaller issuers whose commercial paper, nonconvertible debt securities, or preferred stock have only a minimal amount of credit risk, but for whom the costs of obtaining an NRSRO rating is potentially prohibitive. Such changes could increase competition among issuers for capital and improve the efficiency of the capital allocation process.
While it is the intent of the Commission that today's amendments not alter the quality of assets that qualify for the lower haircut, it is nonetheless a possibility that the policies and procedures that broker-dealers establish will change the risk and/or net capital levels of broker-dealers. Changes or perceived changes to the amount of net capital being held by a broker-dealer could have negative repercussions on confidence in broker-dealers' financial position among their customers, counterparties, and investors. These impacts on confidence could disrupt the orderly functioning of the markets—for example, by encouraging counterparties to reduce their exposures to broker-dealers in response to uncertainty about broker-dealers' financial positions—and thereby harm the capital formation process.
Finally, today's amendments could have an effect on competition in the credit rating agency industry with consequences on economic efficiency. Currently there are ten NRSROs with the three largest accounting for the majority of all credit ratings. As noted earlier, the favorable regulatory treatment of NRSRO-rated securities increases demand for securities that have been rated by at least two NRSROs. Eliminating this favorable treatment may increase broker-dealers' use of alternative providers of credit risk analysis, which could increase competition in the credit rating agency industry. Furthermore, to the extent that NRSRO ratings are biased, as some have argued, additional competition among credit rating providers could help expose any such biases and increase incentives for NRSROs to produce accurate ratings.
Reducing the emphasis on NRSRO ratings also could adversely affect the quality of NRSRO ratings. Currently, the importance attached to NRSRO ratings may impart franchise value to the NRSRO's ratings business. Eliminating references to NRSRO ratings in certain federal regulations could reduce these franchise values and mitigate NRSROs' incentives to produce credible and reliable ratings. Moreover, the Commission recognizes that the elimination of the required use of credit ratings in the specified Commission rules and forms may reduce the incentive for credit rating agencies to register as NRSROs with the Commission and thereby be subject to the Commission's oversight and the statutory and regulatory requirements applicable to NRSROs. To the extent that the quality and accuracy of NRSRO ratings is adversely affected, negative impacts on the capital allocation process and economic efficiency could result.
The Commission requested comment on all aspects of the benefits associated with the amendments to Rule 15c3–1, the appendices to Rule 15c3–1, and Rule 17a–4, and received no comments. The Commission believes that one of the primary benefits of the amendments being adopted today is reducing potential undue reliance on NRSRO ratings that could be caused by references to NRSROs in Commission rules. Significantly, the Commission believes that eliminating references to NRSRO ratings in its rules would remove any appearance that the Commission has placed its imprimatur on such ratings. The Commission, however, also recognizes that credit ratings provide useful information to institutional and retail investors as part of the process of making an investment decision.
The Commission believes that the amendments to Rule 15c3–1 and its appendices, as well as the conforming amendment to Rule 17a–4, will encourage a more complete assessment of the credit risks associated with securities held by broker-dealers. As the NRSROs themselves have stressed, NRSRO ratings are a one-dimensional measure that summarizes the likelihood that an obligor or financial obligation will fail to repay investors in accordance with the terms on which they made their investment and investors' expected recoveries in the event of such a failure.
Many broker-dealers already conduct their own risk evaluation. As one commenter noted “[a] significant number of large broker-dealers have sophisticated internal credit review functions.”
The Commission recognizes, as a result of today's amendments, that broker-dealers may incur additional costs associated with performing a more detailed and comprehensive analysis of the debt securities they own. The Commission received two comments on the costs associated with the proposed amendments to Rule 15c3–1.
There will be minimal costs associated with the amendments for firms that use Appendix A to Rule 15c3–1. The amendment to the definition of
Firms that use Appendices E and F to Rule 15c3–1 already undergo an approval process to use internal credit ratings to determine credit risk charges for each counterparty. Any new firms that apply to use either Appendix E or Appendix F will not incur any separate costs as a result of the amendments. Currently, firms that apply to use these appendices must have their internal models approved by the Commission prior to using their selected appendix. Although the Commission will have to assess the firm's process for determining internal credit ratings, this step will not cause broker-dealers who are applying to use these appendices to incur any additional costs. Furthermore, because the firms currently using these appendices have traditionally used models to compute capital charges, as opposed to NRSRO ratings, these firms will not incur any additional costs by complying with the amendments.
The Commission requested comment on all aspects of the benefits associated with the amendment to Exhibit A to Rule 15c3–3 and received no comments. The amendment eliminates a criterion that qualified the debits at a clearing agency or derivatives clearing organization if it was assigned the highest credit rating given by any NRSRO. Broker-dealers instead will be required to look to two other criterions based on financial metrics.
The Commission requested comment on all aspects of the costs associated with Note G to Exhibit A to Rule 15c3–3 and received no comments. The total cost of compliance with Note G to Exhibit A to Rule 15c3–3 will be minimal as the removal of the NRSRO credit ratings criterion from Note G is neither intended nor expected to change current security futures margining practices by broker-dealers. As stated in the PRA section, the Commission anticipates that a broker-dealer will incur a one-time cost to verify that a clearing or derivatives clearing organization meets the requirements of Note G. If a broker-dealer is currently using one of the non-NRSRO criterions, it will not incur any one-time costs.
The Commission believes that the amendment to Rule 10b–10 will benefit investors. As explained previously, the existing requirement to inform customers if a debt security, other than a government security, is unrated by an NRSRO may have the unintended effect of suggesting that rated securities are inherently better or less risky than unrated debt securities. The Commission believes that the existence of a rating should not give an investor extra comfort regarding the risks associated with the rated security. The amendment, by removing paragraph (a)(8)'s requirement to disclose whether certain securities are rated by an NRSRO, should help avoid promoting excessive reliance on NRSRO ratings. It also should help encourage investors to view NRSRO ratings as only one of multiple types of information relevant to evaluating credit risk. This in turn should help investors make more informed decisions regarding investments in debt securities.
As stated in the proposing release, the Commission does not expect the amendment to result in any significant changes in the costs associated with Rule 10b–10. Broker-dealers will continue to generate transaction confirmations and send those confirmations to customers, and the amendment is not expected to change the cost of generating and sending confirmations. Moreover, the Commission believes that broker-dealers may not incur costs if they choose not to input information that a debt security is unrated into their existing confirmation systems.
As stated above, the Commission acknowledges that, in some instances, eliminating paragraph (a)(8) of Rule 10b–10 may remove some incentive to investigate the quality of unrated debt securities. The Commission believes, however, that any such potential cost would be balanced by the benefit of encouraging investors not to rely excessively on credit ratings for information about credit risk and to consider additional information.
In adopting the amendments to Rule 15c3–1, the Commission considered several alternative approaches, including suggestions by commenters. The main suggestion by commenters was to use an objective standard of creditworthiness instead of a subjective standard of creditworthiness.
The Commission understands that by not mandating an objective standard to determine the creditworthiness of a security or money market instrument there is a risk that a broker-dealer may incorrectly assess the credit risk. Using a subjective standard also could lead to inconsistent determinations of credit risk of the same security or money market instrument among broker-dealers. Inconsistent determinations of credit risk will lead to situations where broker-dealers that determine the security has only a minimal amount of credit risk will apply a lower haircut to the position than broker-dealers that determine that the security does not have a minimal amount of credit risk. The Commission expects, however, that the risk of this occurring will be mitigated by the Commission and SRO examination process, during which Commission and SRO examiners will assess the reasonableness of broker-dealers' policies and procedures for determining net capital haircuts under the minimal amount of credit risk standard and review the firms' adherence to the policies and procedures. A broker-dealer will need to be able to explain its credit risk analysis and ultimate determination to examiners as part of the examination process. If a broker-dealer has reasonable policies and procedures in place for determining credit risk, and those policies and procedures are followed, the potential for bias to be a part of the assessment process should be mitigated.
The Commission also considered mandating that broker-dealers use a certain number of factors or specific factors when making a credit risk determination. Ultimately, the Commission decided that allowing broker-dealers to establish policies and procedures that are tailored to the size and activities of the broker-dealer would keep costs down. Further, a given factor may be appropriate only for certain types of positions and could, if applied inappropriately, lead to inaccurate credit risk determinations. Allowing a broker-dealer the flexibility in selecting the factors it uses to assess the credit risk of its portfolio could lead to more accurate credit risk determinations.
In adopting the amendments to Appendices E and F of Rule 15c3–1, the Commission considered the alternative proposed by commenters that the minimal amount of credit risk standard be used. However, as explained earlier, the Commission does not believe such a standard would work in Appendices E and F because the minimal amount of credit risk standard in Rule 15c3–1 replaced a binary NRSRO credit rating standard under which the application of a lower or higher haircut amount depends on whether the commercial paper is rated in the top three rating categories and the nonconvertible debt and preferred stock is rated in the top four rating categories. Thus, the instrument either meets the requirement to apply the lower haircut or is subject to the higher haircut. The NRSRO credit ratings standard in Appendices E and F to Rule 15c3–1 is not binary because there are three gradations for credit risk weights. Thus, the minimal amount of credit risk standard would not be a suitable replacement.
In adopting the amendments to Exhibit A to Rule 15c3–3, the Commission did not consider any alternatives to the proposal and did not receive comments offering any alternatives to the proposal. The Commission could have established an alternative criterion but chose not to because the remaining three criteria in the rule are alternatives that permit broker-dealers to meet the objectives of the rule.
In adopting the amendments to Rule 10b–10, the Commission considered not deleting paragraph (a)(8) as proposed. The Commission also considered requiring broker-dealers to disclose alternative information relating to the credit risk of certain debt securities. The Commission determined, however, that requiring the disclosure of alternative information regarding credit risk associated with debt securities similar to that required by paragraph (a)(8) would be inconsistent with the goal of reducing investors' reliance on credit ratings. Elevating an alternative measure of credit risk to the status now conferred upon NRSRO ratings by paragraph (a)(8) would merely substitute one standard upon which investors may have come to rely upon excessively for another. Prohibiting any reference to NRSRO credit ratings in confirmations, however, would seem to go too far by preventing broker-dealers from including information that they believe a reasonable investor would want to consider in particular circumstances. The Commission also determined that substituting another credit risk-related disclosure requirement for paragraph (a)(8) was unnecessary, given that credit risk information is likely to be disclosed before a transaction for reasons independent of paragraph (a)(8),
The Regulatory Flexibility Act of 1980 (“RFA”)
For purposes of Commission rulemaking in connection with the RFA, small entities include broker-dealers with total capital (net worth plus subordinated liabilities) of less than $500,000 on the date in the prior fiscal year as of which its audited financial statements were prepared pursuant to Rule 17a–5 under the Exchange Act,
The amendments adopted today relating to the securities haircut provisions in Rule 15c3–1 and the conforming amendment to Rule 17a–4 will not have a significant economic impact on a small number of entities. Only seven of the 434 broker-dealers that hold proprietary debt positions are considered small for purposes of the RFA and, in the staff's experience, broker-dealers with less than $500,000 in total capital typically hold very few proprietary securities positions and, in particular, a small number of debt securities. Thus, there are few small entities that will be impacted by these amendments. In addition, the amendments allow broker-dealers that hold these debt positions, including those broker-dealers that are considered small for purposes of the RFA, to establish policies and procedures that rely on only a few factors to keep costs low. Further, a small broker-dealer could choose to take the 15% catchall haircut instead of establishing policies and procedures if it determines such an approach is cost-effective. Accordingly, the amendments will not have a significant economic impact on a substantial number of small entities because even if the small entities have to change their current process, they can do so in such a way to minimize economic impact and still comply with the rule amendments.
The amendment to Appendix A to Rule 15c3–1 will not result in a significant impact on small entities. Although the definition of
The amendments to the Appendices E and F to Rule 15c3–1 (which include conforming amendments to Appendix G to Rule 15c3–1 and the General Instructions to Form X–17A–5, Part IIB) will not apply to small entities. Appendices E and G apply to ANC broker-dealers and Appendix F and Form X–17A–5, Part IIB apply to OTC derivatives dealers. The ANC broker-dealers and the OTC derivatives dealers are not small entities as defined in Rule 0–10.
The amendments to Exhibit A to Rule 15c3–3 will not have a significant economic impact on a substantial number of small entities. As noted above, the OCC is the only clearing agency that meets the criteria to qualify for the debit for purposes of the reserve computation. The fact that the OCC meets the criteria to qualify for the debit is well understood among broker-dealers, including small broker-dealers.
The amendment to Rule 10b–10 will not have a significant economic impact on a substantial number of small entities. While a number of the broker-dealers that effect transactions in the debt securities currently subject to paragraph (a)(8) may be small entities, the Commission believes that it is uncommon for small broker-dealers to issue confirmations.
For the reasons described above, the Commission again certifies that the amendments to Rule 15c3–1, Appendices A, E, F, and G to Rule 15c3–1, Exhibit A to Rule 15c3–3, Rule 17a–4, the General Instructions to Form X–17A–5, Part IIB, and Rule 10b–10 will not have a significant economic impact on a substantial number of small entities.
Pursuant to the Exchange Act, 15 U.S.C. 78a
Brokers, Fraud, Reporting and recordkeeping requirements, Securities.
In accordance with the foregoing, Title 17, Chapter II of the Code of Federal Regulations is amended as follows:
15 U.S.C. 77c, 77d, 77g, 77j, 77s, 77z–2, 77z–3, 77eee, 77ggg, 77nnn, 77sss, 77ttt, 78c, 78c–3, 78c–5, 78d, 78e, 78f, 78g, 78i, 78j, 78j–1, 78k, 78k–1, 78
Sections 240.15c3–1a, 240.15c3–1e, 240.15c3–1f, 240.15c3–1g are also issued under Pub. L. 111–203, secs. 939, 939A, 124. Stat. 1376 (2010) (15 U.S.C. 78c, 15 U.S.C. 78
Section 240.15c3–3a is also issued under Pub. L. 111–203, §§ 939, 939A, 124. Stat. 1376 (2010) (15 U.S.C. 78c, 15 U.S.C. 78
The revisions and addition read as follows:
(c) * * *
(2) * * *
(vi) * * *
(E)
(F)(
(
(H) In the case of cumulative, non-convertible preferred stock ranking prior to all other classes of stock of the same issuer, which has only a minimal amount of credit risk and which are not in arrears as to dividends, the deduction shall be 10% of the market value of the greater of the long or short position.
(I) In order to apply a deduction under paragraphs (c)(2)(vi)(E), (c)(2)(vi)(F)(
For a discussion of the “minimal amount of credit risk” standard,
The revisions read as follows:
(c) * * *
(4) * * *
(vi)
(A) As part of its initial application or in an amendment, the broker or dealer may request Commission approval to apply a credit risk weight of either 20%, 50%, or 150% based on internal calculations of credit ratings, including internal estimates of the maturity adjustment. Based on the strength of the broker's or dealer's internal credit risk management system, the Commission may approve the application. The broker or dealer must make and keep current a record of the basis for the credit rating of each counterparty;
The revisions read as follows:
(d) * * *
(3) * * *
(i) For counterparties for which an OTC derivatives dealer assigns an internal rating for senior unsecured long-term debt or commercial paper that would apply a 20% counterparty factor under paragraph (d)(2) of this section, 5% of the amount of the net replacement value in excess of 25% of the OTC derivatives dealer's tentative net capital;
(ii) For counterparties for which an OTC derivatives dealer assigns an internal rating for senior unsecured long-term debt that would apply a 50% counterparty factor under paragraph (d)(2) of this section, 20% of the amount of the net replacement value in excess of 25% of the OTC derivatives dealer's tentative net capital;
(iii) For counterparties for which an OTC derivatives dealer assigns an internal rating for senior unsecured long-term debt that would apply a 100% counterparty factor under paragraph (d)(2) of this section, 50% of the amount of the net replacement value in excess of 25% of the OTC derivatives dealer's tentative net capital.
(4) Counterparties may be rated by the OTC derivatives dealer, or by an affiliated bank or affiliated broker-dealer of the OTC derivatives dealer, upon approval by the Commission on application by the OTC derivatives dealer. Based on the strength of the OTC derivatives dealer's internal credit risk management system, the Commission may approve the application. The OTC derivatives dealer must make and keep current a record of the basis for the credit rating for each counterparty.
The addition reads as follows:
(b) * * *
(13) The written policies and procedures the broker-dealer establishes, documents, maintains, and enforces to assess creditworthiness for the purpose of § 240.15c3–1(c)(2)(vi)(E), (c)(2)(vi)(F)(
15 U.S.C. 78a
Section 249.617 is also issued under Pub. L. 111–203, §§ 939, 939A, 124. Stat. 1376 (2010) (15 U.S.C. 78c, 15 U.S.C. 78
The text of Form X–17A–5 Part IIB does not, and this amendment will not, appear in the Code of Federal Regulations.
By the Commission.
Fish and Wildlife Service, Interior.
Final rule.
We, the U.S. Fish and Wildlife Service (Service), designate critical habitat for the
This rule is effective on February 7, 2014.
This final rule is available on the Internet at
The coordinates, plot points, or both from which the maps are generated are included in the administrative record for this critical habitat designation and are available at
Larry Williams, Field Supervisor, U.S. Fish and Wildlife Service, South Florida Ecological Services Office, 1339 20th Street, Vero Beach, FL 32960; telephone 772–562–3909; or facsimile 772–562–4288. If you use a use a telecommunications device for the deaf (TDD), call the Federal Information Relay Service (FIRS) at 800–877–8339.
We published our determination for
The areas we are designating in this rule constitute our current best assessment of the areas that meet the definition of critical habitat for
On October 11, 2012, we published a proposed rule to list
We requested that the public submit written comments on the proposed designation of critical habitat for
The October 11, 2012, proposed rule contained both the proposed listing of
All substantive information provided during the comment periods specifically relating to the proposed critical habitat designation for
In accordance with our peer review policy published on July 1, 1994 (59 FR 34270), we solicited expert opinions from seven knowledgeable individuals with scientific expertise that included familiarity with the species, the geographic region in which the species occurs, and conservation biology principles. Of those, three reviewers were experts on
We reviewed all comments we received from the peer reviewers for substantive issues and new information regarding critical habitat for
(1)
(2)
The proposed designation of critical habitat for
(3)
In the next 50 to 100 years, in order for
(4)
Based on information we received in comments regarding the habitats that support
We corrected errors in the critical habitat unit acreage that were due to rounding errors. These rounding errors resulted in changes of no more than 1 to 3 ac (0 to 1 ha) in any given unit. We also corrected a calculation error in the acreage of Unit 1 (ENP). This error was due to a miscalculation of the unit size. In the proposed rule, we reported the area of Unit 1 as 3,768 ac (1,525 ha). In the final rule, we report the correct area, which is 6,166 ac (2,495 ha). The Service coordinated this change with ENP, who expressed no concern with the change, as their review focused on the mapped boundaries in the proposed rule, which correctly represented the proposed designated habitat. No adjustments to the unit boundaries were needed as a result of this change. This change does not affect the outcome of economic analysis for the proposed unit designations concerning the projection of incremental effects, as it is based on the consultation history in the mapped area, not the acres. The rounding error corrections and the unit 1 acreage correction results in the total acreage of designated critical habitat for
For more information on
We have evaluated the biological status of this species and threats affecting its continued existence. Our assessment, as summarized immediately below, is based upon the best available scientific and commercial data and the opinion of the species experts.
The climate of south Florida where
Detailed descriptions of coastal berm, coastal rock barren, rockland hammock, and buttonwood forest are presented in the proposed listing rule for
Coastal hardwood hammock that supports
The sparsely vegetated edges or interior portions of rockland and coastal hardwood hammock where the canopy is open are the areas that have light levels sufficient to support
Forests dominated by buttonwood often exist in upper tidal areas, especially where mangrove swamp transitions to rockland or coastal hardwood hammock. These buttonwood forests have canopy dominated by
Temperature, salinity, tidal fluctuation, substrate, and wave energy influence the size and extent of buttonwood forests (FNAI 2010e, p. 3). Buttonwood forests often grade into salt marsh, coastal berm, rockland hammock, coastal hardwood hammock, and coastal rock barren (FNAI 2010d, p. 5).
In ENP, 11
In the Florida Keys,
The reproductive biology and genetics of
Critical habitat is defined in section 3 of the Act as:
(1) The specific areas within the geographical area occupied by the species, at the time it is listed in accordance with the Act, on which are found those physical or biological features
(a) Essential to the conservation of the species, and
(b) Which may require special management considerations or protection; and
(2) Specific areas outside the geographical area occupied by the species at the time it is listed, upon a determination that such areas are essential for the conservation of the species.
Conservation, as defined under section 3 of the Act, means to use and the use of all methods and procedures that are necessary to bring an endangered or threatened species to the point at which the measures provided pursuant to the Act are no longer necessary. Such methods and procedures include, but are not limited to, all activities associated with scientific resources management such as research, census, law enforcement, habitat acquisition and maintenance, propagation, live trapping, and transplantation, and, in the extraordinary case where population pressures within a given ecosystem cannot be otherwise relieved, may include regulated taking.
Critical habitat receives protection under section 7 of the Act through the requirement that Federal agencies ensure, in consultation with the Service, that any action they authorize, fund, or carry out is not likely to result in the destruction or adverse modification of critical habitat. The designation of critical habitat does not affect land ownership or establish a refuge, wilderness, reserve, preserve, or other conservation area. Such designation does not allow the government or public to access private lands. Such designation does not require implementation of restoration, recovery, or enhancement measures by non-
Under the first prong of the Act's definition of critical habitat, areas within the geographical area occupied by the species at the time it was listed are included in a critical habitat designation if they contain physical or biological features (1) which are essential to the conservation of the species and (2) which may require special management considerations or protection. For these areas, critical habitat designations identify, to the extent known using the best scientific and commercial data available, those physical or biological features that are essential to the conservation of the species (such as space, food, cover, and protected habitat). In identifying those physical or biological features within an area, we focus on the principal biological or physical constituent elements (primary constituent elements such as roost sites, nesting grounds, seasonal wetlands, water quality, tide, soil type) that are essential to the conservation of the species. Primary constituent elements are those specific elements of the physical or biological features that provide for a species' life-history processes and are essential to the conservation of the species.
Under the second prong of the Act's definition of critical habitat, we can designate critical habitat in areas outside the geographical area occupied by the species at the time it is listed, upon a determination that such areas are essential for the conservation of the species. For example, an area currently occupied by the species but that was not occupied at the time of listing may be essential to the conservation of the species and may be included in the critical habitat designation. We designate critical habitat in areas outside the geographical area occupied by a species only when a designation limited to its range would be inadequate to ensure the conservation of the species.
Section 4 of the Act requires that we designate critical habitat on the basis of the best scientific and commercial data available. Further, our Policy on Information Standards Under the Endangered Species Act (published in the
When we are determining which areas should be designated as critical habitat, our primary source of information is generally the information developed during the listing process for the species. Additional information sources may include the recovery plan for the species, articles in peer-reviewed journals, conservation plans developed by States and counties, scientific status surveys and studies, biological assessments, other unpublished materials, or experts' opinions or personal knowledge.
Habitat is dynamic, and species may move from one area to another over time. We recognize that critical habitat designated at a particular point in time may not include all of the habitat areas that we may later determine are necessary for the recovery of the species. For these reasons, a critical habitat designation does not signal that habitat outside the designated area is unimportant or may not be needed for recovery of the species. Areas that are important to the conservation of the species, both inside and outside the critical habitat designation, will continue to be subject to: (1) Conservation actions implemented under section 7(a)(1) of the Act, (2) regulatory protections afforded by the requirement in section 7(a)(2) of the Act for Federal agencies to insure their actions are not likely to jeopardize the continued existence of any endangered or threatened species, and (3) section 9 of the Act's prohibitions on taking any individual of the species, including taking caused by actions that affect habitat. Federally funded or permitted projects affecting listed species outside their designated critical habitat areas may still result in jeopardy findings in some cases. These protections and conservation tools will continue to contribute to recovery of this species. Similarly, critical habitat designations made on the basis of the best available information at the time of designation will not control the direction and substance of future recovery plans, habitat conservation plans (HCPs), or other species conservation planning efforts if new information available at the time of these planning efforts calls for a different outcome.
In accordance with section 3(5)(A)(i) and 4(b)(1)(A) of the Act and regulations at 50 CFR 424.12, in determining which areas within the geographical area occupied by the species at the time of listing to designate as critical habitat, we consider the physical or biological features essential to the conservation of the species and which may require special management considerations or protection. These include, but are not limited to:
(1) Space for individual and population growth and for normal behavior;
(2) Food, water, air, light, minerals, or other nutritional or physiological requirements;
(3) Cover or shelter;
(4) Sites for breeding, reproduction, or rearing (or development) of offspring; and
(5) Habitats that are protected from disturbance or are representative of the historical, geographical, and ecological distributions of a species.
We derived the specific physical or biological features essential for
Plant Community and Competitive Ability.
While there have been no studies on the reproductive biology of
The sparsely vegetated edges or interior portions opened by canopy disruption are the areas of rockland and coastal hardwood hammock that have light levels sufficient to support
Under the Act and its implementing regulations, we are required to identify the physical or biological features essential to the conservation of
Based on our current knowledge of the physical or biological features and habitat characteristics required to sustain the species' life-history processes, we determine that the PCEs specific to
(1) Areas of upland habitats consisting of coastal berm, coastal rock barren, coastal hardwood hammock, rockland hammocks, and buttonwood forest.
(a) Coastal berm habitat that contains:
(i) Open to semi-open canopy, subcanopy, and understory; and
(ii) Substrate of coarse, calcareous, storm-deposited sediment.
(b) Coastal rock barren (Keys cactus barren, Keys tidal rock barren) habitat that contains:
(i) Open to semi-open canopy and understory; and
(ii) Limestone rock substrate.
(c) Coastal hardwood hammock habitat occurring in Everglades National Park that contains:
(i) Canopy gaps and edges with an open to semi-open canopy, subcanopy, and understory; and
(ii) Substrate of marl covered with a thin layer of highly organic soil.
(d) Rockland hammock habitat that contains:
(i) Canopy gaps and edges with an open to semi-open canopy, subcanopy, and understory; and
(ii) Substrate with a thin layer of highly organic soil, marl, humus, or leaf litter on top of the underlying limestone.
(e) Buttonwood forest habitat that contains:
(i) Open to semi-open canopy and understory; and
(ii) Substrate with calcareous marl muds, calcareous sands, or limestone rock.
(2) Plant communities of predominately native vegetation with either no invasive, nonnative species or with low enough quantities of nonnative, invasive plant species to have minimal effect on the survival of
(3) A disturbance regime, due to the effects of strong winds or saltwater inundation from storm surge or infrequent tidal inundation, that creates canopy openings in coastal berm, coastal rock barren, coastal hardwood hammock, rockland hammocks, and buttonwood forest.
(4) Habitats that are connected and of sufficient area to sustain viable populations in coastal berm, coastal rock barren, coastal hardwood hammock, rockland hammocks, and buttonwood forest.
When designating critical habitat, we assess whether the specific areas within the geographical area occupied by the species at the time of listing contain features that are essential to the conservation of the species and which may require special management considerations or protection.
Special management considerations or protection are necessary throughout the critical habitat areas to avoid further degradation or destruction of the habitat that contains those features essential for the conservation of the species. The primary threats to the physical or biological features that
Management activities that could ameliorate these threats include the monitoring and minimizing recreational activities impacts, nonnative species control, and protection from development. Precautions are needed to avoid the inadvertent trampling of
In summary, we find that each of the areas we are designating as critical habitat contain features essential to the conservation of
As required by section 4(b)(2) of the Act, we used the best scientific data available to designate critical habitat. In accordance with the Act and our implementing regulations at 50 CFR 424.12(b) we review available information pertaining to the habitat requirements of the species and identify occupied areas at the time of listing that contain the features essential to the conservation of the species. If after identifying currently occupied areas, we determine that those areas are inadequate to ensure conservation of the species, in accordance with the Act and our implementing regulations at 50 CFR 424.12(e), we then consider whether designating additional areas—outside those currently occupied—are essential for the conservation of the species. In this rule, we are designating critical habitat in areas within the geographical area occupied by the species at the time of listing in 2013. We also are designating specific areas outside the geographical area occupied by the species at the time of listing that were historically occupied, because we have determined that such areas are essential for the conservation of the species. Sources of data for this analysis included the following:
(1) Florida Natural Areas Inventory (FNAI) population records and ArcGIS geographic information system (GIS) software to spatially depict the location and extent of documented populations of
(2) Reports prepared by botanists with the Institute for Regional Conservation (IRC), National Park Service (NPS), and Florida Department Environmental Protection (FDEP). Some of these were funded by the Service, others were requested or volunteered by biologists with the NPS or FDEP;
(3) Historical records found in reports and associated voucher specimens housed at herbaria, all of which are also referenced in the above mentioned reports from the IRC and FNAI;
(4) Digitally produced habitat maps provided by NPS and Monroe County; and
(5) Aerial images of Miami-Dade and Monroe Counties. The presence of PCEs was determined through the use of GIS spatial data depicting the current habitat status. This habitat data for the Florida Keys were developed by Monroe County from 2006 aerial images, and ground conditions for many areas were checked in 2009. Habitat data for ENP were provided by the NPS. The areas that contain PCEs follow predictable landscape patterns and have a recognizable signature in the aerial photographs.
Four of the eight extant
The current distribution of the
For the purpose of designating critical habitat for
(1) Space to allow for the successional nature of the occupied habitats (i.e., gain and loss of areas with sufficient light availability due to disturbance of the tree canopy driven by natural events such as inundation and hurricanes), and habitat transition or loss due to sea-level rise. In ENP, the distribution of
(2) Some areas will require special management to maintain connectivity of occupied habitat to allow for population expansion and connection with other populations. Isolation of populations can result in localized extinctions.
(3) Some areas will require special management to be able to support a higher density of the plant within the occupied space. These areas generally are habitats where some of the primary constituent elements have been lost through natural or human causes. These areas would help to off-set the anticipated loss and degradation of habitat occurring or expected from the effects of climate change (such as sea-level rise) or due to development.
After following the above criteria, we determined that occupied areas were not sufficient for the conservation of the species for the following reasons: (1) Restoring the species to its historical range and reducing its vulnerability to stochastic events such as hurricanes and storm surge requires reintroduction to areas where it occurred in the past but has since been extirpated; (2) providing increased connectivity for populations and areas for small populations to expand requires currently unoccupied habitat; and (3) reintroduction or assisted migration to reduce the vulnerability of the species to sea-level rise and storm surge requires higher elevation sites that currently are unoccupied by
When designating critical habitat, we consider future recovery efforts and conservation of the species. Realizing that the current occupied habitat is not enough for the conservation and recovery of
The unoccupied areas are essential for the conservation of the species because they:
(1) Represent the historical range of
(2) Provide areas of sufficient size to support ecosystem processes for populations of
The amount and distribution of designated critical habitat will allow
(1) Maintain its existing distribution;
(2) Expand its distribution into historically occupied areas (needed to offset habitat loss and fragmentation);
(3) Use habitat depending on habitat availability (respond to changing nature of coastal habitat including occurring sea-level rise) and support genetic diversity;
(4) Increase the size of each population to a level where the threats of genetic, demographic, and normal environmental uncertainties are diminished; and
(5) Maintain its ability to withstand local or unit level environmental fluctuations or catastrophes.
When determining critical habitat boundaries within this final rule, we made every effort to avoid including developed areas such as lands covered by buildings, pavement, and other structures because such lands lack physical or biological features for
The critical habitat designation is defined by the map or maps, as modified by any accompanying regulatory text, presented at the end of
We are designating nine units as critical habitat for
We present brief descriptions of all units, and reasons why they meet the definition of critical habitat for
Unit 1 consists of a total of 6,166 ac (2,495 ha) in Monroe and Miami-Dade Counties. This unit is composed entirely of lands in Federal ownership, 100 percent of which are located within the Everglades National Park along the southern coast of Florida from Cape Sable to Trout Cove, located between the mean high water line to approximately 2.5 mi (4.02 km) inland. This unit is currently occupied and contains all the physical or biological features required by the species. The unit contains coastal hardwood hammock and buttonwood forest primary constituent elements. The physical or biological features in this unit may require special management considerations or protection to address threats of nonnative plant species and sea-level rise. The National Park Service conducts nonnative species control and monitors
Unit 2 consists of a total of 3,431 ac (1,388 ha) in Monroe County. This unit is composed of Federal lands within Crocodile Lake National Wildlife Refuge (NWR) (804 ac (325 ha)); State lands within Dagny Johnson Botanical State Park, John Pennekamp Coral Reef State Park, and the Florida Keys Wildlife and Environmental Area (2,170 ac (878 ha)); and parcels in private ownership (457 ac (185 ha)).
This unit extends from near the northern tip of Key Largo, along the length of Key Largo, beginning at the south shore of Ocean Reef Harbor near South Marina Drive and the intersection of County Road (CR) 905 and Clubhouse Road on the west side of CR 905, and between CR 905 and Old State Road 905, then extending to the shoreline south of South Harbor Drive. The unit then continues on both sides of CR 905 through the Crocodile Lake NWR, Dagny Johnson Key Largo Hammock Botanical State Park, and John Pennekamp Coral Reef State Park. The unit then terminates near the junction of U.S. 1 and CR 905 and Garden Cove Drive. The unit resumes on the east side of U.S. 1 from South Andros Road to Key Largo Elementary School; then from intersection of Taylor Drive and Pamela
This unit is not currently occupied but is essential for the conservation of the species because it serves to protect habitat needed to recover the species, reestablish wild populations within the historical range of the species, and maintain populations throughout the historical distribution of the species in the Florida Keys. It also provides area for recovery in the case of stochastic events that otherwise would eliminate the species from the one or more locations it is presently found. The Service conducts nonnative species control efforts at Crocodile Lake NWR, and FDACS conducts nonnative species control efforts at Dagny Johnson Botanical State Park, John Pennekamp Coral Reef State Park, and the Florida Keys Wildlife and Environmental Area.
Unit 3 consists of a total of 69 ac (28 ha) in Monroe County. This unit is composed of State lands within Lignumvitae Key State Botanical Park, Indian Key Historical State Park (24 ac (10 ha)); City of Islamorada lands within the Key Tree Cactus Preserve and Green Turtle Hammock Park and parcels in private ownership (45 ac (18 ha)).
This unit extends from Matecumbe Avenue south to Seashore Avenue along either side of U.S. 1. The unit then continues along the west side of U.S. 1, including the Green Turtle Hammock Park and a nature preserve owned by the City of Islamorada; straddles U.S. 1 in the vicinity of Indian Key Historical Park; and continues for 0.5 mi (0.8 km) to near the southern tip of Key Largo on the west side of U.S. 1. This unit is currently occupied and contains all the physical or biological features essential for the conservation of the species. It contains the primary constituent elements of coastal berm, coastal rock barren, and rockland hammock.
The physical or biological features in this unit may require special management considerations or protection to address threats of small population size, nonnative species, and sea-level rise. FDACS conducts nonnative species control efforts in Lignumvitae Key State Botanical Park and Indian Key Historical State Park.
Unit 4 consists of a total of 180 ac (73 ha) in Monroe County. This unit is composed entirely of lands in State ownership, 100 percent of which are located within the Lignumvitae Key Botanical State Park (LKBSP) on Lignumvitae Key in the Florida Keys. This unit includes the entire upland area of Lignumvitae Key.
This unit is currently occupied and contains all the physical or biological features essential for the conservation of the species. This unit includes all the primary constituent of rockland hammock and buttonwood forest habitat that occur within LKBSP on Lignumvitae Key. The physical or biological features in this unit may require special management considerations or protection to address threats of small population size, nonnative species, and sea-level rise. FDACS conducts nonnative species control efforts at LKBSP.
Unit 5 consists of a total of 44 ac (18 ha) in Monroe County. The unit is composed of State lands within Lignumvitae Key Botanical State Park and parcels owned by the Florida Department of Transportation (22 ac (9 ha)); and parcels in private ownership (22 ac (9 ha)). This unit extends from the east side of U.S. 1 from 0.14 mi (0.2 km) from the north edge of Lower Matecumbe Key, situated across U.S. 1 from Davis Lane and Tiki Lane. The unit continues on either side of U.S. 1 approximately 0.4 mi (0.6 km) from the north edge of Lower Matecumbe Key for approximately 0.6 mi (0.9 km).
This unit is currently occupied and contains all the physical or biological features essential for the conservation of the species. The physical or biological features in this unit may require special management considerations or protection to address threats of small population size, nonnative species, and sea-level rise. FDACS conducts nonnative species control efforts at Lignumvitae Key Botanical State Park.
Unit 6 consists of a total of 208 ac (84 ha) in Monroe County. This unit is composed of State lands within Long Key State Park (151 ac (61 ha)) and parcels in private ownership (57 ac (23 ha)). The unit extends from the southwestern tip of Long Key along the island's west and south shores.
The unit is currently occupied and contains all the physical or biological features essential to the conservation of the species. It contains the PCEs of coastal berm, coastal rock barren, rockland hammock, and buttonwood forest. The physical or biological features in this unit may require special management considerations or protection to address threats of development, small population size, nonnative species, and sea-level rise. FDACS conducts nonnative species control efforts at Long Key State Park.
Unit 7 consists of a total of 780 ac (316 ha) in Monroe County. This unit is composed of Federal land within the National Key Deer Refuge (NKDR) (686 ac (278 ha)) and parcels in private ownership (94 ac (38 ha)). This unit extends from near the northern tip of Big Pine Key along the eastern shore to the vicinity of Hellenga Drive and Watson Road; from Gulf Boulevard south to West Shore Drive; extending from the southwest tip of Big Pine Key, bordered by Big Pine Avenue and Elma Avenues on the east, Coral and Yacht Club Road, and U.S. 1 on the north, and Industrial Avenue on the east; along Long Beach Drive; and from the southeastern tip of Big Pine Key to Avenue A.
This unit is not currently occupied but is essential for the conservation of the species because it serves to protect habitat needed to recover the species, reestablish wild populations within the historical range of the species, and maintain populations throughout the historical distribution of the species in the Florida Keys. It also provides area for recovery in the case of stochastic events that otherwise hold the potential to eliminate the species from the one or more locations where it is presently found. The Service conducts nonnative species control at the National Key Deer Refuge.
Unit 8 consists of a total of 28 ac (11 ha) in Monroe County. This unit is composed entirely of lands in private ownership, owned by the Boy Scouts of America. This unit is occupied and contains all the physical or biological features essential for the conservation of the species. It includes all the PCEs of coastal berm, rockland hammock, and buttonwood forest habitat that occur on Big Munson Island.
The physical or biological features in this unit may require special management considerations or protection to address threats of development, recreation, nonnative species, and sea-level rise. No conservation actions are known.
Unit 9 consists of a total of 62 ac (25 ha) in Monroe County. This unit is composed entirely of lands in Federal ownership, 100 percent of which is located within the Key West National Wildlife Refuge. This unit is occupied and contains all the physical or biological features essential for the conservation of the species. This unit includes all the primary constituent elements of coastal berm, rockland hammock, and buttonwood forest habitat on the island, comprising the entirety of Boca Grande Key.
The physical or biological features in this unit may require special management considerations or protection to address threats of small population size, nonnative species, and sea-level rise. The Service conducts nonnative species control at the Key West Refuge.
Unit 9 of the critical habitat units for
Section 7(a)(2) of the Act requires Federal agencies, including the Service, to ensure that any action they fund, authorize, or carry out is not likely to jeopardize the continued existence of any endangered species or threatened species or result in the destruction or adverse modification of designated critical habitat of such species. In addition, section 7(a)(4) of the Act requires Federal agencies to confer with the Service on any agency action which is likely to jeopardize the continued existence of any species proposed to be listed under the Act or result in the destruction or adverse modification of proposed critical habitat.
Decisions by the 5th and 9th Circuit Courts of Appeals have invalidated our regulatory definition of “destruction or adverse modification” (50 CFR 402.02) (see
If a Federal action may affect a listed species or its critical habitat, the responsible Federal agency (action agency) must enter into consultation with us. Examples of actions that are subject to the section 7 consultation process are actions on State, tribal, local, or private lands that require a Federal permit (such as a permit from the U.S. Army Corps of Engineers under section 404 of the Clean Water Act (33 U.S.C. 1251
As a result of section 7 consultation, we document compliance with the requirements of section 7(a)(2) through our issuance of:
(1) A concurrence letter for Federal actions that may affect, but are not likely to adversely affect, listed species or critical habitat; or
(2) A biological opinion for Federal actions that may affect and are likely to adversely affect, listed species or critical habitat.
When we issue a biological opinion concluding that a project is likely to jeopardize the continued existence of a listed species and/or destroy or adversely modify critical habitat, we provide reasonable and prudent alternatives to the project, if any are identifiable, that would avoid the likelihood of jeopardy and/or destruction or adverse modification of critical habitat. We define “reasonable and prudent alternatives” (at 50 CFR 402.02) as alternative actions identified during consultation that:
(1) Can be implemented in a manner consistent with the intended purpose of the action,
(2) Can be implemented consistent with the scope of the Federal agency's legal authority and jurisdiction,
(3) Are economically and technologically feasible, and
(4) Would, in the Director's opinion, avoid the likelihood of jeopardizing the continued existence of the listed species and/or avoid the likelihood of destroying or adversely modifying critical habitat.
Reasonable and prudent alternatives can vary from slight project modifications to extensive redesign or relocation of the project. Costs associated with implementing a reasonable and prudent alternative are similarly variable.
Regulations at 50 CFR 402.16 require Federal agencies to reinitiate consultation on previously reviewed actions in instances where we have listed a new species or subsequently designated critical habitat that may be affected and the Federal agency has retained discretionary involvement or control over the action (or the agency's discretionary involvement or control is authorized by law). Consequently, Federal agencies sometimes may need to request reinitiation of consultation with us on actions for which formal consultation has been completed, if those actions with discretionary involvement or control may affect subsequently listed species or designated critical habitat.
The key factor related to the adverse modification determination is whether, with implementation of the proposed Federal action, the affected critical habitat would continue to serve its intended conservation role for the species. Activities that may destroy or adversely modify critical habitat are those that alter the physical or biological features to an extent that appreciably reduces the conservation value of critical habitat for
Section 4(b)(8) of the Act requires us to briefly evaluate and describe, in any proposed or final regulation that designates critical habitat, activities involving a Federal action that may destroy or adversely modify such habitat, or that may be affected by such designation.
Activities that may affect critical habitat, when carried out, funded, or authorized by a Federal agency, should result in consultation for
(1) Actions that would significantly alter the hydrology or substrate, such as
(2) Actions that would significantly alter vegetation structure or composition, such as clearing vegetation for construction of residences, facilities, trails, and roads.
(3) Actions that would introduce nonnative species that would significantly alter vegetation structure or composition. Such activities may include, but are not limited to, residential and commercial development, and road construction.
Section 4(a)(3)(B)(i) of the Act (16 U.S.C. 1533(a)(3)(B)(i)) provides that: “The Secretary shall not designate as critical habitat any lands or other geographic areas owned or controlled by the Department of Defense, or designated for its use, that are subject to an integrated natural resources management plan (INRMP) prepared under section 101 of the Sikes Act (16 U.S.C. 670a), if the Secretary determines in writing that such plan provides a benefit to the species for which critical habitat is proposed for designation.” There are no Department of Defense lands with a completed INRMP within the proposed critical habitat designation. Therefore, we are not exempting any lands from this final designation of critical habitat for
Section 4(b)(2) of the Act states that the Secretary shall designate and make revisions to critical habitat on the basis of the best available scientific data after taking into consideration the economic impact, national security impact, and any other relevant impact of specifying any particular area as critical habitat. The Secretary may exclude an area from critical habitat if she determines that the benefits of such exclusion outweigh the benefits of specifying such area as part of the critical habitat, unless she determines, based on the best scientific data available, that the failure to designate such area as critical habitat will result in the extinction of the species. In making that determination, the statute on its face, as well as the legislative history, is clear that the Secretary has broad discretion regarding which factor(s) to use and how much weight to give to any factor.
Under section 4(b)(2) of the Act, the Secretary may exclude an area from designated critical habitat based on economic impacts, impacts on national security, or any other relevant impacts. In considering whether to exclude a particular area from the designation, we identify the benefits of including the area in the designation, identify the benefits of excluding the area from the designation, and evaluate whether the benefits of exclusion outweigh the benefits of inclusion. If the analysis indicates that the benefits of exclusion outweigh the benefits of inclusion, the Secretary may exercise her discretion to exclude the area only if such exclusion would not result in the extinction of the species.
Under section 4(b)(2) of the Act, we consider the economic impacts of specifying any particular area as critical habitat. In order to consider economic impacts, we prepared a draft economic analysis of the proposed critical habitat designation and related factors (Loomis
The intent of the final economic analysis (FEA) is to quantify the economic impacts of all potential conservation efforts for
The FEA also addresses how potential economic impacts are likely to be distributed, including an assessment of any local or regional impacts of habitat conservation and the potential effects of conservation activities on government agencies, private businesses, and individuals. The FEA measures lost economic efficiency associated with residential and commercial development and public projects and activities, such as economic impacts on water management and transportation projects, Federal lands, small entities, and the energy industry. Decision-makers can use this information to assess whether the effects of the designation might unduly burden a particular group or economic sector. Finally, the FEA looks retrospectively at costs that occurred between the publication of the final listing rule and the final rule designating critical habitat, and considers those costs that may occur in the 20 years following the designation of critical habitat, which was determined to be the appropriate period for analysis because limited planning information was available for most activities to forecast activity levels for projects beyond a 20-year timeframe. The FEA quantifies economic impacts of
Based on the best available information, including extensive discussions with stakeholders, we estimate the critical habitat designation will result in direct incremental costs of approximately between $578,000 (at a 7 percent discount rate), $764,000 (at a 3 percent discount rate), and $982,000 (not discounted) over the next 20 years, or $38,000 to $49,000 on an annual basis depending on the discount rate. We estimate 93 percent of the costs are attributable to Federal land management and restoration and conservation activities, and the remaining costs are attributable to with development in the area. The majority of these costs is administrative and is borne by Federal and State agencies; however, some costs may be incurred by local governments and businesses. These costs stem from
Our economic analysis did not identify any disproportionate costs that are likely to result from the designation. Consequently, the Secretary is not exercising her discretion to exclude any areas from this designation of critical habitat for
A copy of the FEA with supporting documents may be obtained by contacting the South Florida Ecological Services Office (see
Under section 4(b)(2) of the Act, we consider whether there are lands owned or managed by the Department of Defense where a national security impact might exist. In preparing this final rule, we have determined that no lands within the designation of critical habitat for
Under section 4(b)(2) of the Act, we consider any other relevant impacts, in addition to economic impacts and impacts on national security. We consider a number of factors, including whether the landowners have developed any HCPs or other management plans for the area, or whether there are conservation partnerships that would be encouraged by designation of, or exclusion from, critical habitat. In addition, we look at any tribal issues, and consider the government-to-government relationship of the United States with tribal entities. We also consider any social impacts that might occur because of the designation.
In preparing this final rule, we have determined that there are currently no HCPs or other management plans for
Executive Order 12866 provides that the Office of Information and Regulatory Affairs (OIRA) will review all significant rules. The Office of Information and Regulatory Affairs has determined that this rule is not significant.
Executive Order 13563 reaffirms the principles of E.O. 12866 while calling for improvements in the nation's regulatory system to promote predictability, to reduce uncertainty, and to use the best, most innovative, and least burdensome tools for achieving regulatory ends. The executive order directs agencies to consider regulatory approaches that reduce burdens and maintain flexibility and freedom of choice for the public where these approaches are relevant, feasible, and consistent with regulatory objectives. E.O. 13563 emphasizes further that regulations must be based on the best available science and that the rulemaking process must allow for public participation and an open exchange of ideas. We have developed this rule in a manner consistent with these requirements.
Under the Regulatory Flexibility Act (RFA; 5 U.S.C. 601
According to the Small Business Administration, small entities include small organizations, such as independent nonprofit organizations; small governmental jurisdictions, including school boards and city and town governments that serve fewer than 50,000 residents; as well as small businesses. Small businesses include manufacturing and mining concerns with fewer than 500 employees, wholesale trade entities with fewer than 100 employees, retail and service businesses with less than $5 million in annual sales, general and heavy construction businesses with less than $27.5 million in annual business, special trade contractors doing less than $11.5 million in annual business, and agricultural businesses with annual sales less than $750,000. To determine if potential economic impacts on these small entities are significant, we consider the types of activities that might trigger regulatory impacts under this rule, as well as the types of project modifications that may result. In general, the term “significant economic impact” is meant to apply to a typical small business firm's business operations.
Importantly, the incremental impacts of a rule must be
The Service's current understanding of recent case law is that Federal agencies are only required to evaluate the potential impacts of rulemaking on those entities directly regulated by the rulemaking; therefore, they are not required to evaluate the potential impacts to those entities not directly regulated. The designation of critical habitat for an endangered or threatened species only has a regulatory effect where a Federal action agency is involved in a particular action that may affect the designated critical habitat. Under these circumstances, only the Federal action agency is directly regulated by the designation, and, therefore, consistent with the Service's current interpretation of RFA and recent case law, the Service may limit its evaluation of the potential impacts to those identified for Federal action agencies. Under this interpretation, there is no requirement under the RFA
In conclusion, we believe that, based on our interpretation of directly regulated entities under the RFA and relevant case law, this designation of critical habitat will only directly regulate Federal agencies, which are not by definition small business entities. Accordingly, we certify that this designation of critical habitat will not have a significant economic impact on a substantial number of small business entities. Therefore, a regulatory flexibility analysis is not required. However, in our final economic analysis for this rule, we considered and evaluated the potential effects to third parties that may be involved with consultations with Federal action agencies related to this action.
Designation of critical habitat only affects activities authorized, funded, or carried out by Federal agencies. Some kinds of activities are unlikely to have any Federal involvement and so will not be affected by critical habitat designation. In areas where the species is present, Federal agencies already are required to consult with us under section 7 of the Act on activities they authorize, fund, or carry out that may affect the
In our FEA, we evaluated the potential economic effects on small business entities resulting from conservation actions related to the listing of the
The threshold for a small governmental jurisdiction is a city, county, town, school district, or special district with a population of less than 50,000. The village of Islamorada, which manages conservation areas within the Upper Matecumbe Key habitat unit, qualifies as a small entity under this definition. Based on communication with the village of Islamorada (2013), current management of these areas, including control of invasive species, is consistent with management expected following the listing and designation of critical habitat for
There is the potential that project proponents for commercial, residential, and recreational development could be small businesses. As discussed in section 4.2 of the FEA, we do not estimate any incremental administrative time or project modifications above existing permitting requirements and restrictions on land clearing associated with development.
In summary, we considered whether this designation will result in a significant economic effect on a substantial number of small entities. Based on the above reasoning and currently available information, we concluded that this rule will not result in a significant economic impact on a substantial number of small entities. Therefore, we are certifying that the designation of critical habitat for
Executive Order 13211 (Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use) requires agencies to prepare Statements of Energy Effects when undertaking certain actions. OMB has provided guidance for implementing this Executive Order that outlines nine outcomes that may constitute “a significant adverse effect” when compared to not taking the regulatory action under consideration.
Appendix A of the economic analysis discusses the potential for critical habitat to affect energy supply, distribution, or use through the additional cost of considering adverse modification in section 7 consultation. The economic analysis finds that none of the seven outcomes relative to significant adverse effect thresholds set forth by the Office of Management and Budget are relevant to this analysis. Thus, based on information in the economic analysis, energy-related impacts associated with
In accordance with the Unfunded Mandates Reform Act (2 U.S.C. 1501
(1) This rule will not produce a Federal mandate. In general, a Federal mandate is a provision in legislation, statute, or regulation that would impose an enforceable duty upon State, local, or tribal governments, or the private sector, and includes both “Federal intergovernmental mandates” and “Federal private sector mandates.” These terms are defined in 2 U.S.C. 658(5)–(7). “Federal intergovernmental mandate” includes a regulation that “would impose an enforceable duty upon State, local, or tribal governments” with two exceptions. It excludes “a condition of Federal assistance.” It also excludes “a duty arising from participation in a voluntary Federal program,” unless the regulation “relates to a then-existing Federal program under which $500,000,000 or more is provided annually to State, local, and tribal governments under entitlement authority,” if the provision would “increase the stringency of conditions of assistance” or “place caps upon, or otherwise decrease, the Federal Government's responsibility to provide funding,” and the State, local, or tribal governments “lack authority” to adjust accordingly. At the time of enactment, these entitlement programs were: Medicaid; Aid to Families with Dependent Children work programs; Child Nutrition; Food Stamps; Social Services Block Grants; Vocational Rehabilitation State Grants; Foster Care, Adoption Assistance, and Independent Living; Family Support Welfare Services; and Child Support Enforcement. “Federal private sector
The designation of critical habitat does not impose a legally binding duty on non-Federal Government entities or private parties. Under the Act, the only regulatory effect is that Federal agencies must ensure that their actions do not destroy or adversely modify critical habitat under section 7. While non-Federal entities that receive Federal funding, assistance, or permits, or that otherwise require approval or authorization from a Federal agency for an action, may be indirectly impacted by the designation of critical habitat, the legally binding duty to avoid destruction or adverse modification of critical habitat rests squarely on the Federal agency. Furthermore, to the extent that non-Federal entities are indirectly impacted because they receive Federal assistance or participate in a voluntary Federal aid program, the Unfunded Mandates Reform Act would not apply, nor would critical habitat shift the costs of the large entitlement programs listed above onto State governments.
(2) We do not believe that this rule will significantly or uniquely affect small governments because it will not produce a Federal mandate of $100 million or greater in any year, that is, it is not a “significant regulatory action” under the Unfunded Mandates Reform Act. Small governments will be affected only to the extent that any programs having Federal funds, permits, or other authorized activities must ensure that their actions will not adversely affect the critical habitat. The final economic analysis concludes incremental impacts may occur due to administrative costs of section 7 consultations for activities related to commercial, residential, and recreational development and associated actions; however, these are not expected to significantly affect small government entities. Consequently, a Small Government Agency Plan is not required.
In accordance with Executive Order 12630 (Government Actions and Interference with Constitutionally Protected Private Property Rights), we have analyzed the potential takings implications of designating critical habitat for
In accordance with Executive Order 13132 (Federalism), this rule does not have significant Federalism effects. A federalism summary impact statement is not required. In keeping with Department of the Interior and Department of Commerce policy, we request information from, and coordinated development of, this critical habitat designation with appropriate State resource agencies in Florida. From a federalism perspective, the designation of critical habitat directly affects only the responsibilities of Federal agencies. The Act imposes no other duties with respect to critical habitat, either for States and local governments, or for anyone else. As a result, the rule does not have substantial direct effects either on the States, or on the relationship between the national government and the States, or on the distribution of powers and responsibilities among the various levels of government. The designation may have some benefit to these governments in that the areas that contain the physical or biological features essential to the conservation of the species are more clearly defined, and the elements of the physical and biological features of the habitat necessary to the conservation of the species are specifically identified. This information does not alter where and what federally sponsored activities may occur. However, it may assist local governments in long-range planning (rather than having them wait for case-by-case section 7 consultations to occur).
Where State and local governments require approval or authorization from a Federal agency for actions that may affect critical habitat, consultation under section 7(a)(2) would be required. While non-Federal entities that receive Federal funding, assistance, or permits, or that otherwise require approval or authorization from a Federal agency for an action, may be indirectly impacted by the designation of critical habitat, the legally binding duty to avoid destruction or adverse modification of critical habitat rests squarely on the Federal agency.
In accordance with Executive Order 12988 (Civil Justice Reform), the Office of the Solicitor has determined that the rule does not unduly burden the judicial system and that it meets the applicable standards set forth in sections 3(a) and 3(b)(2) of the Order. We are designating critical habitat in accordance with the provisions of the Act. To assist the public in understanding the habitat needs of the species, the rule identifies the elements of physical or biological features essential to the conservation of
This rule does not contain any new collections of information that require approval by OMB under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
It is our position that, outside the jurisdiction of the U.S. Court of Appeals for the Tenth Circuit, we do not need to prepare environmental analyses pursuant to the National Environmental Policy Act in connection with designating critical habitat under the Act. We published a notice outlining our reasons for this determination in the
In accordance with the President's memorandum of April 29, 1994 (Government-to-Government Relations with Native American Tribal Governments; 59 FR 22951), Executive Order 13175 (Consultation and
We determined that there are no tribal lands occupied by
A complete list of all references cited is available on the Internet at
The primary authors of this rulemaking are the staff members of the U.S. Fish and Wildlife Service, South Florida Ecological Services Office.
Endangered and threatened species, Exports, Imports, Reporting and recordkeeping requirements, Transportation.
Accordingly, we amend part 17, subchapter B of chapter I, title 50 of the Code of Federal Regulations, as set forth below:
16 U.S.C. 1361–1407; 1531–1544; 4201–4245, unless otherwise noted.
(h) * * *
(a)
Family Asteraceae:
(1) Critical habitat units for
(2) Within these areas, the primary constituent elements of the physical or biological features essential to the conservation of
(i) Areas of upland habitats consisting of coastal berm, coastal rock barren, coastal hardwood hammock, rockland hammocks, and buttonwood forest.
(A) Coastal berm habitat that contains:
(
(
(B) Coastal rock barren (Keys cactus barren, Keys tidal rock barren) habitat that contains:
(
(
(C) Coastal hardwood hammock habitat occurring in Everglades National Park that contains:
(
(
(D) Rockland hammock habitat that contains:
(
(
(E) Buttonwood forest habitat that contains:
(
(
(ii) Plant communities of predominately native vegetation with either no invasive, nonnative species or with low enough quantities of nonnative, invasive plant species to have minimal effect on the survival of
(iii) A disturbance regime, due to the effects of strong winds or saltwater inundation from storm surge or infrequent tidal inundation, that creates canopy openings in coastal berm, coastal rock barren, coastal hardwood hammock, rockland hammocks, and buttonwood forest.
(iv) Habitats that are connected and of sufficient area to sustain viable populations in coastal berm, coastal rock barren, coastal hardwood hammock, rockland hammocks, and buttonwood forest.
(3) Critical habitat does not include manmade structures (such as buildings, aqueducts, runways, roads, and other paved areas) and the land on which they are located exists within the legal boundaries on February 7, 2014.
(4)
(5) Index map of all critical habitat units for
(6) Unit 1: Everglades National Park, Monroe and Miami-Dade Counties, Florida.
(i)
(ii) Map of Unit 1 follows:
(7) Unit 2: Key Largo, Monroe County, Florida.
(i)
(ii) Index map of Unit 2 follows:
(iii) Map A of Unit 2 follows:
(iv) Map B of Unit 2 follows:
(v) Map C of Unit 2 follows:
(vi) Map D of Unit 2 follows:
(vii) Map E of Unit 2 follows:
(viii) Map F of Unit 2 follows:
(8) Unit 3: Upper Matecumbe Key, Monroe County, Florida.
(i)
(ii) Map of Unit 3 follows:
(9) Unit 4: Lignumvitae Key, Monroe County, Florida.
(i)
(ii) Map of Unit 4 follows:
(10) Unit 5: Lower Matecumbe Key, Monroe County, Florida.
(i)
(ii) Map of Unit 5 follows:
(11) Unit 6: Long Key, Monroe County, Florida.
(i)
(ii) Index map of Unit 6 follows:
(iii) Map A of Unit 6 follows:
(iv) Map B of Unit 6 follows:
(12) Unit 7: Big Pine Key, Monroe County, Florida.
(i)
(ii) Index map of Unit 7 follows:
(iii) Map A of Unit 7 follows:
(iv) Map B of Unit 7 follows:
(v) Map C of Unit 7 follows:
(vi) Map D of Unit 7 follows:
(vii) Map E of Unit 7 follows:
(13) Unit 8: Big Munson Island, Monroe County, Florida.
(i)
(ii) Map of Unit 8 follows:
(14) Unit 9: Boca Grande Key, Monroe County, Florida.
(i)
(ii) Map of Unit 9 follows: