Federal Crop Insurance Corporation
National Institute of Food and Agriculture
Committee for Purchase From People Who Are Blind or Severely Disabled
Foreign-Trade Zones Board
International Trade Administration
National Institute of Standards and Technology
National Oceanic and Atmospheric Administration
Navy Department
Federal Energy Regulatory Commission
Centers for Disease Control and Prevention
Centers for Medicare & Medicaid Services
Children and Families Administration
Food and Drug Administration
National Institutes of Health
Coast Guard
U.S. Customs and Border Protection
Fish and Wildlife Service
Land Management Bureau
National Park Service
Occupational Safety and Health Administration
Federal Aviation Administration
Federal Highway Administration
Surface Transportation Board
Consult the Reader Aids section at the end of this page for phone numbers, online resources, finding aids, reminders, and notice of recently enacted public laws.
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Nuclear Regulatory Commission.
Final rule.
The U.S. Nuclear Regulatory Commission (NRC) is amending its regulations to make miscellaneous corrections. These changes include updating the name of its human capital office, correcting and adding missing cross-references, correcting grammatical errors, revising language for clarity and consistency, and specifying metric units. This document is necessary to inform the public of these non-substantive changes to the NRC's regulations.
This rule is effective on July 8, 2013.
Please refer to Docket ID NRC–2013–0019 when contacting the NRC about the availability of information for this final rule. You may access information related to this final rule, which the NRC possesses and is publicly available, using any of the following methods:
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•
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Christian Leatherbury, Rules Announcements and Directives Branch, Division of Administrative Services, Office of Administration, U.S. Nuclear Regulatory Commission, Washington, DC 20555–0001, telephone: 301–492–3515, email:
The NRC is amending its regulations in chapter I of Title 10 of the
In appendix E to 10 CFR part 50, section IV, paragraph F.2.a.(i), the phrase “rated power” is revised to read “rated thermal power” for clarity and consistency with 10 CFR 50.54(gg)(1).
In § 50.55(e)(4)(iii), the references to “(e)(3)(ii)(C)” and “(4)(v)” are incorrect. In this paragraph, the reference “(e)(3)(ii)(C)” is replaced with reference “(e)(3)(iii)(C)” and the reference “(4)(v)” is replaced with reference “(e)(4)(v).”
In § 50.55(e)(6), the reference to “(e)(9)(ii)” is incorrect. In this paragraph, the reference “(e)(9)(ii)” is replaced with the reference “(e)(5)(ii).”
In appendix G to 10 CFR part 50, section IV, the reference to “Table 3” is incorrect. In this section the references to “Table 3” are replaced with the references to “Table 1.”
Under the Administrative Procedure Act (5 U.S.C. 553(b)), an agency may waive the normal notice and comment requirements if it finds, for good cause, that they are impracticable, unnecessary, or contrary to the public interest. As authorized by 5 U.S.C. 553(b)(3)(B), the NRC finds good cause to waive notice and opportunity for comment on the amendments because they will have no substantive impact and are of a minor and administrative nature dealing with corrections to certain CFR sections related only to management, organization, procedure, and practice. Specifically, the revisions are of the following types: Revision of the name for an NRC office; correction and insertion of cross-references to sections of 10 CFR chapter I; correction of grammatical errors; specification of metric units; and revision to provide clarity and consistency. These amendments do not require action by any person or entity regulated by the NRC. Also, the final rule does not change the substantive responsibilities of any person or entity regulated by the NRC.
The NRC has determined that this final rule is the type of action described in categorical exclusion 10 CFR 51.22(c)(2), which excludes from a major action rules which are corrective or of minor nonpolicy nature and do not substantially modify existing regulations. Therefore, neither an environmental impact statement nor an environmental assessment has been prepared for this rule.
This final rule does not contain information collection requirements and, therefore, is not subject to the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.).
The NRC may not conduct or sponsor, and a person is not required to respond to, a request for information or an information collection requirement unless the requesting document displays a currently valid Office of Management and Budget control number.
The Plain Writing Act of 2010 (Pub. L. 111–274) requires Federal agencies to write documents in a clear, concise, and well-organized manner. The NRC has written this document to be consistent with the Plain Writing Act as well as the Presidential Memorandum, “Plain Language in Government Writing,” published June 10, 1998 (63 FR 31883).
The NRC has determined that the administrative changes in this final rule do not constitute backfitting, and therefore a backfit analysis is not included. The revisions are administrative in nature, including revision of the name for an NRC office; correction and insertion of cross-references to sections of 10 CFR Chapter I; correction of grammatical errors; specification of metric units; and revisions to provide clarity and consistency. They impose no new requirements and make no substantive changes to the regulations. The revisions do not involve any provisions that would impose backfits as defined in 10 CFR chapter I, or would be inconsistent with the issue finality provisions in 10 CFR part 52. For these reasons, the issuance of the rule in final form would not constitute backfitting. Therefore, a backfit analysis was not prepared.
Organization and functions (Government Agencies).
Administrative practice and procedure, Antitrust, Byproduct material, Classified information, Environmental protection, Nuclear materials, Nuclear power plants and reactors, Penalties, Sex discrimination, Source material, Special nuclear material, Waste treatment and disposal.
Criminal penalties, Government contracts, Hazardous materials transportation, Nuclear materials, Reporting and recordkeeping requirements, Source material, Uranium.
Antitrust, Classified information, Criminal penalties, Fire protection, Intergovernmental relations, Nuclear power plants and reactors, Radiation protection, Reactor siting criteria, Reporting and recordkeeping requirements.
Administrative practice and procedure, Environmental impact statement, Nuclear materials, Nuclear power plants and reactors, Reporting and recordkeeping requirements.
Administrative practice and procedure, Antitrust, Backfitting, Combined license, Early site permit, Emergency planning, Fees, Inspection, Limited work authorization, Nuclear power plants and reactors, Probabilistic risk assessment, Prototype, Reactor siting criteria, Redress of site, Reporting and recordkeeping requirements, Standard design, Standard design certification.
Criminal penalties, Hazardous materials transportation, Material control and accounting, Nuclear materials, Packaging and containers, Radiation protection, Reporting and recordkeeping requirements, Scientific equipment, Security measures, Special nuclear material.
Criminal penalties, Export, Hazardous materials transportation, Import, Nuclear materials, Nuclear power plants and reactors, Reporting and recordkeeping requirements, Security measures.
Nuclear power plants and reactors, Reactor siting criteria.
For the reasons set out in the preamble and under the authority of the Atomic Energy Act of 1954, as amended; the Energy Reorganization Act of 1974, as amended; and 5 U.S.C. 552 and 553, the NRC is adopting the following amendments to 10 CFR parts 1, 2, 40, 50, 51, 52, 70, 73, and 100.
Atomic Energy Act secs. 23, 29, 161, 191 (42 U.S.C. 2033, 2039, 2201, 2241); Energy Reorganization Act secs. 201, 203, 204, 205, 209 (42 U.S.C. 5841, 5843, 5844, 5845, 5849); 5 U.S.C. 552, 553; Reorganization Plan No. 1 of 1980, 45 FR 40561, June 16, 1980.
Atomic Energy Act secs.161, 181, 191 (42 U.S.C. 2201, 2231, 2241); Energy Reorganization Act sec. 201 (42 U.S.C. 5841); 5 U.S.C. 552; Government Paperwork Elimination Act sec. 1704 (44 U.S.C. 3504 note).
Section 2.101 also issued under Atomic Energy Act secs. 53, 62, 63, 81, 103, 104 (42 U.S.C. 2073, 2092, 2093, 2111, 2133, 2134, 2135); Nuclear Waste Policy Act sec. 114(f) (42 U.S.C. 10143(f)); National Environmental Policy Act sec. 102 (42 U.S.C. 4332); Energy Reorganization Act sec. 301 (42 U.S.C. 5871).
Sections 2.102, 2.103, 2.104, 2.105, 2.321 also issued under Atomic Energy Act secs. 102, 103, 104, 105, 183i, 189 (42 U.S.C. 2132, 2133, 2134, 2135, 2233, 2239). Sections 2.200–2.206 also issued under Atomic Energy Act secs. 161, 186, 234 (42 U.S.C. 2201 (b), (i), (o), 2236, 2282); sec. 206 (42 U.S.C. 5846). Section 2.205(j) also issued under Pub. L. 101–410, as amended by section 3100(s), Pub. L. 104–134 (28 U.S.C. 2461 note). Subpart C also issued under Atomic Energy Act sec. 189 (42 U.S.C. 2239). Section 2.301 also issued under 5 U.S.C. 554. Sections 2.343, 2.346, 2.712 also issued under 5 U.S.C. 557. Section 2.340 also issued under Nuclear Waste Policy Act secs. 135, 141, Pub. L. 97–425, 96 Stat. 2232, 2241 (42 U.S.C. 10155, 10161). Section 2.390 also issued under 5 U.S.C. 552. Sections 2.600–2.606 also issued under sec. 102 (42 U.S.C. 4332). Sections 2.800 and 2.808 also issued under 5 U.S.C. 553. Section 2.809 also issued under 5 U.S.C. 553; Atomic Energy Act sec. 29 (42 U.S.C. 2039). Subpart K also issued under Atomic Energy Act sec. 189 (42 U.S.C. 2239); Nuclear Waste Policy Act sec. 134 (42 U.S.C. 10154). Subpart L also issued under Atomic Energy Act sec. 189 (42 U.S.C. 2239). Subpart M also issued under Atomic Energy Act sec. 184, 189 (42 U.S.C. 2234, 2239). Subpart N also issued under Atomic Energy Act sec. 189 (42 U.S.C. 2239).
(b) These appeals must be made as specified by the provisions of this section, within 25 days after the service of the order. The appeal must be initiated by the filing of a notice of appeal and accompanying supporting brief. Any party who opposes the appeal may file a brief in opposition to the appeal within 25 days after service of the appeal. The supporting brief and any answer must conform to the requirements of § 2.341(c)(3). No other appeals from rulings on requests for hearing are allowed.
(e) Extend the time for the Commission to rule on a petition for review under § 2.341;
Atomic Energy Act secs. 11(e)(2), 62, 63, 64, 65, 81, 161, 181, 182, 183, 186, 193, 223, 234, 274, 275 (42 U.S.C. 2014(e)(2), 2092, 2093, 2094, 2095, 2111, 2113, 2114, 2201, 2231, 2232, 2233, 2236, 2243, 2273, 2282, 2021, 2022); Energy Reorganization Act secs. 201, 202, 206 (42 U.S.C. 5841, 5842, 5846); Government Paperwork Elimination Act sec. 1704 (44 U.S.C. 3504 note); Energy Policy Act of 2005, Pub. L. No. 109–59, 119 Stat. 594 (2005).
Section 40.7 also issued under Energy Reorganization Act sec. 211, Pub. L. 95–601, sec. 10, as amended by Pub. L. 102–486, sec. 2902 (42 U.S.C. 5851). Section 40.31(g) also issued under Atomic Energy Act sec. 122 (42 U.S.C. 2152). Section 40.46 also issued under Atomic Energy Act sec. 184 (42 U.S.C. 2234). Section 40.71 also issued under Atomic Energy Act sec. 187 (42 U.S.C. 2237).
(e) * * *
(2)
Atomic Energy Act secs. 102, 103, 104, 105, 147, 149, 161, 181, 182, 183, 186, 189, 223, 234 (42 U.S.C. 2132, 2133, 2134, 2135, 2167, 2169, 2201, 2231, 2232, 2233, 2236, 2239, 2273, 2282); Energy Reorganization Act secs. 201, 202, 206 (42 U.S.C. 5841, 5842, 5846); Nuclear Waste Policy Act sec. 306 (42 U.S.C. 10226); Government Paperwork Elimination Act sec. 1704 (44 U.S.C. 3504 note); Energy Policy Act of 2005, Pub. L. No. 109–58, 119 Stat. 194 (2005). Section 50.7 also issued under Pub. L. 95–601, sec. 10, as amended by Pub. L. 102–486, sec. 2902 (42 U.S.C. 5851). Section 50.10 also issued under Atomic Energy Act secs. 101, 185 (42 U.S.C. 2131, 2235); National Environmental Policy Act sec. 102 (42 U.S.C. 4332). Sections 50.13, 50.54(dd), and 50.103 also issued under Atomic Energy Act sec. 108 (42 U.S.C. 2138).
Sections 50.23, 50.35, 50.55, and 50.56 also issued under Atomic Energy Act sec. 185 (42 U.S.C. 2235). Appendix Q also issued under National Environmental Policy Act sec. 102 (42 U.S.C. 4332). Sections 50.34 and 50.54 also issued under sec. 204 (42 U.S.C. 5844). Sections 50.58, 50.91, and 50.92 also issued under Pub. L. 97–415 (42 U.S.C. 2239). Section 50.78 also issued under Atomic Energy Act sec. 122 (42 U.S.C. 2152). Sections 50.80—50.81 also issued under Atomic Energy Act sec. 184 (42 U.S.C. 2234).
(d) Notwithstanding the requirements of paragraphs (a) and (b) of this section, and except as specified by this paragraph, no NRC or FEMA review, findings, or determinations concerning the state of offsite emergency preparedness or the adequacy of and capability to implement State and local or utility offsite emergency plans are required prior to issuance of an operating license authorizing only fuel loading or low power testing and training (up to 5 percent of the rated thermal power). * * *
* * * The following paragraphs with the exception of paragraph (r), (s), and (u) of this section are conditions in every combined license issued under part 52 of this chapter, provided, however, that paragraphs (i), (i-1), (j), (k), (l), (m), (n), (q), (w), (x), (y), (z), and (hh) of this section are only applicable after the Commission makes the finding under § 52.103(g) of this chapter.
(e) * * *
(4) * * *
(i) The holder of a facility construction permit subject to this part, combined license (until the Commission makes the finding under 10 CFR 52.103(g)), and manufacturing license who obtains information reasonably indicating that the facility fails to comply with the AEA, as amended, or any applicable regulation, order, or license of the Commission relating to a substantial safety hazard must notify the Commission of the failure to comply through a director or responsible officer or designated person as discussed in paragraph (e)(4)(v) of this section.
(iii) The holder of a facility construction permit subject to this part, combined license, or manufacturing license, who obtains information reasonably indicating that the quality assurance program has undergone any significant breakdown discussed in paragraph (e)(3)(iii)(C) of this section must notify the Commission of the breakdown in the quality assurance program through a director or responsible officer or designated person as discussed in paragraph (e)(4)(v) of this section.
(6)
IV. * * *
F. * * *
2. * * *
a. * * *
(i) For an operating license issued under this part, this exercise must be conducted within 2 years before the issuance of the first operating license for full power (one authorizing operation above 5 percent of rated thermal power) of the first reactor and shall include participation by each State and local government within the plume exposure pathway EPZ and each state within the ingestion exposure pathway EPZ. * * *
IV. * * *
A. * * *
2. * * *
a. Pressure-temperature limits and minimum temperature requirements for the reactor vessel are given in table 1, and are defined by the operating condition (i.e., hydrostatic pressure and leak tests, or normal operation including anticipated operational
b. The pressure-temperature limits identified as “ASME Appendix G limits” in table 1 require that the limits must be at least as conservative as limits obtained by following the methods of analysis and the margins of safety of Appendix G of Section XI of the ASME Code.
c. The minimum temperature requirements given in table 1 pertain to the controlling material, which is either the material in the closure flange of the material in the beltline region with the highest reference temperature. As specified in table 1, the minimum temperature requirements and the controlling material depend on the operating condition (i.e., hydrostatic pressure and leak tests, or normal operation including anticipated operational occurrences), the vessel pressure, whether fuel is in the vessel, and whether the core is critical. The metal temperature of the controlling material, in the region of the controlling material which has the least favorable combination of stress and temperature must exceed the appropriate minimum temperature requirement for the condition and pressure of the vessel specified in table 1.
Atomic Energy Act sec. 161, 1701 (42 U.S.C. 2201, 2297f); Energy Reorganization Act secs. 201, 202, 211 (42 U.S.C. 5841, 5842, 5851); Government Paperwork Elimination Act sec. 1704 (44 U.S.C. 3504 note). Subpart A also issued under National Environmental Policy Act secs. 102, 104, 105 (42 U.S.C. 4332, 4334, 4335); Pub. L. 95–604, Title II, 92 Stat. 3033–3041; Atomic Energy Act sec. 193 (42 U.S.C. 2243). Sections 51.20, 51.30, 51.60, 51.80. and 51.97 also issued under Nuclear Waste Policy Act secs. 135, 141, 148 (42 U.S.C. 10155, 10161, 10168). Section 51.22 also issued under Atomic Energy Act sec. 274 (42 U.S.C. 2021) and under Nuclear Waste Policy Act sec. 121 (42 U.S.C. 10141). Sections 51.43, 51.67, and 51.109 also issued under Nuclear Waste Policy Act sec. 114(f) (42 U.S.C. 10134(f)).
(c) * * *
(9) Issuance of an amendment to a permit or license for a reactor under part 50 or part 52 of this chapter that changes a requirement or issuance of an exemption from a requirement, with respect to installation or use of a facility component located within the restricted area, as defined in part 20 of this chapter; or the issuance of an amendment to a permit or license for a reactor under part 50 or part 52 of this chapter that changes an inspection or a surveillance requirement; provided that:
Atomic Energy Act secs. 103, 104, 147, 149, 161, 181, 182, 183, 185, 186, 189, 223, 234 (42 U.S.C. 2133, 2201, 2167, 2169, 2232, 2233, 2235, 2236, 2239, 2282); Energy Reorganization Act secs. 201, 202, 206, 211 (42 U.S.C. 5841, 5842, 5846, 5851); Government Paperwork Elimination Act sec. 1704 (44 U.S.C. 3504 note); Energy Policy Act of 2005, Pub. L. 109–58, 119 Stat. 594 (2005).
(b) * * *
(2) * * *
(i) Propose major features of the emergency plans, in accordance with the pertinent standards of 10 CFR 50.47 and the requirements of appendix E to 10 CFR part 50 of this chapter, such as the exact size and configuration of the emergency planning zones, for review and approval by the NRC, in consultation with the Federal Emergency Management Agency (FEMA) in the absence of complete and integrated emergency plans; or
(ii) Propose complete and integrated emergency plans for review and approval by the NRC, in consultation with FEMA. In accordance with the applicable standards of 10 CFR 50.47 and the requirement of appendix E to 10 CFR part 50 of this chapter. To the extent approval of emergency plans sought, the application must contain the information required by § 50.33(g) and (j) of this chapter.
* * * The Commission shall determine, after consultation with FEMA, whether the information required of the applicant by § 52.17(b)(1) shows that there is not significant impediment to the development of emergency plans that cannot be mitigated or eliminated by measures proposed by the applicant, whether any major features of emergency plans submitted by the applicant under § 52.17(b)(2)(i) are acceptable in accordance with the applicable standards of 10 CFR 50.47 and the requirements of appendix E to 10 CFR part 50 of this chapter, and whether any emergency plans submitted by the applicant under § 52.17(b)(2)(ii) provide reasonable assurance that adequate protective measures can and will be taken in the event of a radiological emergency.
(b) * * *
(4) * * * The application must identify changes to the emergency plans or major features of emergency plans that have been incorporated into the proposed facility emergency plans and that constitute or would constitute a reduction in effectiveness under § 50.54(q) of this chapter.
* * * All hearings on manufacturing licenses are governed by the hearing procedures contained in 10 CFR part 2, subparts C, E, G, L, and N.
Atomic Energy Act secs. 51, 53, 161, 182, 183, 193, 223, 234 (42 U.S.C. 2071, 2073, 2201, 2232, 2233, 2243, 2273, 2282, 2297f); secs. 201, 202, 204, 206, 211 (42 U.S.C. 5841, 5842, 5845, 5846, 5851); Government Paperwork Elimination Act sec. 1704 (44 U.S.C. 3504 note); Energy Policy Act of 2005, Pub. L. No. 109–58, 119 Stat. 194 (2005).
Sections 70.1(c) and 70.20a(b) also issued under secs. 135, 141, Pub. L. 97–425, 96 Stat. 2232, 2241 (42 U.S.C. 10155, 10161).
Section 70.21(g) also issued under Atomic Energy Act sec. 122 (42 U.S.C. 2152). Section 70.31 also issued under Atomic Energy Act sec. 57(d) (42 U.S.C. 2077(d)). Sections 70.36 and 70.44 also issued under Atomic Energy Act sec. 184 (42 U.S.C. 2234). Section 70.81 also issued under Atomic Energy Act secs. 186, 187 (42 U.S.C. 2236, 2237). Section
(f) * * *
(2)
Atomic Energy Act secs. 53, 147, 161, 223, 234, 1701 (42 U.S.C. 2073, 2167, 2169, 2201, 2273, 2282, 2297(f), 2210(e)); Energy Reorganization Act sec. 201, 204 (42 U.S.C. 5841, 5844); Government Paperwork Elimination Act sec. 1704, 112 Stat. 2750 (44 U.S.C. 3504 note); Energy Policy Act of 2005, Pub. L. 109–58, 119 Stat. 594 (2005).
Section 73.1 also issued under Nuclear Waste Policy Act secs. 135, 141 (42 U.S.C, 10155, 10161). Section 73.37(f) also issued under sec. 301, Pub. L. 96–295, 94 Stat. 789 (42 U.S.C. 5841 note).
(a) Uranium-235 contained in uranium enriched to less than 20 percent in the U–235 isotope.
(b) Special nuclear material which is not readily separable from other radioactive material and which has a total external radiation level in excess of 1 Gray (100 Rad) per hour at a distance of 1 meter (3.3 feet) from any accessible surface without intervening shielding.
Atomic Energy Act secs. 103, 104, 161, 182 (42 U.S.C. 2133, 2134, 2201, 2232); Energy Reorganization Act secs. 201, 202 (42 U.S.C. 5841, 5842); Government Paperwork Elimination Act sec. 1704 (44 U.S.C. 3504 note).
(b) The nature and proximity of man-related hazards (e.g., airports, dams, transportation routes, military and chemical facilities) must be evaluated to establish site characteristics for use in determining whether a plant design can accommodate commonly occurring hazards, and whether the risk of other hazards is very low.
(d) The physical characteristics of the site, including meteorology, geology, seismology, and hydrology must be evaluated and site characteristics established such that potential threats from such physical characteristics will pose no undue risk to the type of facility proposed to be located at the site;
(e) Potential hazards associated with nearby transportation routes, industrial and military facilities must be evaluated and site characteristics established such that potential hazards from such routes and facilities will pose no undue risk to the type of facility proposed to be located at the site;
The investigations described in this appendix are within the scope of investigations permitted by § 50.10(a)(2)(ii) of this chapter.
For the Nuclear Regulatory Commission.
Office of the Under Secretary of Defense for Personnel and Readiness/Office of the Deputy Assistant Secretary of Defense for Military Personnel Policy, DoD.
Final rule.
This final rule establishes policy, assigns responsibilities, and prescribes procedures for carrying out the Post-9/11 GI Bill. It establishes policy for the use of supplemental educational assistance (hereafter referred to as “kickers”) for Service members with critical skills or specialties, or for members serving additional service; for authorizing the transferability of education benefits (TEB); and the DoD Office of the Actuary to perform determinations in support of DoD funding responsibilities.
Robert Clark, (703) 697–9267.
This rule will provide the mechanism to implement the Secretary of Defense authorities with regard to Supplemental Educational Benefits (Kickers) and transferability of educational benefits to family members to aid recruiting and retention of the Armed Forces under chapter 33 38 U.S.C. chapter 33, and enable the Secretary of Defense to establish policy, assign responsibilities, and prescribe procedures for such authorities.
This rule establishes policy, assigns responsibilities, and prescribes procedures for carrying out the Post-9/11 GI Bill, as codified in 38 U.S.C. chapter 33. It establishes policy for the use of supplemental educational assistance “kickers”, for members with critical skills or specialties, or for members serving additional service; for authorizing the transferability of education benefits; and for the DoD Education Benefits Fund Board of Actuaries to perform determinations in support of DoD funding responsibilities for “kickers.”
There is no cost to the public. Administrative costs to the Department of Defense for implementation of the authorities under this rule are negligible. Workload will be accomplished with existing staffing and be integrated into normal business. There will be no new costs for supplemental educational assistance, or “kickers”, since the Services will use existing programmed and budgeted resources currently dedicated to Montgomery GI Bill (MGIB) “kickers”. Benefits of “kickers” should parallel those of the existing MGIB “kickers”, which give the Services the ability to channel “high-quality” youth into critical “hard-to-fill” specialties. Transferability of educational benefits to family members will aid recruiting and retention of the Armed Forces.
The Department of Defense published an interim final rule on June 5, 2009 (74 FR 30212–30220) with a request for comments. The following two comments were received:
It has been certified that 32 CFR part 65 does not:
(1) Have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy; a section 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 these Executive Orders.
It has been certified that 32 CFR part 65 does not contain a Federal mandate that may result in expenditure by State, local and tribal governments, in aggregate, or by the private sector, of $100 million or more in any one year.
It has been certified that 32 CFR part 65 is not subject to the Regulatory Flexibility Act (5 U.S.C. 601) because it would not, if promulgated, have a significant economic impact on a substantial number of small entities.
It has been certified that 32 CFR part 65 does not impose reporting or recordkeeping requirements under the Paperwork Reduction Act of 1995.
It has been certified that 32 CFR part 65 does not have federalism implications, as set forth in Executive Order 13132. This rule does not have substantial direct effects on:
(1) The States;
(2) The relationship between the National Government and the States; or
(3) The distribution of power and responsibilities among the various levels of Government.
Armed forces, Education.
Accordingly 32 CFR part 65 is revised to read as follows:
38 U.S.C. chapter 33.
This part:
(a) Establishes policy, assigns responsibilities, and prescribes procedures for implementing DoD authorities and responsibilities for chapter 33 of title 38, United States Code (U.S.C.) (also known and hereafter referred to as “the Post-9/11 GI Bill”)
(b) Establishes policy for the use of supplemental educational assistance (hereafter referred to as “kickers”) for Service members with critical skills or specialties, or for members serving additional service in accordance with 38 U.S.C. 3316.
(c) Establishes policy for authorizing the transferability of education benefits (TEB) in accordance with 38 U.S.C. 3319.
(d) Assigns responsibility to the DoD Office of the Actuary to perform determinations in support of DoD funding responsibilities for 38 U.S.C. chapter 33 in accordance with 10 U.S.C. 183 and 2006.
This part applies to the Office of the Secretary of Defense, the Military Departments (including the Coast Guard at all times, including when it is a Service in the Department of Homeland Security (DHS) by agreement with that Department), the Office of the Chairman of the Joint Chiefs of Staff and the Joint Staff, the Combatant Commands, the Office of the Inspector General of the Department of Defense, the Defense Agencies, the DoD Field Activities, and all other organizational entities within the DoD (hereinafter referred to collectively as the “DoD Components”). Section 65.6 of this part also applies to the Commissioned Corps of the Public Health Service (PHS) by agreement with the Surgeon General, and to the National Oceanic and Atmospheric Administration Commissioned Officer Corps (NOAA Corps) by agreement with the Director, NOAA Corps.
Unless otherwise noted, these terms and their definitions are for the purpose of this part:
It is DoD policy that:
(a) Kickers may be authorized to assist in the recruitment, reserve affiliation, and retention of individuals into skills or specialties in which there are critical shortages or for which it is difficult to recruit or, in the case of critical units, to retain personnel.
(b) Transferability of education benefits may be used to promote recruitment and retention.
(a) The Deputy Assistant Secretary of Defense for Military Personnel Policy (DASD(MPP)), under the authority, direction, and control of the Assistant Secretary of Defense for Readiness and Force Management, shall:
(1) Develop guidance and procedures for implementation and oversight of DoD authorities and responsibilities under the Post-9/11 GI Bill.
(2) Coordinate administrative procedures of the Post-9/11 GI Bill with the Department of Veterans Affairs (VA), and other appropriate DoD and intergovernmental agencies, as applicable.
(3) Review and approve each Military Department plan to use supplemental assistance in accordance with the provisions of 38 U.S.C. 3316.
(4) Establish the standard data elements needed to administer the Post-9/11 GI Bill.
(b) The Under Secretary of Defense (Comptroller) (USD(C))/Chief Financial Officer (CFO) (USD(C)/CFO), Department of Defense shall:
(1) Provide guidance on budgeting, accounting, and funding for the educational benefits program in support of plans established in § 65.6, and for investing the available DoD Education Benefits Fund balance.
(2) In coordination with the DASD(MPP), review and approve the Military Department budget estimates for the supplemental payments in accordance with the provisions of 38 U.S.C. 3316.
(c) The Director, Department of Defense Human Resources Activity (DoDHRA), under the authority, direction, and control of the Under Secretary of Defense for Personnel and Readiness, shall ensure the Director, Defense Manpower Data Center (DMDC) shall:
(1) Replicate Post 9/11 GI Bill eligibility data using the Veterans Affairs and DoD Identity Repository (VADIR) with the DVA as needed and specified.
(i) Maintain personnel information needed by the DVA to determine benefit entitlement.
(ii) Maintain DVA payment and usage data for the Post 9/11 GI Bill program.
(2) [Reserved]
(d) The Secretaries Concerned shall:
(1) Provide implementing guidance within their Department to govern the administration of the Post-9/11 GI Bill consistent with this part and other guidance issued by the DASD(MPP) and the USD(C)/CFO consistent with the needs of the Military Services. This guidance must include Service implementation of kickers and the transfer of unused educational benefits as established in 38 U.S.C. 3319, as outlined in § 65.6.
(2) Ensure that all eligible active duty Service members and members of the Reserve Components are aware that they are automatically eligible for Post-9/11 GI Bill educational assistance upon serving the required active duty time as outlined in 38 U.S.C. 3311.
(3) Ensure that all officers without earlier established eligibility, following commissioning through the Service academies (with the exception of the Coast Guard Academy for individuals who enter into an agreement to service before January 4, 2011) or Reserve Officer Training Corps Scholarship Programs consistent with 10 U.S.C. 2107, are aware that their eligible period of active duty for Post-9/11 GI Bill benefits does not begin until they have completed their statutory obligated active duty service. Ensure that such officers are aware that any active duty service after that obligated period of service may qualify as active duty service for Post-9/11 GI Bill eligibility.
(4) Ensure that all Service members participating in the student loan repayment program in accordance with 10 U.S.C. chapter 109 are aware that their service counted pursuant to 10 U.S.C. chapter 109 does not count as qualifying active duty service for Post-9/11 GI Bill eligibility. Ensure that such Service members are aware that any service after that obligated period of service may qualify as active duty service for Post-9/11 GI Bill eligibility.
(5) Authorize kickers for recruitment and retention of individuals with critical skills or in programs that are hard to recruit or retain in accordance with 38 U.S.C. 3316, and advise the DASD(MPP) of such approval.
(6) Budget for and transfer funds to support the kickers, in accordance with § 65.6 of this part and guidance issued by the USD(C)/CFO.
(7) Ensure pre-separation or release from active duty counseling on Post-9/11 GI Bill benefits to active duty members and members of the Reserve Components with qualifying active duty service and document this counseling accordingly.
(8) Promulgate guidance for their Service(s) to administer the transferability of unused education entitlements to family members to support recruiting and retention in accordance with § 65.6.
(9) Ensure maintenance of records for individuals who receive kickers in accordance with 38 U.S.C. 3316. Provide those records to the DMDC and VA.
(10) Report all qualifying active duty pursuant to DoD Manual 7730.54–M–V1, “Reserve Component Common Personnel Data System (RCCPDS)” (see
(11) Direct use of DoD standard data elements and codes established by DoD Instruction 1336.05, “Automated Extract of Active Duty Military Personnel Records” (see
(a)
(b)
(2)
(3)
(4)
(c)
(1)
(i) Has at least 6 years of service in the Military Services (active duty or Selected Reserve), NOAA Corps, or PHS on the date of approval and agrees to serve 4 additional years in the Military Services, NOAA Corps, or PHS from the date of election.
(ii) Has at least 10 years of service in the Military Services (active duty or Selected Reserve), NOAA Corps, or PHS on the date of approval, is precluded by either standard policy (Service or DoD) or statute from committing to 4 additional years, and agrees to serve for the maximum amount of time allowed by such policy or statute.
(iii) Is or becomes retirement eligible during the period from August 1, 2009, through July 31, 2012, and agrees to serve the additional period, if any, specified in paragraphs (c)(1)(iii)(A) through (c)(1)(iii)(D) of this section. A Service member is considered to be retirement eligible if he or she has completed 20 years of active Federal service or 20 qualifying years as computed pursuant to 10 U.S.C. 12732. This paragraph will no longer be in effect on August 1, 2013, and on or after that date all members must comply with paragraphs (c)(1)(i) or (c)(1)(ii) of this section to be eligible for transfer of unused education benefits to family members.
(A) For individuals eligible for retirement on August 1, 2009, no additional service is required.
(B) For individuals eligible for retirement after August 1, 2009, and
(C) For individuals eligible for retirement on or after August 1, 2010, and before August 1, 2011, 2 years of additional service is required.
(D) For individuals eligible for retirement on or after August 1, 2011, and before August 1, 2012, 3 years of additional service is required.
(iv) The provisions of paragraph (c)(1)(iii) of this section will apply to Service members recalled to active duty under the provisions of 10 U.S.C. 688 or members of the Individual Ready Reserve ordered to active duty under the provisions of 10 U.S.C. 12301(d) only when the active duty is for a period of at least 90 days.
(2)
(ii) For purposes of this provision, the definition of spouse and child are as codified in 38 U.S.C. 101. Confirmation of family members will be made using the DEERS.
(iii) Once an individual has designated a child as a transferee, a child's subsequent marriage will not affect his or her eligibility to receive the educational benefit; however, the individual retains the right to revoke or modify the transfer at any time.
(iv) Once an individual has designated a spouse as a transferee, subsequent divorce will not affect the transferee's eligibility to receive educational benefits; however, the eligible individual retains the right to revoke or modify the transfer at any time.
(3)
(i) The months of Post-9/11 GI Bill unused benefits available.
(ii) 36 months.
(4)
(ii) Commencement of use by a family member is subject to these conditions:
(A) A spouse may start to use the benefit only after the individual making the transfer has completed at least 6 years of service in the Military Services, NOAA Corps, or PHS.
(B) A child may start to use the benefit after the individual making the transfer:
(
(
(5)
(i) Designate the family member or members to whom such entitlement is being transferred.
(ii) Designate the number of months of such entitlement to be transferred to each family member.
(iii) Specify the period for which the transfer shall be effective for each family member. The effective period must be on or after the date of designation.
(6)
(ii)
(
(
(B) The modification or revocation of the transfer of entitlement shall be made by submitting notice of the action to both the Secretary of the Military Department concerned and the Secretary of Veterans Affairs. Additions, modifications, or revocations made while in the Military Services, NOAA Corps, or PHS will be made through the TEB Web site as described in paragraph (c)(8) of this section. Modifications or revocations after separation from the Military Services, NOAA Corps, or PHS will be accomplished through VA.
(7)
(ii) Paragraph (c)(7)(i) of this section shall not apply to an individual who fails to complete service agreement due to:
(A) His or her death.
(B) Discharge or release from active duty or the Selected Reserve for a medical condition that pre-existed his or her service and was not service-connected.
(C) Discharge or release from active duty or the Selected Reserve for hardship as determined by the Secretary of the Military Department concerned.
(D) Discharge or release from active duty or the Selected Reserve for a physical or mental condition, not a disability, that did not result from his or her willful misconduct, but did interfere with the performance of duty.
(iii) The transferor is also considered to have completed his or her service agreement as a result of being discharged for a disability or a reduction in force or force shaping.
(iv) The Secretaries of the Military Departments may promulgate guidance regarding waiver of the military service obligation agreed to consistent with paragraph (c)(1) of this section if the individual revokes all transfers and no benefits have been used.
(8)
(9)
(i) The manner of verifying and documenting the additional service commitment, if any, consistent with paragraph (c)(1) of this section, to be authorized to transfer education benefits.
(ii) The manner of determining eligibility to authorize the transfer of education benefits as allowed in paragraphs (c)(1)(i), (c)(1)(ii), or (c)(1)(iii) of this section.
Coast Guard, DHS.
Temporary final rule.
The Coast Guard is establishing a Regulated Navigation Area (RNA) on the Illinois River. This Temporary Final Rule stipulates operational requirements and places navigational and operational restrictions on all vessels transiting the Illinois River from Mile Marker 240.0 to Mile Marker 271.4. This RNA is necessary to protect the general public, vessels, and tows from the hazards associated with obstructions in the Marseilles Lock canal, recovery efforts related to the restoration of the Marseilles Dam, and salvage operations being conducted in its vicinity.
This rule will be enforced with actual notice from May 4, 2013, until June 7, 2013. This rule is effective in the Code of Federal Regulations from June 7, 2013 until June 30, 2013.
Documents mentioned in this preamble are part of docket USCG–2013–0344. To view documents mentioned in this preamble as being available in the docket, go to
If you have questions on this temporary rule, contact or email MST1 Joseph McCollum, U.S. Coast Guard Sector Lake Michigan, at 414–747–7148 or
On April 18, 2013, in light of dangerously high water conditions, the Coast Guard established a temporary safety zone on the Illinois River from Mile Marker 187.2 to Mile Marker 285.9 (USCG–2013–0299). The safety zone restricted recreational and commercial vessel transit in the zone without the permission of the Captain of the Port Lake Michigan. The safety zone was effective and enforced from April 18 to 30, 2013. Because of the emergent nature of the flooding, the Coast Guard did not solicit comments before establishing this temporary safety zone.
On April 26, 2013, in order to facilitate commerce and in consideration of salvage operations around the Marseilles Dam, the Coast Guard established a temporary safety zone (USCG–2013–0323) that authorized commercial vessels to transit the Illinois River except from Mile Marker 244 to Mile Marker 252. Recreational vessels were prohibited from Mile Marker 187.2 to 285.9. Because of the emergent nature of the flooding, the Coast Guard also did not solicit comments prior to establishing this temporary safety zone.
On April 29, 2013, the Coast Guard issued a third TFR that established a safety zone from Mile Marker 231.0 to Mile Marker 271.4 on the Illinois River (USCG–2013–0334). This safety zone restricted vessel traffic within the portion of the Illinois River deemed to be affected by both salvage operations and the potential for structural failure at the Marseilles Dam.
Now, the Coast Guard is issuing this rule without prior notice and opportunity to comment pursuant to authority under section 4(a) of the Administrative Procedure Act (APA) (5 U.S.C. 553(b)). This provision authorizes an agency to issue a rule without prior notice and opportunity to comment when the agency for good cause finds that those procedures are “impracticable, unnecessary, or contrary to the public interest.” Under 5 U.S.C. 553(b)(B), the Coast Guard finds that good cause exists for not publishing a notice of proposed rulemaking (NPRM) with respect to this rule because doing so would be impracticable and contrary to the public interest. The Coast Guard is issuing this rule in response to an immediate and emergency situation that involves salvage and port recovery operations in the vicinity of the Marseilles Lock and Dam. Delaying the effective date of this rule to wait for a comment period to run would be both impracticable and contrary to the public interest because it would inhibit the Coast Guard's ability to protect persons and vessels from the hazards, which are discussed further below, associated with the salvage and port recovery operations in the vicinity of the Marseilles Lock and Dam.
Although the Coast Guard is issuing this rule without prior notice and opportunity to comment, the Coast Guard consulted with towing vessel industry stakeholders to help determine the tow restrictions and operating parameters in this RNA.
Under 5 U.S.C. 553(d)(3), the Coast Guard finds that good cause exists for making this rule effective less than 30 days after publication in the
The legal basis for the rule is the Coast Guard's authority to establish RNAs and limited access areas: 33 U.S.C. 1231; 46 U.S.C. Chapter 701, 3306, 3703; 50 U.S.C. 191, 195; 33 CFR 1.05–1, 6.04–1, 6.04–6, 160.5; Pub. L. 107–295, 116 Stat. 2064; Department of Homeland Security Delegation No. 0170.1.
Heavy and extended periods of rain during the first half of the month of April resulted in dangerously high waters within the Illinois River, bringing excessive debris, rapidly-flowing water, and complicating vessel navigation. These high and rapidly-moving waters also threatened to
On April 18, 2013, seven barges broke loose from their tow during an approach to the Marseilles Lock canal and lodged against the Marseilles Dam. Salvage operations are underway to recover the barges and structural surveys of the dam are being conducted.
On April 29, 2013, the U.S. Army Corps of Engineers released Navigation Notice IW 13–12 declaring lock restrictions for vessel traffic between mile markers 231.0 to 271.4 except for those vessels assisting in the salvage operation or the dam recovery efforts at Marseilles Dam. Currently, both commercial and recreational vessels remain within portions of the Illinois River, which could either be affected by the failure of the Marseilles Dam or could impede the salvage operations at work there.
In an effort to ensure the safety of all vessels that might be either affected by the failure of the Marseilles Dam or could impede the salvage operations being conducted, the Ninth District Commander is issuing this rule. Once this RNA is put into effect, the enforcement of the temporary safety zones discussed previously will be suspended.
The Coast Guard's Ninth District Commander has established the restrictions, stipulations, and directions named within this regulation in response to the safety risks presented by the high water conditions, the potentially compromised dam, and ongoing salvage operations. The safety risks associated with these conditions include loss of vessel control, sinking, swamping, collisions, and allisions.
The Coast Guard's Ninth District Commander has determined that an RNA is necessary to mitigate the aforementioned safety risks. Thus, this rule establishes an RNA that encompasses all waters of the Illinois River from the gates of the Dresden Lock and Dam at Mile Marker 271.4 to Mile Marker 240.0. This rule will place restrictions on vessels entering, transiting, moving within, or departing the waters within the regulated navigation area.
In order to ensure the safety of those vessels and persons transiting the portion of the Illinois River that could be affected by obstructions in the waterway or salvage operations, restrictions will be in place from the gates of the Dresden Lock and Dam at Mile Marker 271.4 to Mile Marker 240.0 so that towing vessels must configure tows within designated parameters. Vessels may not transit under certain ambient weather and water conditions and without a minimum of 240 horsepower for every barge in the tow and an assist tug present. Also, towing vessels are not authorized to break up tows within certain portions of the River. Furthermore, vessels in transit must contact the Ninth District Commander's on-scene representative in order to proceed through the Marseilles Lock and Dam. This rule is effective and will be enforced from May 4, 2013, until June 30, 2013.
The Ninth Coast Guard District Commander will notify the public that this RNA is being enforced by all appropriate means, including publication in the
All persons and vessels shall comply with the instructions of the Ninth District Commander, the Captain of the Port Lake Michigan, or designated on-scene representative. Entry into, transiting, or anchoring within the RNA is prohibited unless authorized by the Ninth District Commander, the Captain of the Port Lake Michigan, or a designated on-scene representative. The Ninth District Commander, the Captain of the Port Lake Michigan, and the designated on-scene representative may be contacted via VHF Channel 16, at (630) 336–0300, or by contacting the Coast Guard Sector Lake Michigan Command Center at (414) 747–7182.
We developed this rule after considering numerous statutes and executive orders related to rulemaking. Below we summarize our analyses based on these statutes and executive orders.
This rule is not a significant regulatory action under section 3(f) of Executive Order 12866, Regulatory Planning and Review, as supplemented by Executive Order 13563, Improving Regulation and Regulatory Review, and does not require an assessment of potential costs and benefits under section 6(a)(3) of Executive Order 12866 or under section 1 of Executive Order 13563. The Office of Management and Budget has not reviewed it under those Orders. It is not “significant” under the regulatory policies and procedures of the Department of Homeland Security (DHS).
We conclude that this rule is not a significant regulatory action because we anticipate that it will have minimal impact on the economy, will not interfere with other agencies, will not adversely alter the budget of any grant or loan recipients, and will not raise any novel legal or policy issues. The regulated navigation area created by this rule will be limited in scope and enforced for just two months. Under certain conditions, moreover, vessels may still transit through the regulated navigation area when permitted by the Ninth District Commander.
The Regulatory Flexibility Act of 1980 (RFA), 5 U.S.C. 601–612, as amended, requires federal agencies to consider the potential impact of regulations on small entities during rulemaking. The term “small entities” comprises small businesses, not-for-profit organizations that are independently owned and operated and are not dominant in their fields, and governmental jurisdictions with populations of less than 50,000. The Coast Guard certifies under 5 U.S.C. 605(b) that this rule will not have a significant economic impact on a substantial number of small entities.
This rule will affect the following entities, some of which might be small entities: the owners or operators of vessels intending to transit or anchor in portions of the Illinois River during the time that this zone is enforced. This RNA will not have a significant economic impact on a substantial number of small entities for the following reasons: this RNA will be effective, and thus subject to enforcement, for just two months. Traffic may be allowed to pass through the RNA with the appropriate authority. Before the enforcement of the zone, the Coast Guard will issue local Broadcast Notice to Mariners.
Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Pub. L. 104–121), we want to assist small entities in understanding this rule so they can better evaluate its effects on them. If the rule would affect your small business, organization, or governmental jurisdiction and you have questions concerning its provisions or options for compliance, please contact the person listed in the
Small businesses may send comments on the actions of Federal employees who enforce, or otherwise determine compliance with, Federal regulations to the Small Business and Agriculture Regulatory Enforcement Ombudsman and the Regional Small Business Regulatory Fairness Boards. The
This rule will not call for a new collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501–3520).
A rule has implications for federalism under Executive Order 13132, Federalism, if it has a substantial direct effect on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government. We have analyzed this rule under that Order and determined that this rule does not have implications for federalism.
The Coast Guard respects the First Amendment rights of protesters. Protesters are asked to contact the person listed in the
The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531–1538) requires Federal agencies to assess the effects of their discretionary regulatory actions. In particular, the Act addresses actions that may result in the expenditure by a State, local, or tribal government, in the aggregate, or by the private sector of $100,000,000 (adjusted for inflation) or more in any one year. Though this rule will not result in such an expenditure, we do discuss the effects of this rule elsewhere in this preamble.
This rule will not cause a taking of private property or otherwise have taking implications under Executive Order 12630, Governmental Actions and Interference with Constitutionally Protected Property Rights.
This rule meets applicable standards in sections 3(a) and 3(b)(2) of Executive Order 12988, Civil Justice Reform, to minimize litigation, eliminate ambiguity, and reduce burden.
We have analyzed this rule under Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks. This rule is not an economically significant rule and does not create an environmental risk to health or risk to safety that may disproportionately affect children.
This rule does not have tribal implications under Executive Order 13175, Consultation and Coordination with Indian Tribal Governments, because it does not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes.
This action is not a “significant energy action” under Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use.
This rule does not use technical standards. Therefore, we did not consider the use of voluntary consensus standards.
We have analyzed this rule under Department of Homeland Security Management Directive 023–01 and Commandant Instruction M16475.lD, which guide the Coast Guard in complying with the National Environmental Policy Act of 1969 (NEPA) (42 U.S.C. 4321–4370f), and have determined that this action is one of a category of actions that do not individually or cumulatively have a significant effect on the human environment. This rule involves the establishment of a regulated navigation area, and, therefore it is categorically excluded from further review under paragraph 34(g) of Figure 2–1 of the Commandant Instruction. An environmental analysis checklist supporting this determination and a Categorical Exclusion Determination are available in the docket where indicated under
Harbors, Marine safety, Navigation (water), Reporting and record keeping requirements, Security measures, Waterways.
For the reasons discussed in the preamble, the Coast Guard amends 33 CFR parts 165 as follows:
33 U.S.C. 1231; 46 U.S.C. Chapters 701, 3306, 3703; 50 U.S.C. 191, 195; 33 CFR 1.05–1, 6.04–1, 6.04–6, and 160.5; Pub. L. 107–295, 116 Stat. 2064; Department of Homeland Security Delegation No. 0170.1.
(a)
(b)
(c)
(2) Vessels transiting within the RNA with tow must have:
(i) A minimum of 240 horsepower for every barge in the tow.
(ii) A minimum of 1000 feet of visibility.
(iii) An assist tug arranged for passage past the sunken barge at the east entrance to the Marseilles Lock Canal.
(iv) Tow configurations made out to no more than 2 barges wide and 4 barges long.
(v) Tow dimensions of less than 70 feet in width and 800 feet in length. These dimensions do not include the towing vessel.
(vi) Make way with at least 2 mph speed of advance for the entire transit from Mile Marker 246 to Mile Marker 250.
(3) Vessels transiting the RNA with tow are prohibited from breaking tows between Mile Marker 240.6 to Mile Marker 244.4 and between Mile Marker 246 to Mile Marker 250.
(4) Vessels transiting the RNA are prohibited from making way when under the following conditions:
(i) Wind speeds exceeding 25 mph.
(ii) The flow rate of the Illinois River at the Marseilles Dam exceeds 23,000 CFS.
(5) Vessels must contact the Ninth District Commander's on-scene representative at (630) 336–0300 prior to processing through Lock and Dams within the RNA as follows:
(i) Northbound vessels must contact the Ninth District Commander's on-scene representative at (630) 336–0300 1 hour prior to anticipated lockage at Marseilles Lock and Dam. A secondary contact to the Ninth District Commander's on-scene representative must be made prior to Mile Marker 240.6 to obtain a lockage authorization code.
(ii) Southbound vessels must contact the Ninth District Commander's on-scene representative at (630) 336–0300 1 hour prior to anticipated lockage at Marseilles Lock and Dam. A secondary contact to the Ninth District Commander's on-scene representative must be made prior to Mile Marker 250 to obtain a lockage authorization code.
(6) Vessel operators given permission to enter, operate, or transit within the regulated navigations area must comply with all directions given to them by the Ninth District Commander, Captain of the Port, Lake Michigan, or a designated on-scene representative. The “on-scene representative” of the Ninth District Commander will be standing watch at the Marseilles Lock and is any Coast Guard commissioned, warrant or petty officer who has been designated by the Ninth District Commander to act on his behalf.
(d)
(2) Vessels with tow transiting southbound through the RNA may break their tow beyond Mile Marker 240.6.
(e)
(f)
(g)
Coast Guard, DHS.
Temporary final rule.
The Coast Guard is establishing a temporary safety zone on the waters of the Illinois River starting at Mile Marker 246.9 and extending 600 yards upstream of the Marseilles Dam to Mile Marker 247.2. This zone is intended to restrict the movement of vessels due to the salvage operations and repair efforts at the Marseilles Dam. This safety zone is necessary to protect the general public, vessels, and tows from the hazards associated with those repair and salvage operations.
This rule is effective in the CFR June 7, 2013 through November 30, 2013. This rule is effective for purposes of enforcement with actual notice on May 17, 2013. This rule will remain in effect until November 30, 2013.
Documents mentioned in this preamble are part of docket [USCG–2013–0405]. To view documents mentioned in this preamble as being available in the docket, go to
If you have questions on this rule, contact MST1 Joseph McCollum, Prevention Department, Coast Guard Sector Lake Michigan, Milwaukee, WI at (414) 747–7148 or by email at
On April 18, 2013, in light of dangerously high water conditions, the Coast Guard established a temporary safety zone on the Illinois River from Mile Marker 187.2 to Mile Marker 285.9 (USCG–2013–0299). The safety zone restricted recreational and commercial vessel transits in the zone without the permission of the Captain of the Port Lake Michigan. Because of the emergent nature of the flooding, the Coast Guard did not solicit comments before establishing this temporary safety zone.
On April 26, 2013, in order to facilitate commerce and in consideration of salvage operations around the Marseilles Dam, the Coast Guard established a temporary safety zone (USCG–2013–0323) that authorized commercial vessels to transit the Illinois River except from Mile Marker 244 to Mile Marker 252. Recreational vessels were prohibited from Mile Marker 187.2 to 285.9. Because of the emergent nature of the flooding, the Coast Guard also did not solicit comments prior to establishing this temporary safety zone.
On April 29, 2013, to further ensure the safety of those vessels transiting in the vicinity of the Marseilles Dam and the salvage operations there, the Coast Guard established a temporary safety zone (USCG–2013–0334) that restricted access on the Illinois River from the gates of the Dresden Lock and Dam at Mile Marker 271.4 to the gates of the Starved Rock Lock and Dam at Mile Marker 231.0. Because of the emergent nature of the flooding, the Coast Guard also did not solicit comments prior to establishing this temporary safety zone.
On May 3, 2013 the Coast Guard established an RNA on the Illinois River from the gates of the Dresden Lock and Dam at Mile Marker 271.4 to Mile Marker 240.0 (USCG–2013–0344). This RNA was established to ensure the safety of those vessels transiting in the vicinity of the Marseilles Dam and the Salvage Operation there. Enforcement of the prior safety zones were suspended.
Now the Coast Guard is issuing a fifth temporary final rule without prior notice and opportunity to comment pursuant to authority under section 4(a) of the Administrative Procedure Act (APA) (5 U.S.C. 553(b)). This provision authorizes an agency to issue a rule without prior notice and opportunity to comment when the agency for good cause finds that those procedures are “impracticable, unnecessary, or contrary to the public interest.” Under 5 U.S.C. 553(b)(B), the Coast Guard finds that good cause exists for not publishing a notice of proposed rulemaking (NPRM) with respect to this rule because doing so would be impracticable and contrary to the public interest. The Coast Guard is issuing this rule in response to an immediate and hazardous situation which involves: salvage operations in the vicinity of the Marseilles Dam. Thus, delaying the effective date of this rule to wait for a comment period to run would be both impracticable and contrary to the public interest because it would inhibit the Coast Guard's ability to protect persons and vessels from the hazards, which are discussed further below, associated with the salvage operations and repair efforts at the Marseilles Dam.
Under 5 U.S.C. 553(d)(3), the Coast Guard finds that good cause exists for making this rule effective less than 30 days after publication in the
The legal basis for the rule is the Coast Guard's authority to establish regulated navigation areas and limited access areas: 33 U.S.C. 1231; 46 U.S.C. Chapter 701, 3306, 3703; 50 U.S.C. 191, 195; 33 CFR 1.05–1, 6.04–1, 6.04–6, 160.5; Pub. L. 107–295, 116 Stat. 2064; Department of Homeland Security Delegation No. 0170.1.
Heavy and extended periods of rain during the first half of the month of April resulted in dangerously high waters within the Illinois River, bringing excessive debris, rapidly-flowing water, and complicating vessel navigation. These high and rapidly-moving waters also threatened to damage critical infrastructure including river levees.
Since April 18, 2013, seven barges broke loose from their tow during an approach to the Marseilles Lock canal and lodged against the Marseilles Dam. Salvage operations are underway to recover the barges. The salvage operations involve the use of multiple barges, cranes, vessels, and heavy equipment. A survey of the Marseilles Dam found that two gates had been severely damaged. Thus, in addition to the current hazardous conditions involved in the salvage operation, the Captain of the Port is issuing this temporary final rule for an extended effective period to allow for the repair efforts at the Marseilles Dam and the hazardous conditions which will be present during that time.
The safety risks associated with these conditions include collisions among heavy equipment, barges, and work vessels involved in the salvage and repair effort and passing vessel traffic, as well as damage or injury caused by falling debris.
The Captain of the Port, Lake Michigan, has determined that a safety zone is necessary to mitigate the aforementioned safety risks. Thus, this rule establishes a safety zone that encompasses all waters of the Illinois River starting at Mile Marker 246.9 and extending 600 yards upstream of the Marseilles Dam to Mile Marker 247.2. This rule will restrict vessels that intend to transit this portion of the Illinois River. This rule is effective and will be enforced with actual notice from May 17, 2013 until November 30, 2013.
The Captain of the Port Lake Michigan will notify the public that this safety zone is being enforced by all appropriate means to the affected segments of the public including publication in the
All persons and vessels shall comply with the instructions of the Captain of the Port, Lake Michigan, or his or her designated on-scene representative. Entry into, transiting, or anchoring within the safety zone is prohibited unless authorized by the Captain of the Port, Lake Michigan, or his or her designated on-scene representative. The Captain of the Port, Lake Michigan, or his or her designated on-scene representative may be contacted via VHF Channel 16 or by contacting the Coast Guard Sector Lake Michigan Command Center at (414) 747–7182.
We developed this rule after considering numerous statutes and executive orders related to rulemaking. Below we summarize our analyses based on these statutes or executive orders.
This rule is not a significant regulatory action under section 3(f) of Executive Order 12866, Regulatory Planning and Review, as supplemented by Executive Order 13563, Improving Regulation and Regulatory Review, and does not require an assessment of potential costs and benefits under section 6(a)(3) of Executive Order 12866 or under section 1 of Executive Order 13563. The Office of Management and Budget has not reviewed it under that Order. It is not “significant” under the regulatory policies and procedures of the Department of Homeland Security (DHS). We conclude that this rule is not a significant regulatory action because we anticipate that it will have minimal impact on the economy, will not interfere with other agencies, will not adversely alter the budget of any grant or loan recipients, and will not raise any novel legal or policy issues. The safety zone created by this rule will be relatively small and enforced for about six months to allow for vital salvage and repair operations. Also, this safety zone is designed to minimize its impact on navigable waters by allowing vessels to transit unrestricted to portions of the waterways not affected by the safety zone. Thus, restrictions on vessel movements within that particular area are expected to be minimal. Under certain conditions, moreover, vessels may still transit through the safety zone when permitted by the Captain of the Port, Lake Michigan. On the whole, the Coast Guard expects insignificant adverse impact to mariners from the activation of this safety zone.
The Regulatory Flexibility Act of 1980 (RFA), 5 U.S.C. 601–612, as amended, requires federal agencies to consider the potential impact of regulations on small entities during rulemaking. The term “small entities” comprises small businesses, not-for-profit organizations that are independently owned and operated and are not dominant in their fields, and governmental jurisdictions with populations of less than 50,000.
This safety zone will not have a significant economic impact on a substantial number of small entities for the following reasons: this safety zone is designed to allow vessels to transit unrestricted to portions of the waterways not affected by the safety zone; an area to the south of the salvage and repair operations has been provided to allow traffic to transit the Illinois River when conditions surrounding the salvage operations allow. This safety zone would be effective and thus subject to enforcement, for about six months. Traffic may be allowed to pass through the zone with the permission of the Captain of the Port. The Captain of the Port can be reached via VHF channel 16. Before the enforcement of the zone, we would issue local Broadcast Notice to Mariners.
Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Pub. L. 104–121), we want to assist small entities in understanding this rule so they can better evaluate its effects on them. If this rule would affect your small business, organization, or governmental jurisdiction and you have questions concerning its provisions or options for compliance, please contact the person listed in the
Small businesses may send comments on the actions of Federal employees who enforce, or otherwise determine compliance with, Federal regulations to the Small Business and Agriculture Regulatory Enforcement Ombudsman and the Regional Small Business Regulatory Fairness Boards. The Ombudsman evaluates these actions annually and rates each agency's responsiveness to small business. If you wish to comment on actions by employees of the Coast Guard, call 1–888–REG–FAIR (1–888–734–3247). The Coast Guard will not retaliate against small entities that question or complain about this rule or any policy or action of the Coast Guard.
This rule will not call for a new collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501–3520).
A rule has implications for federalism under Executive Order 13132, Federalism, if it has a substantial direct effect on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government. We have analyzed this rule under that Order and determined that this rule does not have implications for federalism.
The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531–1538) requires Federal agencies to assess the effects of their discretionary regulatory actions. In particular, the Act addresses actions that may result in the expenditure by a State, local, or tribal government, in the aggregate, or by the private sector of $100,000,000 (adjusted for inflation) or more in any one year. Though this rule would not result in such an expenditure, we do discuss the effects of this rule elsewhere in this preamble.
This rule will not affect the taking of private property or otherwise have taking implications under Executive Order 12630, Governmental Actions and Interference with Constitutionally Protected Property Rights.
This rule meets applicable standards in sections 3(a) and 3(b)(2) of Executive Order 12988, Civil Justice Reform, to minimize litigation, eliminate ambiguity, and reduce burden.
We have analyzed this rule under Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks. This rule is not an economically significant rule and would not create an environmental risk to health or risk to safety that might disproportionately affect children.
This rule does not have tribal implications under Executive Order 13175, Consultation and Coordination with Indian Tribal Governments, because it does not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes.
This action is not a “significant energy action” under Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use.
This rule does not use technical standards. Therefore, we did not consider the use of voluntary consensus standards.
We have analyzed this rule under Department of Homeland Security Management Directive 023–01 and Commandant Instruction M16475.lD, which guide the Coast Guard in complying with the National Environmental Policy Act of 1969 (NEPA) (42 U.S.C. 4321–4370f), and have determined that this action is one of a category of actions that do not individually or cumulatively have a significant effect on the human environment. This rule involves the establishment of a safety zone, and thus, paragraph 34(g) of figure 2–1 in Commandant Instruction M16475.lD applies.
An environmental analysis checklist supporting this determination and a Categorical Exclusion Determination are available in the docket where indicated under
Harbors, Marine safety, Navigation (water), Reporting and recordkeeping requirements, Security measures, Waterways.
For the reasons discussed in the preamble, the Coast Guard amends 33 CFR part 165 as follows:
33 U.S.C. 1231; 46 U.S.C. Chapter 701, 3306, 3703; 50 U.S.C. 191, 195; 33 CFR 1.05–1, 6.04–1, 6.04–6, and 160.5; Pub. L. 107–295, 116 Stat. 2064; Department of Homeland Security Delegation No. 0170.1.
(a)
(b)
(c)
(1) In accordance with the general regulations in § 165.23 of this part, entry into, transiting, or anchoring within this safety zone is prohibited unless authorized by the Captain of the Port, Lake Michigan or his designated on-scene representative.
(2) This safety zone is closed to all vessel traffic, except as may be permitted by the Captain of the Port, Lake Michigan or his designated on-scene representative. The Captain of the Port, Lake Michigan or his on-scene representative may make exceptions to the restrictions of this safety zone for vessels intending to transit the Illinois River via the Marseilles Lock Canal and its approach channel south of Marseilles Dam. Notice of this exception, or other exceptions, will be made via Broadcast Notice to Mariners.
(3) The “on-scene representative” of the Captain of the Port, Lake Michigan is any Coast Guard commissioned, warrant or petty officer who has been designated by the Captain of the Port, Lake Michigan to act on his behalf.
(4) Vessel operators desiring to enter or operate within the safety zone shall contact the Captain of the Port, Lake Michigan or his on-scene representative to obtain permission to do so. The Captain of the Port, Lake Michigan or his on-scene representative may be contacted via VHF Channel 16. Vessel operators given permission to enter or operate in the safety zone must comply with all directions given to them by the Captain of the Port, Lake Michigan, or his on-scene representative.
Office of Special Education and Rehabilitative Services, Department of Education.
Final priority.
The Assistant Secretary for Special Education and Rehabilitative Services announces a priority for the Disability and Rehabilitation Research Projects and Centers Program administered by the National Institute on Disability and Rehabilitation Research (NIDRR).
Specifically, we announce a priority for a Rehabilitation Research and Training Center (RRTC) on Promoting Healthy Aging for Individuals with Long-Term Physical Disabilities. The Assistant Secretary may use this priority for competitions in fiscal year (FY) 2013 and later years. We take this action to focus research attention on areas of national need. We intend this priority to improve health and function outcomes for individuals aging with long-term physical disabilities.
Marlene Spencer, U.S. Department of Education, 400 Maryland Avenue SW., Room 5133, Potomac Center Plaza (PCP), Washington, DC 20202–2700. Telephone: (202) 245–7532 or by email:
If you use a telecommunications device for the deaf (TDD) or a text telephone (TTY), call the Federal Relay Service (FRS), toll free, at 1–800–877–8339.
The purpose of the RRTCs, which are funded through the Disability and Rehabilitation Research Projects and Centers Program, is to achieve the goals of, and improve the effectiveness of, services authorized under the Rehabilitation Act through advanced research, training, technical assistance, and dissemination activities in general problem areas, as specified by NIDRR. These activities are designed to benefit rehabilitation service providers, individuals with disabilities, and the family members or other authorized representatives of individuals with disabilities. Additional information on the RRTC program can be found at:
We published a notice of proposed priority in the
There are differences between the proposed priority and this final priority as discussed under
Generally, we do not address technical and other minor changes or suggested changes the law does not authorize us to make under the applicable statutory authority. In addition, we do not address general comments that raised concerns not directly related to the proposed priority.
At the same time, the regulations in 34 CFR 350.22(c) require the RRTC to serve as an informational and technical assistance resource for both providers and individuals with disabilities and their representatives through such means as conferences, workshops, public education programs, in-service training programs, and similar activities. In light of these requirements relating to provision of technical assistance, which are summarized in paragraph (c)(i) of the priority, we do not believe the priority limits the amount of information that would be available to consumers.
NIDRR does not plan to develop and publish “stages of research” that are not focused on interventions. We recognize that research directed toward the development of a new disability outcomes measure, for example, may be in an advanced or mature stage of development. Applicants are free to describe the maturity, or staging of, their proposed research using any framework that they deem appropriate. However, NIDRR believes that all disability and rehabilitation research can and should be categorized under the stages we described so that it is clear how the research that we sponsor is aligned with the practical intent of our authorizing legislation and our mission.
NIDRR views no single research stage as more important than another. By providing a framework for applicants to describe how their research is currently needed at a particular stage and to describe the foundation laid for it at earlier stages of research, we aim to help propel research from exploratory stages to scale-up stages in which benefits can be experienced by large numbers of individuals with disabilities. NIDRR is actively developing peer reviewer orientation strategies to ensure that peer reviewers understand that NIDRR values high-quality at every stage of research.
Through the implementation of the Plan, NIDRR seeks to improve the health and functioning, employment, and community living and participation of individuals with disabilities through comprehensive programs of research, engineering, training, technical assistance, and knowledge translation and dissemination. The Plan reflects NIDRR's commitment to quality, relevance, and balance in its programs to ensure appropriate attention to all aspects of well-being of individuals with disabilities and to all types and degrees of disability, including low-incidence and severe disability.
This priority reflects a major area or domain of NIDRR's research agenda (health and function), combined with a specific broad disability population (long-term physical disability).
The research that is proposed under this priority must be focused on one or more stages of research. If the RRTC is to conduct research that can be categorized under more than one
(i)
(ii)
(iii)
(iv)
The Assistant Secretary for Special Education and Rehabilitative Services establishes a priority for an RRTC on Promoting Healthy Aging for Individuals with Long-Term Physical Disabilities. The term “individuals with long-term physical disabilities” refers to individuals who acquired a disability during the life course from birth to childhood to middle age and are now aging with their disability. The RRTC must contribute to the development of new knowledge and accelerate the development, modification, and evaluation of evidence-based interventions and strategies that can be applied in clinical and community-based settings to promote healthy aging, including reducing secondary conditions, of individuals with long-term physical disabilities.
To contribute to this outcome the RRTC must—
(a) Conduct research activities in one or more of the following priority areas, focusing on individuals aging with long-term physical disabilities as a group or on individuals in specific disability or demographic subpopulations of individuals with long-term physical disabilities:
(i) Individual and environmental factors associated with improved access to rehabilitation and health care resulting in improved health and function outcomes for individuals aging with long-term physical disabilities.
(ii) Interventions that contribute to improved health and function outcomes for individuals aging with long-term physical disabilities. Interventions include any strategy, practice, program, policy, or tool that, when implemented as intended, contributes to improvements in outcomes for the specified population.
(iii) Effects of government practices, policies, and programs on health care access and on health and function outcomes for individuals aging with long-term physical disabilities.
(iv) Technology to improve health and function outcomes for individuals aging with long-term physical disabilities;
(b) Focus its research on one or more specific stages of research. If the RRTC is to conduct research that can be categorized under more than one of the research stages, or research that progresses from one stage to another, those stages must be clearly specified. These stages and their definitions are provided at the beginning of the
(c) Serve as a national resource center related to health and function for individuals aging with long-term physical disabilities, their families, and other stakeholders by:
(i) Providing information and technical assistance to service providers, individuals aging with long-term physical disabilities and their representatives, and other key stakeholders;
(ii) Providing training, including graduate, pre-service, and in-service training, to rehabilitation providers and other disability service providers, to facilitate more effective delivery of services to individuals aging with long-term physical disabilities. This training may be provided through conferences, workshops, public education programs, in-service training programs, and similar activities;
(iii) Disseminating research-based information and materials related to health and function for individuals aging with long-term physical disabilities; and
(d) Involve key stakeholder groups, including individuals with long-term disabilities, in the activities conducted under paragraph (a) in order to maximize the relevance and usability of the new knowledge generated by the RRTC.
When inviting applications for a competition using one or more priorities, we designate the type of each priority as absolute, competitive preference, or invitational through a notice in the
This notice does not preclude us from proposing additional priorities, requirements, definitions, or selection criteria, subject to meeting applicable rulemaking requirements.
This notice does
Under Executive Order 12866, the Secretary must determine whether this regulatory action is “significant” and, therefore, subject to the requirements of the Executive order and subject to review by the Office of Management and Budget (OMB). Section 3(f) of Executive Order 12866 defines a “significant regulatory action” as an action likely to result in a rule that may—
(1) Have an annual effect on the economy of $100 million or more, or adversely affect a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or tribal governments or communities in a material way (also referred to as an “economically significant” rule);
(2) Create serious inconsistency or otherwise interfere with an action taken or planned by another agency;
(3) Materially alter the budgetary impacts of entitlement 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 stated in the Executive order.
This final regulatory action is not a significant regulatory action subject to review by OMB under section 3(f) of Executive Order 12866.
We have also reviewed this final regulatory action under Executive Order 13563, which supplements and explicitly reaffirms the principles, structures, and definitions governing regulatory review established in Executive Order 12866. To the extent permitted by law, Executive Order 13563 requires that an agency—
(1) Propose or adopt regulations only upon a reasoned determination that their benefits justify their costs (recognizing that some benefits and costs are difficult to quantify);
(2) Tailor its regulations to impose the least burden on society, consistent with obtaining regulatory objectives and taking into account—among other things and to the extent practicable—the costs of cumulative regulations;
(3) In choosing among alternative regulatory approaches, select those approaches that maximize net benefits (including potential economic, environmental, public health and safety, and other advantages; distributive impacts; and equity);
(4) To the extent feasible, specify performance objectives, rather than the behavior or manner of compliance a regulated entity must adopt; and
(5) Identify and assess available alternatives to direct regulation, including economic incentives—such as user fees or marketable permits—to encourage the desired behavior, or provide information that enables the public to make choices.
Executive Order 13563 also requires an agency “to use the best available techniques to quantify anticipated present and future benefits and costs as accurately as possible.” The Office of Information and Regulatory Affairs of OMB has emphasized that these techniques may include “identifying changing future compliance costs that might result from technological innovation or anticipated behavioral changes.”
We are issuing this final priority only on a reasoned determination that its benefits justify its costs. In choosing among alternative regulatory approaches, we selected those approaches that maximize net benefits. Based on the analysis that follows, the Department believes that this regulatory action is consistent with the principles in Executive Order 13563.
We also have determined that this regulatory action does not unduly interfere with State, local, and tribal governments in the exercise of their governmental functions.
In accordance with both Executive orders, the Department has assessed the potential costs and benefits, both quantitative and qualitative, of this regulatory action. The potential costs are those resulting from statutory requirements and those we have determined as necessary for administering the Department's programs and activities.
The benefits of the Disability and Rehabilitation Research Projects and Centers Program have been well established over the years, as projects similar to the one envisioned by the final priority have been completed successfully. The new RRTC will generate, and promote the use of, new knowledge that will improve the options for individuals with disabilities to perform regular activities of their choice in the community.
You may also access documents of the Department published in the
Office for Civil Rights, Department of Health and Human Services.
Final rule.
These technical corrections address certain inadvertent errors and omissions in the HIPAA Privacy, Security, and Enforcement Rules that are located at 45 CFR parts 160 and 164.
This final rule is effective on June 7, 2013.
Andra Wicks 202–205–2292.
On January 25, 2013, the Department of Health and Human Services (HHS or “the Department”) published a final rule to implement changes to the HIPAA Privacy, Security, Enforcement, and Breach Notification Rules (“the HIPAA Rules”) pursuant to statutory amendments under the Health Information Technology for Economic and Clinical Health Act (“the HITECH Act”), pursuant to section 105 of Title I of the Genetic Information Nondiscrimination Act of 2008, to address public comment received on the interim final Breach Notification Rule, and to make certain other modifications to the HIPAA Rules to improve their workability and effectiveness and to increase flexibility for and decrease burden on the regulated entities. See 78 FR 5566. Since then, HHS has discovered a number of minor inadvertent errors and omissions in citations, and one typographical error, in several provisions of the HIPAA Rules. As explained below, with one exception, the errors and omissions are related to the modifications made in the final rule published on January 25, 2013. This final rule contains technical corrections to the HIPAA Rules to revise these errors and omissions, which are discussed below.
a. Section 160.508(c)(5) should be corrected to refer to § 160.410(b)(2)(ii)(B) and 42 U.S.C. 1320d–5(b)(2)(B) instead of § 160.410(b)(3)(ii)(B) and 42 U.S.C. 1320d–5(b)(3)(B), respectively, as § 160.410(b)(3)(ii)(B) and 42 U.S.C. 1320d–5(b)(3)(B) were previously amended and became § 160.410(b)(2)(ii)(B) and 42 U.S.C. 1320d–5(b)(2)(B) as a result. Also, § 160.508(c)(5) should include a reference to § 160.410(c)(2)(ii) after the reference to § 160.410(b)(2)(ii)(B), so that there is a corresponding regulatory reference for the grant of an extension of time pursuant to the Secretary's discretion for violations occurring on or after February 18, 2009, as there is for violations occurring prior to February 18, 2009.
b. Section 160.548(e) references an affirmative defense by which the Secretary may not impose a civil money penalty on a covered entity if the violation falls under the HIPAA criminal provisions at 42 U.S.C. 1320d–6 and cites § 160.410(b)(1) as the regulatory reference for this affirmative defense. However, § 160.410(b)(1) was changed to be § 160.410(a)(1) and (2). Thus, § 160.548(e) should be corrected to refer to § 160.410(a)(1) or (2) instead of § 160.410(b)(1).
a. The definition of
b. The definition of
c. Section 164.314(a)(1), in discussing business associate contracts or other arrangements, refers to the requirements for such contracts or other arrangements found at § 164.308(b)(4). However, as such requirements were renumbered and are now found at § 164.308(b)(3), § 164.314(a)(1) should be revised to refer to § 164.308(b)(3).
d. Section 164.512(k)(4)(i) refers to Executive Order (“E.O.”) 12698. However E.O. 12698 discusses pay rate adjustments and is not applicable to the subject of § 164.512(k)(4)(i). The preamble to the 2000 HIPAA Privacy Final Rule refers to E.O. 12968, which discusses classified information and is applicable to the subject of § 164.512(k)(4)(i). See 65 FR 82707. Given that § 164.512(k)(4)(i) relates to uses and disclosures of protected health information to the Department of State to determine medical suitability for the purpose of a required security clearance, as discussed in the preamble to the 2000 Privacy Final Rule, § 164.512(k)(4)(i) should properly refer to E.O. 12968.
e. Section 164.514(f)(2)(iv), in discussing the implementation specifications for covered entities that make fundraising communications, refers to the requirements to allow an individual to opt out of receiving fundraising communications, and erroneously refers to § 164.514(f)(1)(ii)(B), which does not exist. The proper reference for the opt out requirements is at § 164.514(f)(2)(ii). Accordingly, § 164.514(f)(2)(iv) should be revised to refer to § 164.514(f)(2)(ii).
f. Section 164.524(c)(4)(iv) describes the summary or explanation allowed by § 164.524(c)(2)(iii), while incorrectly referring to § 164.524(c)(2)(ii), which discusses the form of access requested by an individual. As such, § 164.524(c)(4)(iv) should be revised to refer to § 164.524(c)(2)(iii).
g. In section 164.532(f), the “[” should be removed before “January 25, 2013” to correct a typographical error.
Under the Administrative Procedure Act, an agency may waive the normal notice and comment procedures if it finds, for good cause, that they are impracticable, unnecessary, or contrary to the public interest. The Department has determined that the corrections in this final rule are minor, routine determinations in which the public would not be particularly interested, or about which the public has already been put on notice, given the context of the errors or omissions to be corrected. Therefore, the Department finds that good cause exists for waiving the notice and public comment procedures as unnecessary under 5 U.S.C. 553(b)(B). For the same reasons, pursuant to 5 U.S.C. 553(d)(3), a delayed effective date is not required.
Because this document is not subject to the notice and public procedure requirements of 5 U.S.C. 553, it is not subject to the provisions of the Regulatory Flexibility Act (5 U.S.C. 601 et seq.).
These technical corrections do not meet the criteria for a “significant regulatory action” as specified in Executive Order 12866, as supplemented by Executive Order 13563.
Administrative practice and procedure, Computer technology, Electronic information system, Electronic transactions, Employer benefit plan, Health, Health care, Health facilities, Health insurance, Health records, Hospitals, Investigations, Medicaid, Medical research, Medicare, Penalties, Privacy, Reporting and recordkeeping requirements, Security.
Administrative practice and procedure, Computer technology,
For the reasons set forth in the preamble, the Department amends 45 CFR Subtitle A, Subchapter C, parts 160 and 164, as set forth below:
42 U.S.C. 1302(a); 42 U.S.C. 1320d–1320d–9; sec. 264, Pub. L. 104–191, 110 Stat. 2033–2034 (42 U.S.C. 1320d–2 (note)); 5 U.S.C. 552; secs. 13400–13424, Pub. L. 111–5, 123 Stat. 258–279; and sec. 1104 of Pub. L. 111–148, 124 Stat. 146–154.
42 U.S.C. 1302(a); 42 U.S.C. 1320d–1320d–9; sec. 264, Pub. L. 104–191, 110 Stat. 2033–2034 (42 U.S.C. 1320d–2 (note)); and secs. 13400–13424, Pub. L. 111–5, 123 Stat. 258–279.
Assistant Secretary for Policy, Management and Budget, Interior.
Final rule.
The Department of the Interior is finalizing regulations guiding implementation of the Buy Indian Act, which provides Indian Affairs (IA) with authority to set aside procurement contracts for Indian-owned and controlled businesses. This rule supplements the Federal Acquisition Regulation (FAR) and the Department of the Interior Acquisition Regulation (DIAR).
This rule is effective on July 8, 2013.
Jonodev Chaudhuri, Office of the Assistant Secretary—Indian Affairs, (202) 208–7163;
IA has obtained services and supplies from Indian sources using the Buy Indian Program since 1965, based on policy memoranda and acquisition. This rule describes uniform administrative procedures that IA will use in all of its locations to encourage procurement relationships with eligible Indian Economic Enterprises in the execution of the Buy Indian Act.
This rule incorporates the decision of the Assistant Secretary—Indian Affairs to increase economic development and employment of Indian persons by reducing the percentage of Indian ownership of business enterprises from a mandatory 100 percent to minimum 51 percent.
In addition, the regulations respond to and incorporate the nuances of Section 831 of the National Defense Authorization Act for Fiscal Year 1991 (Pub. L. 101–510, 10 U.S.C. 2301 note) that amended 25 U.S.C. 47 to allow Indian firms to participate in the Department of Defense's Mentor-Protégé Program and not lose their eligibility for contracts awarded under the authority of the Buy Indian Act. This rule includes language stating that participation in the Mentor-Protégé program has no effect on eligibility for contracts awarded under the authority of the Buy Indian Act.
This rule also includes revisions to address the input received as a result of earlier publications and consultation hearings in Indian Country.
Indian economic enterprises interested in contracting with IA should monitor
The authority to issue regulations is vested in the Secretary of the Interior by 5 U.S.C. 301. The authorizing statute is section 23 of the Act of June 25, 1910 (25 U.S.C. 47, as amended).
This rule supplements the Federal Acquisition Regulation (FAR) and the Department of the Interior Acquisition Regulation (DIAR). For this reason the rule is issued by the Assistant Secretary for Policy, Management and Budget. This rule formalizes an administrative procedure for all IA acquisition activities and locations to ensure uniformity for eligible Indian Economic Enterprises that submit offers under solicitations set aside under the Act and this part.
This rule follows the numbering system established by the FAR and supplements the DIAR. Section 1401.303(a)(3) of 48 CFR authorizes each Interior bureau to codify regulations implementing the DIAR. Where material in the FAR and/or DIAR do not require IA implementing regulations, there will be no corresponding section number in the supplementary material.
This rule formalizes an administrative procedure for all IA acquisition activities/locations to ensure that IA will apply the procedures uniformly for eligible Indian Economic Enterprises that submit offers under solicitations set aside under the Act. This rule also incorporates Congress's determination that Indian firms should not lose their eligibility for contract awards under the Buy Indian Act due to participation in the Department of Defense's Mentor-Protégé Program.
This rule has been in development for decades. IA published proposed rules in the
Notification regarding a series of three public consultation sessions was published in the
IA then circulated a draft rule and held a series of three tribal consultation sessions in 2010. The consultation sessions were conducted in Portland, Oregon on April 26, 2010; in Rapid City, South Dakota, on April 28, 2010; and in Tulsa, Oklahoma on April 29, 2010. IA published notice of these consultations in the
IA published a proposed rule on July 26, 2012 (77 FR 43782) and hosted four additional tribal consultation sessions: in Albuquerque, New Mexico, on August 14, 2012; in Billings, Montana, on August 15, 2012; in Sacramento, California, on August 21, 2012; and in Prior Lake, Minnesota, on August 23, 2012. A summary of the comments received during these consultations and throughout the public comment period is provided below.
Most comments were oral at consultation sessions. Only a few written comments were received. The following is a summary of some of the main categories of comments, including oral comments, and IA's responses. Overall, they expressed general support for finalizing the Buy Indian rule as soon as possible.
In addition, the rule defines Indian economic enterprise to include additional qualifications beyond just 51 percent Indian ownership to help prevent companies “fronting” as Indian economic enterprises. To be an Indian economic enterprise, Indian(s) or tribe(s) must manage the contract, receive the majority of earnings from the contract, and control management and daily business operations. To ensure actual control, the Indians must possess requisite management or technical capabilities directly related to the primary industry in which the enterprise conducts business.
• Road facilities on Indian-owned land;
• Road facilities on an Indian reservation;
• Road facilities that are primary access routes proposed by tribal governments, including roads between villages, roads to landfills, roads to drinking water sources, roads to natural resources identified for economic development;
• Roads that provide access to intermodal termini, such as airports, harbors, or boat landings;
• Bridges along these roads;
• Planning and other needs and facilities associated with roads; and
• Sidewalks along these roads.
IA has determined that it may not use Buy Indian set-asides for other categories of public works including buildings, sewers, water mains, and similar items. The final rule reflects this distinction.
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. This rule is also part of the Department's commitment under the Executive Order to reduce the number and burden of regulations.
The Department of the Interior certifies that this document will not
This rule is not a major rule under 5 U.S.C. 804(2), the Small Business Regulatory Enforcement Fairness Act.
(a) This rule does not have an annual effect on the economy of $100 million or more. The annual value of contracts is less than $45 million.
(b) This rule will not cause any increase in costs or prices for consumers, individual industries, Federal, State, or local government agencies, or geographic regions. The rule will be applied on a national basis and has no effect on the dollar amount expended for acquisitions.
(c) This rule does not have significant adverse effects on competition, employment, investment, productivity, innovation, or the ability of U.S.-based enterprises to compete with foreign-based enterprises. The annual value of the acquisitions made under this authority is less than $45 million.
This rule does not impose any unfunded mandate on State, local, or tribal governments or the private sector. The rule does not have a significant or unique effect on State, local or tribal governments or the private sector. The rule merely governs acquisitions from contractors.
In accordance with Executive Order 12630, the rule does not have any takings implications. The rule governs acquisitions from contractors.
In accordance with Executive Order 13132, the rule does not have any Federalism implications to warrant the preparation of a Federalism Assessment. The rule governs acquisitions from contractors and does not interfere with the administration of programs by State governments.
In accordance with Executive Order 12988, the Office of the Solicitor has determined that this rule does not unduly burden the judicial system and meets the requirements of sections 3(a) and 3(b)(2) of the Order.
In accordance with Executive Order 13175, IA held consultation meetings with the tribes on draft and proposed versions of this rule, as well as the several previous publications of the proposed rule (see “IV. Development of Rule” of this preamble for details). The rule will more directly affect Indian economic enterprises and any contractors who use the Buy Indian Act for subcontracting.
This regulation requires offerors to state whether they meet the definition of an “Indian economic enterprise.” This statement is a simple representation that an offeror submits to support its claim for eligibility to participate in contract awards under the authority of the Buy Indian Act 25 U.S.C. 47, as amended. Because this statement is a simple certification or acknowledgment, it does not qualify as a collection of information under the Paperwork Reduction Act. See 5 CFR 1320.3(h).
This rule does not constitute a major Federal action significantly affecting the quality of the human environment. A detailed statement under the National Environmental Policy Act of 1969 is not required because there is nothing inherent in the rule that will significantly affect the quality of the human environment; the rule merely regulates the implementation of an acquisition authority.
This rule is not a significant energy action under the definition in Executive Order 13211. A statement of energy effects is not required.
Government procurement, Indian Economic Enterprises, Reporting and recordkeeping requirements.
For the reasons set out in the preamble, the Department of the Interior amends chapter 14 of title 48 of the Code of Federal Regulations as follows:
Sec. 205(c), 63 Stat. 390, 40 U.S.C. 486(c); and 5 U.S.C. 301.
Indian Affairs must use the negotiation authority of the Buy Indian Act, 25 U.S.C. 47 to give preference to Indians whenever using that authority is authorized and feasible. The Buy Indian Act requires that, so far as may be feasible, Indian labor must be employed, and purchases of the products of Indian industry may be made in open market at the discretion of the Secretary of the Interior. This requirement applies notwithstanding any other law and applies to all products of industry, including printing.
Sec. 205(c), 63 Stat. 390, 40 U.S.C. 486(c); and 5 U.S.C. 301.
As prescribed in 1480.503(d)(3), and in lieu of the requirements of FAR 19.508, insert the following provision in each written solicitation of offers to provide supplies or services when purchasing commercial items under FAR Part 12 or using simplified acquisition procedures under FAR Part 13. If the solicitation is oral, information substantially identical to that contained in the provision must be given to potential offerors.
Under the Buy Indian Act, 25 U.S.C. 47, offers are solicited only from Indian economic enterprises (Subpart 1480.8) that are also small business concerns. Any acquisition resulting from this solicitation will be from such a concern. Offers received from enterprises that are not both Indian economic enterprises and small business
As prescribed in 1480.503(d)(4) and 1480.504–1(f)(5), insert the following clause in solicitations and contracts involving Indian economic enterprise set-asides. If the solicitation is oral, information substantially identical to that contained in the provision must be given to potential offerors.
(a) Definitions as used in this clause.
(i) The combined Indian or Indian Tribe ownership shall constitute not less than 51 percent of the enterprise; (ii) the Indians or Indian Tribes shall, together, receive at least a majority of the earnings from the contract; and (iii) the management and daily business operations of an Indian economic enterprise must be controlled by one or more individuals who are members of an Indian Tribe. To ensure actual control over the enterprise, the individuals must possess requisite management or technical capabilities directly related to the primary industry in which the enterprise conducts business. The enterprise must meet these requirements throughout the following time periods:
(1) At the time an offer is made in response to a written solicitation;
(2) At the time of contract award; and,
(3) During the full term of the contract.
(b) General.
(1) Under the Buy Indian Act, offers are solicited only from Indian economic enterprises.
(2) BIA will reject all offers received from ineligible enterprises.
(3) Any award resulting from this solicitation will be made to an Indian economic enterprise, as defined in paragraph (a) of this clause.
(c) Required Submissions. In response to this solicitation, an offeror must also provide the following:
(1) A description of the required percentage of the work/costs to be provided by the offeror over the contract term as required by section 1452.280–3, Subcontracting Limitations clause;
(2) A description of the source of human resources for the work to be performed by the offeror;
(3) A description of the method(s) of recruiting and training Indian employees, indicating the extent of soliciting employment of Indian persons, as required by DIAR 1452.226–70, Indian Preference, or DIAR 1452.226–71, Indian Preference Program, clause(s);
(4) A description of how subcontractors (if any) will be selected in compliance with the “Indian Preference” or “Indian Preference Program” clause(s);
(5) The names, addresses, and descriptions of work to be performed by Indian persons or economic enterprises being considered for subcontracts (if any) and the percentage of the total direct project work/costs they would be performing;
(6) Qualifications of the key personnel (if any) that will be assigned to the contract; and
(7) A description of method(s) for compliance with any supplemental Tribal employment preference requirements, if contained in this solicitation.
(d) Required Assurance. The offeror must provide written assurance to the Indian Affairs that it will comply, or has, complied fully with the requirements of this clause. It must do this before Indian Affairs awards the Buy Indian contract, and upon successful and timely completion of the contract, but before the Indian Affairs Contracting Officer (CO) accepts the work or product.
(e) Non-responsiveness. Failure to provide the information required by paragraphs (c) and (d) of this clause may cause Indian Affairs to find an offer non-responsive and to reject it.
(f) Eligibility.
(1) Participation in the Mentor-Protégé Program established under section 831 of the National Defense Authorization Act for Fiscal Year 1991 (25 U.S.C. 47 note) does not render an Indian economic enterprise ineligible for contracts awarded under the Buy Indian Act.
(2) If a contractor no longer meets the definition of an Indian economic enterprise after award, the contractor must notify the CO in writing. The notification must include full disclosure of circumstances causing the contractor to lose eligibility status and a description of any actions that the contractor will take to regain eligibility. Failure to give the CO immediate written notification means that: (i) The economic enterprise may be declared ineligible for future contract awards under this part; and (ii) Indian Affairs may consider termination for default if it is in the best interest of the government.
A contractor shall not subcontract to other than responsible Indian economic enterprises more than 50 percent of the subcontracted work when the prime contract was awarded under the Buy Indian Act. For this purpose, work to be performed does not include the provision of materials, supplies, or equipment. As prescribed in 1480.601(b), insert the following clause in each written solicitation or contract to provide supplies, services, or covered construction:
(a) Definitions as used in this clause.
(1)
(2)
(3)
(b) Required Percentages of work by the concern. The contractor must comply with FAR 52.219–14 Limitations on Subcontracting clause in allocating what percentage of work to subcontract. Of the work subcontracted, no more than 50 percent may be subcontracted to a concern other than a responsible Indian economic enterprise.
(c) Indian Preference. Regardless of the contract type for services, supplies, or covered construction, the contractor agrees to give preference to Indian organizations and Indian owned economic enterprises in awarding subcontracts under this contract in accordance with DIAR 1452.226–71, Indian Preference.
(d) Cooperation. The contractor must:
(1) Carry out the requirements of this clause to the fullest extent; and
(2) Cooperate in any study or survey that the CO, Indian Affairs, or its agents may conduct to verify the contractor's compliance with this clause.
(e) Incorporation in Subcontracts. The contractor must incorporate the substance of this clause, including this paragraph (e), in all subcontracts for supplies, services, and construction awarded under this contract.
As prescribed in 1480.801(a), insert the following provision in each written
The offeror represents as part of its offer that it [ ] does [ ] does not meet the definition of Indian economic enterprise as defined in 1480.201.
25 U.S.C. 47, as amended (36 Stat. 861), 41 U.S.C. 253(c)(5), and 5 U.S.C. 301.
This part prescribes policies and procedures for the procurement of supplies and services from Indian economic enterprises under the Buy Indian Act, 25 U.S.C. 47, and this part.
(a) This part supplements Federal Acquisition Regulation (FAR) and Department of the Interior Acquisition Regulation (DIAR) requirements to satisfy the needs of Indian Affairs in implementing the Buy Indian Act.
(b) This part is under the direct oversight and control of the Chief Financial Officer, within the Office of the Assistant Secretary—Indian Affairs, Department of the Interior (CFO). The CFO is responsible for issuing and implementing this part.
(c) Acquisitions conducted under this part are subject to all applicable requirements of the FAR and DIAR, as well as internal policies, procedures or instructions issued by the Indian Affairs. The provisions of the FAR take precedence in all instances where there may be a conflict or discrepancy.
The following words and terms are used as defined below unless a different definition is prescribed for a particular subpart or portion of a subpart.
(1) At the time an offer is made in response to a written solicitation;
(2) At the time of contract award; and
(3) During the full term of the contract.
Except as provided in 1480.302 and 1480.401(b), this part applies to all acquisitions, including simplified acquisitions, made by IA and by any other bureau or office of the Department of the Interior delegated the authority to make acquisitions under the Buy Indian Act and 1480.401(d).
(a) IA must not use the authority of the Buy Indian Act and the procedures contained in this part to award intergovernmental contracts to tribal organizations to plan, operate or administer authorized IA programs (or parts thereof) that are within the scope and intent of the Indian Self-Determination and Education Assistance Act. IA must use the Buy Indian Act solely to award procurement contracts to IEEs.
(b) IA must not use the authority of this Act for construction contracts, as defined in FAR 36.102, unless the construction is covered construction, as defined in 1480.201.
(a) IA must use the negotiation authority of the Buy Indian Act, 25 U.S.C. 47, to give preference to Indians whenever the use of that authority is authorized and practicable. The Buy Indian Act provides that, “so far as may be practicable, Indian labor shall be employed, and purchases of the products (including, but not limited to printing, notwithstanding any other law) of Indian industry may be made in open market at the discretion of the Secretary of the Interior.” Thus, IA may use the Buy Indian Act to give preference to IEEs through set-asides when acquiring supplies, services, and covered construction to meet IA needs and requirements. IA must contract for covered construction in accordance with FAR Part 36.
(b) IA or any other bureau or office of the Department of the Interior delegated the authority to make acquisitions under the Buy Indian Act may not use the Buy Indian Act to give preference to IEEs through set-asides when acquiring construction that is not covered construction.
(c) The provisions of this section shall not apply to the awarding of contracts under the Indian Self-Determination and Education Assistance Act (25 U.S.C. 450b et seq.) by the Department of the Interior.
(a) The Secretary has delegated authority under the Buy Indian Act to the Assistant Secretary—Indian Affairs. IA exercises this authority in support of its mission and program activities and as a means of fostering Indian employment and economic development.
(b) The Secretary may delegate authority under the Buy Indian Act to a bureau or office within the Department of the Interior other than IA only in accordance with the Departmental Manual.
(c) As the head of the contracting activity, the CFO is responsible for ensuring that all IA acquisitions under the Buy Indian Act comply with the requirements of this part.
(a) The following officials may authorize a deviation for an IA acquisition:
(b) Deviations may be authorized prior to issuing the solicitation when IA makes the following determinations and the appropriate official takes the following actions:
(c) Deviations may be authorized after issuing solicitations when IA makes the following determinations and the appropriate official takes the following actions:
(d) In response to a set-aside acquisition, when using competitive proposals, proposals may be rejected by a written determination by the CCO that a reasonable price cannot be negotiated.
All acquisitions made in accordance with this part, including simplified or commercial item acquisitions, must conform to all applicable requirements of the FAR and DIAR.
Acquisitions made under an authorized deviation from the Buy Indian Act regulation must be made in conformance with the order of precedence required by FAR 8.002.
(a) Each acquisition of supplies, services, and covered construction that is subject to commercial item or simplified acquisition procedures in accordance with FAR Parts 12 or 13 and DIAR 1413 must be set aside exclusively for ISBEEs. IA will use ISBEE commercial item(s) or simplified acquisition set-asides to accomplish this preference action.
(b) If the CO proceeds with an ISBEE commercial item or simplified acquisition set-aside and receives an offer at a reasonable price from only one such responsible economic enterprise (see FAR 19.502–2), the CO must make an award to that enterprise. If the CO proceeds with an ISBEE commercial item or simplified acquisition set-aside and receives an offer from only one responsible economic enterprise at a price that is not reasonable, the CO may negotiate with that enterprise to reach a reasonable price.
(c) Commercial item or simplified acquisitions under this section must conform to the competition and price reasonableness documentation requirements of FAR 12.209 for commercial item acquisitions and FAR 13.106 for simplified acquisitions.
(d) Clauses and Provisions.
(1) Insert the clause at DIAR 1452.226–70, Indian Preference, in accordance with DIAR 1426.7003(a).
(2) Insert the clause at DIAR 1452.226–71, Indian Preference Program, in accordance with DIAR 1426.7003(b).
(3) Insert the clause at 1452.280–1, NOTICE OF INDIAN SMALL BUSINESS ECONOMIC ENTERPRISE SET-ASIDE in accordance with 1480.503(a).
(4) Insert the clause at 1452.280–2, NOTICE OF INDIAN ECONOMIC ENTERPRISE SET-ASIDE, in accordance with 1480.504–1(a).
(5) Insert the clause at 1452.280–3, SUBCONTRACTING LIMITATIONS, in accordance with 1480.601(b).
(6) Insert the clause at 1452.280–4, INDIAN ECONOMIC ENTERPRISE REPRESENTATION, in accordance with 1480.801(a).
(a) Each proposed procurement for supplies or services that has an anticipated dollar value in excess of the simplified acquisition threshold amount in FAR Part 13.003 must be set aside exclusively for IEEs, and referred to as an “Indian Economic Enterprise Set-aside,” when there is a reasonable expectation that offers will be received from two or more responsible IEEs, and award will be made at a reasonable price except when:
(1) The acquisition is for construction that is not covered construction, as described in 1480.401(b);
(2) A deviation has been obtained in accordance with 1480.403; or
(3) Use of other than full and open competition has been justified and approved in accordance with 1480.504–2.
(b) When acquiring services to be performed in whole or in part on Indian land under a tribe's jurisdiction, the CO must give written notice to the governing body or bodies of the applicable Indian tribe simultaneously with publication of the synopsis required by paragraph (c)(1) of this section. The notice must state IA's intent to solicit services or supplies using an IEE set-aside and provide the tribe with the opportunity to contract for the program within 15 calendar days from the date of the synopsis publication in the GPE.
(1) If the tribe does not oppose the set-aside intention or advise IA by the established deadline of its intent to contract, IA will proceed with the solicitation in accordance with FAR 5.2.
(2) If the tribe advises IA by the established deadline of its intent to contract, it must adequately justify a deviation for work on or near Indian land under its jurisdiction through a tribal resolution in accordance with Public Law 93–638.
(c) When using an IEE set-aside in accordance with this section, the CO must do the following:
(1) Synopsize the acquisition in the Governmentwide point of entry (GPE) as required by FAR Subpart 5.2, and identify it as an IEE set-aside.
(2) Use the Class Justification for Use of Other Than Full and Open Competition (JOFOC) in Acquisition of Supplies and Services from Indian Industry to meet the requirements of FAR 6.303.
(3) By separate memorandum to the file, document that the supplies or services to be acquired are available from two or more responsible and IEEs; the anticipated cost to IA of the required supplies or services is determined to be reasonable; and the information in the JOFOC in Acquisition of Supplies and Services from Indian Industry is accurate and complete as it pertains to the proposed acquisition.
(4) Reject offers that fail to provide representation that they meet the definition of an IEE. The CO may also request the Office of the Inspector General (on Form DI–1902 as part of a normal pre-award audit) to:
(i) Assist in determining the eligibility of the low responsive and responsible offerors on Buy Indian Act awards; and
(ii) Determine whether the work will be performed by the labor force required under 1480.601.
(5) When using sealed bidding, determine that the price offered by the prospective contractor is considered to be reasonable and at a fair market price as required by FAR 14.408–2 before awarding a contract.
(6) When using competitive proposals, solicit proposals in accordance with FAR Subpart 15.2 and select sources in accordance with FAR Subpart 15.3 and DIAR Subpart 1415.6.
(7) When using competitive proposals or when negotiating modifications that impact the cost of a contract, conduct proposal analyses, including cost or price analyses in accordance with FAR Subpart 15.4, negotiate profit or fee in accordance with the procedures in FAR Subpart 15.4 and DIAR Subpart 1415.9, and prepare a negotiation memorandum in accordance with FAR 15.406–3 and DIAR 1415.808.
(8) When acquiring architect-engineer services, solicit proposals and evaluate potential contractors in accordance with FAR Part 36 and DIAR Subpart 1436.6.
(d) This paragraph applies to solicitations that are not restricted to participation of IEEs.
(1) If an interested IEE is identified after a market survey has been performed and a solicitation has been issued, but before the date established for receipt of offers, the contracting office must provide a copy of the solicitation to this enterprise. In this case, the CO:
(i) Will not give preference under the Buy Indian Act to the IEE, and
(ii) May extend the date for receipt of offers when practical.
(2) If more than one IEE comes forward subsequent to the solicitation, but prior to the date established for receipt of offers, the CO may cancel the solicitation and re-compete it as an IEE set-aside.
(e) When only one offer is received from a responsible IEE in response to an acquisition set-aside under paragraph (a) of this section:
(1) If the offer is not at a reasonable and fair market price, then the CO may negotiate with that enterprise for a reasonable and fair market price.
(2) If the offer is at a reasonable and fair market price, the CO must:
(i) Make an award to that enterprise;
(ii) Document the reason only one offer was considered; and
(iii) Initiate action to increase competition in future solicitations.
(f) Provisions and Clauses.
(1) Insert the clause at DIAR 1452.226–70, Indian Preference, in accordance with DIAR 1426.7003(a).
(2) Insert the clause at DIAR 1452.226–71, Indian Preference Program, in accordance with DIAR 1426.7003(b).
(3) Insert the clause at 1452.280–2, NOTICE OF INDIAN ECONOMIC ENTERPRISE SET-ASIDE, in accordance with 1480.504–1(a).
(4) Insert the clause at 1452.280–3, SUBCONTRACTING LIMITATIONS, in accordance with 1480.601(b).
(5) Insert the clause at 1452.280–4, INDIAN ECONOMIC ENTERPRISE REPRESENTATION, in accordance with 1480.801(a).
(6) When applicable, Tribal employment preference requirements may be added to the requirements of the clause in accordance with DIAR 1426.7005.
(a) Other circumstances may exist where the use of an IEE set-aside in accordance with 1480.401(a) and FAR 6.302–5 is not feasible. In such situations, the requirements of FAR Subparts 6.3 and DIAR Subparts 1406.3 apply in justifying the use of the appropriate authority for other than full and open competition.
(b) Except as provided in FAR 5.202, all proposed acquisition actions must first be publicized in accordance with the requirements of FAR 5.2 and DIAR 1405.2.
(c) Justifications for use of other than full and open competition in accordance with this section must be approved in accordance with DIAR 1406. These approvals are required for a proposed contract, or for an out of scope modification to an existing contract.
Violation of the regulations in this part by an offeror or an awardee may be cause for debarment or suspension in accordance with FAR 9.406 and 9.407. IA must refer recommendations for debarment or suspension to the Director, Office of Acquisition and Property Management, Department of the Interior, in accordance with DIAR 1409.406 and 1409.407 through the IA Division of Acquisitions with the concurrence of the head of the contracting activity.
(a) In contracts awarded under the Buy Indian Act and this part, the contractor must agree to perform the contract in accordance with FAR 52.219–14, Limitations on Subcontracting.
(b) The CO must also insert the clause at 1452.280–3, SUBCONTRACTING LIMITATIONS, in all purchase orders and contracts for services, supplies, or covered construction and awarded to IEEs pursuant this part.
Solicitations requiring performance and payment bonds must conform to FAR Part 28 and authorize use of any of the types of security acceptable in accordance with FAR Subpart 28.2 or section 11 of Public Law 98–449, the Indian Financing Act Amendments of 1984. The CO may accept alternative forms of security in lieu of performance and payment bonds according to FAR 28.102 and 25 U.S.C. 47a, if a determination is made that such forms of security provide the Government with adequate security for performance and payment.
The CO and the CO's representative (see DIAR 1401.670) must monitor performance and progress to ensure contractor compliance with FAR Part 42 regarding all contract requirements. The CO must ensure contractor compliance with the following provisions of this part:
(a) Qualification as an IEE as defined in 1480.201;
(b) Maintenance of the subcontracting limitations required by the clause at 1452.280–3 when acquiring services, supplies, and covered construction; and
(c) Enforcement of Indian preference requirements contained in DIAR 1426.7004.
(a) The CO must insert the provision at 1452.280–4, INDIAN ECONOMIC ENTERPRISE REPRESENTATION, in all solicitations regardless of dollar value that are set aside for IEEs in accordance this part.
(b) To be considered for an award under 1480.503 or 1480.504–1, an offeror must represent that it meets the definition of “Indian economic enterprise” in response to a specific solicitation set-aside in accordance with the Buy Indian Act and this part.
(c) The enterprise must meet the definition of “Indian economic enterprise” throughout the following time periods:
(1) At the time an offer is made in response to a solicitation;
(2) At the time of contract award; and
(3) During the full term of the contract.
(d) If, after award, a contractor no longer meets the eligibility requirements in paragraph (b) of this section, the contractor must provide immediate, written notification to the CO. The notification must include:
(1) Full disclosure of circumstances causing the contractor to lose eligibility status; and
(2) A description of actions, if any, that must be taken to regain eligibility.
(e) Failure to provide immediate written notification required by paragraph (d) of this section means that:
(1) The economic enterprise may be declared ineligible for future contract awards under this part; and
(2) IA may consider termination for default if it is determined to be in the best interest of the government.
(f) The CO will accept an offeror's representation in a specific bid or proposal that it is an IEE unless another interested party challenges the IEE representation or the CO has reason to question the representation. Challenges of and questions concerning a specific representation must be referred to the CO or CCO in accordance with Subpart 1480.9.
(g) Participation in the Mentor-Protégé Program established under section 831 of the National Defense Authorization Act for Fiscal Year 1991 (25 U.S.C. 47 note) does not render an IEE ineligible for contracts awarded under the Buy Indian Act.
(a) IA contracting offices must provide copies of the IEE representation to any interested parties upon written request.
(b) The submission of a Solicitation Mailing List Application by an enterprise does not remove the requirement for it to provide representation as an IEE, as required by this part, if it wishes to be considered as an offeror for a specific solicitation. COs may determine the validity of the contents of the applicant's representation.
(c) Any false or misleading information submitted by an enterprise when submitting an offer in consideration for an award set aside under the Buy Indian Act is a violation of the law punishable under 18 U.S.C. 1001. False claims submitted as part of contract performance are subject to the penalties enumerated in 31 U.S.C. 3729 to 3731 and 18 U.S.C. 287.
(a) Only IEEs may participate in acquisitions set aside in accordance with the Buy Indian Act and this part. IA procedure supports responsible IEEs and seeks to prevent circumvention or abuse of the Buy Indian Act.
(b) Eligibility is based on information furnished by the enterprise to an IA CO
(c) The CO may ask the appropriate Regional Solicitor to review the enterprise's representation.
(d) The IEE representation does not relieve the CO of the obligation for determining contractor responsibility, as required by FAR Subpart 9.1.
(a) The CO can accept an offeror's written representation of being an IEE (as defined in 1480.201) only when it is submitted with an offer in response to a solicitation under the Buy Indian Act. Another interested party may challenge the representation of an offeror or contractor by filing a written challenge to the applicable CO in accordance with the procedures in 1480.902.
(b) After receipt of offers, the CO may question the representation of any offeror in a specific offer by filing a formal objection with the CCO.
(a) An interested party must file any challenges against an offeror's representation with the local CO.
(b) The challenge must be in writing and must contain the basis for the challenge with accurate, complete, specific, and detailed evidence. The evidence must support the allegation that the offeror is either ineligible or fails to meet both the definitions of “Indian” and of “Indian economic enterprise” established in 1480.201. The CO will dismiss any challenge that is deemed frivolous or that does not meet the conditions in this section.
(c) To be considered timely, a challenge must be received by the CO no later than 10 days after the basis of challenge is known or should have been known, whichever is earlier.
(1) A challenge may be made orally if it is confirmed in writing within the 10-day period after the basis of challenge is known or should have been known, whichever is earlier.
(2) A challenge may be made in writing if it is delivered by hand, telefax, telegram, or letter postmarked within the 10-day period after the basis of challenge is known or should have been known, whichever is earlier.
(3) A CO's objection is always considered timely, whether filed before or after award.
(d) Upon receiving a timely challenge, the CO must:
(1) Notify the challenger of the date it was received, and that the representation of the enterprise being challenged is under consideration by IA; and
(2) Furnish to the economic enterprise (whose representation is being challenged) a request to provide detailed information on its eligibility by certified mail, return receipt requested.
(e) Within 3 days after receiving a copy of the challenge and IA's request for detailed information, the challenged offeror must file with the CO a complete statement answering the allegations in the challenge, and furnish evidence to support its position on representation. If the offeror does not submit the required material within the 3 days, or another period of time granted by the CO, IA may assume that the offeror does not intend to dispute the challenge and IA must not award to the challenged offeror.
(f) Within 10 days after receiving a challenge, the challenged offeror's response and other pertinent information, the CO must determine the representation status of the challenged offeror and notify the challenger and the challenged offeror of the decision by certified mail, return receipt requested, and make known the option to appeal the determination to the Office of Acquisition and Property Management, Department of the Interior (PAM).
(g) If the representation accompanying an offer is challenged and subsequently upheld by the PAM, the written notification of this action must state the reason(s). The PAM may review the economic enterprise for possible suspension or debarment recommendations.
(a) Award of a contract in the face of challenge may be made on the basis of the CO's written determination that the challenged offeror's representation is valid.
(1) This determination is final for IA unless it is appealed to the PAM, and the CO is notified of the appeal before award.
(2) If an award was made before the time the CO received notice of appeal, the contract must be presumed to be valid.
(b) After receiving a challenge involving an offeror being considered for award, the CO must not award the contract until the CO has determined the validity of the representation, or 10 days have expired since the CO received the challenge, whichever occurs first. Award must be made when the CO determines in writing that an award must be made to protect the public interest, or the supplies and services are urgently required, or a prompt award will otherwise be advantageous to the Government.
(c) If a timely challenge on representation is filed with the CO and received before award in response to a specific offer and solicitation, the CO must notify eligible offerors within one day that the award will be withheld and a time extension for acceptance is requested.
(d) If a challenge on representation is filed with the CO and received after award in response to a specific offer and solicitation, the CO need not suspend contract performance or terminate the awarded contract unless the CO believes that an award may be invalidated and a delay would prejudice the Government's interest. However, if contract performance is to be suspended, a mutual no cost agreement will be sought.
If a CO receives an untimely filed challenge of a representation, the CO must notify the challenger that the challenge cannot be considered on the instant acquisition but will be considered in any future actions. However, the CO may question at any time, before or after award, the representation of an IEE.
Federal Aviation Administration (FAA), DOT.
Notice of proposed rulemaking (NPRM).
We propose to adopt a new airworthiness directive (AD) for Bell Model 230 helicopters. This proposed AD would require installing a placard on the instrument panel and revising the limitations section of the rotorcraft flight manual (RFM). This proposed AD is prompted by several incidents of third stage engine turbine wheel failures, which were caused by excessive vibrations at certain engine speeds during steady-state operations. The proposed actions are intended to alert pilots to avoid certain engine speeds during steady-state operations, prevent failure of the third stage engine turbine, engine power loss, and subsequent loss of control of the helicopter.
We must receive comments on this proposed AD by August 6, 2013.
You may send comments by any of the following methods:
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You may examine the AD docket on the Internet at
For service information identified in this proposed AD, contact Bell Helicopter Textron Canada Limited, 12,800 Rue de l'Avenir, Mirabel, Quebec J7J1R4; telephone (450) 437–2862 or (800) 363–8023; fax (450) 433–0272; or at
Chinh Vuong, Aviation Safety Engineer, Safety Management Group, Rotorcraft Directorate, FAA, 2601 Meacham Blvd., Fort Worth, Texas 76137; telephone (817) 222–5110; email
We invite you to participate in this rulemaking by submitting written comments, data, or views. We also invite comments relating to the economic, environmental, energy, or federalism impacts that might result from adopting the proposals in this document. The most helpful comments reference a specific portion of the proposal, explain the reason for any recommended change, and include supporting data. To ensure the docket does not contain duplicate comments, commenters should send only one copy of written comments, or if comments are filed electronically, commenters should submit only one time.
We will file in the docket all comments that we receive, as well as a report summarizing each substantive public contact with FAA personnel concerning this proposed rulemaking. Before acting on this proposal, we will consider all comments we receive on or before the closing date for comments. We will consider comments filed after the comment period has closed if it is possible to do so without incurring expense or delay. We may change this proposal in light of the comments we receive.
Transport Canada (TC), which is the aviation authority for Canada, has issued TC AD No. CF–2005–24, dated July 4, 2005, to correct an unsafe condition for Model 230 helicopters. TC advises of several failures of third stage turbine wheels used in Rolls Royce 250–C30S and 250–C47B engines and that three of these failures have occurred on the same engine used by Bell on Model 230 helicopters. According to TC, Rolls Royce has determined that detrimental vibrations can occur within a particular range of turbine speeds, and may be a contributing factor to these failures. Bell has revised the operating limitations of the RFM and provided a corresponding decal on the instrument panel to inform pilots to avoid steady-state operations between 71% and 92% turbine speeds.
The TC AD requires amending the RFM, advising pilots of the change, and installing a decal as described in Bell Alert Service Bulletin (ASB) No. 230–05–33, dated June 10, 2005 (ASB 230–05–33).
These helicopters have been approved by the aviation authority of Canada and are approved for operation in the United States. Pursuant to our bilateral agreement with Canada, TC, its technical representative, has notified us of the unsafe condition described in its AD. We are proposing this AD because we evaluated all known relevant information and determined that an unsafe condition is likely to exist or develop on other helicopters of the same type design.
Bell has issued ASB 230–05–33, which contains procedures for installing a placard on the instrument panel and for inserting the RFM changes into the flight manual.
This proposed AD would require installing a placard on the instrument
The TC AD requires compliance within 10 calendar days, the proposed AD requires compliance within 30 days.
We estimate that this proposed AD would affect 12 helicopters of U.S. Registry. Based on an average labor rate of $85 per hour, we estimate that operators may incur the following costs in order to comply with this AD. Amending the RFM would require about 0.5 work-hours, for a cost per helicopter of about $43 and a cost to U.S. operators of $516. Installing the decal would require about 0.2 work-hours and required parts would cost $20, for a cost per helicopter of $37 and a cost to U.S. operators of $444. Based on these estimates, the total cost of this proposed AD would be $80 per helicopter and $960 for the U.S. operator fleet.
Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. “Subtitle VII: Aviation Programs,” describes in more detail the scope of the Agency's authority.
We are issuing this rulemaking under the authority described in “Subtitle VII, Part A, Subpart III, Section 44701: General requirements.” Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.
We determined that this proposed AD would not have federalism implications under Executive Order 13132. This proposed AD would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government.
For the reasons discussed, I certify this proposed regulation:
1. Is not a “significant regulatory action” under Executive Order 12866;
2. Is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979);
3. Will not affect intrastate aviation in Alaska 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 an economic evaluation of the estimated costs to comply with this proposed 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 proposes to amend 14 CFR part 39 as follows:
49 U.S.C. 106(g), 40113, 44701.
This AD applies to Bell Model 230 helicopters, certificated in any category.
This AD defines the unsafe condition as a third stage turbine vibration, which could result in turbine failure, engine power loss, and subsequent loss of control of the helicopter.
We must receive comments by August 6, 2013.
You are responsible for performing each action required by this AD within the specified compliance time unless it has already been accomplished prior to that time.
Within 30 days:
(1) Revise the Operating Limitations section of the Model 230 Rotorcraft Flight Manual by inserting Section 1, Limitations, page 1–12, of Bell BHT–230–FM–1, revision 5, dated May 6, 2005.
(2) Install placard part number 230–075–213–115, or equivalent, on the instrument panel directly below the No. 1 and No. 2 engine oil temp/press indicator.
(1) The Manager, Safety Management Group, FAA, may approve AMOCs for this AD. Send your proposal to: Chinh Vuong, Aviation Safety Engineer, Safety Management Group, Rotorcraft Directorate, FAA, 2601 Meacham Blvd., Fort Worth, Texas 76137; telephone (817) 222–5110; email
(2) For operations conducted under a 14 CFR part 119 operating certificate or under 14 CFR part 91, subpart K, we suggest that you notify your principal inspector, or lacking a principal inspector, the manager of the local flight standards district office or certificate holding district office before operating any aircraft complying with this AD through an AMOC.
(1) Bell Alert Service Bulletin No. 230–05–33, dated June 10, 2005, which is not incorporated by reference, contains additional information about the subject of this AD. For service information identified in this AD, contact Bell Helicopter Textron Canada Limited, 12,800 Rue de l'Avenir, Mirabel, Quebec J7J1R4; telephone (450) 437–2862 or (800) 363–8023; fax (450) 433–0272; or at
(2) The subject of this AD is addressed in Transport Canada AD No. CF–2005–24, dated July 4, 2005.
Joint Aircraft Service Component (JASC) Code: 7250: Turbine Section.
Federal Aviation Administration (FAA), DOT.
Notice of proposed rulemaking (NPRM).
We propose to adopt a new airworthiness directive (AD) for certain Bell Model 206B and 206L helicopters. This proposed AD would require installing a placard beneath the engine power dual tachometer and revising the operating limitations section of the rotorcraft flight manual (RFM). This proposed AD is prompted by several incidents of third stage engine turbine wheel failures, which were caused by excessive vibrations at certain engine speeds during steady-state operations. The proposed actions are intended to alert pilots to avoid certain engine speeds during steady-state operations, prevent failure of the third stage engine turbine, engine power loss, and subsequent loss of control of the helicopter.
We must receive comments on this proposed AD by August 6, 2013.
You may send comments by any of the following methods:
•
•
•
•
You may examine the AD docket on the Internet at
For service information identified in this proposed AD, contact Bell Helicopter Textron Canada Limited, 12,800 Rue de l'Avenir, Mirabel, Quebec J7J1R4; telephone (450) 437–2862 or (800) 363–8023; fax (450) 433–0272; or at
Chinh Vuong, Aviation Safety Engineer, Safety Management Group, Rotorcraft Directorate, FAA, 2601 Meacham Blvd., Fort Worth, Texas 76137; telephone (817) 222–5110; email
We invite you to participate in this rulemaking by submitting written comments, data, or views. We also invite comments relating to the economic, environmental, energy, or federalism impacts that might result from adopting the proposals in this document. The most helpful comments reference a specific portion of the proposal, explain the reason for any recommended change, and include supporting data. To ensure the docket does not contain duplicate comments, commenters should send only one copy of written comments, or if comments are filed electronically, commenters should submit only one time.
We will file in the docket all comments that we receive, as well as a report summarizing each substantive public contact with FAA personnel concerning this proposed rulemaking. Before acting on this proposal, we will consider all comments we receive on or before the closing date for comments. We will consider comments filed after the comment period has closed if it is possible to do so without incurring expense or delay. We may change this proposal in light of the comments we receive.
Transport Canada (TC), which is the aviation authority for Canada, has issued TC AD No. CF–2007–13R2, dated November 10, 2009, to correct an unsafe condition for certain Model 206B (including those converted from Model 206A) and 206L helicopters. TC advises of several failures of third stage turbine wheels used in Rolls Royce 250–C20 engines. According to TC, Rolls Royce has determined that detrimental vibrations can occur within a particular range of turbine speeds, and may be a contributing factor to these failures. Bell has revised the operating limitations of the RFM and provided a corresponding decal on the instrument panel to inform pilots to avoid steady-state operations between 75% and 88% turbine speeds.
The TC AD requires amending the RFMs, advising pilots of the change, and installing a decal as described in Bell Alert Service Bulletin (ASB) No. 206–07–115, Revision C, dated February 4, 2009, for Model 206B helicopters (ASB 206–07–115) and Bell ASB No. 206L–07–146, Revision B, dated March 3, 2009, for Model 206L helicopters (ASB 206L–07–146).
These helicopters have been approved by the aviation authority of Canada and are approved for operation in the United States. Pursuant to our bilateral agreement with Canada, TC, its technical representative, has notified us of the unsafe condition described in its AD. We are proposing this AD because we evaluated all known relevant information and determined that an unsafe condition is likely to exist or develop on other products of the same type design.
Bell has issued ASB 206–07–115 and ASB 206L–07–146, which contain procedures for installing a placard on the instrument panel below the main rotor RPM (Nr)/power turbine RPM (N2) dual tachometer and for inserting the RFM changes into the flight manual.
This proposed AD would require installing a placard on the instrument panel below the NR/N2 dual tachometer and revising the Operating Limitations sections of the Model 206B and 206L RFMs to limit steady-state operations between speeds of 75% and 88%.
The TC AD requires compliance within 10 calendar days, the proposed AD would require compliance within 30 days.
We estimate that this proposed AD would affect 970 helicopters of U.S. Registry. Based on an average labor rate of $85 per hour, we estimate that operators may incur the following costs in order to comply with this AD. Amending the RFM would require about 0.5 work-hours, for a cost per helicopter of about $43 and a cost to U.S. operators of $41,710. Installing the decal would require about 0.2 work-hours and required parts would cost $20, for a cost per helicopter of $37 and a cost to U.S. operators of $35,890. Based on these estimates, the total cost of this proposed AD would be $80 per helicopter and $77,600 for the U.S. operator fleet.
Title 49 of the United States Code specifies the FAA's authority to issue
We are issuing this rulemaking under the authority described in “Subtitle VII, Part A, Subpart III, Section 44701: General requirements.” Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.
We determined that this proposed AD would not have federalism implications under Executive Order 13132. This proposed AD would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government.
For the reasons discussed, I certify this proposed regulation:
1. Is not a “significant regulatory action” under Executive Order 12866;
2. Is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979);
3. Will not affect intrastate aviation in Alaska 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 an economic evaluation of the estimated costs to comply with this proposed 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 proposes to amend 14 CFR part 39 as follows:
49 U.S.C. 106(g), 40113, 44701.
This AD applies to the following helicopters, certificated in any category:
(1) Bell Model 206B, serial number (S/N) 004 through 4675, including helicopters converted from Model 206A; and
(2) Bell Model 206L, S/N 45001 through 45153, and 46601 through 46617.
This AD defines the unsafe condition as a third stage turbine vibration, which could result in turbine failure, engine power loss, and subsequent loss of control of the helicopter.
We must receive comments by August 6, 2013.
You are responsible for performing each action required by this AD within the specified compliance time unless it has already been accomplished prior to that time.
Within 30 days:
(1) For Model 206B helicopters:
(i) Revise the Operating Limitations section of the Model 206B Rotorcraft Flight Manual (RFM) by inserting Section 1, Operating Limitations, page 1–2A, of Bell BHT–206B–FM–1, revision B–50, dated December 8, 2008.
(ii) Remove placard part number (P/N) 230–075–213–121, if installed.
(iii) Install placard P/N 230–075–213–125, or equivalent, on the instrument panel directly below the dual tachometer.
(2) For Model 206L helicopters:
(i) Revise the Operating Limitations section of the Model 206L RFM by inserting Section 1, Operating Limitations, page 1–4B, of Bell BHT–206L–FM–1, revision 28, dated December 8, 2008.
(ii) Remove placard P/N 230–075–213–123, if installed.
(ii) Install placard P/N 230–075–213–127, or equivalent, on the instrument panel below the dual tachometer.
(1) The Manager, Safety Management Group, FAA, may approve AMOCs for this AD. Send your proposal to: Chinh Vuong, Aviation Safety Engineer, Safety Management Group, Rotorcraft Directorate, FAA, 2601 Meacham Blvd., Fort Worth, Texas 76137; telephone (817) 222–5110; email
(2) For operations conducted under a 14 CFR part 119 operating certificate or under 14 CFR part 91, subpart K, we suggest that you notify your principal inspector, or lacking a principal inspector, the manager of the local flight standards district office or certificate holding district office before operating any aircraft complying with this AD through an AMOC.
(1) Bell Alert Service Bulletin (ASB) No. 206–07–115, Revision C, dated February 4, 2009, and Bell ASB No. 206L–07–146, Revision B, dated March 3, 2009, which are not incorporated by reference, contain additional information about the subject of this AD. For service information identified in this AD, contact Bell Helicopter Textron Canada Limited, 12,800 Rue de l'Avenir, Mirabel, Quebec J7J1R4; telephone (450) 437–2862 or (800) 363–8023; fax (450) 433–0272; or at
(2) The subject of this AD is addressed in Transport Canada AD No. CF–2007–13R2, dated December 9, 2009.
Joint Aircraft Service Component (JASC) Code: 7250: Turbine Section.
Federal Aviation Administration (FAA), DOT.
Notice of proposed rulemaking (NPRM).
We propose to adopt a new airworthiness directive (AD) for certain Bell Model 206L–3 and 206L–4 helicopters. This proposed AD would require installing a placard beneath the engine power dual tachometer and revising the limitations section of the rotorcraft flight manual (RFM). This proposed AD is prompted by several incidents of third stage engine turbine wheel failures, which were caused by excessive vibrations at certain engine speeds during steady-state operations.
We must receive comments on this proposed AD by August 6, 2013.
You may send comments by any of the following methods:
•
•
•
•
You may examine the AD docket on the Internet at
For service information identified in this proposed AD, contact Bell Helicopter Textron Canada Limited, 12,800 Rue de l'Avenir, Mirabel, Quebec J7J1R4; telephone (450) 437–2862 or (800) 363–8023; fax (450) 433–0272; or at
Chinh Vuong, Aviation Safety Engineer, Safety Management Group, Rotorcraft Directorate, FAA, 2601 Meacham Blvd., Fort Worth, Texas 76137; telephone (817) 222–5110; email
We invite you to participate in this rulemaking by submitting written comments, data, or views. We also invite comments relating to the economic, environmental, energy, or federalism impacts that might result from adopting the proposals in this document. The most helpful comments reference a specific portion of the proposal, explain the reason for any recommended change, and include supporting data. To ensure the docket does not contain duplicate comments, commenters should send only one copy of written comments, or if comments are filed electronically, commenters should submit only one time.
We will file in the docket all comments that we receive, as well as a report summarizing each substantive public contact with FAA personnel concerning this proposed rulemaking. Before acting on this proposal, we will consider all comments we receive on or before the closing date for comments. We will consider comments filed after the comment period has closed if it is possible to do so without incurring expense or delay. We may change this proposal in light of the comments we receive.
Transport Canada (TC), which is the aviation authority for Canada, has issued TC AD No. CF–2005–28R1, dated June 14, 2007, to correct an unsafe condition for certain Model 206L–3 and 206L–4 helicopters. TC advises of several failures of third stage turbine wheels used in Rolls Royce 250–C30S and 250–C–47B engines. According to TC, Rolls Royce has determined that detrimental vibrations can occur within a particular range of turbine speeds, and may be a contributing factor to these failures. Bell has revised the RFM and has provided a corresponding decal to inform pilots to avoid steady-state operations between 71.8% and 91.5% turbine speeds.
The TC AD requires amending the RFMs, advising pilots of the change, and installing a decal as described in Bell Alert Service Bulletin (ASB) No. 206L–05–134, dated June 8, 2005.
These helicopters have been approved by the aviation authority of Canada and are approved for operation in the United States. Pursuant to our bilateral agreement with Canada, TC, its technical representative, has notified us of the unsafe condition described in its AD. We are proposing this AD because we evaluated all known relevant information and determined that an unsafe condition is likely to exist or develop on other products of the same type design.
Bell has issued ASB No. 206L–05–134, Revision A, dated April 9, 2007, which describes procedures for installing a placard on the instrument panel below the main rotor RPM (Nr)/power turbine RPM (N2) dual tachometer and for inserting the RFM changes into the flight manual. Revision A to ASB was issued to exclude Bell Model 206L–3 and 206L–4 helicopters with 250–C20R engines installed under supplemental type certificate (STC) number SR00036SE from the requirements of ASB 206L–05–134.
This proposed AD would require installing a placard on the instrument panel below the NR/N2 dual tachometer and revising the Operating Limitations section of the Model 206L3 and 206L4 RFMs to limit steady-state operations between speeds of 71.8% and 91.5%.
The TC AD requires compliance within 10 calendar days, the proposed AD requires compliance within 30 days.
We estimate that this proposed AD would affect 525 helicopters of U.S. Registry. Based on an average labor rate of $85 per hour, we estimate that operators may incur the following costs in order to comply with this AD. Amending the RFM would require about 0.5 work-hours, for a cost per helicopter of about $43 and a cost to U.S. operators of $22,575. Installing the decal would require about 0.2 work-hours, and required parts would cost $20, for a cost per helicopter of $37 and a cost to U.S. operators of $19,425. Based on these estimates, the total cost of this proposed AD would be $80 per helicopter and $42,000 for the U.S. operator fleet.
Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. “Subtitle VII: Aviation Programs,” describes in more detail the scope of the Agency's authority.
We are issuing this rulemaking under the authority described in “Subtitle VII, Part A, Subpart III, Section 44701: General requirements.” Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation
We determined that this proposed AD would not have federalism implications under Executive Order 13132. This proposed AD would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government.
For the reasons discussed, I certify this proposed regulation:
1. Is not a “significant regulatory action” under Executive Order 12866;
2. Is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979);
3. Will not affect intrastate aviation in Alaska 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 an economic evaluation of the estimated costs to comply with this proposed 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 proposes to amend 14 CFR part 39 as follows:
49 U.S.C. 106(g), 40113, 44701.
This AD applies to the following helicopters, certificated in any category:
(1) Bell Model 206L–3, serial number (S/N) 51001 through 51612; and
(2) Bell Model 206L–4, S/N 52001 through 52313.
This AD defines the unsafe condition as a third stage turbine vibration, which could result in turbine failure, engine power loss, and subsequent loss of control of the helicopter.
We must receive comments by August 6, 2013.
You are responsible for performing each action required by this AD within the specified compliance time unless it has already been accomplished prior to that time.
Within 30 days:
(1) Install placard P/N 230–075–213–117, or equivalent, on the instrument panel directly below the dual tachometer.
(2) For Model 206L–3 helicopters, revise the Operating Limitations section of the Model 206L–3 Rotorcraft Flight Manual (RFM) by inserting Section 1, Limitations, pages 1–7 and 1–8, of Bell BHT–206L3– FM–1, revision 6, dated April 26, 2005.
(3) For Model 206L–4 helicopters, revise the Operating Limitations section of the Model 206L–4 RFM by inserting Section 1, Limitations, pages 1–6 and 1–13, of Bell BHT–206L4–FM–1, Revision 2, dated August 22, 2008.
(1) The Manager, Safety Management Group, FAA, may approve AMOCs for this AD. Send your proposal to: Chinh Vuong, Aviation Safety Engineer, Safety Management Group, Rotorcraft Directorate, FAA, 2601 Meacham Blvd., Fort Worth, Texas 76137; telephone (817) 222–5110; email
(2) For operations conducted under a 14 CFR part 119 operating certificate or under 14 CFR part 91, subpart K, we suggest that you notify your principal inspector, or lacking a principal inspector, the manager of the local flight standards district office or certificate holding district office before operating any aircraft complying with this AD through an AMOC.
(1) Bell Alert Service Bulletin No. 206L–05–134, Revision A, dated April 9, 2007, which is not incorporated by reference, contains additional information about the subject of this AD. For service information identified in this AD, contact Bell Helicopter Textron Canada Limited, 12,800 Rue de l'Avenir, Mirabel, Quebec J7J1R4; telephone (450) 437–2862 or (800) 363–8023; fax (450) 433–0272; or at
(2) The subject of this AD is addressed in Transport Canada AD No. CF–2005–28R1, dated June 14, 2007
Joint Aircraft Service Component (JASC) Code: 7250: Turbine Section.
Federal Aviation Administration (FAA), DOT.
Notice of proposed rulemaking (NPRM).
We propose to supersede an existing airworthiness directive (AD) that applies to all Turbomeca S.A. Arriel 2D turboshaft engines. The existing AD currently requires replacing the hydromechanical metering unit (HMU) at a reduced life. Since we issued that AD, further cases of deterioration of HMU rotating components have been reported before the HMU reached the replacement interval in that AD. The proposed AD would maintain the existing AD requirements and would also require inspections of the HMU. We are proposing this AD to prevent an uncommanded in-flight shutdown of the engine, and possible loss of the helicopter.
We must receive comments on this proposed AD by August 6, 2013.
You may send comments, using the procedures found in 14 CFR 11.43 and 11.45, by any of the following methods:
•
•
•
•
For service information identified in this AD, contact Turbomeca, 40220
You may examine the AD docket on the Internet at
Frederick Zink, Aerospace Engineer, Engine Certification Office, FAA, Engine & Propeller Directorate, 12 New England Executive Park, Burlington, MA 01803; phone: 781–238–7779; fax: 781–238–7199; email:
We invite you to send any written relevant data, views, or arguments about this proposed AD. Send your comments to an address listed under the
We will post all comments we receive, without change, to
On January 11, 2013, we issued AD 2013–01–07, Amendment 39–17321 (78 FR 6725, January 31, 2013), for all Turbomeca S.A. Arriel 2D turboshaft engines. That AD requires replacing the HMU at a reduced life. That AD resulted from a low fuel pressure event caused by deterioration and a loss of the low-pressure drive function within the HMU. We issued that AD to prevent an uncommanded in-flight shutdown of the engine, and possible loss of the helicopter.
Since we issued AD 2013–01–07 (78 FR 6725, January 31, 2013), further cases of deterioration of HMU rotating components have been reported before the HMU reached the replacement interval in that AD. Also since we issued AD 2013–01–07, the European Aviation Safety Agency (EASA) issued AD 2013–0079, dated March 22, 2013. EASA's AD imposes the same reduced life as AD 2013–01–07, and, also requires inspections of the HMU.
We reviewed Turbomeca S.A. Alert Mandatory Service Bulletin (MSB) No. A292 73 2847, Version B, dated March 6, 2013. The Alert MSB describes procedures for inspecting and/or replacing the HMU.
We are proposing this AD because we evaluated all the relevant information and determined the unsafe condition described previously is likely to exist or develop in other products of the same type design.
This proposed AD would maintain the existing AD requirements of AD 2013–01–07 (78 FR 6725, January 31, 2013), and would also require inspections of the HMU.
We estimate that this proposed AD would affect 56 Arriel 2D turboshaft engines installed on helicopters of U.S. registry. We also estimate that it would take about two hours per engine to comply with this proposed AD. The average labor rate is $85 per hour. Required parts would cost about $14,400 per engine. Based on these figures, we estimate the total cost of the proposed AD to U.S. operators is $815,920.
Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, Section 106, describes the authority of the FAA Administrator. Subtitle VII, Aviation Programs, describes in more detail the scope of the Agency's authority.
We are issuing this rulemaking under the authority described in Subtitle VII, Part A, Subpart III, Section 44701, “General requirements.” Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.
We have determined that this proposed AD would not have federalism implications under Executive Order 13132. This proposed AD would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government.
For the reasons discussed above, I certify that the proposed regulation:
(1) Is not a “significant regulatory action” under Executive Order 12866,
(2) Is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979),
(3) Will not affect intrastate aviation in Alaska to the extent that it justifies making a regulatory distinction, and
(4) Will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
Air transportation, Aircraft, Aviation safety, Incorporation by reference, Safety.
Accordingly, under the authority delegated to me by the Administrator, the FAA proposes to amend 14 CFR part 39 as follows:
49 U.S.C. 106(g), 40113, 44701.
The FAA must receive comments on this AD action by August 6, 2013.
This AD supersedes AD 2013–01–07, Amendment 39–17321 (78 FR 6725, January 31, 2013).
This AD applies to all Turbomeca S.A. Arriel 2D turboshaft engines.
This AD was prompted by further cases of deterioration of hydromechanical metering unit (HMU) rotating components that have been reported before the HMU reached the replacement interval in AD 2013–01–07 (78 FR 6725, January 31, 2013). We are issuing this AD to prevent an uncommanded in-flight shutdown of the engine, and possible loss of the helicopter.
Comply with this AD within the compliance times specified, unless already done.
(1) Replace inter-pump complete sleeve, and inspect the female splines and HMU high-pressure (HP) pump and low-pressure (LP) pump male splines for corrosion, scaling, cracks and wear, at the following:
(i) Before exceeding 400 HMU operating hours since new if the HMU has 375 or fewer operating hours on the effective date of this AD; or
(ii) Within 25 HMU operating hours if the HMU has more than 375 operating hours on the effective date of this AD; and
(iii) Thereafter, at intervals not to exceed 400 HMU operating hours.
(iv) Use Section 2.B.(1) of the Instructions to be Incorporated of Turbomeca S.A. Alert Mandatory Service Bulletin (MSB) No. A292 73 2847, Version B, dated March 6, 2013, to accomplish the replacement and visual inspection required by paragraph (e)(1) of this AD.
(v) If the HMU does not pass the initial or repetitive visual inspections required by paragraph (e)(1) of this AD, then before next flight, replace the affected HMU with an HMU eligible for installation.
(2) Replace the rotating components of the HP and LP pumps, including the complete sleeve, or replace the HMU with an HMU eligible for installation at the following:
(i) Before exceeding 800 HMU operating hours since new; or
(ii) Within 800 HMU operating hours since last replacement of LP and HP fuel pumps rotating components; whichever occurs later.
(iii) Thereafter, replace the LP and HP fuel pump rotating components within every 800 HMU operating hours.
(iv) Use Section 2.B.(1) of the Instructions to be Incorporated of Turbomeca S.A. Alert MSB No. A292 73 2847, Version B, dated March 6, 2013, to accomplish the replacements required by paragraph (e)(2) of this AD.
If before the effective date of this AD, you complied with Turbomeca S.A. Alert MSB No. A292 73 2847, Version A, dated May 29, 2012, you met the initial inspection requirements in paragraph (e) of this AD. However, you must still comply with the repetitive inspection requirements of this AD.
After the effective date of this AD, do not install any HMU onto any engine, or install any engine onto any helicopter, unless the HMU is in compliance with this AD.
The Manager, Engine Certification Office, may approve AMOCs for this AD. Use the procedures found in 14 CFR 39.19 to make your request.
(1) For more information about this AD, contact Frederick Zink, Aerospace Engineer, Engine Certification Office, FAA, Engine & Propeller Directorate, 12 New England Executive Park, Burlington, MA 01803; phone: 781–238–7779; fax: 781–238–7199; email:
(2) European Aviation Safety Agency AD 2013–0079, dated March 22, 2013, Turbomeca S.A. Alert MSB No. A292 73 2847, Version B, dated March 6, 2013, and Turbomeca Maintenance Manual Task 73–23–00–802–A01, pertain to the subject of this AD.
(3) For service information identified in this AD, contact Turbomeca, 40220 Tarnos, France; phone: 33 (0)5 59 74 40 00; telex: 570 042; fax: 33 (0)5 59 74 45 15. You may view this service information at the FAA, Engine & Propeller Directorate, 12 New England Executive Park, Burlington, MA. For information on the availability of this material at the FAA, call 781–238–7125.
Federal Aviation Administration (FAA), DOT.
Notice of proposed rulemaking (NPRM).
We propose to adopt a new airworthiness directive (AD) for certain Bell Model 407 helicopters. This proposed AD would require installing a placard beneath the NR/NP dual tachometer and revising the limitations section of the rotorcraft flight manual (RFM). This proposed AD is prompted by several incidents of third stage engine turbine wheel failures, which were caused by excessive vibrations at certain engine speeds during steady-state operations. The proposed actions are intended to alert pilots to avoid certain engine speeds during steady-state operations, prevent failure of the third stage engine turbine, engine power loss, and subsequent loss of control of the helicopter.
We must receive comments on this proposed AD by August 6, 2013.
You may send comments by any of the following methods:
•
•
•
•
You may examine the AD docket on the Internet at
For service information identified in this proposed AD, contact Bell Helicopter Textron Canada Limited, 12,800 Rue de l'Avenir, Mirabel, Quebec J7J1R4; telephone (450) 437–2862 or (800) 363–8023; fax (450) 433–0272; or at
Chinh Vuong, Aviation Safety Engineer, Safety Management Group, Rotorcraft Directorate, FAA, 2601 Meacham Blvd., Fort Worth, Texas 76137; telephone (817) 222–5110; email
We invite you to participate in this rulemaking by submitting written comments, data, or views. We also invite comments relating to the economic, environmental, energy, or federalism impacts that might result from adopting the proposals in this document. The most helpful comments reference a specific portion of the proposal, explain the reason for any recommended change, and include supporting data. To ensure the docket does not contain duplicate comments, commenters should send only one copy of written comments, or if comments are filed electronically, commenters should submit only one time.
We will file in the docket all comments that we receive, as well as a report summarizing each substantive public contact with FAA personnel concerning this proposed rulemaking. Before acting on this proposal, we will consider all comments we receive on or before the closing date for comments. We will consider comments filed after the comment period has closed if it is possible to do so without incurring expense or delay. We may change this proposal in light of the comments we receive.
Transport Canada (TC), which is the aviation authority for Canada, has issued TC AD No. CF–2004–09R1, dated July 4, 2005, to correct an unsafe condition for Model 407 helicopters. TC advises of several failures of third stage turbine wheels used in Rolls Royce 250–C30S and 250–C47B engines, and three of these failures have occurred to the 250–C47B engine used by Bell on the Model 407. According to TC, Rolls Royce has determined that detrimental vibrations can occur within a particular range of turbine speeds, and may be a contributing factor to these failures. Bell has revised the operating limitations of the RFM and provided a corresponding decal on the instrument panel to inform pilots to avoid steady-state operations between 68.4% and 87.1% turbine speeds.
The TC AD requires amending the RFMs, advising pilots of the change, and installing a decal as described in Bell Alert Service Bulletin (ASB) No. 407–05–67, dated June 8, 2005 (ASB 407–05–67).
These helicopters have been approved by the aviation authority of Canada and are approved for operation in the United States. Pursuant to our bilateral agreement with Canada, TC, its technical representative, has notified us of the unsafe condition described in its AD. We are proposing this AD because we evaluated all known relevant information and determined that an unsafe condition is likely to exist or develop on other helicopters of the same type design.
Bell has issued ASB 407–05–67, which contains procedures for installing a placard on the instrument panel below the main rotor RPM (Nr)/power turbine RPM (Np) dual tachometer and for inserting the RFM changes into the flight manual.
This proposed AD would require installing a placard on the instrument panel below the NR/NP dual tachometer and revising the Operating Limitations section of the Model 407 RFM to limit steady-state operations between speeds of 68.4% to 87.1%.
The TC AD requires compliance within 10 calendar days; the proposed AD requires compliance within 30 days.
We estimate that this proposed AD would affect 472 helicopters of U.S. Registry. Based on an average labor rate of $85 per hour, we estimate that operators may incur the following costs in order to comply with this AD. Amending the RFM would require about 0.5 work-hours, for a cost per helicopter of about $43 and a cost to U.S. operators of $20,296. Installing the decal would require about 0.2 work-hours and required parts would cost $20, for a cost per helicopter of $37 and a cost to U.S. operators of $17,464. Based on these estimates, the total cost of this proposed AD would be $80 per helicopter and $37,760 for the U.S. operator fleet.
Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. “Subtitle VII: Aviation Programs,” describes in more detail the scope of the Agency's authority.
We are issuing this rulemaking under the authority described in “Subtitle VII, Part A, Subpart III, Section 44701: General requirements.” Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.
We determined that this proposed AD would not have federalism implications under Executive Order 13132. This proposed AD would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government.
For the reasons discussed, I certify this proposed regulation:
1. Is not a “significant regulatory action” under Executive Order 12866;
2. Is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979);
3. Will not affect intrastate aviation in Alaska 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 an economic evaluation of the estimated costs to comply with this proposed 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 proposes to amend 14 CFR part 39 as follows:
49 U.S.C. 106(g), 40113, 44701.
This AD applies to Bell Model 407 helicopters, serial numbers 53000 through 53644, certificated in any category.
This AD defines the unsafe condition as a third stage turbine vibration, which could result in turbine failure, engine power loss, and subsequent loss of control of the helicopter.
We must receive comments by August 6, 2013.
You are responsible for performing each action required by this AD within the specified compliance time unless it has already been accomplished prior to that time.
Within 30 days:
(1) Revise the Operating Limitations section of the Model 407 Rotorcraft Flight Manual by inserting Section 1, Operating Limitations, pages 1–6 and 1–14, of Bell BHT–407–FM–1, revision 3, dated April 26, 2005.
(2) Remove placard part number (P/N) 230–075–213–105, if installed.
(3) Install placard P/N 230–075–213–111, or equivalent, directly below the NR/NP dual tachometer.
(1) The Manager, Safety Management Group, FAA, may approve AMOCs for this AD. Send your proposal to: Chinh Vuong, Aviation Safety Engineer, Safety Management Group, Rotorcraft Directorate, FAA, 2601 Meacham Blvd., Fort Worth, Texas 76137; telephone (817) 222–5110; email
(2) For operations conducted under a 14 CFR part 119 operating certificate or under 14 CFR part 91, subpart K, we suggest that you notify your principal inspector, or lacking a principal inspector, the manager of the local flight standards district office or certificate holding district office before operating any aircraft complying with this AD through an AMOC.
(1) Bell Alert Service Bulletin No. 407–05–67, dated June 8, 2005, which is not incorporated by reference, contains additional information about the subject of this AD. For service information identified in this AD, contact Bell Helicopter Textron Canada Limited, 12,800 Rue de l'Avenir, Mirabel, Quebec J7J1R4; telephone (450) 437–2862 or (800) 363–8023; fax (450) 433–0272; or at
(2) The subject of this AD is addressed in Transport Canada AD No. CF–2004–09R1, dated July 4, 2005.
Joint Aircraft Service Component (JASC) Code: 7250: Turbine Section.
Federal Aviation Administration (FAA), DOT.
Notice of proposed rulemaking (NPRM).
We propose to adopt a new airworthiness directive (AD) for Eurocopter France (Eurocopter) Model AS332L2 and EC225LP helicopters. This proposed AD would require inspecting the torque value of the bolts that secure the front and rear main gearbox (MGB) suspension bar attaching fittings, and re-torqueing the bolts to the proper value if the torque value is out of tolerance. This proposed AD would also require, if the torque value is out of tolerance by more than 20 percent, inspecting the bolts, frames, and related equipment for a crack and repairing or replacing them if cracked. This proposed AD is prompted by reports of cracks on Frame 5295 of Model AS332L2 helicopters. These actions are intended to detect the torque loss of the bolts that secure the MGB bar attaching fittings and to prevent cracks that could lead to failure of the MGB supporting structure, detachment of the MGB, and loss of helicopter control.
We must receive comments on this proposed AD by August 6, 2013.
You may send comments by any of the following methods:
•
•
•
•
You may examine the AD docket on the Internet at
For service information identified in this proposed AD, contact American Eurocopter Corporation, 2701 N. Forum Drive, Grand Prairie, TX 75052; telephone (972) 641–0000 or (800) 232–0323; fax (972) 641–3775; or at
Gary Roach, Aviation Safety Engineer, Regulations and Policy Group, Rotorcraft Directorate, FAA, 2601 Meacham Blvd., Fort Worth, Texas 76137; telephone (817) 222–5110; email
We invite you to participate in this rulemaking by submitting written comments, data, or views. We also invite comments relating to the economic, environmental, energy, or federalism impacts that might result from adopting the proposals in this document. The most helpful comments reference a specific portion of the proposal, explain the reason for any recommended change, and include supporting data. To ensure the docket does not contain duplicate comments, commenters should send only one copy of written comments, or if comments are filed electronically, commenters should submit only one time.
We will file in the docket all comments that we receive, as well as a report summarizing each substantive public contact with FAA personnel concerning this proposed rulemaking. Before acting on this proposal, we will consider all comments we receive on or before the closing date for comments. We will consider comments filed after the comment period has closed if it is possible to do so without incurring
Direction Générale de l'Aviation Civile (DGAC), the aviation authority for France, has issued AD No. F–2006–020 for Model AS 332 L2 helicopters and AD No. F–2006–021 for Model EC 225 LP helicopters, both dated February 1, 2006, to correct an unsafe condition in those model helicopters. The DGAC ADs require conducting visual checks after the last flight of each day for cracks in the outer skin paneling and the butt strap of the MGB sliding cowling left and right attachment points on Frame 5295. If a crack is found in the outer skin paneling Zone 2, then the DGAC ADs require visually inspecting the corresponding Zone 2 of Frame 5295 for a crack and suspending all flights if a crack is found. If no crack is found through visual inspections, the DCAG ADs provide instructions for further inspections and repairs. Issues with the outer skin paneling were resolved by the time the FAA certificated the EC225 on January 30, 2008.
The European Aviation Safety Agency (EASA), which is the Technical Agent for the Member States of the European Community, issued AD No. 2006–102–E, which superseded DGAC AD F–2006–021, and AD No. 2006–103–E, which superseded DGAC AD F–2006–020. Both EASA ADs are dated April 25, 2006. AD Nos. 2006–102–E and 2006–103–E retain the requirements of the DGAC ADs but expand the area to be inspected.
EASA then issued AD No. 2006–0163, dated June 9, 2006, to supplement the requirements of AD Nos. 2006–102–E and 2006–103–E by mandating that the bolts securing the front and rear of the MGB bar attaching fittings be inspected for tightening torque loss. According to EASA, analysis of the tightening torques revealed some cases of tightening torque loss, which can lead to the formation of a crack at the MGB bar attaching fittings. EASA subsequently issued AD No. 2006–0163 R1, dated December 13, 2007, which revises and replaces AD No. 2006–0163, retaining its requirements but extending the compliance interval for inspecting the bolts on Model EC 225 LP helicopters.
These helicopters have been approved by the aviation authority of France and are approved for operation in the United States. Pursuant to our bilateral agreement with France, EASA, its technical representative, has notified us of the unsafe condition described in its AD. We are proposing this AD because we evaluated all known relevant information and determined that an unsafe condition is likely to exist or develop on other products of the same type design.
We reviewed Eurocopter Alert Service Bulletin (ASB) No. 05.00.65, Revision 0, dated March 28, 2006, for Model AS332L2 helicopters, and ASB No. 05A002, Revision 1, dated December 6, 2007, for Model EC225LP helicopters. The ASBs specify inspecting the tightening torque of the bolts that secure the front and rear of the MGB bar attaching fittings. If more than a 20 percent tightening torque load loss is discovered, the ASBs require inspecting the frames 3855 and 5295 for a crack in the area of the MGB bar attaching fittings. EASA classified these ASBs as mandatory and issued EASA AD No. 2006–0163 R1, dated December 13, 2007, to ensure the continued airworthiness of these helicopters.
This proposed AD would require repetitively inspecting the tightening torque value of the bolts that secure the front and rear MGB suspension bar attaching fittings. If the torque value is out of tolerance 20 percent or less, then the proposed AD would require that each bolt be re-torqued to the proper value. If the torque value is out of tolerance more than 20 percent, then this proposed AD would require re-torqueing each bolt to the proper value and inspecting the bolts, frame, and related equipment for a crack. If a cracked bolt is detected, this AD would require replacing all four attaching fitting bolts. If a crack in the frame or other equipment is detected, this proposed AD would require repairing or replacing the cracked frame and other equipment.
This AD differs from the EASA AD in that we use the word “inspect” to describe actions required by a mechanic versus the word “check,” which is how we describe actions allowed by a pilot. We also require that if you find a crack in a frame or fitting, you repair or replace the cracked part instead of contacting the manufacturer. Also, we have different compliance times for the initial inspection for the tightening torque of the bolts that secure the MGB attaching fitting.
We estimate that this proposed AD would affect 4 helicopters of U.S. Registry and that labor costs would average $85 a work-hour. Based on these estimates, we would expect the following costs:
• Inspecting the torque of each bolt that secures the front and rear MGB attaching fitting would require 1 work-hour and no parts for a total cost of $85 per helicopter, and $340 for the U.S. fleet.
• Readjusting the torque would add another 0.25 work-hour for a total cost of about $21 per helicopter.
• Replacing all four nuts and bolts of an attachment fitting would require 4 work-hours. Parts would cost $1,000 for a total cost of $1,340 per helicopter.
• Replacing the attachment fitting or plate would require 16 work-hours respectively. Parts would cost $2,000 respectively for a total cost of $3,360 to replace each part per helicopter.
• Replacing frames 3855 and 5295 would require 40 work-hours respectively. Parts would cost $5,000 to replace each frame for a total cost of $8,400 per frame per helicopter.
Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. “Subtitle VII: Aviation Programs,” describes in more detail the scope of the Agency's authority.
We are issuing this rulemaking under the authority described in “Subtitle VII, Part A, Subpart III, Section 44701: General requirements.” Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.
We determined that this proposed AD would not have federalism implications under Executive Order 13132. This proposed AD would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government.
For the reasons discussed, I certify this proposed regulation:
1. Is not a “significant regulatory action” under Executive Order 12866;
2. Is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979);
3. Will not affect intrastate aviation in Alaska 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 an economic evaluation of the estimated costs to comply with this proposed 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 proposes to amend 14 CFR part 39 as follows:
49 U.S.C. 106(g), 40113, 44701.
This AD applies to Eurocopter France (Eurocopter) Model AS332L2 and EC225LP helicopters, certificated in any category.
This AD defines the unsafe condition as loss of tightening torque of a bolt that secures the front and rear main gearbox (MGB) suspension bar attaching fittings, which can change the loads on the frames and cause cracking. This condition could lead to failure of the MGB supporting structure, detachment of the MGB, and subsequent loss of control of the helicopter.
We must receive comments by August 6, 2013.
You are responsible for performing each action required by this AD within the specified compliance time unless accomplished previously.
(1) Within 500 hours time-in-service (TIS), and thereafter at intervals not to exceed 825 hours TIS, inspect the tightening torque of each bolt that secures the front and rear MGB attaching fitting by using as reference Figure 1 of Eurocopter Alert Service Bulletin (ASB) No. 05.00.65, Revision 0, dated March 28, 2006, for the Model AS332L2 helicopters; and ASB No. 05A002, Revision 1, dated December 6, 2007, for the Model EC225LP helicopters.
(2) If the loss of tightening torque of a nut is less than or equal to 20 percent of the minimum tightening torque, before further flight, readjust the tightening torque.
(3) If the loss of tightening torque of any nut (front or rear) is greater than 20 percent of the minimum tightening torque, before further flight:
(i) Inspect each bolt and nut that secures the attachment fitting for a crack, and
(ii) Inspect for a crack in the attachment area of the attachment fitting, the attachment plate, and Frame 3855 for the front fitting and Frame 5295 for the rear fitting.
(A) If no crack exists, readjust the tightening torque.
(B) If there is a crack in any nut or bolt, before further flight, replace all four nuts and bolts of the affected attachment fitting.
(C) If there is a crack in the attachment area of the attachment fitting or the attachment plate, before further flight, replace the cracked attachment fitting or plate with an airworthy fitting or plate.
(D) If there is a crack in Frame 3855 for the front fitting or Frame 5295 for the rear fitting, before further flight, repair or replace the frame.
(1) The Manager, Safety Management Group, FAA, may approve AMOCs for this AD. Send your proposal to: Gary Roach, Aviation Safety Engineer, Regulations and Policy Group, Rotorcraft Directorate, FAA, 2601 Meacham Blvd., Fort Worth, Texas 76137; telephone (817) 222–5110; email
(2) For operations conducted under a 14 CFR part 119 operating certificate or under 14 CFR part 91, subpart K, we suggest that you notify your principal inspector, or lacking a principal inspector, the manager of the local flight standards district office or certificate holding district office before operating any aircraft complying with this AD through an AMOC.
The subject of this AD is addressed in European Aviation Safety Agency AD No. 2006–0163 R1, dated December 13, 2007.
Joint Aircraft Service Component (JASC) Code: 6330, Main Rotor Transmission Mount.
Federal Aviation Administration (FAA), DOT.
Notice of proposed rulemaking (NPRM).
We propose to adopt a new airworthiness directive (AD) for certain Bell Model 430 helicopters. This proposed AD would require installing a placard on the instrument panel and revising the limitations section of the rotorcraft flight manual (RFM). This proposed AD is prompted by several incidents of third stage engine turbine wheel failures, which were caused by excessive vibrations at certain engine speeds during steady-state operations. The proposed actions are intended to alert pilots to avoid certain engine speeds during steady-state operations, prevent failure of the third stage engine turbine, engine power loss, and subsequent loss of control of the helicopter.
We must receive comments on this proposed AD by August 6, 2013.
You may send comments by any of the following methods:
•
•
•
•
You may examine the AD docket on the Internet at
For service information identified in this proposed AD, contact Bell Helicopter Textron Canada Limited, 12,800 Rue de l'Avenir, Mirabel, Quebec J7J1R4; telephone (450) 437–2862 or (800) 363–8023; fax (450) 433–0272; or at
Chinh Vuong, Aviation Safety Engineer, Safety Management Group, Rotorcraft Directorate, FAA, 2601 Meacham Blvd., Fort Worth, Texas 76137; telephone (817) 222–5110; email
We invite you to participate in this rulemaking by submitting written comments, data, or views. We also invite comments relating to the economic, environmental, energy, or federalism impacts that might result from adopting the proposals in this document. The most helpful comments reference a specific portion of the proposal, explain the reason for any recommended change, and include supporting data. To ensure the docket does not contain duplicate comments, commenters should send only one copy of written comments, or if comments are filed electronically, commenters should submit only one time.
We will file in the docket all comments that we receive, as well as a report summarizing each substantive public contact with FAA personnel concerning this proposed rulemaking. Before acting on this proposal, we will consider all comments we receive on or before the closing date for comments. We will consider comments filed after the comment period has closed if it is possible to do so without incurring expense or delay. We may change this proposal in light of the comments we receive.
Transport Canada (TC), which is the aviation authority for Canada, has issued TC AD No. CF–2005–25, dated July 5, 2005, to correct an unsafe condition for Model 430 helicopters. TC advises of several failures of third stage turbine wheels used in Rolls Royce 250–C30S and 250–C47B engines and that a similar turbine wheel is installed on the 250–C40B engine used by Bell on Model 430 helicopters. According to TC, Rolls Royce has determined that detrimental vibrations can occur within a particular range of turbine speeds, and may be a contributing factor to these failures. Bell has revised the operating limitations of the RFM and has provided a corresponding decal on the instrument panel to inform pilots to avoid steady-state operations between 71% and 91% turbine speeds.
The TC AD requires amending the RFM, advising pilots of the change, and installing a decal as described in Bell Alert Service Bulletin (ASB) No. 430–05–34, dated June 10, 2005 (ASB 430–05–34).
These helicopters have been approved by the aviation authority of Canada and are approved for operation in the United States. Pursuant to our bilateral agreement with Canada, TC, its technical representative, has notified us of the unsafe condition described in its AD. We are proposing this AD because we evaluated all known relevant information and determined that an unsafe condition is likely to exist or develop on other helicopters of the same type design.
Bell has issued ASB 430–05–34, which contains procedures for installing a placard on the instrument panel and for inserting the RFM changes into the flight manual.
This proposed AD would require installing a placard on the instrument panel and revising the Operating Limitations section of the Model 430 RFM to limit steady-state operations between speeds of 71% and 91%.
The TC AD requires compliance within 10 calendar days, the proposed AD requires compliance within 30 days.
We estimate that this proposed AD would affect 37 helicopters of U.S. Registry. Based on an average labor rate of $85 per hour, we estimate that operators may incur the following costs in order to comply with this AD. Amending the RFM would require about 0.5 work-hours, for a cost per helicopter of about $43 and a cost to U.S. operators of $1,591. Installing the decal would require about 0.2 work-hours and required parts would cost $20, for a cost per helicopter of $37 and a cost to U.S. operators of $1,369. Based on these estimates, the total cost of this proposed AD would be $80 per helicopter and $2,960 for the U.S. operator fleet.
Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. “Subtitle VII: Aviation Programs,” describes in more detail the scope of the Agency's authority.
We are issuing this rulemaking under the authority described in “Subtitle VII, Part A, Subpart III, Section 44701: General requirements.” Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.
We determined that this proposed AD would not have federalism implications under Executive Order 13132. This proposed AD would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government.
For the reasons discussed, I certify this proposed regulation:
1. Is not a “significant regulatory action” under Executive Order 12866;
2. Is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979);
3. Will not affect intrastate aviation in Alaska 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 an economic evaluation of the estimated costs to comply with this proposed 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,
49 U.S.C. 106(g), 40113, 44701.
This AD applies to Bell Model 430 helicopters, serial number 49001 through 49111, certificated in any category.
This AD defines the unsafe condition as a third stage turbine vibration, which could result in turbine failure, engine power loss, and subsequent loss of control of the helicopter.
We must receive comments by August 6, 2013.
You are responsible for performing each action required by this AD within the specified compliance time unless it has already been accomplished prior to that time.
Within 30 days:
(1) Revise the Operating Limitations section of the Model 430 Rotorcraft Flight Manual by inserting Section 1, Limitations, page 1–7, of Bell BHT–430–FM–1, revision 18, dated September 1, 2009.
(2) Install placard part number 230–075–213–113, or equivalent, on the instrument panel directly below the pilot audio select panel.
(1) The Manager, Safety Management Group, FAA, may approve AMOCs for this AD. Send your proposal to: Chinh Vuong, Aviation Safety Engineer, Safety Management Group, Rotorcraft Directorate, FAA, 2601 Meacham Blvd., Fort Worth, Texas 76137; telephone (817) 222–5110; email
(2) For operations conducted under a 14 CFR part 119 operating certificate or under 14 CFR part 91, subpart K, we suggest that you notify your principal inspector, or lacking a principal inspector, the manager of the local flight standards district office or certificate holding district office before operating any aircraft complying with this AD through an AMOC.
(1) Bell Alert Service Bulletin No. 430–05–34, dated June 10, 2005, which is not incorporated by reference, contains additional information about the subject of this AD. For service information identified in this AD, contact Bell Helicopter Textron Canada Limited, 12,800 Rue de l'Avenir, Mirabel, Quebec J7J1R4; telephone (450) 437–2862 or (800) 363–8023; fax (450) 433–0272; or at
(2) The subject of this AD is addressed in Transport Canada AD No. CF–2005–25, dated July 5, 2005.
Joint Aircraft Service Component (JASC) Code: 7250: Turbine Section.
Office of the Secretary, DoD.
Proposed rule.
This proposed rule would establish an exception to the usual rule that TRICARE Prime enrollment fees are uniform for the group of retirees and their dependents. Survivors and medically retired members are part of the retiree group under TRICARE rules. This exception would allow Survivors of Active Duty Deceased Sponsors and Medically Retired Uniformed Services Members and their Dependents enrolled in Prime to be exempt from future increases in TRICARE Prime enrollment fees. The Prime beneficiaries in these categories prior to 10/1/2013 would have their annual enrollment fee frozen at their current annual rate (FY 2011 rate $230 per single or $460 per family, FY 2012 rate $260 or $520, or the FY 2013 rate $269.38 or $538.56). The beneficiaries added to these categories on or after 10/1/2013 would have their fee frozen at the rate in effect at the time they are classified in either category and enroll in Prime or, if not enrolling, at the rate in effect at the time of enrollment. The fee remains frozen as long as at least one family member remains enrolled in Prime and there is not a break in enrollment. The fee charged for the dependent(s) of a Medically Retired Uniformed Services Member would not change if the dependent(s) was later re-classified a Survivor.
Written comments received at the address indicated below by August 6, 2013 will be considered and addressed in the final rule.
You may submit comments, identified by docket number and or RIN number and title, by any of the following methods:
•
•
Ralph (Doug) McBroom, (703) 681–0039, TRICARE Management Activity, TRICARE Policy and Operations Directorate. Questions regarding payment of specific claims under the TRICARE allowable charge method should be addressed to the appropriate TRICARE contractor.
With respect to TRICARE Prime enrollment fees, the regulation (32 CFR 199.18(c)) currently includes the following provision: “The specific enrollment fee requirements shall be published annually by the Assistant Secretary of Defense (Health Affairs), and shall be uniform within the following groups: dependents of active duty members in pay grades of E–4 and below; active duty dependents of sponsors in pay grades E–5 and above; and retirees and their dependents.” There is no enrollment fee for active duty dependents. The annual enrollment fee
Although the increases have been modest, TRICARE intends to exempt from this increase Survivors of Active Duty Deceased Sponsors and Medically Retired Uniformed Services Members and their Dependents enrolled in Prime. The enrollment fees for the current beneficiaries in these categories would remain at their current rate. The beneficiaries added to these categories on or after 10/1/2013 would have their fee frozen at the rate in effect at the time they are classified in either category and enroll in Prime or, if not enrolling, at the rate in effect at the time of enrollment. The fee remains frozen as long as at least one family member remains enrolled in TRICARE Prime and there is not a break in enrollment. To allow this exemption to be implemented, a change to the regulation is needed to authorize an exception to the general rule that the enrollment fees “shall be uniform” for the group of retirees and their dependents. (Survivors and medically retired members are part of the retiree group under TRICARE rules.) This proposed rule articulates that change. It provides that as an exception to the requirement for uniformity within the group of retirees and their dependents, the Assistant Secretary of Defense (Health Affairs) may exempt Survivors of Active Duty Deceased Sponsors and Medically Retired Uniformed Services Members and their dependents from increases in enrollment fees that occur on or after October 1, 2013.
It is the Department's intent that the exemption will apply only to the beneficiaries in the two categories specified above and only if they enroll in TRICARE Prime. If a beneficiary in one of the categories does not enroll in Prime, but later elects to enroll, their rate would be frozen at the rate in effect at the time of enrollment. If a beneficiary dis-enrolls from Prime and later re-enrolls, their rate would be frozen at the rate in effect at re-enrollment. The fee charged for a dependent of a Medically Retired Uniformed Services Member would not change if the dependent was later re-classified a Survivor and remained enrolled in Prime.
Executive Orders 12866 and 13563 require certain regulatory assessments for any significant regulatory action that would result in an annual effect on the economy of $100 million or more, or have other substantial impacts. The Congressional Review Act establishes certain procedures for major rules, defined as those with similar major impacts. The Regulatory Flexibility Act (RFA) requires that each Federal agency prepare, and make available for public comment, a regulatory flexibility analysis when the agency issues a regulation that would have significant impact on a substantial number of small entities. This proposed rule will have none of those effects. Nor does it establish information collection requirements under the Paperwork Reduction Act. Nor for purposes of Executive Order 13132 does it have federalism implications affecting States.
Claims, Handicapped, Health insurance, and Military personnel.
Accordingly, 32 CFR part 199 is proposed to be amended as follows:
5 U.S.C. 301; 10 U.S.C. chapter 55.
(c)
Coast Guard, DHS.
Supplemental notice of proposed rulemaking and notice of public meeting.
This supplemental notice of proposed rulemaking (SNPRM) proposes revisions to the existing Regulated Navigation Area (RNA) established to protect the floodwalls and levees in the New Orleans area from possible storm surge damage caused by floating vessels. The Coast Guard proposes to revise the areas where floating vessels are prohibited and other areas where floating vessels will be restricted within the Gulf Intracostal Waterway (GIWW), the Inner Harbor Navigation Canal (IHNC), the Harvey Canal, and the Algiers Canal. This action is necessary for the flood protection of high-risk areas throughout the Greater New Orleans Area when a tropical event threatens to approach and impact the area.
Comments and related material must be received by the Coast Guard on or before August 6, 2013. A public meeting will be held in New Orleans, LA, to discuss this regulated navigation area on June 20, 2013, at 5 p.m. local time.
Written comments. You may submit comments identified by docket number using any one of the following methods:
(1)
(2)
(3)
See the “Public Participation and Request for Comments” portion of the
If you have questions on this rule, call or email LCDR Brandon Sullivan, Sector New Orleans Waterways Division, U.S. Coast Guard; telephone (504) 365–2281, email
We encourage you to participate in this rulemaking by submitting comments and related materials. All comments received will be posted without change to
If you submit a comment, please include the docket number for this rulemaking, indicate the specific section of this document to which each comment applies, and provide a reason for each suggestion or recommendation. You may submit your comments and material online at
To submit your comment online, go to
If you submit your comments by mail or hand delivery, submit them in an unbound format, no larger than 8
To view comments, as well as documents mentioned in this preamble as being available in the docket, go to
Anyone can search the electronic form of comments received into any of our dockets by the name of the individual submitting the comment (or signing the comment, if submitted on behalf of an association, business, labor union, etc.). You may review a Privacy Act notice regarding our public dockets in the January 17, 2008, issue of the FR (73 FR 3316).
We plan to hold one public meeting on June 20, 2013, at 5 p.m. local time at Dillard University located at 2601 Gentilly Boulevard, New Orleans, LA 70122. This meeting will be held in the Georges Auditorium, located in the Professional Schools and Science Building. The gate guard at this institution will instruct each participant of the exact location on the campus. The Coast Guard will draft minutes of this meeting and post them to the public docket for review. For information on facilities or services for individuals with disabilities or to request special assistance at the public meeting, contact the person named in the
On May 14, 2009, the Coast Guard published a notice of proposed rulemaking (NPRM) entitled “Regulated Navigation Area; Gulf Intracoastal Waterway, Inner Harbor Navigation Canal, Harvey Canal, Algiers Canal, New Orleans, LA” in the
In this SNPRM, the Coast Guard proposes changes to the requirements of the RNA from those in the interim rule. In developing these requirements, the Coast Guard established an RNA Work Group comprised of Federal, State, and local flood protection authorities, and port industry representatives. We held three meetings with this work group and used input from the group to address the protections still necessary and developed the restrictions to provide those protections. The minutes from those meetings are available for public viewing on the docket. In addition to the work group meetings, the Coast
The legal basis for this SNPRM is the Ports and Waterways Safety Act (PWSA), 33 U.S. Code 1221 et seq., as well as the Coast Guard's authority to establish RNAs under 33 CFR part 165. The purpose of this SNPRM is to permanently establish the RNA to protect floodwalls and levees in the New Orleans area from possible storm damage caused by moored barges and vessels, and to avoid flooding in the New Orleans area that could result from that storm damage.
This SNPRM proposes changes to the interim RNA to fit the needs now that the flood protection system is complete. This SNPRM builds upon the Interim Rule in place since 2010 to respond to these risks. Without this RNA, when navigational structures within the HSDRRS are to be closed because of an approaching storm, the Coast Guard would have to individually order each vessel within the subject area to depart or to comply with specific mooring arrangements. Issuing individual orders places a significant administrative burden on the Coast Guard during a time when important pre-storm preparations must also be made. By proposing this rule, the Coast Guard is informing the public in advance of the restrictions and requirements for vessels in the area during periods of enforcement, thus eliminating the need for individual Captain of the Port Orders.
An additional purpose of this RNA is to aid the Coast Guard in the early identification of vessels that may not depart the RNA when required. Under the PWSA, the Coast Guard has no authority to take possession of, and move these vessels during emergency periods such as the approach of a hurricane. Rather, Coast Guard enforcement is limited to imposing civil or criminal penalties on anyone who fails to comply with the requirements of an order or regulation issued under PWSA. Therefore early identification of vessels that may be unwilling to depart the area, or unable to remain safely moored within the area during a storm, is extremely important as it will give the Coast Guard time to consider alternatives and work with interagency authorities and vessel & facility representatives to appropriately resolve the problem well in advance of a storm.
The Coast Guard received five comments to the interim rule published in 2010. Collectively, these comments requested an extended commenting period; supported the use of waivers and prearranged agreements that would permit a vessel to remain in the RNA during a closure; requested clarification on the requirements for a mooring plan or prearranged agreement; and objected to the use of an 8′ and 10.5′ storm surge as a trigger for activating the RNA. The requirements of the RNA in this SNPRM are significantly different from those of the interim rule. While these changes were not made in direct response to the submitted comments, many of the changes do address some of the issues raised by the submitted comments. For example, the technical requirements for a mooring agreement and the elimination of storm surge as a trigger for activating the RNA are described in more detail below. One comment also urged the Coast Guard to disestablish the RNA when the ACOE completed its flood control projects. However, the Coast Guard has determined that this RNA is still necessary to protect the flood control structures by ensuring that only those vessels that are safely and securely moored remain within the area during a tropical weather event.
Based on completion of the flood protection systems and the specifications for those systems as provided to the Coast Guard, and to further reduce the potential risks to the HSDRRS from floating vessels during tropical events, the Coast Guard is proposing to expand the geographic parameters of the RNA currently published at 33 CFR 165.838, and to revise the requirements related to that area. The area of the new proposed RNA includes: (1) The GIWW from Mile Marker (MM) 22 East of Harvey Locks, west on the GIWW, including the Michoud Canal and the IHNC, extending North
These additional areas include the Michoud Canal on the GIWW, which will protect the pumping stations located at the entrance of the Michoud Canal. The COTP has also included the waters extending
The Coast Guard proposes to enforce each portion of the RNA beginning 24 hours prior to the closure of the main gate within that portion of the flood protection system (IHNC Surge Barrier for the east portion and West Closure Complex for the west portion). Closure of main gates within the flood protection system was chosen as the RNA enforcement trigger since it signals full implementation of actions necessary to protect populated areas from hurricane-related flooding. Closure of these structures also cuts off main egress routes for vessels to comply with RNA requirements. When main gates are closed, RNA implementation needs to be complete.
If the Coast Guard received notice of closure of any or all of the flood protection structures within the HSDRRS less than 24 hours before the closure, the RNA will be enforced upon the Coast Guard receiving the notice. Additionally, in the event that a particularly dangerous storm is predicted, the COTP may require all floating vessels to evacuate the RNA beginning as early as 72 hours before predicted closure of any flood protection closure structure, or upon notice that particularly dangerous storm conditions are approaching, whichever is less. This enforcement option is intended to give the COTP the discretion to begin early enforcement of the RNA when a storm presents a greater than usual threat, to better ensure the conditions of the RNA are met. The Coast Guard has chosen not to include a specific definition of “particularly dangerous storm” at this time, however the Coast Guard does seek public comment on whether such a definition is necessary, and the factors that should be considered when determining if a storm qualifies as “particularly dangerous.”
Early in the development of this SNPRM, the Coast Guard considered including forecast wind and minimum standing water levels within the canals
The Coast Guard is proposing that all floating vessels be prohibited from entering into or remaining in the RNA during the enforcement period with some exceptions. In the Interim Rule, the Coast Guard allows vessels to remain during RNA enforcement only if they have an approved waiver from the COTP. These waivers are valid for one year and require resubmission and approval each hurricane season. As a result of comments from maritime industry representatives and flood protection authorities voicing concern that an annual waiver process may be subject to differing interpretations over time, and expressing a desire for long-term consistency and predictability, the Coast Guard is proposing to transition from a waiver system to a performance-based system. This system includes minimum mooring, documentation, facility oversight, and standby towing vessel requirements for vessels to remain in certain lower risk portions of the RNA and will ensure consistent enforcement and application over the long-term.
During the period of enforcement, floating vessels may remain in the Michoud Canal at least
During the period of enforcement, vessels may transit through the RNA en route to a destination outside of the RNA, given that there is sufficient time to do so prior to the closure of a navigational structure, or they may transit to a facility within the RNA with which they have a prearranged mooring agreement. These types of transits will be closely monitored and discussed within the Port Coordination Team activated by the COTP as part of the Maritime Hurricane Contingency Port Plan.
This SNPRM proposes to require additional information from facilities located in the RNA that intend to keep vessels at the facility during enforcement of the RNA. All facilities that have vessels intending to remain within the areas allowed within this RNA would have to develop an Annual Hurricane Operations Plan, readily available for Coast Guard and USACE inspection. For the purpose of this Rulemaking, facilities is defined as a fleeting, mooring, industrial facility or marina along the shoreline at which vessels are or can be moored and which owns, possesses, moors, or leases vessels located in the area defined by this regulation that could pose a risk to the flood protection system. This plan describes details of mooring arrangements in accordance with the mooring requirements and conditions set forth in this SNPRM and must be submitted by May 1st of each calendar year. Information that must be included in this plan includes a diagram of the facility and fleeting area, characteristics for each vessel the facility intends to keep in the RNA during enforcement, and 24-hour contact information for qualified individuals who are empowered to make on-site decisions regarding pollution response and salvage.
Also, as part of the Annual Hurricane Operations Plan, a professional engineer must clearly certify in the Hurricane Operations Plan that the mooring arrangements are able to withstand winds of up to 140 mph, a water level of eleven feet, a current of four mph and a wave height of three feet within the canal basin in the area defined in the regulatory text section of paragraph (a)(1), and withstand winds of up to 140 mph, a water level of eight feet, a current of four mph, and a wave height of two and one half feet within the canal basin in the areas defined in the regulatory text section of paragraphs (a)(2–4). The Coast Guard is proposing these standards based on discussions and technical information, including UFC 4–159 and American Society of Civil Engineers (ASCE) 7, presented by the USACE at the RNA Work Group Sessions and a letter between USACE and Coast Guard which has been uploaded to the docket for review. The eleven and eight foot water levels proposed in this RNA for the Annual Hurricane Operations Plan are consistent with the USACE's recommendations in discussions with the Coast Guard. Therefore, the Coast Guard is proposing a standard consistent with maximum potential water levels within the designed HSDRRS system as defined by the USACE. The Coast Guard is proposing the 140 mph wind speed, which is the maximum American Society of Civil Engineers (ASCE) 7 three second gust velocity in the New Orleans area, to decrease risk from a vessel breaking away from its mooring.
At least 72 hours prior to the predicted closure of the navigational structures, the Coast Guard is proposing that those facilities that have vessels that intend to remain within the allowable portions of the RNA must submit a Storm Specific Verification Report to the COTP New Orleans. The requirements for this report are located in the Canal Hurricane Operations Plan, which is Enclosure Six to the Sector New Orleans Maritime Hurricane Contingency Port Plan,
As mentioned above, one purpose of the Annual Hurricane Operations Plan is to ensure that vessels remaining within the RNA during enforcement comply with the mooring requirements of this proposed rule. Those requirements prohibit vessels from being secured to trees or other vegetation, from being moored with frayed lines, from being moored side to side unless secured to each other from fitting as close to each corner of abutting sides as practicable, etc. These mooring requirements also prescribe requirements for various types of rigging; specifically that wire rope must be of at least 1
This SNPRM also requires detailed facility information be maintained on all inspections required within this SNPRM by the facility. This will ensure quality checks are provided to ensure mooring standards and configurations are adequate. These facility led inspections will be made available for COTP and USACE “verification” checks at all times during enforcement of the RNA.
The Coast Guard is also proposing a requirement for every facility with eight or more vessels that are not under their own power to maintain one tug on scene for every 50 vessels in case of an emergency.
We developed this proposed rule after considering numerous statutes and executive orders related to rulemaking. Below we summarize our analyses based on a number of these statutes or executive orders.
This proposed rule is not a significant regulatory action under section 3(f) of Executive Order 12866, Regulatory Planning and Review, as supplemented by Executive Order 13563, Improving Regulation and Regulatory Review, and does not require an assessment of potential costs and benefits under section 6(a)(3) of Executive Order 12866 or under section 1 of Executive Order 13563. The Office of Management and Budget has not reviewed it under those Orders.
In determining if this rule was a significant regulatory action, the Coast Guard considered alternatives so as not to unduly impact the segment of the economy impacted by the RNA. The Coast Guard incorporated into the regulatory requirements a provision that enables plans to be submitted with alternative minimum mooring requirements which will be reviewed by the COTP on a case-by-case basis. This provision enables the Coast Guard to review and allow mooring alternatives such as piling systems that permanently moor a vessel not intending to move from its berth that present an equal or greater level of safety under the regulation in an effort to mitigate possible regulatory and economic impacts. The Coast Guard also provided a series of questions for industry comment with the sole purpose of determining regulatory and economic impact. The questions were provided to those entities that had submitted waivers to remain in the RNA under the Interim Rule, along with the responses received, are available for public viewing in the docket.
Based on responses to the questions, the Coast Guard modified the proposed tug boat requirements for on-scene monitoring of vessels during RNA enforcement. The Coast Guard originally contemplated requiring each facility with three or more vessels to have one tug on-scene for every 25 vessels. As a result of the Coast Guard's outreach to industry with these questions and subsequent responses indicating an unnecessary economic hardship, the Coast Guard modified this requirement. This SNPRM proposes every facility with eight or more vessels to maintain one tug for every 50 vessels which significantly reduces the economic impact on industry but still provides a substantial measure of safety in the event that tugs are required in an emergency.
The Coast Guard is requesting comments on any proposed changes that may have an economic hardship from any entity that may be affected by this RNA.
Under the Regulatory Flexibility Act (5 U.S.C. 601–612), we have considered the impact of this proposed rule on small entities. The Coast Guard certifies under 5 U.S.C. 605(b) that this proposed rule will not have a significant economic impact on a substantial number of small entities. This proposed rule would affect the following entities, some of which might be small entities: The owners or operators of vessels intending to transit or moor in the RNA during enforcement, and the owners or operators or facilities in the RNA who intend to keep vessels at their facility during enforcement of the RNA. On a case by case basis, the Coast Guard will continue to review alternatives to the minimum mooring requirements for those that have an equal or greater measure of safety. This provision supports the Coast Guard's ongoing effort to keep this rulemaking from having a significant economic impact on a substantial number of small entities. Therefore small entities have the option of remaining in place during RNA enforcement by submitting, and having approved, an alternative mooring plan that explains how the small entity intends to ensure safe conditions on the navigable waterways during a tropical event. In addition, alternate routes for vessel traffic exist for departure from the area before the RNA goes into effect.
If you think that your business, organization, or governmental jurisdiction qualifies as a small entity and that this rule would have a significant economic impact on it, please submit a comment (see
Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Pub. L. 104–121), we want to assist small entities in understanding this proposed rule. If the rule would affect your small business, organization, or governmental jurisdiction and you have questions concerning its provisions or options for compliance, please contact the person listed in the
This proposed rule will not call for a new collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501–3520.). While the Coast Guard did solicit information from the maritime industry concerning this rulemaking, the Coast Guard did not ask questions that would meet the guidelines of a new collection of information.
A rule has implications for federalism under Executive Order 13132, Federalism, if it has a substantial direct effect on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government. We have analyzed this proposed rule under that Order and determined that this rule does not have implications for federalism.
The Coast Guard respects the First Amendment rights of protesters. Protesters are asked to contact the person listed in the
The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531–1538) requires Federal agencies to assess the effects of their discretionary regulatory actions. In particular, the Act addresses actions that may result in the expenditure by a State, local, or tribal government, in the aggregate, or by the private sector of $100,000,000 (adjusted for inflation) or more in any one year. Though this proposed rule would not result in such expenditure, we do discuss the effects of this rule elsewhere in this preamble.
This proposed rule would not cause a taking of private property or otherwise have taking implications under Executive Order 12630, Governmental Actions and Interference with Constitutionally Protected Property Rights.
This proposed rule meets applicable standards in sections 3(a) and 3(b)(2) of Executive Order 12988, Civil Justice Reform, to minimize litigation, eliminate ambiguity, and reduce burden.
We have analyzed this proposed rule under Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks. This rule is not an economically significant rule and would not create an environmental risk to health or risk to safety that might disproportionately affect children.
This proposed rule does not have tribal implications under Executive Order 13175, Consultation and Coordination with Indian Tribal Governments, because it would not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes.
This proposed rule is not a “significant energy action” under Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use because it is not a “significant regulatory action” under Executive Order 12866 and is not likely to have a significant adverse effect on the supply, distribution, or use of energy. The Administrator of the Office of Information and Regulatory Affairs has not designated it as a significant energy action. Therefore, it does not require a Statement of Energy Effects under Executive Order 13211.
This proposed rule does not use technical standards. Therefore, we did not consider the use of voluntary consensus standards.
We have analyzed this proposed rule under Management Directive 023–01 and Commandant Instruction M16475.lD, which guide the Coast Guard in complying with the National Environmental Policy Act of 1969 (NEPA) (42 U.S.C. 4321–4370f), and have made a preliminary determination that this action is one of a category of actions that do not individually or cumulatively have a significant effect on the human environment. This proposed rule involves establishing a regulated navigation area as defined within this regulation, which is categorically excluded under figure 2–1, paragraph (34)(g)
Harbors, Marine safety, Navigation (water), Reporting and recordkeeping requirements, Security measures, Waterways.
For the reasons discussed in the preamble, the Coast Guard proposes to amend 33 CFR Part 165 as follows:
33 U.S.C. 1225, 1231, 46 U.S.C. Chapter 701, 3306, 3703, 50 U.S.C. 191, 195; 33 CFR 1.05–1, 6.04–1, 6.04–6 and 160.5; Pub. L. 107–295, 116 Stat. 2064; Delegation No. 0170.1.
(a)
(1) The Gulf Intracoastal Waterway (GIWW) from Mile Marker (MM) 22 East of Harvey Locks, west on the GIWW, including the Michoud Canal and the Inner Harbor Navigation Canal (IHNC), extending North
(2) The Harvey Canal, between the Lapalco Boulevard Bridge and the confluence of the Harvey Canal and the Algiers Canal;
(3) The Algiers Canal, from the Algiers Lock to the confluence of the Algiers Canal and the Harvey Canal;
(4) The GIWW from the confluence of Harvey Canal and Algiers Canal to MM 7.5 West of Harvey Locks
(b)
(1)
(2)
(3)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
(10)
(11)
(c)
(1) The provisions of paragraph (d) of this section will be enforced during a tropical event beginning 24 hours in advance of the predicted closure of the Lake Borne Surge Barrier structure within the HSDRRS (IHNC & GIWW) in the area defined in paragraph (a)(1).
(2) The provisions of paragraph (d) of this section will be enforced beginning 24 hours in advance of the predicted closure of the West Closure Complex within the HSDRRS (Harvey & Algiers Canals) in the area defined in paragraphs (a) (2)–(4) of this section.
(3) If the Coast Guard receives notice of a closure less than 24 hours before closure, the RNA will be enforced upon the COTP receiving the notice of predicted closing.
(4) In the event that a particularly dangerous storm is predicted, the COTP may require all floating vessels to evacuate the RNA beginning as early as 72 hours before predicted closure of any navigational structure or upon notice that particularly dangerous storm conditions are approaching, whichever is less.
(5) The COTP will notify the maritime community of the enforcement periods for this RNA through Marine Safety Information Bulletins and Safety Broadcast Notices to Mariners.
(d)
(1) Floating vessels may remain in the Harvey and Algiers Canals, provided they are moored sufficiently to prevent a breakaway and meet the minimum mooring requirements and conditions set forth in paragraphs (f) and (g) of this section.
(2) Floating vessels may remain in the Michoud Canal at least
(3) During the period that the RNA is not enforced and before closure of the navigational structures, vessels may transit through the RNA en route to a destination outside of the RNA given there is sufficient time to transit prior to the closure of a navigational structure, or they may transit to a facility within the RNA with which they have a prearranged agreement.
(4) The COTP may review on a case-by-case basis alternatives to minimum mooring requirements and conditions set forth in paragraphs (f) and (g) of this section and may approve a one-time deviation to these requirements and conditions should they provide an equivalent level of safety.
(e)
(1) Annual Hurricane Operations Plan: All facilities that have vessels intending to remain within the areas allowed in paragraph (d)(1) and (2) of this section shall develop an operations plan. The operations plan shall be readily available by May 1st of each calendar year for review by the COTP and the United States Army Corps of Engineers (USACE). The Annual Hurricane Operations Plan shall include:
(i) A description of the maximum number of vessels the facility intends to have remaining at any one time during hurricane season.
(ii) A detailed plan for any vessel(s) that are intended to be sunk/grounded in place when the RNA is enforced if evacuation is not possible.
(iii) A diagram of the waterfront facility and fleeting area.
(iv) Name, call sign, official number, and operational status of machinery on board (i.e., engines, generators, fire fighting pumps, bilge pumps, anchors, mooring machinery, etc.) each standby towboat.
(v) Characteristics for each vessel remaining at the fleeting or mooring facility, as applicable (length, breadth, draft, air draft, gross tonnage, hull type, horsepower, single or twin screw);
(vi) Details of mooring arrangements in accordance with mooring requirements and conditions set forth in paragraphs (g) and (h) of this section or COTP case-by-case approved deviations;
(vii) Certification by a professional engineer that the mooring arrangements are able to withstand winds of up to 140 mph, a surge water level of eleven feet, a current of four mph and a wave height of three feet within the canal basin in the area defined in paragraph (a)(1) of this section and a surge water level of eight feet, a current of four mph, and a wave height of two and a half feet within the canal basin in the area defined in paragraphs (a)(2)-(4) of this section;
(viii) Name, address and phone number of the owner/operator, and/or agent of the facility/property.
(ix) 24-hour contact information for qualified individuals empowered in writing by the owners/operators to make on-site decisions and authorize expenditures for any required pollution response or salvage.
(x) Full insurance disclosure to the COTP. Vessels moored to a facility shall provide insurance information to the facility.
(2) Storm Specific Verification Report: 72 hours prior to predicted closure of the navigational structures, those facilities which have vessels that intend to remain within the RNA shall submit a Storm Specific Verification Report to the COTP New Orleans. The requirements for this Storm Specific Verification Report are located in the Canal Hurricane Operations Plan, which is Enclosure Six to the Sector New Orleans Maritime Hurricane Contingency Port Plan,
(i) Updated contact information, including names of manned towboat(s) and individuals remaining on the towboat(s).
(ii) Number of vessels currently moored and mooring configurations if less than stated in Annual Hurricane Operations Plan.
(iii) If the number of vessels exceeds the amount listed in the Annual
(3) The person in charge of a facility shall inspect each mooring wire, chain, line and connecting gear between mooring devices and each wire, line and connecting equipment used to moor each vessel, and each mooring device. Inspections shall be performed according to the following timelines and guidance:
(i) Annually between May 1 and June 1 of each calendar year; and
(ii) After vessels are added to, withdrawn from, or moved at a facility, each mooring wire, line, and connecting equipment of each barge within each tier affected by that operation; and
(iii) At least weekly between June 1 and November 30; and
(iv) 72 hours prior to predicted closure of the navigation structures within this RNA; or within 6 hours of the predicted closure, if the notice of predicted closure is less than 72 hours.
(4) The person who inspects moorings shall take immediate action to correct any deficiency.
(5) Facility Records: The person in charge of a fleeting or mooring facility shall maintain, and make available to the COTP, records containing the following information:
(i) The time of commencement and termination of each inspection.
(ii) The name of each person who makes the inspection.
(iii) The identification of each vessel, barge entering or departing the fleeting or mooring facility, along with the following information:
(A) Date and time of entry and departure; and
(B) The names of any hazardous cargo which the vessel is carrying.
(6) The person in charge of a facility shall ensure continuous visual surveillance of all vessels at the facility.
(7) The person who observes the vessels shall:
(i) Inspect for movements that are unusual for properly secured vessels; and
(ii) Take immediate action to correct each deficiency.
(f)
(1) No person may secure a vessel to trees or to other vegetation.
(2) No person may allow a vessel to be moored with unraveled or frayed lines or other defective or worn mooring.
(3) No person may moor barges side to side unless they are secured to each other from fittings as close to each corner of abutting sides as practicable.
(4) No person may moor barges end to end unless they are secured to each other from fittings as close to each corner of abutting ends as practicable.
(5) A vessel may be moored to mooring devices if both ends of that vessel are secured to mooring devices.
(6) Barges may be moored in tiers if each shoreward barge is secured to mooring devices at each end.
(7) A vessel must be secured as near as practicable to each abutting corner by:
(i) Three parts of wire rope of at least 1
(ii) A mooring of natural or synthetic fiber rope that has at least the breaking strength of three parts of 1
(iii) Fixed rigging that is at least equivalent to three parts of 1
(8) The person in charge shall ensure that all mooring devices, wires, chains, lines and connecting gear are of sufficient strength and in sufficient number to withstand forces that may be exerted on them by moored vessels/barges.
(g)
(1) Each facility consisting of eight or more vessels that are not under their own power must be attended by at least one radar-equipped towboat for every 50 vessels.
(2) Each towboat required must be:
(i) Able to secure any breakaways;
(ii) Capable of safely withdrawing or moving any vessel at the fleeting or mooring facility;
(iii) Immediately operational;
(iv) Radio-equipped;
(v) No less than 800 horsepower;
(vi) Within 500 yards of the vessels.
(3) The person in charge of each towboat required must maintain a continuous guard on the frequency specified by current Federal Communications Commission regulations found in Part 83 of Title 47, Code of Federal Regulations; a continuous watch on the vessels moored at facility; and report any breakaway as soon as possible to the COTP via telephone, radio or other means of rapid communication.
(h) Prearranged agreement for safe haven. Transient vessels will not be permitted to seek safe haven in the RNA except in accordance with a prearranged agreement between the vessel and a facility within the RNA.
(i) Penalties. Failure to comply with this section may result in civil or criminal penalties pursuant to the Ports and Waterways Safety Act, 33 U.S.C. 1221 et seq.
Coast Guard, DHS.
Notice of proposed rulemaking.
The Coast Guard is proposing a temporary safety zone on the navigable waters of the Colorado River in Bullhead City, Arizona for the Bullhead City Regatta on August 10, 2013. This temporary safety zone is necessary to provide for the safety of the participants, crew, spectators, participating vessels, and other vessels and users of the waterway. Persons and vessels would be prohibited from entering into, transiting through or anchoring within this safety zone unless authorized by the Captain of the Port or his designated representative.
Comments and related material must be received by the Coast Guard on or before July 8, 2013. Rquests for public meetings must be received by the Coast Guard on or before June 21, 2013.
You may submit comments identified by docket number using any one of the following methods:
(1)
(2)
(3)
See the “Public Participation and Request for Comments” portion of the
If you have questions on this rule, call or email Lieutenant John Bannon, Waterways Management, U.S. Coast Guard Sector San Diego; telephone (619) 278–7261, email
We encourage you to participate in this rulemaking by submitting comments and related materials. All comments received will be posted without change to
If you submit a comment, please include the docket number for this rulemaking, indicate the specific section of this document to which each comment applies, and provide a reason for each suggestion or recommendation. You may submit your comments and material online at
To submit your comment online, go to
To view comments, as well as documents mentioned in this preamble as being available in the docket, go to
Anyone can search the electronic form of comments received into any of our dockets by the name of the individual submitting the comment (or signing the comment, if submitted on behalf of an association, business, labor union, etc.). You may review a Privacy Act notice regarding our public dockets in the January 17, 2008, issue of the
We do not now plan to hold a public meeting. But you may submit a request for one, using one of the methods specified under
The Ports and Waterways Safety Act (33 U.S.C sections 1221 et seq.) authorizes the Coast Guard to establish safety zones.
The City of Bullhead is sponsoring the Bullhead City Regatta, which is held on the navigable waters of the Colorado River in Bullhead City, AZ. The proposed temporary safety zone is necessary to provide for the safety of the participants, crew, spectators, sponsor vessels, and other vessels and users of the waterway. This event involves people floating down the river on inflatable rafts, inner tubes and floating platforms. The size of vessels used would vary in length from 3 feet to 100 feet. Approximately 30,000 people would be participating in this event. The sponsor would provide 38 patrol and rescue vessels to help facilitate the event and ensure public safety.
The Coast Guard is proposing a temporary safety zone that would be enforced from 6 a.m. to 6 p.m. on August 10, 2013. This safety zone is necessary to provide for the safety of the crews, spectators, participants, and other vessels and users of the waterway. Persons and vessels would be prohibited from entering into, transiting through, or anchoring within this safety zone unless authorized by the Captain of the Port, or his designated representative. The proposed temporary safety zone would include the waters of the Colorado River between Davis Camp and Rotary Park in Bullhead City, AZ. Before the effective period, the Coast Guard will publish a Local Notice to Mariners (LNM).
We developed this proposed rule after considering numerous statutes and executive orders related to rulemaking. Below we summarize our analyses based on a number of these statutes or executive orders.
This proposed rule is not a significant regulatory action under section 3(f) of Executive Order 12866, Regulatory Planning and Review, as supplemented by Executive Order 13563, Improving Regulation and Regulatory Review, and does not require an assessment of potential costs and benefits under section 6(a)(3) of Executive Order 12866 or under section 1 of Executive Order 13563. The Office of Management and Budget has not reviewed it under those Orders. This determination is based on the size and location of the safety zone. Although the safety zone would apply to the entire width of the river, traffic would be allowed to pass through the zone with the permission of the Captain of the Port. Additionally, before the effective period, the Coast Guard will publish a Local Notice to Mariners (LNM).
The Regulatory Flexibility Act of 1980 (RFA), 5 U.S.C. 601–612, as amended, requires federal agencies to consider the potential impact of regulations on small entities during rulemaking. The term “small entities” comprises small businesses, not-for-profit organizations that are independently owned and operated and are not dominant in their fields, and governmental jurisdictions with populations of less than 50,000. The Coast Guard certifies under 5 U.S.C. 605(b) that this proposed rule will not have a significant economic impact on a substantial number of small entities.
This safety zone will not have a significant economic impact on a substantial number of small entities for the following reasons. Although the safety zone would apply to the entire width of the river, traffic would be allowed to pass through the zone with the permission of the Coast Guard patrol commander. Before the effective period, the Coast Guard will publish a Local Notice to Mariners (LNM).
If you think that your business, organization, or governmental jurisdiction qualifies as a small entity and that this rule would have a significant economic impact on it, please submit a comment (see
Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Pub. L. 104–121), we want to assist small entities in understanding this proposed rule. If the rule would affect your small business, organization, or governmental jurisdiction and you have questions concerning its provisions or options for compliance, please contact the person listed in the
This proposed rule will not call for a new collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501–3520).
A rule has implications for federalism under Executive Order 13132, Federalism, if it has a substantial direct effect on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government. We have analyzed this proposed rule under that Order and determined that this rule does not have implications for federalism.
The Coast Guard respects the First Amendment rights of protesters. Protesters are asked to contact the person listed in the
The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531–1538) requires Federal agencies to assess the effects of their discretionary regulatory actions. In particular, the Act addresses actions that may result in the expenditure by a State, local, or tribal government, in the aggregate, or by the private sector of $100,000,000 (adjusted for inflation) or more in any one year. Though this proposed rule would not result in such an expenditure, we do discuss the effects of this rule elsewhere in this preamble.
This proposed rule would not cause a taking of private property or otherwise have taking implications under Executive Order 12630, Governmental Actions and Interference with Constitutionally Protected Property Rights.
This proposed rule meets applicable standards in sections 3(a) and 3(b)(2) of Executive Order 12988, Civil Justice Reform, to minimize litigation, eliminate ambiguity, and reduce burden.
We have analyzed this proposed rule under Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks. This rule is not an economically significant rule and would not create an environmental risk to health or risk to safety that might disproportionately affect children.
This proposed rule does not have tribal implications under Executive Order 13175, Consultation and Coordination with Indian Tribal Governments, because it would not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes.
This proposed rule is not a “significant energy action” under Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use.
This proposed rule does not use technical standards. Therefore, we did not consider the use of voluntary consensus standards.
We have analyzed this proposed rule under Department of Homeland Security Management Directive 023–01 and Commandant Instruction M16475.lD, which guide the Coast Guard in complying with the National Environmental Policy Act of 1969 (NEPA) (42 U.S.C. 4321–4370f), and have made a preliminary determination that this action is one of a category of actions that do not individually or cumulatively have a significant effect on the human environment. This proposed rule involves establishing a temporary safety zone. This proposed rule is categorically excluded from further review under paragraph 34(g) of Figure 2–1 of the Commandant Instruction. A preliminary environmental analysis checklist supporting this determination and a Categorical Exclusion Determination are available in the docket where indicated under
Harbors, Marine safety, Navigation (water), Reporting and recordkeeping requirements, Security Measures, Waterways.
For the reasons discussed in the preamble, the Coast Guard proposes to amend 33 CFR part 165 as follows:
33 U.S.C. 1226, 1231; 46 U.S.C. Chapter 701, 3306, 3703; 50 U.S.C. 191, 195; 33 CFR 1.05–1, 6.04–1, 6.04–6, and 160.5; Pub. L. 107–295, 116 Stat. 2064; Department of Homeland Security Delegation No. 0170.1.
(a)
(b)
(c)
(d)
(2) Mariners can request permission to transit through the safety zone from the Patrol Commander. The Patrol Commander can be contacted on VHF–FM channels 16 and 23.
(3) All persons and vessels shall comply with the instructions of the Coast Guard Captain of the Port or his designated representative.
(4) Upon being hailed by U.S. Coast Guard patrol personnel by siren, radio, flashing light, or other means, the operator of a vessel shall proceed as directed.
(5) The Coast Guard may be assisted by other federal, state, or local agencies.
Environmental Protection Agency (EPA).
Proposed rule.
EPA is proposing to approve changes to the North Carolina State Implementation Plan (SIP) submitted by the State of North Carolina Department of Environment and Natural Resources (NC DENR), Division of Air Quality on September 18, 2009, for the purpose of removing Stage II vapor control requirements for new and upgraded gasoline dispensing facilities in the State. The September 18, 2009, SIP revision also addresses several non-Stage II related rule changes. However, action on the other portions for the September 18, 2009, SIP revision is being addressed in a separate rulemaking action. EPA has preliminarily determined that North Carolina's September 18, 2009, SIP revision regarding the Stage II vapor control requirements is approvable because it is consistent with the Clean Air Act (CAA or Act).
Written comments must be received on or before July 8, 2013.
Submit your comments, identified by Docket ID No. EPA–R04–OAR–2009–0140, by one of the following methods:
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Kelly Sheckler, Air Quality Modeling and Transportation Section, Air Planning Branch, Air, Pesticides and Toxics Management Division, U.S. Environmental Protection Agency, Region 4, 61 Forsyth Street SW., Atlanta, Georgia 30303–8960. The telephone number is (404) 562–9222. Ms. Sheckler can be reached via electronic mail at
EPA, under the CAA Amendments of 1990, designated (pursuant to section 107(d)(1)) and classified certain counties in North Carolina, either in their entirety or portions thereof, as “moderate” ozone nonattainment areas for the 1-hour ozone national ambient air quality standards (NAAQS). Specifically, the Charlotte-Gastonia Area (comprised of Gaston and Mecklenburg Counties); Greensboro-Winston-Salem-High Point Area (comprised of Davidson, Davis (partial), Forsyth and Guilford Counties); and Raleigh-Durham Area (comprised of Durham, Granville (partial), and Wake Counties) were all designated as “moderate” ozone nonattainment areas for the 1-hour ozone NAAQS. The designations were based on the Areas' 1-hour ozone design values for the 1987–1989 three-year period. The “moderate” classification triggered various statutory requirements for these Areas including included the Stage II vapor recovery requirements pursuant to section 182(b)(3) of the CAA.
Prior to the deadline for implementing the requirement of section 182(b)(3) of the CAA, the Charlotte-Gastonia, Greensboro-Winston-Salem-High Point and the Raleigh-Durham Areas in North Carolina attained the 1-hour ozone NAAQS. North Carolina had implemented all measures required at the time for moderate ozone nonattainment areas under the CAA, and with three years of data (1990–1992), demonstrated compliance with the 1-hour ozone NAAQS.
Subsequently, NC DENR submitted to EPA a 1-hour ozone maintenance plan and request for redesignation for the three moderate nonattainment areas. As part of the associated maintenance plans, North Carolina provided contingency measures that included regulation 15A North Carolina Administrative Code (NCAC) 02D.0953 (hereafter referred to as rule .0953), entitled
EPA's primary consideration for determining the approvability of North Carolina's request to remove Stage II vapor control requirements from the contingency measures in its SIP for the Charlotte-Gastonia, Greensboro-Winston-Salem-High Point, and Raleigh-Durham Areas is whether these requested actions comply with section 110(l) of the CAA. Below is EPA's analysis of these considerations.
States were required to adopt Stage II rules for all areas classified as “moderate” or worse under section 182(b)(3) of the CAA. However, section 202(a)(6) of the CAA states that “the requirements of section 182(b)(3) (relating to Stage II gasoline vapor recovery) for areas classified under section 181 as moderate for ozone shall not apply after the promulgation of such [ORVR] standards.” ORVR regulations were promulgated by EPA on April 6, 1994.
Section 110(l) of the Act provides that EPA cannot approve a SIP revision if that revision interferes with any applicable requirement regarding attainment, reasonable further progress (RFP) or any requirement established in the CAA. EPA can, however, approve a SIP revision that removes or modifies control measures in the SIP once states make a “noninterference” demonstration that such a removal or modification will not interfere with attainment of the NAAQS, RFP or any other CAA requirement. As such, North Carolina must make a demonstration of noninterference in order to remove the Stage II requirements from its SIP in relation to the Charlotte-Gastonia, Greensboro-Winston-Salem-High Point, and Raleigh-Durham Areas.
All areas in the State are currently designated as attainment for the carbon monoxide and fine particulate matter NAAQS. Effective July 20, 2013, EPA designated the Greensboro-Winston-Salem-High Point and Raleigh-Durham Areas as attainment for the 2008 8-hour ozone NAAQS. The Charlotte-Gastonia Area was designated as nonattainment for the 2008 8-hour ozone NAAQS in association with other counties in the Region, including a portion of a county in South Carolina. The designations for the 2008 8-hour ozone NAAQS were effective July 20, 2012.
On September 18, 2009, NC DENR submitted a SIP revision requesting removal of the Stage II vapor recovery requirements for new and upgraded gasoline dispensing facilities from the North Carolina SIP. North Carolina's September 18, 2009, SIP revision includes changes to rules .0953—
Additionally, the removal of rules .0953 and .0954 triggered subsequent amendments
EPA's consideration to approve North Carolina's removal of the Stage II requirements is contingent on the applicability of a section 110(l) noninterference demonstration. North Carolina never realized emission reductions in the Charlotte-Gastonia, Greensboro-Winston-Salem-High Point, and Raleigh-Durham Areas as a result of the Stage II requirements that the State included as a contingency measure in the SIP. Thus removing this requirement from the contingency measures will not impact emissions of volatile organic compounds (VOC) and nitrogen oxides in the aforementioned Areas.
Additionally, since the time of EPA's approval of these requirements in North Carolina's SIP as contingency measures for the Charlotte-Gastonia, Greensboro-Winston-Salem-High Point, and Raleigh-Durham Areas, EPA has made a determination that ORVR is in “widespread use” nationwide. Specifically, on May 16, 2012, EPA made a determination that ORVR was in widespread use throughout the motor vehicle fleet for purposes of controlling motor vehicle refueling emissions. In that rulemaking, EPA estimated that approximately 70 percent of all vehicles would be equipped with on-board systems to capture these vapors by the end of 2012, thus rendering the use of Stage II vapor recovery systems redundant because, beyond that date, the refueling emissions of the motor vehicle fleet are controlled through widespread use of ORVR.
EPA is proposing to approve North Carolina's September 18, 2009, SIP revision to remove Stage II rules .0953 and .0954 from the North Carolina SIP, and to amend rules .0902(d), .0909, and .0952, to reflect the removal of rules .0953 and .0954 in the State's implementation plan because the Agency has preliminarily determined that this revision is consistent with section 110(l) of the CAA and will not interfere with the relevant requirements in the Charlotte-Gastonia, Greensboro-Winston-Salem-High Point, and Raleigh-Durham Areas.
EPA also considered this SIP revision in relation to section 110(a)(2)(D)(i)(I) of the CAA. CAA section 110(a)(2)(D)(i)(I) prohibits facilities within the State from emitting any air pollutants in amounts which will contribute significantly to nonattainment in, or interfere with maintenance by, any other State with respect to any such national primary or secondary ambient air quality standards. The only CAA-regulated pollutant emitted by refueling vehicles is VOC, which is a precursor of ozone, and its emissions are mitigated by the use of vehicles equipped with ORVR. As previously mentioned, EPA has previously determined that ORVR is now in widespread use and accordingly EPA views removal of the Stage II requirements from North Carolina's SIP as not contributing significantly to nonattainment in, or interfering with maintenance by, any other State with respect to a national primary or secondary ambient air quality standard.
EPA is proposing to approve the SIP revision submitted by North Carolina for the purpose of removing Stage II vapor control requirements for new and upgraded gasoline dispensing facilities in the Charlotte-Gastonia, Greensboro-Winston-Salem-High Point, and Raleigh-Durham Areas. Specifically, this action proposes to remove Stage II rules .0953 and .0954 from the North Carolina SIP, and to amend at rules .0902(d), .0909, and .0952 to reflect the removal of rules .0953 and .0954 in the State's implementation plan. EPA has preliminarily determined that North Carolina's September 18, 2009, SIP revision related to the State's Stage II rules is consistent with the CAA and EPA's regulations and guidance.
Under the CAA, the Administrator is required to approve a SIP submission that complies with the provisions of the Act and applicable federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in reviewing SIP submissions, EPA's role is to approve state choices, provided that they meet the criteria of the CAA. Accordingly, this 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, Nitrogen dioxide, Ozone, Reporting and recordkeeping requirements, Volatile organic compounds.
42 U.S.C. 7401
Environmental Protection Agency (EPA).
Proposed rule.
On May 1, 2013, the State of North Carolina, through the North Carolina Department of Environment and Natural Resources (NC DENR), submitted to EPA a state implementation plan (SIP) revision to satisfy North Carolina's commitment associated with the conditional approval of its reasonably available control technology (RACT) requirements for volatile organic compound (VOC) sources located in the North Carolina portion of the Charlotte—Gastonia—Rock Hill, North Carolina—South Carolina 1997 8-hour ozone nonattainment area (hereafter referred to as the “bi-state Charlotte Area”). NC DENR's May 1, 2013, SIP revision also includes additional changes to North Carolina's RACT rules. EPA is proposing to approve these SIP revisions to the State's RACT rules and to convert the existing conditional approval of VOC RACT provisions in the North Carolina SIP to a full approval under the Clean Air Act (CAA or Act). EPA has evaluated the proposed changes to North Carolina's SIP, and has made the preliminary determination that they are consistent with statutory and regulatory requirements and EPA guidance.
Comments must be received on or before July 8, 2013.
Submit your comments, identified by Docket ID No. EPA–R04–OAR–2009–0140 by one of the following methods:
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Jane Spann, Regulatory Development Section, Air Planning Branch, Air, Pesticides and Toxics Management Division, U.S. Environmental Protection Agency, Region 4, 61 Forsyth Street SW., Atlanta, Georgia 30303–8960. Ms. Spann may be reached by phone at (404) 562–9029, or via electronic mail at
On April 30, 2004, EPA designated the bi-state Charlotte Area as a moderate nonattainment area with respect to the 1997 8-hour ozone national ambient air quality standards (NAAQS).
As a result of this designation, North Carolina and South Carolina were required to amend their SIPs for their respective portions of the bi-state Charlotte Area to satisfy the requirements of section 182 of the CAA. Today's action specifically addresses the North Carolina portion of the bi-state Charlotte Area. EPA approved the RACT requirements for the South Carolina portion of the bi-state Charlotte Area on November 28, 2011, at 76 FR 72844.
Section 182(b)(2) of the CAA requires states to adopt RACT rules for all areas designated nonattainment for ozone and classified as moderate or above. The three parts of the section 182(b)(2) RACT requirements are: (1) RACT for sources covered by an existing CTG (i.e., a CTG
On May 9, 2013, EPA took final action to approve, in part, and conditionally approve in part, North Carolina SIP revisions submitted on October 14, 2004, April 6, 2007, June 15, 2007, January 31, 2008, November 19, 2008, September 18, 2009, February 3, 2010, April 6, 2010, and November 9, 2010, to address NO
NC DENR submitted a SIP revision on May 1, 2013, to address deficiencies with the State's VOC RACT rules as identified in EPA's May 9, 2013, conditional approval of North Carolina's VOC RACT rules.
As described above, North Carolina revised its VOC regulations to address the deficiencies identified in EPA's May 9, 2013, conditional approval action. EPA's conditional approval was based on North Carolina finalizing their November 28, 2012, draft submittal, to correct deficiencies with the State's VOC RACT regulations. As previously mentioned, section 182(b)(2) of the CAA requires RACT for all sources addressed by a CTG issued by EPA in areas classified as moderate nonattainment for ozone. North Carolina's previous RACT applicability rule, 15A NCAC 02D.0902 (hereafter “.0902”), however, applied only to facilities located in the Charlotte-Gastonia-Rock Hill, NC 8-hour ozone nonattainment area that have the potential to emit (PTE) greater than or equal to 100 tons of VOC per year. North Carolina's May 1, 2013, SIP revision corrects this deficiency by extending applicability to all VOC sources in the nonattainment area for all CTG source categories. In addition, North Carolina's May 1, 2013, SIP revision also addresses the conditional approval of rules 15A NCAC 02D.0909 (hereafter “.0909”), 15A NCAC 02D.0951 (hereafter “.0951”), 15A NCAC 02D.0961 (hereafter “.0961”), and 15A NCAC 02D.0962 (hereafter “.0962”). In today's action, EPA is proposing to approve North Carolina's changes to rules .0902, .0909, .0951, .0961, and .0962 as satisfying the deficiencies in the State's VOC RACT rules, and thus the Agency is also proposing to convert the May 9, 2013, conditional approval to a full approval for North Carolina VOC RACT rules.
North Carolina's May 1, 2013, SIP revision also proposes updates to rules .0903 and .0102. In today's action, EPA is proposing to approve the changes to rule .0903. EPA will take action on rule .0102 in a separate action. Below is a summary of the changes to each rule being proposed for approval in today's action.
North Carolina originally adopted rule .0902 in 1979, amended it a number of times and submitted this rule to EPA for approval. The following table shows the dates that rule .0902 was submitted to EPA and approved into the federally-approved SIP for North Carolina.
On November 9, 2010, North Carolina revised rule .0902 again. On May 9, 2013, EPA conditionally approved the November 9, 2010, version of rule .0902.
North Carolina originally adopted rule .0903 in 1979, amended it a number of times and submitted this rule to EPA for approval on November 8, 1984. EPA approved rule .0903 into the federally-approved North Carolina SIP on December 19, 1986, (51 FR 45468). The rule was amended again and submitted to EPA for SIP approval on April 16, 2001. EPA approved these amendments into the federally-approved North Carolina SIP on August 8, 2002 (67 FR 51461).
Changes to rule .0903 were submitted to EPA on May 1, 2013. EPA is proposing to approve the changes to rule .0903 as submitted on May 1, 2013.
Rule .0909 was changed a number of times and submitted to EPA for approval. It was revised to add compliance schedules for the facilities to comply with RACT requirements, became State effective on March 1, 2007, and was submitted to EPA for approval on April 6, 2007. Rule .0909 was amended to add compliance schedules for the facilities to comply with RACT requirements should the bi-state Charlotte Area fail to attain the 1997 8-hour ozone NAAQS and as a result be reclassified as serious area for that NAAQS. This rule was State effective on July 1, 2007, and was submitted to EPA for approval on January 31, 2008.
Subsequently, rule .0909 was amended to remove the reference to Stage II vapor recovery at Rules 15A NCAC 02D.0953, “Vapor Return Piping for Stage II Vapor Recovery,” and 15A NCAC 02D.0954, “Stage II Vapor Recovery,” as these provisions were repealed by the State. This amendment became State effective on January 1, 2009, and submitted to EPA for approval on September 18, 2009. Additionally, rule .0909 was amended to change cross-references, became State effective on September 1, 2010, and submitted to EPA for approval on November 9, 2010. On May 9, 2013, EPA conditionally approved the November 9, 2010, version of rule .0909, which comprehensively addressed the above mentioned revisions to this rule.
North Carolina originally adopted rule .0951 in 1994 and submitted this rule for EPA approval on August 16, 1995. EPA approved the August 16, 1995, submittal on August 1, 1997, at 62 FR 41277. Subsequently, North Carolina submitted rule .0951 amendments to EPA for approval into the federally-approved SIP on July 28, 2000. EPA approved these amendments on June 27, 2001, at 66 FR 34117. North Carolina again changed rule .0951 with a State effective date of September 1, 2010. The September 1, 2010, version of this rule was submitted to EPA on November 9, 2010, for SIP approval. Specifically, the rule was amended to change cross references to other Chapter 15A NCAC 02D.0900 rules.
On May 9, 2013, EPA conditionally approved the November 9, 2010, version of rule .0951.
In December 1978, EPA published a CTG for graphic arts (rotogravure printing and flexographic printing) that included flexible packaging printing. On October 5, 2006 (71 FR 58745), EPA updated the 1978 CTG, as part of Group II CTG, addressing the control of VOC emissions from graphic arts systems consisting of packaging rotogravure, publication rotogravure or flexographic printing operations.
North Carolina originally adopted Rule 15A NCAC 02D.0936 (hereafter “.0936”), “Graphic Arts” in 1980, amended it, and then submitted it to EPA for approval on April 17, 1990. It was approved into the federally-approved North Carolina SIP on June 23, 1994 (59 FR 32362). In a November 9, 2010, SIP revision North Carolina repealed rule .0936, “Graphic Arts” and replaced it in part with rule .0961, “Offset Lithographic Printing and Letterpress Printing.” See 78 FR 15895, March 13, 2013, for more information regarding rule .0936, “Graphic Arts.”
On May 9, 2013, EPA conditionally approved the November 9, 2010, version of rule .0961.
On October 5, 2006 (71 FR 58745), as part of the Group II CTG, EPA updated the portion of the 1977 Solvent Metal Cleaning CTG regarding the control of VOC emissions from the use of industrial cleaning solvents. North Carolina originally adopted rule .0962, on September 1, 2010, and submitted this rule to EPA for approval into the federally-approved North Carolina SIP on November 9, 2010. Rule .0962 was amended again, and submitted for EPA approval on May 1, 2013.
On May 9, 2013, EPA conditionally approved the November 9, 2010, version of rule .0962.
Pursuant to section 110 of the CAA, EPA is proposing to approve the changes to North Carolina's SIP to address deficiencies with the State's VOC RACT rules at .0902, .0909, .0951, .0961, and .0962 for the North Carolina portion of the bi-state Charlotte Area as provided in a May 1, 2013, SIP revision. EPA has evaluated North Carolina's May 1, 2013, SIP revision, and has preliminarily determined that the changes to rules .0902, .0909, .0951, .0961, and .0962 meet the applicable requirements of the CAA and EPA regulations addressing VOC RACT requirements. As a result, EPA is also proposing to convert a May 9, 2013, conditional approval of rules .0902, .0909, .0951, .0961, and .0962, at 78 FR 27065, to a full approval.
Additionally, in today's action, EPA is proposing to approve changes to North Carolina's rule .0903, “Recordkeeping: Reporting, Monitoring,” and to approve the name change for rule .0951 from “Miscellaneous Volatile Organic Compound Emissions” to “RACT for Sources of Volatile Organic Compounds,” as provided in SIP revision on May 1, 2013. EPA has made the preliminary determination that North Carolina's changes are consistent with the CAA and EPA's regulations.
Under the CAA, the Administrator is required to approve a SIP submission that complies with the provisions of the Act and applicable federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in reviewing SIP submissions, EPA's role is to approve state choices, provided that they meet the criteria of the CAA. Accordingly, this action merely proposes to approve state law as meeting federal requirements and does not impose additional requirements beyond those imposed by state law. For that reason, this proposal 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).
Environmental protection, Air pollution control, Incorporation by reference, Intergovernmental relations, Nitrogen dioxide, Ozone, Reporting and recordkeeping requirements, Volatile organic compounds.
Federal Communications Commission.
Petition for reconsideration.
In this document, a Petition for Reconsideration and Clarification (Petition) has been filed in the Commission's Rulemaking proceeding by Bruce A. Olcott on behalf of The Boeing Company.
Oppositions to the Petition must be filed on or before June 24, 2013. Replies to an opposition must be filed on or before July 2, 2013.
Federal Communications Commission, 445 12th Street SW., Washington, DC 20554.
Howard Griboff or Jennifer Balatan, Policy Division, International Bureau, (202) 418–1460.
This is a summary of the Commission's document, Report No. 2980, released May 30, 2013. The full text of Report No. 2980 is available for viewing and copying in Room CY–B402, 445 12th Street SW., Washington, DC or may be purchased from the Commission's copy contractor, Best Copy and Printing, Inc. (BCPI) (1–800–378–3160). The Commission will not send a copy of this document pursuant to the Congressional Review Act, 5 U.S.C. 801(a)(1)(A), because this document does not have an impact on any rules of particular applicability.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Extension of public comment period.
We, NMFS, are extending the public comment period soliciting information to inform our status review of Pacific harbor seals (
The deadline for receipt of comments is extended from July 16, 2013, to August 16, 2013.
You may submit comments about the harbor seals in Iliamna Lake, identified by FDMS Docket Number NOAA–NMFS–2012–0236, by any of the following methods:
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Interested persons may obtain a copy of the petition online at the NMFS Alaska Region Web site:
Mandy Migura, NMFS Alaska Region, (907) 271–1332; Jon Kurland, NMFS Alaska Region, (907) 586–7638; or Lisa Manning, NMFS Office of Protected Resources, (301) 427–8466.
On May 17, 2013, we published a notice (78 FR 29098) announcing a positive 90-day finding on a petition to list harbor seals in Iliamna Lake, Alaska under the ESA and initiated a status review. In that notice we also solicited comments and information from the public about the harbor seals in Iliamna Lake to be considered during the status review.
We have received a request from the Bristol Bay Native Association/Bristol Bay Marine Mammal Council to extend the public comment period by a minimum of 30 days. This extension would allow the communities of Bristol Bay and Iliamna Lake more time to comment because the current schedule overlaps with their summer subsistence and commercial fishing seasons. We considered this request and concluded that a 30-day extension should allow sufficient time for responders to submit comments without significantly delaying the completion of the status review. We are therefore extending the close of the public comment period from July 16, 2013, to August 16, 2013. Although we have extended the public comment period, we are unable to extend the deadline for completing the status review. As such, we urge members of the public to submit their comments as soon as possible to allow us more time to review and incorporate the submitted information where appropriate.
The authority for this action is the Endangered Species act of 1973, as amended (16 U.S.C. 1531
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Proposed rule; request for comments.
NMFS proposes regulations to implement Regulatory Amendment 2 to the Fishery Management Plan (FMP) for the Queen Conch Resources of Puerto Rico and the U.S. Virgin Islands (USVI) (Regulatory Amendment 2), as prepared by the Caribbean Fishery Management Council (Council). If implemented, this rule would revise the commercial trip limit for queen conch in the Caribbean exclusive economic zone (EEZ) to be compatible with the trip limit in USVI territorial waters. The purpose of this proposed rule is to improve the compatibility of Federal and USVI territorial regulations for queen conch in order to facilitate enforcement efforts while ensuring the long-term health of the queen conch resource.
Written comments must be received on or before July 8, 2013.
You may submit comments on this document, identified by “NOAA–NMFS–2013–0068,” by any of the following methods:
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Electronic copies of Regulatory Amendment 2, which includes an environmental assessment, an initial regulatory flexibility analysis (IRFA) and a regulatory impact review, may be obtained from the Southeast Regional Office Web site at:
Maria del Mar Lopez, Southeast Regional Office, NMFS, telephone: 727–824–5305, email:
The Caribbean queen conch fishery is managed under the FMP. The FMP was prepared by the Council, and is implemented through regulations at 50 CFR part 622 under the authority of the
The queen conch is currently classified as an overfished species, and it is managed under a 15-year rebuilding plan. Harvest and possession of queen conch in the U.S. Caribbean EEZ is limited to the area east of 64°34′ W. longitude which includes Lang Bank to the east of St. Croix, USVI, and only from November 1 through May 31 each year. The USVI has expressed interest in having Federal regulations modified to make them compatible with the territorial regulations to facilitate enforcement efforts, enhance compliance by fishers, and allow for more efficient management of the queen conch resource in the U.S. Caribbean.
Regulatory Amendment 1 to the FMP, implemented in 2011 (76 FR 23907, April 29, 2011), established a compatible seasonal closure with the USVI (from June 1 through October 31, each year), and a compatible queen conch harvest quota closure for Federal waters. The quota or annual catch limit (ACL) consists of an annual harvest of 50,000 lb (22,680 kg) for combined Federal and St. Croix waters. When that ACL is reached and the USVI closes territorial waters off St. Croix to the harvest and possession of queen conch, NMFS will concurrently close the Caribbean EEZ in the area east of 64°34′ W. longitude. The EEZ closure will remain in effect until the next fishing season for territorial and Federal waters opens on November 1.
Current commercial trip limits and recreational bag limits for the harvest of queen conch in Federal waters are not compatible with USVI regulations. The current trip limit in Federal waters allows a licensed commercial fisherman to harvest up to 150 queen conch per day, but does not establish a harvest limit per vessel. USVI regulations allow the harvest of 200 queen conch per vessel per day regardless of the number of licensed fishermen on board. The daily recreational bag limit in Federal waters allows 3 queen conch per person and a maximum of 12 queen conch per vessel. In contrast, the USVI daily recreational bag limit consists of 6 queen conch per person and a maximum of 24 per vessel.
At its March 2013 meeting, the Council voted to establish a daily commercial trip limit of 200 queen conch per vessel and to leave the recreational bag limit unchanged. As the Federal recreational bag limit is less than the territorial limit, increasing the recreational bag limit would only slightly facilitate law enforcement efforts, but may negatively impact the continued health of the queen conch resource.
If implemented, this rule would revise the commercial trip limit to 200 queen conch per vessel per day instead of the current 150 queen conch per licensed commercial fisher per day.
This rule would also change the language in the codified text specifying the queen conch fishing season. This revision is intended to correct a mistake that occurred in prior rule-making (Regulatory Amendment 1), in which the sentence was restructured and a distinction was inadvertently removed. This rule would revise the codified text to its previous form. Fishing for queen conch is only allowed from November 1 through May 31, and only in the area east of 64°34′ W. longitude which includes Lang Bank east of St. Croix, USVI. In the rest of the Caribbean EEZ, there is a prohibition on the harvest and possession of queen conch. Changing the text to its previous form reflects the original and current intent of the Council.
Pursuant to section 304(b)(1)(A) of the Magnuson-Stevens Act, the NMFS Assistant Administrator has determined that this proposed rule is consistent with the regulatory amendment, the FMP, the Magnuson-Stevens Act and other applicable law, subject to further consideration after public comment.
This proposed rule has been determined to be not significant for purposes of Executive Order 12866.
NMFS prepared an IRFA, as required by section 603 of the Regulatory Flexibility Act, for this proposed rule. The IRFA describes the economic impact this rule, if adopted, would have on small entities. A description of the action, why it is being considered, and the objectives of, and legal basis for this action are contained in the preamble. A copy of the full analysis is available from NMFS (see
The purpose of this proposed rule is to revise the commercial trip limit for queen conch in the Caribbean EEZ. This rule would also implement an administrative change to the regulations regarding the queen conch season. The Magnuson-Stevens Act provides the statutory basis for this proposed rule. No duplicative, overlapping, or conflicting Federal rules have been identified. This proposed rule would not establish any changes to current reporting, record-keeping, or other compliance requirements.
This rule, if adopted, would be expected to directly affect commercial fishermen in St. Croix, U.S. Virgin Islands, who harvest queen conch. Queen conch harvest in the EEZ in the U.S. Caribbean is restricted to the Lang Bank area off St. Croix and all queen conch harvest from this area is believed to be landed in St. Croix because of the prohibitive travel distances that would be required to land in other locations. As a result, the assessment of the number of commercial entities expected to be affected by this rule is based on St. Croix commercial trip ticket data.
The USVI fishing year for all species is July 1 through June 30. Over the 2009/2010 through 2011/2012 fishing years, an average of 40 fishermen (range of 30–48) per fishing year recorded landings of queen conch in St. Croix. The average total revenue per fishing year from the harvest of all marine species (queen conch and all other species) by these fishermen was approximately $2.6 million (nominal or un-inflated dollars), or approximately $64,000 per fisherman ($2.6 million/40). These estimates include all fishermen with recorded queen conch landings in St. Croix, regardless of where the queen conch were harvested (EEZ or territorial waters). Precise comparable estimates for fishermen who harvested queen conch in the EEZ are not available because the area of harvest was not provided on all trip tickets (area fished was not reported on trip tickets that accounted for approximately 11 percent of the average queen conch harvest per fishing year). However, an average of 17 fishermen (range of 9–23) per fishing year reported queen conch harvests from the EEZ. The average total revenue from the harvest of all marine species by these fishermen during this period was approximately $1.0 million (nominal or un-inflated dollars), or approximately $60,000 per fishermen ($1.0 million/17).
The Small Business Administration (SBA) has established size criteria for all major industry sectors in the U.S. including fish harvesters. A business involved in fish harvesting is classified as a small business if it is independently owned and operated, is not dominant in its field of operation (including its affiliates), and has combined annual receipts not in excess of $4.0 million (NAICS code 114111, finfish fishing) for all its affiliated operations worldwide. Both average revenue estimates, approximately $64,000 for all fishermen with commercial queen conch landings
This rule, if adopted, would increase the number of queen conch that could be harvested per vessel per trip if one licensed commercial fisherman is on board the vessel and decrease the allowable harvest if multiple licensed commercial fishermen are on board. However, 2 percent or fewer of the trips that harvest queen conch are believed to carry multiple licensed commercial fishermen and no licensed commercial fishermen are known to exclusively fish with other licensed commercial fishermen on board. As a result, the effects of increasing the allowable queen conch harvest per vessel per trip on trips with a single licensed commercial fisherman on board would be expected to account for the majority of the impacts.
The net direct economic effects of this proposed rule cannot be quantified with available data. Increasing the number of queen conch that could be harvested per vessel per trip would be expected to increase the average daily harvest and associated revenue per trip for trips on which queen conch are harvested. Total operating costs could be reduced if fishermen take fewer trips to harvest the queen conch ACL. An increase in the revenue per trip and a decrease in operating costs would result in an increase in profit to affected small entities.
The queen conch commercial ACL in St. Croix is 50,000 lb (22,680 kg) and queen conch harvest and possession in the EEZ is prohibited when the St. Croix ACL is reached. As a result, the total average annual revenue to all commercial fishermen from queen conch harvest would not be expected to be affected by this proposed rule other than as a result of a possible reduction in average price if increased harvest rates result in a derby fishery and depress prices. However, of the estimated average 40 fishermen who harvest queen conch per year, only an estimated average of 17 fishermen per year harvest queen conch in the EEZ. Additionally, closure of the fishery due to the ACL being reached has only occurred once since the 2008/2009 fishing year and because approximately two-thirds of the total queen conch harvest in St. Croix comes from territorial waters, any increased harvest rate accruing in response to the proposed increase in the trip limit in the EEZ may not significantly reduce the length of the open season and, thus, have minimal to no effect on queen conch prices. Therefore, increasing the daily average harvest rate, which may occur as a result of the proposed increase in the trip limit, may have only a small effect on increasing the likelihood of the fishery closing due to the ACL being reached and/or reducing the average price for queen conch.
In addition to the effects described in the previous paragraph, fishing for, and revenue from, other species may increase as a result of this proposed rule, if adopted, if fishermen are able to take fewer trips to harvest the queen conch ACL and increase fishing effort for other species. However, any increase in revenue from other species would be an indirect effect of the proposed action and, therefore, outside the scope of the IRFA.
This rule, if adopted, would also change the language in the codified text specifying the queen conch fishing season. This change would correct an inadvertent change to the text that occurred in a prior rulemaking, as discussed in the preamble. The proposed revision better reflects the original and current intent of the Council. Queen conch fishing in the Caribbean EEZ has been consistent with the season specified by the proposed change and, therefore, this proposed change would not be expected to result in any economic effects on any small entities.
In summary, the average fisherman expected to be directly affected by this proposed rule would be expected to experience an increase in revenue and profit. However, neither the amount nor the significance of these increases can be determined with available data.
Although the significance of the expected change in profit to the small entities expected to be directly affected by this proposed rule cannot be determined, the proposed rule would be expected to increase the revenue and profit of the average small entity that would be expected to be affected. Because the expected effect of this proposed rule would be positive and not adverse, the issue of significant alternatives to minimize the adverse effects is not relevant.
Fisheries, Fishing, Queen Conch, St. Croix, Virgin Islands.
For the reasons set out in the preamble, 50 CFR part 622 is proposed to be amended as follows:
16 U.S.C. 1801
(a) No person may fish for or possess on board a fishing vessel a Caribbean queen conch in or from the Caribbean EEZ, except from November 1 through May 31 in the area east of 64°34′ W. longitude which includes Lang Bank east of St. Croix, U.S. Virgin Islands.
(a)
(b)
The Department of Agriculture has submitted the following information collection requirement(s) to OMB for review and clearance under the Paperwork Reduction Act of 1995, Public Law 104–13. Comments regarding (a) Whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility; (b) the accuracy of the agency's estimate of burden including the validity of the methodology and assumptions used; (c) ways to enhance the quality, utility and clarity of the information to be collected; (d) ways to minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology.
Comments regarding this information collection received by July 8, 2013 will be considered. Written comments should be addressed to: Desk Officer for Agriculture, Office of Information and Regulatory Affairs, Office of Management and Budget (OMB), New Executive Office Building, 725—17th Street NW., Washington, DC 20502. Commenters are encouraged to submit their comments to OMB via email to:
An agency may not conduct or sponsor a collection of information unless the collection of information displays a currently valid OMB control number and the agency informs potential persons who are to respond to the collection of information that such persons are not required to respond to the collection of information unless it displays a currently valid OMB control number.
The information gathered from this survey will be used to develop estimates of recreation services provided by hunting in North Dakota and South Dakota. Without data on hunter use and expenditures, the economic contribution generated by the federal investment in CRP cannot be reliability estimated.
Funding availability for this program may be announced at approximately the same time as funding availability for similar but separate programs:—CFDA No. 10.458 (Crop Insurance Education in Targeted States). Prospective applicants should carefully
The collections of information in this Announcement have been approved by OMB under control numbers 0563–0066 and 0563–0067. All applications, which must be submitted electronically through
The Federal Crop Insurance Corporation (FCIC), operating through the Risk Management Agency (RMA), announces its intent to award approximately $3,000,000 to fund the Risk Management Education Partnerships Program. The minimum award for any cooperative partnership agreement is $20,000. The maximum award for any cooperative partnership agreement is $99,999. The cooperative partnership agreements will be awarded on a competitive basis up to one year from the date of the award. The purpose of this competitive cooperative partnership agreement program is to deliver crop insurance education and risk management training to U.S. agricultural producers to assist them in identifying and managing production, marketing, legal, financial, and human risk. The program gives priority to: (1) Educating producers of crops currently not insured under Federal crop insurance, specialty crops, and underserved commodities, including livestock and forage; and (2) providing collaborative partnerships to develop and deliver crop insurance education and other risk management training. Education activities developed under the Risk Management Education Partnerships Program will provide U.S. farmers and ranchers, including limited resource, socially disadvantaged, and other traditionally under-served farmers and ranchers with training and information opportunities to be able to understand:
1. The kinds of risks addressed by existing and emerging risk management tools;
2. The features and appropriate use of existing and emerging risk management tools; and
3. How to make sound risk management decisions.
The Risk Management Education Partnership Program is authorized under section 522(d)(3)(F) of the Federal Crop Insurance Act (Act) (7 U.S.C. 1522(d)(3)(F)) and provides FCIC funding for risk management training and informational efforts for agricultural producers through the formation of partnerships with public and private organizations.
RMA promotes and regulates sound risk management solutions to improve the economic stability of American agriculture. On behalf of FCIC, RMA does this by offering Federal crop insurance products through a network of private-sector partners, overseeing the creation of new risk management products, seeking enhancements in existing products, ensuring the integrity of crop insurance programs, offering programs aimed at equal access and participation of underserved communities, and providing risk management education and information.
The goal of this program is to ensure that “. . . producers will be better able to use financial management, crop insurance, marketing contracts, and other existing and emerging risk management tools.” One of RMA's strategic goals is to ensure that producers are well informed of the risk management solutions available to them. This educational goal is supported by section 522(d)(3)(F) of the Federal Crop Insurance Act (FCIA) (7 U.S.C. 1522(d)(3)(F), which authorizes FCIC funding for risk management training and informational efforts for agricultural producers through the formation of partnerships with public and private organizations. With respect to such partnerships, priority is to be given to reaching producers of Priority Commodities, as defined below. A project is considered as giving priority to Priority Commodities if 75 percent of the educational and training activities of the project are directed to producers of any one of the three classes of commodities listed in the definition of Priority Commodities or any combination of the three classes.
For purposes of this program, Priority Commodities are defined as:
1.
1.
2.
For the 2013 fiscal year, the FCIC Board of Directors and the FCIC Manager are seeking projects that (1) address one or more of the Priority Commodities (as defined above), (2) provides Crop Insurance Education on FCIC approved policies, or (3) address one or more of the five (5) areas of risk described as Production, Legal, Financial, Marketing or Human Risk including but not limited to:
• Education on the proper use and application of cover crops as recommended or recognized by USDA, to include a thorough discussion of how cover crops are specifically recognized within the Federal crop insurance program and administered in accordance with USDA procedures or recognized good farming practices applicable specific crop and regions/location;
• Crop Insurance Education on:
○ Pasture, Rangeland and Forage (Rainfall Index) program;
○ Pasture, Rangeland and Forage (Vegetative Index) program;
○ Enterprise Units;
○ Prevented Planting;
• Crop Insurance Education and Risk Management Training on the five (5) areas of risk to High School or College Students who are preparing careers in agriculture;
• Record Keeping practices;
• Farm Benchmarking for production and financial management;
• Commodity Contracting and Hedging methods;
• Marketing Strategies to promote domestic and foreign market opportunities to local producers;
• Production and Market Strategies to expand the use of farm products differently for value added (such as using plant residue for biomass);
• Organic production methods;
• Integrated Livestock Crop management practices;
• Best Practices to Transition Conservation Reserve Program Land to Crop Production;
• Translating RMA Risk Management Education brochures into Spanish, Hmong or Navajo language for producer crop insurance education;
• Farm and Food safety education to farmworkers;
• Proper Irrigation Methods;
• Erosion Control Measures;
• Good Farming Practices;
• Forest Management;
• Range Management;
• Water Management;
• Jackson Regional Office area: Livestock Risk Protection Program;
• Topeka Regional Office area: Livestock Risk Protection Program, Livestock Gross Margin Program, and AGR-lite Program;
• Billings, Oklahoma City, and Topeka Regional Offices' areas: Training on the new Annual Forage Policy (2014 Crop Year); or
• Spokane Regional Office Area: AGR and AGR-Lite, Perennial Crops; Revenue Insurance for non-Board of Trade Commodities; Livestock Gross Margin Dairy, Livestock Protection Program; Crop Insurance for Irrigated Crops; and Crop Insurance for Organic Crops.
Only electronic applications will be accepted and they must be submitted through
There is no commitment by USDA to fund any particular application. Approximately $3,000,000 is available in fiscal year 2013. All awards will be made and agreements finalized no later than September 1, 2013 with the project start date of September 30, 2013.
Any application that requests Federal funding of less than $20,000 or more than $99,999 for a project will be rejected. RMA also reserves the right to fund successful applications at an amount less than requested if it is judged that the application can be implemented at a lower funding level.
Projects will be funded for a period of up to one year from the project starting date.
RMA Regional Offices and the States available for competition for this award are listed below. Staff from the respective RMA Regional Offices will provide substantial involvement (as defined in G below) for projects conducted within the Region.
Valdosta, Georgia Regional Office: (AL, FL, GA, PR, and SC)
Each application must clearly designate the RMA Region where educational activities will be conducted in the application narrative in block 12 of the SF–424 form. Applications without this designation will be rejected. Applications may designate more than one state but cannot designate more than one RMA Region. Applications with proposed activities in more than one state all serviced by the same RMA Region are acceptable. Single applications proposing to conduct educational activities in states served by more than one RMA Region will be rejected. Applications serving Tribal Nations will be accepted and managed from the RMA Regional office serving the designated Tribal Office.
Audience emphasis is on U.S. producers and ranchers, while reaching out to, for example, small, limited resource and socially disadvantaged producers and ranchers to ensure they are given the opportunity to participate in educational activities. Other Producer types to which the Applicant may propose to direct its training may include, but are not necessarily limited to, traditional farmers and ranchers; new and beginning farmers; women; veterans; minority producers, and
FCIC, working through RMA, will be substantially involved during the performance of the funded project through RMA's ten (10) Regional Offices (see E above). Potential types of substantial involvement may include, but are not limited to, the following activities.
1. Collaborate with the awardee in assembling, reviewing, and approving crop insurance and risk management materials for producers in the designated RMA Region.
2. Collaborate with the awardee in reviewing and approving a promotional program for raising awareness for crop insurance and risk management and for informing producers of training and informational opportunities in the RMA Region.
3. Collaborate with the awardee on the delivery of education to producers and agribusiness leaders in the RMA Region. This will include: (a) reviewing and approving in advance all producer and agribusiness leader educational activities; (b) advising the project leader on technical issues related to crop insurance education and information; and (c) assisting the project leader in informing crop insurance professionals about educational activity plans and scheduled meetings.
4. Conduct an evaluation of the performance of the awardee in meeting the tasks and subtasks of the project.
Applications that do not address substantial involvement by RMA will be rejected.
In conducting activities to achieve the purpose and goal of this program in a designated RMA Region, the awardee will be responsible for performing the following tasks:
1. Develop and conduct a promotional program in English or a non-English language to producers as appropriate to the audience. This program will include activities using media, newsletters, publications, or other appropriate informational dissemination techniques that are designed to: (a) Raise awareness for crop insurance and risk management; (b) inform producers of the availability of crop insurance and risk management tools; and (c) inform producers and agribusiness leaders in the designated RMA Region of training and informational opportunities.
2. Deliver crop insurance and risk management training in English or non-English language as appropriate to the audience as well as informational opportunities to agricultural producers and agribusiness professionals in the designated RMA Region. This will include organizing and delivering educational activities using the instructional materials assembled by the awardee to meet the local needs of agricultural producers. Activities should be directed primarily to agricultural producers, but may include those agribusiness professionals that have frequent opportunities to advise producers on risk management tools and decisions.
3. Document all educational activities conducted under the cooperative partnership agreement and the results of such activities, including criteria and indicators used to evaluate the success of the program. The awardee will also be required to provide information to RMA as requested for evaluation purposes.
In addition to the specific, required tasks listed above, the applicant may propose additional tasks that would contribute directly to the purpose of this program. For any proposed additional task, the applicant must identify the objective of the task, the specific subtasks required to meet the objective, specific time lines for performing the subtasks, and the specific responsibilities of the applicant and any entities working with the applicant in the development or delivery of the project.
Eligible applicants include not-for profit organizations, State Departments of Agriculture, State Cooperative Extension Services; Federal, State, or tribal agencies; groups representing producers, community based organizations or a coalition of community-based organization that has demonstrated experience in providing agricultural or other agricultural-related services to producers; nongovernmental organizations; junior and four-year colleges or universities or foundations maintained by a college or university; faith-based organizations and other appropriate partners with the capacity to lead a local program of crop insurance and risk management education for producers in an RMA Region.
1. Individuals are not eligible applicants.
2. Although an applicant may be eligible to compete for an award based on its status as an eligible entity, other factors may exclude an applicant from receiving Federal assistance under this program governed by Federal law and regulations (
3. Private organizations that are involved in the sale of Federal crop insurance, or that have financial ties to such organizations, are eligible to apply for funding under this Announcement. However, such entities and their partners, affiliates, and collaborators for this Announcement will not receive funding to conduct activities that are already required under a Standard Reinsurance Agreement or any other agreement in effect between FCIC/RMA and the entity, or between FCIC/RMA and any of the partners, affiliates, or collaborators for awards under this Announcement. In addition, such entities and their partners, affiliates, and collaborators for this Announcement will not be allowed to receive funding to conduct activities that could be perceived by producers as promoting the services or products of one company over the services or products of another company that provides the same or similar services or products. If applying for funding, such organizations must be aware of potential conflicts of interest and must describe in their application the specific actions they will take to avoid actual and perceived conflicts of interest.
Although RMA prefers cost sharing by the applicant, this program has neither a cost sharing nor a matching requirement.
To be eligible, applicants must also be able to demonstrate that they will receive a non-financial benefit as a result of a cooperative partnership agreement. Non-financial benefits must accrue to the applicant and must include more than the ability to provide employment income to the applicant or for the applicant's employees or the community. The applicant must demonstrate that performance under the cooperative partnership agreement will
Only electronic applications will be accepted and they must be submitted to
The applicant is strongly encouraged to use the tutorial located at
1. Project Information. Information must include the Project Name, RMA Regional Office, State/Area, Project Director's Name and Contact Information; Second Project Point of Contact Name and Contact Information; and Financial Representative or Grants Office Official and Contact Information.
2. Executive Summary of the Project (limit 200 words). This is a summary of the project and includes the project's goal and objectives, location of work, audience to be reached, and expected impacts and results of the work completed.
3. Proposed Results. Applicants must clearly identify the proposed results that producers will gain as a result of participating in the project. Each proposed result should identify the specific actions producers will take as a result of the education activities.
4. Audience Emphasis. Applicant may select one or more audiences that the project will intentionally reach.
5. Statement of Work. The Statement of Work (SOW) is in a table format and must include each task and subtask associated with the work, the objective of each task and subtask, specific time lines for performing the tasks and subtasks, and the responsible party for completing the activities listed under each task and subtask including the specific responsibilities of partners and RMA's substantial involvement. Tasks that directly involve producer participants, such as workshops, should estimate the number of participants to be reached. The SOW must be very clear on who does what, where, and when, as well as, the objective for each task and subtask.
6. Proposal Narrative (limit of 400 words). The proposal narrative is a description of work to be done, why the work is important, who will benefit from the work and any additional explanation of the expected results entered under Proposed Results that you want to communicate. The narrative should (a) Discuss the specific actions producers will likely be able to take as a result of the educational activities; (b) identify the specific measures for evaluating results that will be used in the project; (c) reasonably estimate the total number of producers that will be reached through the educational activities; (d) identify the location and number of meetings that will be held; (e) provide an estimate of the number of training hours that will be conducted; (f) provide an estimated cost per producer, and (e) justify such estimates with specific information.
7. Team and Partners. There are three subsections under Team and Partners. (1) Key Personnel: This section must list designated key personnel, and any partner(s) or consultant(s) who will be working on this project. Each person identified must be described by title, role, and responsibilities including specific tasks and subtasks in the SOW designated to them. (2) Organizational Capacity: The organizational capacity of the applicant must be described to assure RMA that designated key personnel have the skills, knowledge and experience to do the work described in the SOW and have the necessary resources to add other team members as necessary. (3) Partnering Plan: Each Partner or Consultant working on the project must be listed and must include what skills, knowledge, and experience that they will provide that is not already present in the applicant's organization, as well as why that skill, knowledge, or experience is important and what will be the cost and benefit of their involvement. Higher consideration will be given to an application that includes partnering activities with groups representing small, limited resource, or socially disadvantaged producers.
8. Budget Narrative must show the total cost for the project. The budget narrative must also include the cost per producer. The budget must describe how category costs listed on the SF 424–A are derived. The budget narrative must provide enough detail for reviewers to easily understand how costs were determined and how they relate to the tasks and subtasks listed in the SOW. There must be a relationship between work planned and performed to the costs incurred.
9. Priority Commodities. This section must list the Priorities Commodities addressed as defined in Section I, D.
10. RMA Substantial Involvement. This section must describe what tasks will be completed with RMA assistance as defined under RMA Substantial Involvement in Section II, G.
11. Non-Financial Benefits. This section must describe the Non-Financial Benefits from the proposed project as defined in Section III, C.
12. Pandemic Plan of Operation in the Event of a Human Pandemic Outbreak (Pandemic Plan). RMA requires that project leaders submit a project plan of operation in case of a human pandemic event. The plan must address the concept of continuing operations as they relate to the project. This plan must include the roles, responsibilities, and contact information for the project team and individuals serving as back-ups in case of a pandemic outbreak.
13. Requested Documents (to be downloaded from the system, completed and uploaded prior to submission of the application).
• A completed OMB Standard Form 424, “Application for Federal Assistance.”
• A completed OMB Standard Form 424–A, “Budget Information—Non-construction Programs.” Federal funding requested (the total of direct and indirect costs) must not exceed $99,999.
• A completed OMB Standard Form 424–B, “Assurances, Non-constructive Programs.”
• A completed and signed OMB Standard Form LLL, Disclosure of Lobbying Activities.
• A completed and signed AD–1049, Certification Regarding Drug-Free Workplace
• Current and Pending Report. This form contains a document called the Current and Pending Report. On the Current and Pending Report you must state for this fiscal year if this application is a duplicate application or overlaps substantially with another application already submitted to or funded by another USDA Agency, including RMA, or other private organization. The percentage of each person's time associated with the work
• Letters of Support. Letters of Support may be submitted that recommends the applicant to RMA based on previous good work performance. Each letter must include the contact information of the writer, what work was done including specific tasks or subtasks, when the work was done, and what outcome was achieved by the applicant.
• Letters of Commitment. A Letter of Commitment is required from each partner, which includes each partner and consultant, who will do each the specific task or subtask as identified in the SOW. The Letters must (1) be dated within 45 days of the submission and (2) list the specific tasks or subtasks Letter of Commitment are required for each partner or consultant who is designated to do a specific task or subtask as identified in the SOW.
Applications that do not include the items listed above will be considered incomplete, will not receive further consideration, and will be rejected.
Cooperative partnership agreement funds may not be used to:
a. Plan, repair, rehabilitate, acquire, or construct a building or facility including a processing facility;
b. Purchase, rent, or installs fixed equipment;
c. Purchase portable equipment (such as laptops, I-pads, cell phones, projectors or similar items. Rental or lease fees are payable from RMA funds for such items in lieu of purchase.)
d. Repair or maintain privately owned vehicles;
e. Pay for the preparation of the cooperative agreement application;
f. Fund political activities;
g. Purchase alcohol, food, beverage, give-away promotional items, or entertainment;
h. Lend money to support farming or agricultural business operation or expansion;
i. Pay costs incurred prior to receiving a cooperative agreement;
j. Provide producer scholarships to meetings, seminars or similar events;
k. Pay entrance fees, conference registration fees, or other expenses to conferences or similar activities for any person not on the agenda or not working at an event booth promoting RMA programs or the RMA funded project. These expenses will not be paid for the awardee's Board of Directors, family members or similar entities. These fees will not be paid for the awardee to attend personal development training in order to train producers;
l. Pay costs associated 501(c) applications;
m. Fund any activities prohibited in 7 CFR Parts 3015 and 3019, as applicable.
Total costs for salary and benefits allowed for projects under this Announcement will be limited to not more than 70 percent reimbursement of the funds awarded under the cooperative partnership agreement. The reasonableness of the total costs for salary and benefits allowed for projects under this Announcement will be reviewed and considered by RMA as part of the application review process. Applications for which RMA does not consider the salary and benefits reasonable for the proposed work will be rejected, or will only be offered a cooperative agreement upon the condition of changing the salary and benefits structure to one deemed appropriate by RMA.
1. Indirect costs allowed for projects submitted under this Announcement will be limited to ten (10) percent of the total direct cost of the cooperative partnership agreement. Therefore, when preparing budgets, applicants should limit their requests for recovery of indirect costs to the lesser of their institution's official negotiated indirect cost rate or 10 percent of the total direct costs.
2. RMA reserves the right to negotiate final budgets with successful applicants.
Applicants are entirely responsible for ensuring that RMA receives a complete application package by the closing date and time. RMA strongly encourages applicants to submit applications well before the deadline. Application packages submitted after the deadline will be rejected.
Applications submitted under the Risk Management Education Partnerships Program will be evaluated within each RMA Region according to the following criteria:
Each application must demonstrate that the project benefits and results to producers warrant the funding requested. Applications will be scored according to the extent they can: (a) Identify the specific actions producers will likely be able to take as a result of the educational activities described in the Proposal Narrative; (b) identify the specific measures for evaluating results that will be employed in the project including but limited to a change in producer behavior that results in (i) understanding crop insurance program and other risk management tools presented, (ii) evaluating what risk management options works best for his/her operation, and (iii) developing and implementing a specific course of action (
Each application must include a clear and specific Statement of Work for the project as part of the Proposal Narrative.
Each application must list all partners working on the project, their titles, and how they will contribute to the deliverables listed in the application. The application must describe how each partner will aid in carrying out the project goal and purpose stated in this announcement and should include letters of commitment dated no more than 45 days prior to submission of the relevant application stating that the partner has agreed to do this work. Applications will receive higher scores to the extent that the application demonstrates: (a) That partnership commitments are in place for the express purpose of delivering the program in this announcement; (b) that a broad group of producers will be reached within the State; (c) that partners are contributing to the project and involved in recruiting producers to attend the training; (d) that a substantial effort has been made to partner with organizations that can meet the needs of producers in the designated State; and (e) statements from each partner regarding the number of producers that partner is committed to recruit for the project that would support the estimates specified under the Project Impacts criterion.
Each application must demonstrate an ability to implement sound and effective project management practices. Higher scores in this category will be awarded to applications that demonstrate organizational skills, leadership, and experience in delivering services or programs that assist agricultural producers in the designated State. Each application must demonstrate that the Project Director has the capability to accomplish the project goal and purpose stated in this announcement by (a) having a previous or existing working relationship with the agricultural community in the designated State of the application, including being able to recruit approximately the number of producers to be reached in the application and/or (b) having established the capacity to partner with and gain the support of producer organizations, agribusiness professionals, and agribusiness leaders locally to aid in carrying out a program of education and information, including being able to recruit approximately the number of producers to be reached in this application. Applications must designate an alternate individual to assume responsibility as Project Director in the event the original Project Director is unable to finish the project. Applications that will employ, or have access to, personnel who have experience in directing local educational programs that benefit agricultural producers in the respective State will receive higher rankings in this category.
Applications must provide a (1) Total cost of the project; (2) cost per producer and (3) a detailed budget summary that clearly explains and justifies costs associated with the project's tasks and subtasks. Applications will receive higher scores in this category to the extent that they can demonstrate a fair and reasonable use of funds appropriate for the project and a budget that contains the estimated cost of reaching each individual producer.
Applications will be evaluated using a two-part process. First, each application will be screened by USDA and RMA personnel to ensure that it meets the requirements in this Announcement. Applications that do not meet the requirements of this Announcement or that are incomplete will not receive further consideration during the next process. Applications that meet Announcement requirements will be sorted into the RMA Region in which the applicant proposes to conduct the project and will be presented to a review panel for consideration.
Second, the review panel will meet to consider and discuss the merits of each application. The panel will consist of not less than three independent reviewers. Reviewers will be drawn from USDA, other Federal agencies, and public and private organizations, as needed. After considering the merits of all applications within an RMA Region, panel members will score each application according to the criteria and point values listed above. The panel will then rank each application against others within the RMA Region according to the scores received. The review panel will report the results of the evaluation to the Manager of FCIC. The panel's report will include the recommended applicants to receive cooperative partnership agreements for each RMA Region. Funding will not be provided for an application receiving a score less than 60. Funding will not be provided for an application that is “highly similar” to a higher-scoring application in the same RMA Region. “Highly similar” is defined as one that proposes to reach the same producers, farmers and ranchers who are likely to be reached by another applicant that scored higher by the panel and provides the same general educational material. An organization, or group of organizations in partnership, may apply for funding under other FCIC or RMA programs, in addition to the program described in this Announcement. However, if the Manager of FCIC determines that an application recommended for funding is sufficiently similar to a project that has been funded or has been recommended to be funded under another RMA or FCIC program, then the Manager may elect not to fund that application in whole or in part. The Manager of FCIC will make the final determination on those applications that will be awarded funding.
The award document will provide pertinent instructions and information including, at a minimum, the following:
(1) Legal name and address of performing organization or institution to which the Manager of FCIC has issued an award under the terms of this request for applications;
(2) Title of project;
(3) Name(s) and employing institution(s) of Project Directors chosen to direct and control approved activities;
(4) Identifying award number assigned by RMA;
(5) Project period, specifying the amount of time RMA intends to support the project;
(6) Total amount of RMA financial assistance approved by the Manager of FCIC during the project period;
(7) Legal authority(ies) under which the award is issued;
(8) Appropriate Catalog of Federal Domestic Assistance (CFDA) numbers;
(9) Applicable RMA award terms and conditions;
(10) Approved budget plan for categorizing allocable project funds to
(11) Other information or provisions deemed necessary by RMA to carry out its respective awarding activities or to accomplish the purpose of a particular award. Following approval by the Manager of FCIC of the applications to be selected for funding, project leaders whose applications have been selected for funding will be notified. Within the limit of funds available for such a purpose, the Manager of FCIC will enter into cooperative partnership agreements with those selected applicants.
After a cooperative partnership agreement has been signed, RMA will extend to awardees, in writing, the authority to draw down funds for the purpose of conducting the activities listed in the agreement. All funds provided to the applicant by FCIC must be expended solely for the purpose for which the funds are obligated in accordance with the approved cooperative partnership agreement and budget, the regulations, the terms and conditions of the award, and the applicability of Federal cost principles. No commitment of Federal assistance beyond the project period is made or implied for any award resulting from this notice.
Notification of denial of funding will be sent to applicants after final funding decisions have been made and the awardees announced publicly. Unsuccessful applicants will be provided a debriefing upon request to the Director, Risk Management Education.
Applicants awarded cooperative partnership agreements will be required to use a USDA Logo provided by RMA for all instructional and promotional materials, when deemed appropriate.
Applicants awarded cooperative partnership agreements will be required to provide RMA educational materials, tools, Web pages or similar items no later than 20 business days before use in the public domain for the purpose of RMA review and approval. Educational materials cannot be used without RMA approval. In addition, award recipients will assist RMA in evaluating the effectiveness of its educational programs by notifying RMA of upcoming training meeting and by providing documentation of educational activities, materials, and related information to any representative selected by RMA for program evaluation purposes.
Upon written request from the applicant, scores from the evaluation panel, not including the identity of reviewers, will be sent to the applicant after the review and award process has been completed.
The names of applicants, the names of individuals identified in the applications, the content of applications, and the panel evaluations of applications will all be kept confidential, except to those involved in the review process, to the extent permitted by law. In addition, the identities of review panel members will remain confidential throughout the entire review process and will not be released to applicants. At the end of the fiscal year, names of panel members will be made available. However, panelists will not be identified with the review of any particular application. When an application results in a cooperative partnership agreement, that agreement becomes a part of the official record of RMA transactions, available to the public upon specific request. Information that the Secretary of Agriculture determines to be of a confidential, privileged, or proprietary nature will be held in confidence to the extent permitted by law. Therefore, any information that the applicant wishes to be considered confidential, privileged, or proprietary should be clearly marked within an application, including the basis for such designation. The original copy of an application that does not result in an award will be retained by RMA for a period of one year. Other copies will be destroyed. Copies of applications not receiving awards will be released only with the express written consent of the applicant or to the extent required by law. An application may be withdrawn at any time prior to award.
Applicants awarded cooperative partnership agreements are subject to audit.
All cooperative agreements will be subject to the requirements of 7 CFR part 3015, “Uniform Federal Assistance Regulations.” A signed copy of the certification and disclosure forms must be submitted with the application and are available at the address and telephone number listed in Section VII, Agency Contact.
Departmental regulations published at 7 CFR part 3018 imposes prohibitions and requirements for disclosure and certification related to lobbying on awardees of Federal contracts, grants, cooperative partnership agreements and loans. It provides exemptions for Indian Tribes and tribal organizations. Current and prospective awardees, and any subcontractors, are prohibited from using Federal funds, other than profits from a Federal contract, for lobbying Congress or any Federal agency in connection with the award of a contract, grant, cooperative partnership agreement or loan. In addition, for each award action in excess of $100,000 ($150,000 for loans) the law requires awardees and any subcontractors to complete a certification in accordance with Appendix A to Part 3018 and a disclosure of lobbying activities in accordance with Appendix B to Part 3018. The law establishes civil penalties for non-compliance.
All cooperative partnership agreements funded as a result of this notice will be subject to the requirements contained in all applicable OMB circulars at
Awardees and all partners/collaborators of all cooperative agreements funded as a result of this notice are required to know and abide by Federal civil rights laws, which include, but are not limited to, Title VI of the Civil Rights Act of 1964 (42 U.S.C. 2000d
RMA requires that project leaders participate in a post award teleconference, if conducted, to become fully aware of agreement requirements and for delineating the roles of RMA personnel and the procedures that will
RMA requires that project leaders participate in a post award Civil Rights and EEO training to become fully aware of Civil Rights and EEO law and requirements.
RMA requires that project leaders upload digital copies of all risk management educational materials developed because of the project to the Ag Risk and Farm Management Library at
Awardees will be required to submit quarterly financial reports (OMB Standard Form 425) throughout the project period, as well as a final program and financial report not later than 90 days after the end of the project period. The quarterly progress reports and final program reports must be submitted through the Results Verification System. The Web site address is
Applicants and other interested parties are encouraged to contact: USDA–RMA–RME, phone: 202–720–0779, email:
The Agriculture, Rural Development, Food and Drug Administration, and Related Agencies Appropriations Act, 2012 (Pub. L. 112–55) contains the restriction of the expenditure of funds to enter into financial transactions Corporations that have been convicted of felonies within the past 24 months or that have federal tax delinquencies where the agency is aware of the felonies and/or tax delinquencies.
None of the funds made available by this Act may be used to enter into a contract, memorandum of understanding, or cooperative agreement with, make a grant to, or provide a loan or loan guarantee to any corporation that was convicted (or had an officer or agency of such corporation acting on behalf of the corporation convicted) of a felony criminal violation under any Federal or State law within the preceding 24 months, where the awarding agency is aware of the conviction, unless the agency has considered suspension or debarment of the corporation, or such officer or agent, and made a determination that this further action is not necessary to protect the interest of the Government.
None of the funds made available by this Act may be used to enter into a contract, memorandum of understanding, or cooperative agreement with, make a grant to, or provide a loan or loan guarantee to, any corporation that [has] any unpaid Federal tax liability that has been assessed, for which all judicial and administrative remedies have been exhausted or have lapsed, and that is not being paid in a timely manner pursuant to an agreement with the authority responsible for collecting the tax liability, where the awarding agency is aware of the unpaid tax liability, unless the agency has considered suspension or debarment of the corporation and made a determination that this further action is not necessary to protect the interests of the Government.
Under the Federal Funding Accountability and Transparency Act of 2006, the applicant must comply with the additional requirements set forth in Attachment A regarding the Dun and Bradstreet Universal Numbering System (DUNS) Requirements and the SAM Requirements found at 2 CFR part 25. For the purposes of this RFA, the term “you” in Attachment A will mean “applicant”. The applicant will comply with the additional requirements set forth in Attachment B regarding Subawards and Executive Compensation. For the purpose of this RFA, the term “you” in Attachment B will mean “applicant”. SAM (
Funding availability for this program may be announced at approximately the same time as funding availability for similar but separate programs—and CFDA No. 10.458 (Crop Insurance Education in Targeted States). These programs have some similarities, but also key differences. The differences stem from important features of each program's authorizing legislation and different RMA objectives. Prospective applicants should carefully examine and compare the notices for each program.
Unless you are exempted from this requirement under 2 CFR 25.110, you as the recipient must maintain the currency of your information in SAM until you submit the final financial report required under this award or receive the final payment, whichever is later. This requires that you review and update the information at least annually after the initial registration, and more frequently if required by changes in your information or another award term.
If you are authorized to make subawards under this award, you:
1. Must notify potential sub recipients that no entity (see definition in paragraph C of this award) may receive a subaward from you unless the entity has provided its DUNS number to you.
2. May not make a subaward to an entity unless the entity has provided its DUNS number to you.
1. SAM means the Federal repository into which an entity must provide information required for the conduct of business as a recipient. Additional information about registration procedures may be found at
2. Data Universal Numbering System (DUNS) number means the nine-digit number
3. Entity, as it is used in this award term, means all of the following, as defined at 2 CFR part 25, subpart C:
a. A Governmental organization, which is a State, local government, or Indian Tribe;
b. A foreign public entity;
c. A domestic or foreign nonprofit organization;
d. A domestic or foreign for-profit organization; and
e. A Federal agency, but only as a subrecipient under an award or subaward to a non-Federal entity.
4. Subaward:
a. This term means a legal instrument to provide support for the performance of any portion of the substantive project or program for which you received this award and that you as the recipient award to an eligible subrecipient.
b. The term does not include your procurement of property and services needed to carry out the project or program (for further explanation, OMB Circular A–I33, “Audits of States, Local Governments, and Non-Profit Organizations”).
c. A subaward may be provided through any legal agreement, including an agreement that you consider a contract.
5. Subrecipient means an entity that:
a. Receives a subaward from you under this award; and
b. Is accountable to you for the use of the Federal funds provided by the subaward.
I. Reporting Sub awards and Executive Compensation.
a. Reporting of first-tier subawards.
1. Applicability. Unless you are exempt as provided in paragraph d. of this award term, you must report each action that obligates $25,000 or more in Federal funds that does not include Recovery funds (as defined in section 1512(a)(2) of the American Recovery and Reinvestment Act of 2009 (Pub. L. 111–5) for a subaward to an entity (see definitions in paragraph e. of this award term).
2. Where and when to report.
i. You must report each obligating action described in paragraph a.I. of this award term to
ii. For sub award information, report no later than the end of the month following the month in which the obligation was made. (For example, if the obligation was made on November 7, 2012, the obligation must be reported by no later than December 31, 2012.)
3. What to report. You must report the information about each obligating action that the submission instructions posted at
b. Reporting Total Compensation of Recipient Executives.
1. Applicability and what to report. You must report total compensation for each of your five most highly compensated executives for the preceding completed fiscal year, if—
i. The total Federal funding authorized to date under this award is $25,000 or more;
ii. In the preceding fiscal year, you received—
(A) 80 percent or more of your annual gross revenues from Federal procurement contracts (and subcontracts) and Federal financial assistance subject to the Transparency Act, as defined at 2 CFR 170.320 (and subawards); and
(B) $25,000,000 or more in annual gross revenues from Federal procurement contracts (and subcontracts) and Federal financial assistance subject to the Transparency Act, as defined at 2 CFR 170.320 (and subawards); and
iii. The public does not have access to information about the compensation of the executives through periodic reports filed under section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a), 780(d)) or section 6104 of the Internal Revenue Code of 1986. (To determine if the public has access to the compensation information, see the U.S. Security and Exchange Commission total compensation filings at
2. Where and when to report. You must report executive total compensation described in paragraph b.1. of this award term:
i. As part of your registration profile at
ii. By the end of the month following the month in which this award is made, and annually thereafter.
c. Reporting of Total Compensation of Sub recipient Executives.
1. Applicability and what to report. Unless you are exempt as provided in paragraph d. of this award term, for each first-tier sub recipient under this award, you will report the names and total compensation of each of the sub recipient's five most highly compensated executives for the sub recipient's preceding completed fiscal year, if—
i. in the subrecipient's preceding fiscal year, the subrecipient received—
(A) 80 percent or more of its annual gross revenues from Federal procurement contracts (and subcontracts) and Federal financial assistance subject to the Transparency Act, as defined at ~ CFR 170.320 (and subawards); and
(B) $25,000,000 or more in annual gross revenues from Federal procurement contracts (and subcontracts), and Federal financial assistance subject to the Transparency Act (and subawards); and
ii. The public does not have access to information about the compensation of the executives through periodic reports filed under section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a), 780(d) or section 6104 of the Internal Revenue Code of 1986. (To determine if the public has access to the compensation information, see the U.S. Security and Exchange Commission total compensation filings at
2. Where and when to report. You must report subrecipient executive total compensation described in paragraph c.1. of this award term:
i. To the recipient.
ii. By the end of the month following the month during which you make the subaward. For example, if a subaward is obligated on any date during the month of October of a given year (
d. Exemptions
If, in the previous tax year, you had gross income, from all sources, under $300,000, you are exempt from the requirements to report:
i. Subawards, and
ii. The total compensation of the five most highly compensated executives of any sub recipient.
e. Definitions. For purposes of this award term:
1. Entity means all of the following, as defined in 2 CFR part 25:
i. A Governmental organization, which is a State, local government, or Indian tribe;
ii. A foreign public entity;
iii. A domestic or foreign nonprofit organization;
iv. A domestic or foreign for-profit organization;
v. A Federal agency, but only as a subrecipient under an award or subaward to a non-Federal entity.
2. Executive means officers, managing partners, or any other employees in management positions.
3. Subaward:
1. This term means a legal instrument to provide support for the performance of any portion of the substantive project or program for which you received this award and that you as the recipient award to an eligible subrecipient.
ii. The term does not include your procurement of property and services needed to carry out the project or program (OMB Circular A–133, “Audits of States, Local Governments, and Non-Profit Organizations”).
iii. A subaward may be provided through any legal agreement, including an agreement that you or a subrecipient considers a contract.
4. Subrecipient means an entity that:
i. Receives a sub award from you (the recipient) under this award; and
ii. Is accountable to you for the use of the Federal funds provided by the subaward.
5. Total compensation means the cash and noncash dollar value earned by the executive during the recipient's or subrecipient's preceding fiscal year and includes the following (for more information see 17 CFR 229.402(c)(2):
i. Salary and bonus.
ii. Awards of stock, stock options, and stock appreciation rights. Use the dollar amount recognized for financial statement reporting purposes with respect to the fiscal year in accordance with the Statement of Financial Accounting Standards No. 123 (Revised 2004) (FAS 123R), Shared Based Payments.
iii. Earnings for services under non-equity incentive plans. This does not include group life, health, hospitalization or medical reimbursement plans that do not discriminate in favor of executives, and are available generally to all salaried employees.
iv. Change in pension value. This is the change in present value of defined benefit and actuarial pension plans.
v. Above-market earnings on deferred compensation which is not tax-qualified.
vi. Other compensation, if the aggregate value of all such other compensation (
All applications, which must be submitted electronically through
The Federal Crop Insurance Corporation (FCIC), operating through the Risk Management Agency (RMA), announces its intent to award approximately $5,000,000 to fund cooperative agreements under the Risk Management Education in Targeted States Program.
Purpose: The purpose of the Targeted States program is to deliver crop insurance education and information to U.S. agricultural producers in States where there is traditionally, and continues to be a low level of Federal crop insurance participation and availability, and producers are underserved by the Federal crop insurance program. These states, defined as Targeted States for the purposes of this RFA, are Connecticut, Delaware, Hawaii, Maine, Maryland, Massachusetts, Nevada, New Hampshire, New Jersey, New York, Pennsylvania, Rhode Island, Utah, Vermont, West Virginia, and Wyoming. Any cooperative agreements that may be funded will not exceed the maximum funding amount established for each of the Targeted States. Awardees must agree to the substantial involvement of RMA in the project.
Applications submitted under this RFA must demonstrate how the proposed crop insurance education activities will help producers in Targeted States understand:
• The kinds of risks addressed by crop insurance;
• the features of existing and emerging crop insurance products;
• in states where applicable, the proper use and application of cover crops as recommended or recognized by USDA, to include a thorough discussion of how cover crops are specifically recognized within the Federal crop insurance program and administered in accordance with USDA procedures or recognized good farming practices applicator specific crop and regions/location;
• the use of crop insurance in the management of risk;
• how the use of crop insurance can affect other risk management decisions, such as the use of marketing and financial tools;
• how to make informed decisions on crop insurance prior to the sales closing date deadline; and,
• record-keeping requirements for crop insurance.
Funding availability for this program may be announced at approximately the same time as funding availability for similar but separate program, the Risk Management Education Partnerships Program (CFDA No. 10.460). Prospective applicants must carefully examine and compare the notices of each announcement.
The collections of information in this announcement have been approved by the Office of Management and Budget (OMB) under control number 0563–0067.
The Targeted States Program is authorized under section 524(a)(2) of the Federal Crop Insurance Act (FCIA), 7 U.S.C. 1524(a)(2).
RMA promotes and regulates sound risk management solutions to improve the economic stability of American agriculture. On behalf of FCIC, RMA does this by offering Federal crop insurance products through a network of private-sector partners, overseeing the creation of new risk management products, seeking enhancements in existing products, ensuring the integrity of crop insurance programs, offering programs aimed at equal access and participation of underserved
One of RMA's strategic goals is to ensure that its customers are well-informed of risk management solutions available. This educational goal is authorized by section 524(a)(2) of the FCIA (7 U.S.C. 1524(a)(2). This section authorizes funding for the establishment of crop insurance education and information programs in States where there is traditionally, and continues to be, a low level of Federal crop insurance participation and availability, and producers are underserved by the Federal crop insurance program. In accordance with the FCIA, the States with this designation for Fiscal Year (FY) 2013 are Connecticut, Delaware, Hawaii, Maine, Maryland, Massachusetts, Nevada, New Hampshire, New Jersey, New York, Pennsylvania, Rhode Island, Utah, Vermont, West Virginia, and Wyoming (defined as “Targeted States” for the purposes of this RFA).
The goal of the Targeted States Program is to ensure that producers in the Targeted States are fully informed of existing and emerging crop insurance products in order to take full advantage of such products including but not limited to:
Applications submitted under this RFA must demonstrate how the proposed crop insurance education activities will help producers in Targeted States understand:
• The kinds of risks addressed by crop insurance;
• the features of existing and emerging crop insurance products;
• in states where applicable, the proper use and application of cover crops as recommended or recognized by USDA, to include a thorough discussion of how cover crops are specifically recognized within the Federal crop insurance program and administered in accordance with USDA procedures or recognized good farming practices applicator specific crop and regions/location;
• The use of crop insurance in the management of risk;
• how the use of crop insurance can affect other risk management decisions, such as the use of marketing and financial tools;
• how to make informed decisions on crop insurance prior to the sales closing date deadline; and,
• record-keeping requirements for crop insurance.
In carrying out the requirements under Section 12026 of the Food, Conservation, And Energy Act of 2008, the Secretary of Agriculture has placed special emphasis on risk management strategies and crop insurance education specifically targeted to the following producers:
(A) Beginning farmers or ranchers;
(B) legal immigrant farmers or ranchers that are attempting to become established producers in the United States;
(C) socially disadvantaged farmers or ranchers;
(D) farmers or ranchers that—
(i) are preparing to retire; and
(ii) are using transition strategies to help new farmers or ranchers get started; and
(E) new or established farmers or ranchers that are converting production and marketing systems to pursue new markets.
Only electronic applications will be accepted and they must be submitted through
There is no commitment by USDA to fund any particular application or make a specific number of awards. RMA intends to award approximately $5,000,000 (in fiscal year 2013 to fund one or more cooperative agreement(s) not to exceed the maximum funding amount established for each of the Targeted States. An applicant must apply for funding for that Targeted State where the applicant intends to deliver the educational activities, and must limit its request for funding in a particular Targeted State based upon the funding levels available below.
Funding amounts were determined by first allocating an equal amount of $200,000 to each Targeted State. Remaining funds were allocated on a pro rata basis according to each Targeted State's share of agricultural cash receipts reported in the National Agricultural Statistics Service (NASS) 2007 Agricultural Census, relative to the total for all Targeted States. Both the equal allocation and the pro rata allocation were totaled together and rounded to the nearest $1,000 to arrive at the funding limit for each Targeted State.
In the event that additional funds become available under this program or in the event that no application for a given Targeted State is recommended for funding by the evaluation panel, these additional funds, or unused funds for a particular Targeted State, may be allocated pro-rata to other awardees. These additional or unused funds may be offered to selected awardees for use in broadening the size or scope of awarded projects within the Targeted States in which funds were awarded, if such selected awardees agree to any changes to the project necessary determined by RMA to make use of the additional funds. The decision of whether any additional or unused funds are offered to other award recipients, and the pro-rata manner in which they may be distributed to recipients that are willing to make required adjustments to their awarded projects to accept such additional funds, is within the discretion of the FCIC Manager. RMA is not required to distribute any additional or unused funds to the awardees.
In the event that the Manager of FCIC determines that available RMA resources cannot support the administrative and substantial involvement requirements of all agreements recommended for funding, the Manager may elect to fund fewer agreements than the available funding might otherwise allow. All awards will be made and agreements finalized no later than September 1, 2013 with a project start date of September 30, 2013.
The RMA Regional Offices that service the Targeted States are listed below. Staff from these respective RMA Regional Offices will provide the RMA substantial involvement for Targeted
Each application must clearly designate the Targeted State where crop insurance educational activities for the project will be delivered in block 14 of the SF–424, “Application for Federal Assistance.” Applications without this designation in block 14 will be rejected. Applicants may apply to deliver education to producers in more than one Targeted State, but a separate application must be submitted for each Targeted State because applications will be compared to applications submitted for the same state. Any single application proposing to conduct educational activities in more than one Targeted State will be rejected.
Any application that requests funding under this Announcement of more than the amount listed above for a project in a given Targeted State will be rejected.
Projects will be funded for a period of up to one year from the project starting date.
Audience emphasis is on U.S. producers and ranchers, while reaching out to, for example, small, limited resource and socially disadvantaged producers and ranchers to ensure they are given the opportunity to participate in educational activities. Other Producer types to which the Applicant may propose to direct its training may include, but are not necessarily limited to, traditional farmers and ranchers; new and beginning farmers; women; veterans; minority producers, and producers living in areas designated as Strike Force communities as defined by USDA, provided that the producers in these categories that are emphasized also meet the minimum statutory criteria.
In conducting activities to achieve the purpose and goal of this program in a designated Targeted State, the awardee will be responsible for performing the following tasks:
• Develop and conduct a promotional program in English or a non-English language to producers. If non-English language is used, a translation in English must be provided. This program will include activities using media, newsletters, publications, or other appropriate informational dissemination techniques that are designed to: (a) Raise awareness for crop insurance; (b) inform producers of the availability of crop insurance; (c) inform producers of the crop insurance sales closing dates prior to the deadline; and (d) inform producers (and may inform agribusiness professionals), in the designated Targeted State of training and informational opportunities.
• Deliver crop insurance training and informational opportunities in English or a non-English language to agricultural producers (and may deliver to agribusiness professionals) in the designated Targeted State in a timely manner, prior to crop insurance sales closing dates, in order for producers to make informed decisions regarding risk management tools prior to the crop insurance sales closing dates deadline. This delivery will include organizing and delivering educational activities using instructional materials that have been assembled to meet the local needs of agricultural producers. Activities must be directed primarily to agricultural producers, but may include those agribusiness professionals that frequently advise producers on crop insurance tools and decisions and will use the information gained from these trainings to advise producers.
• Document all educational activities conducted under the cooperative agreement and the results of such activities, including criteria and indicators used to evaluate the success of the program. The awardee will also be required, if requested by RMA, to provide information to RMA-selected contractor(s) to evaluate all educational activities and advise RMA regarding the effectiveness of activities.
RMA will be substantially involved during the performance of the funded project through RMA's three (3) Regional Offices identified earlier. Potential types of substantial involvement by these three (3) Regional Offices will include, but are not limited to, the following activities.
• Collaborate with the awardee in assembling, reviewing, and approving risk management materials for producers in the designated Targeted States.
• Collaborate with the awardee in reviewing and approving a promotional program for raising awareness for risk management and for informing producers of training and informational opportunities in the Targeted States.
• Collaborate with the awardee on the delivery of education to producers and agribusiness professionals for the Targeted States. This collaboration will include: (a) Reviewing and approving in advance all producer and agribusiness professional educational activities; (b) advising the awardee on technical issues related to crop insurance education and information; and (c) assisting the awardee in informing producers and agribusiness professionals about educational activity plans and scheduled meetings.
• Conduct an evaluation of the performance of the awardee in meeting the tasks and subtasks of the project.
Applications that do not contain substantial involvement by RMA will be rejected.
In addition to the specific, required tasks listed above, the applicant may propose additional tasks that would contribute directly to the purpose of this program. For any proposed additional task, the applicant must identify the objective of the task, the specific subtasks required to meet the objective, specific time lines for performing the subtasks, and the specific responsibilities of partners. The applicant must also identify specific ways in which RMA would have substantial involvement in the proposed project task.
Eligible applicants include not-for-profit organizations, State Departments of Agriculture, State Cooperative Extension Services; Federal, State, or tribal agencies; groups representing producers, community based organizations or a coalition of community-based organization that has demonstrated experience in providing agricultural education or other agricultural-related services to producers; nongovernmental organizations; junior and four-year colleges or universities or foundations maintained by a college or university; and other entities with the capacity to lead a program of risk management education for producers in one or more Targeted States.
1. Individuals are not eligible applicants.
2. Although an applicant may be eligible to compete for an award based on its status as the type of entity described immediately above, other factors may exclude an applicant from receiving Federal assistance under this program, which is governed by Federal law and regulations (e.g. debarment and suspension; a determination of non-
3. Private organizations that are involved in the sale of Federal crop insurance, or that have financial ties to such organizations, are eligible to apply for funding under this Announcement. However, such entities and their partners, affiliates, and collaborators for this Announcement will not receive funding to conduct activities that are already required under a Standard Reinsurance Agreement or any other agreement in effect between FCIC/RMA and the entity, or between FCIC/RMA and any of the partners; affiliates, or collaborators for awards under this Announcement. In addition, such entities and their partners, affiliates, and collaborators for this Announcement will not be allowed to receive funding to conduct activities that could be perceived by producers as promoting the services or products of one company over the services or products of another company that provides the same or similar services or products. If applying for funding, such organizations must be aware of potential conflicts of interest and must describe in their application the specific actions they will take to avoid actual and perceived conflicts of interest.
Although RMA prefers cost sharing by the applicant, this program has neither a cost sharing nor a matching requirement.
To be eligible, applicants must also be able to demonstrate that they will receive a non-financial benefit as a result of a cooperative partnership agreement. Non-financial benefits must accrue to the applicant and must include more than the ability to provide employment income to the applicant or for the applicant's employees or the community. The applicant must demonstrate that performance under the cooperative partnership agreement will further the specific mission of the applicant (such as providing research or activities necessary for graduate or other students to complete their educational program). Applications that do not demonstrate a non-financial benefit will be rejected.
Only electronic applications will be accepted and they must be submitted to
The applicant is strongly encouraged to use the tutorial located at
1. Project Information. Information must include the Project Name, RMA Regional Office, State/Area, Project Director's Name and Contact Information; Second Project Point of Contact Name and Contact Information; and Financial Representative or Grants Office Official and Contact Information.
2. Executive Summary of the Project (limit 200 words). This is a summary of the project and includes the project's goal and objectives, location of work, audience to be reached, and expected impacts and results of the work completed.
3. Proposed Results. Applicants must clearly identify the proposed results that producers will gain as a result of participating in the project. Each proposed result should identify the specific actions producers will take as a result of the education activities.
4. Audience Emphasis. Applicant may select one or more audiences that the project will intentionally reach.
5. Statement of Work. The Statement of Work (SOW) is in a table format and must include each task and subtask associated with the work, the objective of each task and subtask, specific time lines for performing the tasks and subtasks, and the responsible party for completing the activities listed under each task and subtask including the specific responsibilities of partners and RMA's substantial involvement. Tasks that directly involve producer participants, such as workshops, should estimate the number of participants that each task reaches. The SOW must be very clear on who does what, where, and when, as well as, the objective for each task and subtask.
6. Proposal Narrative (limit of 400 words). The proposal narrative is a description of work to be done, why the work is important, who will benefit from the work and any additional explanation of the expected results entered under Proposed Results that you want to communicate. The narrative should (a) discuss the specific actions producers will likely be able to take as a result of the educational activities; (b) identify the specific measures for evaluating results that will be used in the project; (c) reasonably estimate the total number of producers that will be reached through the educational activities; (d) identify the location and number of meetings that will be held; (e) provide an estimate of the number of training hours that will be conducted; (f) provide an estimated cost per producer, and (e) justify such estimates with specific information.
7. Team and Partners. There are three subsections under Team and Partners. (1) Key Personnel: This section must list designated key personnel, and any partner(s) or consultant(s) who will be working on this project. Each person identified must be described by title, role, and responsibilities including specific tasks and subtasks in the SOW designated to them. (2) Organizational Capacity: The organizational capacity of the applicant must be described to assure RMA that designated key personnel have the skills, knowledge and experience to do the work described in the SOW and have the necessary resources to add other team members as necessary. (3) Partnering Plan: Each Partner or Consultant working on the project must be listed and must include what skills, knowledge, and experience that they will provide that is not already present in the applicant's organization, as well as why that skill, knowledge, or experience is important and what will be the cost and benefit of their involvement. Higher consideration will be given to an application that includes partnering activities with groups representing small, limited resource, or socially disadvantaged producers.
8. Budget Narrative. The budget narrative must show the total cost for the project and must also include the cost per producer. The budget narrative must describe how category costs listed on the SF 424–A are derived. The budget narrative must provide enough detail for reviewers to easily understand how costs were determined and how they relate to the tasks and subtasks
9. RMA Substantial Involvement. This section must describe what tasks will be completed with RMA assistance as defined under RMA Substantial Involvement in Section II, G.
10. Non-Financial Benefits. This section must describe the Non-Financial Benefits from the proposed project as defined in Section III, C.
11. Pandemic Plan of Operation in the Event of a Human Pandemic Outbreak (Pandemic Plan). RMA requires that project leaders submit a project plan of operation in case of a human pandemic event. The plan must address the concept of continuing operations as they relate to the project. This plan must include the roles, responsibilities, and contact information for the project team and individuals serving as back-ups in case of a pandemic outbreak.
12. Requested Documents (to be downloaded from the system, completed and uploaded prior to submission of the application).
• A completed OMB Standard Form 424, “Application for Federal Assistance.”
• A completed OMB Standard Form 424–A, “Budget Information—Non-construction Programs.” Federal funding requested (the total of direct and indirect costs) must not exceed the amount allocated for the state (Section II, B.)
• A completed OMB Standard Form 424–B, “Assurances, Non-constructive Programs.”
• A completed and signed OMB Standard Form LLL, Disclosure of Lobbying Activities.
• A completed and signed AD–1049, Certification Regarding Drug-Free Workplace.
• Current and Pending Report. This form contains a document called the Current and Pending Report. On the Current and Pending Report you must state for this fiscal year if this application is a duplicate application or overlaps substantially with another application already submitted to or funded by another USDA Agency, including RMA, or other private organization. The percentage of each person's time associated with the work to be done under this project must be identified in the application. The total percentage of time for both “Current” and “Pending” projects must not exceed 100% of each person's time. Applicants must list all current public or private employment arrangements or financial support associated with the project or any of the personnel that are part of the project, regardless of whether such arrangements or funding constitute part of the project under this Announcement (supporting agency, amount of award, effective date, expiration date, expiration date of award, etc.). If the applicant has no projects to list, “N/A” should be shown on the form. An application submitted under this RFA that duplicates or overlaps substantially with any application already reviewed and funded (or to be funded) by any other organization or agency, including but not limited to other RMA, USDA, and Federal government programs, will not be funded under this program. RMA reserves the right to reject your application based on the review of this information.
• Letters of Support. Letters of Support may be submitted that recommends the applicant to RMA based on previous good work performance. Each letter must include the contact information of the writer, what work was done including specific tasks or subtasks, when the work was done, and what outcome was achieved by the applicant.
• Letters of Commitment. A Letter of Commitment is required from each partner, which includes each partner and consultant, who will do each specific task or subtask as identified in the SOW. The Letters must (1) be dated within 45 days of the submission and (2) list the specific tasks or subtasks Letter of Commitment are required for each partner or consultant who is designated to do a specific task or subtask as identified in the SOW.
Applications that do not include the items listed above will be considered incomplete, will not receive further consideration, and will be rejected.
Cooperative partnership agreement funds may not be used to:
a. Plan, repair, rehabilitate, acquire, or construct a building or facility including a processing facility;
b. purchase, rent, or installs fixed equipment;
c. purchase portable equipment (such as laptops, I-pads, cell phones, projectors or similar items. Rental or lease fees are payable from RMA funds for such items in lieu of purchase.)
d. repair or maintain privately owned vehicles;
e. pay for the preparation of the cooperative agreement application;
f. fund political activities;
g. purchase alcohol, food, beverage, give-away promotional items, or entertainment;
h. lend money to support farming or agricultural business operation or expansion;
i. pay costs incurred prior to receiving a cooperative agreement;
j. provide producer scholarships to meetings, seminars, or similar events;
k. pay entrance fees, conference registration fees, or other expenses to conferences or similar activities for any person not on the agenda or not working at an event booth promoting RMA programs or the RMA funded project. These expenses will not be paid for the awardee's Board of Directors, family members or similar entities. These fees will not be paid for the awardee to attend personal development training in order to train producers;
l. pay costs associated 501(c) applications;
m. fund any activities prohibited in 7 CFR Parts 3015 and 3019, as applicable.
Total costs for salary and benefits allowed for projects under this Announcement will be limited to not more than 70 percent reimbursement of the funds awarded under the cooperative partnership agreement. The reasonableness of the total costs for salary and benefits allowed for projects under this Announcement will be reviewed and considered by RMA as part of the application review process. Applications for which RMA does not consider the salary and benefits reasonable for the proposed application will be rejected, or will only be offered a cooperative agreement upon the condition of changing the salary and benefits structure to one deemed appropriate by RMA for that application. The goal of the Targeted States Program is to maximize the use of the limited funding available for crop insurance education to producers in Targeted States.
a. Indirect costs allowed for projects submitted under this announcement will be limited to ten (10) percent of the total direct cost of the cooperative agreement. Therefore, when preparing budgets, applicants should limit their requests for recovery of indirect costs to the lesser of their institution's official negotiated indirect cost rate or 10 percent of the total direct costs.
b. RMA reserves the right to negotiate final budgets with successful applicants.
Applicants are entirely responsible for ensuring that RMA receives a complete application package by the closing date and time. RMA strongly encourages applicants to submit applications well before the deadline. Application
Applications submitted under the Targeted States Program will be evaluated within each RMA Region according to the following criteria:
Each application must demonstrate that the project benefits and results to producers warrant the funding requested. Applications will be scored according to the extent they can: (a) Identify the specific actions producers will likely be able to take as a result of the educational activities described in the Proposal Narrative; (b) identify the specific measures for evaluating results that will be employed in the project including but limited to a change in producer behavior that results in (i) understanding crop insurance program and other risk management tools presented, (ii) evaluating what risk management options works best for his/her operation, and (iii) developing and implementing a specific course of action (e.g., participation in crop insurance programs or creating a risk management plan or other risk management actions); (c) reasonably estimate the total number of producers that will be reached through the various methods and educational activities described in the Statement of Work; (d) identify the number of meetings that will be held; (e) provide an estimate of the number of training hours that will be held; (f) justify such estimates with specific information. Estimates for reaching agribusiness professionals may also be provided but such estimates must be provided separately from the estimates of producers. Reviewers' scoring will be based on the scope and reasonableness of the application's clear descriptions of specific expected actions producers will accomplish, and well-designed methods for measuring the project's results and effectiveness.
Each application must include a clear and specific Statement of Work for the project as part of the Proposal Narrative. For each of the tasks contained in the Description of Agreement Award (see Section II, Award Information), the application must identify and describe specific subtasks, responsible entities including partners, expected completion dates and deliverables that will further the purpose of this program. RMA substantial involvement must be included. Higher consideration will be given to the Statement of Work that demonstrates specific, measurable results and definite deadlines for the completion of tasks and subtasks
Each application must list all partners working on the project, their titles, and how they will contribute to the deliverables listed in the application. The application must describe how each partner will aid in carrying out the project goal and purpose stated in this announcement and should include letters of commitment dated no more than 45 days prior to submission of the relevant application stating that the partner has agreed to do this work. Applications will receive higher scores to the extent that the application demonstrates: (a) That partnership commitments are in place for the express purpose of delivering the program in this announcement; (b) that a broad group of producers will be reached within the State; (c) that partners are contributing to the project and involved in recruiting producers to attend the training; (d) that a substantial effort has been made to partner with organizations that can meet the needs of producers in the designated State; and (e) statements from each partner regarding the number of producers that partner is committed to recruit for the project that would support the estimates specified under the Project Impacts criterion.
Each application must demonstrate an ability to implement sound and effective project management practices. Higher scores in this category will be awarded to applications that demonstrate organizational skills, leadership, and experience in delivering services or programs that assist agricultural producers in the designated State. Each application must demonstrate that the Project Director has the capability to accomplish the project goal and purpose stated in this announcement by (a) having a previous or existing working relationship with the agricultural community in the designated State of the application, including being able to recruit approximately the number of producers to be reached in the application and/or (b) having established the capacity to partner with and gain the support of producer organizations, agribusiness professionals, and agribusiness leaders locally to aid in carrying out a program of education and information, including being able to recruit approximately the number of producers to be reached in this application. Applications must designate an alternate individual to assume responsibility as Project Director in the event the original Project Director is unable to finish the project. Applications that will employ, or have access to, personnel who have experience in directing local educational programs that benefit agricultural producers in the respective State will receive higher rankings in this category.
Applications must provide a (1) total cost of the project; (2) cost per producer and (3) a detailed budget summary that clearly explains and justifies costs associated with the project's tasks and subtasks. Applications will receive higher scores in this category to the extent that they can demonstrate a fair and reasonable use of funds appropriate for the project and a budget that contains the estimated cost of reaching each individual producer.
Applications will be evaluated using a two-part process. First, each application will be screened by USDA and RMA personnel to ensure that it meets the requirements in this announcement. Applications that do not meet the minimum requirements of this announcement or are incomplete will not advance to the second portion of the review process. Applications that meet announcement requirements will be grouped together for comparison by the Targeted State for which the application proposes to conduct the project and will be presented to a review panel for consideration in such groups. Thus, applications will only be compared against other applications for the same Targeted State.
Second, the review panel will meet in person or via live meeting teleconference to consider and discuss the merits of each application. The panel will consist of at least three independent reviewers. Reviewers will be drawn from USDA, other Federal agencies, and/or public and private organizations, as needed. After considering the merits of all applications within a Targeted State, panel members will score each application according to the criteria and point values described above. The panel will then rank each application against
The review panel will report the results of the evaluation to the Manager of FCIC. The panel's report will include the applicants recommended to receive awards for each Targeted State. An application receiving a total score less than 60 will not receive funding.
An organization, or group of organizations in partnership, may apply for funding under other FCIC or RMA programs, in addition to the program described in this announcement. However, if the Manager of FCIC determines that an application recommended for funding under this Announcement is substantially similar to or duplicative of a project that has been funded or has been recommended to be funded under another RMA or FCIC program, then the Manager may elect to not fund that application under this program in whole or in part, depending upon the extent of the similarity or duplicity of applications. The Manager of FCIC will make the final determination on those applications that will be awarded funding.
The award document will provide pertinent instructions and information including, at a minimum, the following:
(1) Legal name and address of performing organization or institution to which the FCIC Manager has issued an award under the terms of this Request for Applications;
(2) Title of project;
(3) Name(s) and employing institution(s) of Project Directors chosen to direct and control approved activities;
(4) Identifying award number assigned by RMA;
(5) Project period, specifying the amount of time RMA intends to support the project without requiring recompeting for funds;
(6) Total amount of RMA financial assistance approved by the Manager of FCIC for the project period;
(7) Legal authority(ies) under which the award is issued;
(8) Appropriate Catalog of Federal Domestic Assistance (CFDA) number;
(9) Applicable RMA award terms and conditions);
(10) Approved budget plan for categorizing allowable project funds to accomplish the stated purpose of the award; and
(11) Other information or provisions required by RMA to carry out its respective awarding activities or to accomplish the purpose of a particular award.
Following approval by the Manager of FCIC of the applications to be selected for funding, awardees whose applications have been selected for funding will be notified. Within the limit of funds available for such a purpose, the Manager of FCIC will enter into cooperative agreements with the awardees. After a cooperative agreement has been signed by all Parties (including RMA), RMA will extend to awardees, in writing, the authority to draw down funds for the purpose of conducting the activities listed in the agreement. All funds provided to the awardee by RMA must be expended solely for the purpose for which the funds are obligated in accordance with the approved agreement and any applicable Federal law. No commitment of Federal assistance beyond the project period is made or implied for any award resulting from this notice. Notification to applicants for whom funding is denied will be sent to applicants after final funding decisions have been made and awardees have been announced publicly. Reasons for denial of funding may include, but are not limited to, incomplete applications, applications with evaluation scores below 60, or applications with evaluation scores that are lower than those of other applications in a Targeted State. Debriefings will be offered to unsuccessful applicants.
Awardees of cooperative agreements will be required to use a USDA Logo provided by RMA for all instructional and promotional materials if appropriate.
Awardees of cooperative agreements may be required to assist RMA in evaluating the effectiveness of its educational programs by notifying the RMA of upcoming training, meeting, and by providing documentation of educational activities, materials, and related information to any representative(s) selected by RMA for program evaluation purposes.
Upon written request from the applicant, scores from the evaluation panel, not including the identity of reviewers, will be sent to the applicant after the review and awards process has been completed.
The names of applicants, the names of individuals identified in the applications, the content of applications, and the panel evaluations of applications will remain confidential, except to those involved in the review process, to the extent permitted by law. In addition, the identities of review panel members will remain confidential throughout the entire review process and will not be released to applicants. At the end of the fiscal year, names of panel members may be made available. However, panelists will not be identified with the review of any particular application. When an application results in a cooperative agreement, that agreement becomes a part of the official record of RMA transactions, available to the public upon specific request. Information that the Secretary of Agriculture determines to be of a confidential, privileged, or proprietary nature will be held in confidence to the extent permitted by law. Therefore, any information that the applicant wishes to be considered confidential, privileged, or proprietary must be clearly marked within an application, including the legal basis for such designation. The original copy and extra copies of all applications, regardless of whether the application results in an award, will be retained by RMA for a period of at least three years, then may be destroyed. Any copies of an application will be released only to the extent required by law. An application may be withdrawn at any time prior to the time when award decisions are made.
Awardees of cooperative agreements may be subject to audit.
All cooperative agreements will be subject to the requirements of 7 CFR part 3015, “Uniform Federal Assistance Regulations.” A signed copy of the certification and disclosure forms must be submitted with the application and are available at the address and telephone number listed in Section VII, Agency Contact.
Departmental regulations published at 7 CFR part 3018 imposes prohibitions and requirements for disclosure and certification related to lobbying on awardees of Federal contracts, grants, cooperative partnership agreements and loans. It provides exemptions for Indian Tribes and tribal organizations. Current and prospective awardees, and any
All cooperative agreements funded as a result of this notice will be subject to the requirements contained in all applicable OMB circulars
Awardees and all partners/collaborators of all cooperative agreements funded as a result of this notice are required to know and abide by Federal civil rights laws, which include, but are not limited to, Title VI of the Civil Rights Act of 1964 (42 U.S.C. 2000d et. seq.), and 7 CFR part 15. RMA requires that awardees submit an Assurance Agreement (Civil Rights), assuring RMA of this compliance prior to the beginning of the project period. Although awardees are required to report on their civil rights compliance using demographic data among other methodologies, awardees are not required to collect demographic data directly from producers until such time as RMA has an approved form and process in place for that purpose.
RMA requires that project leaders participate in a post award teleconference, if conducted, to become fully aware of agreement requirements and for delineating the roles of RMA personnel and the procedures that will be followed in administering the agreement and will afford an opportunity for the orderly transition of agreement duties and obligations if different personnel are to assume post-award responsibility.
RMA requires that project leaders participate in a post award Civil Rights and EEO training teleconference to become fully aware of Civil Rights and EEO law and requirements.
RMA requires that awardees upload digital copies of all risk management educational materials developed as part of the project to the Ag Risk and Farm Management Library
RMA requires that awardees submit results of the project to the Ag Risk and Farm Management Library
Awardees will be required to submit quarterly progress reports using the Performance Progress Report (OMB SF–PPR) as the cover sheet and quarterly financial reports (OMB SF 425) throughout the project period, as well as a final program and financial report not later than 90 days after the end of the project period. The quarterly progress reports and final program reports MUST be submitted through the Results Verification System. The Web site address is for the Results Verification System is
Applicants and other interested parties must contact: USDA–RMA–RME, phone: 202–720–0779, email:
The Agriculture, Rural Development, Food and Drug Administration, and Related Agencies Appropriations Act, 2012 (Pub. L. 112–55) contains the restriction of the expenditure of funds to enter into financial transactions Corporations that have been convicted of felonies within the past 24 months or that have federal tax delinquencies where the agency is aware of the felonies and/or tax delinquencies.
None of the funds made available by this Act may be used to enter into a contract, memorandum of understanding, or cooperative agreement with, make a grant to, or provide a loan or loan guarantee to any corporation that was convicted (or had an officer or agency of such corporation acting on behalf of the corporation convicted) of a felony criminal violation under any Federal or State law within the preceding 24 months, where the awarding agency is aware of the conviction, unless the agency has considered suspension or debarment of the corporation, or such officer or agent, and made a determination that this further action is not necessary to protect the interest of the Government.
None of the funds made available by this Act may be used to enter into a contract, memorandum of understanding, or cooperative agreement with, make a grant to, or provide a loan or loan guarantee to, any corporation that [has] any unpaid Federal tax liability that has been assessed, for which all judicial and administrative remedies have been exhausted or have lapsed, and that is not being paid in a timely manner pursuant to an agreement with the authority responsible for collecting the tax liability, where the awarding agency is aware of the unpaid tax liability, unless the agency has considered suspension or debarment of the corporation and made a determination that this further action is not necessary to protect the interests of the Government.
Under the Federal Funding Accountability and Transparency Act of 2006, the applicant must comply with the additional requirements set forth in Attachment A regarding the Dun and Bradstreet Universal Numbering System (DUNS) Requirements and the SAM Requirements found at 2 CFR part 25. For the purposes of this RFA, the term “you” in Attachment A will mean “applicant”. The applicant will comply with the additional requirements set forth in Attachment B regarding Subawards and Executive Compensation. For the purpose of this RFA, the term “you” in Attachment B will mean “applicant”. The SAM (
Funding availability for this program may be announced at approximately the same time as funding availability for similar but separate programs—and CFDA No. 10.458 (Crop Insurance Education in Targeted States). These programs have some similarities, but also key differences. The differences stem from important features of each program's authorizing legislation and different RMA objectives. Prospective applicants should carefully examine and compare the notices for each program.
Unless you are exempted from this requirement under 2 CFR 25.110, you as the recipient must maintain the currency of your information in SAM until you submit the final financial report required under this award or receive the final payment, whichever is later. This requires that you review and update the information at least annually after the initial registration, and more frequently if required by changes in your information or another award term.
If you are authorized to make subawards under this award, you:
1. Must notify potential sub recipients that no entity (see definition in paragraph C of this award) may receive a subaward from you unless the entity has provided its DUNS number to you.
2. May not make a subaward to an entity unless the entity has provided its DUNS number to you.
C. Definitions For purposes of this award term:
1. SAM means the Federal repository into which an entity must provide information required for the conduct of business as a recipient. Additional information about registration procedures may be found at
2. Data Universal Numbering System (DUNS) number means the nine-digit number established and assigned by Dun and Bradstreet, Inc. (D & B) to uniquely identify business entities. A DUNS number may be obtained from D & B at
3. Entity, as it is used in this award term, means all of the following, as defined at 2 CFR part 25, subpart C:
a. A Governmental organization, which is a State, local government, or Indian Tribe;
b. A foreign public entity;
c. A domestic or foreign nonprofit organization;
d. A domestic or foreign for-profit organization; and
e. A Federal agency, but only as a subrecipient under an award or subaward to a non-Federal entity.
4. Subaward:
a. This term means a legal instrument to provide support for the performance of any portion of the substantive project or program for which you received this award and that you as the recipient award to an eligible subrecipient.
b. The term does not include your procurement of property and services needed to carry out the project or program (for further explanation, OMB Circular A–I33, “Audits of States, Local Governments, and Non-Profit Organizations”).
c. A subaward may be provided through any legal agreement, including an agreement that you consider a contract.
5. Subrecipient means an entity that:
a. Receives a subaward from you under this award; and
b. Is accountable to you for the use of the Federal funds provided by the subaward.
a. Reporting of first-tier subawards.
1. Applicability. Unless you are exempt as provided in paragraph d. of this award term, you must report each action that obligates $25,000 or more in Federal funds that does not include Recovery funds (as defined in section 1512(a)(2) of the American Recovery and Reinvestment Act of 2009 (Pub.L. 111–5) for a subaward to an entity (see definitions in paragraph e. of this award term).
2. Where and when to report.
i. You must report each obligating action described in paragraph a.I. of this award term to
ii. For subaward information, report no later than the end of the month following the month in which the obligation was made. (For example, if the obligation was made on November 7, 2010, the obligation must be reported by no later than December 31, 2010.)
3. What to report. You must report the information about each obligating action that the submission instructions posted at
b. Reporting Total Compensation of Recipient Executives.
1. Applicability and what to report. You must report total compensation for each of your five most highly compensated executives for the preceding completed fiscal year, if—
i. The total Federal funding authorized to date under this award is $25,000 or more;
ii. In the preceding fiscal year, you received-
(A) 80 percent or more of your annual gross revenues from Federal procurement contracts (and subcontracts) and Federal financial assistance subject to the Transparency Act, as defined at 2 CFR 170.320 (and subawards); and
(B) $25,000,000 or more in annual gross revenues from Federal procurement contracts (and subcontracts) and Federal financial assistance subject to the Transparency Act, as defined at 2 CFR 170.320 (and subawards); and
iii. The public does not have access to information about the compensation of the executives through periodic reports filed under section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a), 780(d)) or section 6104 of the Internal Revenue Code of 1986. (To determine if the public has access to the compensation information, see the U.S. Security and Exchange Commission total compensation filings at
2. Where and when to report. You must report executive total compensation described in paragraph b.1. of this award term:
i. As part of your registration profile at
ii. By the end of the month following the month in which this award is made, and annually thereafter.
c. Reporting of Total Compensation of Subrecipient Executives.
1. Applicability and what to report. Unless you are exempt as provided in paragraph d. of this award term, for each first-tier subrecipient under this award, you will report the names and total compensation of each of the subrecipient's five most highly compensated executives for the
i. in the subrecipient's preceding fiscal year, the subrecipient received-
(A) 80 percent or more of its annual gross revenues from Federal procurement contracts (and subcontracts) and Federal financial assistance subject to the Transparency Act, as defined at ~ CFR 170.320 (and subawards); and
(B) $25,000,000 or more in annual gross revenues from Federal procurement contracts (and subcontracts), and Federal financial assistance subject to the Transparency Act (and subawards); and
ii. The public does not have access to information about the compensation of the executives through periodic reports filed under section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a), 780(d) or section 6104 of the Internal Revenue Code of 1986. (To determine if the public has access to the compensation information, see the U.S. Security and Exchange Commission total compensation filings at
2. Where and when to report. You must report subrecipient executive total compensation described in paragraph c.1. of this award term:
i. To the recipient.
ii. By the end of the month following the month during which you make the subaward. For example, if a subaward is obligated on any date during the month of October of a given year (i.e., between October 1 and 31), you must report any required compensation information of the subrecipient by November 30 of that year.
d. Exemptions
If, in the previous tax year, you had gross income, from all sources, under $300,000, you are exempt from the requirements to report:
i. Subawards, and
ii. The total compensation of the five most highly compensated executives of any sub recipient.
e. Definitions. For purposes of this award term:
1. Entity means all of the following, as defined in 2 CFR part 25:
i. A Governmental organization, which is a State, local government, or Indian tribe;
ii. A foreign public entity;
iii. A domestic or foreign nonprofit organization;
iv. A domestic or foreign for-profit organization;
v. A Federal agency, but only as a subrecipient under an award or subaward to a non-Federal entity.
2. Executive means officers, managing partners, or any other employees in management positions.
3. Subaward:
1. This term means a legal instrument to provide support for the performance of any portion of the substantive project or program for which you received this award and that you as the recipient award to an eligible subrecipient.
ii. The term does not include your procurement of property and services needed to carry out the project or program (for further explanation, see OMB Circular A–133, “Audits of States, Local Governments, and Non-Profit Organizations”).
iii. A subaward may be provided through any legal agreement, including an agreement that you or a subrecipient considers a contract.
4. Subrecipient means an entity that:
i. Receives a sub award from you (the recipient) under this award; and
ii. Is accountable to you for the use of the Federal funds provided by the subaward.
5. Total compensation means the cash and noncash dollar value earned by the executive during the recipient's or subrecipient's preceding fiscal year and includes the following (for more information see 17 CFR 229.402(c)(2):
i. Salary and bonus.
ii. Awards of stock, stock options, and stock appreciation rights. Use the dollar amount recognized for financial statement reporting purposes with respect to the fiscal year in accordance with the Statement of Financial Accounting Standards No. 123 (Revised 2004) (FAS 123R), Shared Based Payments.
iii. Earnings for services under non-equity incentive plans. This does not include group life, health, hospitalization or medical reimbursement plans that do not discriminate in favor of executives, and are available generally to all salaried employees.
iv. Change in pension value. This is the change in present value of defined benefit and actuarial pension plans.
v. Above-market earnings on deferred compensation which is not tax-qualified.
vi. Other compensation, if the aggregate value of all such other compensation (e.g. severance, termination payments, value of life insurance paid on behalf of the employee, perquisites or property) for the executive exceeds $10,000.
National Institute of Food and Agriculture, USDA.
Notice and request for comments.
In accordance with the Paperwork Reduction Act of 1995 and Office of Management and Budget (OMB) regulations (5 CFR part 1320) which implement the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35), this notice announces the intention of the National Institute of Food and Agriculture (NIFA) to request approval to revise and extend a currently approved information collection for the 4–H Youth Enrollment Report.
Written comments on this notice must be received by August 12, 2013 to be assured of consideration. Comments received after this date will be considered to the extent practicable.
Written comments concerning this notice and requests for copies of the information collection may be submitted by any of the following methods to Jason Hitchcock, Director, Information Policy, Planning and Training; Mail: NIFA/USDA, Mail Stop 2216, 1400 Independence Avenue SW., Washington, DC 20250–2216; Hand Delivery/Courier: 800 9th Street SW., Waterfront Centre, Room 4217, Washington, DC 20024; or Email:
Jason Hitchcock, Director of Information Policy, Planning, and Training; Information Systems and Technology Management; NIFA/USDA; Email:
The 1914 Smith-Lever Act created the Cooperative Extension System (CES) of the Land-Grant Institutions and their Federal partner, the Extension Service, now NIFA, USDA. 4–H was already well-established and became the first operating part of the new extension work. The Smith-Lever Act stipulated that “It shall be the duty of said colleges, annually, on or about the first day of January, to make to the Governor of the State in which it is located a full and detailed report of its operations in extension work as defined in this Act . . . a copy of which report shall be sent to the Secretary of Agriculture.” As a result of this requirement, the state 4–H office submits an electronic aggregated summary of their 4–H enrollment.
Information collected in the 4–H Youth Enrollment Report by the state 4–H offices includes the youth enrollment totals, by delivery mode, by type of 4–H activity, by school grade, by gender, by place of residence, by race and ethnicity as well as youth and adult volunteer totals. The NIFA information collection is being revised to include the youth and adult volunteer totals by gender, as well as race and ethnicity.
Need for the Information: The Annual 4–H Enrollment Report is the principal means by which NIFA tracks 4–H member and volunteer enrollments, as well as identifies trends that can indicate emerging needs, potential problems, and opportunities.
Information obtained from this report, as requested by the Congress or the Administration, is used to estimate rural versus urban outreach, enrollment by race, youth participation in leadership, community service, etc. In addition, it is used to estimate market share, percentage of the youth of each state by age and place of residence, and those who are enrolled in the 4–H youth development program. The annual 4–H Youth Enrollment Report also allows oversight of all reasonable efforts by staff and volunteers to reach underserved and minority groups. New information collected will allow NIFA to address civil rights related requests. Information also is available at
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All responses to this notice will be summarized and included in the request to OMB for approval. All comments will become a matter of public record.
National Institute of Food and Agriculture, USDA.
Notice and request for comments.
In accordance with the Paperwork Reduction Act of 1995 and Office of Management and Budget (OMB) regulations, that implement the Paperwork Reduction Act of 1995, this notice announces the National Institute of Food and Agriculture's (NIFA) intention to request approval to establish a new information collection for the REEport system.
Written comments on this notice must be received by August 12, 2013, to be assured of consideration. Comments received after that date will be considered to the extent practicable.
Written comments may be submitted by any of the following methods: Email:
Robert Martin, Records Officer; Email:
NIFA plans to deploy REEport as NIFA's singular non-formula (including competitive grants) and formula grant project reporting system, building on and replacing the existing Current Research Information System (CRIS) Web forms system (OMB Control Number: 0524–0042). REEport will be NIFA's new documentation and data collection system for project initiation and progress reporting and constitutes a necessary information collection for NIFA-supported projects as set forth in requirements established in 7 CFR Parts 3400 through 3430 pertaining to the aforementioned authorities. The transition from CRIS to REEport and this new information collection in support of it are necessary in order to provide descriptive information regarding individual research, education, extension, and integrated activities and to document expenditures and staff support, as well as monitor the progress and impact of such activities.
Out of an initiative of the Research Business Models (RBM) Subcommittee of the Committee on Science (CoS), a committee of the National Science and Technology Council (NSTC), came the Research Performance Progress Report (RPPR). The RPPR is a new uniform format for reporting performance progress on Federally-funded research projects. Upon implementation, the RPPR will be used by agencies that support research and research-related activities for use in submission of interim progress reports. It is intended to replace other interim performance reporting formats currently in use by agencies. In anticipation of the RPPR's implementation, NIFA based REEport's Progress Report format on the RPPR.
As part of REEport's implementation, NIFA intends to transfer existing data in CRIS to REEport and then terminate the applicable components of CRIS. For the existing projects that reported to CRIS, the awardees will then report to REEport. REEport will better address NIFA accountability and reporting needs by supporting limited use of program-specific data fields and the ability to upload documents such as portable document files (PDF) into reports. REEport will allow Hatch and Evans-Allen projects to be linked to planned programs in the Agricultural, Research, Extension and Education Reform Act of 1998 (AREERA) Plan of Work Information System, which will simplify the preparation of State Annual Reports. Each Hatch and Evans-Allen project in REEport will choose which Planned Program it is a part of in the Plan of Work. Once this link is made, expenditures, Full-Time Equivalents (FTEs), and possibly Knowledge Area Classifications can then be rolled up into the Plan of Work system, thus eliminating points of double reporting and eliminating discrepancies between the two systems.
Additionally, deployment of REEport will facilitate the transition to the Research, Education, and Economics Information System (REEIS) as the primary source of information on the research, education, and extension programs, projects and activities of USDA and its partner institutions currently hosted by the CRIS system, including REEIS' Leadership Management Dashboard.
REEport implementation includes:
• Formula and Non-formula new project initiation; and
• Expenditure, progress, and termination reports for all new and existing projects (data transferred from CRIS)
Further information about REEport deployment can be found on
The information provided through REEport will help users (grantees, grantee institutions and NIFA) to keep abreast of the latest developments in agricultural, food science, human nutrition and forestry research and education; track resource utilization in specific target areas of work; plan for future activities; plan for resource allocation to research, education, and extension programs; avoid costly duplication of effort; aid in coordination of efforts addressing similar problems in different locations; and aid research, education, and extension workers in establishing valuable contacts within the agricultural community.
All responses to this notice will be summarized and included in the request to OMB for approval. All comments will become a matter of public record.
The County of Monroe, New York, grantee of FTZ 141, submitted a notification of proposed production activity to the FTZ Board on behalf of John D. Brush & Co., dba Sentry Group (Sentry), located in Pittsford and East Rochester, New York. The notification conforming to the requirements of the regulations of the FTZ Board (15 CFR 400.22) was received on May 30, 2013.
The Sentry facility is located within Subzone 141F. The facility is used for the manufacturing and warehousing of fire resistant safes and secured storage devices. Pursuant to 15 CFR 400.14(b), FTZ activity would be limited to the specific foreign-status materials and components and specific finished products described in the submitted notification (as described below) and subsequently authorized by the FTZ Board.
Production under FTZ procedures could exempt Sentry from customs duty payments on the foreign status components used in export production. On its domestic sales, Sentry would be able to choose the duty rates during customs entry procedures that apply to fire proof safes made of steel, fire and water resistant storage chests, gun safes, security safes, portable security safes, cash boxes, key boxes, safe boxes, drawer safes, depository safes and commercial safes (duty rate ranges from free to 3.8%) for the foreign status inputs noted below. Customs duties also could possibly be deferred or reduced on foreign status production equipment.
The components and materials sourced from abroad include: Interior lights, drawer slides, cap plugs, battery holders, replacement module kits, face plates, touchpads, plastic gun racks, keypad assemblies, panel lock assemblies, door backs, plastic trays, drawers, shelves, battery drawer assemblies, chrome bezels, locks, padlock assemblies, keys, battery packs, electronic lock assemblies, actuator boards, lock solenoids, diecast dial assemblies, metal dial assemblies, wood gun shelf racks, cable assemblies, communication cables, gasket kits, door springs, metal handles, handle assemblies, bungee cords, replacement keys, battery covers, key lock covers, steel screws and bolt down kits (duty rate ranges from 1.5 to 12.5%).
Public comment is invited from interested parties. Submissions shall be addressed to the Board's Executive Secretary at the address below. The closing period for their receipt is July 17, 2013.
A copy of the notification will be available for public inspection at the Office of the Executive Secretary, Foreign-Trade Zones Board, Room 21013, U.S. Department of Commerce, 1401 Constitution Avenue NW., Washington, DC 20230–0002, and in the “Reading Room” section of the Board's Web site, which is accessible via
Elizabeth Whiteman at
Import Administration, International Trade Administration, Department of Commerce.
The Department of Commerce (the Department) is conducting an administrative review of the antidumping duty order on certain circular welded carbon steel pipes and tubes from Taiwan. The period of review (POR) is May 1, 2011, through April 30, 2012, and the review covers Shin Yang Steel Co., Ltd. (Shin Yang), a producer and exporter of subject merchandise. We have preliminarily found that sales of the subject merchandise were made at prices below normal value, and that Shin Yang is the successor-in-interest to Yieh Phui Enterprise Co, Ltd. (Yieh Phui).
As of June 7, 2013.
Steve Bezirganian or Robert James, AD/CVD Operations, Office 7, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington DC 20230; telephone: (202) 482–1131 or (202) 482–0649, respectively.
The merchandise subject to the order is certain circular welded carbon steel pipes and tubes from Taiwan. The product is currently classified under the Harmonized Tariff Schedule of the United States (HTSUS) item numbers 7306.30.5025, 7306.30.5032, 7306.30.5040, and 7306.30.5055. Although the HTSUS numbers are provided for convenience and customs purposes, the written product description remains dispositive.
For a full description of the methodology underlying our conclusions, please see the Preliminary Decision Memorandum.
In response to questionnaires issued in the current review, Shin Yang
Based on the Department's analysis of the information submitted by Shin Yang, the Department preliminarily determines Shin Yang is the successor-in-interest to Yieh Phui. For more details, see the Preliminary Decision Memorandum.
The Department has conducted this review in accordance with section 751(a)(2) of the Tariff Act of 1930, as amended (the Act). Export Price is calculated in accordance with section 772 of the Act. Normal value is calculated in accordance with section 773 of the Act. For a full description of the methodology underlying our conclusions, please see the Preliminary Decision Memorandum.
As a result of this review, we preliminarily determine that a weighted-average dumping margin of 8.90 percent exists for Shin Yang for the POR.
The Department intends to disclose to interested parties the calculations performed in connection with these preliminary results within five days of the date of publication of this notice.
Pursuant to 19 CFR 351.310(c), interested parties who wish to request a hearing, or to participate if one is requested, must submit a written request to the Assistant Secretary for Import Administration, filed electronically via IA ACCESS. An electronically filed document must be received successfully in its entirety by the Department's electronic records system IA ACCESS, by 5 p.m. Eastern Standard Time within 30 days after the date of publication of this notice.
Upon completion of the administrative review, pursuant to 19 CFR 351.212(b), the Department will calculate an assessment rate on all appropriate entries. The Department intends to issue appropriate appraisement instructions for the company subject to this review directly to U.S. Customs and Border Protection (CBP) 15 days after the date of publication of the final results of this review.
If the weighted-average dumping margin for Shin Yang is not zero or
The Department clarified its automatic assessment regulation on May 6, 2003.
The following cash deposit requirements for estimated antidumping duties will be effective upon publication of the notice of final results of administrative review for all shipments of certain circular welded carbon steel pipes and tubes from Taiwan entered, or withdrawn from warehouse, for consumption on or after the date of publication as provided by section 751(a)(2) of the Act: (1) The cash deposit for Shin Yang will be equal to the weighted-average dumping margin established in the final results of this administrative review; (2) for merchandise exported by manufacturers or exporters not covered in this review but covered in a prior segment of the proceeding, the cash deposit rate will continue to be the company-specific rate published for the most recently completed segment of this proceeding in which that manufacturer or exporter participated; (3) if the exporter (now including Yieh Phui) is not a firm covered in this review, a prior review, or the original investigation but the manufacturer is, the cash deposit rate will be the rate established for the most recently completed segment of this proceeding in which that manufacturer or exporter participated; and (4) the cash deposit rate for all other manufacturers or exporters (now including Yieh Phui) will continue to be 9.70 percent, the all-others rate referenced in
This notice also serves as a preliminary 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 Secretary's presumption that reimbursement of antidumping duties occurred and the subsequent assessment of double antidumping duties.
This notice also serves as a preliminary reminder to parties subject to administrative protective order (APO) of their responsibility concerning the disposition of proprietary information disclosed under APO in accordance with 19 CFR 351.305(a)(3). Timely written notification of the return or destruction of APO materials, or conversion to judicial protective order, is hereby requested. Failure to comply with the regulations and the terms of an APO is a sanctionable violation.
We are issuing and publishing these results in accordance with sections 751(a)(1) and 777(i)(1) of the Act.
Import Administration, International Trade Administration, Department of Commerce.
On February 1, 2013, the Department of Commerce (Department) published the preliminary results of the administrative review of the antidumping duty order on stainless steel bar from India (
As of June 7, 2013.
Joseph Shuler or Yasmin Nair, AD/CVD Operations, Office 1, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington DC 20230; telephone (202) 482–1293, or (202) 482–3813, respectively.
The merchandise subject to the order is stainless steel bar. The stainless steel bar subject to the order is currently classifiable under subheadings 7222.10.00, 7222.11.00, 7222.19.00, 7222.20.00, 7222.30.00 of the Harmonized Tariff Schedule (HTS). The HTS subheadings are provided for convenience and customs purposes. For a full description of the scope of the order,
All issues raised in the case briefs are addressed in the Final IDM, dated concurrently and hereby adopted by this notice. A list of the issues which parties raised and to which we responded in the Final IDM is attached to this notice as an Appendix. The Final IDM is a public document and is on file electronically via Import Administration's Antidumping and Countervailing Duty Centralized Electronic Service System (IA ACCESS). IA ACCESS is available to registered users at
Based on our analysis of the comments received since the
We determine that the following weighted-average dumping margin exists for Ambica for the period February 1, 2011, through January 31, 2012.
Pursuant to 19 CFR 351.224(b), we intend to disclose calculation memoranda used in our analysis to parties to these proceedings within five days of the date of publication of this notice.
Pursuant to section 751(a)(2)(A) of the Tariff Act of 1930, as amended (the Act), and 19 CFR 351.212(b), the Department will determine, and U.S. Customs and Border Protection (CBP) shall assess, antidumping duties on all appropriate entries of subject merchandise in accordance with the final results of this review. The Department intends to issue assessment instructions to CBP 15 days after the date of publication of these final results of review.
In accordance with the
The Department clarified its “automatic assessment” regulation on May 6, 2003.
The following deposit rates will be effective upon publication of the final results of this administrative review for all shipments of stainless steel bar from India entered, or withdrawn from warehouse, for consumption on or after the publication date, as provided by section 751(a)(2)(C) of the Act: (1) For the company covered by this review, the cash deposit rate will be zero; (2) for previously reviewed or investigated companies not listed above, the cash deposit rate will continue to be the company-specific rate published for the most recent final results in which that manufacturer or exporter participated; (3) if the exporter is not a firm covered in this review, a prior review, or the original LTFV investigation, but the producer is, the cash deposit rate will be the rate established for the most recent final results for the manufacturer of the merchandise; and (4) if neither the exporter nor the producer is a firm covered in this or any previous review conducted by the Department, the cash deposit rate will be 12.45 percent, the “all others” rate established in the LTFV investigation.
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 Department's presumption that reimbursement of antidumping duties occurred and the subsequent assessment of double antidumping duties.
This notice serves as the only reminder to parties subject to administrative protective order (APO) of their responsibility concerning the disposition of proprietary information disclosed under APO in accordance with 19 CFR 351.305(a)(3). Timely written notification of return/destruction of APO materials or conversion to judicial protective order is hereby requested. Failure to comply with the regulations and the terms of an APO is a sanctionable violation.
These final results of review are issued and published in accordance with sections 751(a)(1) and 777(i)(1) of the Act.
Import Administration, International Trade Administration, Department of Commerce.
The Department of Commerce (the Department) is conducting an administrative review of the antidumping duty order on citric acid and certain citrate salts (citric acid) from Canada. The period of review (POR) is May 1, 2011, through April 30, 2012. The review covers one producer and exporter of the subject merchandise, Jungbunzlauer Canada Inc. (JBL Canada). We have preliminarily determined that sales of subject merchandise have been made at prices below normal value (NV) by JBL Canada.
As of June 7, 2013.
Rebecca Trainor or Katherine Johnson, AD/CVD Operations, Office 2, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone (202) 482–4007 or (202) 482–4929, respectively.
The merchandise covered by this order is citric acid and certain citrate salts. The product is currently classified in the Harmonized Tariff Schedule of the United States (HTSUS) at item numbers 2918.14.0000 and 2918.15.1000, 2918.15.5000 and 3824.90.9290. Although the HTSUS numbers are provided for convenience and customs purposes, the full written scope description, as published in the antidumping duty order
The Department has conducted this review in accordance with section 751(a)(2) of the Tariff Act of 1930, as amended (the Act). Constructed export price (CEP) is calculated in accordance with section 772 of the Act. NV is calculated in accordance with section 773 of the Act. To determine the appropriate comparison method, the Department applied a “differential pricing” analysis and has preliminarily determined to use a combination of the average-to-average method and the average-to-transaction method in making comparisons of CEP and NV for
As a result of this review, we preliminarily determine that a dumping margin of 1.20 percent exists for JBL Canada for the period May 1, 2011, through April 30, 2012.
The Department will disclose to parties the calculations performed in connection with these preliminary results within five days of the date of publication of this notice.
Interested parties who wish to request a hearing, or to participate if one is requested, must submit a written request to the Assistant Secretary for Import Administration, filed electronically via IA ACCESS.
Upon completion of the administrative review, the Department shall determine, and U.S. Customs and Border Protection (CBP) shall assess, antidumping duties on all appropriate entries, in accordance with 19 CFR 351.212(b)(1). We intend to issue instructions to CBP 41 days after the date of publication of the final results of this review.
Although JBL Canada reported entered value for its U.S. sales, based on verification findings, we have determined it is appropriate to calculate importer-specific per-unit duty assessment rates.
We will instruct CBP to assess antidumping duties on all appropriate entries covered by this review if any importer-specific assessment rate calculated in the final results of this review is above
The final results of this review shall be the basis for the assessment of antidumping duties on entries of merchandise covered by the final results of this review and for future deposits of estimated duties, where applicable.
The Department clarified its “automatic assessment” regulation on May 6, 2003. This clarification will apply to entries of subject merchandise during the POR produced by JBL Canada for which it did not know its merchandise was destined for the United States. In such instances, we will instruct CBP to liquidate unreviewed entries at the all-others rate if there is no rate for the intermediate company(ies) involved in the transaction. For a full discussion of this clarification,
The following deposit requirements will be effective for all shipments of the subject merchandise entered, or withdrawn from warehouse, for consumption on or after the publication date of the final results of this administrative review, as provided by section 751(a)(2)(C) of the Act: 1) the cash deposit rate for JBL Canada will be the rate established in the final results of this review, except if the rate is less than 0.50 percent and, therefore,
This notice also serves as a preliminary 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 Secretary's presumption that reimbursement of antidumping duties occurred and the subsequent assessment of double antidumping duties.
We are issuing and publishing these results in accordance with sections 751(a)(1) and 777(i)(1) of the Act and 19 CFR 351.221(b)(4).
Import Administration, International Trade Administration, U.S. Department of Commerce.
In response to a request by interested parties,
As of June 7, 2013.
Fred Baker, Victoria Cho, or Robert James at (202) 482–2924, (202) 482–5075, or (202) 482–0649, respectively; AD/CVD Operations, Office 7, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230.
The merchandise subject to the order is welded pipe and tube. The welded pipe and tube subject to the order is currently classifiable under subheading 7306.30.10.00, 7306.30.50.25, 7306.30.50.32, 7306.30.50.40, 7306.30.50.55, 7306.30.50.85, and 7306.30.50.90 of the Harmonized Tariff Schedule of the United States (HTSUS). The HTSUS subheading is provided for convenience and customs purposes. A full description of the scope of the order is contained in the memorandum from Christian Marsh, Deputy Assistant Secretary for Antidumping and Countervailing Duty Operations, to Ronald K. Lorentzen, Acting Assistant Secretary for Import Administration, “Decision Memorandum for Preliminary Results of Antidumping Duty Administrative Review: Welded Carbon Steel Standard Pipe and Tube Products from Turkey; 2011–2012 Administrative Review” (Preliminary Decision Memorandum), which is hereby adopted by this notice. The written description is dispositive.
The Preliminary Decision Memorandum is a public document and is on file electronically via Import Administration's Antidumping and Countervailing Duty Centralized Electronic Service System (IA ACCESS). Access to IA ACCESS is available to registered users at
The Department has conducted this review in accordance with section 751(a)(2) of the Tariff Act of 1930, as amended (the Act). Export price is calculated in accordance with section 772 of the Act. Normal value (NV) is calculated in accordance with section 773 of the Act.
To determine the appropriate comparison method, the Department applied a “differential pricing” analysis and has preliminarily determined to use the average-to-transaction method in making comparisons of export price and normal value for Borusan and the average-to-average method in making comparisons of export price and normal value for Erbosan.
For a full description of the methodology underlying our conclusions, see the Preliminary Decision Memorandum.
Toscelik and Yucel, in letters dated August 20, 2012, reported that they made no shipments, entries or sales of subject merchandise during the POR. On September 24, 2012, the Department issued a “No Shipment Inquiry” to U.S. Customs and Border Protection (CBP) to confirm that there were no entries of welded pipe and tube from Turkey exported by Toscelik or Yucel during the POR. In addition, we obtained other documentation from CBP to evaluate the
Based on the certification of Toscelik and Yucel and our analysis of CBP information, we preliminarily determine that Toscelik and Yucel had no shipments during the POR.
However, consistent with our practice, the Department finds that it is not appropriate to rescind the review with respect to Toscelik and Yucel, but rather to complete the review with respect to Toscelik and Yucel and issue appropriate instructions to CBP based on the final results of this review.
As a result of this review, we preliminarily determine that the weighted-average dumping margins for the period May 1, 2011, through April 30, 2012, are as follows:
The Department will disclose to interested parties the calculations performed in connection with these preliminary results within five days of the date of publication of this notice.
Pursuant to 19 CFR 351.310(c), interested parties who wish to request a hearing, or to participate if one is requested, must submit a written request to the Assistant Secretary for Import Administration, filed electronically via IA ACCESS. The Department's electronic records system, IA ACCESS, must successfully receive an electronically-filed document in its entirety by 5 p.m. Eastern Daylight Time within 30 days after the date of publication of this notice.
Upon completion of the administrative review, the Department shall determine, and CBP shall assess, antidumping duties on all appropriate entries in accordance with 19 CFR 351.212(b)(1). We intend to issue instructions to CBP 15 days after the date of publication of the final results of this review.
If Borusan's or Erbosan's weighted-average dumping margins are not zero or
The Department clarified its “automatic assessment” regulation on May 6, 2003.
The following cash deposit requirements will be effective for all shipments of the subject merchandise entered, or withdrawn from warehouse, for consumption on or after the publication date of the final results of this administrative review, as provided by section 751(a)(2)(C) of the Act: (1) The cash deposit rate for Borusan and Erbosan will be equal to the weighted-average dumping margin established in the final results of this review, except if the rate is
This notice also serves as a preliminary 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 Secretary's presumption that reimbursement of antidumping duties
We are issuing and publishing these results in accordance with sections 751(a)(1) and 777(i)(1) of the Act.
Import Administration, International Trade Administration, Department of Commerce.
On December 11, 2012, the Department of Commerce (the Department) published the preliminary results of the administrative review of the antidumping duty order on certain circular welded non-alloy steel pipe from Mexico.
As of June 7, 2013.
Mark Flessner or Robert James, AD/CVD Operations, Office 7, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone: (202) 482–6312 and (202) 482–0649, respectively.
On December 11, 2012, the Department published in the
In response to the Department's invitation to comment on the
The products covered by this order are circular welded non-alloy steel pipes and tubes, of circular cross-section, not more than 406.4 millimeters (16 inches) in outside diameter, regardless of wall thickness, surface finish (black, galvanized, or painted), or end finish (plain end, beveled end, threaded, or threaded and coupled).
All issues raised in the case brief and the rebuttal brief are addressed in the Issues and Decision Memorandum (Decision Memorandum) from Christian Marsh, Deputy Assistant Secretary for Antidumping and Countervailing Duty Operations, to Ronald K. Lorentzen, Acting Assistant Secretary for Import Administration, dated May 30, 2013, which is hereby adopted by this notice. A list of the issues raised is attached to this notice as Appendix I. The Decision Memorandum is a public document and is on file electronically via Import Administration's Antidumping and Countervailing Duty Centralized Electronic Service System (IA ACCESS). Access to IA ACCESS is available to registered users at
As stated in the
As stated above, the request for administrative review of Ternium, which had been selected as a mandatory respondent, was timely withdrawn.
The companies for which administrative reviews were requested and not rescinded (
TUNA and its successor in interest,
Mueller submitted a “no shipments” letter on April 9, 2013. An inquiry was made to CBP to confirm that no shipments by Mueller were recorded at the ports during the POR. No record evidence contradicts the assertion of Mueller that it made no shipments of subject merchandise into the United States. Therefore, we find that Mueller did not make shipments of subject merchandise into the United States during this POR.
Conduit also submitted a claim that “it did not have any exports, sales, or entries of the subject merchandise to the United States” during the POR on April 9, 2013. An inquiry was made to CBP to confirm that no reviewable sales by Conduit were recorded at the ports during the POR. No record evidence contradicts the assertion of Conduit that it made no reviewable sales of subject merchandise into the United States. Therefore, we find that Conduit did not make reviewable sales of subject merchandise into the United States during this POR.
As stated above, all of the requests for administrative review with respect to Galvak, HYLSA, IMSA, Southland, and Ternium were timely withdrawn; the administrative reviews with respect to these five companies were preliminarily rescinded.
The Department will determine, and U.S. Customs and Border Protection (CBP) shall assess, antidumping duties on all appropriate entries, pursuant to section 751(a)(1) of the Act and 19 CFR 351.212(b). We will issue appraisement instructions directly to CBP to assess antidumping duties on appropriate entries by applying the assessment rate to the entered value of the merchandise. Pursuant to 19 CFR 356.8(a), the Department intends to issue assessment instructions to CBP 41 days after the date of publication of these final results of review.
The Department clarified its “automatic assessment” regulation on May 6, 2003.
For PYTCO's no-sale entry, subject merchandise that is entered for consumption but is not sold either in the form as entered or as further manufactured merchandise to an unaffiliated customer in the United States is not subject to antidumping duties because there is no U.S. sale, and, therefore, no dumping in the United States.
For all entries by TUNA, Lamina y Placa, Mueller, and Conduit, we will instruct CBP to assess antidumping duties in accordance with the reseller policy.
The following cash deposit requirements will be effective upon publication of these final results for all shipments of the subject merchandise entered, or withdrawn from warehouse, for consumption, on or after the publication date of these final results of administrative review, consistent with section 751(a)(2)(C) of the Act: (1) The cash deposit rate for the reviewed companies will continue to be the company-specific rates published for the most recently completed segment in which the company participated; (2) for merchandise exported by producers or exporters not covered in this review, but covered in a previous segment of this proceeding, the cash deposit rate will continue to be the company-specific rate published for the most recently completed segment of this proceeding in which that manufacturer or exporter participated; (3) if the exporter is not a firm covered in a prior segment of this proceeding, but the manufacturer is, then the cash deposit rate will be the rate established for the most recently completed segment of this proceeding for the manufacturer of the subject merchandise; and (4) the cash deposit rate for all other manufacturers or exporters will continue to be 32.62 percent, the all-others rate established in the original antidumping investigation.
This notice also 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 Department's presumption that reimbursement of the antidumping duties occurred and the subsequent assessment of doubled antidumping duties.
This notice also serves as a reminder to parties subject to administrative protective orders (APOs) of their responsibility concerning the disposition of proprietary information disclosed under APO in accordance with 19 CFR 351.305, 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 the terms of an APO is a sanctionable violation.
This notice is issued and published in accordance with sections 751(a)(1) and 777(i)(1) of the Tariff Act of 1930, as amended.
International Trade Administration, Department of Commerce.
Notice.
The United States Department of Commerce, International Trade Administration, U.S. & Foreign Commercial Service, is organizing a Trade Mission to Taiwan, Japan, and Korea March 10 –14, 2014. The purpose of the mission is to help U.S. firms in the travel and tourism industry find business partners and sell services in Taipei, Taiwan; Seoul, Korea; and Tokyo, Japan. The targeted sector for participation in this mission is travel and tourism, including U.S.-based travel and tourism suppliers, destination marketing organizations (i.e., convention and visitors bureaus), travel promotion organizations and other travel and tourism entities promoting and selling travel to the United States including trade associations.
Each year, roughly 41% of Taiwan's 23 million people travel abroad and an estimated 300,000 traveled to the United States in 2012. The forecast is that nearly 400,000 visitors from Taiwan (a 25% increase) will travel to the United States annually by 2015 as a result of Taiwan's entry into the U.S. Visa Waiver Program on November 1, 2012. Taiwan is the only economy to receive visa-free status in the last three years, and it is an exciting time to promote U.S. travel destinations given the pent-up demand for travel to the United States from Taiwan.
On average, a Taiwan visitor to the United States spends about $4,000 per trip. This number translates to over $1.1 billion yearly in travel and tourism spending by Taiwan outbound travelers to the United States. Taiwanese enjoy shopping, dining out, sightseeing in cities, experiencing amusement and theme parks, and visiting historic places.
For Taiwan nationals, outbound travel is both a vital part of doing business in this trade-oriented economy and a trendy form of leisure holidays. Taiwan's GDP per capita is one of the highest in Asia at approximately $20,400, which means that an increasing share of the population has the means to seek and enjoy leisure travel abroad. In the capital city, Taipei, it rains about 180 days each year, and Taiwan travelers are always searching for sunny and dry destinations for their holiday adventures. Taiwan is also the sixth-largest source of international students for the United States, many of whom have friends and family visiting them regularly and enjoying U.S. destinations and attractions.
The United States is among the top five destinations for Taiwan outbound travelers, and is the top non-Asian and long-haul destination. Despite its popularity with Taiwan outbound travelers, the United States faces strong competition from other destinations that also don't require a visa, such as Australia, China, Japan, Thailand and European Union countries.
In 2012, over 13.7 million Koreans, roughly one fourth of the population, traveled abroad and over one million traveled to the United States. It is estimated that by 2014 nearly 1.5 million Koreans (a 23% increase) will travel to the United States annually. On average, a Korean visitor to the United States spends approximately $3,500 per trip. This will translate to over $5 billion in tourism spending by Korean outbound travelers to the United States in 2014.
Korea's remarkable economic growth over the past 30 years has transformed the country, moving it from the ranks of developing nations to exclusive membership among the world's most developed and richest economies. In 2012 Korea enjoyed a 2.1% increase in GDP, which now totals $1.14 trillion. Korea's per capita GDP in 1963 was just $100. Today, it exceeds $32,400. Increased income has given Koreans the means to seek and enjoy leisure travel abroad. Industry experts expect that the number of outbound travelers will continue to increase for the next five years and that demand for sophisticated and niche market travel, such as for meetings, conventions and exhibitions; cruises and edu-tourism will grow significantly.
The United States remains one of the top five destinations for both Taiwan and Korean outbound travelers, and is the top non-Asian and long-haul destination for both countries. Despite its popularity with Taiwan and Korean outbound travelers, the United States faces strong competition from aggressive marketing from other destinations that also don't require a visa, such as Australia, China, Japan, Thailand and the European Union.
Japan remains the world's third-largest economy, after the United States and China, with a GDP of roughly $5.8 trillion. Japan is the fourth largest export market for U.S. goods and services, and was our fourth largest trading partner overall in 2012.
Japan is a major source of travel to the United States, providing substantial economic benefits. An estimated 3.7 million Japanese visited the United States in 2012, ranking Japan 4th in number of travelers to the United States. Japan ranked second behind Canada, however, in the amount of total spending by travelers in the United States in 2012—close to $15 billion.
The number of Japanese outbound travelers in 2012 was 18.5 million, an increase of 8.8 percent over the previous year. This is the highest in Japanese history. As of November 2012, 3.4 million Japanese visitors had traveled to the United States, a 14-percent increase over the same period last year. CS Japan projects that Japan should finish 2012 at around 3.7 million visitors to the United States. Projections for United States destinations remain good in 2013 regardless of any depreciation of the yen.
After more than two decades of stagnation, Japan's travel industry is seen as growing. With the implementation of the Open Skies Agreement and the introduction of the Boeing 787 Dreamliner, new nonstop flights have begun between Boston, Seattle, San Diego, San Jose, and Denver with Tokyo. In addition, BrandUSA and the Japan Association of Travel Agents successfully implemented a “Japan-U.S. Tourism Exchange Year” in 2012/13. As a result, the United States has enjoyed high visibility in recent months, and now is an excellent time for the U.S. travel industry to capitalize on that groundwork to actively promote their
The foregoing analysis of travel and tourism opportunities in Taiwan, Japan, and Korea is not intended to be exhaustive, but illustrative of the many opportunities available to U.S. businesses. Applications from companies selling products or services within the scope of this mission, but not specifically identified, will be considered and evaluated by the Department of Commerce. Companies whose products or services do not fit the scope of the mission may contact their local U.S. Export Assistance Center to learn about other business development missions and services that may provide more targeted export opportunities. Companies may call 1–800–872–8723, or go to
The goal of this Trade Mission is to help U.S. destinations and tourism suppliers, including receptive tour operators, to develop their contacts and generate exports in Taiwan, Japan and Korea by providing business-to-business introductions and market access information so they can position themselves to enter or expand their presence in the Taiwan, Japanese and Korean markets.
The Taiwan-Japan-Korea Travel and Tourism Trade Mission will visit Taipei, Tokyo and Seoul, allowing participants to access the largest markets and business centers in the three countries. In each city, participants will meet with potential business contacts.
All parties interested in participating in the trade mission to Japan, Korea and Taiwan must complete and submit an application package for consideration by DOC. All applicants will be evaluated on their ability to meet certain conditions and best satisfy the selection criteria as outlined below. U.S. companies or trade associations already doing business with Japan, Korea and Taiwan, as well as U.S. companies seeking to enter these markets for the first time, may apply. A minimum of fifteen, and a maximum of thirty, companies and/or trade associations will be selected from the applicant pool for participation in this mission.
After a company has been selected to participate in the mission, a payment to the Department of Commerce in the form of a participation fee is required.
This Trade Mission is organized as three separate segments (Taiwan, Korea and Japan). Companies may choose to participate in one, two or all three segments. The fee for participating in more than one segment is the sum of the individual segments.
For business-to-business meetings in Taiwan only (not traveling to an additional trade mission country), the participation fee will be $1,400 for a small or medium-sized enterprise (SME)
For business-to-business meetings in Japan only (not traveling to an additional trade mission country), the participation fee will be $1,725 for a small or medium-sized enterprise (SME)
For business-to-business meetings in Korea only (not traveling to an additional trade mission country), the participation fee will be $1,275 for a small or medium-sized enterprise (SME)
• An applicant must submit a completed and signed mission application and supplemental application materials, including adequate information on the company's products and/or services, primary market objectives, and goals for participation. If the Department of Commerce receives an incomplete application, the Department may reject the application, request additional information, or take the lack of information into account when evaluating the application.
• Each applicant must also certify that it seeks to attract international travelers to the United States and that the travel and tourism products and services it seeks to export through the mission are located in the United States.
• Suitability of the company's (or, in the case of a trade association or trade organization, represented companies') products or services to the market.
• Company's (or, in the case of a trade association or trade organization, represented companies') potential for conducting business in the country and region, including likelihood of exports resulting from the mission.
• Consistency of the applicant's goals and objectives with the stated scope of the mission.
Diversity of company size, sector or subsector, and location may also be considered during the review process.
Referrals from political organizations and any documents containing references to partisan political activities (including political contributions) will be removed from an applicant's
Mission recruitment will be conducted in an open and public manner, including publication in the
Recruitment for the mission will conclude no later than February 7, 2014. The U.S. Department of Commerce will review applications and make selection decisions on a rolling basis until the maximum of thirty participants is reached. We will inform all applicants of selection decisions as soon as possible after the applications are reviewed. Applications received after February 7, 2014 will be considered only if space and scheduling constraints permit.
Applications can be downloaded from the trade mission Web site or can be obtained by contacting the Department of Commerce staff listed below. Completed applications should be submitted to Frank Spector at
National Institute of Standards and Technology (NIST), Commerce.
Notice.
The Department of Commerce, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995.
Written comments must be submitted on or before August 6, 2013.
Direct all written comments to Jennifer Jessup, Departmental Paperwork Clearance Officer, Department of Commerce, Room 6616, 14th and Constitution Avenue NW., Washington, DC 20230 (or via the Internet at
Requests for additional information or copies of the information collection instrument and instructions should be directed to: Dede McMahon, NIST MEP, 100 Bureau Drive, Stop 4800, Gaithersburg, Maryland 20899–4800; (301–975–8328);
This is a request for a new information collection.
The purpose of the Advanced Manufacturing Jobs and Innovation Accelerator Challenge (AMJIAC) is to provide strategic, catalytic funding for regional partnerships that have the potential to accelerate innovation and strengthen capacity in advanced manufacturing. The objectives of the challenge are to support job creation, encourage economic development, and enhance the competitiveness of U.S. manufacturers in regions across the country. The AMJIAC is a partnership among the U.S. Department of Commerce's Economic Development Administration and the National Institute of Standards and Technology, the U.S. Department of Energy, the U.S. Department of Labor's Employment and Training Administration, the U.S. Small Business Administration, and the National Science Foundation.
Ten Award Recipients were selected though a competitive multi-agency grant process announced in May 2012 to support initiatives that strengthen advanced manufacturing at the local and/or regional level. The funds help the ten partnerships support local and/or regional efforts to spur job creation through a variety of projects, including initiatives that connect innovative small suppliers with large companies, link research with start-up companies that can commercialize new ideas, and train workers with skills that firms need to capitalize on business opportunities.
The data collected from the companies served by the ten AMJIAC Award Recipients will provide all of the agencies with information about the outcomes and impacts of the AMJIAC program on U.S. manufacturers obtained from the companies. This information will include quantified impacts on their sales, cost savings, employment growth, and additional investment. These figures will be used to determine the effectiveness of the project work and to gauge the overall success of the AMJIAC project. The purpose of the survey is to collect data from the companies to display the effectiveness of the AMJIAC project.
Information will be collected electronically.
Comments are invited on: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden (including hours and cost) of the proposed collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; and (d) ways to minimize the burden of the collection of information on respondents, including through the
Comments submitted in response to this notice will be summarized and/or included in the request for OMB approval of this information collection; they also will become a matter of public record.
National Institute of Standards and Technology (NIST), Commerce.
Notice.
The Department of Commerce, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995.
Written comments must be submitted on or before August 6, 2013.
Direct all written comments Jennifer Jessup, Departmental Paperwork Clearance Officer, Department of Commerce, Room 6616, 14th and Constitution Avenue NW., Washington, DC 20230 (or via the Internet at
Requests for additional information or copies of the information collection instrument and instructions should be directed to Dede McMahon, NIST MEP, 100 Bureau Drive, Stop 4800, Gaithersburg, Maryland 20899–4800; (301–975–8328);
This is a request for a new information collection.
Sponsored by the National Institute of Standards and Technology (NIST), the Manufacturing Extension Partnership (MEP) and the Department of Energy (DOE), Energy Efficiency and Renewable Energy/Building Technologies Office (EERE/BTO), the Building Construction Technology Extension Pilot (BCTEP) is focused on training building operators in the principles and practices of building energy systems re-tuning. Re-tuning is a systematic semi-automated process of identifying operational problems in commercial and industrial buildings. It leverages data collected from the building automation system to identify opportunities to improve the building operations and provides guidance on implementing corrections at no cost or very low cost, leading to a reduction in the overall energy consumption.
NIST MEP, in collaboration with the DOE EERE/BTO, has funded 3 projects in CA, NY and PA to develop, refine and test curricula for buildings that do and do not have building automation systems, then train trainers to deliver the curriculum to building operators, using real commercial, government and industrial buildings as the test beds.
The purpose of the survey is to collect information that will provide the MEP with information regarding Competitive Award Recipient performance regarding the delivery of technology and business solutions to U.S.-based clients.
Information will be collected electronically.
Comments are invited on: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden (including hours and cost) of the proposed collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; and (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology.
Comments submitted in response to this notice will be summarized and/or included in the request for OMB approval of this information collection; they also will become a matter of public record.
National Marine Fisheries Service, National Oceanic and Atmospheric Administration, Commerce.
Notice of availability.
The National Marine Fisheries Service (NMFS) announces the adoption and availability of the final Recovery Plan (Plan) for the North Pacific right whale (
Electronic copies of the Final Recovery Plan are available online at
Shannon Bettridge (301–427–8402), email
Recovery plans describe actions beneficial to the conservation and recovery of species listed under the Endangered Species Act of 1973 (ESA), as amended (16 U.S.C. 1531
The Northern right whale (
Because the current status of North Pacific right whales is unknown, the primary purpose of the Recovery Plan is to provide a research strategy to obtain data necessary to determine distribution and estimate population abundance, trends, and structure and to identify factors that may be limiting North Pacific right whale recovery. Criteria for the reclassification of the North Pacific right whale are included in the Recovery Plan. In summary, the North Pacific right whale may be reclassified from endangered to threatened when all of the following have been met: (1) Given current and projected threats and environmental conditions, the North Pacific right whale population satisfies the risk analysis standard for threatened status (has no more than a 1 percent chance of extinction in 100 years)
The population will be considered for delisting if all of the following can be met: (1) Given current and projected threats and environmental conditions, the total North Pacific right whale population satisfies the risk analysis standard for unlisted status (has less than a 10 percent probability of becoming endangered in 20 years). Any factors or circumstances that are thought to substantially contribute to a real risk of extinction that cannot be incorporated into a Population Viability Analysis will be carefully considered before delisting takes place; and (2) none of the known threats to North Pacific right whales are known to limit the continued growth of populations. Specifically, the factors in 4(a)(l) of the ESA are being or have been addressed. The time and cost to recovery is not predictable with the current information on North Pacific right whales. The difficulty in gathering data on North Pacific right whales and uncertainty about the success of passive acoustic monitoring in fulfilling data needs make it impossible to give a timeframe to recovery. While we are comfortable estimating costs for 50 years of plan implementation ($27.283 million), any projections beyond this date are likely to be too imprecise to predict. The anticipated date for removal from the endangered species list also cannot be determined because of the uncertainty in the success of recovery plan actions for North Pacific right whales. The effectiveness of many management activities is not known on a global level. Currently it is impossible to predict when such measures will bring the species to a point at which the protections provided by the ESA are no longer warranted, or even determine whether the species has recovered enough to be downlisted or delisted. In the future, as more information is obtained it should be possible to make more informative projections about the time to recovery, and its expense. NMFS has reviewed the Plan for compliance with the requirements of the ESA section 4(f), determined that it does incorporate the required elements, and is therefore adopting it as the Final Recovery Plan North Pacific Right Whales.
16 U.S.C. 1531
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of SEDAR 33 Gulf of Mexico Gag and Greater Amberjack webinar.
The SEDAR 33 assessment of the Gulf of Mexico stocks of Gag (
The Post-Data Workshop webinar will be held on Thursday, June 27, 2013 at 10 a.m. Eastern Time. See
The webinar will be held via GoToWebinar online meeting service. All workshops and webinars are open to members of the public. Those interested in participating should contact Ryan Rindone at SEDAR (see
Ryan Rindone, SEDAR Coordinator; telephone: (813) 348–1630; email:
The Gulf of Mexico, South Atlantic, and Caribbean Fishery Management Councils, in conjunction with NOAA Fisheries and the Atlantic and Gulf States Marine Fisheries Commissions, have implemented the Southeast Data,
The items of discussion in the Post-Data Workshop are as follows:
Evaluate final discussions, decisions and other recommendations pertinent to data inputs for the stock assessments of Gulf of Mexico Gag and Greater Amberjack.
Although non-emergency issues not contained in this agenda may come before this group for discussion, those issues may not be the subject of formal action during this meeting. Action will be restricted to those issues specifically identified in this notice and any issues arising after publication of this notice that require emergency action under section 305(c) of the Magnuson-Stevens Fishery Conservation and Management Act, provided the public has been notified of the intent to take final action to address the emergency.
This meeting is accessible to people with disabilities. Requests for auxiliary aids should be directed to the SEDAR office (see
The times and sequence specified in this agenda are subject to change.
16 U.S.C. 1801
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of public workshops.
Free Atlantic Shark Identification Workshops and Protected Species Safe Handling, Release, and Identification Workshops will be held in July, August, and September of 2013. Certain fishermen and shark dealers are required to attend a workshop to meet regulatory requirements and to maintain valid permits. Specifically, the Atlantic Shark Identification Workshop is mandatory for all federally permitted Atlantic shark dealers. The Protected Species Safe Handling, Release, and Identification Workshop is mandatory for vessel owners and operators who use bottom longline, pelagic longline, or gillnet gear, and who have also been issued shark or swordfish limited access permits. Additional free workshops will be conducted during 2013 and will be announced in a future notice.
The Atlantic Shark Identification Workshops will be held July 18, August 15, and September 12, 2013.
The Protected Species Safe Handling, Release, and Identification Workshops will be held on July 3, July 9, August 9, August 21, September 10, and September 18, 2013.
See
The Atlantic Shark Identification Workshops will be held in Fort Lauderdale, FL; Rosenberg, TX; and Manahawkin, NJ.
The Protected Species Safe Handling, Release, and Identification Workshops will be held in Boston, MA; Daytona Beach, FL; Ronkonkoma, NY; Kenner, LA; Charleston, SC; and Corpus Christi, TX.
See
Richard A. Pearson by phone: (727) 824–5399, or by fax: (727) 824–5398.
The workshop schedules, registration information, and a list of frequently asked questions regarding these workshops are posted on the Internet at:
Since January 1, 2008, Atlantic shark dealers have been prohibited from receiving, purchasing, trading, or bartering for Atlantic sharks unless a valid Atlantic Shark Identification Workshop certificate is on the premises of each business listed under the shark dealer permit which first receives Atlantic sharks (71 FR 58057; October 2, 2006). Dealers who attend and successfully complete a workshop are issued a certificate for each place of business that is permitted to receive sharks. These certificate(s) are valid for 3 years. Approximately 86 free Atlantic Shark Identification Workshops have been conducted since January 2007.
Currently, permitted dealers may send a proxy to an Atlantic Shark Identification Workshop. However, if a dealer opts to send a proxy, the dealer must designate a proxy for each place of business covered by the dealer's permit which first receives Atlantic sharks. Only one certificate will be issued to each proxy. A proxy must be a person who is currently employed by a place of business covered by the dealer's permit; is a primary participant in the identification, weighing, and/or first receipt of fish as they are offloaded from a vessel; and who fills out dealer reports. Atlantic shark dealers are prohibited from renewing a Federal shark dealer permit unless a valid Atlantic Shark Identification Workshop certificate for each business location which first receives Atlantic sharks has been submitted with the permit renewal application. Additionally, trucks or other conveyances that are extensions of a dealer's place of business must possess a copy of a valid dealer or proxy Atlantic Shark Identification Workshop certificate.
1. July 18, 2013, 12 p.m.–4 p.m., LaQuinta Inn and Suites, 999 West
2. August 15, 2013, 12 p.m.–4 p.m., Hampton Inn & Suites, 3312 Vista Drive, Rosenberg, TX 77471.
3. September 12, 2013, 12 p.m.–4 p.m., Holiday Inn, 151 Route 72 East, Manahawkin, NJ 08050.
To register for a scheduled Atlantic Shark Identification Workshop, please contact Eric Sander at
To ensure that workshop certificates are linked to the correct permits, participants will need to bring the following specific items to the workshop:
• Atlantic shark dealer permit holders must bring proof that the attendee is an owner or agent of the business (such as articles of incorporation), a copy of the applicable permit, and proof of identification.
• Atlantic shark dealer proxies must bring documentation from the permitted dealer acknowledging that the proxy is attending the workshop on behalf of the permitted Atlantic shark dealer for a specific business location, a copy of the appropriate valid permit, and proof of identification.
The Atlantic Shark Identification Workshops are designed to reduce the number of unknown and improperly identified sharks reported in the dealer reporting form and increase the accuracy of species-specific dealer-reported information. Reducing the number of unknown and improperly identified sharks will improve quota monitoring and the data used in stock assessments. These workshops will train shark dealer permit holders or their proxies to properly identify Atlantic shark carcasses.
Since January 1, 2007, shark limited-access and swordfish limited-access permit holders who fish with longline or gillnet gear have been required to submit a copy of their Protected Species Safe Handling, Release, and Identification Workshop certificate in order to renew either permit (71 FR 58057; October 2, 2006). These certificate(s) are valid for 3 years. As such, vessel owners who have not already attended a workshop and received a NMFS certificate, or vessel owners whose certificate(s) will expire prior to the next permit renewal, must attend a workshop to fish with, or renew, their swordfish and shark limited-access permits. Additionally, new shark and swordfish limited-access permit applicants who intend to fish with longline or gillnet gear must attend a Protected Species Safe Handling, Release, and Identification Workshop and submit a copy of their workshop certificate before either of the permits will be issued. Approximately 154 free Protected Species Safe Handling, Release, and Identification Workshops have been conducted since 2006.
In addition to certifying vessel owners, at least one operator on board vessels issued a limited-access swordfish or shark permit that uses longline or gillnet gear is required to attend a Protected Species Safe Handling, Release, and Identification Workshop and receive a certificate. Vessels that have been issued a limited-access swordfish or shark permit and that use longline or gillnet gear may not fish unless both the vessel owner and operator have valid workshop certificates onboard at all times. Vessel operators who have not already attended a workshop and received a NMFS certificate, or vessel operators whose certificate(s) will expire prior to their next fishing trip, must attend a workshop to operate a vessel with swordfish and shark limited-access permits that uses longline or gillnet gear.
1. July 3, 2013, 9 a.m.–5 p.m., Hilton Inn, 1 Hotel Drive, Boston, MA 02128.
2. July 9, 2013, 9 a.m.–5 p.m., Best Western, 2620 West International Speedway Boulevard, Daytona Beach, FL 32114.
3. August 9, 2013, 9 a.m.–5 p.m., Holiday Inn, 3845 Veterans Memorial Highway, Ronkonkoma, NY 11779.
4. August 21, 2013, 9 a.m.–5 p.m., Hilton Inn, 901 Airline Drive, Kenner, LA 70062.
5. September 10, 2013, 9 a.m.–5 p.m., Holiday Inn, 301 Savannah Highway, Charleston, SC 29407.
6. September 18, 2013, 9 a.m.–5 p.m., Holiday Inn, 1102 South Shoreline Drive, Corpus Christi, TX 78401.
To register for a scheduled Protected Species Safe Handling, Release, and Identification Workshop, please contact Angler Conservation Education at (386) 682–0158.
To ensure that workshop certificates are linked to the correct permits, participants will need to bring the following specific items with them to the workshop:
• Individual vessel owners must bring a copy of the appropriate swordfish and/or shark permit(s), a copy of the vessel registration or documentation, and proof of identification.
• Representatives of a business-owned or co-owned vessel must bring proof that the individual is an agent of the business (such as articles of incorporation), a copy of the applicable swordfish and/or shark permit(s), and proof of identification.
• Vessel operators must bring proof of identification.
The Protected Species Safe Handling, Release, and Identification Workshops are designed to teach longline and gillnet fishermen the required techniques for the safe handling and release of entangled and/or hooked protected species, such as sea turtles, marine mammals, and smalltooth sawfish. In an effort to improve reporting, the proper identification of protected species will also be taught at these workshops. Additionally, individuals attending these workshops will gain a better understanding of the requirements for participating in these fisheries. The overall goal of these workshops is to provide participants with the skills needed to reduce the mortality of protected species, which may prevent additional regulations on these fisheries in the future.
16 U.S.C. 1801
Committee for Purchase From People Who are Blind or Severely Disabled.
Proposed additions to and deletions from the procurement list.
The Committee is proposing to add products and services to the Procurement List that will be furnished by nonprofit agencies employing persons who are blind or have other
Comments must be received on or before 7/8/2013.
Committee for Purchase From People Who are Blind or Severely Disabled, 1401 S. Clark Street, Suite 10800, Arlington, Virginia, 22202–4149.
For further information or to submit comments contact Barry S. Lineback, Telephone: (703) 603–7740, Fax: (703) 603–0655, or email
This notice is published pursuant to 41 U.S.C. 8503(a)(2) and 41 CFR 51–2.3. Its purpose is to provide interested persons an opportunity to submit comments on the proposed actions.
If the Committee approves the proposed additions, the entities of the Federal Government identified in this notice will be required to procure the products and services listed below from nonprofit agencies employing persons who are blind or have other severe disabilities.
The following products and services are proposed for addition to the Procurement List for production by the nonprofit agencies listed:
The following products are proposed for deletion from the Procurement List:
Committee for Purchase from People Who are Blind or Severely Disabled.
Additions to the Procurement List.
This action adds services to the Procurement List that will be provided by nonprofit agencies employing persons who are blind or have other severe disabilities.
As of 7/8/2013.
Committee for Purchase from People Who are Blind or Severely Disabled, 1401 S. Clark Street, Suite 10800, Arlington, Virginia 22202–4149.
Barry S. Lineback, Telephone: (703) 603–7740, Fax: (703) 603–0655, or email
On 4/12/2013 (78 FR 21916), the Committee for Purchase from People Who are Blind or Severely Disabled published notice of proposed additions to the Procurement List.
After consideration of the material presented to it concerning capability of qualified nonprofit agencies to provide the services and impact of the additions on the current or most recent contractors, the Committee has determined that the services listed below are suitable for procurement by the Federal Government under 41 U.S.C. 8501–8506 and 41 CFR 51–2.4.
I certify that the following action will not have a significant impact on a substantial number of small entities. The major factors considered for this certification were:
1. The action will not result in any additional reporting, recordkeeping or other compliance requirements for small entities other than the small organizations that will provide the services to the Government.
2. The action will result in authorizing small entities to provide the services to the Government.
3. There are no known regulatory alternatives which would accomplish
Accordingly, the following services are added to the Procurement List:
Bureau of Consumer Financial Protection.
Notice and request for comment.
In accordance with the Paperwork Reduction Act of 1995 (PRA), the Consumer Financial Protection Bureau (Bureau) is proposing a new information collection, titled “Telephone Survey Exploring Consumer Awareness of and Perceptions Regarding Dispute Resolution Provisions in Credit Card Agreements.”
Written comments are encouraged and must be received on or before August 6, 2013 to be assured of consideration.
You may submit comments, identified by the title of the information collection, Office of Management and Budget (OMB) Control Number (see below), and docket number (see above), by any of the following methods:
•
•
Please note that comments submitted by fax or email and those submitted after the comment period will not be accepted. In general, all comments received will be posted without change to regulations.gov, including any personal information provided. Sensitive personal information, such as account numbers or social security numbers, should not be included.
Documentation prepared in support of this information collection request is available at
The survey will explore the extent of consumer awareness of dispute resolution provisions in their agreements with credit card providers, as well as consumers' assessments of such provisions. The survey will necessarily seek information regarding consumers' perceptions and valuations of the two primary forms of dispute resolution: arbitration and litigation. The survey will not, however, gather data regarding respondents' post-fact satisfaction with arbitration or litigation proceedings.
Office of the Secretary of Defense, DoD.
Notice to add a new System of Records.
The Office of the Secretary of Defense proposes to add a new system of records in its inventory of record systems subject to the Privacy Act of 1974 (5 U.S.C. 552a), as amended.
This proposed action will be effective on July 8, 2013 unless comments are received which result in a contrary determination. Comments will be accepted on or before July 8, 2013.
You may submit comments, identified by docket number and title, by any of the following methods:
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Ms. Cindy Allard, Chief, OSD/JS Privacy Office, Freedom of Information Directorate, Washington Headquarters Service, 1155 Defense Pentagon, Washington, DC 20301–1155, or by telephone at (571) 372–0461.
The Defense Information Systems Agency notices for systems of records subject to the Privacy Act of 1974 (5 U.S.C. 552a), as amended, have been published in the
Adjunct Faculty Information Database.
Defense Institute of International Legal Studies (DIILS), 441 Elliot Avenue, Newport, RI 02841–1531.
Military (e.g., Active, National Guard, Reserve, and Coast Guard), civilian and contractor employees, Foreign Nationals and private sector personnel.
Full name, date and place of birth, Social Security Number (SSN), Department of Defense Identification Number (DoD ID Number), home and work addresses, work, fax, home and personal cell phone numbers, US government credit card number, personal and alternative email addresses, pay grade, military status (e.g., military rank, branch of service, retired and reserves), security clearance and current status, passport information, language capability, self-rating/level of expertise and abilities, training completed (e.g, trafficking in persons, human rights, code of conduct, etc.), biography, and professional references.
10 U.S.C. 134, Under Secretary of Defense for Policy; DoD Directive 5105.65, Defense Security Cooperation Agency (DSCA); DoD Directive 5101.1, DoD Executive Agent; DoD Directive 5132.03, DoD Policy and Responsibilities Relating to Security Cooperation; and E.O. 9397 (SSN), as amended.
Defense Institute of International Legal Studies (DIILS) supports U.S. foreign policy and national security policy with rule of law training and education focused on human rights, international humanitarian law, and the law of armed conflict. The purpose of the Adjunct Faculty Information Database is to collect supplied information from qualified adjunct faculty members to make preparations for their overseas travel assignments as well as maintain a record of their qualifications for participation in future training programs. This data will also be used as a resource for future travel and training assignments, as a record of adjunct assignments and a basis to identify training requirements for the adjunct faculty.
In addition to those disclosures generally permitted under 5 U.S.C. 552a(b) of the Privacy Act of 1974, as amended, these records contained herein may specifically be disclosed outside the DoD as a routine use pursuant to 5 U.S.C. 552a(b)(3) as follows:
The DoD Blanket Routine Uses set forth at the beginning of the Office of the Secretary of Defense (OSD) compilation of systems of records notices may apply to this system.
Paper and electronic storage media.
Name, SSN and/or DoD ID Number.
Records are maintained in a controlled facility. Physical entry is restricted by the use of locks, guards, and is accessible only to authorized personnel. Access to records is limited to person(s) responsible for servicing the record in performance of their official duties and who are properly screened and cleared for need-to-know. Access to computerized data is restricted by centralized access control to include the use of Common Access cards (CAC), passwords (which are changed periodically), file permissions, firewalls, and intrusion alert systems, including the use of a “block out” restriction feature when viewing SSNs.
Temporary: Update periodically; destroy when no longer required for reference.
Training Specialist, Curriculum Department, Defense Institute of International Legal Studies, 441 Elliot Avenue, Newport, RI 02841–1531.
Individuals seeking to determine whether information about themselves is contained in this system of records should address written inquiries to the Training Specialist, Curriculum Department, Defense Institute of International Legal Studies, 441 Elliot Avenue, Newport, RI 02841–1531.
Written requests should include the full name, current address and telephone number, and the number of this system of records notice and be signed.
Individuals seeking access to records about themselves contained in this system should address written inquiries to the Office of the Secretary of Defense/Joint Staff, Freedom of Information Act Requester Services, 4800 Mark Center Drive, Alexandria, VA 22350–3100.
Written requests should include the full name, current address and telephone number, and the number of this system of records notice and be signed.
The Office of the Secretary of Defense (OSD) rules for accessing records, for contesting contents and appealing initial agency determinations are published in OSD Administrative Instruction 81; 32 CFR part 311; or may be obtained from the system manager.
Individual.
None.
Department of the Navy, DoD.
Notice to alter a System of Records.
The Department of the Navy proposes to alter a system of records in its inventory of record systems subject to the Privacy Act of 1974 (5 U.S.C. 552a), as amended.
This proposed action will be effective on July 8, 2013 unless comments are received which result in a contrary determination. Comments will be accepted on or before July 8, 2013.
You may submit comments, identified by docket number and title, by any of the following methods:
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Ms. Robin Patterson, Head, PA/FOIA Office (DNS–36), Department of the Navy, 2000 Navy Pentagon, Washington, DC 20350–2000, or by phone at (202) 685–6545.
The Department of the Navy's notices for systems of records subject to the Privacy Act of 1974 (5 U.S.C. 552a), as amended, have been published in the
The proposed system report, as required by 5 U.S.C. 552a(r) of the Privacy Act of 1974, as amended, was submitted on May 14, 2013, to the House Committee on Oversight and Government Reform, the Senate Committee on Governmental Affairs, and the Office of Management and Budget (OMB) pursuant to paragraph 4c of Appendix I to OMB Circular No. A–130, “Federal Agency Responsibilities for Maintaining Records About Individuals,” dated February 8, 1996 (February 20, 1996, 61 FR 6427).
Enlisted Master File Automated Systems (September 21, 2006, 71 FR 55173).
Delete entry and replace with “Defense Information Systems Agency (DISA), 5450 Carlisle Pike, Mechanicsburg, PA 17050–0975.”
Delete entry and replace with “All Navy enlisted personnel.”
Delete entry and replace with “System contains personnel data to support enlisted assignment, planning, programming, accounting, promotions, career development, and procurement, including: name, Social Security Number (SSN), rank, status, education, training, security clearance, qualifications, assignments, performance, service, rotation and retirement dates, marital status, and number of dependents. The system also contains Activity Personnel Diaries, personnel accounting documents, and other personnel transaction documents necessary to maintain file accuracy and currency.”
Delete entry and replace with “10 U.S.C. 5013, Secretary of the Navy; Department of Defense Instructions DoDI 1336.08, Military Human Resource Records Life Cycle Management; DoDI 1336.05, Automated Extract of Active Duty Military Personnel Records; DoDI 7730.54, Reserve Components Common Personnel Data System (RCCPDS); Chief of Naval Operations Instructions OPNAVINST 1070.2 Series, Automated Extracts of Active Duty Military Personnel Records; and OPNAVINST 1001.19 Series, Reserve Components Common Personnel Data System (RCCPDS); and E.O. 9397 (SSN), as amended.”
Delete entry and replace with “Paper and electronic storage media.”
Delete entry and replace with “Commander, Navy Personnel Command (PERS–33), 5720 Integrity Drive, Millington, TN 38055–3130.”
Delete entry and replace with “Individuals seeking to determine whether this system of records contains information about themselves should address written inquiries to the Commander, Navy Personnel Command (PERS–33), 5720 Integrity Drive, Millington, TN 38055–3130.
Written request should contain full name, Social Security Number (SSN), rank, status, and signature of requester. The system manager may require an original signature or a notarized signature as a means of proving the identity of the individual requesting access to the records.”
Delete entry and replace with “Individuals seeking access to records about themselves contained in this system of records should address written inquiries to the Commander, Navy Personnel Command (PERS–33), 5720 Integrity Drive, Millington, TN 38055–3130.
Written request should contain full name, Social Security Number (SSN), rank, status, and signature of requester. The system manager may require an original signature or a notarized signature as a means of proving the identity of the individual requesting access to the records.”
In notice document 2013–12988, appearing on page 33075 in the issue of Monday, June 3, 2013, make the following correction:
In the second column, in the eighth and ninth lines, “June 3, 2013” should read “July 3, 2013”.
Office of Special Education and Rehabilitative Services, Department of Education.
Notice.
The purpose of the RRTCs, which are funded through the Disability and Rehabilitation Research Projects and Centers Program, is to achieve the goals of, and improve the effectiveness of, services authorized under the Rehabilitation Act through advanced research, training, technical assistance, and dissemination activities in general problem areas, as specified by NIDRR. These activities are designed to benefit rehabilitation service providers, individuals with disabilities, and the family members or other authorized representatives of individuals with disabilities. Additional information on the RRTC program can be found at:
These priorities are:
Priority 1—Promoting Healthy Aging for Individuals with Long-Term Physical Disabilities.
The full text of this priority is included in the notice of final priority published elsewhere in this issue of the
Priority 2—General RRTC Requirements.
The full text of this priority is included in the notice of final priorities for the Disability and Rehabilitation Research Projects and Centers Program, published in the
The regulations in 34 CFR part 86 apply to institutions of higher education (IHEs) only.
The Department is not bound by any estimates in this notice.
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You can contact ED Pubs at its Web site, also:
If you request an application from ED Pubs, be sure to identify this competition as follows: CFDA number 84.133B–10.
Individuals with disabilities can obtain a copy of the application package in an accessible format (e.g., braille, large print, audiotape, or compact disc) by contacting the person or team listed under
2.
• A “page” is 8.5″ x 11″, on one side only, with 1″ margins at the top, bottom, and both sides.
• Double space (no more than three lines per vertical inch) all text in the application narrative, including titles, headings, footnotes, quotations, references, and captions, as well as all text in charts, tables, figures, and graphs.
• Use a font that is either 12 point or larger or no smaller than 10 pitch (characters per inch).
• Use one of the following fonts: Times New Roman, Courier, Courier New, or Arial. An application submitted in any other font (including Times Roman or Arial Narrow) will not be accepted.
The recommended page limit does not apply to Part I, the cover sheet; Part II, the budget section, including the narrative budget justification; Part IV, the assurances and certifications; or the one-page abstract, the resumes, the bibliography, or the letters of support. However, the page limit does apply to all of the application narrative section (Part III).
An applicant should consult NIDRR's Long-Range Plan for Fiscal Years 2013–2017 (78 FR 20299) (Plan) when preparing its application. The Plan is organized around the following research domains: (1) Community Living and Participation; (2) Health and Function; and (3) Employment.
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Applications for grants under this competition must be submitted electronically using the Grants.gov Apply site (Grants.gov). For information (including dates and times) about how to submit your application electronically, or in paper format by mail or hand delivery if you qualify for an exception to the electronic submission requirement, please refer to section IV. 7.
We do not consider an application that does not comply with the deadline requirements.
Individuals with disabilities who need an accommodation or auxiliary aid in connection with the application process should contact the individual listed under
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a. Have a Data Universal Numbering System (DUNS) number and a Taxpayer Identification Number (TIN);
b. Register both your DUNS number and TIN with the Central Contractor Registry (CCR)—and, after July 24, 2012, with the System for Award Management (SAM), the Government's primary registrant database;
c. Provide your DUNS number and TIN on your application; and
d. Maintain an active CRR or SAM registration with current information while your application is under review by the Department and, if you are awarded a grant, during the project period.
You can obtain a DUNS number from DUN and Bradstreet. A DUNS number can be created within one business day.
If you are a corporate entity, agency, institution, or organization, you can obtain a TIN from the Internal Revenue Service. If you are an individual, you can obtain a TIN from the Internal Revenue Service or the Social Security Administration. If you need a new TIN, please allow 2–5 weeks for your TIN to become active.
The CCR or SAM registration process may take five or more business days to complete. If you are currently registered with the CCR, you may not need to make any changes. However, please make certain that the TIN associated with your DUNS number is correct. Also note that you will need to update your registration annually. This may take three or more business days to complete. Information about SAM is available at SAM.gov.
In addition, if you are submitting your application via Grants.gov, you must (1) be designated by your organization as an Authorized Organization Representative (AOR); and (2) register yourself with Grants.gov as an AOR. Details on these steps are outlined at the following Grants.gov Web page:
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Applications for grants under the RRTC on Promoting Healthy Aging for Individuals with Long-Term Disabilities program, CFDA Number 84.133B–10, must be submitted electronically using the Governmentwide Grants.gov Apply site at
We will reject your application if you submit it in paper format unless, as described elsewhere in this section, you qualify for one of the exceptions to the electronic submission requirement
You may access the electronic grant application for the RRTC program at
Please note the following:
• When you enter the Grants.gov site, you will find information about submitting an application electronically through the site, as well as the hours of operation.
• Applications received by Grants.gov are date and time stamped. Your application must be fully uploaded and submitted and must be date and time stamped by the Grants.gov system no later than 4:30:00 p.m., Washington, DC time, on the application deadline date. Except as otherwise noted in this section, we will not accept your application if it is received—that is, date and time stamped by the Grants.gov system—after 4:30:00 p.m., Washington, DC time, on the application deadline date. We do not consider an application that does not comply with the deadline requirements. When we retrieve your application from Grants.gov, we will notify you if we are rejecting your application because it was date and time stamped by the Grants.gov system after 4:30:00 p.m., Washington, DC time, on the application deadline date.
• The amount of time it can take to upload an application will vary depending on a variety of factors, including the size of the application and the speed of your Internet connection. Therefore, we strongly recommend that you do not wait until the application deadline date to begin the submission process through Grants.gov.
• You should review and follow the Education Submission Procedures for submitting an application through Grants.gov that are included in the application package for this competition to ensure that you submit your application in a timely manner to the Grants.gov system. You can also find the Education Submission Procedures pertaining to Grants.gov under News and Events on the Department's G5 system home page at
• You will not receive additional point value because you submit your application in electronic format, nor will we penalize you if you qualify for an exception to the electronic submission requirement, as described elsewhere in this section, and submit your application in paper format.
• You must submit all documents electronically, including all information you typically provide on the following forms: the Application for Federal Assistance (SF 424), the Department of Education Supplemental Information for SF 424, Budget Information—Non-Construction Programs (ED 524), and all necessary assurances and certifications.
• You must upload any narrative sections and all other attachments to your application as files in a PDF (Portable Document) read-only, non-modifiable format. Do not upload an interactive or fillable PDF file. If you upload a file type other than a read-only, non-modifiable PDF or submit a password-protected file, we will not review that material.
• Your electronic application must comply with any page-limit requirements described in this notice.
• After you electronically submit your application, you will receive from Grants.gov an automatic notification of receipt that contains a Grants.gov tracking number. (This notification indicates receipt by Grants.gov only, not receipt by the Department.) The Department then will retrieve your application from Grants.gov and send a second notification to you by email. This second notification indicates that the Department has received your application and has assigned your application a PR/Award number (a Department-specified identifying number unique to your application).
• We may request that you provide us original signatures on forms at a later date.
If you are prevented from electronically submitting your application on the application deadline date because of technical problems with the Grants.gov system, we will grant you an extension until 4:30:00 p.m., Washington, DC time, the following business day to enable you to transmit your application electronically or by hand delivery. You also may mail your application by following the mailing instructions described elsewhere in this notice.
If you submit an application after 4:30:00 p.m., Washington, DC time, on the application deadline date, please contact the person listed under
The extensions to which we refer in this section apply only to the unavailability of, or technical problems with, the Grants.gov system. We will not grant you an extension if you failed to fully register to submit your application to Grants.gov before the application deadline date and time or if the technical problem you experienced is unrelated to the Grants.gov system.
• You do not have access to the Internet; or
• You do not have the capacity to upload large documents to the Grants.gov system;
• No later than two weeks before the application deadline date (14 calendar days or, if the fourteenth calendar day before the application deadline date falls on a Federal holiday, the next business day following the Federal holiday), you mail or fax a written statement to the Department, explaining which of the two grounds for an exception prevents you from using the Internet to submit your application.
If you mail your written statement to the Department, it must be postmarked no later than two weeks before the application deadline date. If you fax your written statement to the Department, we must receive the faxed statement no later than two weeks before the application deadline date.
Address and mail or fax your statement to: Marlene Spencer, U.S. Department of Education, 400 Maryland Avenue SW., Room 5133, PCP, Washington, DC 20202–2700. FAX: (202) 245–7323.
Your paper application must be submitted in accordance with the mail or hand delivery instructions described in this notice.
b.
If you qualify for an exception to the electronic submission requirement, you may mail (through the U.S. Postal Service or a commercial carrier) your application to the Department. You must mail the original and two copies of your application, on or before the application deadline date, to the Department at the following address: U.S. Department of Education, Application Control Center, Attention: (CFDA Number 84.133B–10), LBJ Basement Level 1, 400 Maryland Avenue SW., Washington, DC 20202–4260.
You must show proof of mailing consisting of one of the following:
(1) A legibly dated U.S. Postal Service postmark.
(2) A legible mail receipt with the date of mailing stamped by the U.S. Postal Service.
(3) A dated shipping label, invoice, or receipt from a commercial carrier.
(4) Any other proof of mailing acceptable to the Secretary of the U.S. Department of Education.
If you mail your application through the U.S. Postal Service, we do not accept either of the following as proof of mailing:
(1) A private metered postmark.
(2) A mail receipt that is not dated by the U.S. Postal Service.
If your application is postmarked after the application deadline date, we will not consider your application.
The U.S. Postal Service does not uniformly provide a dated postmark. Before relying on this method, you should check with your local post office.
c.
If you qualify for an exception to the electronic submission requirement, you (or a courier service) may deliver your paper application to the Department by hand. You must deliver the original and two copies of your application by hand, on or before the application deadline date, to the Department at the following address: U.S. Department of Education, Application Control Center, Attention: (CFDA Number 84.133B–10), 550 12th Street SW., Room 7041, Potomac Center Plaza, Washington, DC 20202–4260.
The Application Control Center accepts hand deliveries daily between 8:00 a.m. and 4:30:00 p.m., Washington, DC time, except Saturdays, Sundays, and Federal holidays.
(1) You must indicate on the envelope and—if not provided by the Department—in Item 11 of the SF 424 the CFDA number, including suffix letter, if any, of the competition under which you are submitting your application; and
(2) The Application Control Center will mail to you a notification of receipt of your grant application. If you do not receive this notification within 15 business days from the application deadline date, you should call the U.S. Department of Education Application Control Center at (202) 245–6288.
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In addition, in making a competitive grant award, the Secretary also requires various assurances including those applicable to Federal civil rights laws that prohibit discrimination in programs or activities receiving Federal financial assistance from the Department of Education (34 CFR 100.4, 104.5, 106.4, 108.8, and 110.23).
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If your application is not evaluated or not selected for funding, we notify you.
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We reference the regulations outlining the terms and conditions of an award in the
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(b) At the end of your project period, you must submit a final performance report, including financial information, as directed by the Secretary. If you receive a multi-year award, you must submit an annual performance report that provides the most current performance and financial expenditure information as directed by the Secretary under 34 CFR 75.118. The Secretary may also require more frequent performance reports under 34 CFR 75.720(c). For specific requirements on reporting, please go to
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• The number of products (e.g., new or improved tools, methods, discoveries, standards, interventions, programs, or devices) developed or tested with NIDRR funding that have been judged by expert panels to be of high quality and to advance the field.
• The average number of publications per award based on NIDRR-funded research and development activities in refereed journals.
• The percentage of new NIDRR grants that assess the effectiveness of
• The number of new or improved NIDRR-funded assistive and universally designed technologies, products, and devices transferred to industry for potential commercialization.
NIDRR uses information submitted by grantees as part of their Annual Performance Reports for these reviews.
Department of Education program performance reports, which include information on NIDRR programs, are available on the Department's Web site:
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Marlene Spencer, U.S. Department of Education, 400 Maryland Avenue SW., Room 5133, PCP, Washington, DC 20202–2700. Telephone: (202) 245–7532 or by email:
If you use a TDD or a TTY call the Federal Relay Service (FRS), toll free, at 1–800–877–8339.
You may also access documents of the Department published in the
Take notice that on May 20, 2013, NET Mexico Pipeline Partners, LLC (NET Mexico), 5847 San Felipe Street, Suite 1910, Houston, Texas 77057, filed an application in Docket No. CP13–482–000 under section 3 of the Natural Gas Act (NGA), and Part 153 of the Commission's regulations requesting authorization to site, construct, and operate new natural gas facilities to export natural gas from the United States to the Republic of Mexico at a point on the International Boundary between the United States and Mexico in Starr County, Texas, all as more fully set forth in the application which is on file with the Commission and open to public inspection. This filing is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's Web site at
Any questions regarding this application should be directed to Duncan Rhodes, Managing Director, NET Mexico Pipeline Partners, LLC, 5847 San Felipe Street, Suite 1910, Houston, Texas 77057, or by calling (713) 800–1900 (telephone) or (713) 871–0510 (fax)
Pursuant to section 157.9 of the Commission's rules, 18 CFR 157.9, within 90 days of this Notice the Commission staff will either: Complete its environmental assessment (EA) and place it into the Commission's public record (eLibrary) for this proceeding; or issue a Notice of Schedule for Environmental Review. If a Notice of Schedule for Environmental Review is issued, it will indicate, among other milestones, the anticipated date for the Commission staff's issuance of the final environmental impact statement (FEIS) or EA for this proposal. The filing of the EA in the Commission's public record for this proceeding or the issuance of a Notice of Schedule for Environmental Review will serve to notify federal and state agencies of the timing for the completion of all necessary reviews, and the subsequent need to complete all federal authorizations within 90 days of the date of issuance of the Commission staff's FEIS or EA.
There are two ways to become involved in the Commission's review of this project. First, any person wishing to obtain legal status by becoming a party to the proceedings for this project should, on or before the comment date stated below, file with the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, a motion to intervene in accordance with the requirements of the Commission's Rules of Practice and Procedure (18 CFR 385.214 or 385.211) and the Regulations under the NGA (18 CFR 157.10). A person obtaining party status will be placed on the service list maintained by the Secretary of the Commission and will receive copies of all documents filed by the applicant and by all other parties. A party must submit 5 copies of filings made with the Commission and must mail a copy to the applicant and to every other party in the proceeding. Only parties to the proceeding can ask for court review of Commission orders in the proceeding.
However, a person does not have to intervene in order to have comments considered. The second way to participate is by filing with the Secretary of the Commission, as soon as possible, an original and two copies of comments in support of or in opposition to this project. The Commission will consider these comments in
Persons who wish to comment only on the environmental review of this project should submit an original and two copies of their comments to the Secretary of the Commission. Environmental commentors will be placed on the Commission's environmental mailing list, will receive copies of the environmental documents, and will be notified of meetings associated with the Commission's environmental review process. Environmental commentors will not be required to serve copies of filed documents on all other parties. However, the non-party commentors will not receive copies of all documents filed by other parties or issued by the Commission (except for the mailing of environmental documents issued by the Commission) and will not have the right to seek court review of the Commission's final order.
The Commission strongly encourages electronic filings of comments, protests and interventions in lieu of paper using the “eFiling” link at
This filing is accessible on-line at
Take notice that the following hydroelectric application has been filed with the Commission and is available for public inspection:
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All documents may be filed electronically via the Internet. See, 18 CFR 385.2001(a)(1)(iii) and the instructions on the Commission's Web site at
The Commission's Rules of Practice and Procedure require all intervenors filing documents with the Commission to serve a copy of that document on each person whose name appears on the official service list for the project. Further, if an intervenor files comments or documents with the Commission relating to the merits of an issue that may affect the responsibilities of a particular resource agency, they must also serve a copy of the document on that resource agency.
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m. Individuals desiring to be included on the Commission's mailing list should so indicate by writing to the Secretary of the Commission.
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Take notice that the Commission received the following exempt wholesale generator filings:
Take notice that the Commission received the following electric rate filings:
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
Take notice that the Commission received the following electric corporate filings:
Take notice that the Commission received the following electric rate filings:
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
Take notice that the Commission received the following electric rate filings:
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
Take notice that the Commission received the following electric rate filings:
Take notice that the Commission received the following electric securities filings:
Take notice that the Commission received the following electric reliability filings:
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
Take notice that the 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 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
Take notice that the Commission received the following electric corporate filings:
Take notice that the Commission received the following electric rate filings:
Take notice that the Commission received the following PURPA 210(m)(3) filings:
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
Take notice that the Commission has received the following Natural Gas Pipeline Rate and Refund Report 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
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 corporate filings:
Take notice that the Commission received the following electric rate filings:
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
Take notice that the Commission received the following electric rate filings:
Take notice that the Commission received the following electric securities filings:
Take notice that the Commission received the following public utility holding company filings:
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
Take notice that the Commission has received the following Natural Gas Pipeline Rate and Refund Report filings:
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
Take notice that the Commission received the following electric rate filings:
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
Take notice that the Commission received the following exempt wholesale generator filings:
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 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
Take notice that the Federal Energy Regulatory Commission (Commission) is making available on its Web site a video, which shows how to file Electric Quarterly Reports (EQRs) pursuant to Order No. 770,
Any comments or questions concerning the video may be directed to
We encourage all EQR filers to subscribe to our EQR RSS Feed to stay up-to-date on all updates.
Take notice that on May 30, 2013, East Kentucky Power Cooperative, Inc. filed its proposed revenue requirements for reactive supply and voltage control from generation sources service (Cooper Generating Plant), pursuant to Schedule 2 of the PJM Interconnection, L.L.C. Open Access Transmission Tariff.
Any person desiring to intervene or to protest this filing must file in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211, 385.214). Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceeding. Any person wishing to become a party must file a notice of intervention or motion to intervene, as appropriate. Such notices, motions, or protests must be filed on or before the comment date. On or before the comment date, it is not necessary to serve motions to intervene or protests on persons other than the Applicant.
The Commission encourages electronic submission of protests and
This filing is accessible on-line at
This is a supplemental notice in the above-referenced proceeding, of Centinela Solar Energy, LLC's application for market-based rate authority, with an accompanying rate schedule, 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 June 24, 2013.
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(s) 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
This is a supplemental notice in the above-referenced proceeding, of Magnolia Energy LP's application for market-based rate authority, with an accompanying rate schedule, 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 June 24, 2013.
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(s) 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
This is a supplemental notice in the above-referenced proceeding, of Longfellow Wind, LLC's application for market-based rate authority, with an accompanying rate schedule, noting that
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 June 24, 2013.
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(s) 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
This is a supplemental notice in the above-referenced proceeding, of TGP Energy Management, LLC's application for market-based rate authority, with an accompanying rate schedule, 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 June 24, 2013.
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(s) 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
This is a supplemental notice in the above-referenced proceeding, of Catalina Solar Lessee, LLC's application for market-based rate authority, with an accompanying rate schedule, 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 June 24, 2013.
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(s) are accessible in the
This is a supplemental notice in the above-referenced proceeding of Campo Verde Solar, LLC'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 June 13, 2013.
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
This notice establishes the location and date for the technical conference directed by the Commission in an Order on California Independent System Operator Corporation's (CAISO) proposal to implement an interim flexible capacity and local reliability resource retention mechanism.
Those interested in participating in panel discussions should notify the Commission by close of business on June 14 by completing the online form at:
There is no fee to attend, and no deadline to register to attend the conference. However, because there will be limited seating for the conference, those attending the conference are encouraged to pre-register by July 17 by filling out the on-line registration form located at:
The technical conference will not be transcribed. However, there will be a free audiocast of the conference. The audiocast will allow persons to listen to the conference, but not participate. Anyone with Internet access who wants to listen can do so by navigating to the Calendar of Events at www.ferc.gov and locating the technical conference in the Calendar. The FERC Web site's link to the technical conference will contain a link to the audiocast. The Capitol Connection provides technical support for the audiocast. If you have questions, visit
FERC conferences are accessible under section 508 of the Rehabilitation Act of 1973. For accessibility accommodations please send an email to
For more information on this conference, please contact Colleen Farrell at
The staff of the Office of Energy Projects has revised its Upland Erosion Control, Revegetation, and Maintenance Plan (Plan) and Wetland and Waterbody Construction and Mitigation Procedures (Procedures). Attached to this notice are full texts of the final Plan and Procedure revisions, identifying all changes from the January 2003 versions in tracked changes format
The Plan and Procedures are referred to at 18 Code of Federal Regulations (CFR) 380.12(i)(5) and 380.12(d)(2), respectively, as well as 18 CFR 157C.206(b)(3)(iv). The Plan and Procedures identify the staff's baseline mitigation measures for minimizing erosion, enhancing revegetation, and minimizing the extent and duration of disturbance on wetlands and waterbodies during the construction of FERC jurisdictional natural gas projects.
In accordance with Order 603,
All of the information related to the Plan and Procedures revisions and submitted comments can be found on the FERC Web site (
In compliance with the requirements of the Paperwork Reduction Act of 1995, 44 USC 3507(a)(1)(D), the FERC is submitting the information collection changes described in this notice to the Office of Management and Budget (OMB) for review.
Any interested person may file comments regarding the information collection requirements directly with OMB and should address a copy of those comments to the Commission as explained below. The Commission issued a Notice in the
Comments filed with OMB, identified by the OMB Control No. 1902–0128, should be sent via email to the Office of Information and Regulatory Affairs:
A copy of the comments should also be sent to the Federal Energy Regulatory Commission, identified by the Docket No. AD12–2–000, by either of the following methods:
• eFiling at Commission's Web site:
• You may file a paper copy of your comments at the following address: Kimberly D. Bose, Secretary, Federal Energy Regulatory Commission, 888 First Street NE., Room 1A, Washington, DC 20426.
The information collection requirements in the Plan and Procedures are part of FERC–577, Natural Gas Facilities: Environmental Review and Compliance (OMB Control No. 1902–0128).
The final Plan and Procedure revisions identified in this notice are primarily modifications and clarifications to the content of information collections required by the current versions. For example, revisions to Plan sections III.I and VII.B.2 clarify staff's expectations for the content of winter construction plans and quarterly activity reports. Revisions to Plan section III.F standardize staff's expectations regarding wildlife and livestock protection measures and blasting plans. A revision to Procedure section VI.D.5 modifies the wetland revegetation success criteria used for monitoring and reporting. Such revisions do not constitute entirely new information collections; however, we estimate the revisions will increase reporting burden by adjusting the existing ways to comply with previously applicable instructions and requirements; training personnel to respond to the modified collection of information; and completing and reviewing these collections.
We estimate that certain revisions will reduce reporting burden on jurisdictional natural gas companies by providing guidance that is frequently requested during report preparations; directions to provide information that frequently results in data requests; and improved flexibility to reduce variance
We revised terminology to be inclusive of prior notice, advanced notice, and automatic authorization projects to address the wider net of project types subject to the Plan and Procedure requirements. The revisions clarify applicability for projects constructed under the Commission's blanket certificate program (18 CFR part 157, subpart F) and construction of facilities for transportation services under the Natural Gas Policy Act (NGPA) section 311 (18 CFR part 284, Subpart A). We expect these clarifications to improve the efficiency of the environmental review process, and reduce labor hours required of jurisdictional natural gas companies to prepare reports.
We implement a new record retention requirement regarding drainage system repairs or improvements (see revised Plan section VII.B.1.e). In addition, we also put in place a new annual report for affected wetlands that do not successfully revegetate within three years after construction (see revised Procedure section VI.D.6). We expect this revision to result in a minor increase in reporting burden due to the low incidence of wetland revegetation failure.
We expect that the revisions will lead to additional filings for blanket certificate projects, subject to our prior notice regulations (see revised “Applicability” discussions in section I of the Plan and Procedures). Such filings include winter construction plans noted in revised Plan section III.I, and the pre-construction filings noted in section II of the Procedures (e.g., hydrostatic testing information, waterbody crossing schedules, spill prevention and response procedures, plans for major waterbody crossings, horizontal directional drill crossings, and justifications for any variances). This would not reflect entirely new reporting burdens however, as this information is typically requested by staff during review of these projects to ensure compliance with blanket certificate standard conditions in 18 CFR 157.206.
Overall, in consideration of the revisions to reporting requirements and the increased efficiency that would be realized during the environmental review process, we expect the net effect of the revised Plan and Procedures to constitute a minor increase in information collection burden.
The total
We expect the estimated burden would reduce in subsequent years, as companies adjust to the modified information collections and have trained their personnel to collect information per the revised Plan and Procedures.
Interested persons may obtain additional information on the OMB process and information collection statement by contacting Ellen Brown, Office of the Executive Director, via email at
Environmental Protection Agency (EPA).
Notice.
The Environmental Protection Agency is planning to submit an information collection request (ICR), “Exhaust Emissions of Light-duty Vehicles in Metropolitan Detroit” (EPA ICR No. 2363.02, OMB Control No. 2060–0645) to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act (44 U.S.C. 3501
Comments must be submitted on or before August 6, 2013.
Submit your comments, referencing Docket ID No. EPA–HQ–OAR–2009–0548, online using
EPA's policy is that all comments received will be included in the public docket without change including any personal information provided, unless the comment includes profanity, threats, information claimed to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute.
James Warila, Assessment and Standards Division, Office of Transportation and Air Quality, (AADTC), Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone number: 734–214–4951; fax number: 734–214–4821; email address:
Supporting documents which explain in detail the information that the EPA will be collecting are available in the public docket for this ICR. The docket can be viewed online at
Pursuant to section 3506(c)(2)(A) of the PRA, EPA is soliciting comments and information to enable it to: (i) Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the Agency, including whether the information will have practical utility; (ii) evaluate the accuracy of the Agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used; (iii) enhance the quality, utility, and clarity of the information to be collected; and (iv) minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated electronic, mechanical, or other technological collection techniques or other forms of information technology, e.g., permitting electronic submission of responses. EPA will consider the comments received and amend the ICR as appropriate. The final ICR package will then be submitted to OMB for review and approval. At that time, EPA will issue another
One of the main issues in the study of vehicle emissions is the difficulty in acquiring representative results. Major challenges include the diversity of technology, the highly variable nature of emissions, the complexity and expense of measurement, difficulty in acquiring and retaining engines or vehicles, and the array of external variables that influence emissions, ranging from temperature to driver behavior. In combination, these factors tend to limit the numbers of vehicles that can be included in a given study. Limited sample sizes in combination with high variability make emissions data challenging to interpret.
The collection is a research program, to be conducted by the Office of Transportation and Air Quality (OTAQ) in the Office of Air and Radiation (OAR). This study will be designed to develop and test novel screening, sampling and measurement procedures. These approaches promise to substantially reduce the cost of exhaust emissions measurement as well as to improve the accuracy of resulting estimates.
An innovative feature of this project is the use of roadside remote-sensing measurements to construct a pool of vehicles from which vehicles can be sampled for purposes of recruitment and measurement using portable emissions measurement systems (PEMS). The acquisition of remote-sensing measurements for hydrocarbons, carbon-monoxide, and oxides of nitrogen will provide an index of emissions for all vehicles prior to sampling and recruitment for more intensive measurement. The index is expected to facilitate recruitment of vehicles with an emphasis on rare sub-populations such as high-emitting vehicles, and provide a means to appropriately relate measured vehicles to the overall fleet.
Research questions for the project include: (1) Can remote-sensing be used as a reliable index of exhaust emissions across the range of emissions? (2) can portable instruments measure accurate emissions time series for very clean vehicles, such as Tier 2 (Bins 2, 3 or 5) or LEV–II (ULEV, SULEV)? (3) how can portable instruments be used to measure start emissions?, and (4) can the emissions index used for recruitment also serve as a means to estimate potential non-response bias?
We have collected remote-sensing measurements on approximately 35,000 vehicles, and from this pool, plan to recruit vehicles for measurement using PEMS. Participation in the program will be voluntary. The target population for the project will include light-duty cars and trucks certified to Tier 2 (Bins 5, 3 or 2) or an equivalent LEV–II standards (LEV, ULEV or SULEV), respectively.
Section 309(a) of the Clean Air Act requires that EPA make public its comments on EISs issued by other Federal agencies. EPA's comment letters on EISs are available at:
Environmental Protection Agency (EPA).
Notice.
EPA's contractor, The Scientific Consulting Group (SCG), Inc., has identified a panel of scientific experts to conduct peer review of EPA's draft Toxic Substances Control Act (TSCA) chemical risk assessment, “TSCA Workplan Chemical Risk Assessment for Trichloroethylene: Degreaser and Arts/Crafts Uses.” EPA will hold three peer review meetings by web connect and teleconference. EPA invites the public to register to attend the meetings as observers and/or speakers providing oral comments during any or all of the peer review meetings as discussed in this notice. The public may also provide comment on whether they believe the appearance of conflict of interest exists for any proposed peer review panel expert.
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This action is directed to the public in general, and may be of interest to a wide range of stakeholders including those interested in environmental and human health assessment, the chemical industry, chemical users, consumer product companies, and members of the public interested in the assessment of chemical risks. Since others also may be interested, the Agency has not attempted to describe all the specific entities that may be affected by this action.
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i. Identify the document by docket ID number and other identifying information (subject heading,
ii. Follow directions. The Agency may ask you to respond to specific questions or organize comments by referencing a Code of Federal Regulations (CFR) part or section number.
iii. Explain why you agree or disagree; suggest alternatives and substitute language for your requested changes.
iv. Describe any assumptions and provide any technical information and/or data that you used.
v. If you estimate potential costs or burdens, explain how you arrived at your estimate in sufficient detail to allow for it to be reproduced.
vi. Provide specific examples to illustrate your concerns and suggest alternatives.
vii. Explain your views as clearly as possible, avoiding the use of profanity or personal threats.
viii. Make sure to submit your comments by the comment period deadline identified.
On January 9, 2013, EPA published a notice in the
This information is distributed solely for the purpose of pre-dissemination peer review under applicable information quality guidelines. It has not been formally disseminated by EPA. It does not represent and should not be construed to represent any Agency determination or policy.
The draft TCE TSCA risk assessment is being peer reviewed consistent with guidelines for the peer review of influential scientific information and highly influential scientific assessments. EPA asked a contractor, SCG, to assemble a panel of experts to evaluate the draft TCE TSCA risk assessment report for specific uses of TCE. SCG evaluated 27 candidates that were nominated as peer reviewers by the February 8, 2013 deadline established in the January 9, 2013
The peer review panel is responsible for the review of the scientific and technical merit of the draft TCE TSCA risk assessment, which is available through
The first peer review meeting on July 9, 2013, will be dedicated to hearing registered speakers' oral comments on the draft TCE TSCA risk assessment and reviewing the charge to the peer reviewers. Each speaker is allowed between 3–5 minutes, depending on the number of registered speakers. Given time constraints, a maximum of 30 speakers will be allowed to offer comments. If more than 30 speakers register to provide oral comments, speakers will be selected by SCG in a manner designed to optimize representation from all organizations, affiliations, and present a balance of science issues relevant to the Agency's TSCA risk assessment. Peer review panel members will have access to written comments and materials and electronic materials submitted to the docket by July 23, 2013. Registered observers and speakers will not be allowed to distribute any written comments or materials or electronic materials directly to the peer review panel members. To submit written comments, please follow one of the methods outlined in
The second peer review panel meeting on July 17, 2013, will be devoted to deliberations of the draft TCE TSCA risk assessment by the peer review panel, guided by the charge questions to the peer review panel.
The third and final peer review panel meeting on August 7, 2013, will focus on the peer review panel's discussion of its draft TCE TSCA risk assessment recommendations to EPA. The final peer review panel report will be prepared by SCG and made available to the public according to the Agency peer review guidance at
To attend the peer review meetings, you must register for the meeting no later than 11:59 p.m., EDT, on July 6, 2013. To register for the meeting go to
Members of the public may register to attend any or all three meetings as observers, or register to speak if planning to offer oral comments during the scheduled public comment session of a meeting. To register for the meetings online or by mail, you must provide your full name, organization or affiliation, and contact information. You must also indicate which meetings you plan to attend and if you would like to speak during the scheduled public comment session of a meeting. If you register to speak, you must also indicate if you have any special requirements related to your oral comments (e.g., translation).
If you indicate that you wish to speak, you will be asked to select one category most closely reflecting the content of your oral comments. These comment categories related to the charge questions are:
1. General comments on the risk assessment document;
2. Comments on the exposure assessment;
3. Comments on the hazard assessment;
4. Comments on the risk characterization; or
5. Other issues.
Should more than 30 speakers register for a single meeting, these categories will be used to ensure that a balance of substantive science issues relevant to the assessment is heard. Additional information on the selection of speakers and speaking times will be sent out by SCG 3 days prior to each peer review meeting to all individuals registered to speak.
To accommodate as many registered speakers as possible, registered speakers may present oral comments only, without visual aids or written material. Peer review panel members will have access to any written comments and materials and electronic materials previously submitted to the docket. Registered observers and speakers will not be allowed to distribute any written comments and materials or electronic materials directly to the peer review panel members.
Each peer review meeting will be held via web connect and teleconferencing. SCG will provide all registered participants with information on how to participate in advance of the first peer review meeting.
Environmental protection, Chemicals, Peer review, Risk assessments, Trichloroethylene.
Environmental Protection Agency (EPA).
Notice.
Based on documentation submitted by the U.S. Department of Energy (DOE) for the Waste Isolation Pilot Plant (WIPP), the U.S. Environmental Protection Agency (EPA or “we”) determined that, between 2010 and 2012, DOE operated the WIPP facility in compliance with applicable Federal statutes, regulations, and permit requirements designated in Section 9(a)(1) of the WIPP Land Withdrawal Act, as amended. The Secretary of Energy was notified of the determination via a letter from EPA Acting Administrator Bob Perciasepe dated May 29, 2013.
Nick Stone; telephone number: (214) 665–7226; address: WIPP Project Officer, Mail Code 6PD–O, U.S. Environmental Protection Agency, Region 6, 1445 Ross Avenue, Dallas, TX 75202.
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EPA made this determination under the authority of Section 9 of the WIPP Land Withdrawal Act (WIPP LWA, Pub. L. 102–579 and 104–201). Section 9(a)(1) of the WIPP LWA requires that, as of the date of the enactment of the WIPP LWA, DOE shall comply with respect to WIPP with (1) regulations for the management and storage of radioactive waste (40 CFR Part 191, Subpart A); (2) the Clean Air Act; (3) the Solid Waste Disposal Act; (4) the Safe Drinking Water Act; (5) the Toxic Substances Control Act; (6) the Comprehensive Environmental Response, Compensation, and Liability Act; and (7) all other applicable Federal laws pertaining to public health and safety or the environment. Section 9(a)(2) of the WIPP LWA requires DOE biennially to submit to EPA documentation of continued compliance with the laws, regulations, and permit requirements set forth in Section 9(a)(1). (DOE must also submit similar documentation of compliance with the Solid Waste Disposal Act to the State of New Mexico.) Section 9(a)(3) requires the Administrator of EPA to determine on a biennial basis, following the submittal of documentation of compliance by the Secretary of DOE, whether the WIPP is in compliance with the pertinent laws, regulations, and permit requirements, as set forth at Section 9(a)(1).
We determined that for the period 2010 to 2012, the DOE-submitted documentation showed continued compliance with 40 CFR Part 191, subpart A, the Clean Air Act, the Safe Drinking Water Act, the Toxic Substances Control Act, and the Comprehensive Environmental Response, Compensation, and Liability Act. With respect to other applicable Federal laws pertaining to public health and safety or the environment, as required by Section 9(a)(1)(G), DOE's documentation also indicates that DOE was in compliance with the Clean Water Act, the Federal Insecticide, Fungicide, and Rodenticide Act (FIFRA), and certain statutes under the jurisdiction of the Department of Interior.
This determination is not in any way related to, or a part of, our certification and recertification decisions regarding whether the WIPP complies with EPA's disposal regulations for transuranic radioactive waste at 40 CFR part 191.
Export-Import Bank of the United States.
Submission for OMB review and comments request.
The Export-Import Banks of the United States (Ex-Im Bank), as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal Agencies to comment on the proposed information collection, as required by the Paperwork Reduction Act of 1995.
The Letter of Interest (LI) is a pre-export tool to accelerate the start of the financing process. LI is an indication of Export-Import (Ex-Im) Bank's willingness to consider financing a given export transaction. Ex-Im Bank uses the requested information to determine the applicability of the proposed export transaction and determines whether or not to consider financing that transaction.
This application tool streamlines the LI application process by guiding the applicant via automated prompts to submit the information specifically required for the desired transaction. By presenting only the information necessary for the transaction, the application reduces user confusion and wasted effort. The application allows for payment by credit card.
The application tool can be reviewed at:
Comments must be received on or before August 6, 2013 to be assured of consideration.
Comments may be submitted electronically on
Export-Import Bank of the United States.
Submission for OMB Review and Comments Request.
The Export-Import Bank of the United States (Ex-Im Bank), as a part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal Agencies to comment on the proposed information collection, as required by the Paperwork Reduction Act of 1995.
The Application for Special Buyer Credit Limit under the Multi-Buyer Export Credit Insurance Policy is used by 2,500 policyholders, the majority of whom are U.S. small businesses, who export U.S. goods and services. This application provides Ex-Im Bank with the credit information necessary to make a determination of eligibility of a transaction for Ex-Im Bank support with a foreign buyer credit request and to obtain legislatively required assurance of repayment and fulfills other statutory requirements.
The application can be reviewed at:
Comments should be received on or before July 8, 2013 to be assured of consideration.
Comments may be submitted electronically on
Farm Credit Administration.
Notice is hereby given, pursuant to the Government in the Sunshine Act, of the regular meeting of the Farm Credit Administration Board (Board).
The regular meeting of the Board will be held at the offices of the Farm Credit Administration in McLean, Virginia, on June 13, 2013, from 9:00 a.m. until such time as the Board concludes its business.
Dale L. Aultman, Secretary to the Farm Credit Administration Board, (703) 883–4009, TTY (703) 883–4056.
Farm Credit Administration, 1501 Farm Credit Drive, McLean, Virginia 22102–5090.
Parts of this meeting of the Board will be open to the public (limited space available) and parts will be closed to the public. In order to increase the accessibility to Board meetings, persons requiring assistance should make arrangements in advance.
The matters to be considered at the meeting are:
* Session Closed-Exempt pursuant to 5 U.S.C. 552b(c)(8) and (9).
Federal Communications Commission.
Notice; request for comments.
As part of its continuing effort to reduce paperwork burden and as required by the Paperwork Reduction Act (PRA) of 1995 (44 U.S.C. 3501–3520), the Federal Communications Commission invites the general public and other Federal agencies to take this opportunity to comment on the following information collection(s). Comments are requested concerning: Whether the proposed collection of information is necessary for the proper performance of the functions of the Commission, including whether the information shall have practical utility; the accuracy of the Commission's burden estimate; ways to enhance the quality, utility, and clarity of the information collected; ways to minimize the burden of the collection of information on the respondents, including the use of automated collection techniques or other forms of information technology; and ways to further reduce the information burden for small business concerns with fewer than 25 employees.
The FCC may not conduct or sponsor a collection of information unless it displays a currently valid OMB control number. No person shall be subject to any penalty for failing to comply with a collection of information subject to the Paperwork Reduction Act (PRA) that does not display a valid OMB control number.
Written Paperwork Reduction Act (PRA) comments should be submitted on or before August 6, 2013. If you anticipate that you will be submitting PRA comments, but find it difficult to do so within the period of time allowed by this notice, you should advise the FCC contact listed below as soon as possible.
Submit your PRA comments to Nicholas A. Fraser, Office of Management and Budget (OMB), via fax at 202–395–5167 or via Internet at
To submit your PRA comments to the FCC by email send them to:
Judith B. Herman, FCC, Office of Managing Director, (202) 418–0214.
The Commission established a recordkeeping procedure in section 97.303(s) that required that amateur operator licensees using other antennas must maintain in their station records either manufacturer data on the antenna gain or calculations of the antenna gain.
The amateur radio service governed by 47 CFR part 97 of the Commission's rules, provides spectrum for amateur radio service licensees to participate in a voluntary noncommercial communication service which provides emergency communications and allows experimentation with various radio techniques and technologies to further the understanding of radio use and the development of technologies.
The information collection is used to calculate the effective radiated power (ERP) that the station is transmitting to ensure that ERP does not exceed 100 W PEP.
Federal Communications Commission.
Notice; request for comments.
As part of its continuing effort to reduce paperwork burden and as required by the Paperwork Reduction Act (PRA) of 1995 (44 U.S.C. 3502–3520), the Federal Communications Commission invites the general public and other Federal agencies to take this opportunity to comment on the following information collection(s). Comments are requested concerning: whether the proposed collection of information is necessary for the proper performance of the functions of the Commission, including whether the information shall have practical utility; the accuracy of the Commission's burden estimates; ways to enhance the quality, utility, and clarity of the information collected; ways to minimize the burden of the collection of information on the respondents, including the use of automated collection techniques or other forms of information technology; and ways to further reduce the information collection burden on small business concerns with fewer than 25 employees.
The FCC may not conduct or sponsor a collection of information unless it displays a currently valid OMB control number. No person shall be subject to any penalty for failing to comply with a collection of information subject to the Paperwork Reduction Act (PRA) that does not display a valid OMB control number.
Written Paperwork Reduction Act (PRA) comments should be submitted on or before July 8, 2013. If you anticipate that you will be submitting PRA comments, but find it difficult to do so within the period of time allowed by this notice, you should advise the FCC contact listed below as soon as possible.
Submit your PRA comments to Nicholas A. Fraser, Office of Management and Budget (OMB), via fax at 202–395–5167 or via Internet at
Judith B. Herman, Office of Managing Director, FCC, at 202–418–0214.
This collection involves information regarding the location of the demarcation point, antennas placed on subscriber premises, and the state of the market. In an October 2001 Order (FCC 22–366), the Commission adopted the following information collection requirements:
(1) Prohibited carriers from entering into contracts that restrict or effectively restrict a property owner's ability to permit entry by competing carriers;
(2) Established procedures to facilitate moving the demarcation point to the minimum point of entry (“MPOE”) at the building owner's request, and requires incumbent local exchange carriers (LECs) to timely disclose the location of existing demarcation points where they are not located at the MPOE;
(3) Determined that, under section 224 of the Communications Act of 1934, as amended, utilities, including LECs, must afford telecommunications carriers and cable service providers reasonable and nondiscriminatory access to conduits and rights-of-way located in customer buildings and campuses, to the extent such conduits and rights-of-way are owned or controlled by the utility; and
(4) Extended to antennas that receive and transmit telecommunications and other fixed wireless signals the existing prohibition of restrictions that impair the installation, maintenance or use of certain video antennas on property within the exclusive use or control of the antenna user, where the user has a direct or indirect ownership or leasehold interest in the property.
This collection has two parts. The first part requires that manufacturers, dealers, distributors, and other entities that sell or lease wireless microphones must display a disclosure at the point of sale or lease that informs consumers of the conditions that apply to the operation of wireless microphones. The second part establishes a labeling requirement for wireless microphones capable of operating in the 700 MHz band that are destined for non-U.S. markets.
The Commission requires all incumbent local exchange carriers (ILECs) to file shapefile maps of their service territories in a state (study area). State commissions can also submit these data voluntarily for ILECs in their state. Shapefiles are a commonly used, digitized, geographic information system (GIS) format. Accurate and accessible maps are essential to the legitimate distribution of universal service support to rural, high cost carriers. After the shapefiles are uploaded into a web interface provided by the Commission, each ILEC (or state) must certify the accuracy of its study area maps. Filers must also submit updated shapefile maps if their study area boundaries change, and must recertify the accuracy of the map every two years.
Federal Deposit Insurance Corporation.
Update listing of financial institutions in liquidation.
Notice is hereby given that the Federal Deposit Insurance Corporation (Corporation) has been
The notificants listed below have applied under the Change in Bank Control Act (12 U.S.C. 1817(j)) and § 225.41 of the Board's Regulation Y (12 CFR 225.41) to acquire shares of a bank or bank holding company. The factors that are considered in acting on the notices are set forth in paragraph 7 of the Act (12 U.S.C. 1817(j)(7)).
The notices are available for immediate inspection at the Federal Reserve Bank indicated. The notices also will be available for inspection at the offices of the Board of Governors. Interested persons may express their views in writing to the Reserve Bank indicated for that notice or to the offices of the Board of Governors. Comments must be received not later than June 21, 2013.
A. Federal Reserve Bank of Chicago (Colette A. Fried, Assistant Vice President) 230 South LaSalle Street, Chicago, Illinois 60690–1414:
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The companies listed in this notice have applied to the Board for approval, pursuant to the Bank Holding Company Act of 1956 (12 U.S.C. 1841
The applications listed below, as well as other related filings required by the Board, are available for immediate inspection at the Federal Reserve Bank indicated. The applications will also be available for inspection at the offices of the Board of Governors. Interested persons may express their views in writing on the standards enumerated in the BHC Act (12 U.S.C. 1842(c)). If the proposal also involves the acquisition of a nonbanking company, the review also includes whether the acquisition of the nonbanking company complies with the standards in section 4 of the BHC Act (12 U.S.C. 1843). Unless otherwise noted, nonbanking activities will be conducted throughout the United States.
Unless otherwise noted, comments regarding each of these applications must be received at the Reserve Bank indicated or the offices of the Board of Governors not later than July 1, 2013.
A. Federal Reserve Bank of Dallas (E. Ann Worthy, Vice President) 2200 North Pearl Street, Dallas, Texas 75201–2272:
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Office of Government-wide Policy, U.S. General Services Administration (GSA).
Meeting Notice.
The President's Commission on Election Administration (PCEA), a Federal Advisory Committee established in accordance with the Federal Advisory Committee Act (FACA), 5 U.S.C., App., and Executive Order 13639, as amended by EO 13644, will hold a meeting open to the public on Friday, June 21, 2013.
Mr. Mark Nejbauer, Designated Federal Officer, President's Commission on Election Administration, GSA, 1776 G Street NW., Washington, DC 20006, email
The public is invited to submit written comments for this meeting until 5:00 p.m. eastern time on Tuesday, June 18th, 2013, by either of the following method:
The Centers for Disease Control and Prevention (CDC) publishes a list of information collection requests under review by the Office of Management and Budget (OMB) in compliance with the Paperwork Reduction Act (44 U.S.C. Chapter 35). To request a copy of these requests, call (404) 639–7570 or send an email to
School Health Policies and Practices Study (formerly titled School Health Policies and Programs Study, OMB No. 0920–0445, exp. 9/30/2012)—Reinstatement with Changes—Division of Adolescent and School Health (DASH), National Center for HIV/AIDS, Viral Hepatitis, STD, and TB Prevention (NCHHSTP), Centers for Disease Control and Prevention, (CDC).
CDC has previously examined the role schools play in addressing health risk behaviors through the School Health Policies and Programs Study (SHPPS, OMB NO. 0920–0445), a series of data collections conducted at the state, district, school, and classroom levels in 1994 (OMB No. 0920–0340, exp. 1/31/1995), 2000 (OMB No. 0920–0445, exp. 10/31/2002), 2006 (OMB No. 0920–0445, exp. 11/30/2008), and 2012 (OMB No. 0920–0445, exp. 9/30/2012).
CDC plans to reinstate data collection in 2014 and 2016 with changes. SHPPS will assess the characteristics of eight components of school health programs at the elementary, middle, and high school levels: health education, physical education, health services, mental health and social services, nutrition services, healthy and safe school environment, faculty and staff health promotion, and family and community involvement. This data collection will take place at the school- and classroom-levels in 2014 and at the district level in 2016. The school- and classroom-level data collection proposed for 2014 was approved for 2012 but was not conducted because of insufficient funds.
Sixteen questionnaires will be used: seven at the district level, seven at the school level and two at the classroom level. The school- and classroom-level questionnaires will be identical to those approved for data collection in 2012. The district-level questionnaires will include minor modifications to the 2012 questionnaires. For example, question wording will be revised to improve clarity. The school-level data collection also will include vending machine observations, which will yield the only nationally representative dataset of snack and beverage offerings available to students through school vending machines. These observations were a part of the 2012 study protocol but were not conducted because of insufficient funds.
The SHPPS data collection will have significant implications for policy and program development for school health programs nationwide. The results will be used by Federal agencies, state and local education and health agencies, the private sector, and others to support school health programs; monitor progress toward achieving health and education goals and objectives; develop educational programs, demonstration efforts, and professional education/training; and initiate other relevant research initiatives to contribute to the reduction of health risk behaviors among our nation's youth. SHPPS data also will be used to provide measures for 14 Healthy People 2020 national health objectives. No other national source of data exists for these objectives. The data also will have significant implications for policy and program development for school health programs nationwide. The combined total burden hours estimated for the 2014 and 2016 SHPPS and associated support activities are 9,722.
There are no costs to respondents other than their time.
The Centers for Disease Control and Prevention (CDC) publishes a list of information collection requests under review by the Office of Management and Budget (OMB) in compliance with the Paperwork Reduction Act (44 U.S.C. Chapter 35). To request a copy of these requests, call (404) 639–7570 or send an email to
Frame Development for the Residential Care Component of the National Study of Long-Term Care Providers (OMB No. 0920–0912, expired 1/31/2013)—Reinstatement no change—National Center for Health Statistics (NCHS), Centers for Disease Control and Prevention (CDC).
NCHS seeks approval to collect data needed to develop up-to-date sampling frames of residential care facilities. Three year clearance is requested. Section 306 of the Public Health Service (PHS) Act (42 U.S.C. 242k), as amended, authorizes that the Secretary of Health and Human Services (DHHS), acting through NCHS, “shall collect statistics on health resources. . . [and] utilization of health care, including extended care facilities, and other institutions.”
The sampling frames will be used to draw nationally representative samples for two waves of the National Study of Long-Term Care Providers (NSLTCP). The frame-related data will be collected from representatives in state regulatory agencies in the 50 states and the District of Columbia primarily via telephone calls, emails, and in a few cases, via formal written requests. The frame information was first collected in 2012 (OMB No. 0920–0912, expired 1/31/2013). The data to be collected from these state officials include (1) confirming that we have identified the appropriate licensure categories of residential care facilities within each state that meet the NSLTCP definition and (2) for each relevant licensure category, requesting an electronic file of the licensed residential care facilities for which the agency is responsible if such files with the needed variables are not downloadable from the state's Web site.
The NSLTCP study definition of a residential care facility is one that is licensed, registered, listed, certified, or otherwise regulated by the state to provide room and board with at least two meals a day, provide around-the-clock on-site supervision, and help with activities of daily living (e.g., bathing, eating, or dressing) or health related services, such as medication supervision; serves primarily an adult population; and has at least four licensed, certified, or regulated beds. Facilities licensed to serve the mentally ill or the intellectually disabled/developmentally disabled populations exclusively are excluded. Nursing homes and skilled nursing facilities are also excluded, unless they have a unit or wing meeting the above definition and residents can be separately enumerated.
The electronic files we seek to obtain from the states should include the name, address, phone number, and Web site (if available) of the residential care facility; name, phone number, and email address (if available) of facility director; licensure category; chain affiliation; ownership type; and bed size. Data on individual facilities are confidential and a public-use file will not be produced.
Expected users of the findings from the frame data include, but are not limited to CDC's NCHS and its contractors; other Department of Health and Human Services (DHHS) agencies, such as the Office of the Assistant Secretary for Planning and Evaluation and the Agency for Healthcare Research and Quality; associations, such as
Burden is estimated at approximately 2.5 hours per state each time the frame will be developed, including time to verify contact information, to respond to a semi-structured telephone protocol, and to develop the facility listing in an electronic format. Three year clearance is requested to cover two collections of frame information. The burden for the two collections is shown in Table 1 below. There is no cost to respondents other than their time to participate. The total estimate of annualized burden is 88 hours based on two data collections during the three year clearance period.
Notice.
The Centers for Medicare & Medicaid Services (CMS) is announcing an opportunity for the public to comment on CMS' intention to collect information from the public. Under the Paperwork Reduction Act of 1995 (PRA), federal agencies are required to publish notice in the
Comments must be received by August 6, 2013.
When commenting, please reference the document identifier or OMB control number (OCN). To be assured consideration, comments and recommendations must be submitted in any one of the following ways:
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To obtain copies of a supporting statement and any related forms for the proposed collection(s) summarized in this notice, you may make your request using one of following:
1. Access CMS' Web site address at
2. Email your request, including your address, phone number, OMB number, and CMS document identifier, to
3. Call the Reports Clearance Office at (410) 786–1326.
Reports Clearance Office at (410) 786–1326.
This notice sets out a summary of the use and burden associated with the following information collections:
More detailed information can be found in each collection's supporting statement and associated materials (see
Under the Paperwork Reduction Act of 1995 (PRA) (44 U.S.C. 3501–3520), federal agencies must obtain approval from the Office of Management and Budget (OMB) for each collection of information they conduct or sponsor. The term “collection of information” is defined in 44 U.S.C. 3502(3) and 5 CFR 1320.3(c) and includes agency requests or requirements that members of the public submit reports, keep records, or
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Subsequent to the first publication, we determined that we will measure Medicaid and CHIP in the same state. Therefore, states will measure Medicaid and CHIP eligibility in the same year measured for fee-for-service and managed care. We believe this approach will advantage states through economies of scale (
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The HITECH Act creates incentive programs for EPs and eligible hospitals, including CAHs, in the Medicare Fee-for-Service (FFS), MA, and Medicaid programs that successfully demonstrate meaningful use of certified EHR technology. In their first payment year, Medicaid EPs and eligible hospitals may adopt, implement or upgrade to certified EHR technology. It also, provides for payment adjustments in the Medicare FFS and MA programs starting in FY 2015 for EPs and eligible hospitals participating in Medicare that are not meaningful users of certified EHR technology. These payment adjustments do not pertain to Medicaid providers.
The first final rule for the Medicare and Medicaid EHR Incentive Program, which was published in the
The information collection requirements contained in this information collection request are needed to implement the HITECH Act. In order to avoid duplicate payments, all EPs are enumerated through their National Provider Identifier (NPI), while all eligible hospitals and CAHs are enumerated through their CMS Certification Number (CCN). State Medicaid agencies and CMS use the provider's tax identification number and NPI or CCN combination in order to make payment, validate payment eligibility and detect and prevent duplicate payments for EPs, eligible hospitals and CAHs.
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Enrollees have the option of submitting either a CMS 855 form, or submitting information via a web based process. In establishing a web based application process, we allow providers and suppliers the ability to enroll in the Medicare program, revalidate their enrollment and make changes to their enrollment information via Internet-based Provider Enrollment, Chain and Ownership System (PECOS). Individual providers/suppliers (hereinafter referred to as “Individual Providers”) log into Internet-based PECOS using their User IDs and passwords established when they applied on-line to the National Plan and Provider Enumeration System (NPPES) for their National Provider Identifiers (NPIs). Authorized Officials (AOs) of the provider or supplier organizations (hereinafter referred to as “Organizational Providers”) must register for a user account and authenticate their identity and connection to the organization they represent before being able to log into Internet-based PECOS. Once authenticated, AOs for Organizational Providers, receive complete access to their enrollment information via Internet-based PECOS. Individuals and AOs of Organizational Providers are not required to submit a Security Consent and Surrogate Authorization Form to enroll, revalidate or make changes to their Medicare enrollment information.
Individual and Organizational Providers may complete their Medicare enrollment responsibilities on their own or elect to delegate this task to a Surrogate. A Surrogate is an individual or organization identified by an Individual or Organizational Provider as someone authorized to access CMS computer systems, such as Internet-based PECOS, National Provider Plan and Enumeration System (NPPES) and the Medicare and Medicaid Electronic Health Records (EHR) Incentive Program Registration and Attestation System (HITECH), on their behalf and to modify or view any information contained therein that the Individual or Organizational Provider may have permission or right to access in accordance with Medicare statutes, regulations, policies, and usage guidelines for any CMS system. Surrogates may consist of administrative staff, independent contractors, 3rd party consulting companies or credentialing departments. In order for an Individual or Organizational Provider to delegate the Medicare credentialing process to a Surrogate to access and update their enrollment information in the above mentioned CMS systems on their behalf, it is required that a Security Consent and Surrogate Authorization Form be completed, or Individual and Organizational Providers use an equivalent online process via the PECOS Identity and Access Management (I&A) system. The Security Consent and Surrogate Authorization form replicates business service agreements between Medicare providers, suppliers or both and Surrogates providing enrollment services.
We are proposing one version of the Security Consent and Surrogate Authorization Form. The form, once signed, mailed and approved, grants a Surrogate access to all current and future enrollment data for the Individual or Organization Provider.
10.
Notice.
The Centers for Medicare & Medicaid Services (CMS) is announcing an opportunity for the public to comment on CMS' intention to collect information from the public. Under the
Comments on the collection(s) of information must be received by the OMB desk officer by July 8, 2013.
When commenting on the proposed information collections, please reference the document identifier or OMB control number. To be assured consideration, comments and recommendations must be received by the OMB desk officer via one of the following transmissions:
To obtain copies of a supporting statement and any related forms for the proposed collection(s) summarized in this notice, you may make your request using one of following:
1. Access CMS' Web site address at
2. Email your request, including your address, phone number, OMB number, and CMS document identifier, to
3. Call the Reports Clearance Office at (410) 786–1326.
Reports Clearance Office at (410) 786–1326
Under the Paperwork Reduction Act of 1995 (PRA) (44 U.S.C. 3501–3520), federal Agencies must obtain approval from the Office of Management and Budget (OMB) for each collection of information they conduct or sponsor. The term “collection of information” is defined in 44 U.S.C. 3502(3) and 5 CFR 1320.3(c) and includes agency requests or requirements that members of the public submit reports, keep records, or provide information to a third party. Section 3506(c)(2)(A) of the PRA (44 U.S.C. 3506(c)(2)(A)) requires federal agencies to publish a 30-day notice in the
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We established the grandfathering process in the April 10, 2007 final rule for competitive bidding (72 FR 17992) for rented DME and oxygen and oxygen equipment when these items are included under the Medicare DMEPOS Competitive Bidding Program. This process only applies to suppliers that rented DME and oxygen and oxygen equipment to beneficiaries who maintain a permanent residence in a competitive bidding area (CBA) before the implementation of the competitive bidding program.
The competitive bidding program will require some beneficiaries to change their suppliers. To avoid a beneficiary being without medically necessary equipment we believe it is necessary to establish this notification process. The notification to the beneficiaries is a beneficiary protection that will keep them informed of whether or not they can continue to rent an item from their current supplier or go to a contract supplier. The notification will also provide information to the beneficiary as to how to find a contract supplier in their CBA. In the event that the beneficiary must go to a contract supplier, the notification will identify the procedure for the pick-up of their current equipment and delivery of new equipment.
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42 U.S.C. 612 (Section 412 of the Social Security Act) requires each Indian Tribe that elects to administer and operate a Temporary Assistance for Needy Families (TANF) program to submit a TANF Tribal Plan. The TANF Tribal Plan is a mandatory statement submitted to the Secretary by the Indian Tribe, which consists of an outline of how the Indian Tribes TANF program will be administered and operated. It is used by the Secretary to determine whether the plan is approvable and to determine that the Indian Tribe is eligible to receive a TANF assistance grant. It is also made available to the public.
Indian Tribes applying to operate a TANF program.
Copies of the proposed collection may be obtained by writing to the Administration for Children and Families, Office of Planning, Research and Evaluation, 370 L'Enfant Promenade SW., Washington, DC 20447, Attn: ACF Reports Clearance Officer. All requests should be identified by the title of the information collection. Email address:
OMB is required to make a decision concerning the collection of information between 30 and 60 days after publication of this document in the
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA) is announcing the availability of a final guidance document entitled “Technical Considerations for Pen, Jet, and Related Injectors Intended for Use With Drugs and Biological Products,” dated June 2013. The final guidance document provides technical and scientific
Submit either electronic or written comments on Agency guidances at any time.
Submit written requests for single copies of the guidance to the Office of Combination Products, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 32, Rm. 5129, Silver Spring, MD 20993. Send one self-addressed adhesive label to assist the office in processing your requests. The guidance may also be obtained by mail by calling the Office of Combination Products at 301–796–8930. See the
Submit electronic comments on the guidance to
Patricia Y. Love, Office of Combination Products, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 32, Rm. 5129, Silver Spring, MD 20993.
FDA is announcing the availability of a document entitled “Guidance for Industry and FDA Staff: Technical Considerations for Pen, Jet, and Related Injectors Intended for Use With Drugs and Biological Products” dated June 2013. FDA is providing this final guidance document to assist industry in developing technical and scientific information to support a marketing application for a pen, jet, or related injector device. The marketing application would typically be a 510(k) or a PMA application for the injector alone. For a combination product that includes the injector, the marketing application would typically be an NDA or a BLA. For purposes of this guidance, the term injector includes, but is not limited to, jet injectors, pen injectors, piston syringes, needle-free injectors, mechanically operated injectors, and injectors with computerized or electronic elements.
In the
The guidance is being issued consistent with FDA's good guidance practices regulation (21 CFR 10.115). The guidance represents FDA's current thinking on this topic. It does not create or confer any rights for or on any person and does not operate to bind FDA or the public. An alternative approach may be used if such approach satisfies the requirements of the applicable statutes and regulations.
This guidance contains information collection provisions that are subject to review and have been approved by the Office of Management and Budget (OMB) under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501–3520). The collections of information in 21 CFR part 807 have been approved under OMB control number 0910–0120. The collections of information in 21 CFR part 814 have been approved under OMB control number 0910–0231. The collections of information in 21 CFR part 314 have been approved under OMB control number 0910–0001. The collections of information in 21 CFR part 601 have been approved under OMB control number 0910–0338.
Interested persons may submit either electronic comments regarding this document to
Persons with access to the Internet may obtain the guidance at either
Food and Drug Administration, HHS.
Notice of public workshop; request for comments.
The Food and Drug Administration (FDA), Center for Tobacco Products (CTP), is announcing a 1-day workshop to obtain public input on topics related to the potential electronic submission of tobacco product applications and other information. This workshop will focus on the technical aspects of electronic submissions, including potential standards for content, format, and structure. The input from the public workshop may assist the Agency in the potential development and implementation of an electronic submission standard for CTP. FDA is also opening a public docket to receive comments on this topic.
If you need special accommodations because of disability, please contact Karen M. Templeton-Somers (see
The purpose of this workshop is to obtain public input from regulated industry and other stakeholders and interested parties on the potential development and implementation of a standardized structure for electronic submission of tobacco product applications and other information. Stakeholders and interested parties could include, but are not limited to, large and small pharmaceutical manufacturers with experience in electronic submissions; vendors of software used to support electronic submissions; and large and small tobacco product manufacturers. The workshop will focus on technical aspects related to electronic submissions and standards currently used in other FDA centers. The types of submissions potentially subject to any future electronic submission standard may include, but are not limited to, applications for premarket review of new tobacco products (section 910(b)(1) of the Federal Food, Drug, and Cosmetic Act) (the FD&C Act) (21 U.S.C. 387j(b)(1)), modified risk tobacco product applications (section 911(d) of the FD&C Act (21 U.S.C. 387k(d)), and reports submitted under section 905(j) of the FD&C Act (21 U.S.C. 387e(j)). In particular, FDA would like to discuss how available standardized submission structure and technologies facilitate preparation, submission, retrieval, processing, review, and archiving of submissions. For more information on study data standards resources, please see
The electronic submission workshop will include discussion on eCTD, which is an International Conference on Harmonization (ICH) specification developed by ICH and its member parties. The eCTD provides an organizational structure for regulatory submissions utilizing comprehensive table of contents headings and hierarchy. Other FDA centers have been receiving submissions in the eCTD format since 2003. For more information on eCTD, please see
CTP is interested in receiving input at the workshop and in the docket on the potential standardization of electronic tobacco product submissions. The input from the workshop may assist the Agency in developing and implementing a harmonized electronic submission standard at CTP.
FDA is seeking public input on the following topics:
• How have other regulated industries standardized the structure of submissions to FDA and how has that facilitated the submission and review process? What aspects may be applicable to tobacco product submissions?
• What technologies do tobacco companies currently use to prepare their submissions? Is a document management system used? Are specific technologies used? Is electronic data capture used in clinical trials or other
• How are data collected and managed for submission to CTP? Is a laboratory information management system used?
• Are there any technical limitations CTP should consider in developing and implementing any harmonized electronic submission standard?
• Would a pilot program designed to test a modified eCTD be useful?
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meetings.
The meetings will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Notice is hereby given of a change in the meeting of the National Cancer Institute Clinical Trials and Translational Research Advisory Committee, July 10, 2013, 09:00 a.m. to July 10, 2013, 04:00 p.m., National Institutes of Health, 31 Center Drive, Building 31, C Wing, 6th Floor, Conference Room 10, Bethesda, MD, 20892 which was published in the
The notice is being amended to change the meeting format and time. The meeting will be held as a virtual meeting on July 10, 2013, 10:00 a.m. to 12:00 p.m. The webinar meeting may be viewed at
U.S. Customs and Border Protection, Department of Homeland Security.
General notice.
This notice announces U.S. Customs and Border Protection's (“CBP's”) plan to conduct a voluntary general test regarding certain foreign-trade zone (“FTZ” or “zone”) activities. Pursuant to the FTZ test, under
The FTZ test is intended to evaluate whether liberalizing certain FTZ operational procedures will impact CBP's supervision and control over the zone, as well as the agency's ability to enforce applicable laws. This notice invites public comment concerning any aspect of the planned test, describes the eligibility, procedural and documentation requirements for voluntary participation in the test, and outlines the development and evaluation methodology to be used in the test.
A zone operator interested in voluntary participation in the FTZ test must submit an email to CBP establishing that he or she meets the eligibility criteria for participation in the test by July 8, 2013. CBP will notify interested parties of their test participation status within 10 calendar days of receipt of the email requesting participation in the test. The initial phase of the FTZ test will commence July 17, 2013, and will run for approximately two years. CBP will begin an evaluation of this test approximately 90 days after the test's commencement.
Comments concerning this notice or any aspect of the test may be submitted via email, with a subject line identifier reading “Comment on FTZ Test,” to
Alyce Modesto, Acting Director, Cargo Security and Control, Office of Field Operations, (202) 344–2549 or via email at
A Foreign-Trade Zone (“FTZ” or “zone”) is a secure area under U.S. Customs and Border Protection (“CBP”) control and supervision that is within the United States, but considered to be outside the customs territory of the United States. Formal CBP entry procedures and payments of duties are not required on foreign merchandise lawfully within the FTZ until the merchandise enters the U.S. customs territory for domestic consumption. Merchandise that is lawfully admitted to an FTZ may undergo prescribed activities, such as storage, manipulation, manufacture, exhibition and destruction.
The Foreign-Trade Zones Act of 1934, as amended (19 U.S.C. 81a–81u), created the Foreign-Trade Zones Board (“FTZ Board”), which is responsible for the review and approval of applications to establish, operate and maintain FTZs. Upon approval, the FTZ Board issues a Grant of Authority to the zone grantee (the corporate recipient of the grant of authority for the establishment, operation, and maintenance of a zone project) to permit specified operations within the zone. Daily management of the zone is typically delegated to a zone operator (a CBP-approved entity that operates a zone under the terms of the Grant of Authority on behalf of the Zone grantee).
Before merchandise may be admitted into a zone, CBP must approve activation of the FTZ. CBP is responsible for the transfer of merchandise into and out of the zone and for matters involving revenue collection. The CBP port director, in whose port a zone is located, is charged with enforcing applicable laws and overseeing zone activity as the local representative of the FTZ Board. The port director controls the admission, handling, and disposition of merchandise within the zone, and the removal of merchandise from the zone.
The Foreign-Trade Zones Act is administered through two sets of regulations, the FTZ Board regulations (15 CFR Part 400) and CBP regulations (19 CFR Part 146). FTZs are also subject to the laws and regulations of the United States, as well as those of the states and communities in which they are located.
Under this FTZ test, zone operators who are approved FTZ test participants will be permitted liberalized procedures for two zone activities under prescribed circumstances. This test is intended to increase efficiencies and reduce administrative burdens for both CBP and the trade without compromising CBP's obligation to supervise and exercise control over the zone and enforce applicable laws. This test will evaluate whether liberalizing certain FTZ operational procedures will impact CBP's obligations.
Section 146.52(a), within subpart E of part 146 of the CBP regulations (19 CFR 146.52(a)), provides that a zone operator, prior to any action being taken, must apply for a permit on the CBP Form 216 (“Application for Foreign-Trade Zones Activity Permit”) to manipulate, manufacture, exhibit, or destroy merchandise in a zone or transfer merchandise for any purpose from a zone. The CBP Form 216 pertains to both individual and blanket permits. The blanket permit covers continuous or repetitive activity for up to a one-year period.
Under this FTZ test, approved test operators will not be required to submit a CBP Form 216 for permission to manipulate or manufacture goods, or exhibit goods under certain circumstances, within an FTZ if the subject activity has already been approved in the zone's Grant of Authority. In the case of exhibition of merchandise within a zone, a CBP Form 216 will not be required if the test operators can demonstrate that the conditions designated for exhibition are suitable for preventing confusion of the identity or status of the merchandise and that the approved test operator exercises adequate oversight of individuals granted access to the FTZ, including those present for purposes of the exhibition.
In these circumstances, CBP views the permit function served by the CBP Form 216 as duplicative and unnecessary inasmuch as the subject activities have already been permitted by the FTZ Board with CBP's concurrence. As the CBP port director has access to the zone's Grant of Authority, the elimination of the requirement to submit a CBP Form 216 that describes
It is noted that submission of a CBP 216 remains a requirement for approved test operators for the following zone activities:
• Destruction of goods.
• Sampling.
• Temporary removal of goods (including temporary removal for purposes of exhibition
• Manipulation or manufacture (including processing and production) of goods when the subject activity is
Section 146.71, within subpart F of part 146 of the CBP regulations (19 CFR 146.71), prescribes the release and removal of merchandise from a zone. Paragraph (a) states that, except as provided for in § 146.43, no merchandise will be transferred from a zone without a CBP permit on the appropriate entry or withdrawal form or other document as required in this part. Section 146.71(c) provides that, except in the case of articles for use in a zone, merchandise for which a CBP permit for transfer to U.S. customs territory has been issued must be physically removed from the zone within five (5) working days of issuance of that permit and that merchandise awaiting removal within the required time limit will not be further manipulated or manufactured in the zone, but will be segregated or otherwise identified by the operator as merchandise that has been constructively transferred to the U.S. customs territory.
Pursuant to this FTZ test, an approved test operator will have the option of allowing duty-paid merchandise that has been entered for consumption to remain in an activated zone area for up to 90 calendar days after CBP releases the merchandise, so long as the merchandise remains segregated, does not undergo further manufacturing, and is accurately recorded in the Inventory Control and Recordkeeping (“ICR”) system within five (5) business days of release. Such merchandise is considered to be constructively transferred to the customs territory of the United States and, while remaining in the zone, will have no zone status.
Elimination of the requirement, for purposes of this FTZ test, to remove merchandise from a zone within the prescribed 5-day period after release is intended to benefit the trade by permitting them to focus on production and accurate maintenance of their ICR system, rather than the timing of merchandise moving in and out of the zone. In addition, in situations where data or documentation from other government agencies is required, elimination of the 5-day zone removal requirement is intended to simplify logistics in that merchandise will not have to be moved from a secured FTZ location pending receipt of that information.
Participation in this FTZ test is voluntary and open to all FTZ operators who timely notify CBP of their interest in participating in the test and establish, to CBP's satisfaction, that they: (1) Are authorized and approved in an activated FTZ; (2) have an approved FTZ operator bond on file with CBP; and (3) can demonstrate the ability to comply with the requirements of the test.
This FTZ test is being conducted in accordance with § 101.9(a) of the CBP regulations (19 CFR 101.9(a)), which prescribes general test requirements.
The following regulatory provisions will be suspended to the extent that they conflict with the terms of this FTZ test. The regulatory suspensions will remain in effect for the duration of this test and will apply to approved test participants only; the regulatory provisions remain in effect for all non-test participants:
• Section 146.51, which requires that no merchandise, other than domestic status merchandise provided for in § 146.43, will be manipulated, manufactured, exhibited, destroyed or transferred from a zone in any manner or for any purpose, except under CBP permit.
• Section 146.52(a), to the extent that it requires a zone operator, prior to any action being taken, to apply for a blanket permit on the CBP Form 216 to manipulate, manufacture, or exhibit merchandise in a zone.
• Section 146.71(c), which requires that merchandise for which a CBP permit for transfer to the U.S. customs territory has been issued must be physically removed from the zone within five (5) working days of issuance of that permit, except in the case of articles for use in a zone.
This FTZ test will commence no earlier than July 17, 2013, and will run for approximately two years from that date with a final evaluation to take place at the end of the test period. CBP may extend, terminate, or change the terms of the test at any time, by way of announcement in the
CBP will begin an evaluation of the FTZ test approximately 90 days after its commencement.
An FTZ test participant may be subject to civil and criminal penalties, administrative sanctions, liquidated damages, and/or discontinuance from participation in this test for any of the following:
• Failure to follow the terms and conditions of this test.
• Failure to exercise reasonable care in the execution of participant obligations.
• Failure to abide by applicable laws and regulations that have not been waived.
The Director, Cargo Security and Control, Office of Field Operations, CBP Headquarters, will administer the suspension or revocation of participation privileges for misconduct under the test. CBP will issue a written notice to the test participant that describes the proposed action and includes a description of the facts or conduct warranting the action. The test participant may appeal the decision, in writing, within ten (10) calendar days of receipt of the written notice. The appeal must be submitted to U.S. Customs and
Except in the case of willful misconduct, or where a test participant's conduct may cause immediate harm to the public health, interest, or safety, a proposed discontinuance of a test participant's participation privileges will not take effect until the time to file an appeal has expired. In the case of willful misconduct, or where a test participant's conduct may cause immediate harm to the public health, interest, or safety, the Director, Cargo Security and Control, OFO, may immediately discontinue a participant's test privileges upon written notice to the test participant. The notice will contain a description of the facts or conduct warranting the immediate action.
The test participant will be offered the opportunity to appeal the decision within ten (10) calendar days of receipt of the written notice providing for immediate discontinuance. The appeal must be submitted to U.S. Customs and Border Protection, Office of Field Operations, CCS, 1300 Pennsylvania Ave. NW., Suite 2.3D, Washington, DC 20229–1015 or by email to
The following is a non-exhaustive list of evaluation factors that CBP may use to assess the merits of the FTZ test:
1. Workload impact;
2. Policy and procedure accommodations;
3. Cost savings;
4. Trade compliance impact;
5. System efficiency;
6. Operational efficiency; or
7. Other issues raised by public comment or by the test participants.
Results of the FTZ test will be formulated at the conclusion of the test and will be made available to the public upon request.
Office of the Assistant Secretary for Community Planning and Development, HUD.
Notice.
This Notice identifies unutilized, underutilized, excess, and surplus Federal property reviewed by HUD for suitability for use to assist the homeless.
Juanita Perry, Department of Housing and Urban Development, 451 Seventh Street SW., Room 7266, Washington, DC 20410; telephone (202) 402–3970; TTY number for the hearing- and speech-impaired (202) 708–2565 (these telephone numbers are not toll-free), or call the toll-free Title V information line at 800–927–7588.
In accordance with 24 CFR part 581 and section 501 of the Stewart B. McKinney Homeless Assistance Act (42 U.S.C. 11411), as amended, HUD is publishing this Notice to identify Federal buildings and other real property that HUD has reviewed for suitability for use to assist the homeless. The properties were reviewed using information provided to HUD by Federal landholding agencies regarding unutilized and underutilized buildings and real property controlled by such agencies or by GSA regarding its inventory of excess or surplus Federal property. This Notice is also published in order to comply with the December 12, 1988 Court Order in
Properties reviewed are listed in this Notice according to the following categories: Suitable/available, suitable/unavailable, and suitable/to be excess, and unsuitable. The properties listed in the three suitable categories have been reviewed by the landholding agencies, and each agency has transmitted to HUD: (1) Its intention to make the property available for use to assist the homeless, (2) its intention to declare the property excess to the agency's needs, or (3) a statement of the reasons that the property cannot be declared excess or made available for use as facilities to assist the homeless.
Properties listed as suitable/available will be available exclusively for homeless use for a period of 60 days from the date of this Notice. Where property is described as for “off-site use only” recipients of the property will be required to relocate the building to their own site at their own expense. Homeless assistance providers interested in any such property should send a written expression of interest to HHS, addressed to Theresa Ritta, Office of Enterprise Support Programs, Program Support Center, HHS, room 12–07, 5600 Fishers Lane, Rockville, MD 20857; (301) 443–2265. (This is not a toll-free number.) HHS will mail to the interested provider an application packet, which will include instructions for completing the application. In order to maximize the opportunity to utilize a suitable property, providers should submit their written expressions of interest as soon as possible. For complete details concerning the processing of applications, the reader is encouraged to refer to the interim rule governing this program, 24 CFR part 581.
For properties listed as suitable/to be excess, that property may, if subsequently accepted as excess by GSA, be made available for use by the homeless in accordance with applicable law, subject to screening for other Federal use. At the appropriate time, HUD will publish the property in a Notice showing it as either suitable/available or suitable/unavailable.
For properties listed as suitable/unavailable, the landholding agency has decided that the property cannot be declared excess or made available for use to assist the homeless, and the property will not be available.
Properties listed as unsuitable will not be made available for any other purpose for 20 days from the date of this Notice. Homeless assistance providers interested in a review by HUD of the determination of unsuitability should call the toll free information line at 1–800–927–7588 for detailed instructions or write a letter to Ann Marie Oliva at the address listed at the beginning of this Notice. Included in the request for review should be the property address (including zip code), the date of publication in the
For more information regarding particular properties identified in this Notice (i.e., acreage, floor plan, existing sanitary facilities, exact street address), providers should contact the appropriate landholding agencies at the following addresses:
Fish and Wildlife Service, Interior.
Notice of availability.
We, the U.S. Fish and Wildlife Service (Service), are advising the public of the availability of the Final Environmental Impact Statement (FEIS) associated with an application received from NiSource Inc. (hereafter “NiSource”) for an incidental take permit (hereafter “ITP”) pursuant to Section 10(a)(1)(B) of the Endangered Species Act of 1973, as amended (ESA). If issued, the ITP would authorize NiSource to take 10 federally listed species over a 50-year period. For record of decision availability, see DATES. For directions on how to review the FEIS and related documents, see
The Record of Decision will be available no sooner than July 8, 2013.
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•
•
Thomas J. Magnuson, Regional HCP Coordinator, U.S. Fish and Wildlife Service, 5600 American Blvd. West, Suite 990, Bloomington, Minnesota 55437–1458; 612–713–5467.
We are advising the public of the availability of the Final Environmental Impact Statement (FEIS) associated with an application received from NiSource ITP pursuant to the ESA. If issued, the ITP would authorize NiSource to take 10 federally listed species over a 50-year period.
NiSource prepared a multi-species habitat conservation plan (MSHCP) to cover a suite of activities associated with operation, maintenance, and construction of their existing natural gas pipeline system in the States of Delaware, Indiana, Kentucky, Louisiana, Maryland, Mississippi, New Jersey, New York, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, and West Virginia.
The Service was the lead Federal agency for preparation of the FEIS. The Federal Energy Regulatory Commission (FERC), the U.S. Army Corps of Engineers (USACE), the U.S. Department of Agriculture (USDA) Forest Service (FS) Eastern Region and Southern Region, and the National Park Service (NPS) Southeast Region served as cooperating agencies.
NiSource, Inc., headquartered in Merrillville, Indiana, is engaged in natural gas transmission, storage, and distribution, as well as electric generation, transmission, and distribution. NiSource, Inc.'s wholly owned pipeline subsidiaries, Columbia Gas Transmission, LLC; Columbia Gulf Transmission LLC; Crossroads Pipeline Company; Central Kentucky Transmission Company; and NiSource Gas Transmission and Storage Company (companies referred to collectively as “NiSource”), are interstate natural gas companies whose primary operations are subject to the Natural Gas Act (15 U.S.C. 717) and fall under the jurisdiction of the Federal Energy Regulatory Commission (FERC) and the U.S. Department of Transportation (USDOT). NiSource is seeking authorization under the ESA to take species in the course of engaging in otherwise lawful gas transmission and storage operations.
On July 16, 2009, NiSource filed an application with the Service for a Section 10(a)(1)(B) ITP for 10 ESA listed species known to occur within NiSource's operating territory. These species include the Indiana bat (
The Covered Land for the MSHCP and requested ITP includes 12 counties in Maryland, Ohio, Pennsylvania, and West Virginia; and a 1-mile-wide corridor associated with 15,562 miles of existing NiSource right-of-way within the 14 aforementioned States.
The Covered Activities, or those NiSource activities that fall under the purview of the MSHCP and requested ITP, include a wide range of operation, maintenance, and new construction activities that are specific to NiSource Inc.'s wholly owned pipeline subsidiaries and to the Covered Land specified in the MSHCP.
The MSHCP evaluated 42 species that could potentially occur within the NiSource Covered Land, and that could potentially be impacted by NiSource Covered Activities. However, after analysis of the 42 species and the Covered Land, it was concluded that NiSource Covered Activities will have no impact on 32 of the 42 species evaluated. Therefore, NiSource is requesting incidental take for the remaining 10 species, for which take could be minimized, but not avoided.
In addition to the 42 species evaluated in the MSHCP, 46 additional ESA-listed, proposed, or candidate species are either known to occur or potentially occur within the NiSource Covered Land. Potential impacts to these species are discussed in the FEIS and in the Service's Biological Opinion.
Issuance of an ITP by the Service to NiSource is a Federal action that may affect the quality of the human environment and therefore is subject to review under the National Environmental Policy Act (NEPA). To comply with the NEPA, the Service prepared an FEIS. The FEIS analyzes and discloses potential impacts that could result from issuance of an ITP to NiSource and through subsequent
On October 11, 2007, the Service published a Notice of Intent (NOI) to prepare an EIS in the
In accordance with the NEPA, a draft EIS and MSHCP were circulated for public review and comment. The public review period was initiated with the publication of the Notice of Availability (NOA) in the FR on July 13, 2011 (76 FR 41288), and the public comment period was extended for an additional 90 days (76 FR 63950). Three public meetings were announced in the NOA, and were held in Columbus, Ohio, on August 16, 2011; Lexington, Kentucky, on August 17, 2011; and Charleston, West Virginia, on August 18, 2011. The comment period closed on December 13, 2011. A variety of comments were received on the DEIS and associated MSHCP, and are available at
We provide this notice under Section 10(c) of the ESA (16 U.S.C. 1531, 1539(c)) and its implementing regulations (50 CFR 17.22 and 17.32), and the NEPA (42 U.S.C. 4321
Bureau of Land Management, Interior.
Notice of Availability.
The Bureau of Land Management (BLM) announces the availability of the Record of Decision (ROD) to grant rights-of-way (ROWs) and approve an amendment to the BLM's Yuma Field Office Resource Management Plan (RMP) for the Quartzsite Solar Energy Project (QSEP). The Acting Assistant Secretary for Land and Minerals Management approved the ROD on May 30, 2013, which constitutes the final decision of the Department.
Copies of the ROD are available for public inspection at the BLM's Colorado River District Office, 2610 Sweetwater Avenue, Lake Havasu City, AZ 86406; Yuma Field Office, 2555 East Gila Ridge Road, Yuma, AZ 85365; and the BLM Arizona State Office, One North Central Avenue, Suite 800, Phoenix, AZ 85004. Interested parties may also review the Final Environmental Impact Statement (Final EIS) at the following Web site:
Eddie Arreola, BLM Renewable Energy Coordination Office Supervisor, Arizona State Office, One North Central Avenue, Suite 800, Phoenix, AZ 85004; phone: 602–417–9505; or email:
Quartzsite Solar Energy LLC, a subsidiary of Solar Reserve LLC, proposes to build the QSEP, a 100-megawatt concentrated solar thermal plant on approximately 1,675 acres of land managed by the BLM. The company applied to the BLM for a ROW to construct, operate, maintain, and decommission the project. The site is located east of State Route 95, approximately 10 miles north of Quartzsite, Arizona. The company also applied to Western Area Power Administration (Western), an agency of the U.S. Department of Energy, to interconnect the project to Western's transmission system. In connection with the project's interconnection request, Western applied to the BLM for a ROW to construct, operate, maintain, and decommission a substation and associated fiber optic or microwave communication facilities.
As required under the National Environmental Policy Act of 1969, as amended, the Final EIS for the QSEP analyzed a No Action alternative and two action alternatives, the Proposed Action, the proposed project with dry-cooling systems, and Alternative 1, the proposed project with a hybrid wet/dry cooling system. The Final EIS also analyzed three alternatives for the amendment to the Yuma Field Office RMP—Alternative 1, the proposed plan amendment with project approval, Alternative 2, the plan amendment with no project approval, and the No-Action Alternative.
The BLM preferred alternative is the proposed action with dry-cooling technology, an amendment to the RMP to re-classify 6,800 acres in and around the QSEP site from Visual Resource Management Class III to Class IV, and Western's proposed switchyard and fiber optic or microwave communication facilities that are ancillary to the interconnection of the QSEP to Western Bouse-Kofa 161-kilovolt transmission line. As described in the Final EIS, the BLM Selected Alternative was developed through the analysis of the resources, cooperating agency involvement, and public involvement. Publication of the Notice of Availability of the Final EIS for the QSEP and Proposed Yuma Field Office RMP Amendment was published in the
Because this decision is approved by the Acting Assistant Secretary for Land and Minerals Management, it is not subject to administrative appeal (43 CFR 4.410(a)(3)).
40 CFR 1506.6.
Nominations for the following properties being considered for listing or related actions in the National Register were received by the National Park Service before May 11, 2013. Pursuant to section 60.13 of 36 CFR Part 60, written comments are being accepted concerning the significance of the nominated properties under the National Register criteria for evaluation. Comments may be forwarded by United States Postal Service, to the National Register of Historic Places, National Park Service, 1849 C St. NW., MS 2280, Washington, DC 20240; by all other carriers, National Register of Historic Places, National Park Service,1201 Eye St. NW., 8th floor, Washington, DC 20005; or by fax, 202–371–6447. Written or faxed comments should be submitted by June 24, 2013. Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment—including your personal identifying information—may be made publicly available at any time. While you can ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.
A request to move has been made for the following resource:
A request for removal has been made for the following resources:
United States International Trade Commission.
June 13, 2013 at 9:30 a.m.
Room 101, 500 E Street SW., Washington, DC 20436, Telephone: (202) 205–2000.
Open to the public
1. Agendas for future meetings: none.
2. Minutes.
3. Ratification List.
4. Vote in Inv. Nos. 731–TA–873–875, 878–880, and 882 (Second Review) (Steel Concrete Reinforcing Bar from Belarus, China, Indonesia, Latvia, Moldova, Poland, and Ukraine). The Commission is currently scheduled to transmit its determinations and Commissioners' opinions to the Secretary of Commerce on or before July 2, 2013.
5. Outstanding action jackets: none
In accordance with Commission policy, subject matter listed above, not disposed of at the scheduled meeting, may be carried over to the agenda of the following meeting.
By order of the Commission.
On May 22, 2013, the Department of Justice lodged a proposed Consent Decree in
The PCS Nitrogen (“PCS”) Geismar, Louisiana plant is located on about 10 acres at 10886 Highway 75 Geismar, Louisiana 70737. The facility is a phosphoric acid plant that produces phosphoric acid and manufactures nitrogen solutions, phosphate fertilizer and other industrial products. The phosphoric acid production process is subject to new source standards in the National Emissions Standard for Hazardous Air pollutants (“NESHAPS”) for phosphoric acid manufacturing plants, promulgated under Section 112 of the Clean Air Act, and codified in 40 CFR part 63, Subpart AA.
Like the rest of the phosphoric acid industry, the PCS facility uses scrubbers to control air emissions, particularly fluorides, emanating from its phosphoric acid process equipment. The facility's cooling towers are therefore subject to the maximum available control technology (“MACT”) standard set forth at 40 CFR 63.602(e).
PCS historically discharged phosphoric acid scrubber effluent into its cooling ponds, and thereafter introduced the commingled effluent and pondwater into its cooling towers in violation of 40 CFR 63.602(e). Under the proposed Decree, PCS will pay a penalty of $198,825.30 and agrees to disable the two pre-scrubber elements discharging to the ponds and cooling tower; the majority of this injunctive relief was completed as of December 20, 2012, at
The Louisiana Department of Environmental Quality (“LDEQ”) is a co-plaintiff in this action, and concurs in the settlement. LDEQ will share in the penalty and coordinate with EPA to monitor and enforce compliance with the Consent Decree.
The publication of this notice opens a period for public comment on the proposed Consent Decree. Comments should be addressed to the Assistant Attorney General, Environment and Natural Resources Division, and should refer to
During the public comment period, the proposed Consent Decree may be examined and downloaded at this Justice Department Web site:
Please enclose a check or money order for $10.00 (25 cents per page reproduction cost) payable to the United States Treasury.
On June 3, 2013, the Department of Justice lodged a proposed consent decree with the United States District Court for the District of Idaho in the lawsuit entitled
The United States of America, on behalf of the United States Environmental Protection Agency (EPA), filed a Complaint in this action asserting claims against Defendant Davisco Foods International, Inc. (“Davisco”) for penalties pursuant to Section 309 of the Clean Water Act, 33 U.S.C. 1319. Specifically, the Complaint alleges that, from October of 2006 to August of 2010, Davisco violated its National Pollutant Discharge Elimination System permit issued by EPA under Section 402 of the Clean Water Act, 33 U.S.C. 1342, by discharging amounts and concentrations of phosphorus in excess of its permit limits. The proposed Consent Decree requires Davisco to pay a civil penalty of $304,000 for the violations alleged in the Complaint.
The publication of this notice opens a period for public comment on the Consent Decree. Comments should be addressed to the Assistant Attorney General, Environment and Natural Resources Division, and should refer to
During the public comment period, the Consent Decree may be examined and downloaded at this Justice Department Web site:
Please enclose a check or money order for $6 (25 cents per page reproduction cost) payable to the United States Treasury.
Occupational Safety and Health Administration (OSHA), Labor.
Request for public comments.
OSHA solicits public comments concerning its proposal to extend the Office of Management and Budget's (OMB) approval of the information collection requirements specified in the Standard on Asbestos in General Industry (29 CFR 1910.1001).
Comments must be submitted (postmarked, sent, or received) by August 6, 2013.
Theda Kenney or Todd Owen, Directorate of Standards and Guidance, OSHA, U.S. Department of Labor, Room N–3609, 200 Constitution Avenue NW., Washington, DC 20210; telephone (202) 693–2222.
The Department of Labor, as part of its continuing effort to reduce paperwork and respondent (
The basic purpose of the information collection requirements in the Standard is to document that employers in general industry are providing their workers with protection from exposure to hazardous asbestos. Asbestos exposure results in asbestosis, an emphysema-like condition; lung cancer; mesothelioma; and gastrointestinal cancer.
Several provisions of the Standard specify paperwork requirements, including: implementing an exposure monitoring program that notifies workers of their exposure monitoring results, establishing a written compliance program, and informing laundry personnel of the requirement to prevent release of airborne asbestos above the time-weighted average and excursion limit. Other provisions associated with paperwork requirements include: Maintaining records of information obtained concerning the presence, location, and quantity of asbestos-containing materials (ACMs) and/or presumed asbestos-containing materials (PACMs) in a building/facility; notifying housekeeping workers of the presence and location of ACMs and PACMs in areas they may occupy during their work; posting warning signs demarcating regulated areas; posting signs in mechanical rooms/areas that workers may enter and that contain ACMs and PACMs, informing them of the identity and location of these materials and about work practices that prevent disturbing the materials; and affixing warning labels to asbestos-containing products and to containers holding such products. Additional provisions that contain paperwork requirements include: Using information, data, and analyses to demonstrate that PACMs do not contain asbestos; providing medical surveillance for workers potentially exposed to ACMs and/or PACMs, including administering a worker medical questionnaire, providing information to the examining physician, and providing the physician's written opinion to the worker; maintaining records of exposure monitoring, objective data used for exposure determinations, and medical surveillance; and making specified records (e.g., exposure monitoring and medical surveillance records) available to designated parties.
These paperwork requirements permit employers, workers and their designated representatives, OSHA, and other specified parties to determine the effectiveness of an employer's asbestos-control program. Accordingly, the requirements ensure that workers exposed to asbestos receive all of the protections afforded by the Standard.
OSHA has a particular interest in comments on the following issues:
• Whether the proposed information collection requirements are necessary for the proper performance of the Agency's functions, including whether the information is useful;
• The accuracy of OSHA's estimate of the burden (time and costs) of the information collection requirements, including the validity of the methodology and assumptions used;
• The quality, utility, and clarity of the information collected; and
• Ways to minimize the burden on employers who must comply; for example, by using automated or other technological information collection and transmission techniques.
OSHA is requesting an adjustment decrease in burden hours from 11,932 to 11,694 (a total decrease of 238 hours). The reason for this reduction is the removal of burden hours associated with the requirement that employers provide training to workers. Upon further analysis, this provision is not considered to be a collection of information under PRA–95.
You may submit comments in response to this document as follows: (1) Electronically at
Because of security procedures, the use of regular mail may cause a significant delay in the receipt of comments. For information about security procedures concerning the delivery of materials by hand, express delivery, messenger, or courier service, please contact the OSHA Docket Office at (202) 693–2350, (TTY (877) 889–5627). Comments and submissions are posted without change at
David Michaels, Ph.D., MPH, Assistant Secretary of Labor for Occupational Safety and Health, directed the preparation of this notice. The authority for this notice is the Paperwork Reduction Act of 1995 (44 U.S.C. 3506
National Aeronautics and Space Administration (NASA).
Notice of information collection.
The National Aeronautics and Space Administration, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995.
All comments should be submitted within 60 calendar days from the date of this publication.
All comments should be addressed to Ms. Frances Teel, JF000, National Aeronautics and Space Administration, Washington, DC 20546–0001.
Requests for additional information or copies of the information collection instrument(s) and instructions should be directed to Frances Teel, NASA Clearance Officer, NASA Headquarters, 300 E Street SW., JF000, Washington, DC 20546,
This collection of information supports the National Aeronautics and Space Act of 1958, as amended, to create opportunities to improve processes associated with the evaluation and selection of individuals to participate in the NASA Astronaut Candidate Selection Program. The NASA Astronaut Selection Office (ASO) located at the Lyndon B. Johnson Space Center (JSC) in Houston, Texas is responsible for selecting astronauts for the various United States Space Exploration programs. In evaluating an applicant for the Astronaut Candidate Program, it is important that the ASO have the benefit of qualitative and quantitative information and recommendations from persons who have been directly associated with the applicant over the course of their career.
This information will be used by the NASA ASO and Human Resources (HR) personnel, during the candidate selection process (approx. 2 year duration), to gain insight into the candidates' work ethic and professionalism as demonstrated in previous related employment activities. Respondents may include the astronaut candidate's previous employer(s)/direct-reporting manager, as well as co-workers and other references provided by the candidate.
Electronic and optionally by paper.
Comments are invited on: (1) Whether the proposed collection of information is necessary for the proper performance of the functions of NASA, including whether the information collected has practical utility; (2) the accuracy of NASA's estimate of the burden (including hours and cost) of the proposed collection of information; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) ways to minimize the burden of the collection of information on respondents, including automated collection techniques or the use of other forms of information technology.
Comments submitted in response to this notice will be summarized and included in the request for OMB approval of this information collection. They will also become a matter of public record.
The following is a notice of applications for deregistration under section 8(f) of the Investment Company Act of 1940 for the month of May. A
For the Commission, by the Division of Investment Management, pursuant to delegated authority.
Securities and Exchange Commission (“Commission”).
Notice of an application under section 6(c) of the Investment Company Act of 1940 (“Act”) for an exemption from section 15(a) of the Act and rule 18f-2 under the Act, as well as from certain disclosure requirements.
Applicants, including exchange-traded funds (“ETFs”), request an order that would permit them to enter into and materially amend sub-advisory agreements without shareholder approval and would grant relief from certain disclosure requirements.
First Trust Exchange-Traded Fund, First Trust Exchange-Traded Fund II, First Trust Exchange-Traded Fund III, First Trust Exchange-Traded Fund IV, First Trust Exchange-Traded Fund V, First Trust Exchange-Traded Fund VI, First Trust Exchange-Traded Fund VII, First Trust Exchange-Traded AlphaDEX
An order granting the application will be issued unless the Commission orders a hearing. Interested persons may request a hearing by writing to the Commission's Secretary and serving Applicants with a copy of the request, personally or by mail. Hearing requests should be received by the Commission by 5:30 p.m. on June 28, 2013, and should be accompanied by proof of service on the Applicants, in the form of an affidavit or, for lawyers, a certificate of service. Hearing requests should state the nature of the writer's interest, the reason for the request, and the issues contested. Persons who wish to be notified of a hearing may request notification by writing to the Commission's Secretary.
Elizabeth M. Murphy, Secretary, U.S. Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549–1090. Applicants, Attn: W. Scott Jardine, 120 East Liberty Drive, Suite 400, Wheaton, IL 60187.
Steven I. Amchan, Senior Counsel, at (202) 551–6826, or Jennifer L. Sawin, Branch Chief, at (202) 551–6821 (Division of Investment Management, Exemptive Applications Office).
The following is a summary of the application. The complete application may be obtained via the Commission's Web site by searching for the file number, or an applicant using the Company name box, at
1. The ETF Trusts, the Series Trust, and VIT each are organized as Massachusetts business trusts, and First Defined is organized as a Delaware limited liability company. Each Company is, or will be, registered under the Act as an open-end management investment company.
2. First Trust, an Illinois limited partnership with its principal office in Wheaton, Illinois, is registered as an investment adviser under the Investment Advisers Act of 1940 (“Advisers Act”). First Trust has one limited partner, Grace Partners of DuPage L.P., and one general partner, The Charger Corporation. First Trust currently serves as the investment adviser to the existing Funds pursuant to an investment advisory agreement with respect to each Fund (each, an “Advisory Agreement”) approved by the applicable board of trustees (the “Board”)
3. Under the terms of the applicable Advisory Agreement, the Advisor, subject to the oversight of the Board, generally furnishes a continuous investment program for each Fund. For the investment management services that it provides to each Fund, the Advisor receives the fee specified in the Advisory Agreement from each Fund based on the Fund's average daily net assets. The terms of the Advisory Agreement for any Fund that will use sub-advisers also permit or will permit the Advisor, subject to the approval of the applicable Board, including a majority of the Independent Trustees, and the approval of the shareholders of the Fund (to the extent required by applicable law), to delegate portfolio management responsibilities of all or a portion of the assets of the Fund to one or more sub-advisers. With respect to certain existing Funds the Advisor has entered into investment sub-advisory agreements with unaffiliated sub-
4. Applicants request an order to permit the Advisor, subject to Board approval, to select certain Sub-Advisers to manage all or a portion of the assets of a Fund pursuant to a Sub-Advisory Agreement and materially amend Sub-Advisory Agreements without obtaining shareholder approval. The requested relief will not extend to any sub-adviser that is an affiliated person, as defined in section 2(a)(3) of the Act, of a Company, a Fund, or the Advisor, other than by reason of serving as a sub-adviser to one or more of the Funds (“Affiliated Sub-Advisers”).
5. Applicants acknowledge that the requested order seeks relief for Funds that are ETFs (“ETF Funds”). However, Applicants believe that operations of the ETF Funds under the requested order address the concerns historically considered by the Commission when granting identical relief to mutual funds. Applicants believe that similar to shareholders of a mutual fund who may “vote with their feet” by redeeming their individual shares at net asset value (“NAV”) if they do not approve of a change in sub-adviser or subadvisory agreement, ETF Fund shareholders will be able, due to the arbitrage mechanism implemented for each ETF Fund, to sell shares in the secondary market at negotiated prices that do not vary materially from the relevant Fund's NAV if the shareholders do not approve of a change.
6. Applicants also request an order exempting the Funds from certain disclosure provisions described below that may require the Applicants to disclose fees paid to each Sub-Adviser. Applicants seek an order to permit each Fund to disclose (as a dollar amount and a percentage of the Fund's net assets) only: (a) The aggregate fees paid to the Advisor and any Affiliated Sub-Advisers; and (b) the aggregate fees paid to Sub-Advisers (collectively, the “Aggregate Fee Disclosure”). A Fund that employs an Affiliated Sub-Adviser will provide separate disclosure of any fees paid to the Affiliated Sub-Adviser.
1. Section 15(a) of the Act provides, in relevant part, that it is unlawful for any person to act as an investment adviser to a registered investment company except pursuant to a written contract that has been approved by the vote of a majority of the company's outstanding voting securities. Rule 18f–2 under the Act provides that each series or class of stock in a series investment company affected by a matter must approve that matter if the Act requires shareholder approval.
2. Form N–1A is the registration statement used by open-end investment companies. Item 19(a)(3) of Form N–1A requires disclosure of the method and amount of the investment adviser's compensation.
3. Rule 20a–1 under the Act requires proxies solicited with respect to an investment company to comply with Schedule 14A under the Securities Exchange Act of 1934 (“Exchange Act”). Items 22(c)(1)(ii), 22(c)(1)(iii), 22(c)(8) and 22(c)(9) of Schedule 14A, taken together, require a proxy statement for a shareholder meeting at which the advisory contract will be voted upon to include the “rate of compensation of the investment adviser,” the “aggregate amount of the investment adviser's fees,” a description of the “terms of the contract to be acted upon,” and, if a change in the advisory fee is proposed, the existing and proposed fees and the difference between the two fees.
4. Regulation S–X sets forth the requirements for financial statements required to be included as part of a registered investment company's registration statement and shareholder reports filed with the Commission. Sections 6–07(2)(a), (b) and (c) of Regulation S–X require a registered investment company to include in its financial statements information about the investment advisory fees.
5. Section 6(c) of the Act provides that the Commission may exempt any person, security, or transaction or any class or classes of persons, securities, or transactions from any provisions of the Act, or from any rule thereunder, if such exemption is necessary or appropriate in the public interest and consistent with the protection of investors and the purposes fairly intended by the policy and provisions of the Act. Applicants state that the requested relief meets this standard for the reasons discussed below.
6. Applicants state that the shareholders expect the Advisor to select the portfolio managers or, subject to the review and approval of the Board, the Sub-Adviser for a Fund that is best suited to achieve the Fund's investment objective(s). Applicants assert that, from the perspective of the investor, the role of the Sub-Advisers with respect to the Funds utilizing the Manager of Managers Structure is substantially equivalent to the role of the individual portfolio managers employed by traditional investment company advisory firms. In the absence of exemptive relief from section 15(a) of the Act, when a new Sub-Adviser is proposed for retention by a Fund, shareholders would be required to approve the Sub-Advisory Agreement with that Sub-Adviser. Similarly, approval by the shareholders of the affected Fund would be required in order to amend an existing Sub-Advisory Agreement in any material respect or in order to continue to retain an existing Sub-Adviser whose Sub-Advisory Agreement is “assigned” as a result of a change of control. Obtaining shareholder approval would be costly and slow, and potentially harmful to the affected Fund and its shareholders. Applicants note that each Advisory
7. If new Sub-Advisers are hired, the applicable Fund will inform shareholders of the hiring of a new Sub-Adviser pursuant to the following procedures (“Modified Notice and Access Procedures”): (a) Within 90 days after a new Sub-Adviser is hired for any Fund, that Fund will furnish its shareholders with either a Multi-manager Notice or a Multi-manager Notice and Multi-manager Information Statement;
A “Multi-manager Information Statement” will meet the requirements of Regulation 14C, Schedule 14C and Item 22 of Schedule 14A under the Exchange Act for an information statement, except as modified by the requested order to permit Aggregate Fee Disclosure. Multi-manager Information Statements will be filed electronically with the Commission via the EDGAR system.
8. Applicants assert that the requested disclosure relief would benefit Fund shareholders because it would improve the Advisor's ability to negotiate the fees paid to Sub-Advisers. Applicants state that the Advisor may be able to negotiate rates that are below a Sub-Adviser's “posted” amounts if the Advisor is not required to disclose the Sub-Advisers' fees to the public. Applicants submit that the requested relief will also encourage Sub-Advisers to negotiate lower sub-advisory fees with the Advisor if the lower fees are not required to be made public.
Applicants agree that any order granting the requested relief will be subject to the following conditions:
1. Before a Fund may rely on the order requested in the application, the operation of the Fund in the manner described in the application will be approved by a majority of the Fund's outstanding voting securities, as defined in the Act, or, in the case of a Fund whose public shareholders purchase shares on the basis of a prospectus containing the disclosure contemplated by condition 2 below, by the initial shareholder(s) before offering shares of that sub-advised Fund to the public.
2. The prospectus for each Fund relying on the order requested in the application will disclose the existence, substance, and effect of any order granted pursuant to the application. Each Fund relying on the order requested in the application will hold itself out to the public as utilizing the Manager of Managers Structure described in the application. The prospectus will prominently disclose that the Advisor has ultimate responsibility (subject to oversight by the Board) to oversee the Sub-Advisers and recommend their hiring, termination, and replacement.
3. Funds will inform shareholders of the hiring of a new Sub-Adviser within 90 days of the hiring of the new Sub-Adviser pursuant to the Modified Notice and Access Procedures.
4. The Advisor will not enter into a sub-advisory agreement with any Affiliated Sub-Adviser without such agreement, including the compensation to be paid thereunder, being approved by the shareholders of the applicable Fund.
5. At all times, at least a majority of the Board will be Independent Trustees, and the nomination of new or additional Independent Trustees will be placed within the discretion of the then-existing Independent Trustees.
6. Whenever a sub-adviser change is proposed for a Fund with an Affiliated Sub-Adviser, the Board, including a majority of the Independent Trustees, will make a separate finding, reflected in the applicable Board minutes, that such change is in the best interests of the Fund and its shareholders, and does not involve a conflict of interest from which the Advisor or the Affiliated Sub-Adviser derives an inappropriate advantage.
7. Whenever a sub-adviser is hired or terminated, the Advisor will provide the Board with information showing the expected impact on the profitability of the Advisor.
8. The Advisor will provide general management services to each Fund that is sub-advised, including overall supervisory responsibility for the general management and investment of the Fund's assets and, subject to review and approval of the Board, will: (i) Set each Fund's overall investment strategies; (ii) evaluate, select and recommend Sub-Advisers to manage all or a part of a Fund's assets; (iii) allocate and, when appropriate, reallocate a Fund's assets among one or more Sub-Advisers; (iv) monitor and evaluate the performance of Sub-Advisers; and (v) implement procedures reasonably designed to ensure that the Sub-Advisers comply with the relevant Fund's investment objective(s), policies and restrictions.
9. No trustee or officer of a Company, or director, manager or officer of the Advisor, will own directly or indirectly (other than through a pooled investment vehicle that is not controlled by such person), any interest in a Sub-Adviser except for: (a) Ownership of interests in the Advisor or any entity that controls, is controlled by, or is under common control with the Advisor, or (b) ownership of less than 1% of the outstanding securities of any class of equity or debt of any publicly traded company that is either a Sub-Adviser or an entity that controls, is controlled by, or is under common control with a Sub-Adviser.
10. Each Fund will disclose in its registration statement the Aggregate Fee Disclosure.
11. In the event the Commission adopts a rule under the Act providing substantially similar relief to that in the order requested in the application, the requested order will expire on the effective date of that rule.
12. The Advisor will provide the Board, no less frequently than quarterly, with information about the profitability of the Advisor on a per Fund basis. The information will reflect the impact on profitability of the hiring or termination of any sub-adviser during the applicable quarter.
13. Independent Legal Counsel, as defined in rule 0–1(a)(6) under the Act, will be engaged to represent the Independent Trustees. The selection of such counsel will be within the discretion of the then-existing Independent Trustees.
14. For Funds that pay fees to a Sub-Adviser directly from Fund assets, any changes to a Sub-Advisory Agreement that would result in an increase in the total management and advisory fees payable by a Fund will be required to be approved by the shareholders of the Fund.
For the Commission, by the Division of Investment Management, under delegated authority.
Securities and Exchange Commission (“Commission”).
Notice of an application for an order under section 12(d)(1)(J) of the Investment Company Act of 1940 (the “Act”) for an exemption from sections 12(d)(1)(A) and (B) of the Act, under sections 6(c) and 17(b) of the Act for an exemption from sections 17(a)(1) and (2) of the Act, and under section 6(c) of the Act for an exemption from rule 12d1–2(a) under the Act.
KP Funds (“Trust”), Callan Associates Inc. (“Fund of Funds Adviser”), and SEI Investments Distribution Co. (the “Distributor”).
An order granting the application will be issued unless the Commission orders a hearing. Interested persons may request a hearing by writing to the Commission's Secretary and serving applicants with a copy of the request, personally or by mail. Hearing requests should be received by the Commission by 5:30 p.m. on June 28, 2013, and should be accompanied by proof of service on applicants, in the form of an affidavit or, for lawyers, a certificate of service. Hearing requests should state the nature of the writer's interest, the reason for the request, and the issues contested. Persons who wish to be notified of a hearing may request notification by writing to the Commission's Secretary.
Elizabeth M. Murphy, Secretary, U.S. Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549–1090. Applicants: c/o Dianne M. Sulzbach, SEI Corporation, One Freedom Valley Drive, Oaks, PA 19456.
Courtney S. Thornton, Senior Counsel, at (202) 551–6812, or David P. Bartels, Branch Chief, at (202) 551–6821 (Division of Investment Management, Exemptive Applications Office).
The following is a summary of the application. The complete application may be obtained via the Commission's Web site by searching for the file number, or for an applicant using the Company name box, at
1. The Trust, a Massachusetts business trust, intends to register under the Act as an open-end management investment company and offer shares of multiple series, each of which will pursue different investment objectives and principal investment strategies.
2. The Fund of Funds Adviser, a California corporation, is registered as an investment adviser under the Investment Advisers Act of 1940 (“Advisers Act”) and will serve as investment adviser to the Trust's Funds.
3. The Distributor, a Pennsylvania corporation, is registered as a broker-dealer under the Securities Exchange Act of 1934 (the “Exchange Act”). The Distributor will serve as principal underwriter and distributor for the shares of the Trust's Funds.
4. Applicants request an order to permit (a) a Fund that operates as a “fund of funds” (each a “Fund of Funds”) to acquire shares of (i) registered open-end management investment companies that are not part of the same “group of investment companies,” within the meaning of section 12(d)(1)(G)(ii) of the Act, as the Fund of Funds (“Unaffiliated Investment Companies”) and UITs that are not part of the same group of investment companies as the Fund of Funds (“Unaffiliated Trusts,” together with the Unaffiliated Investment Companies, “Unaffiliated Funds”)
5. Applicants also request an exemption under section 6(c) from rule 12d1–2 under the Act to permit any existing or future Fund that relies on section 12(d)(1)(G) of the Act (“Same Group Investing Fund”) and that otherwise complies with rule 12d1–2 to also invest, to the extent consistent with its investment objective, policies, strategies, and limitations, in financial instruments that may not be securities
1. Section 12(d)(1)(A) of the Act, in relevant part, prohibits a registered investment company from acquiring shares of an investment company if the securities represent more than 3% of the total outstanding voting stock of the acquired company, more than 5% of the total assets of the acquiring company, or, together with the securities of any other investment companies, more than 10% of the total assets of the acquiring company. Section 12(d)(1)(B) of the Act prohibits a registered open-end investment company, its principal underwriter, and any Broker from selling the investment company's shares to another investment company if the sale will cause the acquiring company to own more than 3% of the acquired company's total outstanding voting stock, or if the sale will cause more than 10% of the acquired company's total outstanding voting stock to be owned by investment companies generally.
2. Section 12(d)(1)(J) of the Act provides that the Commission may exempt any person, security, or transaction, or any class or classes of persons, securities, or transactions, from any provision of section 12(d)(1) if the exemption is consistent with the public interest and the protection of investors. Applicants seek an exemption under section 12(d)(1)(J) of the Act to permit a Fund of Funds to acquire shares of the Underlying Funds in excess of the limits in section 12(d)(1)(A), and an Underlying Fund, the Distributor or any principal underwriter for an Underlying Fund, and any Broker to sell shares of an Underlying Fund to a Fund of Funds in excess of the limits in section 12(d)(1)(B) of the Act.
3. Applicants state that the terms and conditions of the proposed arrangement will not give rise to the policy concerns underlying sections 12(d)(1)(A) and (B), which include concerns about undue influence by a fund of funds over underlying funds, excessive layering of fees, and overly complex fund structures. Accordingly, applicants believe that the requested exemption is consistent with the public interest and the protection of investors.
4. Applicants believe that the proposed arrangement will not result in the exercise of undue influence by the Fund of Funds or a Fund of Funds Affiliate over the Unaffiliated Funds.
5. To further ensure that an Unaffiliated Investment Company understands the implications of an investment by a Fund of Funds under the requested order, prior to a Fund of Funds' investment in the shares of an Unaffiliated Investment Company in excess of the limit in section 12(d)(1)(A)(i) of the Act, the Fund of Funds and the Unaffiliated Investment Company will execute an agreement stating, without limitation, that their respective board of directors or trustees (for any entity, the “Board”) and their investment advisers understand the terms and conditions of the order and agree to fulfill their responsibilities under the order (“Participation Agreement”). Applicants note that an Unaffiliated Investment Company (other than an ETF whose shares are purchased by a Fund of Funds in the secondary market) will retain its right at all times to reject any investment by a Fund of Funds.
6. Applicants state that they do not believe that the proposed arrangement will involve excessive layering of fees. The Board of each Fund of Funds, including a majority of the trustees who are not “interested persons” (within the meaning of section 2(a)(19) of the Act) (“Independent Trustees”), will find that the advisory fees charged under investment advisory or management contract(s) are based on services provided that will be in addition to, rather than duplicative of, the services provided under such advisory contract(s) of any Underlying Fund in which the Fund of Funds may invest. In addition, the Fund of Funds Adviser will waive fees otherwise payable to it by a Fund of Funds in an amount at least equal to any compensation (including fees received pursuant to any plan adopted by an Unaffiliated Investment Company under rule 12b–1 under the Act) received from an Unaffiliated Fund by the Fund of Funds Adviser or an affiliated person of the Fund of Funds Adviser, other than any advisory fees paid to the Adviser or its affiliated person by an Unaffiliated Investment Company, in connection with the investment by the Fund of Funds in the Unaffiliated Fund. Any sales charges and/or service fees charged with respect to shares of the Fund of Funds will not exceed the limits applicable to a fund of funds as
7. Applicants submit that the proposed arrangement will not create an overly complex fund structure. Applicants note that no Underlying Fund will acquire securities of any investment company or company relying on section 3(c)(1) or 3(c)(7) of the Act in excess of the limits contained in section 12(d)(1)(A) of the Act, except in certain circumstances identified in condition 11 below.
1. Section 17(a) of the Act generally prohibits sales or purchases of securities between a registered investment company and any affiliated person of the company. Section 2(a)(3) of the Act defines an “affiliated person” of another person to include (a) any person directly or indirectly owning, controlling, or holding with power to vote, 5% or more of the outstanding voting securities of the other person; (b) any person 5% or more of whose outstanding voting securities are directly or indirectly owned, controlled, or held with power to vote by the other person; and (c) any person directly or indirectly controlling, controlled by, or under common control with the other person.
2. Applicants state that a Fund of Funds and the Affiliated Funds managed by the same Adviser might be deemed to be under common control of the Fund of Funds Adviser and therefore affiliated persons of one another. Applicants also state that the Fund of Funds and the Unaffiliated Funds might be deemed to be affiliated persons of one another if the Fund of Funds acquires 5% or more of an Unaffiliated Fund's outstanding voting securities. In light of these and other possible affiliations, section 17(a) could prevent an Underlying Fund from selling shares to and redeeming shares from a Fund of Funds.
3. Section 17(b) of the Act authorizes the Commission to grant an order permitting a transaction otherwise prohibited by section 17(a) if it finds that (a) the terms of the proposed transaction are fair and reasonable and do not involve overreaching on the part of any person concerned; (b) the proposed transaction is consistent with the policies of each registered investment company involved; and (c) the proposed transaction is consistent with the general purposes of the Act. Section 6(c) of the Act permits the Commission to exempt any persons or transactions from any provision of the Act if such exemption is necessary or appropriate in the public interest and consistent with the protection of investors and the purposes fairly intended by the policy and provisions of the Act.
4. Applicants submit that the proposed transactions satisfy the standards for relief under sections 17(b) and 6(c) of the Act.
1. Section 12(d)(1)(G) of the Act provides that section 12(d)(1) will not apply to securities of an acquired company purchased by an acquiring company if: (i) The acquiring company and acquired company are part of the same group of investment companies; (ii) the acquiring company holds only securities of acquired companies that are part of the same group of investment companies, government securities, and short-term paper; (iii) the aggregate sales loads and distribution-related fees of the acquiring company and the acquired company are not excessive under rules adopted pursuant to section 22(b) or section 22(c) of the Act by a securities association registered under section 15A of the Exchange Act or by the Commission; and (iv) the acquired company has a policy that prohibits it from acquiring securities of registered open-end management investment companies or registered unit investment trusts in reliance on section 12(d)(1)(F) or (G) of the Act.
2. Rule 12d1–2 under the Act permits a registered open-end investment company or a registered unit investment trust that relies on section 12(d)(1)(G) of the Act to acquire, in addition to securities issued by another registered investment company in the same group of investment companies, government securities, and short-term paper: (1) Securities issued by an investment company that is not in the same group of investment companies, when the acquisition is in reliance on section 12(d)(1)(A) or 12(d)(1)(F) of the Act; (2) securities (other than securities issued by an investment company); and (3) securities issued by a money market fund, when the investment is in reliance on rule 12d1–1 under the Act. For the purposes of rule 12d1–2, “securities” means any security as defined in section 2(a)(36) of the Act.
3. Applicants state that the proposed arrangement would comply with the provisions of rule 12d1–2 under the Act, but for the fact that a Same Group Investing Fund may invest a portion of its assets in Other Investments. Applicants request an order under section 6(c) of the Act for an exemption from rule 12d1–2(a) to allow the Same Group Investing Funds to invest in Other Investments. Applicants assert that permitting Same Group Investing Funds to invest in Other Investments as described in the application would not raise any of the concerns that the requirements of section 12(d)(1) were designed to address.
4. Consistent with its fiduciary obligations under the Act, the Board of each Same Group Investing Fund will review the advisory fees charged by the Same Group Investing Fund's investment adviser to ensure that they are based on services provided that are in addition to, rather than duplicative of, services provided pursuant to the advisory agreement of any investment company in which the Same Group Investing Fund may invest.
Applicants agree that the relief to permit Funds of Funds to invest in Underlying Funds shall be subject to the following conditions:
1. The members of an Advisory Group will not control (individually or in the
2. No Fund of Funds or Fund of Funds Affiliate will cause any existing or potential investment by the Fund of Funds in shares of an Unaffiliated Fund to influence the terms of any services or transactions between the Fund of Funds or a Fund of Funds Affiliate and the Unaffiliated Fund or an Unaffiliated Fund Affiliate.
3. The Board of each Fund of Funds, including a majority of the Independent Trustees, will adopt procedures reasonably designed to ensure that its Fund of Funds Adviser and any Subadviser(s) to the Fund of Funds are conducting the investment program of the Fund of Funds without taking into account any consideration received by the Fund of Funds or Fund of Funds Affiliate from an Unaffiliated Fund or an Unaffiliated Fund Affiliate in connection with any services or transactions.
4. Once an investment by a Fund of Funds in the securities of an Unaffiliated Investment Company exceeds the limit of section 12(d)(1)(A)(i) of the Act, the Board of the Unaffiliated Investment Company, including a majority of the Independent Trustees, will determine that any consideration paid by the Unaffiliated Investment Company to a Fund of Funds or a Fund of Funds Affiliate in connection with any services or transactions: (a) Is fair and reasonable in relation to the nature and quality of the services and benefits received by the Unaffiliated Investment Company; (b) is within the range of consideration that the Unaffiliated Investment Company would be required to pay to another unaffiliated entity in connection with the same services or transactions; and (c) does not involve overreaching on the part of any person concerned. This condition does not apply with respect to any services or transactions between an Unaffiliated Investment Company and its investment adviser(s) or any person controlling, controlled by, or under common control with such investment adviser(s).
5. No Fund of Funds or Fund of Funds Affiliate (except to the extent it is acting in its capacity as an investment adviser to an Unaffiliated Investment Company or sponsor to an Unaffiliated Trust) will cause an Unaffiliated Fund to purchase a security in any Affiliated Underwriting.
6. The Board of an Unaffiliated Investment Company, including a majority of the Independent Trustees, will adopt procedures reasonably designed to monitor any purchases of securities by the Unaffiliated Investment Company in an Affiliated Underwriting once an investment by a Fund of Funds in the securities of the Unaffiliated Investment Company exceeds the limit of section 12(d)(1)(A)(i) of the Act, including any purchases made directly from an Underwriting Affiliate. The Board of the Unaffiliated Investment Company will review these purchases periodically, but no less frequently than annually, to determine whether the purchases were influenced by the investment by the Fund of Funds in the Unaffiliated Investment Company. The Board of the Unaffiliated Investment Company will consider, among other things: (a) Whether the purchases were consistent with the investment objectives and policies of the Unaffiliated Investment Company; (b) how the performance of securities purchased in an Affiliated Underwriting compares to the performance of comparable securities purchased during a comparable period of time in underwritings other than Affiliated Underwritings or to a benchmark such as a comparable market index; and (c) whether the amount of securities purchased by the Unaffiliated Investment Company in Affiliated Underwritings and the amount purchased directly from an Underwriting Affiliate have changed significantly from prior years. The Board of the Unaffiliated Investment Company will take any appropriate actions based on its review, including, if appropriate, the institution of procedures designed to ensure that purchases of securities in Affiliated Underwritings are in the best interests of shareholders.
7. Each Unaffiliated Investment Company shall maintain and preserve permanently in an easily accessible place a written copy of the procedures described in the preceding condition, and any modifications to such procedures, and shall maintain and preserve for a period not less than six years from the end of the fiscal year in which any purchase in an Affiliated Underwriting occurred, the first two years in an easily accessible place, a written record of each purchase of securities in an Affiliated Underwriting once an investment by a Fund of Funds in the securities of an Unaffiliated Investment Company exceeds the limit of section 12(d)(1)(A)(i) of the Act, setting forth: (a) The party from whom the securities were acquired, (b) the identity of the underwriting syndicate's members, (c) the terms of the purchase, and (d) the information or materials upon which the determinations of the Board of the Unaffiliated Investment Company were made.
8. Prior to its investment in shares of an Unaffiliated Investment Company in excess of the limit in section 12(d)(1)(A)(i) of the Act, the Fund of Funds and the Unaffiliated Investment Company will execute a Participation Agreement stating, without limitation, that their Boards and their investment advisers understand the terms and conditions of the order and agree to fulfill their responsibilities under the order. At the time of its investment in shares of an Unaffiliated Investment Company in excess of the limit in section 12(d)(1)(A)(i), a Fund of Funds will notify the Unaffiliated Investment Company of the investment. At such time, the Fund of Funds will also transmit to the Unaffiliated Investment Company a list of the names of each Fund of Funds Affiliate and Underwriting Affiliate. The Fund of Funds will notify the Unaffiliated Investment Company of any changes to the list of the names as soon as reasonably practicable after a change occurs. The Unaffiliated Investment Company and the Fund of Funds will maintain and preserve a copy of the order, the Participation Agreement, and the list with any updated information for the duration of the investment and for a period of not less than six years thereafter, the first two years in an easily accessible place.
9. Before approving any advisory contract under section 15 of the Act, the Board of each Fund of Funds, including a majority of the Independent Trustees, shall find that the advisory fees charged under such advisory contract are based
10. A Fund of Funds Adviser will waive fees otherwise payable to it by a Fund of Funds in an amount at least equal to any compensation (including fees received pursuant to any plan adopted by an Unaffiliated Investment Company under rule 12b–1 under the Act) received from an Unaffiliated Fund by the Fund of Funds Adviser, or an affiliated person of the Fund of Funds Adviser, other than any advisory fees paid to the Fund of Funds Adviser or its affiliated person by an Unaffiliated Investment Company, in connection with the investment by the Fund of Funds in the Unaffiliated Fund. Any Subadviser will waive fees otherwise payable to the Subadviser, directly or indirectly, by the Fund of Funds in an amount at least equal to any compensation received by the Subadviser, or an affiliated person of the Subadviser, from an Unaffiliated Fund, other than any advisory fees paid to the Subadviser or its affiliated person by an Unaffiliated Investment Company, in connection with the investment by the Fund of Funds in the Unaffiliated Fund made at the direction of the Subadviser. In the event that a Subadviser waives fees, the benefit of the waiver will be passed through to the applicable Fund of Funds.
11. No Underlying Fund will acquire securities of any other investment company or company relying on section 3(c)(1) or 3(c)(7) of the Act in excess of the limits contained in section 12(d)(1)(A) of the Act, except to the extent that such Underlying Fund: (a) Acquires such securities in compliance with section 12(d)(1)(E) of the Act and either is an Affiliated Fund or is in the same “group of investment companies,” as defined in section 12(d)(1)(G)(ii) of the Act, as its corresponding master fund; (b) receives securities of another investment company as a dividend or as a result of a plan of reorganization of a company (other than a plan devised for the purpose of evading section 12(d)(1) of the Act); or (c) acquires (or is deemed to have acquired) securities of another investment company pursuant to exemptive relief from the Commission permitting such Underlying Fund to (i) acquire securities of one or more investment companies for short-term cash management purposes, or (ii) engage in interfund borrowing and lending transactions.
12. Any sales charges and/or service fees charged with respect to shares of a Fund of Funds will not exceed the limits applicable to fund of funds set forth in NASD Conduct Rule 2830.
Applicants agree that the relief to permit Same Group Investing Funds to invest in Other Investments shall be subject to the following condition:
13. Applicants will comply with all provisions of rule 12d1–2 under the Act, except for paragraph (a)(2) to the extent that it restricts any Same Group Investing Fund from investing in Other Investments as described in the application.
For the Commission, by the Division of Investment Management, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”),
The Exchange is filing a proposal to amend Exchange Rule 514 to modify the allocation of Directed Orders in specific limited situations.
The text of the proposed rule change is available on the Exchange's Web site at
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
The Exchange proposes to amend Exchange Rule 514 to modify the allocation of Directed Orders
Exchange Rule 514(h)(1) provides the formula used to calculate the DLMM participation entitlement. Specifically, the DLMM participation entitlement is equal to the greater of: (i) The proportion of the total size at the best price represented by the size of its quote; (ii) sixty percent (60%) of the contracts to be allocated if there is only one (1) other Market Maker quotation at the NBBO; or (iii) forty percent (40%) if there are two (2) or more other Market Maker quotes at the NBBO.
The Exchange notes that other competing exchanges may round up in certain situations where there is a fractional contract size allocation. Rounding up fractional contract sizes in this situation would result in a 0.7 contract size equaling 1 contract.
Three (3) Lead Market Makers (LMMs) quoting at the NBBO; no orders resting on the Exchange System; and the DLMM participation entitlement overlay is in effect.
The Exchange System operates as follows:
• LMM3 is entitled to the greater of: (i) pro-rata allocation, 0.375 contract (10/80 × 3 contracts); or (ii) 40%, 1.2 contract (40% × 3 contracts). LMM3 would receive a DLMM participation entitlement of 1 contract.
• LMM1 and LMM2 would each receive 1 contract.
Three (3) Lead Market Makers (LMMs) quoting at the NBBO; no orders resting on the Exchange System; and the DLMM participation entitlement overlay is in effect.
The Exchange System operates as follows:
• LMM3 is entitled to the greater of: (i) pro-rata allocation, 0.25 contract (10/80 × 2 contracts); or (ii) 40%, 0.8 contract (40% × 2 contracts). LMM3 would receive a DLMM participation entitlement of zero.
• LMM1 and LMM2 would each receive 1 contract.
The Exchange proposes to modify the allocation of Directed Orders to provide a DLMM a minimum participation allocation of one (1) contract in situations where the DLMM participation allocation currently results in an allocation of zero due to the fact that the Exchange System rounds down any fractional contract size allocations. Specifically, the Exchange seeks to remedy these situations by adding “or (iii) one (1) contract” to the DLMM participation entitlement formula of Exchange Rule 514(h)(1). Thus, the DLMM would be entitled to the greatest of: (i) the pro-rata share; (ii) 40% or 60% of the incoming Directed Order (depending on the number of other Market Makers quoting along with the DLMM); or (iii) one (1) contract. The following example, using the same facts as Example 2 above, illustrates the impact of the proposed change.
Three (3) LMMs quoting at the NBBO; no orders resting on the Exchange System; and the DLMM participation entitlement overlay is in effect.
• LMM3 would be entitled to the greater of: (i) Pro-rata allocation, 0.25 contract (10/80 × 2 contracts); (ii) 40%, 0.8 contract (40% × 2 contracts); or (iii) one (1) contract. LMM3 would receive a DLMM participation entitlement of one (1) contract.
• LMM1 would receive one (1) contract.
The Exchange believes that the proposed change preserves the integrity of its Directed Order program by enabling the DLMM to receive a minimum of one (1) contract in situations where the allocation would be zero due to the Exchange System's practice of rounding down fractional allocations. By choosing to enter a Directed Order over a non-directed order, an Electronic Exchange Member (“EEM”) actively intends to trade with the particular quote of the designated DLMM. In most situations when the DLMM participation entitlement applies, the EEM's Directed Order interacts and executes at least partially with the quote of the DLMM. However, when applying the DLMM participation entitlement to Directed Orders of a contract size of two (2) or less, such interaction with the quote of the DLMM may never occur because of the rounding down of fractional contract size by the Exchange System. The Exchange's proposal would fix these scenarios and ensure that the EEM's Directed Order would trade a minimum of one contract with the quote of the DLMM, when the DLMM participation entitlement applies. The Exchange believes this proposal to be fair because it preserves the original purpose of the Directed Order, to trade with the particular quote of the DLMM, and also correspondingly enables the DLMM to be rewarded with an allocation for having attracted the Directed Order to the Exchange.
Because of the technology changes associated with this rule proposal, the Exchange will announce the implementation date of the proposal in a Regulatory Circular to be published no later than 30 days after the publication of the approval order in the
MIAX believes that its proposed rule change is consistent with Section 6(b) of the Act
The proposal to establish a one (1) contract minimum for the DLMM participation entitlement promotes just and equitable principles of trade by enabling DLMM to be eligible for a participation entitlement regardless if the order is for three (3) contracts or more, or for two (2) contracts or less, in a manner that protects investors and the public interest. In addition, the proposal fosters cooperation and coordination with persons engaged in facilitating transactions in securities by fulfilling the intention of a Directed Order in a manner that provides additional certainty to both the EEM that initiates and the DLMM that receives a Directed Order in situations where the DLMM participation entitlement applies. The proposal is also designed to remove impediments to and perfect the mechanisms of a free and open market by providing additional certainty of execution of an EEM's Directed Order in a manner that encourages additional liquidity and order flow to the Exchange, improves overall market quality, and thus benefits all market participants. The Exchange notes that the proposal will have no effect on the existing participation entitlement program, except in the minority of situations where the DLMM participation entitlement is applied to Directed Orders of a contract size of two (2) or less. The Exchange also notes that Priority Customers will be unaffected by the proposal, as Priority Customer orders will continue to be allocated before the DLMM participation entitlement in a manner that promotes the protection of investors and the public interest.
The Exchange does not believe that the proposed rule change will impose any burden on competition not necessary or appropriate in furtherance of the purposes of the Act. The Exchange notes that it operates in a highly competitive market in which market participants can readily direct order flow to competing venues who offer similar functionality. As to inter-market competition, the Exchange notes that other competing exchanges may already operate Directed Order programs which function in a similar manner, depending upon whether those exchanges choose to round up or round down fractional contract allocations. As to intra-market competition, the Exchange believes the proposal to be fair as it only applies to Directed Orders, which by their definition possess an intention by the EEM to trade with the quote of a particular DLMM. The Exchange notes that the proposal will have no effect on the existing participation entitlement program, except in the minority of situations where the DLMM participation entitlement is applied to Directed Orders of a contract size of two (2) or less. The Exchange believes it is appropriate and fair to preserve that intention by assuring that the Directed Order will trade at least one (1) contract with the DLMM.
Written comments were neither solicited nor received.
Within 45 days of the date of publication of this notice in the
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.
All submissions should refer to File Number SR–MIAX–2013–21. This file number should be included on the subject line if email is used. To help the Commission process and review your comments more efficiently, please use only one method. The Commission will post all comments on the Commission's Internet Web site (
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 is filing with the Commission a proposal to correct a typographical error in the title of the Rule 1000D Series of Rules (Rules Applicable to the Trading of Options on Treasury Securities) and a typographical error in Rule 1004D (Reports Related to Position Limits and Liquidation of Positions—Treasury Securities Options).
The Exchange requests that the Commission waive the 30-day operative delay period contained in Exchange Act Rule 19b–4(f)(6)(iii).
The text of the proposed rule change is available on the Exchange's Web site at
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
The purpose of this filing is to correct a typographical error in the title of the Rule 1000D Series and in Rule 1004D, and thereby clarify and conform Exchange rules pertaining to listing options on Treasury securities (“Treasury securities options”).
As of October 2012, Treasury security options are listed, pursuant to the Rule 1000D Series, on Treasury bonds or notes.
First, in the name of the Rule 1000D Series, Rules Applicable to Trading of Options on Treasury Securities (Rules 1000D–1026D) (“the initial rule name”), the Exchange is changing the final rule number from 1026D to 1025D. This is done to clarify and conform the number in the initial rule name to the actual last rule number in the Rule 1000D Series, which is Rule 1025D, as well as with the rule filing initially adopting these requirements, which reflects Rule 1025D as the last rule in the Rule 1000D Series.
Second, in Rule 1004D, the Exchange is changing the number from $20 million principal amount to $2 million principal amount. This is done to clarify and conform the principal amount in Rule 1004D with the rule filing initially adopting these requirements, which reflects $2 million principal amount.
The intent was, and is, to reflect the last rule number and the principal amount as proposed herein.
The Exchange believes that its proposal is consistent with Section 6(b) of the Act
Phlx does not believe that the proposed rule change will impose any burden on competition not necessary or appropriate in furtherance of the purposes of the Act. The Exchange believes that while rule clarity is generally pro-competitive, the act of clarifying and conforming two non-substantive typographical errors should have little, if any, impact on competition.
No written comments were either solicited or received.
The Exchange believes that the foregoing proposed rule change may take effect upon filing with the Commission pursuant to Section 19(b)(3)(A) of the Act
The Exchange has asked the Commission to waive the 30-day operative delay so that the proposal may become operative immediately upon filing. The Commission believes that waiver of the operative delay is consistent with the protection of investors and the public interest because this rule change is not proposing any substantive changes and is merely correcting inaccuracies in the Exchange's rules. This should eliminate member confusion and provide clarity on how the rules apply. Therefore, the Commission designates the proposal operative upon filing.
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: (i) Necessary or appropriate in the public interest; (ii) for the protection of investors; or (iii) 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.
To help the Commission process and review your comments more efficiently, please use only one method. The Commission will post all comments on the Commission's Internet Web site (
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 Fees Schedule. 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 Exchange recently amended its Fees Schedule to add to Footnote 25 the statement that any Floor Broker Trading Permit Holder that executes an average of 15,000 customer open-outcry contracts per day (“CPD”) over the course of a calendar month in multiply-listed options classes will receive a rebate of $7,500 on that Floor Broker Trading Permit Holder's Floor Broker Trading Permit fees (the “Rebate”).
However, in an effort to make the Rebate program's details clear, the Exchange now proposes to add the following clarifying language to the end of Footnote 25: For purposes of determining the rebate, the qualifying volume of all Floor Broker Trading Permit Holders affiliated with a single TPH organization will be aggregated, and, if such total meets or exceeds the 15,000 customer open-outcry contracts per day threshold in multiply-listed options classes, that TPH organization will receive a single $7,500 rebate, regardless of the number of Floor Broker Trading Permits affiliated with that TPH organization. The purpose of aggregating the qualifying volume of all Floor Broker Trading Permit Holders affiliated with a single TPH organization is to make it easier for such TPH organizations that have a number of Floor Broker Trading Permit Holders affiliated with them to be able to reach the threshold. The purpose of stipulating that each TPH organization will receive a single rebate is to ensure that the Rebate program is economically viable for the Exchange.
The Exchange believes the proposed rule change is consistent with the Act and the rules and regulations thereunder applicable to the Exchange and, in particular, the requirements of Section 6(b) of the Act.
CBOE 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. CBOE does not believe that aggregating the qualifying volume of all Floor Broker Trading Permit Holders affiliated with a single TPH organization will impose any burden on intramarket competition that is not necessary or appropriate in furtherance of the purposes of the Act because it will incentivize TPH organizations with affiliated Floor Broker Trading Permit Holders to encourage such Floor Broker Trading Permit Holders to transact more qualifying volume, which should increase volume, which would benefit all market participants (including Floor Broker Trading Permit Holders and TPH organizations with affiliated Floor Broker Trading Permit Holders who do not hit the 15,000 contracts-per-day threshold (indeed, this increased volume could make it possible for some such Floor Brokers and/or TPH organizations to hit the 15,000 contracts-per-day threshold)). CBOE does not believe that limiting TPH organizations to receiving one $7,500 rebate per month will impose any burden on intramarket competition that is not necessary or appropriate in furtherance of the purposes of the Act because this limitation applies to all qualifying TPH organizations.
CBOE does not believe that the proposed rule change will impose any burden on intermarket competition that is not necessary or appropriate in furtherance of the purposes of the Act because the proposed changes only apply to Floor Brokers at CBOE. To the extent that aggregating the qualifying volume of all Floor Broker Trading Permit Holders affiliated with a single TPH organization proves attractive to market participants on other exchanges, such Floor Brokers or market participants may elect to become Floor Brokers or market participants at CBOE.
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.
Federal Aviation Administration (FAA), DOT.
Notice of Availability; reopening of comment period.
This notice announces the reopening of the comment period on the availability of draft Airman Certification Standards (ACS) documents developed by the Airman Testing Standards and Training WG for the private pilot certificate and the instrument rating. These documents are available for public review, download, and comment.
The comment period for the notice published on April 24, 2013 (78 FR 24289) closed May 24, 2013, and is reopened until July 8, 2013.
Send comments identified by docket number FAA–2013–0316 using any of the following methods:
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Van L. Kerns, Manager, Regulatory Support Division, FAA Flight Standards Service, AFS 600, FAA Mike Monroney Aeronautical Center P.O. Box 25082 Oklahoma City, OK 73125; telephone (405) 954–4431, email
On April 24, 2013, the FAA established Docket No. FAA–2013–0316 for the purpose of enabling the public to comment on some draft documents developed by the Airman Testing Standards and Training Working Group. The following documents were placed in that docket for public review and comment:
(1) Background Information; Industry-Led Changes to FAA Airman Testing Standards and Training
(2) Draft PRIVATE PILOT—AIRPLANE Airman Certification Standards;
(3) Draft Change Tracking Matrix referenced to FAA–S–8081–14B, Private Pilot Practical Test Standards for Airplane (Single Engine Land and Single-Engine Sea Areas of Operation); Section 1: Private Pilot
(4) Draft INSTRUMENT RATING—Airman Certification Standards; and
(5) Draft Change Tracking Matrix referenced to FAA–S–8081–4E, Instrument Rating Practical Test Standards for Airplane, Helicopter, and Powered Lift
During the initial 30-day comment period, which closed on May 24, 2013, more than 130 individuals and organizations posted comments on these documents. The ATSTWG received a wide range of comments that provided suggestions on how the ATSTWG could further improve its draft PRIVATE PILOT—AIRPLANE and draft INSTRUMENT RATING Airman
The ATSTWG's work is intended to improve the relevance, reliability, validity, and effectiveness of the FAA's aeronautical testing and training materials, as well as to support the FAA's goal of reducing fatal general aviation accidents by incorporating task-specific risk management considerations into each Area of Operation. Because the ACS documents are intended to be the foundation for transitioning to a more integrated and systematic approach to airman certification testing and training, the ATSTWG wishes to benefit from the broadest possible range of public comment on the work it will submit to the FAA via the Aviation Rulemaking Advisory Committee in September 2013. The ATSTWG has asked the FAA to extend the public comment period by an additional 30 days, and the FAA has accordingly reopened the docket, as noted in the
The ATSTWG will continue its additional work on remaining assignments, including development of the authorized instructor ACS document. The ATSTWG expects to make the authorized instructor ACS document available for public review and comment at a later date.
Federal Highway Administration (FHWA), DOT.
Notice; request for comment.
The National Bridge Inspection Standards (NBIS), codified in 23 CFR 650 Subpart C, establishes the minimum standards for inspection of all structures defined as highway bridges on public roads. The FHWA annually reviews each State's bridge inspection program to evaluate compliance with the NBIS. In 2011, FHWA implemented a new systematic, data-driven, risk-based oversight process which is used by FHWA Divisions to review State compliance with the NBIS. The new process was developed prior to the establishment of the review requirements identified in the Moving Ahead for Progress in the 21st Century Act (MAP–21), Section 1111. Development of the internal FHWA review process included consultation with stakeholders through a pilot project, a joint FHWA/AASHTO task force, as well as with individual States and Federal agencies during the initial implementation of the process in 2011. The FHWA intends to continue this data-driven, risk-based review process to evaluate State compliance with the NBIS, including incorporation of any modifications based upon the comments received through this Notice.
Comments must be received on or before July 8, 2013. Late comments will be considered to the extent practicable.
Mail or hand deliver comments to the U.S. Department of Transportation, Dockets Management Facility, Room W12–140, 1200 New Jersey Avenue SE., Washington, DC 20590, or fax comments to (202) 493–2251. Alternatively, comments may be submitted to the Federal eRulemaking portal at
For questions about the program discussed herein, contact Thomas D. Everett, Principal Bridge Engineer, FHWA Office of Bridge Technology, (202) 366–4675 or via email at
You may submit or retrieve comments online through the Federal eRulemaking portal at:
The FHWA is requesting comment on the process FHWA uses to conduct reviews of State compliance with the NBIS and the associated penalty process for findings of noncompliance. Comments received through this Notice will be considered by FHWA for improving the review process.
For more than 30 years, the FHWA has annually assessed each State's bridge inspection program to evaluate compliance with the NBIS as codified at 23 CFR 650 Subpart C. Historically, the depth and scope of the reviews varied based upon the FHWA's knowledge of the State's inspection program and experience of the FHWA staff. In 2009, the Office of Inspector General (OIG) issued an audit report National Bridge Inspection Program: Assessment of FHWA's Implementation of Data-Driven, Risk-Based Oversight
Section 1111 of the MAP–21 (Pub. L. 114–141, 126 Stat. 405) modified 23 U.S.C. 144(h)(3)(A)(i) to include provisions for the Secretary to establish, in consultation with the States, Federal agencies, and interested and knowledgeable private organizations and individuals, procedures to conduct reviews of State compliance with the NBIS. The MAP–21 also establishes a penalty for States determined to be in noncompliance with the NBIS in 23 U.S.C. 144(h)(5).
The FHWA developed and implemented the current review process to evaluate a State's bridge inspection program for compliance with the NBIS prior to the requirements of MAP–21, Section 1111. The development of the review process included consultation with stakeholders through the pilot project, the joint FHWA/AASHTO taskforce, as well as with individual States and Federal agencies during the initial implementation of the process in 2011. The FHWA intends to continue using the data-driven, risk-based review process that was implemented in 2011 to evaluate State compliance with the NBIS as required by 23 U.S.C. 144(h)(4)(A). The FHWA also proposes to implement the penalty provisions in 23 U.S.C. 144(h)(5) using the process described below. Comments are hereby requested on FHWA's plan to review compliance and address noncompliance as outlined below.
Each FHWA Division office annually assesses the State's compliance with 23 individual metrics which are directly aligned with the existing NBIS regulation. The risk-based assessment process followed during this annual assessment utilizes objective data, employs statistical sampling of data and inspection records, and includes defined criteria for compliance for each metric. States are notified by FHWA of any findings of noncompliance no later than December 31. In accordance with the requirements of 23 U.S.C. 144 as established by MAP–21, within 45 days of the FHWA notification of noncompliance, the State will correct the issue of noncompliance or submit to FHWA a Plan of Corrective Action (PCA) which outlines how noncompliant findings will be addressed. The FHWA will have 45 days for review, comment, and if appropriate accept the PCA. Final compliance determinations by FHWA are to be made no later than March 31. This annual process allows the FHWA to assess NBIS compliance by each State's bridge inspection program and implements any required penalties in a nationally consistent manner.
The metrics, or measures, are designed to assess the quality and performance of each State's bridge inspection program and, collectively, the national program that has been established to assure highway bridges are safe. The following 23 metrics are directly aligned with the existing requirements of the NBIS and have been established to provide a comprehensive assessment of compliance with the NBIS.
Each metric consists of four parts; (1) NBIS component to be reviewed, (2) compliance levels, (3) evaluation criteria, and (4) assessment levels.
Each metric identifies the relevant provisions of the NBIS and focuses on a key inspection area for which compliance will be assessed.
Each of the 23 metrics is annually assessed and assigned one of four compliance levels—compliant, substantially compliant, noncompliant, or conditionally compliant—based upon specific thresholds or measures for each compliance level for each metric. The degrees of compliance are described as follows:
The four compliance levels are grouped into bridge inspection program performance levels for clarity in communicating the results:
Compliant and substantially compliant metrics are grouped to represent program performance at the satisfactory level. Conditionally compliant metrics represent a program area that is categorized as actively improving, and noncompliant represents a program performance at the unsatisfactory level.
Improvement plans and plans of corrective action are defined as follows:
The evaluation criteria identify the specific measures for each metric for which compliance will be evaluated.
Assessment levels define the review requirements necessary to make a compliance determination for a specific metric. Three assessment levels have been identified as follows:
Random samples are selected from the population identified for the specific metric.
A copy of the metrics is available on the docket (docket number FHWA–2013–0021) through the Federal eRulemaking portal at:
In accordance with 23 U.S.C. 144(h)(4), FHWA will annually review State compliance with the NBIS. In calendar year 2011, FHWA performed a baseline assessment in which all 23 metrics were reviewed at the intermediate assessment level. Subsequent reviews will utilize the following process.
A 5-year review cycle shall consist of:
(a) Each of the 23 metrics being assessed annually at the minimum level if an intermediate or in-depth level is not to be performed that year.
(b) Each of the 23 metrics being assessed at the intermediate or in-depth level at least once within the 5-year cycle.
(c) A 5-year plan which identifies the review strategy and schedule based upon the consideration of risk. The assessment level of effort for metrics with higher risk will vary at the discretion of the FHWA Division office from minimum, intermediate, or in-depth, or as directed at the national level. The 5-year plan is intended to be updated as necessary based on the risks identified during the annual metric assessments.
(d) In year five, FHWA will examine the 5-year review history to identify trends in each metric area, to identify any gaps in the program or review process, and to develop a review strategy for the next 5 years.
(e) At the completion of a PCA the metric will be assessed at the intermediate level or in-depth level. The determination of either an intermediate or in-depth level review after completion of a PCA is at the discretion of the FHWA Division.
Each FHWA Division will conduct an annual assessment of the State's compliance with the NBIS. Key dates are as follows:
(a) April 1—FHWA begins annual NBIS assessment.
(b) By December 31—FHWA makes compliance assessment for each metric and issues a report to each State detailing issues of noncompliance or substantial compliance.
(c) March 31—Final compliance determination completed for all metrics. The final determination is based on the resolution of compliance issues or development of an acceptable PCA following the December 31 notification.
The proposed schedule may need to be modified on a case-by-case basis when unique and unexpected extenuating circumstances arise. The FHWA will address this issue on a case-by-case basis when it arises.
Where an issue of noncompliance with the NBIS is identified outside the review procedures above, the FHWA will notify the State of the noncompliance and will work with the State to establish a timeframe in which the issue of noncompliance must be addressed or an acceptable PCA submitted.
The FHWA Division offices will issue a report to the State detailing the issues of noncompliance for a metric determined to be noncompliant by December 31 of the review period. The report will list the regulatory code and title for each noncompliance deficiency, identify the deficiency, and specify that
(a) Identify area of noncompliance;
(b) Identify the date FHWA notified State of noncompliance;
(c) Identify actions to be taken to address areas of noncompliance;
(d) Estimate duration and completion date for each action;
(e) Define frequency and reporting format which will be used to monitor; progress towards successful completion of the PCA; and
(f) Identify what the State considers to be successful completion of PCA.
After the State submits a PCA, FHWA will have 45 days to review and if appropriate, accept the submitted PCA. Upon FHWA acceptance of the PCA, the final compliance determination for the associated metric will be conditionally compliant. If the PCA is not submitted to FHWA in 45 days after notification of noncompliance or the PCA does not address the issues of noncompliance, the final compliance determination for the associated metric will be noncompliant.
The FHWA will continue to encourage the State to address the noncompliance issues following the final noncompliance determination and expiration of the period allowed to develop a PCA. If a State remains in noncompliance on August 1 following a final compliance determination of noncompliance, FHWA will require the State to dedicate funds to correct the noncompliance, in accordance with 23 U.S.C. 144(h)(5). The State must submit an analysis of actions needed to correct the finding of noncompliance to FHWA no later than August 1. The analysis must identify the actions to be taken, estimated duration and completion date for each action, and an itemized amount of funds to be directed for each action to address the noncompliance. The analysis plan will require the approval of the FHWA. The FHWA will require on October 1 of that year, and each year thereafter as may be necessary, the State to dedicate funds apportioned to the State under sections 23 U.S.C. 119 and 23 U.S.C. 133 to correct the issue of noncompliance.
23 U.S.C. 144 and 315; 23 CFR 1.32 and 650 Subpart C; 49 CFR 1.85.
Surface Transportation Board, DOT.
Notice.
The Board is publishing, and providing the public an opportunity to comment on, the 2012 weighted average state tax rates for each Class I railroad, as calculated by the Association of American Railroads (AAR), for use in the Revenue Shortfall Allocation Method (RSAM).
Comments are due by July 9, 2013. If any comment opposing AAR's calculation is filed, AAR's reply will be due by July 29, 2013. If no comments are filed by the due date, AAR's calculation of the 2012 weighted average state tax rates will be automatically adopted by the Board, effective July 10, 2013.
Comments may be submitted either via the Board's e-filing format or in traditional paper format. Any person using e-filing should attach a document and otherwise comply with the instructions at the E-FILING link on the Board's Web site at
Jonathon Binet, (202) 245–0368. Assistance for the hearing impaired is available through the Federal Information Relay Service (FIRS) at (800) 877–8339.
The RSAM figure is one of three benchmarks that together are used to determine the reasonableness of a challenged rate under the Board's
In
Any party wishing to comment on AAR's calculation of the 2011 weighted average state tax rates should file a comment by July 9, 2013.
This action will not significantly affect either the quality of the human environment or the conservation of energy resources.
By the Board, Rachel D. Campbell, Director, Office of Proceedings.
Missouri Central Railroad Company (MCRR) and Central Midland Railway Company (CMR) (collectively, applicants) have jointly filed a verified notice of exemption under 49 CFR part 1152 subpart F—
Applicants have certified that: (1) No local traffic has moved over the line for at least 2 years; (2) there is no overhead traffic on the line; (3) no formal complaint filed by a user of rail service on the line (or by a state or local government entity acting on behalf of such user) regarding cessation of service over the line either is pending with the Surface Transportation Board (Board) or with any U.S. District Court or has been decided in favor of complainant within the 2-year period; and (4) the requirements at 49 CFR 1105.7(c) (environmental report), 49 CFR 1105.11 (transmittal letter), 49 CFR 1105.12 (newspaper publication), and 49 CFR 1152.50(d)(1) (notice to governmental agencies) have been met.
As a condition to these exemptions, any employee adversely affected by the abandonment or discontinuance shall be protected under
Provided no formal expression of intent to file an offer of financial assistance (OFA) has been received, these exemptions will be effective on July 9, 2013, unless stayed pending reconsideration. Petitions to stay that do not involve environmental issues,
A copy of any petition filed with the Board should be sent to applicants' representatives: Sandra L. Brown, 1919 M St. NW., Suite 700, Washington, DC 20036, and Lon Van Gemert, 21778 Highview Ave., Lakeville, MN 55044.
If the verified notice contains false or misleading information, the exemptions are void
Applicants have filed a combined environmental and historic report which addresses the effects, if any, of the abandonment and discontinuance on the environment and historic resources. OEA will issue an environmental assessment (EA) by June 14, 2013. Interested persons may obtain a copy of the EA by writing to OEA (Room 1100, Surface Transportation Board, Washington, DC 20423–0001) or by calling OEA at (202) 245–0305. Assistance for the hearing impaired is available through the Federal Information Relay Service (FIRS) at 1–800–877–8339. Comments on environmental and historic preservation matters must be filed within 15 days after the EA becomes available to the public.
Environmental, historic preservation, public use, or trail use/rail banking conditions will be imposed, where appropriate, in a subsequent decision.
Pursuant to the provisions of 49 CFR 1152.29(e)(2), MCRR shall file a notice of consummation with the Board to signify that it has exercised the authority granted and fully abandoned the line. If consummation has not been effected by MCRR's filing of a notice of consummation by June 7, 2014, and there are no legal or regulatory barriers to consummation, the authority to abandon will automatically expire.
Board decisions and notices are available on our Web site at “
By the Board, Rachel D. Campbell, Director, Office of Proceedings.
National Cemetery Administration, Department of Veterans Affairs.
Notice.
The National Cemetery Administration (NCA), Department of Veterans Affairs (VA), is announcing an opportunity for public comment on the proposed collection of certain information by the agency. Under the Paperwork Reduction Act (PRA) of 1995, Federal agencies are required to publish notice in the
Written comments and recommendations on the proposed collection of information should be received on or before August 6, 2013.
Submit written comments on the collection of information through
Mechelle Powell at (202) 461–4114 or Fax (202) 273–6695.
Under the PRA of 1995 (Pub. L. 104–13; 44 U.S.C. 3501–21), Federal agencies must obtain approval from the Office of Management and Budget (OMB) for each collection of information they conduct or sponsor. This request for comment is being made pursuant to Section 3506(c)(2)(A) of the PRA.
With respect to the following collection of information, NCA invites comments on: (1) Whether the proposed collection of information is necessary for the proper performance of NCA's functions, including whether the information will have practical utility; (2) the accuracy of NCA's estimate of the burden of the proposed collection of information; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or the use of other forms of information technology.
a. Application for Standard Government Headstone or Marker for Installation in a Private or State Veterans' Cemetery, VA Form 40–1330.
b. Claim for Government Medallion for Installation in a Private Cemetery, VA Form 40–1330M.
a. The next of kin or other responsible parties of deceased Veterans complete VA Form 40–1330 to apply for Government provided headstones or markers for unmarked graves.
b. A family member complete VA Form 40–1330M to apply for a Government medallion to be affixed to privately purchased headstone or marker for a deceased Veteran buried in a private cemetery.
By direction of the Secretary.
Environmental Protection Agency (EPA).
Proposed rule.
EPA is proposing a regulation that would strengthen the controls on discharges from certain steam electric power plants by revising technology-based effluent limitations guidelines and standards for the steam electric power generating point source category. Steam electric power plants alone contribute 50–60 percent of all toxic pollutants discharged to surface waters by all industrial categories currently regulated in the United States under the Clean Water Act. Furthermore, power plant discharges to surface waters are expected to increase as pollutants are increasingly captured by air pollution controls and transferred to wastewater discharges. This proposal, if implemented, would reduce the amount of toxic metals and other pollutants discharged to surface waters from power plants. EPA is considering several regulatory options in this rulemaking and has identified four preferred alternatives for regulation of discharges from existing sources. These four preferred alternatives differ with respect to the scope of requirements that would be applicable to existing discharges of pollutants found in two wastestreams generated at power plants. EPA estimates that the preferred options for this proposed rule would annually reduce pollutant discharges by 0.47 billion to 2.62 billion pounds, reduce water use by 50 billion to 103 billion gallons, cost $185 million to $954 million, and would be economically achievable.
Comments on this proposed rule must be received on or before August 6, 2013. EPA will conduct a public hearing on the proposed pretreatment standards on July 9, 2013 at 1:00 p.m. in the EPA East Building, Room 1153, 1201 Constitution Avenue NW., Washington, DC.
Submit your comments on the proposed rule, identified by Docket No. EPA–HQ–OW–2009–0819 by one of the following methods:
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Submit any comments on the Coal Combustion Residuals Rule issues discussed in Section III.D of this
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Comments related to EPA's current thinking, as described in Section III.D, regarding how a final RCRA Coal Combustion Residuals rule might be aligned and structured to account for any final requirements adopted under the ELGs for the Steam Electric Power Generating point source category must be submitted to Docket ID Number Docket ID: EPA–HQ–RCRA–2013–0209.
For technical information, contact Jezebele Alicea-Virella, Engineering and Analysis Division, Telephone: 202–566–1755; Email:
This section is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be regulated by this proposed action. Other types of entities that do not meet the above criteria could also be regulated. To determine whether your facility would be regulated by this proposed action, you should carefully examine the applicability criteria listed in 40 CFR 423.10 and the definitions in 40 CFR 423.11 of the rule and detailed further in Section V—Scope/Applicability of the Proposed Rule, of this preamble. If you still have questions regarding the proposed applicability of this action to a particular entity, consult the person listed for technical information in the preceding
The public may submit comments in written or electronic form. (See the
The rule proposed today is supported by a number of documents including:
• Technical Development Document for Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (TDD), Document No. EPA–821–R–13–002.
• Environmental Assessment for the Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (Environmental Assessment), Document No. EPA–821–R–13–003.
• Benefits and Cost Analysis for the Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category, Document No. EPA–821–R–13–004.
• Regulatory Impact Analysis for Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (RIA), Document No. EPA–821–R–13–005.
These documents are available in the public record for this rule and on EPA's Web site at
This preamble describes the terms, acronyms, and abbreviations used in this notice; the background documents that support these proposed regulations; the legal authority for the proposed rule; a summary of the options considered for the proposal; background information; and the technical and economic methodologies used by the Agency to develop these proposed regulations. In addition, this preamble also solicits comment and data from the public. The following outline summarizes the organization of this document.
EPA is proposing revisions to the effluent limitations guidelines and standards for the Steam Electric Power Generating Point Source Category (40 CFR 423) under the authority of Sections 301, 304, 306, 307, 308, 402, and 501 of the Clean Water Act, 33 U.S.C. 1311, 1314, 1316, 1317, 1318, 1342, and 1361.
The steam electric power generating point source category (i.e., steam electric industry) consists of plants that generate electricity from a process utilizing fossil or nuclear fuel in conjunction with a thermal cycle employing the steam/water system as the thermodynamic medium. The proposed regulations would strengthen the controls on discharges from steam electric power plants by revising the technology-based effluent limitations guidelines and standards that apply to wastewater discharges to surface waters (i.e., direct discharges) and to publicly owned treatment works (i.e., indirect discharges to POTWs). The proposed requirements would reduce the amount of metals and other pollutants discharged to surface waters from power plants.
EPA is considering several options in this rulemaking and has identified four preferred alternatives for regulation of discharges from existing sources. These four preferred alternatives propose the same requirements for most wastestreams but, as described below in Section II.B., differ in the requirements that would be established for discharges associated with two wastestreams from existing sources. EPA also projects different levels of pollutant reduction and cost associated with these alternatives.
EPA estimates that the preferred regulatory options would reduce pollutant discharges by 0.47 billion to 2.62 billion pounds annually, and reduce water use by 50 billion to 103 billion gallons per year. EPA predicts substantial environmental and ecological improvements would result under the preferred regulatory options, along with reduced impacts to wildlife and human health.
The current regulations, which were last updated in 1982, do not adequately address the toxic pollutants discharged from the electric power industry, nor have they kept pace with process changes that have occurred over the last three decades. The development of new technologies for generating electric power (e.g., coal gasification) and the widespread implementation of air pollution controls (e.g., flue gas desulfurization (FGD), selective catalytic reduction (SCR), and flue gas mercury controls (FGMC)) have altered existing wastestreams or created new wastewater streams at many power plants.
As a result, each year the pollutant discharges from this industry are increasing in volume and total mass, and currently account for approximately 50–60 percent of all toxic pollutants discharged into surface waters by all industrial categories currently regulated under the CWA. See Section 3.2.2 of the Environmental Assessment for the Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (Environmental Assessment)—EPA 821–R–13–003. The main pollutants of concern for these discharges include metals (e.g., mercury, arsenic, selenium), nitrogen, and total dissolved solids (TDS). As discussed in Section XIII and the Environmental Assessment report, there are numerous documented instances of environmental impact associated with these power plant discharges, such as harm to human health, harm to aquatic life, contamination of sediment, and detrimental impacts to wildlife. Water quality modeling, in addition to the documented damage cases, corroborates these impacts and indicates that the toxic discharges are a source of widespread aquatic-life impacts, and a source of increased cancer and non-cancer risks in humans, and toxic metal bioaccumulation in wildlife. These discharges also contribute large cumulative nutrient pollutant loads to sensitive watersheds, upsetting the natural balance of such waterbodies as the Great Lakes and the Chesapeake Bay.
This proposed rule would reduce current toxic and other pollutant discharges and their associated impacts. In general, depending on the option, the proposed rule would establish new or additional requirements for wastewaters associated with the following processes and byproducts: Flue gas desulfurization (FGD), fly ash, bottom ash, flue gas mercury control, combustion residual leachate from landfills and surface impoundments, nonchemical metal cleaning wastes, and gasification of fuels such as coal and petroleum coke. In addition to the proposed requirements, as part of this rulemaking EPA is considering establishing best management practices (BMP) requirements that would apply to surface impoundments containing coal combustion residuals (e.g., ash ponds, FGD ponds). EPA is also considering establishing a voluntary program that would provide incentives for existing power plants that dewater and close their surface impoundments containing combustion residuals, and for power plants that eliminate the discharge of all process wastewater (excluding cooling water discharges).
The major provisions of the proposed rule are summarized below. In addition, the proposed requirements and the technologies that serve as the basis for these requirements are explained in more detail in Section VIII of this preamble.
Depending on the option, EPA is proposing to revise or establish Best Available Technology Economically Achievable (BAT), New Source Performance Standards (NSPS), Pretreatment Standards for Existing Sources (PSES) and Pretreatment Standards for New Sources (PSNS) that apply to discharges of pollutants found in the following wastestreams: FGD wastewater, fly ash transport water, bottom ash transport water, combustion residual leachate from landfills and surface impoundments, nonchemical metal cleaning wastes, and wastewater from flue gas mercury control (FGMC) systems and gasification systems.
EPA has identified four preferred alternatives for regulation of existing discharges in the proposed rule (and it has identified one preferred alternative for regulation of new sources). These four preferred alternatives are summarized below.
• “Zero discharge” effluent limit for all pollutants in fly ash transport water and wastewater from flue gas mercury control systems;
• Numeric effluent limits for mercury, arsenic, selenium and TDS in discharges of wastewater from gasification processes;
• Numeric effluent limits for copper and iron in discharges of nonchemical metal cleaning wastes;
• Effluent limits for bottom ash transport water and combustion residual leachate from landfills and surface impoundments that are equal to the current Best Practicable Control Technology Currently Available (BPT) effluent limits for these discharges (i.e., numeric effluent limits for TSS and oil and grease.
Under a second preferred alternative for BAT (referred to as Option 3b in this proposal), the proposed rule would establish numeric effluent limits for mercury, arsenic, selenium, and nitrate-nitrite in discharges of FGD wastewater from certain steam electric facilities (those with a total plant-level wet scrubbed capacity of 2,000 MW or greater
Under a third preferred alternative for BAT (referred to as Option 3 in this proposal), the proposed rule would establish numeric effluent limits for mercury, arsenic, selenium, and nitrate-nitrite in discharges of FGD wastewater, with the exception of small generating units (i.e., 50 MW or smaller). All other proposed Option 3 requirements are identical to the proposed Option 3a requirements described above.
Under a fourth preferred alternative for BAT (referred to as Option 4a in this proposal), the proposed rule would establish “zero discharge” effluent limits for all pollutants in bottom ash transport water, with the exception of all generating units with a nameplate capacity of 400 MW or less (for those generating units that are less than or equal to 400 MW, the proposed rule would set BAT equal to BPT for discharges of pollutants found in the bottom ash transport water). All other proposed Option 4a requirements are identical to the proposed Option 3 requirements described above.
In addition, for oil-fired generating units and small generating units (i.e., 50 MW or smaller
• Numeric standards for discharges of nonchemical metal cleaning wastes would be established only for copper;
• Under Options 3a, 3b, and 3 for PSES, EPA is not proposing to establish pretreatment standards for discharges of bottom ash transport water. Under Option 4a, EPA is not proposing to establish pretreatment standards for discharges of bottom ash transport water for generating units with a nameplate capacity of 400 MW or less;
• Other than the pretreatment standards for nonchemical metal cleaning wastes, EPA is not proposing to establish pretreatment standards for existing sources for discharges from existing oil-fired units and small generating units (i.e., 50 MW or smaller).
• Numeric standards for mercury, arsenic, selenium, and nitrate-nitrite in discharges of FGD wastewater;
• Maintaining the current “zero discharge” standard for all pollutants in fly ash transport water for direct dischargers;
• Establishing “zero discharge” standards for all pollutants in bottom ash transport water and wastewater from flue gas mercury control systems;
• Numeric standards for mercury, arsenic, selenium, and TDS in discharges of wastewater from gasification processes;
• Numeric standards for mercury and arsenic in discharges of combustion residual leachate; and
• Numeric standards for TSS, oil and grease, copper, and iron in discharges of nonchemical metal cleaning wastes.
Additional details about the proposed effluent limitations and standards are described in Sections VIII and X of this preamble.
Table II–1 summarizes the benefits
It is important to note that although point estimates are provided in this table, the benefits estimates rely on complex models that include a variety of assumptions, each of which introduces considerable uncertainty into these estimates. This uncertainty is discussed in the Benefits and Cost Analysis for the Proposed Effluent
Congress passed the Federal Water Pollution Control Act Amendments of 1972, also known as the Clean Water Act (CWA), to “restore and maintain the chemical, physical, and biological integrity of the Nation's waters.” 33 U.S.C. 1251(a). The CWA establishes a comprehensive program for protecting our nation's waters. Among its core provisions, the CWA prohibits the discharge of pollutants from a point source to waters of the U.S., except as authorized under the CWA. Under section 402 of the CWA, discharges may be authorized through a National Pollutant Discharge Elimination System (NPDES) permit. The CWA also authorizes EPA to establish national technology-based effluent limitations guidelines and standards (ELGs) for discharges from different categories of point sources, such as industrial, commercial, and public sources.
The CWA authorizes EPA to promulgate nationally applicable pretreatment standards that restrict pollutant discharges from facilities that discharge wastewater indirectly through sewers flowing to publicly owned treatment works (POTWs), as outlined in sections 307(b) and (c), 33 U.S.C. 1317(b) and (c). EPA establishes national pretreatment standards for those pollutants in wastewater from indirect dischargers that may pass through, interfere with, or are otherwise incompatible with POTW operations. Generally, pretreatment standards are designed to ensure that wastewaters from direct and indirect industrial dischargers are subject to similar levels of treatment. See CWA section 301(b), 33 U.S.C. 1311(b). In addition, POTWs are required to implement local treatment limits applicable to their industrial indirect dischargers to satisfy any local requirements. See 40 CFR 403.5.
Direct dischargers (i.e., those discharging directly to surface waters) must comply with effluent limitations in NPDES permits. Indirect dischargers, who discharge through POTWs, must comply with pretreatment standards. Technology-based effluent limitations in NPDES permits are derived from effluent limitations guidelines (CWA sections 301 and 304, 33 U.S.C. 1311 and 1314) and new source performance standards (CWA section 306, 33 U.S.C. 1316) promulgated by EPA, or based on best professional judgment (BPJ) where EPA has not promulgated an applicable effluent guideline or new source performance standard (CWA section 402(a)(1)(B), 33 U.S.C. 1342(a)(1)(B)). Additional limitations based on water quality standards are also required to be included in the permit in certain circumstances. CWA section 301(b)(1)(C), 33 U.S.C. 1311(b)(1)(C). The ELGs are established by regulation for categories of industrial dischargers and are based on the degree of control that can be achieved using various levels of pollution control technology.
EPA promulgates national ELGs for major industrial categories for three classes of pollutants: (1) Conventional pollutants (i.e., total suspended solids, oil and grease, biochemical oxygen demand (BOD
EPA develops effluent guidelines that are technology-based regulations for a category of dischargers. EPA bases these regulations on the performance of control and treatment technologies. The legislative history of CWA section 304(b), which is the heart of the effluent guidelines program, describes the need to press toward higher levels of control through research and development of new processes, modifications, replacement of obsolete plants and processes, and other improvements in technology, taking into account the cost of controls. Congress has also stated that EPA need not consider water quality impacts on individual water bodies as the guidelines are developed; see Statement of Senator Muskie (October 4, 1972), reprinted in Legislative History of the Water Pollution Control Act Amendments of 1972, at 170. (U.S. Senate, Committee on Public Works, Serial No. 93–1, January 1973.)
There are four types of standards applicable to direct dischargers (plants that discharge directly to surface waters), and two standards applicable to indirect dischargers (plants that discharge to POTWs), described in detail below.
Traditionally, EPA defines BPT effluent limitations based on the average of the best performances of facilities within the industry, grouped to reflect various ages, sizes, processes, or other common characteristics. EPA may promulgate BPT effluent limits for conventional, toxic, and nonconventional pollutants. In specifying BPT, EPA looks at a number of factors. EPA first considers the cost of achieving effluent reductions in relation to the effluent reduction benefits. The Agency also considers the age of equipment and facilities, the
The 1977 amendments to the CWA require EPA to identify additional levels of effluent reduction for conventional pollutants associated with BCT technology for discharges from existing industrial point sources. In addition to other factors specified in section 304(b)(4)(B), the CWA requires that EPA establish BCT limitations after consideration of a two-part “cost reasonableness” test. EPA explained its methodology for the development of BCT limitations in July 9, 1986 (51 FR 24974). Section 304(a)(4) designates the following as conventional pollutants: BOD
BAT represents the second level of stringency for controlling direct discharge of toxic and nonconventional pollutants. In general, BAT ELGs represent the best available economically achievable performance of facilities in the industrial subcategory or category. As the statutory phrase intends, EPA considers the technological availability and the economic achievability in determining what level of control represents BAT. CWA section 301(b)(2)(A), 33 U.S.C. 1311(b)(2)(A). Other statutory factors that EPA considers in assessing BAT are the cost of achieving BAT effluent reductions, the age of equipment and facilities involved, the process employed, potential process changes, and non-water quality environmental impacts, including energy requirements and such other factors as the Administrator deems appropriate. CWA section 304(b)(2)(B), 33 U.S.C. 1314(b)(2)(B). The Agency retains considerable discretion in assigning the weight to be accorded these factors.
NSPS reflect effluent reductions that are achievable based on the best available demonstrated control technology (BADCT). Owners of new facilities have the opportunity to install the best and most efficient production processes and wastewater treatment technologies. As a result, NSPS should represent the most stringent controls attainable through the application of the BADCT for all pollutants (that is, conventional, nonconventional, and toxic pollutants). In establishing NSPS, EPA is directed to take into consideration the cost of achieving the effluent reduction and any non-water quality environmental impacts and energy requirements. CWA section 306(b)(1)(B), 33 U.S.C. 1316(b)(1)(B).
Section 307(b), 33 U.S.C. 1317(b), of the Act calls for EPA to issue pretreatment standards for discharges of pollutants to POTWs. PSES are designed to prevent the discharge of pollutants that pass through, interfere with, or are otherwise incompatible with the operation of POTWs. Categorical pretreatment standards are technology-based and are analogous to BPT and BAT effluent limitations guidelines, and thus the Agency typically considers the same factors in promulgating PSES as it considers in promulgating BAT. The General Pretreatment Regulations, which set forth the framework for the implementation of categorical pretreatment standards, are found at 40 CFR part 403. These regulations establish pretreatment standards that apply to all non-domestic dischargers. See 52 FR 1586 (January 14, 1987).
Section 307(c), 33 U.S.C. 1317(c), of the Act calls for EPA to promulgate PSNS. Such pretreatment standards must prevent the discharge of any pollutant into a POTW that may interfere with, pass through, or may otherwise be incompatible with the POTW. EPA promulgates PSNS based on best available demonstrated control technology (BADCT) for new sources. New indirect dischargers have the opportunity to incorporate into their facilities the best available demonstrated technologies. The Agency typically considers the same factors in promulgating PSNS as it considers in promulgating NSPS.
EPA promulgated BPT, BAT, NSPS, and PSNS for the steam electric point source category on October 8, 1974 (39 FR 36186, as amended at 40 FR 7095, February 19, 1975; 40 FR 23987, June 4, 1975) (the “1974 regulations”). The 1974 regulations controlled two basic kinds of discharges from power plants: (1) Thermal discharges (discharges of heat) and (2) pollutant discharges (e.g., discharges of chlorine, polychlorinated biphenyls (PCBs), and suspended solids). EPA promulgated non-thermal pollutant limitations applicable to discharges from the following wastestreams: Once-through cooling water, cooling tower blowdown, bottom ash transport water, fly ash transport water, boiler blowdown, metal cleaning wastes, low volume wastes, and material storage and construction site runoff (including coal pile runoff).
On July 16, 1976, the U.S. Court of Appeals for the Fourth Circuit remanded the following provisions of the 1974 regulations: (1) The thermal limitations, (2) the NSPS for fly ash transport water, (3) the rainfall runoff limitations for material storage and construction site runoff, and (4) the BPT variance clause. All other provisions of the regulations were upheld.
EPA promulgated PSES on March 23, 1977 (42 FR 15695) applicable only to indirect discharges of copper present in metal cleaning wastes and PCBs and oil and grease for all wastestreams.
On November 19, 1982, EPA revised and supplemented the effluent limitations guidelines and standards for BCT, BPT, BAT, BADCT/NSPS, PSES, and PSNS (47 FR 52290). Under the 1982 revisions, EPA reserved BCT limitations for all wastestreams and withdrew the BAT limitations for TSS and oil and grease from all wastestreams because those pollutants are properly regulated under BCT, instead of BAT. The rule also made revisions to the following effluent limitations guidelines and standards: BAT and NSPS for once-through cooling water; BAT, NSPS, PSES, and PSNS for cooling tower blowdown; NSPS and PSNS for fly ash transport water; NSPS for bottom ash transport water; and PSES and PSNS for chemical metal cleaning wastes. Finally, the rule revised the definition of low volume wastes to include boiler blowdown and withdrew the separate regulation for boiler blowdown.
Section 304 of the CWA requires EPA to periodically review all effluent limitations guidelines and standards to determine whether revisions are warranted. In addition, Section 304(m) of the CWA requires EPA to develop and publish, biennially, a plan that establishes a schedule for reviewing and revising promulgated national effluent guidelines required by Section 304(b) of the CWA. During the 2005 annual review of the existing effluent guidelines for all categories, EPA identified the regulations governing the steam electric power generating point source category for possible revision. At that time, publicly available data reported through the NPDES permit program and the Toxics Release Inventory (TRI) indicated that the industry ranked high in discharges of toxic and nonconventional pollutants. Because of these findings, EPA initiated a more detailed study of the category to determine if the effluent guidelines should be revised. (See “Steam Electric Power Generating Point Source Category: Final Detailed Study Report” (EPA 821–R–09–008) at
During the detailed study, EPA collected data about the industry in several ways. EPA conducted site visits and sampled wastewater at steam electric power plants, and EPA distributed a questionnaire to collect data from nine companies. EPA also reviewed numerous publicly available sources of data and coordinated with and solicited data from EPA program offices and other government organizations (e.g., state groups and permitting authorities), as well as industry, environmental groups, and other stakeholders.
As part of the detailed study, EPA evaluated a range of wastestreams and processes associated with the industry, but it ultimately focused largely on discharges associated with coal ash handling operations and wastewater from FGD air pollution control systems because these sources are responsible for the majority of the toxic pollutants currently discharged by steam electric power plants. EPA also identified several wastestreams that are relatively new to the industry (e.g., carbon capture wastewater), and wastestreams for which there was little characterization data at the time of the detailed study (e.g., gasification wastewater).
During the study, EPA found that the use of wet FGD systems (the kind of systems that generate discharges) to control sulfur dioxide (SO
EPA found that technologies that do not use water to transport ash are available for handling the fly ash (a combustion residual of fine ash particles entrained in the flue gases) generated at plants, and that such technologies do not generate nor discharge wastewater associated with handling fly ash (i.e., fly ash transport water). Most of these systems are operated at newer electric generating units because the current NSPS regulations, which were promulgated in 1982, prohibit the discharge of pollutants in fly ash transport water. Many older generating units have also converted to dry fly ash handling systems that use air (i.e., pneumatic systems that use air pressure and/or vacuum) to transport the fly ash to storage silos instead of using water to sluice the ash (i.e., pump as a mixture of water and ash) to surface impoundments. As a result, over 80 percent of existing plants use dry fly ash handling. For further information, see Section 4.3.1 of the Technical Development Document for Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (TDD)—EPA 821–R–13–002.
Additionally, there are technologies available for handling the bottom ash (i.e., a combustion residual of heavier ash particles collected at the bottom of a boiler) that either do not use water to transport the bottom ash away from the boiler or that manage the transport water in a manner (i.e., closed-loop) that eliminates the need to discharge bottom ash transport water to surface water. Neither of these approaches discharge wastewater associated with transporting bottom ash. In fact, some of these technologies do not even generate bottom ash transport water. EPA estimates that by the time the final rule is promulgated, approximately 45 percent of plants will use dry bottom ash handling systems or will not discharge bottom ash transport water.
From information obtained during the detailed study, EPA found that the fly ash and bottom ash transport waters generated from wet systems at coal-fired power plants are created in large quantities and contain significant concentrations of metals, including arsenic, selenium and mercury. Additionally, EPA determined that some of the metals are present primarily in the dissolved phase, and generally are not removed in the surface impoundments that are used to treat these wastestreams to meet the current BPT limits for TSS and oil and grease. Based on the record, EPA found that there are technologies readily available to reduce or eliminate the discharge of pollutants contained in fly ash and bottom ash transport water.
Finally, the information obtained during the study indicates that FGD and ash transport wastewaters contain pollutants that can have detrimental impacts to the environment. EPA reviewed publicly available data and found documented environmental impacts that were attributable to discharges from surface impoundments or discharges from leachate generated from landfills containing combustion residues. EPA found that there are a number of pollutants present in wastewaters generated at coal-fired power plants that can impact the environment, including metals (e.g.,
Overall, from the detailed study, EPA found that the industry is generating new wastestreams that during the previous rulemakings either were not evaluated or were evaluated to only a limited extent due to insufficient data. Such wastestreams include FGD wastewater, FGMC wastewater, carbon capture wastewater, and gasification wastewaters. EPA also found that these wastestreams, as well as other combustion-related wastestreams at power plants (e.g., fly ash and bottom ash transport water, leachate) contain pollutants in concentrations and mass loadings that are causing documented environmental impacts and that treatment technologies are available to reduce or eliminate the pollutant discharges. For further information, see Section 6 of the Steam Electric Power Generating Point Source Category: Detailed Study is available online at
Based on the findings from the detailed study, which EPA issued in 2009, EPA began taking steps to revise the steam electric power generating effluent limitations guidelines and standards.
When the CAA was amended in 1990, EPA was directed to control mercury and other hazardous air pollutants from major sources of emissions to the air. For power plants using fossil fuels, the amendments required EPA to conduct a study of hazardous air pollutant emissions. CAA Section 112(n)(1)(A). The CAA amendments also required EPA to consider the study and other information and to make a finding as to whether regulation was appropriate and necessary. In 2000, the Administrator found that regulation of hazardous air pollutants, including mercury, from coal- and oil-fired power plants was appropriate and necessary. 65 FR 79825 (Dec. 20, 2000).
EPA published the final MATS rule on February 16, 2012. 77 FR 9304. The rule established standards that will reduce emissions of hazardous air pollutants including metals (e.g., mercury, arsenic, chromium, nickel) and acid gases (e.g., hydrochloric acid, hydrofluoric acid). Steam electric power plants may use any number of practices, technologies, and strategies to meet the new emission limits, including using wet and dry scrubbers, dry sorbent injection systems, activated carbon injection systems, and fabric filters.
EPA promulgated the CSAPR in 2011 to require 28 states in the eastern half of the United States to significantly improve air quality by reducing power plant emissions of sulfur dioxide, nitrogen oxides (NO
On April 13, 2012, the EPA proposed new source standards of performance under CAA section 111 for emissions of carbon dioxide for fossil-fuel-fired electricity generating units. 77 FR 22392. The proposed requirements, which apply only to new sources, would require new plants greater than 25 megawatts (MW) to meet an output-based standard of 1,000 pounds of carbon dioxide per MW-hour of electricity generated. EPA based this proposed standard on the performance of natural gas combined cycle technology because EPA and others project that even without this rule, for the foreseeable future, new fossil-fuel-fired power plants will be built with that technology. New coal- or petroleum coke-fired generating units could meet the standard by using carbon capture and storage of approximately 50 percent of the carbon dioxide in the exhaust gas when the unit begins operating or by later installing more effective carbon capture and storage to meet the standard on average over a 30-year period. EPA is evaluating the public comments received on the proposal and has not determined a schedule at this time for taking final action on the proposed rule.
Section 316(b) of the CWA, 33 U.S.C. 1326(b), requires that standards applicable to point sources under section 301 and 306 of the Act require that the location, design, construction, and capacity of cooling water intake structures reflect the best technology available to minimize adverse environmental impacts. Each year, these facilities withdraw large volumes of water from lakes, rivers, estuaries or oceans for use in their facilities. In the process, these facilities remove billions of aquatic organisms from waters of the United States each year, including fish, fish larvae and eggs, crustaceans, shellfish, sea turtles, marine mammals, and other aquatic life. The most significant effects of these withdrawals are on early life stages of fish and shellfish through impingement (being pinned against intake screens or other parts at the facility) and entrainment (being drawn into cooling water systems).
In November 2001, EPA took final action on regulations for cooling water intake structures at new facilities that have a design intake flow greater than 2 million gallons per day (MGD) and that have at least one cooling water structure that uses at least 25 percent of the water it withdraws for cooling purposes. See 40 CFR 125.81. EPA's requirements provide a two-track approach. Under Track 1, the intake flow at facilities that withdraw greater than 10 MGD is restricted to a level commensurate with the level that may be achieved by use of a closed-cycle recirculating cooling system. Facilities withdrawing greater than 10 MGD located in areas where fisheries need additional protection must also use technology or operational measures to further minimize impingement mortality and entrainment. For facilities with intakes of less than 10 MGD, the cooling water intake structures may not exceed a fixed intake screen velocity and the quantity of intake is restricted. Under Track 2, a facility may choose to demonstrate to the permitting authority that other technologies will reduce the level of adverse environmental impacts to a level that would be achieved under Track 1.
In March 2011, EPA proposed standards to reduce injury and death of fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. The proposed rule would subject existing power plants and manufacturing facilities withdrawing in excess of 2 MGD of cooling water to an upper limit on the number of fish destroyed through impingement, as well as site-specific entrainment mortality standards. Certain plants that withdraw very large volumes of water would also be required to conduct studies for use by the permit writer in determining site-specific entrainment controls for such facilities. Finally, under the proposed rule, new generating units at existing power plants would be required to reduce the intake of cooling water associated with the new unit, to a level that could be attained by using a closed-cycle cooling system. EPA is continuing analysis and is in the process of addressing comments and finalizing the rule.
CCRs are residues from the combustion of coal in steam electric power plants and include materials such as coal ash (fly ash and bottom ash) and FGD wastes. CCRs are currently exempt from the requirements of Subtitle C of the Resource Conservation and Recovery Act (RCRA), which governs the disposition and management of hazardous wastes. Potential environmental concerns regarding the management and disposal of CCR include pollution leaching from surface impoundments and landfills contaminating ground water and natural resource damages and risks to human health caused by structural failures of surface impoundments, like that which occurred at the Tennessee Valley Authority's plant in Kingston, Tennessee, in December 2008. The spill, which flooded more than 300 acres of land with CCRs and contaminated the Emory and Clinch rivers, emphasized the need for national standards to address risks associated with the disposal of CCRs.
On June 21, 2010, EPA co-proposed regulations that included two approaches to regulating the disposal of CCRs generated by electric utilities and independent power producers. Under one proposed approach, EPA would list these residuals as “special wastes,” when destined for disposal in landfills or surface impoundments, and would apply the existing regulatory requirements established under Subtitle C of RCRA to such wastes. Under the second proposed approach, EPA would establish new regulations applicable specifically to CCRs under subtitle D of RCRA, the section of the statute applicable to solid (i.e., non-hazardous) wastes. Under both approaches, CCRs that are beneficially used would remain exempt under the Bevill exclusion.
EPA has not yet taken final action on the proposed CCR regulations. Certain aspects of the CCR rulemaking are discussed in this notice for purposes of better understanding the analyses underlying this proposed revisions to the steam electric generating ELGs. This notice is not proposing anything new or different with respect to the CCR rulemaking (on which the Agency has already solicited public comments) and, therefore, is not opening up that rulemaking to further public comments.
This section describes EPA's current thinking on how a final RCRA Coal Combustion Residuals (CCR) rule might be aligned and structured to account for any final requirements adopted under the ELGs for the Steam Electric Power Generating point source category. Consistent with RCRA section 1006(b), EPA seeks to effectively coordinate any final RCRA requirements with the ELG requirements, to minimize the overall complexity of these two regulatory structures, and facilitate implementation of engineering, financial and permitting activities. EPA's approach would also be consistent with Executive Order 13563, “Improving Regulation and Regulatory Review,” issued on January 18, 2011, which emphasizes that some “sectors and industries face a significant number of regulatory requirements, some of which may be redundant, inconsistent, or overlapping,” and it directs agencies to promote “coordination, simplification, and harmonization.” EPA's goal is to ensure that the two rules work together to effectively address the discharge of pollutants from steam electric generating facilities and the human health and environmental risks associated with the disposal of CCRs, without creating avoidable or unnecessary burdens.
In considering how to coordinate the potential requirements between the two rules, EPA is guided by the following policy considerations: first and foremost, EPA intends to ensure that its statutory responsibilities to restore and maintain water quality under the CWA and to protect human health and the environment under RCRA are fulfilled. At the same time, EPA would seek to minimize the potential for overlapping requirements to avoid imposing any unnecessary burdens on regulated entities and to facilitate implementation and minimize the overall complexity of the regulatory structure under which facilities must operate. Based on these considerations, EPA is exploring two primary means of integrating the two rules: (1) through coordinating the design of any final substantive CCR requirements regulatory requirements, and (2) through coordination of the timing and implementation of final rule requirements to provide facilities with a reasonable timeline for implementation that allows for coordinated planning and protects electricity reliability for consumers.
One approach is to examine the ways in which EPA anticipates that facilities are likely to modify their operations to comply with the ELG rule, and factor the results of those assessments into EPA's evaluation of whether separate RCRA requirements under the CCR rule are needed to ensure protection of human health and the environment. For example, as described in greater detail in this preamble, the ELG rule could eliminate or reduce certain discharges to surface water, including by controlling or eliminating wastewater that is sent to and discharged from surface impoundments. While the ELG would not compel use of a particular technology, EPA predicts that one possible consequence of the proposed ELG requirements is that some number of facilities will choose to convert their sluicing operations to dry ash-handling systems, and will no longer send such wastes to surface impoundments. EPA is considering how these predictions
However, it is also possible that the requirements established under a final ELG rule could affect the development of any final CCR rule more broadly. Since the close of the comment period on the CCR rule, EPA has received significant new data obtained from a 2010 Information Collection Request (ICR) conducted by EPA's Office of Water for the development of the ELG, which have the potential to affect the risk assessment for the CCR rule. This ICR gathered information from, among others, all 495 electric utility plants that operate coal-fired generating units. In the June 21, 2010 proposal, EPA did not have definitive data about the location, size, or age of the waste management units, nor on the type or composition of the wastes contained in surface impoundments. Consequently, the Agency relied on a 1995 industry report and a number of significant assumptions in the 2010 risk assessment supporting the proposed CCR rule.
These facility-specific data could be used in EPA's risk assessment for any CCR rule in several ways that could significantly affect the results of that assessment. For example, these data could be used to determine the extent to which plumes of contamination leaching from coal ash disposal units into groundwater are intercepted (and reduced) by surface water bodies that exist between a disposal unit and a down-gradient drinking water well. This information has the potential to significantly affect the nature and extent of the risks, and would allow EPA to better estimate the contaminant levels that people would be expected to receive in drinking water, and to better model the likely environmental risks (
In addition, these data provide information on the location, size, and the type of waste present in hundreds of surface impoundments that were omitted from the data sources on which EPA relied to develop the proposed CCR rule. These impoundments are generally, smaller than the impoundments included in the data used to support the proposed CCR rule, and can differ significantly from the impoundments located at larger facilities. Exclusion of these smaller impoundments could potentially bias the results of the risk assessment, because smaller surface impoundments contain less waste that would be subject to leaching, and any plumes of contamination would likely be smaller. Similarly, these data would allow EPA to refine its analysis of the potential risks from fugitive dust at landfills. Preliminary comparisons of the Office of Water data indicate that currently active portions of landfills are significantly smaller than the landfills identified in the 1995 survey that EPA used in its assessment of the risks from fugitive dust prepared for the proposed rule.
Although a final risk assessment for the CCR rule has not yet been completed, reliance on the data and analyses discussed above may have the potential to lower the CCR rule risk assessment results by as much as an order of magnitude. If this proves to be the case, EPA's current thinking is that, the revised risks, coupled with the ELG requirements that the Agency may promulgate, and the increased Federal oversight such requirements could achieve, could provide strong support for a conclusion that regulation of CCR disposal under RCRA Subtitle D would be adequate.
As it has in this proposed ELG rule, EPA also intends to consider, to the extent permitted by statute, any practical constraints facilities may face in implementing any requirements under both rules (See, for example, Section XVI, addressing implementation issues for the Steam Electric ELGs).
Comments on EPA's current thinking described above on how any final CCR rule might be aligned and structured to account for any final requirements adopted under the ELGs for the Steam Electric Power Generating point source category should be directed to Docket ID Number: EPA–HQ–RCRA–2013–0209. Any comments submitted on this limited set of issues will be considered as part of the CCR rulemaking. By contrast, comments submitted on any other issue related to the CCR rule will be considered “late comments” and EPA will not respond to such comments, nor will they be considered part of the CCR rulemaking record.
A principal source of information used in developing this proposal is the industry responses to a survey, the Questionnaire for the Steam Electric Power Generating Effluent Guidelines, distributed by EPA under the authority of section 308 of the CWA, 33 U.S.C. 1318. EPA designed the industry survey to obtain technical information related to wastewater generation and treatment, and economic information such as costs of wastewater treatment technologies and financial characteristics of potentially affected companies. The Agency consulted with the major industry trade associations to ensure that the industry survey would be useful and to ensure an accurate list of potential recipients. In June 2010, EPA mailed the survey to 733 plants. In general, plants were required to provide responses for the 2009 calendar year. The following describes the questionnaire, the recipient selection process, and the review of the questionnaire responses.
To obtain information relevant to the rulemaking, EPA's survey consisted of the following nine parts:
• Part A: Steam Electric Power Plant Operations;
• Part B: FGD Systems;
• Part C: Ash Handling;
• Part D: Pond/Impoundment Systems and Other Wastewater Treatment Operations;
• Part E: Wastes from Cleaning Metal Process Equipment;
• Part F: Management Practices for Ponds/Impoundments and Landfills;
• Part G: Leachate Sampling Data for Ponds/Impoundments and Landfills;
• Part H: Nuclear Power Generation; and
• Part I: Economic and Financial Data.
Part A gathered information on all steam electric generating units at the surveyed plant, the fuels used to generate electricity, air pollution controls, cooling water, an inventory of ponds/impoundments and landfills used for combustion residues (including coal, petroleum coke, and oil residues), coal storage and processing, and outfall information. Parts B through I collected economic data and detailed technical information on certain aspects of power plant operations, including requiring some plants to collect and analyze wastewater samples. The process operation sections (Parts B, C, and E) included detailed questions about the types of processes employed, dates that certain types of equipment were installed or plans for future equipment installations, chemical usage, operating characteristics, wastewater generation, pollution prevention activities, and wastewater discharge information.
In Part D of the industry survey, EPA requested detailed information (including diagrams) on the wastewater treatment systems (including chemical usage), discharge flow rates, and operating and maintenance cost data (including chemical usage) (Part D). The ponds/impoundments and landfill questions (Parts F and G) requested information on the size, characteristics, and operation of the ponds/impoundments and landfills located at the facilities. These sections also obtained information on the leachate collection and treatment, and required facilities to collect and analyze samples of untreated and treated leachate from the ponds/impoundments and landfills that receive combustion residues. The survey respondents were required to provide the laboratory analytical results and additional descriptive information about the leachate samples.
For nuclear-fueled generating units, Part H of the industry survey requested general information on the operation of the nuclear units, the wastewaters generated, and the treatment of those wastewaters.
The financial and economic questions (Part I) requested information on the facilities' ownership structure and financial conditions.
The Agency used these data to evaluate process operations and wastewater generation, identify treatment technologies in place, and determine the feasibility of regulatory options for each plant. EPA identified and evaluated the treatment technologies available for treating FGD wastewater and leachate from surface impoundments and landfills, and approaches for ash handling that reduced or eliminated the use of water. EPA also used these data to estimate which plants may incur compliance costs and pollutant removals associated with the various technology control options.
EPA used survey data, along with additional data collected from public sources, to estimate economic impacts on facilities and owning entities under the eight main regulatory options EPA considered for this proposal.
The Energy Information Administration (EIA), a statistical agency of the U.S. Department of Energy (DOE), collects information on existing electric generating plants and associated equipment to evaluate the current status and potential trends in the industry. EPA used the information available from the 2007 Electric Generator Report (Form EIA–860), and supplemented it with information found in Form EIA–923 and a survey conducted by EPA's Office of Solid Waste and Emergency Response (OSWER), to create a listing of plants that have steam electric power generating activities believed to be subject to the existing Steam Electric Power Generating Effluent Guidelines.
EPA used the EIA data, which contains information on the location of each of the plants (e.g., address, city, state), to create an initial draft of potential questionnaire recipients that EPA shared with industry stakeholders (e.g., the Utility Water Act Group (UWAG)) and interested environmental organizations. UWAG distributed the list to its members and provided feedback to the Agency to correct inaccurate addresses as well as identify plants that were not included or plants that are no longer in operation. Based on the original EIA data and industry feedback, EPA identified 1,197 steam electric generating plants for the survey sample frame (i.e., a list of all steam electric power plants from which the surveyed plants would be selected).
As a first step in selecting questionnaire recipients, EPA grouped all identified steam electric power plants based on the types of fuels burned at the facility. EPA first classified the generating units into fuel groups based on the primary and secondary energy sources reported in the 2007 Form EIA–860. EPA used the following hierarchy to classify the generating units: Coal, petroleum coke, gas, oil, and nuclear. Generating units that identified either coal or petroleum coke as the primary or secondary energy source were classified as a coal or petroleum coke generating unit. For generating units that did not identify coal or petroleum coke as a primary or secondary energy source, EPA used the primary energy source to classify the generating unit as gas, oil or nuclear. Based on the generating unit classifications, EPA then grouped plants into the fuel categories based on the following hierarchy: Coal, petroleum coke, combination, gas, oil, nuclear. For example, if a plant has one coal unit and five gas units, EPA identified the plant as a coal plant. EPA used the “combination” designation for plants that have at least two generating units that have different unit-level designations (e.g., oil, gas, nuclear), but do not have any coal or petroleum coke units.
Because much of the focus of this proposed rule is on the FGD and ash wastewaters, which are primarily generated at coal- and petroleum coke-fired plants, EPA sent questionnaires to all plants that operate coal- or petroleum coke-fired generating units. For plants without any coal- or petroleum coke-fired generating units (i.e., gas, oil, or nuclear-fueled), EPA sent questionnaires to a statistically selected subset of the identified plants. EPA created four different versions of the questionnaire to send out to plants based on the different parts of the questionnaire:
• Version 1: Parts A through I;
• Version 2: Parts A, B, C, D, H, and I;
• Version 3: Parts A, B, C, D, E, H, and I; and
• Version 4: Parts A, E, H, and I.
In June 2010, EPA mailed the surveys to 733 power plants. EPA mailed Version 1 of the questionnaire to 97 coal- and petroleum coke-fired power plants, which is a subset of the total
EPA received completed surveys from all 733 questionnaire recipients. A total of 53 plants certified that they were not and did not have the capability to be engaged in steam electric power production, would be retired by December 31, 2011, or did not generate electricity in 2009 by burning any fossil or nuclear fuels.
EPA reviewed the surveys for completeness and consistency, using checklists for the review process to help identify potential issues with responses (e.g., data reported in incorrect units, missing responses). After completing the review for each plant, EPA contacted the plant to review the potential issues identified during the review process, if needed. EPA then created a database that contains all survey responses. The questionnaire database in the public record includes all information submitted for which facilities have not asserted that the information is confidential business information (CBI). In some instances, EPA has redacted non-CBI data to prevent the disclosure of other data claimed as CBI.
EPA conducted 68 site visits to power plants in 22 states and Italy between December 2006 and February 2013 to collect information about plant operations, process wastewater generation and management practices, and wastewater treatment systems. The primary purpose of these site visits was to evaluate candidate best available technologies and best available demonstrated control technologies, the changes necessary to implement new processes or technologies, and evaluate plants for potential inclusion in EPA's field sampling program. EPA used information provided by UWAG, responses from the detailed study data request, industry survey data, and information learned from contacts with industry representatives to identify site visit candidates. EPA based site visit selection on the type of operations at the plant (e.g., wet FGD systems, wet fly ash or bottom ash handling, gasification), and the plant's approach for minimizing pollutant discharges associated with these operations (e.g., sites employing candidate best available technologies, best available demonstrated control technologies, or processes that reduce or eliminate pollutant discharges.)
EPA collected detailed information from the plants visited, such as the operations associated with wastewater generation, in-process treatment and recycling systems, end-of-pipe treatment technologies, and, if the plant was a candidate for sampling, the logistics of collecting samples. EPA also obtained information regarding zero discharge options associated with the various operations and how the plants could potentially achieve zero discharge for some or all of these operations. EPA prepared site visit reports summarizing the collected information. EPA has included in the public record site visit reports that contain all information collected during site visits for which the plants have not asserted a claim of CBI.
Between July 2007 and April 2011, EPA conducted a sampling program at 17 different steam electric power plants in the United States and Italy to collect wastewater characterization data and/or treatment performance data associated with FGD wastewater, fly ash and bottom ash wastewater, and wastewater from gasification and carbon capture processes. EPA conducted on-site sampling (i.e., the Agency collected the samples) at 13 of the 17 power plants. Using its authority under CWA section 308, EPA directed seven of these EPA-sampled plants and four additional plants not sampled by EPA to collect additional samples, which were sent to EPA-contracted laboratories for analysis (i.e., CWA 308 monitoring program). In general, EPA used the following criteria to identify the plants included in the sampling program:
• The plant performs steam electric power generation activities representative of steam electric power plants (i.e., the plant's operations are typical of operations observed at other power plants, and therefore, are representative of more than just itself);
• The plant uses coal and/or petroleum coke (the wastestreams of interest and pollutants of concern identified in this rulemaking are primarily associated with plants using these types of fuels); and
• The plant has the wastestreams or treatment technologies of interest.
EPA also obtained sampling data for surface impoundment and landfill leachate collection and treatment systems at 39 plants, as directed by Part G of the Questionnaire for the Steam Electric Power Generating Effluent Guidelines. This leachate sampling is not included in the following description of the field sampling program. See Section 10.2.3 of the TDD for more information on leachate data collected under the industry survey.
EPA's field sampling program began during its detailed study and continued throughout this rulemaking effort. During the study, EPA conducted one- or two-day sampling episodes at six plants to characterize untreated wastewaters generated by coal-fired power plants, as well as to obtain a preliminary assessment of treatment technologies and best management practices for reducing pollutant discharges. The types of wastewaters sampled during the detailed study were untreated and treated FGD wastewater, fly ash wastewater, and bottom ash wastewater.
Upon completing the detailed study, EPA subsequently selected 13 plants to collect additional wastewater characterization data and to evaluate wastewater treatment performance. Through this effort, EPA evaluated 10 FGD wastewater treatment systems; two gasification systems at integrated gasification combined cycle (IGCC) plants; and one pilot-scale carbon capture system. EPA selected these FGD systems because at the time it believed all were among the better performing FGD wastewater treatment systems in the industry, based on information obtained during the site visits and discussions with industry representatives about the design/operation of the treatment system and optimization efforts performed at the plant. In addition, these plants represent geographic variability, different coal types (i.e., bituminous, subbituminous, coal blends), and different operating practices (e.g., baseload vs cycling). The selected IGCC systems and the pilot-scale carbon capture system were the only known systems operating in the U.S. power industry at the time of EPA's field sampling program.
For the 13 plants sampled following completion of the detailed study, samples were collected as follows:
• For seven plants, EPA collected performance data for four consecutive days and the plants also subsequently collected four sets of samples over a four to five month period;
• For four plants, the facility collected performance data for four consecutive days;
• For one plant, EPA collected performance data for three consecutive days; and
• For one plant, the facility collected performance data for one day.
EPA (or the plant) collected representative samples at the influent and effluent of the treatment system being evaluated using a combination of 24-hour composite and grab samples, depending on the sample location and the parameter to be analyzed. EPA analyzed the samples for up to 64 parameters, including conventional pollutants (e.g., TSS, BOD
Subsequent to the EPA and industry sampling efforts, EPA prepared a report summarizing the wastewater treatment processes, sampling procedures, and analytical results. EPA has included in the public record these reports containing all information collected for which a facility has not asserted a confidentiality claim or which would indirectly reveal information claimed to be CBI.
EPA collected information from the Agency's databases and publications, states, and permitting authorities, including the following:
• Information on current and proposed permitting practices for the steam electric industry from a review of selected NPDES permits and accompanying fact sheets;
• Input from EPA and state permitting authorities regarding implementation of the existing Steam Electric Power Generating effluent guidelines;
• Background information on the steam electric industry from documents prepared during the development of the existing Steam Electric Power Generating effluent guidelines (i.e., the 1974 and 1982 rulemakings);
• Information from a survey of the industry conducted for the Cooling Water Intake Structures rulemaking;
• Information from EPA's Office of Air and Radiation (OAR), including Integrated Planning Model (IPM) projections based on recent air rules (i.e., CAIR/CSAPR rule and MATS);
• Information from EPA's Office of Research and Development (ORD) characterizing CCR and the potential leaching of pollutants from CCRs stored or disposed of in landfills and surface impoundments;
• Data provided by the North Carolina Department of Environment and Natural Resources for one plant that operates an anoxic/anaerobic biological treatment system for FGD wastewater; and
• Information collected by EPA's OSWER, regarding surface impoundments or other similar management units that contain CCRs at power plants and other information gathered in support of the proposed rule for regulating CCR under RCRA.
EPA obtained information on steam electric wastewaters and pollutants directly from the industry through self-monitoring data, as well as NPDES Form 2C data. Specifically, EPA requested self-monitoring data from two power plants to support its calculation of pollutant loading reductions from FGD wastewater treatment technologies and to supplement the data from the EPA sampling program in the development of ELGs for the FGD wastewater. EPA also coordinated with UWAG to create a database of selected NPDES Form 2C data from UWAG's member companies. The NPDES Form 2C database contains information about the outfalls of coal-fired power plants that receive FGD, ash handling, or coal pile runoff wastestreams. EPA received Form 2C data from UWAG for 86 plants in late June 2008 and reviewed the data for use in developing the industry profile, in particular for ash wastewater treatment operations.
EPA gathered data from technology vendors through presentations, conferences, meetings, and email and phone contacts to gain information on the technologies used in the industry. EPA also used these contacts with vendors to obtain costs to install and operate the technologies considered as part of the proposed rule. These data informed the development of the industry survey, the technology costs, and the pollutant loadings estimates.
EPA obtained additional information on steam electric processes, technologies, wastewaters, pollutants, and regulations from sources including trade associations (e.g., UWAG), the Electric Power Research Institute (EPRI), DOE, the U.S. Geological Survey (USGS), and literature and Internet searches. EPA used information provided by the Environmental Integrity Project (EIP), Earthjustice, and the Sierra Club to document known environmental impacts caused by steam electric power plant discharges. In addition, EPA considered information provided in public comments during the effluent guidelines planning process, as well as other contacts with interested stakeholders.
To conduct cost and economic impact analysis of the proposed regulation, EPA used financial and operational data for steam electric power plants and their parent companies collected through the Steam Electric Questionnaire described in Section IV.A of this preamble.
EPA also used publicly available data describing current operating and business conditions at the steam electric power plants, operators, and parent companies, data describing economic/financial conditions in, and the regulatory environment of, the electric power industry, as well as data on electricity prices and electricity consumption. EPA obtained publicly available data from the following sources: the Department of Energy's EIA (in particular, the EIA 860, 861, and 906/920/923 databases),
This proposal would establish new requirements for certain plants within the scope of the existing regulations for the steam electric power generating point source category. The proposed requirements would apply to discharges of wastewater associated with the following processes and byproducts: flue gas desulfurization, fly ash, bottom ash, combustion residual leachate, flue gas mercury control, nonchemical metal
EPA is proposing to correct a typographical error in 40 CFR 423.17(d)(1) by adding a footnote that is missing from the table specifying PSNS for cooling tower blowdown. As is clear from the development document for the 1982 rulemaking, the footnote was intended to appear, as it does in the corresponding table for NSPS, and its omission was an inadvertent mistake, which EPA is now correcting. The footnote proposed to be added reads “No detectable amount” and refers to the effluent standard for 124 of the 126 priority pollutants contained in chemicals added for cooling tower maintenance. (See “Development Document for Final Effluent Guidelines, New Source Performance Standards and Pretreatment Standards for the Steam Electric Power Generating Point Source Category,” Document No. EPA 440/1–82/029. November 1982.)
In addition, EPA is proposing three modifications to the applicability provision for the ELGs. These are not substantive modifications and would not alter which generating units are regulated by the ELGs nor impose compliance costs on the industry. Instead, the proposed modifications would remove potential ambiguity present in the current regulatory text by revising the text to more clearly reflect EPA's long-standing interpretation.
First, the applicability provision in the current ELGs states, in part, that the ELGs apply to “an establishment primarily engaged in the generation of electricity for distribution and sale. . . .” 40 CFR 423.10. EPA is proposing to revise that phrase in the applicability provision to read “an establishment whose generation of electricity is the predominant source of revenue or principal reason for operation . . .” This proposed modification would clarify that certain facilities, such as generating units owned and operated by industrial facilities in other sectors (e.g., petroleum refineries, pulp and paper mills) are not included within the scope of the steam electric ELGs. In addition, the proposed modification would clarify that certain municipal-owned facilities, which generate and distribute electricity within a service area (such as distributing electric power to municipal-owned buildings), but which use accounting practices that are not commonly thought of as a “sale” are nevertheless subject to the ELGs. Such facilities have traditionally been regulated by the steam electric ELGs, and EPA believes the proposed modification will improve regulatory clarity.
Second, EPA is proposing a modification to the applicability provision to clarify that fuels derived from fossil fuel are within the scope of the current ELGs. The ELGs currently state, in part, that the ELGs apply to discharges related to the generation of electricity “which results primarily from a process utilizing fossil-type fuels (coal, oil, or gas) or nuclear fuel . . .” 40 CFR 423.10. Because there are a number of fuel types that are derived from fossil fuel, and which thus are fossil fuels themselves, EPA is proposing to revise that phrase in the applicability provision to read “which results primarily from a process utilizing fossil-type fuel (coal, oil, or gas), fuel derived from fossil fuel (e.g., petroleum coke, synthesis gas), or nuclear fuel . . .”
Third, EPA is proposing to amend the applicability provision to clarify that combined cycle systems are subject to the requirements of the ELGs. The ELGs apply to electric generation processes that utilize “a thermal cycle employing the steam water system as the thermodynamic medium.” 40 CFR 423.10. EPA's longstanding interpretation of this provision is that the ELGs apply to all electric generation processes with at least one prime mover that utilizes steam (if they also meet the other factors specified in Section 423.10, including the use of fossil or nuclear fuel). Combined cycle systems, which are generating units composed of one or more combustion turbines operating in conjunction with one or more steam turbines, are subject to the ELGs. The combustion turbines for a combined cycle system operate in tandem with the steam turbines; therefore, the ELGs apply to wastewater discharges associated with both the combustion turbine and steam turbine portions of the combined cycle system.
The CWA requires EPA to consider a number of different factors when developing ELGs for a particular industry category (see BAT factors listed at Section 304(b)(2)(B), 33 U.S.C. § 1314(b)(2)(B)). For BAT, in addition to the technological availability and economic achievability, these factors are the age of equipment and facilities involved, the process employed, the engineering aspects of the application of various types of control techniques, process changes, the cost of achieving such effluent reduction, non-water quality environmental impact (including energy requirements), and such other factors the Administrator deems appropriate. One way EPA may take these factors into account is by dividing a point source category into groupings called “subcategories.” Regulating a category by subcategory, where determined to be warranted, ensures that each subcategory has a uniform set of ELGs that take into account technology availability and economic achievability and other relevant factors unique to that subcategory.
The current steam electric ELGs do not divide plants or process operations into subcategories, although they do include different effluent requirements for cooling water discharges from generating units smaller than 25 MW generating capacity. For this proposed rule, EPA evaluated whether different effluent requirements should be established for certain facilities within the steam electric power generating point source category using information from responses to the industry questionnaires, site visits, sampling, and other data collection activities (see Section IV for more details). EPA performed analyses to assess the influence of age, size, fuel type, and geographic location on the wastewaters generated, discharge flow rates, pollutant concentrations, and treatment technology availability at steam electric power plants to determine whether subcategorization was appropriate, as discussed further below.
EPA analyzed the age of the power plants and the generating units included in the scope of the rule. It determined that the age of the plant by itself does not in general affect the wastewater characteristics, the processes in place, or the ability to install the treatment technologies evaluated as part of this rulemaking. Therefore, EPA did not establish subcategories based on the age of the plant or generating unit for this proposal.
EPA analyzed the geographic location of power plants included in the scope of the rule. It determined that the geographic location of the plant by itself does not affect the wastewater characteristics, the processes in place, or the ability to install the treatment technologies evaluated as part of this rulemaking. During its evaluation, EPA found that wet FGD systems, both wet and dry fly ash handling systems, and both wet and dry bottom ash handling systems are located throughout the United States, as illustrated in Section
EPA analyzed the size (i.e., nameplate generating capacity in MW) of the steam electric generating unit and determined that it can be an important factor influencing the volume of the discharge flow from the plant. Typically, as the size of the generating unit increases, the discharge flows of ash transport water generally increase. In general, this is to be expected because the larger the generating unit, the more fuel it consumes, which generates more ash, and uses more water in the water/steam thermodynamic cycle. Although the volume of the wastewater increases with the size of the generating unit, the pollutant characteristics of the wastewater generally are unaffected by the size of the generating unit and any variability observed in wastewater pollutant characteristics does not appear to be correlated to generating capacity.
As a result of its evaluation, EPA believes that, in certain circumstances, it would be appropriate to apply different limits for a class of existing generating units or plants based on size. Section VIII of this preamble discusses in greater detail EPA's proposal for applying different standards to certain existing units.
The type of fuel (e.g., coal, petroleum coke, oil, gas, nuclear) used to create steam most directly influences the type and number of wastestreams generated. For example, gas and nuclear power plants typically generate cooling water, metal cleaning wastes (both chemical and nonchemical), and other low volume wastestreams, but do not generate wastewaters associated with air pollution control devices (e.g., fly ash and bottom ash transport water, FGD wastewater). Coal, oil, and petroleum-coke power plants may generate all of those wastewaters. The wastestream that is most influenced by fuel selection is the ash transport water because the quantity and quality of ash generated from oil-fired units is different from that generated from coal- and petroleum coke-fired units. Additionally, the quantity and quality of ash differs based on the type of oil used in the boiler. For example, heavy or residual oils such as No. 6 fuel oil generate fly ash and may generate bottom ash, but lighter oils such as No. 2 fuel oil may not generate any ash.
From an analysis of responses to the industry survey, EPA determined that 74 percent of the steam electric units in the industry burn more than one type of fuel (e.g., coal and oil, coal and gas). Some of these plants may burn only one fuel at a specific time, but burn both types of fuels during the year. Other plants may burn multiple fuels at the same time. In cases where facilities burn multiple fuels at the same time, it would be impossible to separate the wastestreams by fuel type.
EPA did not identify any basis for subcategorizing gas-fired and nuclear generating units. These generating units generally manage nonchemical metal cleaning wastes in the same manner as other steam electric generating units, and the proposed requirements for this wastestream would establish limitations and standards that are equal to current BPT limitations for existing direct dischargers.
The steam electric power generating point source category (i.e., steam electric industry) consists of plants that generate electricity from a process utilizing fossil or nuclear fuel in conjunction with a thermal cycle employing the steam/water system as the thermodynamic medium. Based on responses to the industry survey, the Agency estimates that, excluding plants reporting that they would be retired by December 2011, and those plants reporting that they did not operate fossil- or nuclear-fueled units in 2009, there were 1,079 steam electric power plants operating in 2009. These facilities operate an estimated 2,195–2,230 generating units (including combined cycle systems), which have a total nameplate generating capacity of 741,000 MW. (Note: EPA has withheld the precise number of generating units to prevent disclosing CBI.) Table VI–1 shows the estimated number of steam electric generating units broken out by the five primary types of fuels used: coal, petroleum coke, oil, gas, and nuclear.
As seen from these data, most of the steam electric generating capacity (82 percent) is associated with either coal or gas. Based on survey responses, EPA also found that most plants in the industry have a generating capacity greater than 500 MW and may operate only one generating unit or multiple generating units. Plants of that size account for over 60 percent of all steam electric plants, 70 percent of all electric generating units, and 90 percent of the electric generating capacity.
For coal- and petroleum coke-fired plants, EPA determined that most plants (89 percent) are discharging at least some of their wastewater to surface waters or POTWs. Some plants operate without discharging certain wastewaters (e.g., fly ash transport water, FGD wastewater); however, most plants discharge at least their cooling water. Few of the discharging plants send wastestreams addressed by this rulemaking to POTWs. EPA identified approximately 10 coal- or petroleum coke-fired plants that discharge their FGD wastewater and/or fly ash or bottom ash transport water to POTWs. EPA also found that approximately 11 percent of coal- and petroleum coke-fired power plants do not discharge any wastewater. Most of these zero discharge plants are located in the southwestern United States (e.g., Arizona) and use evaporation ponds to control the wastewater.
In the steam electric process, fuel is fed to a boiler where the fuel is combusted. The hot gases from combustion leave the boiler and pass through air pollution control systems prior to their emission through a stack. The resulting heat from combustion converts water to steam. The high-temperature, high-pressure steam leaves the boiler and enters the turbine generator where it drives the turbine blades as it moves from the high-pressure to the low-pressure stages of the turbine. The lower-pressure steam leaving the turbine enters the condenser, where steam vapor is cooled and condensed back into liquid by cooling water. The water collected in the condenser is sent back to the boiler where it is again converted to steam.
Combined cycle systems consist of combustion turbine electric generating units operating in conjunction with steam turbine electric generating units. Combustion turbines, which typically are similar to jet engines, commonly use natural gas as the fuel. Combined cycle systems feed the fuel into a chamber where it is combusted to generate heat. The combustion exhaust gases are sent directly through a combustion turbine to generate electricity. These exhaust gases still contain useful waste heat as they exit the combustion turbine, so they are directed to heat recovery steam generators to generate steam that is then used to drive a steam turbine, which operates as described above for the steam electric process. The operation of the steam turbine electric generating unit within a combined cycle system is virtually identical to a stand-alone steam electric generating unit, with the exception of the boiler.
IGCC is an electric power generation process that combines gasification technology with combined cycle systems. In an IGCC system, a gasifier converts carbon-based feedstocks (e.g., coal or petroleum coke) into a synthetic gas (syngas) using high temperature and pressure. The syngas is cleaned through multiple process operations and then combusted in a combustion turbine. As with a combined cycle system, a heat recovery steam generator extracts the heat from the exhaust gases to generate steam and drive a steam turbine.
Certain wastewaters generated at steam electric power plants differ based on the fuel used; however, almost all steam electric power plants generate some wastewaters. For example, because all steam electric power plants use a steam water system as the thermodynamic medium, all power plants use cooling water to condense the steam in the system. Additionally, most steam electric power plants have a boiler blowdown stream to purge salts from the water used in the steam water system. Other wastewaters are generated from the use of air pollution control systems and are more directly tied to the type of fuel burned. Coal- and petroleum coke-fired steam electric generating units, and to a lesser degree oil-fired units, generate a flue gas stream that contains large quantities of particulate matter, sulfur dioxide, and nitrogen oxides, which would be emitted to the atmosphere if they were not cleaned from the flue gas prior to emission. Therefore, many of these units are outfitted with air pollution control systems (e.g., particulate removal systems, flue gas desulfurization systems, and NO
The information in the remainder of Section VI below describing industry practices generally presents data collected by the industry survey and represents operational conditions for the year 2009. The industry survey represents the most complete source of data available to EPA regarding the operational conditions and wastewater management practices at steam electric power plants. In some cases, where appropriate and as specified below, EPA presents additional information characterizing significant changes to operational practices that have taken place since 2009.
Plants use particulate removal systems, which typically consist of either electrostatic precipitators (ESPs) or fabric filters, to collect fly ash and other particulates from the flue gas. The fly ash and other particulates are captured by the ESP or fabric filters and collected in hoppers located underneath the equipment. From the collection hoppers, the fly ash is either
Fly ash transport water is one of the largest volume flows for coal-fired power plants. Many wet transport plants (i.e., 45 percent of plants with wet fly ash systems) sluice their fly ash continuously, and 68 percent of wet transport plants sluice their fly ash at least 12 hours per day. Based on responses to the industry survey, the average fly ash transport water flow rate is 2.4 million gallons per day (MGD). EPA estimates that the steam electric industry discharged a total of 81.1 billion gallons of fly ash transport water to surface water in 2009.
In addition to the particulate removal system for removing fly ash from the flue gas, there are also systems for handling the bottom ash that accumulates at the bottom of the furnace. The bottom ash consists of the heavier ash particles that could not be entrained in the flue gas and fall to the bottom of the furnace. In most furnaces, the hot bottom ash is quenched in a water-filled hopper. Ash from the hopper is then fed into a conveying line where it is diluted into slurry and pumped to an impoundment or dewatering bins. The ash sent to a dewatering bin is separated from the transport water and then disposed. For both of these systems, the water used to transport the bottom ash to the impoundment or dewatering bins is usually discharged to surface water as overflow from the systems, after the bottom ash has settled. Alternatively, some furnaces are fitted with mechanical drag systems where the bottom ash drops into a water-filled trough, but the ash is removed using a submerged mechanical drag conveyor that drags the bottom ash out of the furnace. At the end of the trough, the drag chain reaches an incline, which dewaters the bottom ash by gravity, draining the water back to the trough as the ash moves up the conveyor. The bottom ash is often dumped into a nearby bunker for temporary storage. As the bottom ash continues dewatering in the nearby bunker, water that drains from the system may be discharged; however, EPA does not consider this water from the bunker to be bottom ash transport water because the mechanical conveyor, and not the water, is the transport mechanism that moves the ash away from the boiler. Instead, the wastewater draining from the bunker would be low volume wastes. Over 65 percent of the units generating bottom ash operate wet bottom ash transport systems, approximately 30 percent operate systems that eliminate the use of transport water, and approximately 5 percent operate both. Plants that have both wet and dry handling operations typically use the wet handling system as a backup to the dry system. Some plants that have wet bottom ash systems operate them in a manner that does not discharge to surface water.
Bottom ash transport water is an intermittent stream from steam electric units. The bottom ash transport water flow rates are typically not as large as the fly ash transport water flow rates; however, bottom ash transport water is still one of the larger volume flows for steam electric plants. Based on responses to the industry survey, the average bottom ash transport water flow rate is 1.8 MGD. EPA estimates that the steam electric industry discharged a total of 157 billion gallons of bottom ash transport water in 2009.
Power plants that generate fly ash and bottom ash can either dispose of it in landfills or surface impoundments, or can use it in applications such as cement or concrete manufacturing. Power plants have used the ash in many applications that preclude the need to dispose of the ash in landfills/impoundments.
FGD systems remove sulfur dioxide from the flue gas so that it is not emitted into the air. There are both wet and dry FGD systems. Dry FGD systems generally inject an aqueous sorbent (e.g., lime) into a spray dryer such that the water present evaporates as it contacts the hot flue gas. The sulfur dioxide in the flue gas reacts with the lime as it dries and results in a dry particulate product that is captured in a downstream fabric filter; no wastewater is generated from the dry FGD process. In wet FGD systems, the flue gas stream comes in contact with a liquid stream containing a sorbent, typically lime or limestone, which is used to effect the mass transfer of pollutants from the flue gas to the liquid stream. This process not only transfers the sulfur dioxide from the flue gas to the liquid stream, but other pollutants (e.g., metals) as well. During this process, the lime/limestone and sulfur dioxide react to form calcium sulfite or calcium sulfate (i.e., gypsum), depending on the oxidation level of the FGD system. Gypsum is a marketable product, and as such, plants that generate gypsum generally sell (or give away) the material for use in building materials (e.g., wallboard). Plants that do not generate gypsum, or only partially oxidize the calcium sulfite, generally dispose of their FGD solids in landfills or surface impoundments. Those plants that produce a saleable product, such as gypsum, may rinse the product cake to reduce the level of chlorides in the final product. This wash water may be reused or discharged to a receiving water or POTW. Additionally, both calcium sulfite and gypsum typically require dewatering prior to sale/disposal and this dewatering process also generates a wastewater stream that may be reused or discharged. The FGD system generally requires a blowdown stream to purge chlorides to prevent scaling and corrosion of the FGD equipment.
FGD wastewater is typically an intermittent stream generated by coal-fired power plants operating wet FGD systems. Based on responses to the industry survey, the average FGD wastewater flow rate is 559,000 gallons per day (gpd). EPA estimates that the steam electric industry discharged a total of 23.7 billion gallons of FGD wastewater in 2009.
Based on the responses to the industry survey, there are approximately 401 FGD systems either currently operating or that will be installed by January 1, 2014.
FGMC systems remove mercury from the flue gas, so that it is not emitted into the air. According to the responses to the industry survey, two main types of
The use of the oxidizers does not generate a new wastewater stream; however, it may increase the concentration of mercury in the FGD wastewater because the oxidized mercury is more easily removed by the FGD system. The activated carbon injection system does have the potential to generate a new wastestream at a plant, depending on the location of the injection. If the injection occurs upstream of the primary particulate removal system, then the mercury-containing carbon (i.e., FGMC waste) is collected and handled the same way as the fly ash. Therefore, if the fly ash is wet sluiced, then the FGMC wastes are also wet sluiced and likely sent to the same surface impoundment. In this case, adding the FGMC wastes to the fly ash can increase the amount of mercury in the fly ash transport water. If the injection occurs downstream of the primary particulate removal system, then the plant will need a secondary particulate removal system (typically a fabric filter) to capture the FGMC wastes. Plants typically inject the carbon downstream of the primary particulate collection system if they plan to market the fly ash because the carbon in FGMC wastes can make the fly ash unmarketable. In this situation, the FGMC wastes, which would be collected with some carry-over fly ash, could be handled either wet or dry.
Based on the responses to the industry survey, in 2009 there were approximately 120 operating FGMC systems, with an additional 40 planned for installation by 2020. Approximately 90 percent of the currently operating FGMC systems are dry systems that do not generate or affect any wastewater streams. Approximately six percent of the currently operating systems are wet systems. For the remaining 4 percent of the systems, the type of handling system (e.g., wet or dry handling) is unknown.
Combustion residuals comprise a variety of wastes from the combustion process, including fly ash, bottom ash (which includes boiler slag), and FGD solids (e.g., gypsum and calcium sulfite), which are generally collected by or generated from the air pollution control technologies. These combustion residuals may be stored at the plant in on-site landfills or surface impoundments (i.e., ponds). Based on industry survey results, there are approximately 228 plants that operate combustion residual landfills and 264 plants that operate combustion residual surface impoundments. Some plants operate both landfills and impoundments, while other plants may operate only one or the other, or neither type of disposal unit.
Leachate is the liquid that drains or leaches from a landfill or surface impoundment. Most landfills have a system to collect the leachate and some impoundments have leachate collection systems. The two sources of leachate are precipitation that percolates through the waste deposited in the landfill/impoundment and the liquids produced from the combustion residuals placed in the landfill/impoundment. In addition to leachate, stormwater that enters the impoundment or contacts and flows over the landfill would be contaminated with combustion residual pollutants. Leachate and contaminated stormwater contain heavy metals and other contaminants through the contact with the combustion residuals.
Some landfills and surface impoundments are lined. In a lined landfill/impoundment, the leachate collected in the liner typically flows through a collection system consisting of ditches and/or underground pipes. From the collection system, the leachate is transported to an impoundment (e.g., collection pond). The stormwater collection systems typically consist of one or more small impoundments or collection ponds. The leachate and stormwater may be treated in separate impoundments or combined together. Some plants discharge the effluent from these leachate impoundments, while other plants send the leachate impoundment effluent to another impoundment handling the ash transport water or other treatment system (e.g., constructed wetlands). Unlined impoundments and landfills usually do not collect leachate thereby leaving the leachate to potentially migrate to nearby ground waters, drinking water wells, or surface waters.
Based on responses to the industry survey, approximately 100 plants collect landfill leachate from approximately 110 existing (i.e., active or inactive) landfills containing CCR, while approximately 50 plants collect leachate from existing CCR surface impoundments. Another 40 plants collect leachate from both types of systems.
Leachate is an intermittent stream whose flow rate, frequency, and duration are generally determined by weather conditions. For this reason, leachate flow rates can vary greatly for a plant, as well as varying from one plant to another. Additionally, there are differences in flow rates depending on whether the landfill or surface impoundment is active/inactive or retired. Retired landfills or surface impoundments tend to have lower flow rates because they have been capped or closed and, therefore, are not open to the atmospheric rainfall. Based on the industry survey, the average active/inactive landfill leachate flow rate was approximately 60,000 gpd. EPA estimates that the steam electric industry discharged approximately 6.2 billion gallons of leachate in 2009.
As described above, IGCC plants uses a carbon-based feedstock (e.g., coal or petroleum coke) and subject it to high temperature and pressure to produce a synthetic gas (“syngas”) which is used as the fuel for a combined cycle generating unit. In these IGCC plants, after the syngas is produced, it undergoes cleaning prior to combustion. The cleaning processes can involve any number of the following processes:
• Water scrubbing;
• Carbonyl-sulfide hydrolysis;
• Acid gas removal (stripping); and
• Sulfur recovery.
The wastewater generated by these processes, along with any condensate generated in flash tanks, slag handling water, or wastewater generated from the production of sulfuric acid, are referred to as “grey water” or “sour water,” and require treatment prior to reuse or discharge.
EPA identified two plants currently operating IGCC units, and a third IGCC unit is scheduled to begin operation this year. A fourth IGCC power plant is under construction and is scheduled to begin commercial operation in 2014.
The gasification processes generally operate continuously and, therefore, generate most of the individual gasification wastestreams continuously. Based on the information collected during EPA's sampling program, EPA determined the gasification wastewater transferred to the treatment system ranged from 6,000 to 109,000 gpd, with an average flow of 66,000 gpd.
The ELGs define metal cleaning waste as “any wastewater resulting from cleaning [with or without chemical cleaning compounds] any metal process equipment, including, but not limited to, boiler tube cleaning, boiler fireside cleaning, and air preheater cleaning.” 40
The frequency of metal cleaning activities can vary depending on the type of cleaning operation and individual plant practices. Some operations occur as often as several times a day, while others occur once every several years. Soot blowing, the process of blowing away the soot deposits on furnace tubes, generally occurs once a day, but some units do this as often as several hundred times a day. While 83 percent of units responding to the industry survey use steam or service air to blow soot, some plants may generate wastewater streams. Air heater cleaning is another frequent cleaning activity. Sixty-six percent of the units perform this operation at least once every two years, while other units perform this cleaning task very infrequently, only once every 40 years. Generally, plants use raw or potable water to clean the air heater.
The following types of metal cleaning wastes were reported in responses to the industry survey:
• Air compressor cleaning;
• Air-cooled condenser cleaning;
• Air heater cleaning;
• Boiler fireside cleaning;
• Boiler tube cleaning;
• Combustion turbine cleaning (combustion portion and/or compressor portion);
• Condenser cleaning;
• Draft fan cleaning;
• Economizer wash;
• FGD equipment cleaning;
• Heat recovery steam generator cleaning;
• Mechanical dust collector cleaning;
• Nuclear steam generator cleaning;
• Precipitator wash;
• SCR catalyst soot blowing;
• Sludge lancing;
• Soot blowing;
• Steam turbine cleaning; and
• Superheater cleaning.
The industry is investigating carbon capture and storage systems to remove carbon dioxide (CO
There are three main approaches for capturing the CO
• In post-combustion capture, the CO
• In pre-combustion capture, the fossil fuel is partially oxidized, such as in a gasifier. The resulting syngas (CO and H
• In oxy-fuel combustion, also known as oxy-combustion, the fuel is burned in oxygen instead of air. The flue gas consists of mainly CO
Based on preliminary information regarding these technologies, EPA believes they may result in new wastewaters at steam electric power plants. However, as these technologies are currently in the early stages of research and development and/or pilot testing, the industry has little information on the potential wastewaters generated from carbon capture processes. As part of its sampling program, EPA obtained analytical data associated with two wastestreams generated from a post-combustion carbon capture system. Because of the small size of the pilot-scale system, the plant transferred the wastewater off site for treatment.
EPA evaluated the technologies available to control and treat wastewater generated by the steam electric industry. Individual plants may use one or more processes that generate wastewater streams. They may treat these wastestreams separately or in various combinations. For this reason, EPA evaluated available technologies for each major wastestream separately.
EPA identified 145 steam electric power plants that generate FGD wastewater. Of these, 117 plants (81 percent) discharge FGD wastewater after treatment using one or more of the following technologies:
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There are 63 plants (54 percent of the discharging plants) that use surface impoundments as the only type of treatment for FGD wastewaters. Most (49) of these plants also combine their FGD wastewater with other plant wastewater while the remainder (14) use impoundments to treat FGD wastewater alone. Additional plants (above and beyond the 63 plants described in the preceding sentences) also use surface impoundments to remove suspended solids prior to a more advanced treatment process, such as chemical precipitation or biological treatment.
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Some plants also use sulfide chemicals (e.g., organosulfides or sodium sulfide) to precipitate and remove heavy metals, including mercury. Sulfide precipitation is more effective than hydroxide precipitation in removing mercury because mercury sulfides have lower solubilities than mercury hydroxides. Other metal sulfide compounds also typically have lower solubilities than metal hydroxide compounds. Because sulfide precipitation is more expensive than hydroxide precipitation, plants usually use hydroxide precipitation first to remove most of the metals, and then sulfide precipitation to remove the remaining low solubility metals. This configuration overall requires less sulfide, thereby reducing the expense for the sulfide treatment chemicals.
EPA identified 40 plants (34 percent of the discharging plants) that treat their FGD wastewater using chemical precipitation (in some cases, also employing additional treatment steps such as biological treatment). Lime is the most commonly used treatment chemical to perform the pH adjustment needed for these systems. Sulfide precipitation, alone or in combination with hydroxide precipitation, is used by 33 plants (28 percent of the discharging plants). Most plants operating chemical precipitation treatment systems for FGD wastewater employ ferric chloride addition (i.e., iron coprecipitation) as part of the treatment process.
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EPA identified five plants that operate the fixed-film anoxic/anaerobic biological treatment systems to treat FGD wastewater, and another plant recently installed a suspended growth biological treatment system that targets removal of selenium and other metals.
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EPA identified three plants that treat their FGD wastewater using constructed wetlands. The constructed wetlands used to treat FGD wastewater typically are designed to treat only the FGD wastewater (and the service water used for dilution); however, because these systems are open to the environment, they also receive stormwater from the surrounding areas.
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Fly ash separated from boiler exhaust by electrostatic precipitators (ESPs) or fabric filters is collected in hoppers located underneath the equipment. From the collection hoppers, the fly ash is either transferred as dry ash to silos for temporary storage or transported (sluiced) with water to a surface impoundment (i.e., ash settling pond). Plants that generate fly ash transport
Many coal and oil-fired power plants design their fly ash handling systems to minimize or eliminate the discharge of fly ash handling transport water. Such approaches include:
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The following identifies the number of units (and plants) in the steam electric industry operating each of the different technologies available to eliminate the discharge of fly ash transport water:
• Wet vacuum pneumatic system—51 units (22 plants);
• Dry vacuum pneumatic system—485 units (220 plants);
• Pressure system—188 units (91 plants);
• Combined vacuum/pressure system—223 units (102 plants);
• Mechanical system—16 units (13 plants); and
• Other dry systems—5 units (3 plants).
Bottom ash (at times also referred to as boiler slag) is produced as fuel is burned in a boiler and collected in hoppers or other types of collection equipment directly below the boiler. Generally, boilers are sloped inward, with an opening at the bottom to allow the bottom ash to feed by gravity into collection hoppers. The hoppers contain water to quench the hot ash. Once the hoppers are full, gates at the bottom of the hoppers open, releasing the bottom ash and quench water to a conveying line, where the ash is diluted with water to approximately 20 percent solids (by weight) and pumped to a surface impoundment or a dewatering bin for solids removal. Conveying bottom ash in a water slurry is called wet sluicing. EPA identified 870 units (345 plants) that wet sluice at least a portion of their bottom ash. For further information, see Section 4.3.2 of the Technical Development Document for Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (TDD)—EPA 821–R–13–002.
Many coal and oil-fired power plants design their bottom ash handling systems to reduce or eliminate the discharge of bottom ash handling transport water. Available technologies include:
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Although mechanical drag systems require little space under the boiler they may not be suitable for all boiler configurations.
In the steam electric industry, 99 coal-fired units use mechanical drag systems for bottom ash handling. Operators have announced plans to retrofit mechanical drag systems on additional units by 2020. EPA estimates that these announced retrofits include approximately 10–30 generating units. (Note: the precise value has been withheld to prevent disclosing CBI.)
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The following identifies the number of units (and plants) in the steam electric industry operating each of the different technology options available to eliminate or minimize the amount of bottom ash transport water:
• Mechanical drag system—99 units (74 plants);
• Remote mechanical drag system—at least 2 units (2 plants) installing systems since 2009;
• Dry vacuum system—111 units (68 plants);
• Dry pressure system—13 units (11 plants);
• Complete recycle systems—at least 20 plants; and
• Mechanical systems—38 units (19 plants).
Plants often treat combustion residual landfill leachate with some of the same technologies used to treat FGD wastewater as described in Section VI.C.1. EPA identified 102 coal-fired power plants that generate and discharge leachate. Based on the responses to the industry survey, 29 of these plants treat the leachate prior to discharge using surface impoundments, constructed wetlands, or biological treatment. In some cases, plants co-treat the leachate with FGD wastewaters and, in some cases, treat the leachate independently.
Based on information from the industry survey and site visits, surface impoundments are the most common type of system used to treat combustion residual leachate from landfills and impoundments. Constructed wetlands are the next most commonly used treatment system. The anoxic/anaerobic biological treatment system used as the basis for FGD wastewater effluent limits in this proposed rule is also being used by one plant to treat leachate, with the leachate mixing with FGD wastewater immediately prior to the bioreactor stage.
Some plants mix the leachate with fly ash prior to disposing the ash in a landfill to control fugitive dust emissions and to improve the handling characteristics of the dry fly ash. Leachate is also used at some plants for dust control around ash loading areas and landfills. Many plants will collect the leachate from a surface impoundment and pump it directly back to the impoundment from which it originated.
Physical/chemical treatment systems are capable of achieving low effluent concentrations of various metals and are effective at removing many of the pollutants of concern present in leachate discharges to surface waters. The pollutants of concern in leachate have also been identified as pollutants of concern for FGD wastewater, fly ash transport wastewater, bottom ash transport water, and other combustion residuals. This is to be expected since the leachate itself comes from landfills and surface impoundments containing the combustion residuals and those wastes are the source for the pollutants entrained in the leachate. Given the similarities present among the different types of wastewaters associated with combustion residuals, combustion residual leachate will be similarly amenable to chemical precipitation treatment. The treatability of pollutants such as arsenic and mercury using chemical precipitation technology is also demonstrated by technical information compiled for ELGs promulgated for other industry sectors. See, e.g., the TDDs supporting the ELGs for the Landfills point source category (EPA–821–R–99–019) and the ELGs for the Metal Products and Machinery point source category (EPA–821–B–03–001).
The treatment technologies in use at steam electric power plants for gasification wastewater include:
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EPA is aware of two plants that currently operate integrated gasification combined cycle (IGCC) units in the United States, and a third plant is scheduled to begin operating an IGCC unit this year. All three of these plants currently treat or plan to treat the IGCC wastewaters with vapor-compression evaporation systems. The IGCC plant scheduled to begin operating this year is installing both a vapor-compression evaporation system and a cyanide destruction system to treat the gasification wastewater.
FGMC wastewater originates from activated carbon injection systems. The system can be configured either upstream or downstream of the primary particulate collection system. EPA identified 73 plants with current or planned activated carbon injection systems. Of these, 58 plants operate upstream injection systems while the remaining 15 plants inject the carbon downstream.
In cases where the injection occurs upstream of the primary particulate collection system, plants collect and handle the mercury-containing carbon with the fly ash. In cases where the injection occurs downstream of the primary particulate collection system, plants collect the mercury-containing carbon in a secondary particulate control system (e.g., a fabric filter). As with fly ash systems, plants collect the mercury-containing carbon in hoppers located underneath the equipment. From the collection hoppers, plants either transfer the mercury-containing carbon as dry ash to silos for temporary storage (67 plants; 92 percent) or transport (sluice) it with water to an ash impoundment (6 plants; 8 percent). Water transport can result in a wastewater discharge, typically an overflow from the impoundment. However, five of the six plants that use water to transport the FGMC waste to a surface impoundment do not discharge any FGMC wastewater and the remaining plant has the capability to handle the FGMC waste using a dry system but sometimes uses a wet system instead.
Coal-fired power plants can minimize or eliminate the discharge of FGMC particulate handling transport water by using the same solids handling technologies that are available for fly ash. These technologies include:
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As described in Section VI.B.6, metal cleaning wastes are generated from cleaning any metal process equipment. Because there are many different processes at plants that use metal equipment, there are a variety of metal cleaning wastes that are generated. The treatment methods used for each of the different types of metal cleaning wastes vary to some degree depending on the specific cleaning operations.
Based on information from the industry survey, surface impoundments and chemical precipitation systems are two of the most common types of systems used to treat metal cleaning wastes. Other types of treatment systems include constructed wetlands, filtration, reverse osmosis, clarification, oil/water separation, and brine concentrators.
In addition to the treatment systems used to control the discharges of metal cleaning wastes, some plants also employ other handling approaches to control or eliminate the discharge of metal cleaning wastes. For example, some plants immediately recycle the metal cleaning wastes back to other plant operations, while other plants evaporate the metal cleaning wastes in the boiler to evaporate the wastewater and eliminate the discharge. Other handling operations reported in the industry survey include offsite treatment, hazardous waste disposal, third-party disposal, mixing with fly ash and landfilling, and deep well injection.
Physical/chemical treatment systems are capable of reducing the concentration of pollutants, including metals, in the wastewater.
The following paragraphs discuss the pollutants of concern identified for each of the wastestreams considered for regulation in this proposal. For the purpose of this rulemaking, pollutants of concern are those pollutants that have been quantified in a wastestream at sufficient frequency at treatable levels (i.e., concentrations). EPA used the following sources of wastewater characterization data to identify pollutants of concern in wastewater from steam electric power plants: EPA's field sampling program, industry-supplied data including data provided in responses to the industry survey, and various literature sources. EPA relied primarily on its field sampling program data because the data were collected using consistent methods and analytical techniques for a broad range of pollutants. Therefore, where EPA had data from its field sampling program, it preferentially used that data. Where EPA did not collect field sampling data for a wastestream and industry-supplied data was available, EPA used that data. In the absence of either EPA field sampling data or industry-supplied data, EPA used literature data.
After reviewing the available sources of data for each of the wastestreams addressed by this rulemaking, EPA first combined the pollutant data to create consolidated datasets representing the concentrations of pollutants present in each wastestream prior to treatment. EPA then eliminated all pollutants that were not detected in any wastewater samples—any pollutants falling into this category are not considered pollutants of concern. Finally, for the remaining pollutants for each wastestream, EPA then identified each pollutant that was detected at a concentration greater than or equal to ten times the baseline value (see Section 6 of the TDD) in at least 10 percent of all untreated process wastewater samples.
EPA identified the following 34 pollutants of concern for FGD wastewater using EPA field sampling data: one conventional pollutant (TSS);
EPA identified the following 24 pollutants of concern for fly ash transport water using EPA field sampling data: one conventional pollutant (TSS);
EPA was unable to obtain readily available data for untreated bottom ash transport water for use in identifying the pollutants of concern using the methodology described above. However, because the pollutants found in bottom ash are constituents that are present in the coal (or petroleum coke or oil), as is the case for fly ash, EPA concluded that the pollutants of concern for bottom ash transport water are identical to the pollutants of concern identified for fly ash transport water.
EPA was also unable to obtain readily available data for identifying the pollutants of concern in FGMC wastewater. Nevertheless, based on process knowledge and engineering judgment, EPA concluded that the pollutants of concern for FGMC wastewater are likely to be identical to the pollutants of concern identified for fly ash transport water. This is due to the fact that, when activated carbon is injected into the flue gases, the carbon intermixes with the fly ash particles, and then the commingled mixture of activated carbon (which adsorbs mercury and other pollutants from the flue gases) and fly ash particles is captured together and transferred to the FGMC wastewater.
EPA evaluated the pollutants of concern for combustion residual leachate using industry sampling data for untreated leachate submitted under Part G of the industry survey. EPA evaluated the landfill leachate separately from the surface impoundment leachate. The pollutants of concern for landfill leachate include the following: one conventional pollutant (TSS);
EPA identified 19 pollutants of concern for gasification wastewater using EPA field sampling data, including: 1 conventional pollutant (BOD); 7 toxic pollutants (including arsenic, cyanide, mercury, and selenium); 5 nonconventional pollutant metals; and 6 other nonconventional pollutants.
As part of the 1974 rulemaking, EPA collected characterization data associated with chemical and nonchemical metal cleaning wastes. Based on the data collected during that rulemaking, EPA determined that TSS, oil and grease, copper, and iron were pollutants of concern for this wastestream warranting regulation and established BPT limitations for these four pollutants in discharges of metal cleaning wastes, including both nonchemical and chemical metal cleaning wastes. (EPA has also established BAT, NSPS, PSES, and PSNS for chemical metal cleaning wastes.) For additional information regarding the pollutants that may be present in nonchemical metal cleaning wastes, see the 1974
See Section 6 of the Technical Development Document for Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (TDD)—EPA 821–R–13–002 for more detailed information regarding pollutants of concern.
The pollutants of concern identified for each wastestream represents those pollutants that are present at treatable concentrations in a significant percentage of untreated wastewater samples from that wastestream. Effluent limits and monitoring for all pollutants of concern is not necessary to ensure that the pollutants are adequately controlled because many of the pollutants originate from similar sources, have similar treatabilities, and are removed by similar mechanisms. Because of this, it may be sufficient to establish effluent limits for one pollutant as a surrogate or indicator pollutant that ensures the removal of other pollutants of concern. In addition, establishing effluent limits may not be appropriate for certain pollutants of concern when the technology used as the basis for the effluent limits is not reliably effective at removing the pollutant(s).
From the list of pollutants of concern identified for each wastestream, EPA selected a subset of pollutants for establishing numeric effluent limitations. EPA considered the following factors in selecting regulated pollutants from the list of pollutants of concern:
• The pollutant was detected in the untreated wastewater at treatable levels in a significant number of samples.
• The pollutant is not used as a treatment chemical in the treatment technology that serves as a basis for the proposed regulatory option. EPA eliminated pollutants associated with treatment system additives because regulating these pollutants could interfere with efforts to optimize treatment system operation.
• The pollutant is effectively treated by the treatment technology that serves as the basis for the proposed regulatory option. EPA excluded all pollutants for which the treatment technology was ineffective (e.g., pollutant concentrations remained approximately unchanged or increased across the treatment system).
• The pollutant is not adequately controlled through the regulation of another pollutant.
Because the criteria for identifying regulated pollutants from the list of pollutants of concern depends on the treatment technology that serves as the basis for a proposed regulatory option, EPA may regulate a different subset of pollutants for a single wastestream under different regulatory options.
For the proposed options for this rulemaking (described below in Section VIII), EPA identified six pollutants for potential regulation for FGD wastewater: oil and grease, TSS, arsenic, mercury, nitrate/nitrite, and selenium. For leachate, EPA identified four potential pollutants for regulation: oil and grease, TSS, arsenic and mercury.
For fly ash discharges, bottom ash, and FGMC wastewater, under some proposed options, EPA is proposing to establish zero discharge limitations, which in effect directly control all pollutants of concern. For other proposed options that would not require zero pollutant discharge, EPA identified two potential pollutants for regulation: oil and grease and TSS for nonchemical metal cleaning wastes, EPA identified four pollutants for potential regulation (TSS, oil and grease, copper, and iron). EPA identified four pollutants for regulation for gasification wastewater: arsenic, mercury, selenium, and TDS.
See Section 6.7 of the Technical Development Document for Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (TDD)—EPA 821–R–13–002 for more information about the pollutants of concern and EPA's rationale for selecting the pollutants proposed for regulation.
Section 307(b) and (c) of the CWA requires EPA to promulgate pretreatment standards for pollutants that are not susceptible to treatment by POTWs or which would interfere with the operation of POTWs. EPA looks at a number of factors in selecting the technology basis for pretreatment standards for existing and new sources. These factors are generally the same as those considered in establishing BAT and NSPS, respectively. However, unlike direct dischargers whose wastewater will receive no further treatment once it leaves the facility, indirect dischargers send their wastewater to POTWs for further treatment. As such, EPA must also determine that a pollutant is not susceptible to treatment at a POTW or would interfere with POTW operations.
Before establishing PSES/PSNS for a pollutant, EPA examines whether the pollutant “passes through” a POTW to waters of the U.S. or interferes with the POTW operation or sludge disposal practices. In determining whether a pollutant would pass through POTWs, EPA generally compares the percentage of a pollutant removed by well-operated POTWs performing secondary treatment
For this proposed rule, EPA conducted a pass through analysis for the technology basis for each wastestream for each regulatory option presented below in Section VII.C. For those wastestreams and regulatory options for which EPA is proposing zero discharge of pollutants, EPA set the percentage removed by the technology basis at 100 percent. EPA did not conduct its traditional pass-through analysis for these wastestreams (e.g., fly ash transport water, bottom ash transport water, and flue gas mercury control wastewater) because limitations for these wastestreams for direct dischargers would consist of no discharge of process wastewater pollutants to waters of the U.S., and therefore, all pollutants would “pass through” the POTW for these wastestreams.
During the 1976 development of pretreatment standards for chemical metal cleaning wastes, EPA selected pollutants for regulation based on two criteria:
• The pollutant has the potential to harm the POTW (e.g., impair the activity of the biological treatment system); or
• The pollutant has the potential to harm the receiving water (i.e., if the pollutant is not removed or is removed inadequately by the POTW).
For FGD wastewater, leachate, and gasification wastewater, EPA determined the percentage removed for the pollutants by the technology basis using the same data sources used to determine the long-term averages for each set of limitations (see Section 13 of the TDD).
• Fate of Priority Pollutants in Publicly Owned Treatment Works, September 1982, EPA 440/1–82/303 (50 POTW Study); and
• National Risk Management Research Laboratory (NRMRL) Treatability Database, Version 5.0, February 2004 (formerly called the Risk Reduction Engineering Laboratory (RREL) database).
The 50 POTW study presents data on the performance of 50 POTWs achieving secondary treatment in removing toxic pollutants. When data for a pollutant were available from the 50 POTW Study, EPA used that data. When data for pollutants were not available from the 50 POTW Study, EPA used NRMRL data. The NRMRL treatability database provides information on removals obtained by various treatment technologies for a variety of wastewater sources. Therefore, where EPA used data from the NRMRL treatability database, it used only data from the treatment of domestic and industrial wastewater using technologies representative of secondary treatment. For a more detailed discussion of how EPA performed its removal analysis, see Section 11 of the TDD.
With a few exceptions, EPA performs a POTW pass-through analysis for pollutants selected for regulation for BAT/NSPS for each wastestream of concern and for each regulatory option. The exception is for conventional pollutants such as BOD
Section VIII below summarizes the results of the pass through analysis. All of the pollutants proposed for regulation under BAT/NSPS (except for conventional pollutants and iron found in nonchemical metal cleaning wastes) were found to pass through and, therefore, were selected for regulation under PSES/PSNS.
EPA is not proposing to revise the BPT effluent guidelines or establish BCT effluent guidelines in this notice because the same wastestreams would be controlled at the proposed BAT/BADCT (NSPS) level of control. EPA is proposing to remove FGD wastewater, FGMC wastewater, gasification wastewater, and leachate from the definition of low-volume wastes. As a result, EPA is making a structural adjustment to the text of the regulation at 40 CFR part 423 to add paragraphs that list these four wastestreams by name, along with their applicable effluent limitations. The reformatted regulatory text for these four wastestreams includes BPT effluent limits, which are the same as the current BPT effluent limits for low volume wastes.
EPA is proposing to revise or establish BAT, BADCT (NSPS), PSES, and PSNS that may apply to discharges of seven wastestreams: FGD wastewater, fly ash transport water, bottom ash transport water, combustion residual leachate, nonchemical metal cleaning wastes, and wastewater from FGMC systems and gasification systems. In Section VI of this preamble and in the TDD, EPA describes the treatment technologies and operational practices that it reviewed during the development of this proposed rule. From these, EPA identified a subset of technologies (treatment processes and operational practices) that were most promising as candidate BAT/BADCT options. In this proposal, EPA is presenting eight main regulatory options (i.e., Option 1, Option 3a, Option 2, Option 3b, Option 3, Option 4a, Option 4, and Option 5) that represent different levels of pollutant removal associated with different wastewater streams (i.e., each succeeding option from Option 1 to Option 5 would achieve more reduction in discharges of pollutants to waters of the U.S). Table VIII–1 summarizes the eight main regulatory options, which are described in the paragraphs below.
As discussed further below, EPA is also proposing to add provisions to the ELGs that would prevent facilities from circumventing applicable ELGs. The proposed provisions would clarify the acceptable conditions for discharge of reused process wastewater and establish effluent monitoring requirements.
EPA is considering establishing BMPs that would apply to surface impoundments (i.e., ponds) that receive, store, dispose of, or are otherwise used to manage coal combustion residuals including FGD wastes, fly ash, bottom ash (which includes boiler slag), leachate, and other residuals associated with the combustion of coal to prevent uncontrolled discharges from these impoundments as described below in the paragraph titled, “BMPs for CCR Surface Impoundments.”
As part of its consideration of technological availability and economic achievability for all regulatory options, EPA considered the magnitude and complexity of process changes and new equipment installations that would be required at facilities to meet the requirements of the rule. As described further below, EPA proposes that certain limitations and standards being proposed today for existing sources would not apply until July 1, 2017 (approximately three years from the effective date of this rule).
EPA is also considering establishing, as part of the BAT for existing sources, a voluntary incentive program that would provide more time for plants to implement the proposed BAT requirements if they adopt additional process changes and controls that would provide significant environmental protections beyond those achieved by the preferred options in this proposed rule. As described further below, power plants would be granted two additional years (beyond the time described above in the preceding paragraph) if they also dewater, close and cap all CCR surface impoundments at the facility (except combustion residual leachate impoundments), including those surface impoundments located on non-adjoining property that receive CCRs from the facility. A power plant participating in the voluntary incentive program could continue to operate surface impoundments for which combustion residual leachate was the only type of CCR solids or wastewater contained in the impoundment. Power plants would be granted five additional years (beyond the time described above in the preceding paragraph) if they eliminate discharges of all process wastewater to surface waters, with the exception of cooling water discharges.
Surface impoundments use gravity to remove solid particles (i.e., suspended solids) from the wastewater. Metals in FGD wastewater are present in both soluble (i.e., dissolved) and particulate form. Some metals, such as arsenic, are often present mostly in particulate form; these usually can be removed to a substantial degree by a well-operated settling process that has a sufficiently long residence time. However, other pollutants, such as selenium, boron, and magnesium, are present mostly in soluble form and are not effectively and reliably removed by wastewater surface impoundments. For metals present in both soluble and particulate forms (such as mercury), surface impoundments will not effectively remove the dissolved fraction. Furthermore, the conditions present in some surface impoundments can create chemical conditions (e.g., low pH) that convert particulate forms of metals to soluble forms, which would not be removed by the gravity settling process in the surface impoundment. Additionally, EPRI (a technical research organization funded by the electric power industry) has reported that adding FGD wastewater to surface impoundments used to treat ash transport water (i.e., ash ponds) may reduce the settling efficiency in the impoundments due to gypsum particle dissolution, thus increasing the effluent TSS concentrations. EPRI has also reported that the FGD wastewater includes high loadings of volatile metals, which can increase the solubility of metals in surface impoundments, thereby leading to increased levels of dissolved metals and resulting in higher concentrations of metals in the discharge from surface impoundments.
During the summer, some surface impoundments become thermally stratified. When this occurs, the top layer of the impoundment is warmer and contains higher levels of dissolved oxygen, whereas the bottom layer of the impoundment is colder and can have significantly lower levels of oxygen and may develop anoxic conditions. Typically, during fall, as the air temperature decreases, the upper layer of the impoundment becomes cooler and denser, thereby sinking and causing the entire volume of the impoundment to circulate. Solids that have collected at the bottom of the impoundment may become resuspended due to such mixing, increasing the concentrations of pollutants discharged during the turnover period. Seasonal turnover effects largely depend upon the size and configuration of the surface impoundment. Smaller, and especially shallow, surface impoundments likely do not experience turnover because they do not have physical characteristics that promote thermal stratification. However, some surface impoundments are large (e.g., greater than 300 acres) and deep (e.g., greater than 10 meters deep) and likely experience some degree of turnover.
Technologies more advanced than surface impoundments exist and that are more effective at removing both soluble (i.e., dissolved) and particulate forms of metals, as well as other pollutants such as nitrogen compounds and TDS. Because many of the pollutants of concern for FGD wastewater are present in dissolved form and would not be removed by surface impoundments, and because of the relatively large mass loads of these pollutants (e.g., selenium, dissolved mercury) discharged by the FGD wastestream, EPA explored other technologies that would be more effective at removing these pollutants of concern and is co-proposing three options that would include such technologies. However, for reasons discussed in Section VII.A.3, EPA is also co-proposing options under which some or all facilities would continue, for the purposes of the ELGs, to be subject to the BPT requirements based on surface impoundments for treatment of FGD wastewater. Under these options, BAT would be left to a site-specific determination. For the reasons discussed above and in Section VIII.A.3, EPA also does not believe that surface impoundments represent best available demonstrated control technology for controlling pollutants in FGD wastewater. Therefore, none of the regulatory options for NSPS presented in this proposal are based on the performance of surface impoundments for FGD wastewater.
The technology basis for the effluent limitations and standards for FGD wastewater in Option 1 is physical/chemical treatment consisting of the following: Chemical precipitation/coprecipitation (employing the combination of hydroxide precipitation, iron coprecipitation, and sulfide precipitation). Option 1 also incorporates the use of flow minimization for plants with high FGD discharge flow rates (i.e., greater than 1,000 gpm) and FGD system metallurgy and operating practices that can accommodate an increase in chlorides (e.g., scrubber systems constructed of non-metallic materials or corrosion-resistant metal alloys, or systems operating with absorber chloride concentrations substantially below the design chloride limit). The flow minimization at these plants would be achieved by either reducing the FGD purge rate or recycling a portion of their FGD wastewater.
Physical/chemical treatment (i.e., chemical precipitation) is used to remove metals and other pollutants from wastewater. Chemicals are added to the wastewater in a series of reaction tanks to convert soluble metals to insoluble metal hydroxide or metal sulfide compounds, which precipitate from solution and are removed along with other suspended solids. An alkali, such as hydrated lime, is typically added to adjust the pH of the wastewater to the point where metals precipitate out as metal hydroxides (typically referred to as hydroxide precipitation). Chemicals such as ferric chloride are often added to the system to increase the removal of certain metals through iron coprecipitation. The ferric chloride also acts as a coagulant, forming a dense floc that enhances settling of the metal precipitate in the downstream clarification stage. Coagulants and flocculants are often added to facilitate the settling and removal of the newly formed solids. Plants trying to increase removals of mercury and other metals will also include sulfide addition (e.g., organosulfide) as part of the process. Adding sulfide chemicals in addition to hydroxide precipitation provides even greater reductions of heavy metals due to the very low solubility of metal sulfide compounds, relative to metal hydroxides. Sulfide precipitation is widely used in Europe and multiple locations in the United States have installed this technology. Forty U.S. power plants (34 percent of plants
The technology basis for the effluent limitations and standards for FGD wastewater in Options 2, 3b (for units located at facilities with a total wet-scrubbed capacity of 2,000 MW or more)
Physical/chemical treatment systems are capable of achieving low effluent concentrations of various metals and the sulfide addition is particularly important for removing mercury; however, this technology is not effective at removing selenium, nitrogen compounds, and certain metals that contribute to high concentrations of TDS in FGD wastewater (e.g., bromides, boron). Six power plants in the U.S. are operating FGD treatment systems that include a biological treatment stage designed to substantially reduce nitrogen compounds and selenium.
The technology basis for the effluent limitations and standards for FGD wastewater in Option 5 is chemical precipitation/coprecipitation used in combination with vapor compression evaporation. Physical/chemical treatment systems can achieve low effluent concentrations for a number of pollutants, and reduce concentrations even further when combined with biological treatment systems, as described above and in the TDD. However, these technologies have not been effective at removing substantial amounts of boron and pollutants such as sodium and bromides that contribute to high concentrations of TDS. Another FGD wastewater treatment technology that can address these more recalcitrant pollutants, as well as removing the pollutants treated by physical/chemical and biological technologies, is vapor-compression evaporation. This technology uses an evaporator to produce a concentrated wastewater stream and a reusable distillate stream. The concentrated wastewater stream is either disposed of or further processed to produce a solid by-product and additional distillate. The plant can reuse the distillate stream as makeup water. Two U.S. plants and four Italian plants are operating this technology to treat FGD wastewater from their coal-fired generating units.
For Option 3a and Option 3b (for units located at facilities with a total wet-scrubbed capacity of less than 2,000 MW), EPA is proposing not to characterize a technology basis for effluent limitations and standards applicable to discharges of pollutants in FGD wastewater at this time. As illustrated above, there is a wide range of technologies currently in use for reducing pollutant discharges associated with FGD wastewater, and research continues in the development of additional technologies to treat FGD wastewater (see Section 7.1.7 of the TDD for more information on emerging technologies). The more advanced technologies (those that reduce the most pollutants) reflect recent innovations in the area of treatment of FGD wastewater. EPA expects this trend to continue and, therefore, under Option 3a and Option 3b (for units located at facilities with a total wet-scrubbed capacity of less than 2,000 MW), effluent limitations representing BAT for discharges of FGD wastewater would be determined on a site-specific BPJ basis. Under Options 3a and Option 3b (for units located at facilities with a total wet-scrubbed capacity of less than 2,000 MW), pretreatment program control authorities would need to develop local limits to address the introduction of pollutants in FGD wastewater by steam electric plants to the POTWs that cause pass through or interference, as specified in 40 CFR 403.5(c)(2).
As described below in this section of the preamble, EPA is proposing that certain limitations and standards being proposed today for existing sources would apply to discharges of FGD wastewater generated on or after the date established by the permitting authority that is as soon as possible within the next permit cycle after July 1, 2017. FGD wastewater generated prior to that date (i.e., “legacy” wastewater) from existing direct dischargers would remain subject to the existing BPT effluent limits. For indirect dischargers, EPA is proposing that PSES for FGD wastewater would apply to FGD wastewater generated after a date determined by the control authority that is as soon as possible beginning July 1,
Under Options 3a, 3b, 3, 4a, 4, and 5, EPA would establish “zero discharge” effluent limitations and standards for discharges of pollutants in fly ash transport water, based on the use of dry fly ash handling technologies. The dry handling technologies for fly ash are described above in Section VI of this preamble and in the TDD for the proposed rule. Although surface impoundments can be effective at removing particulate forms of certain metals and other pollutants, they are not designed for, nor are they effective at, removing other pollutants of concern such as dissolved metals and nutrients. The concentrations of pollutants that remain in the ash impoundment effluent following gravity settling, in combination with the large volumes of fly ash transport water discharged to surface waters (2.4 MGD on average per discharging plant), results in a large mass loading of pollutants of concern being discharged from surface impoundments. Furthermore, as described in Section VI, surface impoundments can be susceptible to seasonal turnover that degrades pollutant removal efficacy, and co-managing FGD and ash wastes in the same impoundments can lead to increased pollutant discharges.
Dry handling technologies are the technology basis for the current fly ash NSPS/PSNS requirements, which were promulgated in 1982. All generating units built since then have been subject to a “zero discharge” standard. Some existing units have also converted to dry handling technologies. Due to the NSPS discharge standard or economic or operational factors, approximately 66 percent of coal- and petroleum coke-fired generating units that produce fly ash currently operate dry fly ash transport systems, while another 15 percent operate both wet and dry fly ash transport systems. The remaining 19 percent operate only wet fly ash transport systems. In cases where a unit has both wet and dry handling operations, the wet handling system is typically used as a backup to the dry system. Effluent limitations and standards based on dry ash handling would completely eliminate the discharge of pollutants in fly ash transport water.
EPA considered basing one or more regulatory options for fly ash transport water on chemical precipitation treatment technology, with numeric effluent limits for discharges of the wastestream to surface waters. EPA has not identified any facilities using this treatment technology to treat fly ash transport water, although EPA has reviewed two literature sources that describe laboratory- or pilot-scale tests using the technology. Upon reviewing the discharge flow rates for fly ash transport water, however, EPA determined that the costs associated with treatment using chemical precipitation were higher than the cost of the dry handling technology upon which Options 3a, 3b, 3, 4a, 4, and 5 are based, despite being less effective at removing pollutants. Since the costs for chemical precipitation treatment are higher than the cost for converting to dry handling technologies, and chemical precipitation removes fewer pollutants, EPA did not include chemical precipitation treatment as part of the regulatory options for fly ash in this proposed rule. See DCN SE03869.
As described below in this section of the preamble, EPA is proposing that the limitations for existing sources based on Options 3a, 3b, 3, 4a, 4, or 5 would apply to discharges of fly ash transport water generated after the date established by the permitting authority that is as soon as possible within the next permit cycle after July 1, 2017. For indirect dischargers, EPA is proposing that PSES for fly ash would apply to the fly ash transport water generated after a date determined by the control authority that is as soon as possible beginning July 1, 2017. Fly ash transport water generated by existing direct dischargers prior to that date (i.e., “legacy” wastewater) would remain subject to the existing BPT effluent limits. EPA considered subjecting legacy fly ash transport water (i.e., the fly ash transport water generated prior to the date established by the permitting authority, as described above) to the proposed BAT zero discharge requirement. As explained above, currently fly ash transport wastewater and the associated pollutants are sent to surface impoundments for treatment prior to discharge. The technology basis identified above for the proposed zero discharge requirement eliminates the generation of the fly ash wastewater but does not eliminate fly ash transport wastewater that has already been transferred to a surface impoundment. Furthermore, the technologies identified as the basis for fly ash transport water discharge requirements have not been demonstrated for the legacy fly ash transport wastewater that has already been generated. As such, EPA is not proposing BAT or PSES requirements for discharges of legacy fly ash transport water generated prior to the date established by the permitting authority or control authority. As proposed today, discharges of legacy fly ash transport water by existing direct dischargers would remain subject to the existing BPT effluent limits; however, EPA is also considering whether to set the BAT effluent limitations for legacy fly ash transport water equal to the existing BPT effluent limits. See Section XVI for additional information.
Although surface impoundments can be effective at removing particulate forms of metals and other pollutants, they are not designed for nor are they effective at removing other pollutants of concern such as dissolved metals and nutrients. The concentrations of pollutants that remain in the wastestream at the ash impoundment effluent, in combination with the large volumes of bottom ash transport water discharged to surface waters, results in a large mass loading of pollutants of concern being discharged from surface impoundments. Effluent limitations and standards based on the technologies used as the basis for Options 4a (for units more than 400 MW), 4, and 5 would completely eliminate the discharge of pollutants in bottom ash transport water.
Under Options 4a (for units more than 400 MW), 4, and 5, EPA would establish “zero discharge” effluent limitations and standards for discharges of pollutants in bottom ash transport water, based on either using bottom ash handling technologies that do not require transport water or managing a wet-sluicing bottom ash handling system so that it does not discharge bottom ash transport water or pollutants associated with the bottom ash transport water. These technologies for handling bottom ash are described above in section VI of this preamble and in the TDD for the proposed rule. About 80 percent of coal- and petroleum coke-fired units generating bottom ash operate wet bottom ash transport systems, while approximately 20 percent operate systems that eliminate the use of transport water. Most, but not all, of the wet bottom ash transport systems discharge to surface waters. In cases where a plant has both wet and dry handling operations, the wet handling system is typically used as a backup to the dry system. In the case of bottom ash handling systems, the term “dry” is typically used to refer to a process that does not use water as the transport medium to sluice the bottom ash to a CCR impoundment. In some cases, a “dry” bottom ash system may be entirely dry and avoid all use of water. Many dry bottom ash systems, however, include a water bath at the bottom of a boiler in which the bottom ash is dropped and cooled, and then the bottom ash is mechanically dragged out of the boiler along a conveyor belt and deposited in a pile adjacent to the building housing the boiler. The bottom ash conveyed out of the water bath will be damp because the ash particles retain some moisture from the water bath and small volumes of water will typically drain from the standing bottom ash pile. The water draining from the pile is usually collected in a sump and either returned to the water bath below the boiler or managed as low volume waste. Such mechanical drag systems are considered as one available technology that may be used to achieve proposed limitations and standards under Options 4a (for units >400 MW), 4, and 5. Other technologies serving as the basis for limitations and standards proposed under Options 4a (for units >400 MW), 4, and 5 are completely dry bottom ash systems, remote mechanical drag systems, and impoundment-based systems that are managed to eliminate the discharge of all bottom ash transport water and the associated pollutants.
In developing the technologies that serve as the basis for the regulatory options with respect to bottom ash transport water, EPA considered basing one or more options on chemical precipitation treatment technology, with numeric effluent limitations or standards for discharges of the wastestream to surface waters. Upon reviewing the discharge flow rates for bottom ash transport water, however, EPA determined that the costs associated with treatment were comparable to the cost of the technologies upon which Options 4a (for units more than 400 MW), 4, and 5 are based, despite being less effective at removing pollutants. Since the costs for chemical precipitation treatment were found to be higher than the cost for converting to dry handling or closed loop technologies, and the treatment technology removes fewer pollutants, EPA did not include chemical precipitation treatment as part of the regulatory options for bottom ash in this proposed rule. See DCN SE03869.
As described below in this section of the preamble, EPA is proposing that certain BAT limitations for existing sources under Options 4a (for units more than 400 MW), 4, or 5 would apply to discharges of bottom ash transport water generated after the date established by the permitting authority or control authority that is as soon as possible within the next permit cycle after July 1, 2017. For indirect dischargers, EPA is proposing that PSES for bottom ash transport water would apply to bottom ash transport water generated after a date determined by the control authority that is as soon as possible beginning July 1, 2017. Bottom ash transport water generated by existing direct dischargers prior to that date (i.e., “legacy” wastewater) would remain subject to the existing BPT effluent limits. EPA considered subjecting legacy bottom ash transport water (i.e., the bottom ash transport water generated prior to the date established by the permitting authority or control authority, as described above), to the BAT and PSES zero discharge requirement considered under Options 4a (for units more than 400 MW), 4, and 5. As explained above, currently, bottom ash transport wastewater and the associated pollutants are sent to surface impoundments for treatment prior to discharge. The technology bases identified above for Options 4a (for units more than 400 MW), 4, and 5 eliminate the generation of the bottom ash wastewater but do not eliminate bottom ash transport wastewater that has already been transferred to a surface impoundment. The technologies identified as the basis for bottom ash transport water discharge requirements under Options 4a (for units more than 400 MW), 4, and 5 have not been demonstrated for the legacy bottom ash transport wastewater that has already been generated and do not represent BAT/PSES with respect to legacy bottom ash wastewater. As such, under Options 4a (for units more than 400 MW), 4, and 5 EPA would not establish BAT or PSES requirements for discharges of legacy bottom ash transport water generated prior to the date established by the permitting authority. As proposed today, discharges of legacy bottom ash transport water by existing direct dischargers would remain subject to the existing BPT effluent limits; however, EPA is also considering whether to set the BAT effluent limitations for legacy bottom ash transport water equal to the existing BPT effluent limits. See Section XVI for additional information.
The technology basis for effluent limitations and standards for leachate under Options 4 and 5 is chemical precipitation/coprecipitation. This same technology is the basis for BAT Option 1 for FGD wastewater. Properly designed and operated surface impoundments can effectively remove suspended solids, including pollutants such as particulate forms of certain metals when associated with the suspended solids. However, since surface impoundments are not designed for, nor are they effective at, removing other pollutants of concern such as dissolved metals, EPA used chemical precipitation/coprecipitation as the technology basis for Options 4 and 5. Physical/chemical treatment systems are capable of achieving low effluent concentrations of various metals and are effective at removing many of the pollutants of concern present in leachate discharges to surface waters. The pollutants of concern in leachate are the same pollutants that are present in, and in many cases are also pollutants of concern for, FGD wastewater, fly ash transport wastewater, bottom ash transport water, and other combustion residuals. This is to be expected since the leachate itself comes from landfills and surface impoundments containing the combustion residuals and those wastes are the source for the pollutants entrained in the leachate. Given the similarities present among the different types of wastewaters associated with combustion residuals, combustion residual leachate will be similarly amenable to chemical precipitation treatment. The treatability of pollutants such as arsenic and mercury using chemical precipitation technology is also demonstrated by technical information compiled for ELGs promulgated for other industry sectors. See, e.g., the TDDs supporting the ELGs for the Landfills Point Source Category (EPA–821–R–99–019) and the ELGs for the Metal Products and Machinery Point Source Category (EPA–821–B–03–001). However, as is the case when treating FGD wastewater, this technology is not effective at removing selenium, boron and certain other parameters that contribute to total dissolved solids (e.g., magnesium, sodium).
EPA also considered developing a regulatory option that, for leachate, would be based on the technology of chemical precipitation/coprecipitation used in conjunction with anoxic/anaerobic biological treatment. This is the same technology used as the basis for effluent limitations and standards for FGD wastewater under Options 2, 3b (for units at facilities with a total wet-scrubbed capacity of 2,000 MW or more), 3, 4a, and 4. EPA has reviewed this technology as a potential basis for effluent limitations and standards for leachate and the TDD presents information about the compliance costs and pollutant removals associated with this technology. The microorganisms used in the bioreactors for the biological treatment technology for FGD wastewater are resilient and have shown that they operate effectively under varying conditions that occur in FGD system and the FGD wastewater treatment system. However, leachate flows can be more variable than FGD wastewater and, more importantly, may be too intermittent to facilitate reliable and consistent biological treatment. Such variations are easily accommodated in a chemical precipitation treatment system, but may be difficult to manage in a biological treatment system reliant on healthy and sustainable populations of microorganisms.
If EPA did finalize BAT effluent limits developed under Options 4 or 5 would (although it is not proposing such limits as a preferred option today), EPA's intent is that these limits would apply to discharges of leachate generated after the date established by the permitting authority that is as soon as possible within the next permit cycle after July 1, 2017. For indirect dischargers, PSES for leachate would apply to leachate generated after a date determined by the control authority that is as soon as possible beginning July 1, 2017. Leachate generated by existing direct dischargers prior to that date (i.e., “legacy” leachate wastewater) would remain subject to the existing BPT effluent limits. EPA considered subjecting legacy leachate wastewater to the proposed BAT and PSES limitations and standards. However, although some plants use relatively small surface impoundments to treat leachate and these impoundments would contain relatively small volumes of legacy leachate wastewater, other plants send leachate to relatively large surface impoundments that also contain other plant wastewaters, such as fly ash or bottom ash transport water, cooling water, and/or other low volume wastes. EPA does not have the data to demonstrate that the technologies identified above represent BAT for legacy combustion residual leachate. As such, EPA would not expect to finalize BAT requirements associated with discharges of legacy combustion residual leachate (i.e., the leachate generated prior to the date established by the permitting authority or control authority). As proposed today, discharges of legacy combustion residual leachate by existing direct dischargers would remain subject to the existing BPT effluent limits; however, EPA is also considering whether to set the BAT effluent limitations for legacy combustion residual leachate that has not been mixed with non-legacy wastes equal to the existing BPT effluent limits. See Section XVI for additional information.
As discussed above in Section VI of this preamble, some plants inject dry sorbents (e.g., activated carbon) into the flue gas stream to reduce mercury emissions from the flue gas. Mercury adsorbs to the sorbent particles, and these mercury-enriched sorbents are then removed from the flue gas using a fabric filter or ESP. The sorbent can be injected upstream of the primary particulate collector, in which case the mercury-enriched sorbent is collected with the majority of the fly ash. Alternatively, the sorbent can be injected downstream of the primary particulate collector and collected with a much smaller amount of fly ash (i.e., the fly ash that passed through the primary collector) in a smaller, dedicated secondary particulate collector such as a fabric filter. In either case, the plant collects the mercury-
Under Options 3a, 3b, 3, 4a, 4, and 5, EPA would establish “zero discharge” effluent limitations and standards for discharges of pollutants in FGMC wastewater based on using dry handling technologies to store and dispose of fly ash without utilizing transport water. The dry handling technologies that would be used for FGMC wastes are identical to the dry fly ash handling technologies described above in section VI of this preamble and in the TDD for the proposed rule. Although surface impoundments can effectively remove particulate forms of metals and other pollutants, they are not designed for nor are they effective at removing other pollutants of concern such as dissolved metals and nutrients. Effluent limits based on dry handling would completely eliminate the discharge of pollutants in FGMC wastewater.
EPA is also aware of some plants that add oxidizers to the coal prior to burning the coal in the boiler. This chemical addition oxidizes the mercury present in the flue gas, which allows the plant to remove mercury more readily from the flue gas in the wet FGD system. EPA did not evaluate separate treatment technologies for the use of oxidizers to control flue gas mercury emissions because using oxidizers does not generate a separate FGMC wastewater.
To the extent that a power plant generates FGMC wastewater before any BAT zero discharge limitation were to apply, the proposed BAT limitations under Options 3a, 3b, 3, 4a, 4, and 5 would apply to discharges of FGMC wastewater generated after the date established by the permitting authority that is as soon as possible within the next permit cycle after July 1, 2017. For indirect dischargers, EPA is proposing that PSES for FGMC wastewater would apply to FGMC wastewater generated after a date determined by the control authority that is as soon as possible beginning July 1, 2017. As proposed today, legacy FGMC wastewater generated by existing direct dischargers prior to that date would remain subject to the existing BPT effluent limits; however, EPA is also considering whether to set the BAT effluent limitations for legacy FGMC wastewater equal to the existing BPT effluent limits. EPA considered subjecting legacy FGMC wastewater to the proposed BAT/PSES zero discharge requirements. As explained above, although most FGMC wastes are managed using dry handling systems, EPA has identified six plants that manage their FGMC waste with systems that use water to transport the waste to surface impoundments. The technology basis identified above for the proposed zero discharge requirement eliminates the generation of the FGMC wastewater by implementing certain process changes that do not use water to transport the FGMC waste; however, it does not eliminate the already-generated FGMC wastewater that has already been transferred to and stored in a surface impoundment. The technologies that underlie regulatory Options 3a, 3b, 3, 4a, 4, and 5 do not represent BAT or PSES for the control of pollutants from legacy FGMC wastewater and would not allow FGMC wastewater that has already been generated to comply with a zero discharge requirement. As such, EPA is not proposing BAT or PSES requirements associated with discharges of legacy FGMC wastewater generated prior to the date established by the permitting authority or control authority. However, EPA is considering whether to set the BAT effluent limitations for legacy FGMC wastewater equal to the existing BPT effluent limits. See Section XVI for additional information.
In addition to the vapor-compression evaporation technology that is the basis for all BAT and BADCT/NSPS options for gasification wastewater, EPA considered also including cyanide treatment as part of the technology basis for one or more options. EPA notes that the Edwardsport IGCC plant that is scheduled to soon begin commercial operation includes cyanide destruction as one step in the treatment process for gasification wastewater. However, EPA currently does not have sufficient gasification wastewater data with which to calculate effluent limits based on the performance of cyanide treatment as part of a BAT/BADCT (NSPS) regulatory option. A possible approach to resolve this would be to transfer effluent limits for cyanide from an ELG for another industry sector. Alternatively, EPA may obtain effluent data from the gasification wastewater treatment system for the Edwardsport IGCC unit once it begins commercial operation and use these data to calculate effluent limitations for cyanide. EPA solicits data on the concentrations of cyanide present in gasification wastewater and solicits comment on whether EPA should establish BAT or BADCT (NSPS) control on the discharge of cyanide.
The current ELG relies on three key terms specific to metal cleaning waste: “metal cleaning waste,” “chemical metal cleaning waste,” and “nonchemical metal cleaning waste.” The regulation includes a definition of the broadest term, “metal cleaning waste,” as “any wastewater resulting from cleaning [with or without chemical cleaning compounds] any metal process equipment, including, but not limited to, boiler tube cleaning, boiler fireside
The current ELGs include BPT effluent limits for the allowable levels of TSS, oil and grease, copper and iron in discharges of metal cleaning waste, which includes both chemical and nonchemical metal cleaning wastes. Although the current BPT effluent limits apply to nonchemical metal cleaning wastes, EPA has found that some discharges of nonchemical metal cleaning waste are authorized pursuant to permits incorporating limitations based on BPT requirements for low volume wastes and, therefore, do not have iron and copper limits. The information EPA has collected to date indicates many facilities are not discharging nonchemical metal cleaning wastewater or have copper and iron limits (see Section VIII.A.3 and Section 7.7 of the TDD for more information).
The current ELGs do not include BAT/NSPS requirements for the broadly defined category of metal cleaning wastes; however, they do include BAT/NSPS for chemical metal cleaning waste. EPA has not promulgated BAT/NSPS for nonchemical metal cleaning waste. Similarly, although the current ELGs do not include PSES/PSNS for metal cleaning waste, they do include PSES/PSNS for chemical metal cleaning waste. EPA has not promulgated PSES/PSNS for nonchemical metal cleaning waste. An overview of the existing ELGs for metal cleaning waste, including chemical and nonchemical metal cleaning waste, is provided below in Table VIII–2.
As described above, EPA found that some discharges of nonchemical metal cleaning waste are authorized pursuant to permits incorporating limitations based on BPT requirements for low volume wastes and, therefore, do not have iron and copper limits. Because the potential costs for dischargers to comply with iron and copper limits is not known, EPA is proposing to provide an exemption from new copper and iron limitations or standards for existing discharges of nonchemical metal cleaning wastes from generating units that are currently authorized without iron and copper limits. For these discharges, BAT limitations for nonchemical metal cleaning waste would be set equal to BPT limitations for low volume waste, and the regulations would not specify PSES. EPA solicits comment on the specific generating units that should be included in the exemption. See Section VIII.A.3 for additional details regarding the information that EPA is requesting as part of the comment solicitation.
EPA is also considering setting BAT for nonchemical metal cleaning waste equal to the metal cleaning waste BPT for all nonchemical metal cleaning wastes (i.e., no exemption for discharges of nonchemical metal cleaning wastes currently authorized without iron and copper limits) and, for PSES, to establish copper standards for all discharges of nonchemical cleaning wastes. As part of this approach, EPA is evaluating whether some plants would incur costs to comply with the current BPT standards. Therefore, as described later in this preamble, EPA is also soliciting comments associated with each generating unit with discharges of nonchemical metal cleaning wastes that are not currently subject to the BPT copper and iron limits, in order to understand the nonchemical metal cleaning wastes that are generated, the characteristics of the wastewater, what actions would be needed to comply with the proposed copper and iron limits, and estimated costs associated with those actions. See Section VIII.A.3 for details regarding the information that EPA is requesting as part of the comment solicitation.
First, the anti-circumvention provision would require that compliance with the new effluent limits applicable to a particular wastestream (e.g., FGD, gasification wastewater, leachate) be demonstrated prior to use of the wastewater in another plant process that results in surface water discharge or mixing the treated wastestream with other wastestreams. Under 40 CFR 122.45(h), in situations where an NPDES permit effluent limitations or standards imposed at the point of discharge are impractical or infeasible, effluent limitations or standards may be imposed on internal wastestreams before mixing with other wastestreams or cooling water streams. Limitations on internal wastestreams may be necessary, such as in situations where the wastes at the point of discharge are so diluted as to make monitoring impracticable, or the interferences among pollutants would make detection or analysis impracticable. Many power plants combine FGD wastewater and other power plant wastewaters with ash transport water and/or cooling water prior to discharge, which can dilute the wastewaters by several orders of magnitude prior to the final outfall. In addition, surface impoundments typically contain a variety of wastes (e.g., ash transport water, coal pile runoff, landfill/impoundment leachate) that when mixed with the FGD wastewater or gasification wastewater may make the analysis to measure compliance with technology-based effluent limits impracticable. Because of the high degree of dilution and the number of wastestream sources containing similar pollutants, effluent
Second, the anti-circumvention provision would establish requirements intended to prevent steam electric power plants from circumventing the effluent limits and standards by moving effluent produced by a process operation for which there is a zero discharge effluent limit/standard to another process operation for discharge under less stringent requirements than intended by the steam electric ELGs. For example, several options (including Option 3a) considered in this rulemaking would establish a zero discharge requirement for pollutants in fly ash transport water and FGMC wastewater. If this option were selected for the final rule, the anti-circumvention provisions would allow power plants to recycle/reuse these wastestreams in ash transport processes or other plant processes, but only to the extent that the plants do not discharge any pollutants associated with flue gas mercury controls or transporting fly ash. The presence of a zero discharge wastestream in a process that ultimately discharges to surface water (e.g., use of fly ash transport water as FGD absorber make-up water in a scrubber that discharges FGD wastewater) would not be in compliance with the effluent limit. EPA requests comment on the extent to which this provision may discourage water re-use.
Last, the anti-circumvention provisions would expressly require permittees to use analytical EPA-approved methods that are sufficiently sensitive to provide reliable quantified results at levels necessary to demonstrate compliance with the effluent limits proposed by this rulemaking when such methods are available. EPA's detailed study and the field sampling for this rulemaking demonstrate that the use of sufficiently sensitive analytical methods is critically important to detecting, identifying, and measuring the concentrations of pollutants present in power plant wastewaters. Where EPA has approved more than one analytical method for a pollutant, the Agency expects that permittees would select methods that are able to quantify the presence of pollutants in a given discharge at concentrations that are low enough to determine compliance with effluent limits, when such methods are available. Facilities should not use a less sensitive or less appropriate method, thus masking the presence of a pollutant in the discharge, when an EPA-approved method is available that can quantify the pollutant concentration at the lower levels needed for demonstrating compliance. For purposes of the proposed anti-circumvention provision, a method is “sufficiently sensitive” when the sample-specific quantitation level
The Agency believes that the BMP requirements being considered by the Agency in this rulemaking and in the CCR rulemaking are critical to ensure that the owners and operators of surface impoundments become aware of any problems that may arise with the structural stability of the surface impoundment before they occur and, thus, prevent catastrophic releases, such as those that occurred at Martins Creek, Pennsylvania and TVA's Kingston, Tennessee facility.
The BMPs being considered by EPA in this rulemaking would require, first, that inspections be conducted every seven days by a person qualified to recognize specific signs of structural instability and other hazardous conditions by visual observation and, if applicable, to monitor instrumentation such as piezometers. If a potentially hazardous condition develops, the owner or operator shall immediately take action to eliminate the potentially hazardous condition; notify the Regional Administrator or the authorized State Director; and notify and prepare to evacuate, if necessary, all personnel from the property that may be affected by the potentially hazardous condition(s). Additionally, the owner or operator must notify state and local emergency response personnel if conditions warrant so that people living in the area down gradient from the surface impoundment can evacuate. Reports of inspections are to be maintained in the facility operating record.
Second, to address the integrity of surface impoundments, EPA would establish BMPs for CCR surface impoundments similar to those promulgated for coal slurry impoundments regulated by the Mine Safety and Health Administration (MSHA) at 30 CFR 77.216. Although the
In developing these possible structural integrity BMP requirements, EPA sought advice from the federal agencies charged with managing the safety of dams in the United States. Many agencies in the federal government are charged with dam safety, including the U.S. Department of Agriculture (USDA), the Department of Defense (DOD), the Department of Energy (DOE), the Nuclear Regulatory Commission (NRC), the Department of Interior (DOI), and the Department of Labor (DOL), MSHA. EPA looked particularly to MSHA, whose charge and jurisdiction appeared to EPA to be the most similar to the Agency's in this context. MSHA's jurisdiction extends to all dams used as part of an active mining operation and their regulations cover “water, sediment or slurry impoundments” so they include dams for waste disposal, freshwater supply, water treatment, and sediment control. In fact, MSHA's current impoundment regulations were created as a result of the dam failure at Buffalo Creek, West Virginia on February 26, 1972. (This failure released 138 million gallons of stormwater run-off and fine coal refuse, and resulted in 125 persons killed, another 1,000 injured, over 500 homes completely destroyed, and nearly 1,000 others damaged.)
MSHA has nearly 40 years of experience writing regulations and inspecting dams associated with coal mining. MSHA's regulations are comprehensive and directly applicable to the dams used in surface impoundments at coal-fired utilities to manage CCRs. EPA believes that, based on the record compiled by MSHA for its rulemaking, and on MSHA's 40 years of experience implementing these regulations, the requirements being considered in this rulemaking would substantially reduce the potential for catastrophic release of CCRs from surface impoundments, as occurred at TVA's facility in Kingston, Tennessee, and would generally meet RCRA's objective to ensure the protection of humans and the environment.
MSHA's regulations for coal slurry impoundments apply to those impoundments at coal mines, which impound water, sediment or slurry to an elevation of more than five feet and have a storage volume of 20 acre-feet or more and those coal slurry impoundments that impound water, sediment, or slurry to an elevation of 20 feet or more. The BMPs being considered today for the ELG rule would apply to all CCR impoundments at steam electric power generating facilities, regardless of height and storage volume. EPA is also considering variations on BMPs for the ELGs, including, but not limited to, different inspection frequencies or limitations on the applicability of BMPs that more closely mirror the applicability of the MSHA regulations. EPA requests comment on possible BMPs for inclusion in a final ELG rule including those described above and any other appropriate variations on them.
This voluntary program would establish two levels, or “tiers,” of advanced technology performance requirements which would be incorporated into the NPDES permits for the facilities that participate in the program. Under Tier 1, power plants would be granted two additional years (beyond the time described below in Section VIII.B) if they also dewater, close and cap all CCR surface impoundments (except for those impoundments containing only combustion residual leachate) at the facility, including those surface impoundments located on non-adjoining property that receive CCRs from the facility. A power plant participating in the Tier 1 program could continue to operate surface impoundments for which combustion residual leachate is the only type of CCR solids or wastewater contained in the impoundment. In general, power plants accepted in the Tier 1 incentives program would first convert ash handling operations to dry handling or closed-loop tank-based systems and FGD wastewater treatment operations to tank-based systems, as described above in Section VI. This first step would eliminate new contributions of CCRs (solids and wastewater) to the surface impoundments. The plants would then dewater the impoundments by draining
Under Tier 2, power plants would be granted five additional years (beyond the time described below in Section VIII.B) if they eliminate the discharge of all process wastewater to surface waters, with the exception of cooling water discharges. The Tier 2 incentives would not be available to power plants that eliminate direct discharge to surface water by sending the wastewater to a POTW. A plant accepted into the Tier 2 incentives program would ultimately need to manage its processes and wastewater in a manner that implements a coordinated approach toward wastewater minimization, treatment and reuse. To achieve Tier 2 status, these plants would eliminate all process wastewater discharges (except cooling water) by reducing the amount of wastewater generated and preferentially using recycled wastewater to meet water supply demands. To accomplish this, Tier 2 plants would conduct engineering assessments of the processes that generate wastewater and identify opportunities to eliminate or reduce the amount of wastewater they generate. These plants would also assess the processes that use water and determine how they could use recycled wastewater in those processes, as well as the degree of treatment that may be needed to enable such reuse. Based on responses to the industry survey, EPA has identified a number of steam electric power plants that currently discharge no process wastewater. In addition, two of the plants that EPA visited in Italy previously discharged process wastewater, but have implemented wastewater treatment and process changes, including wastewater recycle, that now allow them to operate without discharging any process wastewater except for their cooling water.
The primary objective of this program is to encourage individual power plants to install advanced pollution prevention technologies or make process changes that would further reduce releases of toxic pollutants to the environment beyond the limits that would be set by the proposed rule. The voluntary incentive program being considered is designed to promote improvements that, in concert with other environmental practices, make significant progress toward achieving EPA's vision of the “power plant of the future”—one which will have a minimum impact on the environment. This program would give power plants a platform to advance the research and development of technologies and processes that promote water conservation and water recycling and provide greater environmental protection. EPA has conducted site visits at power plants that have implemented processes that eliminate the use of water or recycle process wastewater to a substantial degree. Furthermore, as noted above, EPA observed operations at power plants that implemented process modifications and treatment technologies that eliminated all discharges of process wastewater with the exception of their cooling water. Implementing such practices at other power plants would dramatically reduce discharges of toxic and other pollutants. These practices would also substantially reduce the amount of water consumed or used by the plant, which could be an important consideration for addressing water availability and other concerns. In exchange for providing additional time for power plants to comply with the proposed BAT limitations, the program would lead to superior effluent quality and greater environmental protection.
Participation in the program would be voluntary and it would be available only to existing power plants that discharge directly to surface waters. Power plants would have until July 1, 2017 (approximately 3 years after promulgation of the final ELGs) to commit to the program and submit a plan for achieving the Tier 1 or Tier 2 requirements. Once a power plant enrolls in the program, the NPDES permitting authority would develop specific discharge limits and key milestones consistent with that tier.
Power plants enrolled in the program would ultimately be agreeing to adopt NPDES permit limits that are more stringent than those that would be required by the proposed and final BAT in exchange for additional time to comply with their new effluent limitations. These power plants and their corporate owners would also receive public recognition for their commitment to increased environmental protection.
EPA considered including features of the Tier 1 and Tier 2 incentives as part of the options for the proposed rule. However, although EPA has observed these practices in operation and they are available for at least a portion of the industry, the degree of complexity will vary from plant to plant and EPA does not have the site-specific information that could be used to sufficiently assess how that complexity may affect the engineering challenges and costs that plants would encounter. EPA requests comment on the voluntary incentives program described in this section and any appropriate variations.
BAT represents the best available economically achievable performance of facilities in an industrial subcategory or category taking into account factors specified in the CWA. The CWA factors considered in assessing BAT are the cost of achieving BAT effluent reductions, the age of equipment and facilities involved, the process employed, potential process changes, and non-water quality environmental impacts, including energy requirements and such other factors as the Administrator deems appropriate. See Section 304(b)(2)(B). In addition to technological availability, economic achievability is also a factor considered in setting BAT. See Section 301(b)(2)(A).
After considering all of the technologies described in Section VII.B.2, in light of the factors specified in Section 304(b)(2)(B) and Section 301(b)(2)(A) of the CWA, as appropriate, EPA is putting forth four preferred alternatives for BAT. These four preferred alternatives primarily differ in that some would establish more environmentally protective BAT requirements for discharges from two of the wastestreams from existing sources. Under the first preferred alternative, EPA is proposing to establish BAT effluent limits based on the technologies specified in Option 3a. With the exception of oil-fired generating units and small generating units (i.e., 50 MW or smaller), the proposed rule under Option 3a would:
• Establish a “zero discharge” effluent limit for all pollutants in fly ash transport water and FGMC wastewater;
• Establish numeric effluent limits for mercury, arsenic, selenium, and TDS in discharges of gasification wastewater;
• Establish numeric effluent limits for copper and iron in discharges of nonchemical metal cleaning wastes
• Establish BAT effluent limits for bottom ash transport water and
• BAT for discharges of FGD wastewater would continue to be determined on a site-specific basis.
Under the second preferred alternative for BAT, EPA is proposing to establish BAT effluent limits based on the technologies specified in Option 3b. With the exception of oil-fired generating units and small generating units (i.e., 50 MW or smaller), the proposed rule under Option 3b would:
• Establish numeric effluent limits for mercury, arsenic, selenium, and nitrate-nitrite in discharges of FGD wastewater for units located at plants with a total wet-scrubbed capacity of 2,000 MW or more
• Establish a “zero discharge” effluent limit for all pollutants in fly ash transport water and FGMC wastewater;
• Establish numeric effluent limits for mercury, arsenic, selenium, and TDS in discharges of gasification wastewater;
• Establish numeric effluent limits for copper and iron in discharges of nonchemical metal cleaning wastes
• Establish BAT effluent limits for bottom ash transport water and leachate that are equal to the current BPT effluent limits for these discharges (i.e., numeric effluent limits for TSS and oil and grease).
Under the third preferred alternative for BAT, EPA is proposing to establish BAT effluent limits based on the technologies specified in Option 3. In addition to the requirements described for Option 3b, the proposed rule would establish the same numeric effluent limits as in Option 3b for mercury, arsenic, selenium, and nitrate-nitrite in discharges of FGD wastewater from units located at all steam electric facilities, with the exception of oil-fired generating units and small generating units (i.e., 50 MW or less).
Under the fourth preferred alternative for BAT (Option 4a), in addition to the requirements described for Option 3, the proposed rule would establish “zero discharge” effluent limits for all pollutants in bottom ash transport water from units greater than 400 MW.
For oil-fired generating units and small generating units (i.e., 50 MW and smaller) that are existing sources, under all four preferred options, EPA is proposing to set the BAT effluent limits equal to the current BPT effluent limits for copper and iron for nonchemical metal cleaning wastes,
Under all of the preferred options, the technology basis for fly ash transport water is dry handling. All generating units built in the 30 years since the ELGs were last revised in 1982 have been subject to a zero discharge standard for the pollutants in fly ash transport water, in nearly all cases installing dry fly ash handling technologies to comply with the standard. In addition, many other generating units that could discharge their fly ash transport water upon meeting a TSS effluent limit have instead retrofitted the dry fly ash handling technology to meet operational needs or for economic reasons. Approximately 40 percent of the plants that were operating wet-sluicing systems in 2000 have converted generating units to dry fly ash (approximately 115 generating units at 45 power plants). Another 61 generating units are slated to convert to dry fly ash handling by 2020. Based on data collected by the industry survey, approximately 66 percent of coal- and petroleum coke-fired generating units handle all fly ash with dry technologies. Another 15 percent of coal- and petroleum coke-fired generating units have both wet and dry fly ash handling systems (typically, the wet system is a legacy system that the plant has not decommissioned following retrofit with a dry system). Only 19 percent of coal- and petroleum coke-fired generating units exclusively use a wet fly ash handling system. Furthermore, some of these plants with wet fly ash handling systems manage the ash handling process so that they do not discharge fly ash transport water. As a result, EPA determined that only 13 percent of coal-fired power plants would incur costs to comply with a BAT zero discharge requirement for fly ash transport water. See Section 9.7.3 of the TDD.
Power plants recently began installing FGMC systems either to comply with state requirements or to prepare for emissions limits established by the MATS rule. Plants using sorbent injection systems (e.g., activated carbon injection) typically handle the spent sorbent in the same manner as their fly ash. Nearly all plants with FGMC systems use dry handling technologies. Only a few plants use wet systems to transport the spent sorbent to disposal in surface impoundments. Based on the industry survey, the plants using wet handling systems currently operate them as closed-loop systems and do not discharge FGMC wastewater to surface waters, or have the capability to do so. These plants could continue to operate these wet systems as closed-loop systems, or could convert to dry handling technologies by managing the fly ash and spent sorbent together in a retrofitted dry system (the wastes are currently managed together in the impoundments) or by installing dedicated dry handling equipment for the FGMC wastes similar to the equipment used for fly ash.
The technology basis for control of discharges of FGD wastewater under Options 3, 3b (for units located at plants with a total wet-scrubbed capacity of 2,000 MW or more), and 4a is chemical precipitation followed by anaerobic biological treatment. Four power plants, or approximately three percent of wet-scrubbed power plants that discharge FGD wastewater already have the
The technology used as the basis for FGD wastewater treatment under Options 3b (for units at plants with a total wet-scrubbed capacity of 2,000 MW or more), 3 and 4a has been tested at power plants for more than 10 years and full-scale systems have been operating at a subset of plants for 5 years. The biological treatment processes used in the bioreactor portion of the treatment technology have been widely used in many industrial applications for decades both in the U.S. and internationally. Five steam electric power plants operate fixed-film anoxic/anaerobic biological treatment systems to treat FGD wastewater and another operates a suspended growth biological treatment system that targets removal of selenium.
More than one-third of plants that discharge FGD wastewater utilize chemical precipitation (in some cases, also using additional treatment steps). As noted above, four power plants currently operate chemical precipitation systems in combination with anaerobic biological treatment systems. The chemical precipitation treatment processes included in the FGD wastewater technology basis for these options are used at 24 percent of steam electric power plants that discharge FGD wastewater (and another 11 percent of plants also use chemical precipitation systems that could be upgraded to this technology basis) and also at thousands of industrial facilities nationwide (See Section 8.1.3 of the TDD).
Option 3b proposes limitations based on this technology for units at the largest plants (as determined by a 2,000 MW total wet-scrubbed capacity threshold), and BAT for the control of discharges of FGD wastewater from units at plants below this threshold would continue to be determined on a site-specific basis. For FGD wastewater only, EPA believes any threshold should be based on a plant level rather than a unit level because many plants currently use a single FGD treatment systems to service multiple units. Additionally, EPA determined that wet-scrubbed capacity is an appropriate metric because it only reflects units that are generating FGD wastewater. For example, a plant could have a total plant nameplate generating capacity of 3,500 MW, but only have a wet-scrubbed capacity of 200 MW if only one of its units is wet-scrubbed. EPA is putting forth this option as a preferred option based on an assumption that these facilities are more able to achieve these limits based on economies of scale. These largest facilities will likely also be able to absorb the costs of installing and operating the chemical precipitation and anaerobic biological treatment systems on which the FGD wastewater limitations are based. For these reasons, as well as those specified above related to current innovation and treatment trends, Option 3b proposes that BAT effluent limitations for discharges of FGD wastewater would continue to be determined on a site-specific basis for units at facilities below the 2,000 MW threshold. EPA solicits comment on the proposed 2,000 MW threshold applicable to discharges of FGD wastewater under Option 3b, including whether this or another threshold may be more appropriate.
The fourth preferred alternative for this proposed rule, Option 4a, in addition to the requirements that would be established under Option 3, would eliminate discharges of pollutants in bottom ash transport water from units greater than 400 MW. The technology basis for bottom ash for the zero discharge requirement is dry handling or a closed-loop system. Bottom ash transport water is one of the three largest sources for discharges of the pollutants of concern from steam electric power plants and these discharges occur at many power plants across the nation. Based on data collected by the industry survey, approximately 30 percent of coal-fired and petroleum coke-fired power plants handle bottom ash using technologies that do not generate any transport water. In addition, another 12 percent of coal- and petroleum coke-fired power plants manage the wet-sluicing bottom ash handling system as a closed-loop system that recirculates all bottom ash transport water so that it is not discharged. In addition, 83 percent of coal-fired generating units built in the last 20 years installed dry bottom ash handling systems.
EPA recognizes that the potential costs associated with compliance with a zero discharge standard for discharges of bottom ash transport water would be substantial if applied to all facilities (for example, approximately half of Option 4 costs and approximately a third of Option 5 costs), and, therefore, looked carefully at this wastestream with a particular focus on generating unit size. Our review demonstrated that, in the case of bottom ash transport water, units less than or equal to 400 MW are more likely to incur compliance costs that are disproportionately higher per MW than those incurred by larger units. For example, the average annualized cost of achieving zero discharge limits for bottom ash discharges (i.e. dry handling or closed loop) per MW for a 200 MW unit is more than three times higher than the average cost for a 400 MW unit. Based on the data from the industry survey, EPA estimates that 25 percent of coal-fired power plants would incur costs to comply with a BAT zero discharge requirement for bottom ash transport water from units greater than 400 MW.
Furthermore, while all plants, regardless of size, are capable of installing and operating dry handling or closed-loop systems for bottom ash transport water, and the costs would be affordable for most plants, EPA believes that companies may choose to shut down 400 MW and smaller units instead of making new investments to comply with proposed zero discharge bottom ash requirements. EPA is basing this belief on its review of units that facilities have announced will be retired or converted to non-coal based fuel sources. Of those units that plants have announced for retirement, and that also
Therefore, for the reasons specified above, for units less than or equal to 400 MW, Option 4a proposes to set the BAT effluent limits equal to the current BPT effluent limits based on surface impoundments. EPA solicits comment on the proposed 400 MW threshold applicable to discharges of bottom ash transport water under Option 4a, including whether this or another threshold may be more appropriate.
The two IGCC plants currently operating in the United States use the technology that is the basis for all four preferred options for gasification wastewater. A third IGCC plant that will soon begin commercial operation will also use the technology and, in addition to that, will also operate a cyanide destruction step as part of the treatment system.
For all four preferred options, the proposed BAT limits for copper and iron in discharges of nonchemical metal cleaning waste are equal to the current BPT effluent limits for these pollutants in metal cleaning waste. These effluent limits are based on the same technology that was used as the basis for the current ELG BPT requirements for metal cleaning waste (i.e., chemical precipitation).
Discharges of metal cleaning wastes that are generated from cleaning metal process equipment without chemical cleaning compounds (i.e., nonchemical metal cleaning waste) are already subject to BPT effluent limits for copper and iron equal to the BAT effluent limits being proposed today. Based on responses to the industry survey, facilities typically treat both chemical and nonchemical metal cleaning waste in similar fashion.
Since, as described above, nonchemical metal cleaning waste is included within the definition of metal cleaning waste, and copper and iron are already regulated under metal cleaning wastes, EPA would be establishing BAT limits equal to the BPT limits (for copper and iron) that already apply to these wastes. As a result, facilities should incur no cost to comply with the proposed BAT for these wastes. However, EPA recognizes that previous guidance provided after the final 1974 regulation stated that wastes from metal cleaning with water are considered “low volume” wastes. The extent to which this statement was relied upon is unclear, and EPA rejected the guidance in the 1982 rulemaking for the steam electric ELGs (47 FR 52297). However, because permitting authorities and others may have relied on this guidance and the potential costs to those facilities are not known, EPA is proposing to exempt from any new copper and iron BAT requirements those discharges of nonchemical metal cleaning waste to which this guidance was applied in the past. In other words, EPA is proposing to exempt from proposed new copper and iron BAT limitations those discharges of nonchemical metal cleaning wastes from generating units that are currently authorized to discharge nonchemical metal cleaning wastes without copper and iron limits pursuant to existing BPT requirements for metal cleaning waste. For such discharges, EPA is proposing to set BAT limitations equal to BPT limitations for low volume waste.
To get a better understanding of how discharges of nonchemical metal cleaning wastes are currently permitted, EPA's regional offices recently reviewed 45 permits for plants that EPA had reason to believe generated nonchemical metal cleaning waste based on responses to the industry survey. For these permits, EPA determined the following based on the review:
• 64 percent of the plants are either zero discharge of metal cleaning wastes or have to comply with copper and iron limits;
• 27 percent of plants do not have to comply with copper and iron limits; and
• 9 percent of plant permits do not include enough information to determine whether the plant would be in compliance with the proposed BAT limitations.
In order to implement the exemption proposed today for certain discharges of nonchemical metal cleaning waste that have historically been treated as low volume wastes and not subject to copper and iron limits under metal cleaning waste BPT requirements, EPA's current thinking is to develop a specific list of generating units eligible for the exemption. Therefore, EPA is seeking to identify those generating units that should be eligible for the exemption through the public comment process on this rulemaking. To qualify for the proposed exemption, the generating unit must meet all three of the following criteria:
• The generating unit must currently generate nonchemical metal cleaning wastes;
• The generating unit must discharge the nonchemical metal cleaning waste; and
• The generating unit must be located at a plant that is authorized to discharge the nonchemical metal cleaning waste without limitations for copper and iron.
EPA is also considering setting BAT limitations equal to BPT limitations applicable to metal cleaning waste for all discharges of nonchemical metal cleaning wastes (i.e., not creating an exemption from copper and iron limits for discharges of nonchemical metal cleaning wastes from generating units currently authorized to discharge those wastes without copper and iron limits). As part of this approach, EPA is evaluating whether plants would incur costs to comply with the current BPT requirements applicable to discharge of metal cleaning wastes. Therefore, EPA is also soliciting comments that provide information on those generating units that are not currently subject to the BPT metal cleaning waste limitations for copper and iron, in order to understand what actions would be required to comply with the proposed BAT nonchemical metal cleaning waste limitations for iron and copper. EPA is
• Type of nonchemical metal cleaning waste generated, frequency of generation, and volume generated;
• Wastewater characterization data (i.e., monitoring data) for the nonchemical metal cleaning waste;
• Information regarding the actions that would need to be taken to comply with the iron and copper limits for the nonchemical metal cleaning wastes discharged; and
• Estimated capital and operating and maintenance costs, broken out by specific cost components (e.g., equipment costs, installation costs, labor costs), to comply with the proposed copper and iron limits, along with the basis for the cost estimate.
EPA's analysis to date suggests that all four preferred options, Option 3a, Option 3b, Option 3, and Option 4a, are economically achievable. EPA performed cost and economic impact assessments using the Integrated Planning Model (IPM) for Option 3 and Option 4.
For the options analyzed overall, the model showed very small effects on the electricity market, on both a national and regional sub-market basis. Based on the results of these analyses, EPA estimates that the proposed requirements associated with Option 3a, Option 3b, and Option 3 would not lead to the premature retirement of any steam electric generating units (i.e., no partial or full plant closures).
The results for Option 4 show fourteen unit (partial) closures and zero plant (full) closures projected as of the model year 2030, reflecting full compliance of all facilities.
As part of its consideration of technological availability and economic achievability, EPA also considered the magnitude and complexity of process changes and new equipment installations that would be required at facilities to meet the requirements of the rule. As described in greater detail in Section XVI, EPA is proposing that, where the limitations and standards being proposed today for existing direct and indirect dischargers are more stringent than existing BPT requirements, those limitations and standards do not begin to apply until July 1, 2017 (approximately three years following promulgation of the final rule). EPA is proposing this approach to provide the time that many facilities will need to raise capital, plan and design systems, procure equipment, and construct and then test systems. Moreover, this approach will enable facilities to take advantage of planned shutdown or maintenance periods to install new pollution control technologies. EPA's proposal is designed to minimize any potential impacts on electricity availability caused by forced outages.
Options 3a, 3b, 3 and 4a have acceptable non-water quality environmental impacts, as discussed in Section XV of the preamble and in the TDD. EPA estimates that Options 3a, 3b, 3, and 4a would increase energy consumption by less than 0.003 percent, less than 0.004 percent, less than 0.008 percent, and less than 0.012 percent, respectively, of the total electricity generated by power plants. EPA also estimates that Options 3a, 3b, 3, and 4a would increase the amount of fuel consumed by increased operation of motor vehicles (e.g., for transporting fly ash) by less than 0.009 percent, less than 0.009 percent, less than 0.009 percent, and less than 0.014 percent, respectively, of total fuel consumption by all motor vehicles.
As discussed in Section XV.B., EPA also evaluated the effect of the proposed rule on air emissions generated by power plants (NO
EPA also evaluated the effect of the proposed rule on solid waste generation and water usage. There would be no increase in solid waste generation under Option 3a, and EPA estimates that solid waste generation at power plants will increase by less than 0.001 percent under the other three preferred options. EPA estimates the power plants would reduce water use by 50 billion gallons per year (136 million gallons per day) under Option 3a, 52 billion gallons per year (143 million gallons per day) under Option 3b, 53 billion gallons per year (144 million gallons per day) under Option 3, and 103 billion gallons per year (282 million gallons per day) under Option 4a.
EPA also examined the effects of the preferred options on consumers as an “other factor” that might be appropriate when considering what level of control represents BAT. If all compliance costs were passed on to residential consumers of electricity instead of being borne by the operators and owners of power plants, the monthly increase in electricity bill would be no more than $0.04, $0.06, $0.13, and $0.22, respectively under Options 3a, 3b, 3, and 4a.
EPA is not proposing either Option 1 or Option 2 as its preferred option for BAT because neither option would represent the best available technology level of control for steam electric power plant discharges. For example, Options 1 and 2 would allow plants to continue
EPA did not select Option 4 as its preferred regulatory option because of concerns expressed above associated with the projected compliance costs associated with zero discharge requirements for bottom ash for units equal to or below 400 MW. The bottom ash requirements for Option 4 and the preferred Option 4a are the same with the exception that Option 4a proposes to set the BAT effluent limits for bottom ash transport water equal to the current BPT effluent limits for units less than or equal to 400 MW, while Option 4 would set the BAT effluent limits for bottom ash transport water equal to the BPT effluent limits for units less than or equal to 50 MW. All other units would be subject to “zero discharge” effluent limits for all pollutants in bottom ash transport water.
Moreover, Option 4 proposes to establish BAT discharge limitations for toxic discharges for leachate. The record demonstrates that the amount of pollutants collectively discharged in leachate by steam electric plants is a very small portion of the pollutants discharged collectively for all steam electric power plants (i.e., less than
EPA did not select Option 5 as its preferred option for BAT because of the high total industry cost for the option ($2.3 billion/year annualized social cost) and because of preliminary indications that Option 5 may not be economically achievable. While EPA has traditionally looked at affordability of the rule to the regulated industry, EPA has in some limited instances over the past three decades rejected an option primarily on the basis of total industry costs. See 48 FR 32462, 32468 (July 15, 1983) (Final Rule establishing ELGs for the Electroplating and Metal Finishing Point Source Categories); 74 FR 62996, 63026 (Dec. 1, 2009) (Final Rule establishing ELGs for the Construction and Development Point Source Category);
For the reasons described below in Section VIII.B., EPA is proposing that, where the limitations and standards being proposed today are more stringent than existing BPT requirements, those limitations and standards do not begin to apply until July 1, 2017 (approximately three years from the effective date of this rule).
For all eight of the main BAT options under consideration, EPA is proposing to establish effluent limits for oil-fired generating units and small generating units (i.e., 50 MW or less) that differ from the effluent limits for all other generating units.
In addition, EPA has identified some differences among the options in terms of cost effectiveness. Section XII of this preamble describes EPA's cost-effectiveness analysis for the preferred regulatory options. EPA's analysis to date shows that the average cost effectiveness ($1981/TWPE) under Option 3a, 3b, 3, and 4a for existing direct dischargers is $27, $31, $44, and $57, respectively. This demonstrates that Option 3a is the most cost effective of the preferred options, Option 4a is the least cost effective of the preferred options, and Option 3 and Option 3b are between the two.
EPA also calculated the cost-effectiveness of particular controls for the wastestreams that would be controlled under the preferred options for existing direct dischargers.
Thus, the cost effectiveness for control of the various wastestreams included within the preferred options ranges from $27–$107 per TWPE in $1981; with zero discharge controls on fly ash transport wastewater being the most cost-effective, zero discharge controls on bottom ash transport wastewater being the least cost effective, and controls for FGD wastewater based on chemical precipitation in combination with anaerobic biological treatment between the two.
The amount of ash generated at oil-fired units is a small fraction of the amount produced by coal-fired units. Coal-fired units generate hundreds or thousands of tons of ash each day, with some plants generating more than 1,500 tons per day of ash. In contrast, oil-fired units generate less than one ton of ash per day. This disparity is also apparent when comparing the ash tonnage to the amount of power generated, with coal-fired units producing nearly 300 times more ash than oil-fired units (0.04 tons per MW-hour on average for coal units; 0.000145 tons per MW-hour on average for oil units). The amount of pollutants discharged to surface waters is roughly correlated to the amount of ash wastewater discharged, thus oil-fired units discharge substantially less pollutants to surface waters than a coal-fired unit even when generating the same amount of electricity. EPA estimates that if BAT effluent limits for oil-fired units were set equal to either the proposed Option 3 or Option 4a limits for coal-fired units (>50 MW), the total industry pollutant reductions attributable to the proposed rule would increase by less than one percent.
Oil-fired units are generally among the oldest steam electric units in the industry. Eighty-seven percent of the units are more than 25 years old. In fact, more than a quarter of the units began operation more than 50 years ago. Based on responses to the industry survey, only 20 percent of oil-fired units operate as baseload units; the rest are either cycling/intermediate units (45 percent) or peaking units (35 percent). These units also have notably low capacity utilization. While a quarter of the baseload units report capacity utilization greater than 75 percent, most baseload units (60 percent) report a capacity utilization of less than 25 percent. Eighty percent of the cycling/intermediate units and all peaking units also report capacity utilization less than 25 percent. Thirty-five percent of oil-fired units operated for more than six months in 2009; nearly half of the units operated for less than 30 days.
As shown above, oil-fired units are generally older and operate intermittently (i.e., they are peaking, cycling, or intermediate units). While these oil-fired units are capable of installing and operating the treatment technologies evaluated as part of this rulemaking, and the costs would be affordable for most of the plants, EPA believes that, due to the factors described here, companies may choose to shut down these oil-fired units instead of making new investments to comply with the rule. If these units shut down, it could reduce the flexibility that grid operators have during peak demand because there would be less reserve generating capacity to draw upon. But more importantly, maintaining a diverse fleet of generating units that includes a variety of fuel sources is vital to the nation's energy security. Because the supply/delivery network for oil is different from other fuel sources, maintaining the existence of oil-fired generating units helps ensure reliable electric power generation. Thus, the oil-fired generating units add substantially to electric grid reliability and the nation's energy security.
Based on responses to the industry survey, EPA estimates that less than 20 oil-fired units discharged fly ash or bottom ash transport water in 2009. At the same time, EPA notes that many oil-fired units operate infrequently, which could contribute to the relatively low numbers of units discharging ash-related wastewater. Should more widespread operation of oil units be required to meet demands of the electric grid, additional plants may find it necessary to discharge ash transport water. Because of the operating conditions unique to the existing fleet of oil-fired units and potential effects on the nation's electric power grid, a non-water quality environmental impact that EPA considers under Section 304(b) of the CWA, EPA believes it is appropriate to set BAT effluent limits for oil-fired equal to the current BPT limits.
Moreover, the record demonstrates that the amount of pollutants collectively discharged by small generating units is a very small portion of the pollutants discharged collectively for all steam electric power plants (e.g., less than 1 percent under Option 3). As a result, setting BAT limits equal to BPT for existing steam electric generating units with a capacity of 50 MW or less will have little impact on the pollutant removals for the overall rule.
EPA considered establishing the size thresholds for small generating units at 25 MW because that threshold is already used for this industry sector in some regulatory contexts. For example, the Clean Air act defines an “electric utility generating unit” as “any fossil fuel fired combustion unit of more than 25 megawatts that serves a generator that produces electricity for sale.” CAA Section 112(a)(8), 42 U.S.C. 7412(a)(8). The existing ELGs for the steam electric power generating point source category also include different effluent limitations for plants with total rated generating capacity of less than 25 MW. See 40 CFR 423.13(c)(1) and 423.15(i)(1).
EPA currently proposes a threshold of 50 MW
Section 306 of the CWA directs EPA to promulgate New Source Performance Standards, or NSPS, “for the control of the discharge of pollutants which reflects the greatest degree of effluent reduction which the Administrator determines to be achievable through application of the best available demonstrated control technology, processes, operating methods, or other alternatives, including, where practicable, a standard permitting no discharge of pollutants.” Congress envisioned that new sources could meet tighter controls than existing sources because of the opportunity to incorporate the most efficient processes and treatment systems into the facility design. As a result, NSPS should represent the most stringent controls attainable through the application of the best available demonstrated control technology, or BADCT, for all pollutants (that is, conventional, nonconventional, and priority pollutants).
After considering all of the technology options described above in Section VII.B.2, EPA is proposing to establish NSPS based on the suite of technologies identified for Option 4 in Table VIII–1. Thus, the proposed NSPS would do the following:
• Establish numeric effluent limits for mercury, arsenic, selenium, and nitrate-nitrite in discharges of FGD wastewater;
• Maintain the current “zero discharge” effluent limit for all pollutants in fly ash transport water, and establish new “zero discharge” effluent limits for all pollutants in bottom ash transport water and FGMC wastewater;
• Establish numeric effluent limits for mercury, arsenic, selenium, and TDS in discharges of gasification wastewater;
• Establish numeric effluent limits for TSS, oil and grease, copper, and iron in discharges of nonchemical metal cleaning wastes; and
• Establish numeric effluent limits for mercury and arsenic in discharges of leachate.
The record indicates that the proposed NSPS is technologically available and demonstrated. The technologies that serve as the basis for Option 4 are all available based on the performance of plants using components of the suite of technologies within the past decade. For example, approximately a third of plants that discharge FGD wastewater utilize chemical precipitation (in some cases, also using additional treatment steps). Five plants operate fixed-film anoxic/anaerobic biological treatment systems for the treatment of FGD wastewater and another operates a suspended growth biological treatment system that targets removal of selenium.
The proposed NSPS for discharges of nonchemical metal cleaning waste are equal to the current BPT effluent limits that apply to discharges of these wastes from existing sources. As such, the proposed NSPS would be consistent with current industry practice for treating nonchemical metal cleaning waste and is based on the same technology that was used as the basis for the current NSPS for chemical metal cleaning waste. Based on responses to the industry survey, facilities typically treat both chemical and nonchemical metal cleaning waste in similar fashion.
The NSPS being proposed today also poses no barrier to entry. The cost to install technologies at new units are typically less than the cost to retrofit existing units. For example, the cost differential between BAT Options 3 and 4 for existing sources is mostly associated with retrofitting controls for bottom ash handling systems. For existing generating units, the effluent requirements considered under Option 4a for BAT would cause those plants with units greater than 400 MW that discharge bottom ash wastewater to either modify their processes to become a closed-loop wet sluicing system, or retrofit modifications such as replacing the bottom of boilers to accommodate mechanical drag chain systems. For new sources, however, Option 4 would not present plants with the same choice of retrofit versus modification of existing processes. This is because every new generating unit already has to install some type of bottom ash handling system as the unit is constructed. Establishing a zero discharge standard for pollutants in bottom ash transport water as part of the NSPS means that power plants will install a dry bottom ash handling system during construction instead of installing a wet-sluicing system. EPA estimates that over the past 20 years, more than 50 new coal-fired generating units were built and that most of these units (83 percent) installed dry bottom ash handling systems.
Moreover, as described above in Section XI, EPA assessed the possible impacts of Option 4 to new units by comparing the costs of the Option 4 technologies to the costs of a new generating unit and as part of its Integrated Planning Model analyses. In both cases, the results show that the incremental costs that would be imposed by Option 4 do not present a barrier to entry. EPA estimated that the compliance costs for a new unit (capital and O&M) represent at most 1.5 percent of the annualized cost of building and operating a new 1,300 MW coal-fired plant, with capital costs representing less than 1 percent of the overnight construction costs, and annual O&M costs representing less than 5 percent of the cost of operating a new plant. IPM results show no barrier to new generation capacity during the model years in which all existing plants must be in compliance as a result of the BAT/NSPS compliance scenario.
Finally, EPA has analyzed non-water quality environmental impacts associated with Option 4 for existing sources, and its analysis is relevant to the consideration of non-water quality environmental impacts associated with Option 4 for new sources. EPA's analysis demonstrates that the non-water quality environmental impacts associated with Option 4 for existing sources are acceptable. Given that there is nothing inherent about a new unit that would alter the analysis for such sources, EPA believes that the non-water quality environmental impacts associated with the proposed NSPS regulatory option are, likewise, acceptable.
In contrast to the best available technology economically achievable, or BAT, that EPA is proposing today for existing sources, the proposed NSPS would establish the same limits for oil-fired generating units and small generating units
EPA is not proposing regulatory Options 1 or 2, which would establish new effluent limits for only two of the seven key wastestreams addressed by this proposed rule, as its preferred option for NSPS. As explained above, neither of these two options represents the greatest degree of effluent reduction which the Administrator determines to be achievable through the best available demonstrated control technology.
EPA also did not select any of the preferred BAT regulatory Options (i.e., Options 3a, 3b, 3, or 4a) as its preferred option for NSPS because they would not control FGD wastewater (Option 3a and Option 3b for units at plants with a total wet-scrubbed capacity of less than 2,000 MW), bottom ash transport water (Option 3a, Option 3b, Option 3, and Option 4a for units less than or equal to 400 MW) or leachate discharges (Options 3a, 3b, 3, and 4a) and other, more effective, available technologies exist that do not present a barrier to entry and have acceptable non-water quality environmental impacts. EPA did not select preferred Option 3a for the same reasons it rejected Options 1 and 2. EPA did not select Options 3b, 3, or 4a because, under these regulatory options, NSPS effluent limits for bottom ash transport water for all or some portion of units and leachate would be set equal to the current BAT effluent limits on TSS and oil and grease, which are based on using surface impoundments.
EPA did not select Option 5 as its preferred option for NSPS because of its high costs, which are substantially higher than the costs for Option 4 and the other options evaluated for NSPS. See the TDD and RIA for more information about the estimated
Finally, EPA notes that Option 5 is comparable to Option 4 with respect to much of the anticipated pollutant removals, particularly the expected removals of arsenic, mercury, selenium and nitrogen. At the same time, Option 5 would control other pollutants in FGD wastewater that Options 1 through 4 do not effectively control, namely boron, bromides, and TDS. EPA is aware that bromide in wastewater discharges from steam electric power plants located upstream from a drinking water intake has been associated with the formation of trihalomethanes, also known as THMs, when it is exposed to disinfectant processes in water treatment plants. EPA recommends that permitting authorities consider the potential for bromide discharges to adversely impact drinking water intakes when determining whether additional water quality-based effluent limits may be warranted. Although EPA did not select Option 5 as the preferred NSPS option, the technologies forming the basis for Option 5 are all technologically available and may be appropriate (individually or in totality) as the basis for water quality-based effluent limits in individual or general permits depending on site-specific conditions. EPA requests comment on its selection of Option 4 instead of Option 5 as the basis for NSPS.
Section 307(b), 33 U.S.C. 1317(b), of the Clean Water Act requires EPA to promulgate pretreatment standards for pollutants that are not susceptible to treatment by POTWs or which would interfere with the operation of POTWs. EPA looks at a number of factors in selecting the technology basis for pretreatment standards. For existing sources, these factors are generally the same as those considered in establishing BAT. However, unlike direct dischargers whose wastewater will receive no further treatment once it leaves the facility, indirect dischargers send their wastewater to POTWs for further treatment. As such, EPA must also determine that a pollutant is not susceptible to treatment at a POTW or would interfere with POTW operations.
Table VIII–3 summarizes the pass through analysis results for the BAT/NSPS pollutants for the various wastestreams and regulatory options. As shown in the table, all of the pollutants proposed for regulation under BAT/NSPS pass through.
For this proposal, EPA evaluated the same model technologies and regulatory options for PSES that it evaluated for BAT (described in Section VIII.A.2). These standards would apply to existing generating units that discharge wastewater to POTWs.
As explained above in Section III.B.5, in selecting the PSES technology basis, the Agency generally considers the same factors as it considers when setting BAT, including economic achievability. Typically, the result is that the PSES technology basis is the same as the BAT technology basis. This proposal is no exception. After considering all of the technology options described in Section VIII.A.2, as is the case for BAT, EPA is proposing four preferred alternatives for PSES (i.e., Options 3a, 3b, 3, and 4a).
With the exception of oil-fired generating units and small generating units (i.e., 50 MW or smaller), the proposed rule under Option 3a would:
• Establish a “zero discharge” effluent limit for all pollutants in fly ash transport water and FGMC wastewater;
• Establish numeric effluent limits for mercury, arsenic, selenium, and TDS in discharges of gasification wastewater;
• Establish numeric effluent limits for copper in discharges of nonchemical metal cleaning wastes;
• Establish BAT effluent limits for bottom ash transport water and leachate that are equal to the current BPT effluent limits for these discharges (i.e., numeric effluent limits for TSS and oil and grease).
With the exception of oil-fired generating units and small generating units (i.e., 50 MW or smaller), the proposed PSES under Option 3b would:
• Establish standards for mercury, arsenic, selenium, and nitrate-nitrite in discharges of FGD wastewater for units located at plants with a total wet-scrubbed capacity of 2,000 MW;
• Establish a “zero discharge” standard for all pollutants in fly ash transport water and FGMC wastewater;
• Establish standards for copper in discharges of nonchemical metal cleaning wastes;
• Establish standards for mercury, arsenic, selenium and TDS in discharges of gasification wastewater.
Under the third preferred alternative for PSES (Option 3), in addition to the requirements described for Option 3b, the proposed rule would establish the same standards for mercury, arsenic, selenium, and nitrate-nitrite in discharges of FGD wastewater as for Option 3b from units at all steam electric facilities, with the exception of oil-fired generating units and small generating units (i.e., 50 MW or smaller).
Under the fourth preferred alternative for PSES (Option 4a), the proposed rule would establish “zero discharge” effluent limits for all pollutants in bottom ash transport water for units greater than 400 MW. All other proposed Option 4a requirements are identical to the proposed Option 3 requirements.
EPA is putting forth Options 3a, 3b, 3, and 4a as the Agency's preferred PSES regulatory options in order to confirm its understanding of the pros and cons of these options through the public comment process and intends to evaluate this information and how it relates to the factors specified in the CWA. For the same reasons identified in Section VIII.A.3 above for BAT, EPA's analysis to date suggests that for indirect dischargers as well as direct dischargers, the Option 3a, Option 3b, Option 3, and Option 4a technologies are available and economically achievable, and that the other regulatory options (Options 1, 2, 4, and 5) do not reflect the criteria for PSES. In addition, EPA has determined that these standards will prevent pass-through of pollutants from POTWs into receiving streams and also help control contamination of POTW sludge. EPA also considered the non-water quality environmental impacts and found them to be acceptable, as described in Section XV. Furthermore, for the same reasons that apply to EPA's preferred BAT options and described in Section VIII.A.3, with the exception of numeric standards for copper in discharges of nonchemical metal cleaning wastes,
Finally, similar to EPA's preferred BAT options and for the reasons supporting those options, for certain wastestreams, EPA is proposing that any new PSES discharge standards would apply to discharges of the regulated wastewater generated after July 1, 2017. See discussion in Section XVI.
Section 307(c) of the CWA, 33 U.S.C. 1317(c), authorizes EPA to promulgate pretreatment standards for new sources (PSNS) at the same time it promulgates new source performance standards (NSPS). As is the case for PSES, PSNS are designed to prevent the discharge of any pollutant into a POTW that may interfere with, pass through, or may otherwise be incompatible with POTWs. In selecting the PSNS technology basis, the Agency generally considers the same factors it considers in establishing NSPS along with the results of a pass through analysis. As a result, EPA typically promulgates pretreatment standards for new sources based on best available demonstrated technology for new sources.
For this proposal, EPA evaluated the same model technologies and regulatory options for PSNS that it evaluated for NSPS (described above in Section VIII.A.4). These standards would apply to new generating units or new facilities that discharge wastewater to POTWs. After considering all of the technology options described in Section VIII.A.2, as is the case for NSPS, EPA is proposing to establish PSNS based on the technologies specified in Option 4. The proposed PSNS would:
• Establish standards for mercury, arsenic, selenium, and nitrate-nitrite in discharges of FGD wastewater;
• Maintain a “zero discharge” standard for all pollutants in fly ash transport water, and establish a zero discharge standard for bottom ash transport water and FGMC wastewater;
• Establish standards for mercury, arsenic, selenium and TDS in discharges of gasification wastewater;
• Establish standards for copper in discharges of nonchemical metal cleaning wastes; and
• Establish standards for mercury and arsenic in discharges of leachate.
For the same reasons identified for NSPS in Section VIII.A.4, EPA is proposing Option 4 as its preferred option because the technologies forming the basis for that option are available and demonstrated and will not pose a barrier to entry.
As explained earlier, implementation of air pollution controls may create new wastewater streams at power plants. The analyses and the findings on economic achievability presented in this preamble reflect consideration of wastestreams generated by air pollution controls that will likely be in operation at plants at the time EPA takes final action on this rulemaking. However, EPA recognizes that some recently promulgated Clean Air Act requirements, along with state requirements or enforcement actions, may lead to additional air pollution controls (and resulting wastestreams) at existing plants beyond this date. In an effort to assess the economic achievability of the proposed rule in such cases, EPA also conducted a sensitivity analysis that forecasts future installations of air controls through 2020
EPA has two primary data sources upon which to make its projections of future air control installations: 1) Integrated Planning Model estimates for the final MATS rule;
As a first step in conducting a sensitivity analysis, EPA compared the projections from the two sources described above. This comparison demonstrates that the IPM results for the MATS Policy Case and the ELG industry survey responses are consistent at the aggregate level. Furthermore, in very large part, both the survey and IPM identify the same generating units as being wet-scrubbed, either currently or in the future (the two sources are in agreement for approximately 94 percent of the wet-scrubbed units). The two sources also project similar wet-scrubbed capacities. In the very few cases where there are differences between the two sources, the differences are primarily due to the expected variation at a unit-level (e.g., IPM projects wet FGD at unit A and dry FGD at unit B, but instead the survey responses report wet FGD at unit B and dry FGD at unit A). Another difference between the MATS IPM estimates and the industry survey estimates is that, in a very few cases, the IPM results estimate that certain plants would retire (and therefore would not install wet scrubbers). In conducting the analyses for the ELG, EPA made the conservative assumption (i.e., one that would tend to overestimate cost, if anything) that a plant would still be in operation in 2020 unless the plant has formally announced its closure by 2014.
Because its goal in conducting this sensitivity analysis was to assess the economic achievability of the proposed ELG, even in light of possible future air controls, EPA developed a conservative upper bound estimate of future installations by combining the results of the two sources to develop its “future steam profile.” In other words, EPA combined any source that reported or projected a wet FGD into one “future steam profile.” This “future steam profile” is conservative because it reflects more wet FGDs than are anticipated to actually be installed; that is, by aggregating the survey and IPM forecast estimates it results in a total number of wet FGD systems and wet-scrubbed capacity that is greater than either of those individual sources. EPA then added costs associated with projected wastewater discharges from this future steam profile to comply with this proposal to the total costs it previously calculated for the existing universe. Based on the results of this conservative analysis, EPA finds that discharges from these additional air controls (which, if actually installed, would be due to various requirements including state rules, consent decrees, CSAPR/CAIR, and MATS) may increase the costs of this proposed rule by no more than 10 to 15 percent. See discussion in Section VII.A.7. Even if all of these additional costs were to come to fruition, which is unlikely since the “future steam profile” overestimates the number of new wet FGD systems that are anticipated, EPA finds that these additional costs are economically achievable.
EPA notes that subsequent to its analysis, the D.C. Circuit Court of Appeals vacated the CSAPR. EPA will continue to assess the potential impacts that changes to air pollution regulations may have on future installations of wet FGD systems. For the purpose of FGD wastewater analyses for this rulemaking, EPA has made a conservative assumption that all of the previously projected wet scrubber additions in the CSAPR-inclusive baseline (which also included MATS, state rules, consent decrees, etc.) would continue to be built, and that discharges from those additional wet scrubbers would therefore be subject to the proposed revisions to the ELGs.
As part of its consideration of technological availability and economic achievability, EPA considered the magnitude and complexity of process changes and new equipment installations that would be required at many existing facilities to meet the requirements of the rule. As discussed in Section VIII.A.2, EPA proposes that certain BAT limitations for existing sources being proposed today (those that would establish requirements more stringent than existing BPT requirements) would apply on a date determined by the permitting authority that is as soon as possible when the next permit is issued beginning July 1, 2017 (approximately three years from the effective date of this rule). This is true of the proposed limitations and standards based on any of the eight main regulatory options, including the preferred options, Option 3a, Option 3b, Option 3, or Option 4a.
EPA is proposing this approach for several practical reasons. While some facilities already have the necessary equipment and processes in place, or could do so relatively quickly, and may need little time before they are able to comply with the revised ELG requirements, not all will be able to do so. Some facilities will need time to raise the capital, plan and design the system, procure equipment, construct and then test the system. Moreover, providing a window of time will better enable facilities to install the pollution control technology during an otherwise
During site visits, EPA found that most facilities need several years to plan, design, contract, and install major system modifications, especially if they are to be accomplished during planned maintenance periods to avoid causing forced outages. EPA recognizes that the proposed rule would require a significant amount of system design by engineering firms, equipment procurement from vendors, and installation by trained labor forces. EPA anticipates that changes to FGD wastewater treatment systems, fly ash system, bottom ash systems, and/or leachate treatment systems would constitute major system modifications requiring several years to accomplish for many plants. EPA identified certain technical and logistical issues at some facilities that may warrant additional time, such as coordinating ash system conversions for multiple generating units. In order to avoid any impacts on the consistency and reliability of power generation, outages at multiple facilities in one geographic area would need to be coordinated, which could also result in the need for more time.
EPA recognizes that permitting authorities have discretion with respect to when to reissue permits and can take into consideration the need to provide additional time to include BAT limits to prevent or minimize forced outages. Thus, in some cases, the new BAT requirements may as a practical matter be applied to a facility sometime after July 1, 2017. However, EPA judges that, under this proposed approach, all steam electric facilities will have the proposed BAT limitations applied to their permits no later than July 1, 2022, approximately 8 years from the date of promulgation of any final ELGs. For indirect discharges, except with respect to discharges of nonchemical metal cleaning waste, the proposed PSES requirements would apply by the date determined by the control authority that is as soon as possible beginning July 1, 2017, or approximately three years after promulgation of any final ELGs. EPA's record indicates it may not take that long for all facilities to meet the limitations and standards. Some plants may not require a major modification for one or more systems to be able to comply with new effluent limits and therefore would need less time. For example, some plants have installed dry fly ash handling systems that have capacity to handle all generated ash dry, yet they also maintain a wet ash handling system as a backup. The backup wet system is typically operated only a few days per year. According to the industry survey, plants such as these could quickly cease operation of the wet system, complying with a zero discharge requirement with relative ease.
EPA envisions that each facility subject to this proposal would study available technologies and operational measures, and subsequently install, incorporate and optimize the technology most appropriate for each site. EPA believes the proposed rule affords flexibility for a reasonable amount of time to conduct engineering studies, assess and select appropriate technologies, apply for necessary permits, complete construction, and optimize the technologies' performance. The permitting authority could establish any additional interim milestones, as appropriate, within these timelines.
This section provides an overview of EPA's approach for estimating the compliance costs and pollutant reductions associated with the regulatory options discussed in this proposal. Sections 9 and 10 of the TDD provide a much more in depth discussion of these analyses.
EPA often estimates costs and pollutant loads on a per plant basis and then sums or otherwise escalates the plant-specific values to represent industry-wide compliance costs and pollutant reductions. Calculating costs and loads on a per plant basis allows EPA to account for differences in plant characteristics such as types of processes used, wastewaters generated and their flows/volumes and characteristics, and wastewater controls in place (e.g., BMPs and end-of-pipe treatment). EPA took this approach in estimating the compliance costs and pollutant reductions associated with this proposed rule.
EPA estimated the costs to steam electric power plants—whose primary business is electric power generation or related electric power services—of complying with the proposed ELGs. EPA evaluated the costs of this proposal on all plants currently subject to the existing ELGs. Some aspects of this proposal (e.g., applicability changes) would likely not lead to increased costs to complying facilities. Other aspects of this proposal would likely lead to increased costs to a subset of complying facilities. These facilities are generally those that generate and discharge the wastestreams for which EPA is proposing new limitations or standards. EPA reviewed the steam electric industry for all facilities that generate the specific types of wastewater streams for which EPA evaluated additional limitations or standards. The following describes the detailed costing and loadings evaluation EPA performed for these plants.
As discussed earlier in this preamble, EPA proposes to establish a separate set of requirements for existing oil-fired generating units and units with a capacity of 50 MW or less. For these units, EPA is proposing to establish BAT limitations that would be set equal to BPT limitations. Since this proposed rule would not establish additional control on discharges associated with these operations, there would be no incremental costs for these units to comply with the requirements of this proposed rule.
For the aspects of these proposed regulatory options that include limitations and standards for additional pollutants, EPA estimated compliance costs and pollutant reductions from data collected through survey responses, site visits, sampling episodes, and from individual power plants and equipment vendors. EPA used this information to develop computerized cost and pollutant loadings models for each of the technologies that form the basis of the regulatory options. EPA used these models to calculate facility-specific compliance costs and pollutant reductions for all power plants that the information suggests may incur costs to comply with one or more proposed limitations or standards associated with the regulatory options.
EPA's cost estimates include two key cost components: Capital costs (one-time costs) and operating and maintenance (O&M) costs (which are incurred every year). Capital costs comprise the direct and indirect costs associated with the purchase, delivery, and installation of pollution control technologies. Capital cost elements are specific to the industry and commonly include purchased equipment and freight, equipment installation, buildings, land, site preparation, engineering costs, construction expenses, contractor's fees, and contingency. Annual O&M costs comprise all costs related to operating and maintaining the pollution control technologies or performing BMPs for a period of one year. O&M costs are also specific to the industry and commonly include costs associated with operating labor, maintenance labor, maintenance materials (routine replacement of equipment due to wear and tear), chemical purchase, energy requirements, residual disposal, and compliance monitoring. In some cases, the technology options may also result in recurring costs that are incurred less frequently than annually (e.g., 3-year recurring costs) or one-time costs other than capital investment (e.g., one-time engineering costs).
The limitations and standards associated with the regulatory options for this proposed rule address various wastestreams and, as such, consist of multiple technology bases (see Table IX–1). As a first step in estimating costs to control discharges associated with a particular generating unit at an existing steam electric power plant subject to this rulemaking (i.e., existing sources), EPA used the plant's survey response to determine if the wastestreams it discharges may be affected by the limitations and standards for the regulatory options considered in this rulemaking. Then, for each of the wastestreams that may be affected by an option, EPA reviewed the industry survey response, available sampling data, and industry long-term self-monitoring data to determine if the plant currently meets the performance level of the technology basis for the requirement of an option for that wastestream. A portion of the steam electric industry has already implemented processes or treatment technologies that serve as the basis for the regulatory options considered for the proposed rule; as a result, these facilities would not incur costs to comply with the proposed rule, or would incur costs lower than they would be if the processes/technologies had not already been implemented. In such cases, EPA assigned no compliance cost associated with the discharge of that particular wastestream other than compliance monitoring costs. For all other applicable wastestreams, EPA assessed the operations and treatment system components in place at the plant, identified necessary components that the plant would need to come into compliance, and estimated the cost to install and operate those components. Table IX–2 presents a list of the major cost components included in the evaluation. As appropriate, EPA also accounted for expected reductions in the plant's costs associated with their current operations or treatment systems that would no longer be needed as a result of installing and operating the technology bases (e.g., avoided costs to manage surface impoundments). For plants that may already have certain components installed, EPA compared certain key operating characteristics, such as chemical addition rates, to determine if additional costs (e.g., chemical costs) were warranted.
For example, to comply with BAT regulatory Option 4 presented in this proposal, EPA estimated compliance costs for a plant that currently sluices fly ash to an ash impoundment and subsequently discharges that fly ash transport water. In this case, EPA estimated the cost for the plant to convert its fly ash handling system to a dry vacuum system and assumed that certain components of its existing system would continue to be used following the conversion.
As another example, EPA estimated compliance costs to comply with BAT regulatory Option 4 for a plant that currently treats its FGD wastewater through a chemical precipitation system prior to discharge. In this case, EPA evaluated 1) whether the chemical precipitation system design basis included equalization with 24-hour residence time, 2) if the plant had an equivalent number and/or type of reaction tanks, and 3) if the plant already had components such as chemical feed systems, solids contact clarification, sand filtration, effluent and sludge holding tanks, sludge filter press, and pumps in place. If the plant had any of these components in place, EPA did not include that cost in its compliance cost estimate. EPA also evaluated whether chemical addition costs would be required based on the plant's reported chemical addition and dosages, and estimated the costs for installing and operating the biological treatment stage.
Following the evaluation of treatment in place, EPA estimated plant and wastestream specific incremental costs using computerized design and cost models. For the applicable wastestreams, the models provide capital, annual O&M, one-time, and 3-, 5-, 6-, and 10-year recurring costs for implementing and using the applicable technology basis. EPA developed cost equations from responses to the industry survey, published information, vendor contacts, and engineering judgment. EPA developed the following cost modules:
• One-Stage Chemical Precipitation—calculates capital and O&M costs associated with a one-stage chemical precipitation system;
• Biological Treatment—calculates capital and O&M costs associated with an anoxic/anaerobic biological treatment system;
• Vapor-Compression Evaporation—calculates capital and O&M costs associated with a vapor-compression evaporation system;
• Dry Fly Ash Handling—calculates capital, O&M, and recurring costs associated with a dry fly ash handling system;
• Dry Bottom Ash Handling—calculates capital, O&M, and recurring costs associated with a dry bottom ash handling system;
• Transportation—calculates O&M costs associated with transporting FGD, ash, and/or landfill leachate solid waste to an on-site or off-site landfill;
• Disposal—calculates capital and O&M costs associated with disposing of FGD, ash, and/or landfill leachate solid waste in an on-site or off-site landfill; and
• Impoundment Costs—calculates capital, O&M, and recurring costs associated with the operation and maintenance of an on-site impoundment.
Ultimately, the cost model produces a plant-level summary of the incremental technology option costs associated with each regulatory option. Each plant incurring a cost for an evaluated wastestream is presented in the output. To determine the total compliance cost for a plant associated with a regulatory option, EPA calculated the various cost components described above for each applicable wastestream. EPA then summed the costs for each component of each wastestream to calculate the total capital, O&M, and other recurring costs for the plant. Section XI of this preamble and the RIA contains a more detailed discussion of EPA's annualization of the compliance costs.
EPA also evaluated the expected costs of compliance for new sources. The construction of new generating units may occur at an existing power plant or at a new plant construction site. The incremental cost associated with complying with the proposed NSPS and PSNS options will vary depending on the types of processes, wastestreams, and waste management systems that the plant would have installed in the absence of the proposed new source requirements. EPA estimated capital and O&M costs for several scenarios that represent the different types of operations that are present at existing units at existing power plants or are typically included at new power plants. These scenarios captured differences in the plant status (i.e., building a unit at a new location versus adding a new unit at an existing power plant), presence of on-site impoundments or landfills, type of ash handling, type of FGD systems in service, and type of leachate collection and handling.
Finally, EPA recognizes there are significant drivers including federal, state, and local requirements for future air control installations at existing units. As such, EPA also conducted a sensitivity analysis that forecasts future installations of air controls through 2020
EPA took a similar approach to the one described above for costs in estimating pollutant reductions associated with the limitations and standards for the regulatory options in this proposal. That is, EPA estimated incremental pollutant reductions for discharges of a particular wastestream at a particular plant when its existing practices would not lead to compliance with the option being evaluated. In such cases, EPA estimated the annual pollutant (baseline) load associated with the current discharge of a wastestream and the post-compliance annual pollutant load expected after implementation of the applicable technology basis. EPA then calculated the pollutant loading reduction at a particular plant as the sum of the difference between the estimated baseline and post-compliance discharge load for each applicable wastestream.
The following provides a brief discussion of the methodology EPA used to estimate baseline loads discharged for the various wastestreams. For those plants that discharge indirectly to POTWs, EPA adjusted the baseline loads to account for pollutant removals expected from POTWs. These adjusted pollutant reductions for indirect dischargers reflect reductions in discharges to receiving waters.
For FGD discharges, EPA estimated baseline loadings by assigning pollutant concentrations based on the type of treatment system currently in place at the plant. EPA assigned treatment in place for this wastestream to one of four classes of treatment: surface impoundment, chemical precipitation, anaerobic/anoxic biological treatment, and vapor-compression evaporation. EPA identified the plant's current treatment system using data reported in the industry survey. Of the 117 plants that discharge FGD wastewater, 40 operate chemical precipitation systems, six operate biological treatment systems, and two operate a vapor-compression evaporation system.
EPA then estimated the average baseline pollutant effluent concentration of each analyte for each class of treatment. EPA used data collected in its sampling program to characterize effluent concentrations from chemical precipitation, anoxic/anaerobic biological treatment, and vapor-compression evaporation systems. Because EPA lacked data on pollutant effluent concentrations associated with FGD wastewater impoundments, EPA estimated that surface impoundments remove particulate matter (including the particulate phase metals) to an equivalent treatment level of 30 mg/L TSS (i.e., thus assuming that the discharge would be in compliance with the current BPT effluent limits for low-volume waste sources). EPA estimated that all dissolved metals will pass through the surface impoundment and be discharged. Section 10 of the TDD contains more information on baseline pollutant effluent concentrations.
EPA then used this average baseline pollutant effluent concentration with plant-specific discharge flow rates reported in the industry survey to estimate the mass pollutant discharged per plant.
For post-compliance FGD pollutant loading concentrations, for each pollutant, EPA used the long-term average for the technology basis for the option being evaluated. With a few exceptions, EPA then used these pollutant concentrations in combination with the same plant-specific discharge flow rates it used for baseline. The exceptions are five plants currently discharging FGD wastewater that EPA predicts will incorporate recycle within the FGD system based on the maximum operating chlorides concentration compared to the design maximum chlorides concentration.
For baseline ash loads, EPA used publicly available data to characterize discharges from ash impoundments, including data collected during EPA's Detailed Study, EPRI PISCES reports, permit application data, and the 1982
For baseline leachate loads, EPA used data reported in Part G of the industry survey to calculate an average baseline pollutant concentration for leachate. These data included responses from 22 active fuel combustion residual landfills and four inactive fuel combustion residual landfills. EPA then used the baseline pollutant concentrations in conjunction with leachate flow rates to calculate the baseline pollutant loadings. Section 9 of the TDD describes how EPA used industry survey data to estimate leachate flow rates. For post-compliance leachate loads, EPA lacked data on effluent concentrations from chemical precipitation or biological treatment of leachate from combustion residual landfills or surface impoundments. EPA is proposing the effluent limits for leachate discharges would be based on transferring the effluent limits calculated for FGD wastewater using the identical technology bases. Therefore, EPA estimates, based on engineering judgment, that post-compliance effluent concentrations for leachate would be equal to the average effluent FGD wastewater concentrations for a similar treatment technology.
FGMC wastewater originates from activated carbon injection systems. EPA identified 73 plants with current or planned activated carbon injection systems. Most of these plants use, or plan to use, a dry handling system to transfer the mercury-containing carbon to silos for temporary storage until the waste is hauled away by trucks for disposal in a landfill. EPA identified only six plants that transport (sluice) FGMC waste with water to a surface impoundment. However, five of these six plants do not discharge any FGMC wastewater and the remaining plant has the capability to handle the FGMC waste using a dry system but sometimes uses a wet system instead. Since the current baseline discharge of pollutants for FGMC wastewater is essentially zero, the proposed rule would establish effluent limitations that are consistent with the current industry practices for FGMC wastewater (i.e., zero discharge) and therefore EPA estimates there will be no (or little) incremental removal of pollutants relative to current practices. At the same time, however, establishing the proposed zero discharge standard for FGMC wastewater will ensure that future FGMC installations implement dry waste handling practices or manage wastewater in a manner that achieves zero discharge of pollutants.
The two IGCC plants currently operating in the United States already use the technology that is the basis for all eight regulatory options for gasification wastewater. A third IGCC plant that will soon begin commercial operation will also use this same treatment technology. Since these plants are already operating the technology that serves as the basis for the proposed BAT, the proposed rule would establish effluent limitations that are consistent with the current industry practices for gasification wastewater and, therefore, EPA estimates there will be no incremental removal of pollutants relative to current practices.
The proposed ELGs for discharges of nonchemical metal cleaning waste are equal to the current BPT effluent limits for metal cleaning waste. The proposed requirements are based on the same technology that was used as the basis for the current ELGs requirements for chemical metal cleaning waste. Since, as described above in Section VIII, nonchemical metal cleaning waste is included within the definition of metal cleaning waste, EPA would be establishing ELGs that are equal to the BPT limits that already apply to discharges of these wastes to surface waters.
While EPA is soliciting comment on all aspects of this proposal, the Agency would like to highlight certain aspects related to the pollutant removal estimates. EPA solicits additional data or information on pollutant loadings in steam electric power plant wastewater discharges that would corroborate or correct the data used in EPA's analysis, including data or information relating to the pollutants of concern that EPA has identified in this rulemaking. It is important that EPA have data and information of sufficient quality in order to incorporate the data into its analysis. If you have data or information or you intend to collect data that you believe would be relevant to EPA and you would like to submit the data as part of your public comments, EPA encourages you to contact the Agency first to ensure that the data submitted contains sufficient and relevant information, and that it is provided in an appropriate format, such that it can inform EPA's analyses for the final action (see points of contact in the introduction to this preamble).
EPA is also seeking comment related to the data used in developing this proposed rule and how it should be analyzed: age of data, treatment of non-detects, treatment of pollutants in the source water and the calculation of toxic-weighted pollutant equivalents.
Age of data. How should EPA take into account changes that may have occurred in the industry over time and what information would be appropriate for demonstrating that certain data for certain pollutants or wastestreams should or should not be used? For
Treatment of non-detect values. How should EPA treat non-detects in effluent data when determining baseline pollutant loadings? What other information should inform how EPA handles the issue of non-detects, given that in some cases, analytical methods cannot determine the actual amount of pollutants in wastewater? Should EPA use a cutoff for the number or percentage of non-detects in a dataset in order for EPA to use the dataset for a specific pollutant? For example, there were more non-detects than detected values for effluent data for sulfides. Does this dataset provide a sufficient basis, in the absence of any other information, for estimating pollutant loadings for sulfides?
Treatment of pollutants in the source water. When should EPA adjust pollutant loadings concentrations to account for contributions from a facility's source water? Should EPA estimate pollutant loadings for pollutants for which a certain percentage of the influent concentration comes from source water? If EPA were to do this, what steps should the Agency take to ensure the adjustments for source water contribution definitively link the source water data to the influent and effluent data?
Calculation of toxic-weighted pollutant equivalents. Is EPA's calculation of TWPEs appropriate? Do commenters have suggestions, either generally or relative to specific pollutants, for how this calculation can be improved?
As described above in Section VIII, EPA evaluated eight regulatory options comprised of various combinations of the technology options considered for each wastestream, summarized in Table VIII–1. The Agency estimated the costs and pollutant loading reductions associated with steam electric power plants to achieve compliance with each regulatory option under consideration. This section summarizes the total estimated compliance costs and pollutant reductions associated with each option for existing plants (see Tables IX–3 and IX–4). These tables present the capital cost, annual operating and maintenance costs, one-time costs, and recurring costs for each regulatory option. Section XI contains a listing of total annualized costs by regulatory option. All cost estimates in this section are expressed in terms of pre-tax 2010 dollars. The costs shown in Section XI take into account the timeframe proposed to meet the limits in the rule.
Information, including plant-specific information, for EPA's compliance cost and pollutant loading estimates and methodologies is located in the rulemaking record. Some of the information EPA used to estimate compliance costs and pollutant loadings was claimed by survey respondents as CBI. Therefore, this information is not included in the public docket. However, the public docket contains a number of documents that set forth EPA's methodology, assumptions and rationale for developing its cost estimates and pollutant loadings estimates, and that also present as much data as possible by using aggregation, summaries, and other techniques to protect CBI. EPA encourages all interested parties to refer to the record and to provide comments where appropriate on any aspect of the methodology or the data used to estimate compliance costs and pollutant loadings associated with this proposal.
EPA estimated the pollutant removals for Option 4a based on approximated plant-level bottom ash loadings for those plants that have at least one generating unit with a nameplate capacity of 400 MW or less and at least one other generating unit with a nameplate capacity of greater than 400 MW. For more details on how EPA estimated these plant-level bottom ash loadings, see the memorandum entitled “Methodologies for Estimating Costs and Pollutant Removals for Steam Electric ELG Regulatory Option 4a” (DCN SE03834).
This section describes the statistical methodology used to calculate the long-term averages, variability factors, and limitations for BAT, new source performance standards and pretreatment standards for existing and new sources. The effluent limitations and standards are based on long-term average effluent values and variability factors that account for variation in treatment performance of the model technology.
The proposed effluent limitations and/or standards, collectively referred to in the remainder of this section as “limitations,” for pollutants for each technology option, as presented in this notice, are provided as “daily maximums” and “maximums for monthly averages.” Definitions provided in 40 CFR 122.2 state that the daily maximum limitation is the “highest allowable `daily discharge,'” and the maximum for monthly average limitation is the “highest allowable average of `daily discharges' over a calendar month, calculated as the sum of all `daily discharges' measured during a calendar month divided by the number of `daily discharges' measured during that month.” Daily discharges are defined to be the “`discharge of a pollutant' measured during a calendar day or any 24-hour period that reasonably represents the calendar day for purposes of sampling.” In this section, the term “option long-term average” and “option variability factor” are used to refer to the long-term averages and variability factors for technology options for an individual wastestream rather than the regulatory options described in Section VIII.
In developing effluent limitations guidelines and standards for any industry, EPA qualitatively reviews all the data before selecting data that represents proper operation of the technology that forms the basis for the limitations. EPA typically uses four criteria to assess the data. The first criterion requires that the plants have the model treatment technology and demonstrate consistently diligent and optimal operation. Application of this criterion typically eliminates any plant with treatment other than the model technology. EPA generally determines whether a plant meets this criterion based upon site visits, discussions with plant management, and/or comparison to the characteristics, operation, and performance of treatment systems at other plants. EPA often contacts plants to determine whether data submitted were representative of normal operating conditions for the plant and equipment. As a result of this review, EPA typically excludes the data in developing the limitations when the plant has not optimized the performance of its treatment system to the degree that represents the appropriate level of control (BAT or BADCT).
A second criterion generally requires that the influents and effluents from the treatment components represent typical wastewater from the industry, without incompatible wastewater from other sources. Application of this criterion results in EPA selecting those plants where the commingled wastewaters did not result in substantial dilution, unequalized slug loads resulting in frequent upsets and/or overloads, more concentrated wastewaters, or wastewaters with different types of pollutants than those generated by the wastestream for which EPA is proposing effluent limitations.
A third criterion typically ensures that the pollutants are present in the influent at sufficient concentrations to evaluate treatment effectiveness. To evaluate whether the data meet this criterion for inclusion as a basis of the limitations, EPA often uses the long-term average test (or LTA test) for plants where EPA possesses paired influent and effluent data (see Section 13 of the Technical Development Document for details of the LTA test). The test measures the influent concentrations to ensure a pollutant is present at a sufficient concentration to evaluate treatment effectiveness. If a dataset for a pollutant fails the test (i.e., pollutant not present at a treatable concentration), EPA excludes the data for that pollutant at that plant when calculating the limitations.
A fourth criterion typically requires that the data are valid and appropriate for their intended use (e.g., the data must be analyzed with a sufficiently-sensitive method). Also, EPA does not use data associated with periods of treatment upsets because these data would not reflect the performance from well-designed and well-operated treatment systems. In applying the fourth criterion, EPA may evaluate the pollutant concentrations, analytical methods and the associated quality control/quality assurance data, flow values, mass loading, plant logs, and other available information. As part of this evaluation, EPA reviews the process or treatment conditions that may have resulted in extreme values (high and low). As a consequence of this review, EPA may exclude data associated with certain time periods or other data outliers that reflect poor performance or
The fourth criterion also is applied in EPA's review of data corresponding to the initial commissioning period for treatment systems. Most industries incur commissioning periods during the adjustment period associated with installing new treatment systems. During this acclimation and optimization process, the effluent concentration values tend to be highly variable with occasional extreme values (high and low). This occurs because the treatment system typically requires some “tuning” as the plant staff and equipment and chemical vendors work to determine the optimum chemical addition locations and dosages, vessel hydraulic residence times, internal treatment system recycle flows (e.g., filter backwash frequency, duration and flow rate, return flows between treatment system components), and other operational conditions including clarifier sludge wasting protocols. It may also take several weeks or months for treatment system operators to gain expertise on operating the new treatment system, which also contributes to treatment system variability during the commissioning period. After this initial adjustment period, the systems should operate at steady state with relatively low variability around a long-term average over many years. Because commissioning periods typically reflect one-time operating conditions unique to the first time the treatment system begins operation, EPA generally excludes such data in developing the limitations.
The sections below discuss the data used as the basis for this proposal, including data selection, the combination of data from multiple sources within each plant, and the data exclusions made prior to calculate the limitations.
This section describes the data selected for use in developing the limitations for each technology option. This section includes an abbreviated description of the technology options. See Section VIII for a more complete discussion of the technology basis for each of the options considered. For fly ash transport water and FGMC wastewater, all of the preferred regulatory options propose zero discharge of pollutants based on dry handling technologies; therefore, no effluent concentration data were used to set the limitations for these wastestreams. This is also true for the options that include zero discharge of pollutants for any set of dischargers for bottom ash.
Except as described in Section VIII, EPA is proposing to establish limitations for discharges of pollutants in nonchemical metal cleaning wastes that are equal to the current BPT limitations that apply to discharges of nonchemical metal cleaning wastes from existing sources that are direct dischargers. No new effluent concentration data were used to set the effluent limitations for nonchemical metal cleaning wastes in this rulemaking, therefore the limitations for this wastestream are not discussed in this section. See Section VIII for a more complete discussion of the basis for the proposed limitations.
Under some regulatory options being proposed today, EPA would establish limitations for certain wastewater discharges that are equal to the current BPT limitations for those discharges. No new effluent concentration data would be used to establish BAT/NSPS limitations that are set equal to BPT, therefore such limitations are not discussed in this section. See Section VIII for a more complete discussion of the basis for the proposed regulatory options. For the limitations for combustion residual leachate (hereafter referred to in this section as leachate) based on the chemical precipitation technology option, EPA is proposing to transfer the limitations calculated based on the chemical precipitation technology option for the FGD wastewater because EPA does not have the available effluent data for leachate from plants that employ the chemical precipitation technology. For the limitations based on the biological treatment technology option for FGD wastewater, EPA is proposing to transfer the limitations for two pollutants (mercury and arsenic) calculated based on the chemical precipitation technology option for the FGD wastewater for the reasons described below. See Section 13 of the Technical Development Document for a detailed discussion on the transfer of limitations for leachate and FGD wastewater.
EPA used specific data sources to derive limitations for pollutants in FGD and gasification wastewater discharges based on particular treatment technology. The data sources used to calculate limitations for each technology option, by wastestream, are described below.
As part of the EPA sampling program and additional plant self-monitoring data EPA obtained during the rulemaking, EPA evaluated the performance of 10 FGD wastewater treatment systems. For seven of the 10 systems, EPA collected data representing the influent and effluent for chemical precipitation treatment systems. EPA evaluated these seven systems and determined that the systems operating the chemical precipitation system with both hydroxide and sulfide precipitation achieved better removals of mercury compared to the plants that used only hydroxide precipitation. Therefore, EPA did not use data from the three plants that use only hydroxide precipitation. Four of the seven plants use hydroxide and sulfide precipitation; however, one of the plants operates a two-stage chemical precipitation system. Because EPA's basis for the technology option is a one-stage system, EPA did not use the data from the two-stage system in developing the limitations.
• Duke Energy's Miami Fort Station (“Miami Fort”);
• RRI Energy's Keystone Generating Station (“Keystone”); and
• Allegheny Energy's Hatfield's Ferry Power Station (“Hatfield's Ferry”).
For the treatment of FGD wastewater using a system that includes biological treatment as part of the process, EPA evaluated the treatment systems at three power plants as part of the EPA sampling program; however, one of the biological treatment systems was not designed for effective removal of selenium and does not represent the model technology. The biological treatment technology option is based on a one-stage chemical precipitation system employing both hydroxide and sulfide precipitation and iron coprecipitation, as well as flow reduction at plants with large FGD wastewater flow rates, followed by anoxic/anaerobic biological treatment designed to remove selenium, hereafter referred to in this section as “biological treatment”—see Section VIII above for a more detailed description. EPA used data from the following two plants to develop the limitations for the treatment of FGD wastewater using a one-stage chemical precipitation system followed by biological treatment:
• Duke Energy Carolina's Belews Creek Steam Station (“Belews Creek”); and
• Duke Energy Carolina's Allen Steam Station (“Allen”).
While these two plants operate the biological treatment system included as the basis for the technology option, neither of these plants include sulfide precipitation in the upstream chemical precipitation system and rely only on hydroxide precipitation. Therefore, the effluent mercury and arsenic concentrations achieved by these plants do not fully represent the effluent concentrations that would be achieved by the system used as the design basis for the technology option. For this reason, EPA is proposing to establish the mercury and arsenic limitations for the biological treatment technology option (which includes one-stage chemical precipitation as an initial treatment stage) based on transferring the limitations that were calculated for the chemical precipitation treatment technology option. This is a reasonable approach for establishing mercury and arsenic limitations for the biological treatment technology option because, in doing so, EPA would be setting the limitations equal to the performance that reflects the level of treatment that would be achieved by the initial treatment stage of the wastewater treatment system.
For the treatment of FGD wastewater using a chemical precipitation followed by vapor-compression evaporation system hereafter referred to in this section as “vapor-compression evaporation” (which is the technology serving as the basis for regulatory Option 5, which is not a preferred option in this proposal), EPA evaluated three systems as part of the EPA sampling program. One plant operates a system that is similar to the technology basis for the FGD wastewater limitations in the proposed rule: A one-stage chemical precipitation system followed by softening and a vapor-compression evaporation system. EPA used the data from this plant to develop the limitations based on the vapor-compression evaporation technology for the treatment of the FGD wastewater. That plant is Enel's Federico II Power Plant, located in Brindisi, Italy. EPA used data from a second plant for characterization purposes and not for limitations development because it only collected effluent data for one day from the plant. The third system does not represent the technology serving as the basis for the vapor compression evaporation option, and thus was not used for the limitations development. This plant operates a solids removal process prior to the vapor-compression evaporation system but does not include a full chemical precipitation system nor a softening step. Furthermore, this plant also operates a one-stage evaporation system and instead of employing a second stage of evaporation to crystallize and remove salts and other pollutants from the concentration brine, mixes the brine with fly ash and sends it to the landfill for disposal.
For the treatment of gasification wastewater using a vapor-compression evaporation system, EPA evaluated systems from the following two plants as part of the EPA sampling program:
• Tampa Electric Company's Polk Station (“Polk”); and
• Wabash Valley Power Association's Wabash River Station (“Wabash River”).
Both systems are representative of the system used as the basis for the technology option and were used in calculating the limitations.
Typically, if sampling data from a plant were collected over two or more distinct time periods, EPA analyzes the data from each time period separately. In previous effluent guidelines rulemakings, where appropriate, EPA has analyzed the data for each time period as if each time period represents a different plant since these data can represent different operating conditions due to changes in management, personnel, and procedures. On the other hand, when EPA obtains the data (such as EPA's sampling and plant self-monitoring data) from a plant during the same time period, EPA combines the data from these sources into a single dataset for the plant for the statistical analysis.
For this rulemaking, data at most selected plants came from multiple sources (EPA's sampling, plant sampling as directed by the EPA through 308 letters, or plant self-monitoring). For some plants, EPA has data collected from multiple sources during overlapping time periods. For these plants, EPA combined the multiple sources of data at each plant into a single dataset for the plant, which provided the basis for developing the limitations. Other plants had data collected from multiple sources during non-overlapping time periods. However, in these instances the time period between the non-overlapping data collection periods was relatively small (two months). Furthermore, EPA has no information to indicate that the data represent different operating conditions. Thus, EPA also combined the multiple sources of data for each of these plants into a single data set for the plant, which provided the basis for developing the limitations. Finally, a couple of plants had data from a single source, and for these plants it was not necessary to combine data. For a listing of all the data and their sampling sources for each of the plants, see DCN SE02002, “Sampling Data Used as the Basis for Effluent Limitations for the Steam Electric Rulemaking.”
Following EPA's selection of the model plant(s), EPA applied the criteria described above in Section A by thoroughly evaluating all available data for each model plant. EPA identified certain data that warranted exclusions from the calculations of the limitations because: (i) The samples were analyzed using an insufficiently-sensitive analytical method (i.e., use of EPA Method 245.1 instead of Method 1631E for mercury); (ii) the samples were collected during the initial commissioning period for the treatment system; (iii) or analytical results were identified as questionable due to quality control issues, abnormal conditions or treatment upsets, or were analytical anomalies. See DCN SE01999 for a detailed discussion of the data excluded.
The sections below describe EPA's objectives for proposing the daily maximum and monthly average limitations and the selection of percentiles for those limitations.
EPA's objective in establishing daily maximum limitations is to restrict the discharges on a daily basis at a level that is achievable for a plant that targets its treatment at the long-term average. EPA acknowledges that variability around the long-term average occurs during normal operations. This variability means that plants occasionally may discharge at a level that is higher (or lower) than the long-term average. To allow for these possibly higher daily discharges, EPA has established the daily maximum limitation. A plant that consistently discharges at a level near the daily maximum limitation would
EPA's objective in establishing monthly average limitations is to provide an additional restriction to help ensure that plants target their average discharges to achieve the long-term average. The monthly average limitation requires dischargers to provide on-going control, on a monthly basis, that supplements controls imposed by the daily maximum limitation. In order to meet the monthly average limitation, a plant must counterbalance a value near the daily maximum limitation with one or more values well below the daily maximum limitation. To achieve compliance, these values must result in a monthly average value at or below the monthly average limitation.
EPA calculates limitations based upon percentiles that should be both high enough to accommodate reasonably anticipated variability within control of the plant, and low enough to reflect a level of performance consistent with the Clean Water Act requirement that these effluent limitations be based on the “best” available technologies. The daily maximum limitation is an estimate of the 99th percentile of the distribution of the
EPA uses the 99th and 95th percentiles to draw a line at a definite point in the statistical distributions that would ensure that operators work to establish and maintain the appropriate level of control. These percentiles reflect a longstanding Agency policy judgment about where to draw the line. The development of the limitations takes into account the reasonable anticipated variability in discharges that may occur at a well-operated plant. By targeting its treatment at the long-term average, a well-operated plant should be capable of complying with the limitations at all times because EPA has incorporated an appropriate allowance for variability in the limitations.
In conjunction with setting the limitations as described above, EPA performs an engineering review to verify that the limitations are reasonable based upon the design and expected operation of the control technologies and the plant process conditions. As part of the review, for each plant EPA compared the influent and effluent measurements with the proposed effluent limitations. See Section F below for details of these comparisons for each pollutant at each plant, as well as a discussion of the findings of the engineering review.
Effluent limitations and standards are based on a combination of the long-term average and the appropriate variability factors. In estimating the limitations for a pollutant, EPA first calculates an average performance level (the option long-term average discussed below) that a plant with well-designed and well-operated model technologies is capable of achieving. This long-term average is calculated using data from the plant or plants with the model technologies for the option.
In the second step of developing a limitation for a pollutant, EPA determines an allowance for the variation (the option variability factors discussed below) in pollutant concentrations for wastewater that has been processed through well-designed and well-operated treatment systems. This allowance for variation incorporates all components of variability including shipping, sampling, storage, and analytical variability. This allowance is incorporated into the limitations through the use of the variability factors, which are calculated from the data from the plants using the model technologies. If a plant operates its treatment system to meet the relevant long-term average, EPA expects the plant will be able to meet the limitations. Variability factors ensure that normal fluctuations in a plant's treatment are accounted for in the limitations. By accounting for these reasonable excursions above the long-term average, EPA's use of variability factors results in limitations that are generally well above the long-term averages.
The following sections describe the calculation of the option long-term averages, option variability factors and limitations, and adjustments for autocorrelation in calculating the limitations for each pollutant proposed for regulation.
EPA calculated the option long-term average for a pollutant using two steps. First, EPA calculated the plant-specific long-term average for each pollutant that had enough distinct detected
Second, EPA calculated the option long-term average for a pollutant as the
The following describes the calculations performed to obtain the option variability factors and limitations. First, EPA calculated the plant-specific variability factors for each pollutant that had enough distinct detected values by fitting a statistical model to the daily effluent concentration values. Each plant-specific daily variability factor for each pollutant is the estimated 99th percentile of the distribution of the daily pollutant concentration values divided by the plant-specific long-term average. Each plant-specific monthly variability factor for each pollutant is the estimated 95th percentile of the distribution of the 4-day average pollutant concentration values divided by the plant-specific long-term average. The calculation of the monthly variability factor assumes that the monthly averages are based on the pollutant being monitored weekly (approximately four times each month). In cases when there were not enough distinct detected values for a specific pollutant at a plant, then the statistical model was not used to obtain the plant-specific variability factors. In these cases, the data for the pollutant at the plant was excluded from the calculation of the option variability factors. Appendix B of the Technical Development Document contains the required minimum number of distinct detected observations and a description of the procedures used to estimate the plant-specific daily and monthly variability factors.
Second, EPA calculated the option variability factors. The option daily variability factor for a pollutant was found as the
Finally, the daily limitation for each pollutant was the product of the option long-term average and option daily variability factor. The monthly average limitation for each pollutant was the product of the option long-term average and option monthly variability factor.
Effluent concentrations that are collected over time may be autocorrelated. The data are positively autocorrelated when measurements taken at specific time intervals, such as one or two days apart, are similar. For example, positive autocorrelation would occur if the effluent concentration were relatively high one day and were likely to remain high on the next and possibly succeeding days. Because the autocorrelated data may affect the true variability of treatment performance EPA typically adjusts the variance estimates for the autocorrelated data, when appropriate. For this rulemaking, whenever there was sufficient data for a pollutant at a plant to evaluate the autocorrelation reliably, EPA estimated the autocorrelation and incorporated it into the calculation of the limitations. For a plant without enough data to reliably evaluate and obtain a reliable estimate of the autocorrelation, EPA set the autocorrelation to zero in calculation of the limitations. EPA did so because there were not sufficient data to reliably evaluate the autocorrelation, nor did EPA have a valid correlation estimate available that could be transferred from a similar technology and wastestream. See DCN SE02001 for details of the statistical methods and procedures used to determine the autocorrelation values, as well as a detailed discussion of the minimum number of observations needed to obtain a reliable estimate of the autocorrelation. Also, see Section 13 of the TDD.
Due to routine variability in treated effluent, a power plant that discharges consistently at a level near the values of the daily maximum limitation or the monthly average limitation may experience frequent values exceeding the limitations. For this reason, EPA recommends that power plants design and operate the treatment system to achieve the option long-term average for the model technology. Thus, a system that is designed to represent the BAT level of control will be capable of complying with the limitations. The table below provides the proposed long-term average, variability factors, and limitations for each of the FGD, gasification, and leachate treatment technology options. See DCN SE01999 for details of the calculation of the results presented in the table below.
In conjunction with the statistical methods, EPA performed an engineering review to verify that the proposed limitations are reasonable based upon the design and expected operation of the control technologies. EPA performed two types of comparisons. First, EPA compared the limitations to the effluent data used to develop the limitations. Second, EPA compared the limitations to the influent data. Sections below summarize the results of these comparisons. For a detailed discussion of the results, see Section 13 of the Technical Development Document for Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (TDD)—EPA 821–R–13.
As part of its data evaluations, EPA compared the limitations to the effluent values used to calculate the limitations. This type of comparison helps to evaluate how reasonable the proposed limitations may be from an engineering perspective. As part of this evaluation, for each pollutant proposed to be regulated under a technology option, EPA first compared the daily limitations to the daily effluent values. EPA then compared the monthly limitations to all the effluent daily values in a month, and identified those months where at least one value exceeded the monthly limitations.
After thoroughly evaluating the results of the comparison between the limitations and the effluent values used to calculate the limitations for each treatment technology option for FGD and gasification wastewaters, EPA determined that the statistical distributional assumptions used to develop the limitations are appropriate for the data, and thus the proposed limitations for each technology option are reasonable. (This conclusion is also true for the leachate limitations based on the chemical precipitation technology since the leachate limitations were transferred from the FGD wastewater technology option.) If a plant properly designs and operates its wastewater treatment system to achieve the option long-term average for the model technology (rather than targeting performance at the effluent limits themselves), it will be able to comply with the limitations.
However, EPA notes that some of the daily effluent values for the BAT plants used to calculate the limitations were found to exceed either the daily or monthly average effluent limitations. See Section 13.9.1 of the TDD for a detailed discussion of the comparison of the limitations and the effluent values, including a discussion of those effluent values that exceed the limitations. EPA solicits comment on this evaluation and EPA's conclusion that plants with a properly designed and operating treatment system would be able to comply with the limitations.
In addition to comparing the proposed limitations to the data used to develop the limitations, EPA also compared the value of the proposed limitations to the influent concentration values. This comparison helps evaluate whether the proposed limitations are set at a level that ensures that treatment of the wastewater would be necessary to meet the limitations and that the influent concentrations were generally well-controlled by the treatment system. In doing so, EPA confirms that treatment to remove the regulated pollutants will take place.
For all treatment technology options for both FGD and gasification wastewater, the minimum, average, and maximum influent concentration values were much higher than the long-term average and proposed limitations (see DCN SE01999). Thus, EPA determined that facilities would need to treat the wastewater to ensure compliance with the proposed limitations and that the proposed rule would result in removing the regulated pollutants and other pollutants of concern. Furthermore, in evaluating influent concentrations, EPA found that influent concentrations were generally well-controlled by the treatment system for all plants with model technology. In general, the treatment systems adequately treated even the extreme influent values, and the high effluent values did not appear to be the result of high influent discharges.
EPA expects that facilities will comply with their effluent limitations at all times. If the exceedance is caused by an upset condition, the facility would have an affirmative defense to an enforcement action if the requirements of 40 CFR 122.41(n) are met. If an exceedance is caused by a design or operational deficiency, then EPA has determined that the facility's performance does not represent the appropriate level of control. For these proposed limitations, EPA has determined that such exceedances can be controlled by diligent process and wastewater treatment system operational practices such as frequent inspection and repair of equipment, use of back-up systems, and operator training and performance evaluations. Additionally, some facilities may need to upgrade or replace existing treatment systems to ensure that the treatment system is designed to achieve performance to target the effluent concentrations at the option long-term average. This is consistent with EPA's costing approach for the ELG technology options and its engineering judgment developed over years of evaluating wastewater treatment processes for power plants and other industrial sectors. EPA recognizes that, as a result of the proposed rule, some dischargers, including those that are operating technologies representing the “best available” technology, may need to improve their treatment systems, process controls, and/or treatment system operations in order to consistently meet the effluent limitations. EPA believes that this is consistent with the Clean Water Act, which requires that discharge limitations reflect the best available technology economically achievable or the best available demonstrated control technology.
EPA assessed the social costs and the projected economic impacts of the eight regulatory options described in this proposal (see Section VIII for a description of the options). This section provides an overview of the methodology EPA used to assess the social costs (or costs from the viewpoint of society rather than the regulated entity) and the economic impacts of the proposed ELGs and summarizes the results of these analyses. The Regulatory
EPA estimated the costs to electric power producers—which include steam electric plants owned by investor-owned utilities, municipalities, states, federal authorities, cooperatives, and nonutilities, whose primary business is electric power generation or related electric power services—of complying with the proposed ELGs. As described in Section VI of this preamble, EPA estimated that 1,079 power plants operated at least one steam electric generating unit subject to the ELGs in 2009. EPA evaluated the costs and associated impacts of this proposal on these existing plants, and on new units that may be subject to the proposed revisions to the ELGs in the future. Plants that EPA estimates would incur compliance costs as a result of the proposed revisions to the ELGs are a subset of the 1,079 steam electric power plants.
EPA's analyses of costs and economic impacts use the plant-level costs described in Section IX of this preamble. As described in that section, EPA developed plant-specific compliance costs for plants that generate a wastestream for which EPA evaluated new limitations and standards. Plant-specific compliance costs were developed for those plants for which EPA obtained detailed technical data through the industry survey. These costs consist of two principal components: initial planning and capital costs; and recurring operating and maintenance costs, which occur annually or according to a specified frequency (e.g., every 3 years, 5 years, 6 years, or 10 years). EPA applied survey weights to obtain costs for all 1,079 steam electric plants. Since all plants incurring non-zero costs have a sample weight of 1, the sum of costs for the surveyed plants also represents the total costs for the entire universe of 1,079 plants.
EPA restated compliance costs, accounting for the specific years in which each plant is assumed to undertake compliance-related activities and in 2010 dollars, using Construction Cost Index (CCI) from McGraw Hill Construction, the Employment Cost Index (ECI) published by the Bureau of Labor Statistics, and the Gross Domestic Product (GDP) deflator index published by the U.S. Bureau of Economic Analysis (BEA). EPA used 2010 dollars based on data available at the time the analysis was developed. As a result, all dollar values reported in this analysis are in constant 2010 dollars.
EPA annualized the stream of future costs using 7 percent. The rate of 7 percent is used in the cost impact analysis as an estimate of the opportunity cost of capital.
EPA annualized one-time costs and costs recurring on other than an annual basis over a specific useful life, implementation, and/or event recurrence period, using a rate of 7 percent. For capital costs and initial one-time costs, EPA used 20 years. For O&M costs incurred at intervals greater than one year, EPA used the interval as the annualization period (i.e., 3 years, 5 years, 6 years, 10 years). EPA added annualized capital, initial one-time costs, and the non-annual portion of O&M costs to annual O&M costs to derive total annualized compliance costs, where all costs are expressed on an equivalent constantly recurring annual cost basis.
EPA uses pre- and/or after-tax compliance costs in different analyses, depending on the concept appropriate to each analysis (e.g., cost-to-revenue screening-level analyses discussed in Section XI.D are conducted using after-tax compliance costs, whereas social costs discussed in Section XI.C are calculated using pre-tax costs). For the assessment of compliance costs, EPA considered costs on both a pre-tax and after-tax basis. Pre-tax costs provide insight on the total expenditure as incurred. After-tax costs are a more meaningful measure of compliance impact on privately owned for-profit plants, and incorporate approximate capital depreciation and other relevant tax treatments in the analysis. EPA calculated the after-tax value of compliance costs by applying combined federal and State tax rates to the pre-tax cost values for privately owned for-profit plants. For this adjustment, EPA used State corporate rates from the Federation of Tax Administrators (
Table XI–1 presents the total annualized compliance costs of the regulatory options on existing plants, estimated on a pre-tax and after-tax base. The table lists the eight options in order of increasing total annualized compliance costs. As shown in the table, after-tax annualized compliance costs range between $108.4 million and $1.55 billion for Options 3a and 5, respectively, with the preferred BAT and PSES options estimated to have annualized industry-wide after-tax costs of $108.4 million, $182.2 million, $389.0 million, $635.7 million (after-tax), respectively for Options3a, 3b, 3, and 4a. The costs shown in Table XI–1 do not reflect the compliance costs for new sources.
The compliance costs above account for unit retirements, repowerings and conversions that have been announced by companies and are scheduled to occur by 2014, based on information obtained by EPA as of August 2012. But they do not reflect additional planned unit retirements, repowerings, and conversions that have been announced since August 2012, nor do they reflect announced retirements, repowerings, and conversions that are scheduled to occur by 2022. (See DCN SE02033, “Changes to Industry Profile for Steam Electric Generating Units Updates”). EPA estimates that accounting for these changes would reduce total annualized compliance costs. For example, EPA estimated that total pre-tax annualized compliance costs for Option 3 would go from $561.3 million to $532.8 million (5 percent reduction), whereas costs for Option 4 would go from $1,373.2 million to $1,252.9 million (9 percent reduction).
Social costs are the costs of the rule from the viewpoint of society as a whole, rather than regulated facilities. In calculating social costs, EPA tabulated the pre-tax costs in the year when they are incurred. EPA assumed that all plants subject to the proposed regulation that would need to upgrade their systems would install control technologies over a five-year period beginning in 2017. This accounts for the time plants would have to implement control technologies, as described in Section XVI. For the purpose of the economic analyses, EPA assumed that plants would implement control technologies 3 years after the renewal of their individual NPDES permit, following the promulgation year, with NPDES permits assumed to be renewed on time, following a 5-year cycle.
EPA performed the social cost analysis over a 24-year analysis period, which combines the length of the period during which plants are expected to install the control technologies (five-year period beginning in 2017) and the useful life of the longest-lived compliance technology installed at any facility (20 years). Under this framework, the last year for which costs (and benefits) were tallied in the analysis is 2040. EPA calculated social cost of the eight regulatory options for existing steam electric power plants using a 3 percent discount rate. EPA also calculated social costs using an alternative discount rate of 7 percent.
As described in Section XVII.B, EPA does not believe the proposed rule would lead to additional costs to permitting authorities. Consequently, the only category of costs necessary to calculate social costs are compliance costs; social costs differ from pre-tax compliance costs due to timing of costs and discounting using a societal discount rate.
Table XI–2 presents the total annualized social cost of the regulatory options on existing plants, calculated using 3 percent and 7 percent discount rates. The table lists the eight options in order of increasing total social costs calculated using a 3 percent discount rate.
At 3 percent discount rate, total annualized social costs for existing plants vary from $185.2 million under Option 3a to $2.3 billion under Option 5, with the preferred BAT and PSES options having total annualized social costs of $185.2 million, $281.4 million, $572.0 million, and $954.1 million, respectively for Options 3a, 3b, 3 and 4a. The values presented in Table XI–2 for the 7 percent discount rate are slightly lower than the comparable values (pre-tax) presented in Table XI–1 due to the timing of compliance expenditures (e.g., $545.3 million versus $561.3 million, for Option 3).
These social costs do not reflect anticipated unit retirements and conversions anticipated through 2024. As noted in the previous Section, EPA anticipates that these changes would reduce total compliance costs incurred by the Steam Electric power industry, and therefore reduce the social costs of this action.
EPA assessed the economic impacts of the regulatory options in two ways: (1) A screening-level assessment of the impact of compliance costs on existing plants and the entities that own those plants, based on comparison of compliance costs to plant and entity revenue; and (2) an assessment of the impact of the proposed regulatory options for both existing and new plants within the context of the broader electricity market, which includes an assessment of incremental plant closures attributable to the proposed ELGs. EPA used the results of the screening-level assessment to inform the selection of regulatory options to be analyzed using the second approach.
The following sections summarize the methods and findings for these analyses.
EPA conducted a screening-level analysis of the rule's potential impact to existing steam electric plants and parent entities based on cost-to-revenue ratios. For each of the two levels of analysis (plant and parent entity), the Agency assumed, for analytic convenience and as a worst-case scenario, that none of the compliance costs would be passed onto consumers through electricity rate increases and would instead be absorbed by complying plants and their parent entities. In performing these and other impact analyses, EPA used the survey weights to extrapolate impacts assessed initially for a sample of plants to all 1,079 steam electric plants and to their respective owning parent entities.
EPA calculated the annualized after-tax compliance costs of the regulatory options as a percent of baseline annual revenues.
Table XI–3 summarizes the screening-level plant-level cost-to-revenue analysis results for the eight main regulatory options. EPA estimates that the vast majority of plants subject to the proposed ELGs will incur annualized costs amounting to less than 1 percent of revenue for all eight regulatory options (887 to 1,051 plants, or 82 to 97 percent of the total 1,079 steam electric plants). A significant share of these plants incur no compliance costs. For the preferred BAT and PSES options (Options 3a, 3b, 3 and 4a), 92 percent to 97 percent of steam electric plants have estimated costs that are less than 1 percent of revenue. The number of plants with ratios between 1 percent and 3 percent, and above 3 percent,
EPA also assessed the economic impact of the eight regulatory options at the parent entity-level. The screening-level cost-to-revenue analysis at the parent entity level provides insight on the impact of compliance requirements on those entities that own more than one plant incurring compliance costs associated with this proposed rule. For this analysis, EPA identified the domestic parent entity of each plant and obtained the entity's revenue from the industry survey or from publicly available data sources. In this analysis, the domestic parent entity associated with any given plant is defined as that entity that has the largest ownership share in the plant.
For each parent entity, EPA compared the total annualized after-tax compliance costs, as of 2014, and the identified parent entity's total revenue (see Chapter 4 of the RIA report for details). The total parent-level annualized after-tax compliance costs represent total costs for all steam electric plants in which the entity is the majority owner.
Compliance costs for the regulatory options were developed based on surveyed plants (see Section XI.D.1.a). For the parent entity-level analysis, EPA considered two approximate bounding cases to analyze the owners of all 1,079 steam electric plants, based on the survey weights developed from the industry survey. These cases, which are described in more detail in Chapter 4 of the RIA, provide a range of estimates for the number of entities incurring compliance costs and the costs incurred by any entity owning a steam electric plant.
Table XI–4 summarizes the results of the entity-level analysis for the two analytic cases and the eight regulatory options.
The cost-to-revenue ratios provide screening-level indicators of potential economic impacts. Entities incurring costs below 1 percent of revenue are unlikely to face economic impacts, while entities with costs between 1 percent and 3 percent of revenue have a higher chance of facing economic impacts, and entities incurring costs above 3 percent of revenue have a still higher probability of economic impacts. As presented in Table XI–4, EPA estimated that the number of entities owning steam electric plants ranges from 243 (lower bound estimate) to 507 (upper bound estimate), depending on the assumed ownership structure of plants not surveyed. Under the lower-bound case, EPA estimates that the vast majority of parent entities will incur annualized costs of less than 1 percent of revenues under all eight analyzed regulatory Options (the shares are 93, 93, 89, and 87 percent under Options 3a, 3 and 4a, respectively). These observations also hold true under the upper bound case; an estimated 94, 94, 92, and 91 percent of parent entities incur annualized costs of less than 1 percent of revenue, for Options 3a, 3b, 3 and 4a, respectively.
Overall, this screening-level analysis shows that the entity-level compliance costs are low in comparison to the entity-level revenues; very few entities are likely to face economic impacts at any level for any of the four preferred BAT and PSES options (Options 3a, 3b, 3 and 4a).
In analyzing the impacts of regulatory actions affecting the electric power sector, EPA has used the Integrated Planning Model (IPM), a comprehensive electricity market optimization model that can evaluate such impacts within the context of regional and national electricity markets. The model is designed to evaluate the effects of changes in production costs at the level of the individual generating unit, on the total cost of electricity supply, subject to specified demand and emissions constraints. To assess facility and market-level effects of these proposed ELGs, EPA used an updated version of this same analytic system: Integrated Planning Model Version 4.10 MATS (IPM V4.10).
Use of a comprehensive, market analysis system is important in assessing the potential impact of the regulatory options because of the interdependence of electricity generating units in supplying power to the electric transmission grid. Increases in electricity production costs at some plants can have a range of broader market impacts affecting other plants, including the likelihood that various plants are dispatched, on average.
IPM V4.10 provides outputs for the North American Electric Reliability Corporation (NERC) regions that lie within the continental United States. IPM V4.10 does not analyze electric power operations in Alaska and Hawaii because these states' electric power operations are not connected to the continental U.S. power grid. However, none of the steam electric plants that are estimated to incur compliance costs associated with this proposal are located in these two regions.
IPM V4.10 is based on an inventory of U.S. utility- and non-utility-owned boilers and generators that provide power to the integrated electric transmission grid, as recorded in EIA 860 (2006) and EIA 767 (2005) databases.
In contrast to the screening-level analyses, which are static analyses and do not account for interdependence of electric generating units in supplying power to the electric transmission grid, IPM accounts for potential changes in the generation profile of steam electric and other units and consequent changes in market-level generation costs, as the electric power market responds to higher generation costs for steam electric units due to the proposed ELGs. IPM is also dynamic in that it is capable of using forecasts of future conditions to make decisions for the present. Additionally, in contrast to the screening-level analyses in which EPA assumed no pass through of compliance costs, IPM depicts production activity in wholesale electricity markets where some recovery of compliance costs through increased electricity prices is possible but not guaranteed.
In performing analyses based on IPM V4.10, EPA used as its baseline—i.e., reflecting the world without this proposed regulation—a projection of electricity markets and facility operations over the period from the expected promulgation year, 2014, through 2030. As discussed above, this baseline accounts for compliance with the recently promulgated federal air rules.
As discussed in greater detail in Appendix C of the RIA, IPM generates least-cost resource dispatch decisions based on user-specified constraints such as environmental, demand, and other operational constraints. In analyzing the proposed ELGs, EPA specified additional fixed and variable costs that are expected to be incurred by specific steam electric plants and generating units to comply with the proposed ELGs. EPA then ran IPM including these additional costs to determine the dispatch of electricity generating units that would meet projected demand at
EPA used the screening-level analyses described above to inform the selection of regulatory options to be analyzed using IPM. In allocating resources to analytical effort, EPA chose to run IPM in a phased approach, starting with Option 3 and then Option 4, with the notion to proceed if additional model runs were warranted.
EPA first analyzed a scenario developed based on Option 3 but where the total compliance costs and the set of existing plants that are assigned costs varied slightly from those in the Option 3 discussed in other parts of this preamble.
The two scenarios analyzed in IPM provide insight on the market impacts of the regulatory options EPA considered for this proposal. Options 3 and 4 as analyzed in IPM are similar enough to these proposed Options 3 and 4 to provide valuable insight on the likely impacts of the proposed ELGs. Options 3a, 1, 2, and 3b are less stringent than either of the two other options analyzed in IPM; as discussed further below, the relatively small impacts observed when analyzing the Option 3 scenario suggest that the impacts of Options 3a, 1, 2 and 3b would be less than Option 3. EPA did not analyze Option 4a due to time and resource constraints, but expects that this option could have impacts between those of Options 3 and 4. EPA did not analyze Option 5 based on screening-level analysis results, which showed that compliance costs could result in financial stress to some entities owning steam electric plants. As shown in Section XI.D.1, under Option 5, about three times as many entities owning steam electric plants would incur costs that exceed 3 percent of revenue than under Options 3 (15 versus 5 entities). Twice as many entities owning steam electric power plants are estimated to incur costs that exceed 3 percent of revenue under Option 5, when compared to Option 4 (15 versus 7 entities). As discussed in Section XVII.C, the potential cost impacts to small entities are also greater under Option 5 than under Options 3 and 4.
The IPM V4.10 runs provide analysis results for selected run-years: 2020 and 2030. These analysis years, each of which represents multiple years, take into account the expected promulgation year for these proposed ELGs (2014) and the years in which all plants would be expected to install compliance technology (five-year period beginning in 2017). In the following sections, EPA reports results for the run-year 2030, which represents years 2025–2034, by which time all plants subject to this rulemaking will meet the revised guidelines and standards and all compliance costs will be reflected in production costs (i.e., steady state of post-compliance operations). EPA considered impact metrics of interest at three levels of aggregation: (1) Impact on national and regional electricity markets (i.e., all electric power generation, including steam and non-steam plants), (2) impact on steam electric power generating plants as a group (i.e., the 1,079 plants subject to the proposed ELGs, not all of which are projected to incur compliance costs), and (3) impact on individual steam electric plants incurring compliance costs.
All results presented below are representative of modeled market conditions in the years 2025–2034. While costs are in 2010 dollars, they are reflective of costs in the modeled years and are not discounted to the start of EPA's analysis period of 2014.
For the assessment of market level electricity impacts, EPA considered five output metrics from IPM V4.10: (1) Incremental early retirements and capacity closures, calculated as the difference between capacity under the regulatory options and capacity under the baseline, which includes both full plant closures and partial plant closures (i.e., unit closures) in aggregate capacity terms; (2) incremental capacity closures as a percentage of baseline capacity; (3) post-compliance changes in variable production costs per MWh, calculated as the sum of total fuel and variable O&M costs divided by net generation; (4) changes in annual costs (fuel, variable O&M, fixed O&M, and capital); and (5) post-compliance changes in energy price, where electricity prices are defined as the wholesale prices received by plants for the sale of electricity they generate.
Table XI–5 presents results for the two market model analysis scenarios. The table provides the baseline capacity and the values of each of the five metrics above, with national totals and detail at level of regional electricity markets defined on the basis of the eight NERC regions defined in IPM.
Additional results are presented in Chapter 5 of the RIA report. Chapter 5 also presents a more detailed interpretation of the results of the market-level analysis.
As shown in Table XI–5, the Market Model Analysis indicates that Option 3 would have very small effects in overall electricity markets, on both a national and regional sub-market basis, in the year 2030. Overall at the national level, the net change in total capacity, including reductions in capacity (which includes early retirements) and capacity additions in new plants/units, results in approximately 1GW of additional capacity (less than 0.05 percent total market capacity), which is too small to appear in Table XI–5. This increase in capacity is expected to take place entirely in the SPP NERC region (0.8 percent of total SPP capacity) and is the result of reduction in retired capacity (avoided capacity closures) and increase in new capacity and capacity at existing generating units.
The findings for Option 4
EPA used IPM V4.10 results for 2030 to assess the potential impact of the regulatory options on steam electric plants. In contrast to the previously described electricity market-level
Table XI–6 reports results for steam electric plants, as a group. In this case, EPA looked at the following metrics IPM produces: (1) Incremental early retirements and capacity closures, calculated as the difference between capacity under the regulatory options and capacity under the baseline, which includes both full plant closures and partial plant closures (i.e., unit closures) in aggregate capacity terms; (2) incremental capacity closures as a percentage of baseline capacity; (3) post-compliance change in electricity generation; (4) post-compliance changes in variable production costs per MWh, calculated as the sum of total fuel and variable O&M costs divided by net generation; and (5) changes in annual costs (fuel, variable O&M, fixed O&M, and capital. Items (1) and (2) are instrumental in determining the economic achievability of various regulatory options.
Under Option 3, the net change in total capacity for steam electric plants is very small; this is similar to prior findings when considering the electricity market as a whole. For the group of steam electric plants, total capacity increases by 106 MW (not shown in Table XI–6, see RIA for details) or approximately 0.02 percent of the 455,894 MW baseline capacity. This results in part from
The change in total generation is an indicator of how steam electric plants fare, relative to the rest of the electricity market. While at the market level there is essentially no projected change in total electricity generation,
Finally, at the national level, variable production costs at steam electric plants increase by approximately 0.5 percent. These effects vary by region from about −0.1 percent in MRO to 0.8 percent in SERC. These findings of very small national and regional effects in these impact metrics confirm EPA's assessment that Option 3 can be expected to have little economic consequence in national and regional electricity markets.
Results of the analysis for Option 4 show almost no change in either total generating capacity or electricity generation for the electric power sector as whole, and steam electric generating capacity and electricity generation fall slightly by 306 MW (0.07 percent) (not shown in Table XI–6, see RIA for
Findings for the change in total costs and variable production costs under Option 4 also exceed those under Option 3. There is a 1.4 percent increase in total costs at the national level, with SERC recording the largest increase of 1.8 percent. As detailed in Chapter 5 of the RIA document, at the national level, the increase in total costs occurs in fixed and variable O&M (3.2 percent and 9.3 percent, respectively) while fuel costs and capital costs decline (0.4 percent and 3.2 percent, respectively). At the national level, variable production costs increase by 1.0 percent, with SERC recording the highest increase of 1.5 percent. As for impacts on national and regional markets, EPA expects the impacts on steam electric plants of Options 3a and 3b to be smaller than those of Option 3, and the impacts of Option 4a to be between those of Options 3 and 4.
Results for the group of steam electric plants as a whole may mask shifts in economic performance among individual plants incurring compliance costs associated with the proposed ELGs. To assess potential plant-level effects, EPA analyzed plant-specific changes between the base case and the post-compliance cases for the following metrics: (1) Capacity utilization (defined as annual generation (in MWh) divided by [capacity (MW) times 8,760 hours]) (2) electricity generation, and (3) variable production costs per MWh, defined as variable O&M cost plus fuel cost divided by net generation.
Table XI–7 presents the estimated number of plants incurring compliance costs with specific degrees of change in operations and financial performance for the two regulatory options EPA analyzed using IPM. Metrics of interest include the number of plants with reductions in capacity utilization or generation (on left side of the table), and the number of plants with increases in variable production costs (on right side of the table).
For Option 3, the analysis of changes in individual plants indicates that most plants experience only slight effects—no change, or less than a 1 percent reduction or 1 percent increase. Only 13 plants (2 percent) are estimated to incur a reduction in capacity utilization exceeding 1 percent and 18 plants (3 percent) incur a reduction in generation exceeding 1 percent. The estimated change in variable production costs is higher; 51 plants (8 percent) incur an
Results for Option 4 show greater effects as compared to Option 3. While the difference in the policy impact on capacity utilization and generation is small, the difference in policy impact on variable costs is greater. The reduction in capacity utilization and generation is estimated to exceed 1 percent for 10 and 16 plants (approximately 2 percent), respectively. The increase in variable production costs is estimated to exceed 1 percent for 136 plants, 99 of which have an increase between 1 and 3 percent.
As for the market and industry-level results discussed above, EPA expects the impacts of Options 3a and 3b to be smaller than those of Option 3, and the impacts of Option 4a to be between those of Options 3 and 4.
EPA performed cost and economic impact assessment in two parts. The first set of cost and economic impact analyses—including entity-level impacts at both the plant and parent company levels—reflects baseline operating characteristics of plants incurring compliance costs and assumes no changes in those baseline operating characteristics (e.g., level of electricity generation and revenue) as a result of the requirements of the proposed regulatory options. They can serve as screening-level indicators of the relative cost of different regulatory options to plants, owning entities, or consumers, but are not determinative in terms of
The second set of analyses look at broader electricity market impacts taking into account the interconnection of regional and national electricity markets, for the full industry, for steam electric plants only, and at the distribution of impacts at the plant level. This second analysis provides insight on the impacts of the proposed ELGs on steam electric plants, as well as the electricity market as a whole, including generation capacity closure, and changes in generation and wholesale electricity prices. Results of the Market Model for Option 3 show no incremental plant closures (complete or partial) and relatively small changes in production costs. This analysis shows that Option 3 for existing steam electric plants is economically achievable. This same conclusion applies to Options 3a and 3b since the costs of these options are less than those of Option 3.
The Market Model analysis of Option 4 shows slightly higher, but still relatively small, impacts on steam electric generation and individual plants as compared to Option 3. For example, the results show incremental partial capacity retirements of 317 MW at the national level (1.4 percent relative to the baseline without the proposed ELGs), no full plant retirements, and greater increases in production costs (1.0 percent), as compared to Option 3. Given these impacts, and since the impacts of Option 4a would fall between those of Options 3 and 4, EPA believes that Option 4a is also economically achievable.
Electric power generating units that meet the definition of a new source would be required to meet the proposed NSPS or PSNS. EPA developed estimated compliance costs for new units using a methodology similar to that used to develop compliance costs for existing plants, with the notable exception that EPA did not develop new unit compliance costs that are plant specific, which would require EPA to predict which plants will construct new units.
EPA assessed the possible impact of incremental costs associated with this proposal for new units in two ways: (1) As part of its analysis using IPM discussed in Section XI.D.3; and (2) by comparing the incremental costs for new units to the overall cost of building and operating new scrubbed coal units.
EPA estimated the incremental capital and fixed O&M costs for each new electricity generating coal unit projected to come online in IPM. The Agency estimated variable O&M costs assuming that any new unit would operate, on average, 330 days per year. IPM takes these additional regulatory costs into account when trying to determine the least costly means of meeting the total electricity demand. Results of the IPM analysis are summarized in Section XI.D.3 of this preamble and discussed in detail in Chapter 5 of the RIA document. IPM results show no barrier to new generation capacity for 2025–2034 as a result of compliance with the preferred NSPS/PSNS regulatory options (Option 4). The model estimates no change in coal steam capacity relative to the baseline, and small increases in generation capacity from other steam (0.3 percent), combustion turbine (0.3 percent), other non-steam (less than 0.1 percent), and combined cycle (less than 0.1 percent) units.
As a separate analysis, EPA also compared total compliance costs to the total cost of building and operating a new coal unit on an annualized basis. EPA obtained the overnight
The comparison suggests that compliance with the proposed ELGs represents a relatively small fraction of overnight capital costs of a new unit (less than 1 percent) and a somewhat higher, but still small (less than 5 percent), fraction of non-fuel O&M costs. On an annualized basis, compliance costs for the proposed ELGs are 1.2 to 1.5 percent of annualized costs for a new plant.
Based on these two separate assessments, EPA finds no evidence that the incremental compliance costs associated with the proposed NSPS/PSNS present a barrier to entry.
EPA assessed the potential electricity price effects of this proposed rule in two ways: (1) an assessment of the potential annual increase in household electricity costs and (2) an assessment of the potential annual increase in electricity costs per MWh of total electricity sales.
Using the assumptions outlined above, EPA estimated the potential annual increase in electricity costs per household, by North American Electric Reliability Corporation (NERC) region. The analysis uses the total annualized pre-tax compliance cost per megawatt hour (MWh) for the year 2014 (in 2010 dollars), in conjunction with the reported total electricity sales quantity for each NERC region for 2009. This analysis also uses the quantity of residential electricity sales per household in 2009. To calculate the average cost per household, by region, EPA divided total compliance costs for each NERC region by the reported total MWh of sales within the region. The potential annual cost impact per household was then calculated by multiplying the estimated average cost per MWh by the average MWh per household, by NERC region.
Table XI–9 summarizes the annual household impact results for each regulatory option, by NERC region. The results for Option 3a show the average annual cost per residential household increasing by $0 to $1.69 depending on the region, with a national average of $0.48. This represents a monthly increase of $0.04 for the typical household. For Option 3b, the results show the average annual cost per residential household increasing by $0 to $2.29, with a national average of $0.75, or $0.06 per month. For Option 3, the average annual cost per residential household increases by $0 to $4.40, with a national average of $1.59, or $0.13 per month. Finally, for Option 4a, the average annual cost per residential household increases by $0 to $7.22, depending on the region, with a national average of $2.69, or $0.22 per month.
As stated above, this analysis assumes that all of the compliance costs (100 percent) will be passed onto consumers through increased electricity rates. However, plants and owning entities are likely to absorb some of these costs, thereby reducing the impact of the proposed ELGs on electricity consumers. At the same time, EPA recognizes that electric generators that operate as regulated public utilities are generally permitted to pass on environmental compliance costs as rate increases to consumers. To evaluate the sensitivity of the results to the pass-through assumption, EPA analyzed alternative scenarios including cases where only half (50 percent) of the incremental compliance costs are passed onto consumers. Appendix B of the RIA report presents the results of this sensitivity analysis. The results show smaller impacts on electricity rates, commensurate with the smaller fraction of the compliance costs that are passed onto consumers.
As an additional measure of the potential electricity price effects associated with the proposed ELGs, EPA also assessed the potential increase in electricity prices to all consumer groups (residential, commercial, industrial, and transportation), again making a counterfactual, conservative assumption of a 100 percent pass-through of compliance costs. This assessment uses as its basis the cost of the regulatory options per unit of electricity sold.
EPA used two data inputs in this analysis (1) total pre-tax compliance cost by NERC region, and (2) estimated total electricity sales for 2014, by NERC region. The Agency summed sample-weighted pre-tax annualized compliance costs as of 2014 over complying plants by NERC region to calculate the total estimated annual cost in each region. EPA then calculated the approximate average price impact per unit of electricity consumption by dividing total compliance costs by the reported total MWh of sales in each NERC region. Details of this analysis are presented in Chapter 7 of the RIA report.
As reported in Table XI–10, on average, across the United States, Option 5 results in the highest increased compliance cost of 0.059¢ per kWh. Annualized compliance costs (in dollars per KWh sales) associated with Option 3a range from 0¢ to 0.016¢, depending on the region, with a national average of
As mentioned in the previous section, EPA ran alternative scenarios using an assumption that only half (50 percent) of the incremental compliance costs are passed onto consumers. The results of these alternative scenarios showed commensurately smaller impacts on compliance costs per unit of electricity sold (see Appendix B of the RIA report).
EPA assessed the potential for employment impacts at the national level for the eight regulatory options considered in this action.
The employment effects analysis estimates employment changes only in the directly regulated electric power industry sector at the national level. This analysis focuses on the longer-term, on-going employment effects of meeting compliance requirements, and accounts for all compliance costs, regardless of their time, duration, or frequency of occurrence. Morgenstern, Pizer and Shih (2000) explore both theoretically and empirically the relationship between employment and compliance costs of environmental regulation. Morgenstern et al. identify three separate components of the employment change within a regulated industry in response to a regulation. First, complying with environmental regulations causes higher production costs which raises market prices, higher prices reduce consumption (and production) reducing demand for labor within the regulated industry (“demand effect”). Second, as costs go up, to produce the same level of output, plants add more capital and labor. For example, pollution abatement activities require additional labor services to produce the same level of output (“cost effect”). Third, post-regulation production technologies may be more or less labor intensive (i.e., more/less labor is required per dollar of output) (“factor-shift effect”). The demand effect is unambiguously negative, the cost effect is unambiguously positive and the factor-shift effect could be positive or negative making the total effect theoretically indeterminate. In addition, Morgenstern et al. also estimate an empirical model for four highly polluting/regulated industries to examine the effect of higher abatement costs from regulation on employment. They conclude that increased abatement expenditures generally do not cause a significant change in employment. More specifically, their results show that, on average across their industries, each additional $1 million spending on pollution abatement (in $1987 dollars) results in a (statistically insignificant) net increase of 1.5 jobs (95 percent confidence interval: −2.9 to + 6.0).
Table XI–11 presents the estimated change, based on the Morgenstern et al. results, in employment in the electric power industry due to the proposed ELGs under each of the eight regulatory options. The table lists the options in increasing order of employment effects. Overall, in the aggregate and by a specific employment effect, Option 1 is projected to have the smallest effect and Option 5 is projected to have the largest effect on employment. The Demand Effect is projected to result in a decline in the number of jobs, while the Cost Effect and Factor Shift Effect are projected to result in an increase in the number of jobs.
EPA estimated an average annual increase of 168 jobs under proposed Option 3a for existing sources. For proposed Option 3b, the average annual increase is estimated at 255 jobs, whereas Options 3 and 4a have estimated increases of 519 jobs and 865 jobs, respectively. Because the electric utility industry is more capital intensive and less labor intensive than the industries examined in Morganstern, Pizer and Shih, in addition to the employment estimates being statistically not distinguishable from the effect being zero, the estimates presented here are likely to be over-estimated. Chapter 6 of the RIA report describes the methodologies and results in greater detail.
EPA performed a cost-effectiveness analysis of the regulatory options for existing plants. EPA often uses cost-effectiveness analysis in the development/revision of effluent limitations guidelines and standards to evaluate the relative efficiency of alternative regulatory options in removing toxic pollutants from the effluent discharges to the nation's waters. Although not required by the Clean Water Act, cost-effectiveness analysis is a useful tool for evaluating regulatory options that address toxic pollutants.
The cost-effectiveness of a regulatory option is defined as the incremental annual cost (in 1981 constant dollars) per incremental toxic-weighted pollutant removals for that option. This definition includes the following concepts:
The result of the cost-effectiveness calculation represents the unit cost of removing the next pound-equivalent of pollutants and is expressed in constant 1981 dollars per toxic pound-equivalent removed ($/lb-eq) to allow comparisons with the reported cost effectiveness of other effluent guidelines, which use 1981 dollars.
EPA performed the cost-effectiveness analysis for the eight regulatory options for the proposed Steam Electric ELGs separately for existing direct dischargers (subject to BAT) and indirect dischargers (subject to PSES). The following sections summarize the results. Note that the same plant may be categorized as a direct discharger for one of the wastestreams it generates and as an indirect discharger for another.
Table XII–1 summarizes the cost-effectiveness analysis for the BAT regulatory options applicable to direct dischargers. The table lists the options in increasing order of total annual toxic-weighted pollutant removals.
As shown in Table XII–1, the proposed technology bases for BAT have a cost-effectiveness ratio of $27/lb-eq, $31/lb-eq, $44/lb-eq, and $57/lb-eq, respectively for Options 3a, 3b, 3 and 4a ($1981). These cost-effectiveness ratios are well within the range of cost-effectiveness ratios for BAT of other industries. A review of approximately 25 of the most recently promulgated or revised BAT limitations shows BAT cost-effectiveness ranging from less than $1/lb-eq (Inorganic Chemicals) to $404/lb-eq (Electrical and Electronic Components), in 1981 dollars.
Table XII–2 summarizes the cost-effectiveness analysis for the PSES regulatory options applicable to indirect dischargers. Toxic-weighted pollutant removals for indirect dischargers account for POTW removal efficiencies. The table lists the options in increasing order of total annual toxic-weighted pollutant removals.
As shown in Table XII–2, there are no indirect dischargers that would incur compliance costs or result in incremental pollutant removals under Options 3a and 3b, whereas Options 3 and 4a both have a cost effectiveness of $168/lb-eq ($1981). The cost-effectiveness of Options 3 and 4a is within the range of cost-effectiveness for PSES of other industries. A review of approximately 25 of the most recently promulgated or revised categorical pretreatment standards shows PSES cost-effectiveness ranging from less than $1/lb-eq (Inorganic Chemicals) to $380/lb-eq (Transportation Equipment Cleaning), in 1981 dollars.
This section describes the environmental assessment conducted in support of this rulemaking. The environmental assessment reviewed currently available literature on the documented environmental and human health impacts of combustion wastewaters and conducted modeling to determine the cumulative impacts caused by the universe of steam electric power plants proposed to be regulated under this effluent limitations guidelines and standards. Modeling calculated both the impacts at baseline conditions (current conditions), and the improvements that will result after implementation of the different potential control options. The environmental improvements discussed in Section XIII.A below are those for the preferred BAT and PSES regulatory options (Option 3a, Option 3b, Option 3, and Option 4a).
A complete review of the scientific literature and a full description of EPA's modeling analysis (including the results for all other control options) are provided in the
Current scientific literature indicates that combustion wastewaters such as fly ash and bottom ash transport water, FGD wastewater, and combustion residual leachate are toxic wastes and are causing significant detrimental environmental and human health impacts. Documented environmental impacts from exposure to these wastes reveals that the threat posed to human health, wildlife and the environment is a widespread problem that is not isolated to a few unique locations or circumstances. Documented instances of drinking water maximum contaminant
Ecological impacts include both acute (e.g., fish kills) and chronic effects (e.g., malformations, and metabolic, hormonal, and behavioral disorders) upon biota within the receiving water and the surrounding environment. Bioaccumulative toxic metals (e.g., selenium, mercury, and arsenic) are commonly cited as the primary cause for ecological damage following exposure to combustion wastewater. Selenium is the most frequently cited metal associated with environmental impacts following exposure to combustion wastewater discharges. Documented selenium-related impacts include lethal effects such as fish kills and sublethal effects such as histopathological changes (i.e., accumulation of trace elements in tissue) and damage to reproductive and developmental success. Other metals in combustion wastewater discharges such as arsenic, cadmium, chromium, copper, and lead have also been documented as causing sublethal effects such as changes to morphology (e.g., fin erosion, oral deformities), behavior (e.g., swimming ability, ability to catch prey, ability to escape from predators), and metabolism that can negatively affect long-term survival. Combined, these impacts can drastically alter aquatic populations and communities and the surrounding ecosystems that rely on them.
Recovery of the environment from exposure to combustion wastewater discharges can be extremely slow due to the accumulation and continued cycling of contaminants within the ecosystem and the potential to alter ecological processes, such as population diversity and community dynamics in the surrounding ecosystems. The ability of aquatic and adjacent terrestrial environments to recover from even short periods of exposure to these wastes depends on, among other factors, the distance from the discharge, the pollutant loadings, pollutant residence time, and the time elapsed since exposure. In particular, accumulation of metals in sediments can make recovery of aquatic systems following exposure to combustion wastewater discharges exceptionally slow due to the potential for resuspension in the water column and for benthic organisms to provide a pathway for exposure long after discharges have ended. In addition, metals such as selenium and arsenic bioaccumulate in organisms exposed to combustion wastewater discharges further complicating the potential magnitude of impacts these wastes pose.
EPA identified several cases in the literature where metals from combustion wastewater discharges bioaccumulated to toxic levels in organisms inhabiting aquatic environments even with low concentrations of these contaminants. The strong bioaccumulative properties of the pollutants, in conjunction with long residence times, emphasize the threat these wastes present to the local environment as many of the impacts may not be fully realized for years to come.
In addition to the bioaccumulative and toxic properties of the pollutants in combustion wastewaters, the total pollutant loadings associated with these discharges are large (see Section IX). EPA estimates that discharges from steam electric power plants alone contribute 50 to 60 percent of the reported toxic-weighted pollutant loadings of the combined discharges of all industrial categories currently regulated in the U.S. Further, many steam electric power plants discharge to sensitive environments where pollutant loadings contribute to reduced water quality (e.g., Great Lakes, valuable estuaries, 303(d) listed waters, drinking water sources, and waters with fish consumption advisories).
EPA has determined that 25 percent of surface waters that receive combustion wastewater discharges are impaired for a pollutant associated with combustion wastewater; 38 percent of surface waters are under a fish advisory for a pollutant associated with combustion wastewater. In addition to the concurrence of combustion wastewater discharges in close proximity to sensitive environments, EPA has identified over 120 steam electric power plants with documented environmental impacts to surface water and ground water environments following exposure to combustion wastewater, which is further evidence these wastes are of great concern. While in the past these cases may have been assumed to be anomalies, an increasing amount of evidence indicates that the characteristics contributing to the documented impact (e.g., size of the pollutant loadings, type of pollutant present in the waste, plant operations, and wastewater handling techniques) are common among power plant discharge locations. Further, as explained earlier, these documented impacts do not yet reflect the increased pollutant loadings associated with increasing use of air pollution controls. This, when coupled with the potential for long-term persistent impacts due to bioaccumulative pollutants, indicates that these impacts most likely are occurring in other locations around the country even though they have not yet been documented. This suggests that the magnitude of the environmental impact of combustion wastewater discharges is potentially greater than the literature estimates.
In addition, EPA has identified other potential impacts from combustion wastewater discharges. Steam electric plants also discharge bromide in large quantities. Bromide in wastewater discharges from steam electric plants located upstream from a drinking water intake has been associated with the formation of trihalomethanes (THMs) and haloacetic acids (HAAs) when it is exposed to chlorination disinfection processes in drinking water treatment plants. Bromate, a disinfection byproduct (DBP) associated with drinking water treatment plants that employ ozonation may also increase under the influence of increased bromide in the source water. Human exposure to THMs and DBPs in chlorinated drinking water is associated with bladder cancer.
Based on the documented environmental impacts discussed in the literature, EPA identified several key environmental and human health concerns and pathways of exposure to evaluate in the environmental assessment. These included changes in surface water, sediment, and ground water quality; toxic effects on aquatic life; toxic metal bioaccumulation in fish and in piscivorous wildlife (e.g., minks and bald eagles); toxic metal bioaccumulation in fish consumed by humans; and contamination of ground water drinking water resources.
EPA developed a three-part receiving water model to quantify changes in plant-specific impacts to surface waters, wildlife, and human health from pollutant reductions associated with the regulatory options discussed in Section VIII for a subset of evaluated wastestreams from steam electric power plants (i.e., fly ash and bottom ash transport water, FGD wastewater, and leachate). EPA considered the type of
EPA's environmental assessment modeling includes three interrelated models: 1) a receiving water-scale water quality model; 2) a receiving water-scale wildlife model; and 3) a receiving water-scale human health model. Each of these models evaluates changes in environmental and human health effects under baseline conditions and five of the regulatory options discussed in Section VIII of this preamble (Options 1, 2, 3, 4, and 5). The receiving water-scale water quality model estimates the concentration of metals (i.e., arsenic, cadmium, chromium VI, copper, lead, mercury, nickel, selenium, thallium, zinc) in the surface waters and sediments in the immediate discharge zone (i.e., approximately one to 10 kilometers [km] from the outfall) for steam electric power plants with direct discharge loadings included in the costs and loadings analysis (see Section IX). EPA compared modeled receiving water concentrations based on pollutant loadings from the evaluated wastestreams against National Recommended Water Quality Criteria (NRWQC) and Maximum Contaminant Levels (MCLs) to assess changes in receiving water quality. The wildlife model evaluates the potential impact that water and sediment concentrations pose to aquatic life, calculates the metal concentrations in exposed fish populations, and evaluates the potential impact to wildlife (minks and eagles) from consumption of fish. The human health model calculates potential threat to cause non-cancer health effects and cancer risks to human populations from the consumption of fish exposed to discharges of the evaluated wastestreams. In addition to the immediate receiving water analysis, EPA modeled receiving water concentrations downstream from steam electric discharges using EPA's Risk-Screening Environmental Indicators (RSEI) model and used the wildlife and human health models to calculate metal concentrations in exposed fish populations and human exposure doses from fish consumption in surface waters downstream from steam electric discharges. EPA compared downstream receiving water concentrations, fish tissue concentrations, and human exposure to water quality, wildlife, and non-cancer and cancer benchmarks to assess the number of improved river miles associated with the different options for this proposed rule.
EPA did not perform modeling to evaluate changes in environmental and human health effects under Option 3a, Option 3b, or Option 4a. To estimate the environmental improvements under these three options, the Agency compared their pollutant load reductions to those of Option 3 (whose reductions would be greater than those of Option 3a and Option 3b, and less than those of Option 4a) and applied corresponding adjustments to the modeled environmental improvements under Option 3 to approximate those of the three un-modeled options.
EPA expects a number of environmental and ecological improvements and reduced impacts to wildlife and human receptors to result from reductions in effluent loadings examined for the different options discussed in this proposed rule. In particular, the Environmental Assessment evaluated the following: a) improvements in water quality, b) reduction in impacts to wildlife, c) reduction in number of receiving waters with potential human health cancer risks, d) reductions in number of receiving waters with potential to cause non-cancer human health effects, e) reduction in nutrient impacts, f) reduction in other environmental impacts, and g) unquantified environmental improvements.
The reduced pollutant loadings associated with the preferred options (Option 3a, Option 3b, Option 3, and Option 4a) would lead to reduced contamination levels in surface waters and sediments. EPA estimated that reduced pollutant loadings to surface waters associated with Option 3a would significantly improve water quality by reducing metal concentrations by up to 33 percent on average within the immediate receiving waters. Option 3b, Option 3, and Option 4a would achieve average reductions of up to 36 percent, 48 percent, and 60 percent, respectively. The pollutants with the greatest number of water quality standard (NRWQC or MCL) exceedances under baseline pollutant loadings include: total arsenic, total thallium, dissolved cadmium, and total selenium. EPA determined that 49 percent of the immediate receiving waters exceeded a water quality standard under baseline loadings. EPA estimates the number of immediate receiving waters with aquatic life exceedances, which are driven by dissolved cadmium and total selenium concentrations, would be reduced by up to 29 percent for both Option 3a and Option 3b, up to 35 percent for Option 3, and up to 55 percent for Option 4a under the post-compliance pollutant loadings. EPA also estimates that the number of immediate receiving waters with human health water quality standards exceedances, primarily driven by total arsenic and total thallium concentrations, would be reduced by up to 14 percent for Option 3a, up to 15 percent for Option 3b, up to 18 percent for Option 3, and up to 41 percent for Option 4a.
Selenium was one of the primary pollutants identified in the literature as causing documented environmental impacts to fish and wildlife. EPA calculates that total selenium receiving water concentrations would be reduced by 33 percent on average under Option 3a, 36 percent on average under Option 3b, 48 percent on average under Option 3, and 60 percent on average under Option 4a. This would reduce the number of immediate receiving waters exceeding the freshwater chronic criteria for selenium by 38 percent under Option 3a, 40 percent under Option 3b, 55 percent under Option 3, and 67 percent under Option 4a. EPA estimates that up to 3,643 river miles (Option 3a), 3,862 river miles (Option 3b), 4,830 river miles (Option 3), and 6,633 river miles (Option 4a) downstream from steam electric discharges would no longer exceed aquatic life and human health NRWQC or MCL standards under the post-compliance pollutant loadings.
The preferred options would both reduce ground water contamination levels and improve the availability of ground water resources by reducing the future leaching of pollutants from steam electric impoundments to groundwater aquifers. Section XIV provides additional details on the benefits analysis of these ground water improvements.
EPA calculates that the number of immediate receiving waterbodies with potential impacts to wildlife would be
EPA determined that combustion wastewater discharges into lakes pose the greatest risk to piscivorous wildlife, with approximately 78 percent of lakes compared to 39 percent of rivers exceeding a NEHC benchmark for minks or eagles under baseline pollutant loadings. Mercury and selenium, and to a lesser extent cadmium and zinc, were the primary pollutants with greatest number of receiving waters with wildlife NEHC benchmark exceedances. EPA estimates that the preferred options would reduce the number of immediate receiving waters exceeding the mercury NEHC for minks and eagles by up to 24 percent under Option 3a, up to 26 percent under Option 3b, up to 33 percent under Option 3, and up to 52 percent under Option 4a. For selenium, EPA estimates that the number of immediate receiving waters exceeding the selenium NEHC would be reduced by up to 29 percent under Option 3a, up to 31 percent under Option 3b, up to 42 percent under Option 3, and up to 56 percent under Option 4a. This indicates that the preferred options would reduce the bioaccumulative impact of the evaluated wastestreams in the broader ecosystem. EPA estimates that up to 4,135 river miles (Option 3a), up to 4,360 river miles (Option 3b), up to 5,300 river miles (Option 3), and up to 8,206 river miles (Option 4a) downstream from steam electric discharges would no longer exceed a NEHC benchmark for minks or eagles under the post-compliance pollutant loadings.
In addition, EPA estimates that the upgrades to water quality (i.e., reductions in aquatic life NRWQC exceedances) discussed above would improve aquatic and wildlife habitats in the immediate and downstream receiving waters from steam electric discharges. EPA determined that these water quality and habitat improvements would enhance efforts to protect threatened and endangered species. EPA identified eight species with a high vulnerability to changes in water quality whose recovery would be expected to be enhanced by the post-compliance pollutant loading reductions associated with the preferred options.
EPA estimates that reductions in arsenic loadings from the preferred options would result in a reduction in potential cancer risks to humans that consume fish exposed to discharges of the evaluated wastestreams. The human health model calculates the potential cancer risk for select age groups and consumption categories (i.e., child and adult recreational fishers and child and adult subsistence fishers) based on assumptions of arsenic bioaccumulation in fish exposed to discharges of the evaluated wastestreams. Under baseline pollutant loadings, EPA determined that up to 9 percent of immediate receiving waters contain fish contaminated with inorganic arsenic that would present cancer risks above the 1-in-a-million threshold for one or more of the cohorts evaluated. EPA determined that, depending on the cohort, immediate receiving waters with cancer risks above the 1-in-a-million threshold would be reduced by up to 40 percent (Option 3a), up to 60 percent (Option 3b and Option 3), and up to 80 percent (Option 4a) under post-compliance loadings. In addition, EPA estimates that up to 266 river miles, depending on the cohort, downstream from the steam electric discharges contain fish contaminated with inorganic arsenic that would present cancer risks above the 1-in-a-million threshold. Under the post-compliance pollutant loadings associated with the preferred options, EPA estimates that up to 111 river miles (Option 3a), up to 116 river miles (Option 3b), up to 133 river miles (Option 3), and up to 169 river miles (Option 4a) downstream from steam electric discharges would no longer contain fish contaminated with inorganic arsenic that would present cancer risks above the 1-in-a-million threshold for adult subsistence fishers.
Exposure to metals poses risk of systemic and other effects to humans, including effects on the circulatory, respiratory, or digestive systems and neurological and developmental effects. The preferred options are estimated to reduce the number of receiving waters with potential to cause non-cancer health effects in humans who consume fish exposed to discharges of the evaluated wastestreams. The human health model calculates the number of immediate receiving waters with the potential to cause non-cancer health effects in select age groups and consumption categories (i.e., child and adult recreational fishers and child and adult subsistence fishers) based on assumptions of metal bioaccumulation in fish exposed to discharges of the evaluated wastestreams. Depending on the cohort, EPA calculates that exceedances of non-cancer reference doses from the consumption of fish would decrease in up to 19 percent of surface waters (Option 3a), up to 21 percent of surface waters (Option 3b), up to 26 percent of surface waters (Option 3), and up to 53 percent of surface waters (Option 4a) immediately receiving discharges of the evaluated wastestreams. Non-cancer risks are driven by mercury (as methylmercury), total thallium, and total selenium, and to a lesser degree, total cadmium pollutant loadings. Under baseline pollutant loadings, the average daily dose from the consumption of fish in up to 65 percent of immediate receiving waters exceeds the non-cancer reference dose for mercury depending on the cohort. Under post-compliance loadings, exceedances of the non-cancer mercury reference dose would decrease in up to 21 percent (Option 3a), up to 22 percent (Option 3b), up to 29 percent (Option 3), and up to 49 percent (Option 4a) of immediate receiving waters, depending on the cohort. In addition, exceedances of total thallium and total selenium non-cancer reference doses would decrease in up to 14 and 50 percent of immediate receiving waters (Option 3a and Option 3b), up to 18 and 69 percent of immediate receiving waters (Option 3), and up to 43 and 77 percent of immediate receiving waters (Option 4a), respectively. EPA also estimates that, under the post-compliance pollutant loadings, exceedances of non-cancer reference doses from the consumption of fish would decrease in up to 4,084 river miles downstream (Option 3a), up to 4,316 river miles downstream (Option 3b), up to 5,400 river miles downstream
In addition to the assessment of non-cancer reference dose exceedances described above, EPA also evaluated the adverse health effects to children who consume fish contaminated with lead from combustion wastewater. EPA estimated the reduction in lead exposure to pre-school children via consumption of contaminated fish tissue and determined that the preferred options would reduce the associated intelligence quotient (IQ) loss among children who live in recreational angler and subsistence fisher households. The preferred options would also be expected to reduce the incidence of other health effects associated with lead exposure among children, including slowed or decayed growth, delinquent and anti-social behavior, metabolic effects, impaired hemesynthesis, anemia, impaired hearing, and cancer. The preferred options would also reduce the IQ loss among children exposed
EPA expects that the preferred options would result in additional non-cancer human health effects beyond those described above, including reduced health hazards due to exposure to contaminants in waters that are used for recreational purposes (e.g., swimming).
The primary concern with nutrients in steam electric discharges is the potential for adverse nutrient impacts to occur in water-bodies that receive discharges from multiple plants. Nine percent of surface waters receiving steam electric wastewater discharges are impaired for nutrients. While the current concentration of nitrogen present in steam electric discharges from any individual power plant is relatively low, the total nitrogen loadings from a single plant can be significant due to large wastewater discharge flow rates. Total nutrient loadings from multiple power plants is especially a concern on water bodies that are nutrient impaired or in watersheds that contribute to downstream nutrient problems.
Excessive nutrient loadings to receiving waters can significantly affect the ecological stability of freshwater and saltwater aquatic systems. Nutrient over-enrichment of surface waters can stimulate excessive plant growth that can obstruct sunlight penetration and increase turbidity, which can result in the death of bottom-dwelling aquatic plants. Higher nutrient loadings from steam electric discharges could result in the eutrophication of waters and the formation of hazardous algal blooms. An additional concern with nutrients in steam electric discharges is the potential for the total nitrogen loadings from plants to increase in the future as air pollution limits become stricter and the use of air pollution controls increases.
EPA projects that the preferred options would reduce total nutrient loadings by 39 percent (Option 3a), by 41 percent (Option 3b), by 53 percent (Option 3), and by 66 percent (Option 4a) and improve overall water quality. EPA used the SPARROW (SPAtially Referenced Regressions On Watershed attributes) model to calculate immediate receiving water concentrations under baseline conditions and under five of the regulatory options discussed in Section VIII of this preamble (Options 1, 2, 3, 4, and 5) to analyze benefits related to improvements in water quality. EPA used these concentrations to develop sub-indices for a water quality index (WQI), a value that translates water quality measurements, gathered for multiple parameters that represent various aspects of water quality, into a single numerical indicator. Section XIV provides additional details on the water quality benefits analysis of nutrient reductions.
The above environmental assessment focused on the quantification of environmental improvements within rivers and lakes from post-compliance pollutant loading reductions for toxic metals and excessive nutrients. While extensive, the environmental improvements quantified do not encompass the full range of improvements anticipated to result from the preferred options simply because some of the improvements have no method for measuring a quantifiable or monetizable improvement. EPA expects post-compliance pollutant loading reductions from the preferred options to result in much greater improvements to wildlife, human health and environmental health by reducing the:
• Loadings of bioaccumulative metals to the broader ecosystem resulting in the reduction of long-term exposures and sublethal ecological effects;
• Sublethal chronic effects of toxic metals on aquatic life not captured by the NRWQC;
• Impacts to aquatic and aquatic-dependant wildlife population diversity and community structures;
• Exposure of wildlife to pollutants through direct contact with combustion residuals impoundments and constructed wetlands built as treatment systems at steam electric power plants;
• Adverse health effects in adults resulting from exposure to lead from consumption of contaminated fish tissue; and
• Potential for the formation of hazardous algal blooms.
Data limitations prevented appropriately modeling the scale and complexity of the ecosystem processes potentially impacted by combustion wastewater, resulting in the inability to quantify the improvements listed. However, documented case studies in the literature reinforce that these impacts are common in the environments surrounding steam electric power plants and fully support the conclusion that reducing pollutant loadings will improve overall environmental, human health and wildlife health.
Although the Environmental Assessment quantifies impacts to wildlife that consume fish contaminated with metals from combustion wastewater, it does not capture the full range of exposure pathways through which bioaccumulative metals can enter the surrounding food web. Wildlife can encounter toxic bioaccumulative metals from discharges of the evaluated wastestreams from a variety of exposure pathways such as direct exposure, drinking water, consumption of contaminated vegetation, and consumption of contaminated prey other than fish. Therefore, the quantified improvements underestimate the complete loadings of bioaccumulative metals that can impact wildlife in the ecosystem. EPA anticipates that the post-compliance pollutant loading reductions associated with the preferred options would lower the total amount of toxic bioaccumulative metals entering the food web near steam electric power plants.
EPA also expects the estimated reduction in pollutant loadings to lower the occurrence of sublethal effects associated with many of the pollutants in combustion wastewater that may not be captured by comparisons with NRWQC for aquatic life. Chronic effects such as changes in metabolic rates, decreased growth rates, changes in morphology (e.g., fin erosion, oral deformities), and behavior (e.g., swimming ability, ability to catch prey, ability to escape from predators) that
EPA anticipates that the expected post-compliance pollutant loading reductions associated with the preferred options would also decrease the environmental impacts to wildlife exposed to pollutants through direct contact with combustion residuals impoundments and constructed wetlands at steam electric power plants. Documented case studies demonstrate that wildlife living in close proximity to combustion residuals impoundments exhibit elevated levels of arsenic, cadmium, chromium, lead, mercury, selenium, strontium, and vanadium. Multiple studies have linked attractive nuisance areas (contaminated areas at a steam electric power plant, such as combustion wastewater surface impoundments, that are attractive to wildlife (place for nesting)) to diminished reproductive success. EPA expects that the post-compliance pollutant loadings would decrease the exposure of wildlife populations to toxic pollutants and reduce the risks for impacts on reproductive success.
EPA anticipates that other secondary, or ancillary, improvements would occur to other resources that are associated directly or indirectly as a result of the preferred options. These would include aesthetic and recreational improvements, reduced economic impacts such as clean up and treatment costs in response to contamination or impoundment failures, reduced injury associated with pond failures, reduced water usage and reduced air emissions. Section XIV provides additional details on the benefits of these other secondary improvements.
This section summarizes EPA's estimates of the national environmental benefits expected to result from reduction in pollutant discharges described in Section IX and the resultant environmental effects summarized in Section XIII. The
Table XIV–1 summarizes benefit categories associated with this proposed rule and notes which categories EPA was able to quantify and monetize. Analyzed benefits fall within six broad categories: human health benefits, ecological conditions and recreational use benefits from surface water quality improvements, market and productivity benefits, air-related benefits, groundwater quality benefits, and water withdrawal benefits. Within these broad categories, EPA was able to assess benefits with varying degrees of completeness and rigor. Where possible, EPA quantified the expected effects and estimated monetary values. However, data limitations and gaps in the understanding of how society values certain water quality changes prevent EPA from quantifying and/or monetizing some benefit categories.
The following section discusses EPA's analysis of the benefits that the Agency was able to quantify and monetize (identified in the second column of Table XIV–1). The proposed rule would also result in additional benefits that the Agency was not able to monetize. See the Benefits and Cost Analysis Document for information about these non-monetized benefits.
EPA estimated benefits for five of the eight regulatory options discussed in this preamble (Options 1, 2, 3, 4, and 5). EPA did not estimate the benefits of Options 3a, 3b and 4a. However, EPA used its understanding of the wastestreams and treatment technologies for these options, along with projections of pollutant reductions for all eight options, to estimate total monetized benefits for Options 3a, 3b, and 4a. However, EPA is less confident that this approach would yield reasonable estimates if applied to the individual categories of benefits (water quality, air emissions, avoided impoundment failure cleanup costs, etc) and so has not done so. For these more granular benefits categories, estimates are provided only for Options 1, 2, 3, 4, and 5. Again, these can serve as upper and lower bounds for the individual categories of benefits of Options 3a, 3b, and 4a. Specifically, monetized benefits for Options 3a and 3b are likely to be between those for Options 2 and 3. Similarly, monetized benefits for Option 4a are likely to be between those for Options 3 and 4.
Reduced pollutant discharges from steam electric plants generate human health benefits in a number of ways. Pollutants commonly discharged in Steam Electric plant wastewater streams include conventional and toxic pollutants such as arsenic, cadmium, chromium, copper, lead, mercury, selenium, and zinc (steam electric pollutants). Exposure to these pollutants via consumption of fish from affected waterways can cause a wide variety of adverse health effects, including cancer, kidney damage, nervous system damage, fatigue, irritability, liver damage, circulatory damage, vomiting, diarrhea, brain damage, IQ loss, and many others. Because the proposed ELGs would reduce discharges of steam electric pollutants into receiving waterways and downstream areas, they are likely to result in decreased incidences of associated illnesses.
Due to data limitations and uncertainties, EPA is able to monetize only a small subset of the health benefits associated with decreased pollutant discharges from steam electric plants. EPA analyzed the following measures of human health-related benefits: reduced cancer risk due to arsenic exposure from fish consumption, reduced lead-related IQ loss in children from fish consumption, and reduced mercury-related IQ loss in children exposed in-utero due to maternal fish consumption. EPA monetized these human health benefits by estimating the change in the expected number of individuals experiencing adverse human health effects in the populations exposed to steam electric discharges under various regulatory options and valuing these changes using a variety of nonmarket approaches (e.g., cost of illness).
EPA quantified and monetized the following four categories of human health benefits:
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Table XIV–2 summarizes monetized human health benefits associated with five of the eight regulatory options considered in this proposed rule using 3 percent and 7 percent discount rates. As mentioned above, EPA did not monetize the human health benefits associated with Options 3a, 3b and 4a. EPA expects the benefits of Option 4a to be between those of Options 3 and 4.
EPA expects that additional health benefits will arise from reduced discharges of steam electric pollutants; however, monetary valuation of these other health benefits is not currently possible due to lack of data on a dose-response relationship between pollutant ingestion rate and potential adverse health effects. To provide an additional measure of the potential health benefits of the proposed ELGs, EPA estimated the effect of steam electric plant discharges on the occurrence of pollutant concentrations in affected waterways that exceed human health-based ambient water quality criteria (AWQCs).
EPA estimates that in-stream concentrations of steam electric pollutants (i.e., arsenic, cadmium, chromium, copper, lead, mercury, nickel, selenium, thallium, and zinc) exceed human health criteria for consumption of water and organisms for at least one pollutant in 146 receiving reaches nationwide in the baseline. Depending on the regulatory option, EPA expects that the proposed rule would eliminate the occurrence of concentrations in excess of human health criteria for consumption of water and organisms for 0 to 98 of the contaminated reaches, and reduce the number of exceedances in 9 to 27 reaches. Option 3 is estimated to
EPA expects the proposed ELGs to provide ecological benefits by improving ecosystems (aquatic and terrestrial) affected by the electric power industry's effluent discharges. Benefits associated with changes in aquatic life include restoration of sensitive species, recovery of diseased species, changes in taste-and odor-producing algae, changes in dissolved oxygen (DO), increased assimilative capacity of affected waterways, and improved related recreational activities. Activities such as fishing, swimming, wildlife viewing, camping, waterfowl hunting, and boating may be enhanced when risks to aquatic life and perceivable water quality effects associated with pollutants are reduced. The magnitude of these benefits depends on the regulatory option.
EPA was able to monetize several categories of ecological benefits associated with this proposed rule, including recreational use and nonuse (i.e., existence, bequest, and altruistic) benefits from improvements in the health of aquatic environments, and nonuse benefits from increased populations of threatened and endangered species. As shown in Table XIV–1, the Agency quantified and monetized two main benefit subcategories, discussed below: (1) Benefits from improvements in surface water quality, and (2) benefits from improved protection of threatened and endangered (T&E) species.
EPA expects these proposed ELGs to improve aquatic species habitats by reducing concentrations of toxic contaminants such as arsenic, cadmium, chromium, lead, mercury, nickel, selenium, and zinc in water. The rule is also expected to reduce nitrogen and phosphorus concentrations. These improvements would be expected to enhance the quality and value of water-based recreation. For example, some of the streams that were not usable for recreation under the baseline discharge conditions may become usable following implementation of the rule, thereby expanding options for recreational users. Streams that have been used for recreation under the baseline conditions can become more attractive for users by making recreational trips even more enjoyable. Individuals may also take trips more frequently if they enjoy their recreational activities more. These proposed ELGs are also expected to generate nonuse benefits from bequest, altruism, and existence motivations. Individuals may value the knowledge that water quality is being maintained, ecosystems are being protected, and species populations are healthy, independently of their use.
To calculate baseline and post-compliance water quality, EPA utilized a water quality index (WQI) that translates water quality measurements, gathered for multiple parameters that are indicative of various aspects of water quality, into a single numerical indicator that reflects achievement of quality consistent with certain uses. The WQI provides the link between specific pollutant levels, as reflected in individual parameters, and the presence of aquatic species and suitability for particular recreational uses. Traditionally, WQIs are based on conventional pollutants (e.g., TSS, BOD, and fecal coliform) and nutrients (nitrogen and phosphorus). To account for water quality improvements resulting from reductions in toxic pollutants, EPA expanded the set of WQI parameters to include metals. The metals sub-index follows an approach developed by the Canadian Council of Ministers of the Environment (CCME) and uses the number of AWQC exceedances for a given waterbody in the baseline and/or under a given regulatory option.
EPA calculated baseline and post compliance WQI values for reaches affected by steam electric plant discharges. Baseline and post compliance water quality data were taken from several sources including USGS's SPARROW model, EPA's Risk-Screening Environmental Indicators (RSEI) model, EPA's STORET data warehouse, and estimated in-stream concentrations of steam electric pollutants. These sources provide water quality for stream networks defined according to the medium-resolution NHD or RF1. EPA conducted the benefits analysis at the level of RF1 reaches and mapped NHD data to the appropriate RF1, as needed, depending on the data source. EPA estimates that 3,945 reach miles would improve under Option 1 for existing sources, 12,683 miles under Option 2, 15,682 miles under Option 3, 22,447 reach miles under Option 4, and 22,441 reach miles under Option 5. EPA did not estimate the number of reach miles that would improve under Option 4a but expects improvements to be between those of Options 3 and 4 (i.e., between 15,682 and 22,447 reach miles).
EPA estimated monetized benefit values using a meta-regression of surface water valuation studies originally developed for the Effluent Guidelines and Standards for the Construction and Development Point Source Category (U.S. EPA, 2009). EPA used two benefit functions for each reach; one for households within a 100-mile radius of the reach that may have user values and one for nonuser households, located in the same state as the reach, but outside the 100-mile radius. Each benefit function was estimated for the years between 2014 and 2040, although benefits start accruing in 2017 when certain plants would be expected to start installing control technologies under this proposal (i.e., no benefits are assumed for 2014–2016). EPA estimated total benefits for each group––users and nonusers—as follows:
• The Agency first estimated annual household WTP values for a given reach and year using the meta-analysis regression. WTP values are a function of (1) reach-specific baseline and change in water quality values in a given year and (2) median household income values estimated for a given state or buffer zone in that year. For this analysis, two benefit functions were used for each reach in a given year; one for households that may have user values (households located within 100 miles of the reach) and one for nonuser households (households located with the same state as the reach, but outside the 100-mile buffer).
• To estimate total WTP values, the Agency multiplied annual household WTP values by the percent of total reach miles within the state or buffer and the total number of households within the state or buffer for a given year.
• EPA then discounted total WTP values to 2014, the expected
A challenge for meta-analysis is developing a framework that both controls for differences in studies and can be used for meaningfully predicting benefits associated with regulatory options. In earlier benefits estimation for effluent guidelines, EPA often relied on the Carson and Mitchell (1993) water quality values. These values come from a survey that was one of the first major stated preference efforts, fielded in the early 1980s. The study reported values for all of the nation's waters, using the same WQI that is used in the meta-analysis. When EPA used the Carson and Mitchell values, the Agency was able to tailor its benefits estimates to its regulations in two important dimensions: the level of water quality improvement, and the percent of the nation's waters being improved. EPA is basing this benefits analysis on the meta-analysis because stated preference methodology and practices have advanced considerably since the Carson and Mitchell study (although methodological issues continue to be debated in the stated preference literature), more studies have been conducted, and changes in individuals' preferences and income may well result in changing water quality values.
A trade-off, however, in using the meta-analysis is the difficulty in representing the percent of the nation's waters that are being improved, in addition to combining the results of studies encompassing a variety of water quality improvements, geographic scales, and resource characteristics that has led to both expected results and results that are counterintuitive. To provide perspective on these different approaches to measure water quality improvement benefits, EPA is also reporting the water quality values obtained by applying the Carson and Mitchell values. In 2011 dollars, using a 3 percent discount rate, these values are: for Option 1, $0.5 million; for Option 2, $2.9 million; for Option 3, $4.5 million; for Option 4, $12.9 million; and for Option 5, $12.7 million. EPA requests comment on its reliance on the meta-analysis values rather than the Carson and Mitchell values (or some other values) as the basis for estimating water quality benefits of the proposed rule. Commenters should address methodological strengths and weaknesses of any suggested approach, and explain the basis for their recommendation.
To assess the potential for impacts on threatened and endangered (T&E) species (both aquatic and terrestrial), EPA constructed a database of waterbodies currently exceeding wildlife-based AWQC but expected to have no wildlife AWQC exceedances as a result of the proposed ELGs. EPA then assessed the overlap between this geographic database and the known locations of approximately 530 T&E species. Once species overlapping waterbodies of interest were identified, EPA examined their life history traits to categorize species by the potential for population impacts likely to occur as a result of changes in water quality. T&E species with high probability of life-history effects were further screened to identify those species for which water quality was identified as a factor for listing under the Endangered Species Act (ESA) or as a limiting factor within species recovery plans. Because of this analysis, EPA identified seven fish species and one dragonfly species that may experience changes in population growth rates as a result of the proposed ELGs. EPA did not identify data sufficient to explicitly model the effects of changes in water quality on population growth rates for these species. Therefore, to estimate total population increases resulting from the proposed ELGs, EPA assumed minimal increases in population size of 0.5, 1, or 1.5 percent. To estimate monetary benefits to T&E species, EPA weighted these population growth estimates by the percent of reaches used by T&E species that are expected to meet wildlife-based AWQC because of the proposed ELGs.
The T&E species expected to benefit from the rule include two species of sturgeon and five species of small minnows. All of these species have nonuse values including existence, bequest, altruistic, and ecological service values apart from human uses or motives.
To estimate the potential economic values of increased T&E species populations affected by the proposed ELGs, EPA used a benefit function transfer approach based on a meta-analysis of 31 stated preference studies eliciting WTP for these changes (Richardson and Loomis 2009). This meta-analysis is based on studies conducted in the United States that valued threatened, rare, or endangered fish, bird, reptile, or mammal species. Because the underlying meta-data does not include insect valuation studies, EPA was unable to monetize any benefits for potential population increases of Hine's Emerald Dragonfly due to the proposed rule. For each state containing T&E species estimated to show population growth because of the proposed ELGs, EPA calculated benefits using the weighted population growth assumptions under each analytic scenario (regulatory option and population increase assumption). For states with more than one T&E species estimated to see population growth, EPA only monetized the value for the species projected to see the greatest proportional population increase. Because population growth was calculated at the state level, EPA was unable to calculate benefits based on when each steam electric plant is assumed to install control technologies to comply with the proposed ELGs. EPA therefore assumed that benefits begin accruing in 2019 for all states because this is the midpoint of the compliance period used in other cost and benefit analyses and thus provides a reasonable assumption.
There may be some overlap between WTP estimates for T&E species and the WTP estimates for improvements in water quality; however, the magnitude of this overlap is likely to be minimal because none of the studies in EPA's meta-analysis of WTP for water quality improvements specifically mentioned or otherwise prompted respondents to include benefits to T&E species populations.
Table XIV–3 summarizes the results of EPA's analysis of benefits from improved ecological conditions and recreational uses for five of the eight regulatory options. EPA did not estimate the benefits of Options 3a, 3b and 4a. As for the other benefit categories, however, the Agency expects the benefits of Option 4a to be between those of Options 3 and 4 (i.e., between $59.9 million and $116.1 million annually, at 3 percent discount rate).
EPA expects that some of the regulatory options will eliminate the future leaching of steam electric pollutants from steam electric impoundments to groundwater aquifers. The Agency monetized the associated benefits to households using private drinking wells in the vicinity of steam electric plants based on a benefits transfer from groundwater valuation studies. Specifically, EPA used existing groundwater valuation studies to derive household WTP estimates for two categorical improvements in groundwater quality: (1) “greatly improved” and (2) “improved.”
EPA identified the exposed population as the number of households using private drinking water wells in the vicinity of steam electric impoundments. EPA then modeled pollutant concentrations in the affected aquifers and determined which aquifers exceed maximum contaminant levels (MCLs) for steam electric pollutants under the baseline. EPA assumed that if a plant ceases to use impoundments to handle combustion waste because of the proposed ELGs, these aquifers would improve, with an average household WTP of $450. For impoundments that continue to receive combustion wastes but in smaller amounts, EPA assumed that the plant-specific benefits would be proportional to the reduction in wastewater flows going to the impoundment, and scaled the benefits accordingly.
Table XIV–4 summarizes the results of EPA's analysis of the groundwater benefits. As for other benefit categories, EPA did not analyze the benefits of Options 3a, 3b and 4a. EPA expects the benefits of Option 4a to be between those of Options 3 and 4 (i.e., $1.6 million to $6.5 million annually, at 3 percent discount rate).
Operational changes prompted by compliance with the proposed ELGs may cause some plant owners to reduce their reliance on impoundments to handle their waste. EPA expects these changes to reduce future impacts from impoundment failures.
To assess the benefits associated with changes in impoundment use, EPA estimated the costs associated with expected failures for baseline conditions (assuming no change in operations) and for projected reductions in the amount of CCR waste managed by impoundments for five of the eight regulatory options (Options 1, 2, 3, 4, and 5). EPA performed the calculations for each of the 1,070 impoundments identified at steam electric plants, and for each year between 2014 and 2040. EPA then calculated benefits as the difference between expected failure costs for a regulatory option and expected failure costs under baseline conditions.
To estimate the number of structural failure events that may be avoided as a result of the proposed ELGs, EPA used data on historical impoundment failures collected by EPA's Office of Resource Conservation and Recovery (ORCR) for its Regulatory Impact Analysis for EPA's Proposed Regulation of Coal Combustion Residues Generated by the Electric Utility Industry (Proposed CCR Rule; U.S. EPA 2010). Based on historical data, EPA estimated an average failure rate of 0.58 percent per impoundment per year and used this average failure rate to calculate the expected number of failure events in the baseline and under each of the regulatory options.
Table XIV–5 presents the analysis results. Depending on the regulatory option, annual benefits range from $62.1 million to $295.1 million (at 3 percent discount rate), with Option 3 having expected benefits of $114.8 million per year. EPA did not estimate the benefits of Options 3a, 3b and 4a; the Agency expects the benefits of Option 4a to be between those of Options 3 and 4 (i.e., $114.8 million to $295.1 million, at 3 percent discount rate). Note that these benefits do not include the effects of BMPs that may reduce the probability of failures and therefore would be expected to increase the benefits of the proposed ELGs. EPA will continue to seek ways to quantify and monetize BMP-related benefits in analyses for the final rule, should EPA ultimately include such BMPs as part of the final ELGs.
The proposed ELGs are expected to affect air pollution through three main mechanisms: 1) additional auxiliary electricity use by steam electric plants to operate wastewater treatment, ash handling, and other systems needed to comply with the new effluent limitations and standards; 2) additional transportation-related emissions due to the increased trucking of CCR waste to landfills; and 3) the change in the profile of electricity generation due to the relatively higher cost to generate electricity at plants incurring compliance costs for the proposed ELGs. Changes in the profile of generation can result in lower or higher air pollutant emissions because of variability in emission factors for different types of electricity generating units. For this analysis, the changes in air emissions are based on the change in dispatch of generation units projected by IPM as a result of overlaying the costs of the proposed ELGs onto steam electric units production costs.
In this analysis, EPA estimated the human health and other benefits resulting from net changes in air emissions of three pollutants: nitrogen oxides (NO
EPA used average benefit-per-ton (BPT) estimates to value benefits of changes in NO
Steam electric plants use water for handling solid waste (e.g., fly ash, bottom ash) and for operating wet FGD scrubbers. By eliminating or reducing water used in sluicing operations or prompting the recycling of water in FGD wastewater treatment systems, the proposed ELGs are expected to reduce water withdrawals from surface waterbodies and reduce demand on aquifers, in the case of plants that rely on groundwater sources.
EPA estimated the benefits of reduced groundwater withdrawals based on avoided costs of groundwater supply. For each affected facility and regulatory option, EPA multiplied the reduction in groundwater withdrawal (in gallons per year) by water costs ranging between $150 and $500 per acre-foot.
Table XIV–7 summarizes the annualized benefits associated with changes in water use by steam electric plants for five of the eight options. Chapter 9 in the BCA report provides the details of this analysis. While EPA did not estimate benefits of Options 3a, 3b and 4a, the Agency expects the benefits of Option 4a to be between those of Options 3 and 4.
Using the analysis approach described above, EPA estimates annual total benefits for the six monetized categories at approximately $82 million to $605.5 million (at 3 percent discount rate), depending on the option and based on EPA's analysis of five of the eight regulatory options (Table XIV–8). BAT and PSES option 3 has annual total benefits estimated at $311.7 million (at 3 percent discount rate). While EPA did not quantify the benefits of the other three preferred BAT and PSES Options (Option 3a, Option 3b and Option 4a), EPA expects the annual total benefits of Option 4a to be between those of Option 3 and 4 (i.e., $311.7 million to $605.5 million at 3 percent discount rate).
The monetized benefits of this proposed rule do not account for all benefits because, as described above, EPA is unable to monetize some categories. Examples of benefit categories not reflected in these estimates include non-cancer health benefits (other than IQ benefits from reduced childhood exposure to lead and in-utero exposure to mercury) and reduced cost of drinking water treatment for the pollutants with drinking water criteria. In addition, EPA's analysis of human health benefits associated with water quality improvements includes only partial benefits for directly receiving reaches.
EPA will continue to seek ways to monetize benefit categories not monetized in this proposal in order to provide a more accurate representation of benefits of the proposed rule.
Further, as noted earlier in this section, EPA calculated benefits for some of the options considered for this proposal. Benefits for these options, however, provide information relevant to understanding the potential magnitude of benefits under all proposed options, including Options 3a, 3b, and 4a. As explained earlier in this preamble, the facilities affected by Option 3a are a subset of Option 3 facilities; Option 3 benefit estimates therefore provide an upper bound estimate of benefits anticipated under Options 3a and 3b. In a similar way, EPA expects Option 4 to provide an upper bound estimate of benefits anticipated under Option 4a. As an illustrative analysis, EPA inferred the potential benefits associated with Options 3a and 3b by subtracting the benefits for Option 2 (scaled up to include a rough estimate of air emissions benefits) from the benefits for Option 3, because Option 3 includes a combination of the wastestreams and control technologies in Options 3a and 2. EPA inferred the potential benefits associated with Option 3b based on the pollutant loading reductions (pounds) projected for Option 3b relative to pollutant loading reductions projected for Option 2 (plus the fly ash dry handling benefits of Option 3a) because Option 3b includes both fly ash requirements and the Option 2 FGD wastewater treatment requirements for a subset of facilities. Specifically, EPA inferred the benefits of Options 3a and 3b by multiplying the FGD benefits estimated for Option 2 by the ratio of pollutant loads removed by 3b over Option 2, and then adding in the fly ash benefits that are also included in Option 3b. Similarly, EPA inferred the potential benefits associated with Option 4a based on the bottom ash pollutant loading reductions projected for this option, relative to bottom ash pollutant loading reductions projected for Option 4, plus the benefits of Option 3, because Option 4a includes all of the requirements of option 3 plus the bottom ash requirements of Option 4 for a subset of facilities.
Table XIV–9 summarizes total annualized benefits estimated (or inferred using the calculations described above) for the eight options discussed in this proposal. Note that there is significant uncertainty in values inferred because the methodology used does not account for differences in the pollutants, receiving waterbodies, and exposed populations between the options.
As described in Section XIV.B.1, EPA assessed whether these proposed ELGs will benefit children by reducing health risk from exposure to steam electric pollutants from consumption of contaminated fish tissue and improving recreational opportunities. The Agency was able to quantify two categories of benefits specific to children: (1) Avoided neurological damage to pre-school age children from reduced exposure to lead and (2) avoided neurological damages from in-utero exposure to mercury.
This analysis considered several measures of children's health benefits associated with lead exposure for children up to age six. Avoided neurological and cognitive damages were expressed as changes in three metrics: (1) Overall IQ levels; (2) the incidence of low IQ scores (<70); and (3) the incidence of blood-lead levels above 20 mg/dL. EPA's methodology for assessing lead-related benefits to children is presented in Chapter 3 of the BCA report. EPA analysis shows that benefits to children from reduced lead discharges range from $0.1 million to $6.8 million (at 3 percent discount), depending on the regulatory option; annual benefits for Option 3 are estimated at $2.7 million (at 3 percent discount rate). EPA did not quantify the benefits to children of Options 3a, 3b and 4a; however, the Agency expects the annual benefits of Option 4a to be between those of Options 3 and 4 (i.e., between $2.7 million and $6.8 million).
Children over the age of seven are also likely to benefit from reduced exposure to lead and the resultant neurological and cognitive damages, even though EPA did not quantify these benefits in its analysis of the proposed ELGs. Giedd et al. (1999) studied brain development among 10- to 18-year-old children and found substantial growth in brain development, mainly during early teenage years. This research suggests that older children may be hypersensitive to lead exposure, as are children aged 0 to 7.
Additional benefits to children from reduced exposure to lead not quantified in this analysis may include prevention of the following adverse health effects: slowed or delayed growth, delinquent and anti-social behavior, metabolic effects, impaired heme synthesis, anemia, impaired hearing, and cancer.
EPA also estimated the IQ-related benefits associated with reduced in-utero mercury exposure from maternal fish consumption in exposed populations. Chapter 3 of the BCA report presents EPA's methodology for assessing mercury-related benefits to children. Among approximately 1,932 babies born per year who are potentially exposed to discharges of mercury from steam electric plants, the proposed ELGs reduce total IQ point losses over the period of 2017 through 2040 by about 9,000 to 24,000 points, depending on the regulatory option. The monetary benefits associated with the avoided IQ point losses range from $3.8 million and $10.2 million per year (mean estimate, at 3 percent discount rate), across the five options EPA analyzed. Option 3 is estimated to avoid the loss of about 12,000 IQ points in exposed infants over the 24-year period. The benefits associated with these avoided IQ point losses are estimated at $5.0 million per year. EPA did not quantify the benefits to children of Options 3a, 3b and 4a; for Option 4a, however, EPA expects the annual benefits to be between those of Options 3 and 4 (i.e., $5.0 million to $10.2 million).
The elimination or reduction of one form of pollution may create or aggravate other environmental problems. Therefore, Sections 304(b) and 306 of the Act require EPA to consider non-water quality environmental impacts (including energy impacts) associated with ELGs. Accordingly, EPA has considered the potential impact of the regulatory options on air emissions, solid waste generation, and energy consumption.
Steam electric power plants use energy when transporting ash and other solids on or off site, operating wastewater treatment systems (e.g., chemical precipitation, biological treatment), operating ash handling systems, or operating water trucks for dust suppression. For those facilities that it projected would incur costs to comply with these regulatory options, EPA considered whether or not there would be an associated incremental energy need. That need varies depending on the regulatory option evaluated and the current operations of the facility. Therefore, as applicable, EPA estimated the additional energy usage in megawatt hours (MWh) for equipment added to the plant systems or in consumed fuel (gallons) for transportation/operating equipment. Similarly, as applicable, EPA also estimated the decrease in energy requirements resulting from the reduction in wet sluicing operations and use of earth moving equipment. EPA scaled the facility-specific estimate to calculate the net increase in energy requirements for the regulatory options discussed in this rulemaking.
To determine potential increases in electrical energy use, EPA estimated the amount of energy needed to operate wastewater treatment systems and ash handling systems based on the horsepower rating of the pumps and other equipment. To determine potential decreases in electrical energy use, EPA estimated the amount of
Energy usage also includes the fuel consumption associated with transportation. EPA estimated the need for increased transportation of solid waste and combustion residuals (e.g., ash) at steam electric power plants to on-site or off-site landfills using open dump trucks. The frequency and distance of transport depends on a plant's operation and configuration. For example, the volume of waste generated per day determines the frequency with which trucks will be travelling to and from the storage sites. The availability of either an on-site or off-site non-hazardous landfill and its distance from the plant determines the length of travel time. EPA also estimated the energy usage associated with the dust suppression water trucks and earth moving equipment based on specific plant operations. For example, EPA calculated earth moving equipment energy usage only if the plant operates an impoundment. To determine the potential decrease in fuel consumption, EPA estimated the amount of fuel saved by reducing the number of backhoes needed to dredge solids from ash impoundments, due to the reduction of wet sluice operations. See DCN SE01957 (
To provide some perspective on the potential increase in annual electric energy consumption associated with the preferred regulatory options, EPA compared the estimated increase in energy usage (MWh) to the net amount of electricity generated in a year by all electric power plants throughout the United States. According to EPA's Emissions & Generation Resource Integrated Database (eGRID), the power plant industry generated approximately 3,951 million MWh of energy in 2009. EPA estimates that energy increases associated with the preferred BAT and PSES regulatory options range from less than 0.003 percent (Option 3a) to 0.012 percent (Option 4a) of the total electricity generated by all electric power plants.
Similarly, EPA compared the additional fuel consumption (gallons) estimated for the preferred BAT and PSES regulatory options to national fuel consumption estimates for motor vehicles in the United States. According to the EIA, on-highway vehicles, which include automobiles, trucks, and buses, consumed approximately 34 billion gallons of distillate fuel oil in 2009. EPA estimates that the fuel consumption increase associated with the proposed Option 3a for BAT and PSES will be 0.008 percent of total fuel consumption by all motor vehicles. Fuel consumption is estimated to increase by less than 0.009 percent under Options 3b and Option 3, and less than 0.014 percent under Option 4a.
The proposed ELGs are expected to affect air pollution through three main mechanisms: (1) Additional auxiliary electricity use by steam electric plants to operate wastewater treatment, ash handling, and other systems needed to comply with the new effluent limitations and standards; (2) additional transportation-related emissions due to the increased trucking of CCR waste to landfills; and (3) the change in the profile of electricity generation due to relatively higher cost to generate electricity at plants incurring compliance costs for the proposed ELGs. This section provides greater detail on air emission changes associated with the first two mechanisms and presents the estimated net change in air emissions that take all three mechanisms into account. See Section XIV for additional discussion of the third mechanism.
Air pollution is generated when fossil fuels are combusted. In addition, steam electric power plants generate air emissions from operating transport vehicles, such as dump and vacuum trucks, dust suppression water trucks, and earth-moving equipment, which release criteria air pollutants and greenhouse gases when operated. Similarly, a decrease in energy use or vehicle operation will result in decreased air pollution.
To estimate the net air emissions associated with increased electrical energy use, EPA combined the energy usage estimates with air emission factors associated with electricity production to calculate air emissions associated with the incremental energy requirements for each of the proposed regulatory options. EPA used emission factors projected by IPM (ton/MWh) for nitrogen oxides, sulfur dioxide, and carbon dioxide to generate estimates of increased air emissions associated with increased energy production.
To estimate net air emissions associated with increased operation of transport vehicles, EPA used the MOBILE6.2 model and the California Climate Action Registry, General Reporting Protocol, Version 2.2 to identify air emission factors (gram per mile) for the air pollutants of interest. EPA assumed the general input parameters such as the year of the vehicle and the annual mileage accumulation by vehicle class to develop these factors. EPA estimated the annual number of miles that dump or vacuum trucks moving ash or wastewater treatment solids to on- or offsite landfills would travel to comply with limits established by the proposed regulatory options. In addition to the trucks transporting the additional solid waste, EPA also estimated the annual number of miles that water trucks spraying water around landfills and ash unloading areas to control dust would travel. EPA used these estimates to calculate the net change in air emissions for this rulemaking.
EPA's analyses using IPM also predict changes in air emissions. The modeled
The net change in air emissions associated with the preferred BAT/PSES regulatory options (Options 3a, 3b, 3, and 4a) are shown in Tables XV–2 through XV–5. To provide some perspective on the potential changes in annual air emissions, EPA compared the estimated change in air emissions to the net amount of air emissions generated in a year by all electric power plants throughout the United States. Tables XV–2 through XV–4 present the estimated changes in air emissions based on the regulatory options, the total emissions generated by the electric power industry in 2009, based on eGRID, and the percent change in emissions associated with Options 3a, 3b, 3, and 4a. See DCN SE02025 (
Steam electric power plants generate solid waste associated with sludge from wastewater treatment systems (e.g., chemical precipitation, biological treatment). The regulatory options evaluated would increase the amount of solid waste generated from FGD wastewater treatment, including sludge from chemical precipitation, biological treatment, and vapor compression evaporation technologies. EPA estimated the amount of solid waste generated from each technology for each plant and estimates that the preferred BAT/PSES regulatory options (Options 3a, 3b, 3, and 4a) would increase solids generated annually from treatment. Fly and bottom ash are also solid wastes generated at steam electric power plants. The preferred regulatory options for BAT and PSES are, however, not expected to alter the amount of ash or other combustion residuals generated. See DCN SE02025 (
To provide some perspective on the potential increase in annual solid waste generation associated with the preferred BAT/PSES regulatory options, EPA compared the estimated increase in solid waste generation for Options 3b, 3, and 4a
Steam electric power plants generally use water for handling solid waste, including ash, and for operating wet FGD scrubbers. The technology options for fly and bottom ash will eliminate or reduce water use associated with current wet sluicing operating systems. EPA estimated the reductions in water use based on the amount of sluice water discharged by each plant, multiplied by the percentage of intake water identified as make-up in the survey. The memorandum entitled
The technology basis for the preferred regulatory option with respect to FGD wastewater discharges (e.g., chemical precipitation, biological treatment) would not be expected to reduce the amount of water used unless plants recycle FGD wastewater as part of their treatment system. EPA estimated that five plants would be able to incorporate recycling within their FGD systems based on the maximum operating chlorides concentration compared to the design maximum chlorides concentration. Based on this comparison, EPA estimated the reduction in intake water at a plant level based on the amount of water that could be recycled by the FGD system and multiplying by the percentage of intake water identified as make-up water in the industry survey. EPA's report entitled
EPA estimates that power plants would reduce the use of water by 50 billion gallons per year (136 million gallons per day) under Option 3a, by 52 billion gallons per year (143 million gallons per day) under Option 3b, by 53 billion gallons per year (144 million gallons per day) under Option 3, and by 103 billion gallons per year (282 million gallons per day) under Option 4a.
Effluent guidelines limitations and standards act as a primary mechanism to control the discharge of pollutants to waters of the United States. This proposed rule would be applied to steam electric wastewater discharges through incorporation into NPDES permits issued by the EPA or states under Section 402 of the Act and through local pretreatment programs under Section 307 of the Act.
The Agency has developed the limitations and standards for this proposed rule to control the discharge of pollutants from the steam electric power generating point source category. Once promulgated, those permits or control mechanisms issued after this rule's effective date would be required to incorporate the effluent limitations guidelines and standards, as applicable. Also, under section 510 of the CWA, states may require effluent limitations under state law as long as they are no less stringent than the requirements of this rule. Finally, in addition to requiring application of the technology-based effluent limitations guidelines and standards in this rule, section 301(b)(1)(C) of CWA requires the permitting authority to impose more stringent effluent limitations on discharges as necessary to meet applicable water quality standards.
For the reasons explained in Section VIII, EPA proposes that certain limitations and standards based on any of the eight main regulatory options being proposed today for existing direct and indirect dischargers do not apply until July 1, 2017 (approximately three years from the effective date of this rule). EPA finds this is appropriate for any proposed BAT and PSES for FGD wastewater, gasification wastewater, fly ash transport water, flue gas mercury control wastewater, bottom ash transport water, or combustion residual leachate where EPA is not proposing to establish BAT limitations that are equal to BPT limitations. For those plants and wastestreams where EPA is proposing to establish BAT equal to the current BPT effluent limitations, the revised BAT requirements would be applicable on the effective date of the final rule. See Section VIII.B for additional discussion regarding the implementation timing for the proposed BAT and PSES requirements.
The proposed requirements for new direct and indirect dischargers (NSPS and PSNS) and the proposed requirements for existing sources where BAT is set equal to BPT would be applicable as of the effective date of the final rule.
In 1982, EPA promulgated NSPS/PSNS for certain discharges from new units. Regardless of the outcome of the current rulemaking, those units that are currently subject to the 1982 NSPS/PSNS will continue to be subject to such standards. In addition, EPA is proposing to clarify in the text of the regulation that, assuming the Agency promulgates BAT/PSES requirements as part of the current rulemaking, units to which the 1982 NSPS/PSNS apply will also be subject to any newly promulgated BAT/PSES requirements because they will be existing sources with respect to such new requirements.
For the reasons explained in Section VIII, EPA is proposing that certain BAT and PSES requirements for existing sources based on any of the eight main regulatory options would apply to discharges of FGD wastewater, fly ash
Working in conjunction with the effluent limitations guidelines and standards are the monitoring conditions set out in a NPDES discharge permit or POTW control mechanism. An integral part of the monitoring conditions is the monitoring point. The point at which a sample is collected can have a dramatic effect on the monitoring results for that facility. Therefore, it may be necessary to require internal monitoring points in order to assure compliance. Authority to address internal wastestreams is provided in 40 CFR 122.44(i)(1)(iii) and 122.45(h).
EPA is proposing that dischargers demonstrate compliance with the proposed effluent limitations and standards applicable to a particular wastestream prior to mixing the treated wastestream with other wastestreams, as described below. Therefore, with the exception of the cases where BAT limitations are equivalent to BPT limitations, any final limitations or standards (except pH) based on any of the eight main regulatory options in this proposed rule could require internal monitoring points. Section 14 of the TDD provides detailed discussion for various types of configurations. The following provides selected information from the TDD:
• FGD wastewater: Where an option proposes BAT/NSPS limitations for FGD wastewater that are not equal to existing BPT limitations,
For example, many plants currently treat their FGD wastewater and leachate in onsite surface impoundments. EPA envisions that, under this proposed Option 3 requirements, some of these plants may choose to install tank-based FGD wastewater treatment systems for their newly generated FGD wastewater. Such a plant may chose to discharge the effluent from its new treatment system directly or may wish to discharge it to the existing surface impoundment containing legacy wastewaters. In this case, the plant would be required to demonstrate compliance with the proposed effluent limitations and standards for the newly generated FGD wastewater at the effluent from the tank-based FGD wastewater treatment system, and compliance with the BPT requirements for the commingled new/legacy FGD wastewater at the point of discharge from the FGD wastewater impoundment. The same plant may also configure its system so that the impoundment (which also contains legacy FGD wastewater)is used for equalization, with the impoundment effluent sent to the tank-based treatment system. In this case, both the newly generated FGD wastewater and the legacy FGD wastewater would be treated by the tank-based treatment system and an appropriate compliance monitoring point would be the treatment system effluent. Under such a scenario, commingling of FGD wastewater generated at any date may occur as long as such combined wastewater meets the effluent limitations or standards prior to use of the treated commingled new/legacy FGD wastewater in any other plant process, or combining the FGD wastewater with any water or other process wastewater.
• Ash transport water and FGMC wastewater: EPA is proposing to specify that whenever ash transport water or flue gas mercury control wastewater generated from a generating unit that must comply with the “zero discharge” standard is used in any other plant process or is sent to a treatment system at the plant, the resulting effluent must comply with the proposed discharge prohibition for the pollutants in such wastewater.
For example, many plants currently treat their fly ash transport water in an onsite fly ash impoundment. In this case, under any proposed “no discharge” requirements, EPA envisions that such plants may convert their fly ash handling to a dry system, and no longer generate fly ash transport water. In such cases, the plant could demonstrate compliance with the proposed zero discharge requirement by showing that no fly ash transport water is generated after the date on which the new, proposed standards apply and by monitoring for compliance with the BPT requirements at the discharge from the legacy fly ash impoundment. Under EPA's proposal, the plant could not demonstrate compliance with the applicable discharge prohibition by simply using the fly ash transport water in another plant process that ultimately discharges because the prohibition on the discharge of pollutants in ash transport water and FGMC wastewater is also applicable to the discharge of wastewater from plant processes that use these wastewaters.
• Gasification wastewater: EPA is proposing to require monitoring for compliance prior to use of the gasification wastewater in any other plant process or commingling of the gasification wastewater with water or any other process wastewater. As an example, EPA envisions gasification plants would show compliance with the proposed BAT or PSES requirements directly following gasification wastewater treatment (however, there would be no need to demonstrate compliance if the gasification wastewater is completely reused within the gasification process). Combustion Residual Leachate: Under Option 4 and 5, EPA is proposing to require monitoring for compliance prior to use of leachate in any other plant process or commingling of the leachate with water or any other process wastewater. This monitoring requirement would not, however, apply prior to commingling of combustion residual leachate with FGD wastewater (including legacy FGD wastewater) or legacy combustion residual leachate that is treated to achieve pollutant removals equivalent to or greater than that achieved by the BAT/NSPS technology that serves as the basis for the effluent limitations and standards proposed today. For example, many plants currently treat their leachate in onsite surface impoundments. EPA envisions that, under the proposed requirements, some plants may choose to install a tank-based leachate treatment system so that the impoundment (which also contains legacy combustion residual leachate) is used for equalization, with the impoundment effluent ultimately sent to the tank-based treatment system. In this case, both the newly generated leachate and the legacy leachate would
Section 304(h) of the CWA directs the EPA to promulgate guidelines establishing test procedures (methods) for the analysis of pollutants. These methods are used to determine the presence and concentration of pollutants in wastewater and for compliance monitoring. They are also used for filing applications for the National Pollutant Discharge Elimination System (NPDES) permit program under 40 CFR 122.41(j)(4) and 122.21(g)(7), and under 40 CFR 403.7(d) for the pretreatment program. The EPA has promulgated analytical methods for monitoring discharges to surface water at 40 CFR part 136 for the pollutants proposed for regulation in this notice. EPA is providing notice of standard operating procedures (SOPs) for the analysis of FGD wastewater using collision cell technology in conjunction with EPA Method 200.8. EPA Method 200.8 has been promulgated under 40 CFR part 136 and is an approved method for use in NPDES compliance monitoring. Also, the use of collision cell technology is an approved modification allowed under 40 CFR part 136.6. See DCN SE03835 and DCN SE03868 for the SOPs and information on EPA's development of the SOPs.
In addition, as explained in Section VIII, with the exception of the cases where BAT limitations are equivalent to BPT limitations, EPA is proposing that compliance with any final limitations or standards (except pH) based on any of the eight main regulatory options in this proposed rule reflects results obtained from sufficiently sensitive analytical methods. Where EPA has approved more than one analytical method for a pollutant, the Agency expects that permittees would select methods that are able to quantify the presence of pollutants in a given discharge at concentrations that are low enough to determine compliance with effluent limits. For purposes of the proposed anti-circumvention provisions, a method is “sufficiently sensitive” when the sample-specific quantitation level
A “bypass” is an intentional diversion of wastestreams from any portion of a treatment facility. An “upset” is an exceptional incident in which there is unintentional and temporary noncompliance with technology-based permit effluent limitations because of factors beyond the reasonable control of the permittee. EPA's regulations concerning bypasses and upsets for direct dischargers are set forth at 40 CFR 122.41(m) and (n) and for indirect dischargers at 40 CFR 403.16 and 403.17.
The CWA requires application of effluent limitations established pursuant to Section 301 or the pretreatment standards of Section 307 to all direct and indirect dischargers. However, the statute provides for the modification of these national requirements in a limited number of circumstances. The Agency has established administrative mechanisms to provide an opportunity for relief from the application of the national effluent limitations guidelines for categories of existing sources for toxic, conventional, and nonconventional pollutants.
As explained above, the CWA requires application of the effluent limitations established pursuant to Section 301 or the pretreatment standards of Section 307 to all direct and indirect dischargers. However, the statute provides for the modification of these national requirements in a limited number of circumstances. Moreover, the Agency has established administrative mechanisms to provide an opportunity for relief from the application of national effluent limitations guidelines and pretreatment standards for categories of existing sources for priority, conventional, and nonconventional pollutants.
EPA may develop, with the concurrence of the state, effluent limitations or standards different from the otherwise applicable requirements for an individual existing discharger if it is fundamentally different with respect to factors considered in establishing the effluent limitations or standards applicable to the individual discharger. Such a modification is known as an FDF variance.
EPA, in its initial implementation of the effluent guidelines program, provided for the FDF modifications in regulations, which were variances from the BPT effluent limitations, BAT limitations for toxic and nonconventional pollutants, and BCT limitations for conventional pollutants for direct dischargers. FDF variances for toxic pollutants were challenged judicially and ultimately sustained by the Supreme Court in
Subsequently, in the Water Quality Act of 1987, Congress added a new section to the CWA—Section 301(n). This provision explicitly authorizes modifications of the otherwise applicable BAT effluent limitations, if a discharger is fundamentally different with respect to the factors specified in CWA Section 304 (other than costs) from those considered by EPA in establishing the effluent limitations. CWA Section 301(n) also defined the conditions under which EPA may establish alternative requirements. Under Section 301(n), an application for approval of a FDF variance must be based solely on (1) information submitted during rulemaking raising the factors that are fundamentally different or (2) information the applicant did not have an opportunity to submit. The alternate limitation must be no less stringent than justified by the difference and must not result in markedly more adverse non-water quality environmental impacts than the national limitation.
EPA regulations at 40 CFR part 125, subpart D, authorizing the regional administrators to establish alternative
Section 301(c) of the CWA authorizes a variance from the otherwise applicable BAT effluent guidelines for nonconventional pollutants due to economic factors. The request for a variance from effluent limitations developed from BAT guidelines must normally be filed by the discharger during the public notice period for the draft permit. Other filing periods may apply, as specified in 40 CFR 122.21(m)(2). Specific guidance for this type of variance is provided in “Draft Guidance for Application and Review of Section 301(c) Variance Requests,” dated August 21, 1984, available on EPA's Web site at
Section 301(g) of the CWA authorizes a variance from BAT effluent guidelines for certain nonconventional pollutants due to localized environmental factors. These pollutants include ammonia, chlorine, color, iron, and total phenols. As this proposed rule would not establish limitations or standards for any of these pollutants, this variance would not be applicable to this particular rule.
Section 307(b)(1) of the CWA establishes a discretionary program for POTWs to grant “removal credits” to their indirect dischargers. Removal credits are a regulatory mechanism by which industrial users may discharge a pollutant in quantities that exceed what would otherwise be allowed under an applicable categorical pretreatment standard because it has been determined that the POTW to which the industrial user discharges consistently treats the pollutant. EPA has promulgated removal credit regulations as part of its pretreatment regulations. See 40 CFR 403.7. These regulations provide that a POTW may give removal credits if prescribed requirements are met. The POTW must apply to and receive authorization from the Approval Authority. To obtain authorization, the POTW must demonstrate consistent removal of the pollutant for which approval authority is sought. Furthermore, the POTW must have an approved pretreatment program. Finally, the POTW must demonstrate that granting removal credits will not cause the POTW to violate applicable federal, state, or local sewage sludge requirements. 40 CFR 403.7(a)(3).
The United States Court of Appeals for the Third Circuit interpreted the CWA as requiring EPA to promulgate the comprehensive sewage sludge regulations pursuant to CWA Section 405(d)(2)(A)(ii) before any removal credits could be authorized.
The part 503 sewage sludge regulations allow four options for sewage sludge disposal: (1) Land application for beneficial use, (2) placement on a surface disposal unit, (3) firing in a sewage sludge incinerator, and (4) disposal in a landfill which complies with the municipal solid waste landfill criteria in 40 CFR part 258. Because pollutants in sewage sludge are regulated differently depending upon the use or disposal method selected, under EPA's pretreatment regulations the availability of a removal credit for a particular pollutant is linked to the POTW's method of using or disposing of its sewage sludge. The regulations provide that removal credits may be potentially available for the following pollutants:
(1) If POTW applies its sewage sludge to the land for beneficial uses, disposes of it in a surface disposal unit, or incinerates it in a sewage sludge incinerator, removal credits may be available for the pollutants for which EPA has established limits in 40 CFR part 503. EPA has set ceiling limitations for nine metals in sludge that is land applied, three metals in sludge that is placed on a surface disposal unit, and seven metals and 57 organic pollutants in sludge that is incinerated in a sewage sludge incinerator. 40 CFR 403.7(a)(3)(iv)(A).
(2) Additional removal credits may be available for sewage sludge that is land applied, placed in a surface disposal unit, or incinerated in a sewage sludge incinerator, so long as the concentration of these pollutants in sludge do not exceed concentration levels established in part 403, Appendix G, Table II. For sewage sludge that is land applied, removal credits may be available for an additional two metals and 14 organic pollutants. For sewage sludge that is placed on a surface disposal unit, removal credits may be available for an additional seven metals and 13 organic pollutants. For sewage sludge that is incinerated in a sewage sludge incinerator, removal credits may be available for three other metals 40 CFR 403.7(a)(3)(iv)(B).
(3) When a POTW disposes of its sewage sludge in a municipal solid waste landfill that meets the criteria of 40 CFR part 258, removal credits may be available for any pollutant in the POTW's sewage sludge. 40 CFR 403.7(a)(3)(iv)(C).
Under Section 3(f)(1) of Executive Order (EO) 12866 (58 FR 51735, October 4, 1993), this action is an “economically significant regulatory action” because it is likely to have an annual effect on the economy of $100 million or more. Accordingly, 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, EPA prepared an analysis of the potential costs and benefits associated with this action. This analysis is contained in Chapter 12 of the BCA report. A copy of the analysis is available in the docket for this action and the analysis is briefly summarized here.
Table XVII–1 (drawn from Table 12–1 of the BCA report) provides the results of the benefit-cost analysis with both costs and benefits annualized over 24 years and discounted using a 3 percent discount rate. The table lists the eight options in order of increasing total social costs.
EPA also analyzed the employment effects of the proposed ELGs. The results of that analysis are summarized in Section XI.E.
This action does not impose any new information collection burden. However, the Office of Management and Budget (OMB) has previously approved the information collection requirements contained in the existing regulations 40 CFR part 423 under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB control number 2040–0281. The OMB control numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9.
EPA estimated small changes in monitoring costs due to additional metals for which EPA is proposing limits and standards; the Agency accounted for these costs as part of its analysis of the economic impacts of the proposed ELGs. However, plants will also realize certain savings by no longer monitoring effluent that would cease to exist under the proposed ELGs. The net changes in monitoring and reporting are expected to be minimal, and EPA consequently did not revise its information collection burden estimate.
EPA does not believe that the proposed rule would lead to additional costs to permitting authorities. The proposed rule would not change permit application requirements or the associated review, it would not increase the number of permits issued to steam electric plants, and nor it increase the efforts involved in developing or reviewing such permits. In the absence of nationally applicable BAT requirements, as appropriate, permitting authorities are directed to establish technology-based effluent limitations using their use best professional judgment (BPJ) to establish site-specific requirements. EPA has data that demonstrates that permitting authorities that establish technology-based effluent limitations on a BPJ basis based on site-specific conditions can spend significant time effort and resources doing so. Establishing nationally applicable BAT requirements that eliminate the need to develop BPJ-based limitations would make permitting easier and less costly in this respect. As explained in Section XVI, under this rule, permitting authorities would be required to determine, for one permit cycle, on a facility-specific basis, what date is “as soon as possible.” This one-time burden, however, would be no more excessive than the existing burden to develop technology-based effluent limitations on a BPJ basis; in fact, it would likely be less burdensome. Nevertheless, EPA conservatively estimated no net change (i.e., increase or decrease) in the cost burden to federal or state governments associated with this proposal.
The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice-and-comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions.
For purposes of assessing the impacts of this proposed rule on small entities, small entity is defined as either a: (1) A small business as defined by the Small Business Administration's (SBA) regulations at 13 CFR 121.201; (2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; or (3) a small organization that is any not-for-profit enterprise which is independently owned and operated and is not dominant in its field. In reaching entity size determinations, EPA assumed that all federal or state entities owning steam electric plants affected by this rulemaking are not small entities.
The SBA criteria for identifying small, non-government entities in the electric power industry are as follows:
• For non-government entities with electric power generation as a primary business, small entities are those with total annual electric output less than 4 million MWh;
• For non-federal or state jurisdictions, small entities are those with a population of less than 50,000.
• For entities with a primary business other than electric power generation, the relevant size criteria are based on revenue or number of employees by NAICS sector (see Table XVII–2).
EPA identified the domestic parent entity of each steam electric plant and obtained the entity's revenue from the Steam Electric industry survey or from publicly available data sources. In this analysis, the domestic parent entity associated with any given plant is defined as that entity that has the largest ownership share in the plant. To determine whether these entities are small entities based on the size criteria outlined above, EPA compared the relevant measure for the identified parent entities to the appropriate SBA size criterion.
EPA used alternative sample-weighting approaches, which provide a range of estimates of the numbers of small entities and affected plants owned by these small entities (see Chapter 8 in the RIA for details of methodology used to develop weighted estimates). The results of this analysis using both weighting approaches are summarized below.
EPA estimates that 243 to 507 entities own steam electric plants subject to this proposal. Applying the small entity identification criteria, EPA estimates that 97 to 170 of these entities are small (see Table XVII–3). Municipalities make up the largest number of small entities owning steam electric plants under the lower bound estimate (37 out of 97) and are also a significant fraction of small entities under the upper bound estimate (46 out of 170). Small entities owning steam electric plants as a percentage of total entities range, by ownership category, from 14 to 17 percent for other political subdivision, to 47 to 51 percent for nonutility and 45 to 57 percent for municipality.
EPA determined that 14 small entities own steam electric plants expected to incur compliance costs under at least one of the eight regulatory options, for either of the two bounding cases.
In total, small entities own a total of 189 steam electric plants, or 18 percent of the total universe of 1,079 steam electric plants. Of these, EPA determined that 14 plants may incur compliance costs under at least one of the eight regulatory options.
EPA notes that its proposal (discussed in Section VIII) to set the BAT equal to BPT for existing generating units with a total nameplate generating capacity of 50 MW or less for all of the eight proposed regulatory options will reduce the potential impacts of the proposed rule on small entities and municipalities. The rulemaking record indicates that establishing a size threshold for the BAT would preferentially minimize some of the economic impacts expected on municipalities and small entities. This is the result, in particular, of the fact that 37 percent of small entities own a steam electric generating unit with a capacity of 50 MW or smaller. This stands in contrast to the 22 percent of all firms (both large and small entities) that own such a unit and the 18 percent of large entities that own one. Moreover, more than half (54 percent) of generating units owned by small entities are 50 MW or smaller. In contrast, only seven percent of generating units owned by large entities are 50 MW or smaller. Municipalities also tend to own smaller generating units, with 30 percent of municipalities and 42 percent of municipal-owned units being affected by the 50 MW size threshold.
EPA requests comment on the proposed 50 MW threshold applicable to discharges of the wastestreams described under each of the preferred options, and as well as other possible thresholds for small units.
As described above, EPA began its assessment of the impact of regulatory options on small entities by first estimating the number of small entities owning Steam Electric plants that would be subject to these proposed ELGs. EPA then assessed whether these small entities would be expected to incur costs that constitute a significant impact; and whether the number of those small entities estimated to incur a significant impact represent a substantial number of small entities.
To assess whether small entities' compliance costs might constitute a significant impact, EPA summed annualized compliance costs for the steam electric plants determined to be owned by a given small entity and calculated these costs as a percentage of entity revenue (cost-to-revenue test). EPA compared the resulting percentages to impact criteria of 1 percent and 3 percent of revenue. Small entities estimated to incur compliance costs exceeding one or more of the 1 percent and 3 percent impact thresholds were identified as potentially incurring a significant impact.
EPA used alternative sample-weighting approaches, which provide a range of estimates of the numbers of small entities and steam electric plants owned by these small entities. The results of this analysis using both weighting approaches are summarized below. Table XVII–4 presents the estimated numbers of small entities incurring costs exceeding 1 percent and 3 percent of revenue. For more information on this analysis in general and the weighting approaches in particular, see Chapter 7 in the RIA report.
As reported in Table XVII–4, EPA estimates that between 0 and 12 small entities owning steam electric plants will incur costs exceeding 1 percent of revenue, and that between 0 and 7 small entities owning steam electric plants will incur costs exceeding 3 percent of revenue, depending on the regulatory option. This is out of an estimated total of 97 to 170 small entities owning steam electric plants. The impact findings in terms of
Based on this analysis, EPA determines that the small entity impact levels for the preferred BAT and PSES options (Options 3a, 3b, 3 and 4a) support a finding of no significant impact on a substantial number of small entities (No SISNOSE). Where not zero altogether, the numbers of small entities incurring costs exceeding either the 1 or 3 percent of revenue impact threshold are small in the absolute and represent small percentages of the total estimated number of small entities (see Table XVII–5). For more details on this
After considering the economic impacts of these proposed ELGs on small entities, I certify that this action will not have a significant economic impact on a substantial number of small entities. EPA bases its finding on the low number of small entities estimated to incur costs exceeding one and/or three percent of revenue, and the small percentage that these entities represent within the total of small entities owning steam electric plants. EPA continues to be interested in the potential impacts of the proposed rule on small entities and welcomes comments on issues related to potential impacts.
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 1531–1538, requires federal agencies, unless otherwise prohibited by law, to assess the effects of their regulatory actions on State, local, and tribal governments and the private sector. This rule contains 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. Accordingly, EPA has prepared under Section 202 of the UMRA a written statement, which is summarized below (see Chapter 9 in the RIA report for more details).
Consistent with the intergovernmental consultation provisions of Section 204 of the UMRA EPA has initiated consultations with governmental entities affected by this rule. As described in Sections XVII.E, EPA held consultation meetings with elected officials or their designated employees in October 2011 to ensure their meaningful and timely input into the proposed ELGs development. EPA also conducted outreach with several intergovernmental associations representing elected officials. As described in Section XVII.F, EPA also initiated consultation and coordination with federally-recognized tribal governments in August 2011 and continued this government-to-government dialogue in March 2012.
Consistent with Section 205, EPA has identified and considered a reasonable number of regulatory alternatives. EPA considered and analyzed several alternative regulatory options to determine BAT/BADCT. These regulatory options are discussed in Section VIII of this preamble. These options included a range of technology-based approaches. As discussed in detail in Section VIII, EPA is proposing Options 3a, 3b, 3 and 4a as the preferred BAT and PSES options because they are technologically available, economically achievable, and have acceptable non-water quality environmental impacts. EPA is proposing Option 4 as the preferred NSPS and PSNS option because it is technologically available and demonstrated, poses no barrier to entry, and has acceptable non-water quality environmental impacts.
This rule is not subject to the requirements of Section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments. For its assessment of the impact of compliance requirements on small governments (i.e., governments with a population of less than 50,000), EPA compared total costs and costs per plant estimated to be incurred by small governments with the costs estimated to be incurred by large governments. EPA also compared costs for small government-owned plants with those of non-government-owned facilities. The Agency evaluated both the average and maximum annualized cost per plant. Chapter 9 of the RIA report provides details of these analyses. In all of these comparisons, both for the cost totals and, in particular, for the average and maximum cost per plant, the costs for small government-owned facilities were less than those for large government-owned facilities or for small non-government-owned facilities. On this basis, EPA concludes that the compliance cost requirements of the proposed Steam Electric ELGs would not significantly or uniquely affect small governments.
Under Executive Order 13132, EPA may not issue an action that has federalism implications, that imposes substantial direct compliance costs, and that is not required by statute, unless the Federal government provides the funds necessary to pay the direct compliance costs incurred by State and local governments, or EPA consults with state and local officials early in the process of developing the proposed action.
EPA has concluded that this action may have federalism implications, because it may impose substantial direct compliance costs on state or local governments, and the federal government will not provide the funds necessary to pay those costs.
As discussed in Section XI, EPA anticipates that this proposed action will not impose incremental administrative burden on states from issuing, reviewing, and overseeing compliance with discharge requirements. However, EPA has identified 168 steam electric plants owned by state or local government entities, out of which less than 10 percent may incur costs under one of the preferred regulatory Options. Specifically, EPA projects that five government-owned plants incur compliance costs under BAT/PSES regulatory Option 3a, six plants incur compliance costs under Option 3b, 14 plants incur compliance costs under Option 3, and 15 plants incur compliance costs under Option 4a. EPA estimates that the maximum compliance cost in any one year to governments (excluding federal government) for the eight regulatory options ranges from $13.8 million under Option 3a to $406.2 million under Option 5. Options 3b, 3 and 4a have maximum compliance costs in any one year to governments of $31.9 million, $109.5 million and $141.8 million, respectively (see Chapter 9 of the RIA report for details). From these cost values, EPA determined that the proposed ELGs contain a federal mandate that may result in expenditures of $100 million or more for state, local, and tribal governments, in the aggregate, in any one year. Based on this information, EPA finds that the action may impose substantial direct compliance costs on state or local governments. Accordingly, EPA provides the following federalism summary impact statement as required by Section 6(b) of Executive Order 13132.
EPA consulted with elected officials or their representative national organizations early in the process of developing the proposed action to permit them to have meaningful and timely input into its development.
EPA invited government officials to a consultation meeting held on October 11, 2011. EPA conducted outreach with several intergovernmental associations representing elected officials and encouraged their members to participate in the meeting, including the National Governors Association, the National Conference of State Legislatures, the Council of State Governments, the National Association of Counties, the National League of Cities, the U.S. Conference of Mayors, the County Executives of America and the National Associations of Towns and Townships.
Over 50 participants attended the consultation by phone and another 20 attended the meeting in person. EPA representatives were also present. Participants raised concerns during the meeting and in written comments
As explained in Section VIII, under all eight proposed regulatory options, EPA is proposing differentiated requirements for oil-fired generating units and units 50 MW or less. EPA believes these differentiated requirements will alleviate some of the concerns raised above. Further, as explained in Section XI, EPA's analysis demonstrates that the proposed requirements are economically achievable for the steam electric industry as a whole and for plants owned by state or local government entities. EPA is including in the docket for this action a memorandum that provides a response to the comments it received through this consultation. In the spirit of Executive Order 13132, and consistent with EPA policy to promote communications between EPA and State and local governments, EPA specifically solicits comment on the proposed ELGs 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 not have substantial direct effects on tribal governments, on the relationship between the federal government and the Indian tribes, or the distribution of power and responsibilities between the Federal government and Indian tribes as specified in Executive Order 13175. EPA's analyses show that no facility subject to these proposed ELGs is owned by tribal governments. Thus, Executive Order 13175 does not apply to this action.
Although Executive Order 13175 does not apply to this action, EPA consulted with tribal officials in developing this action. EPA initiated consultation and coordination with federally recognized tribal governments in August 2011, sharing information about the steam electric effluent guidelines rulemaking with the National Tribal Caucus and the National Tribal Water Council. EPA continued this government-to-government dialogue and, in March 2012, invited tribal representatives to participate in further discussions about the rulemaking process and objectives, with a focus on identifying specific ways that the rulemaking may affect tribes. EPA mailed an invitation letter directly to those tribes that were preliminarily identified as potentially affected by the rulemaking, as well extended the invitation via email to all federally-recognized tribal governments encouraging their participation in the consultation process. The consultation process ended on April 17, 2012 and no comments were received from any tribal representative. For further information regarding the consultation process and supplemental materials provided to tribal representatives please go to the steam electric power generating effluent guidelines Web site at this link:
This action is not subject to Executive Order 13045 (62 FR 19885, April 23, 1997) because the Agency does not believe the environmental health risks or safety risks addressed by this action present a disproportionate risk to children. This proposed action's health and risk assessments are summarized in Section XIV.D.
This action is not a “significant energy action” as defined in Executive Order 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.
The Agency analyzed the potential energy effects of these proposed ELGs. The potentially significant effects of this rule on energy supply, distribution or use concern the electric power sector. EPA's analysis found that the proposed ELGs would not cause effects in the electric power sector that would constitute a significant adverse effect under Executive Order 13211. Namely, the Agency's analysis found that this rule would not reduce electricity production in excess of 1 billion kilowatt hours per year or in excess of 500 megawatts of installed capacity, and therefore would not constitute a significant regulatory action under Executive Order 13211.
For more detail on the potential energy effects of this proposal, see Chapter 10 in the RIA report.
Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (“NTTAA”), Public Law 104–113, 12(d) (15 U.S.C. 272 note), directs EPA to use voluntary consensus standards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by voluntary consensus standards bodies. NTTAA directs EPA to provide Congress, through OMB, explanations when the Agency decides not to use available and applicable voluntary consensus standards.
This rulemaking does not involve technical standards, for example, in the measurement of pollutant loads. Nothing in this proposed rule would prevent the use of voluntary consensus standards for such measurement where available, and EPA encourages permitting authorities and regulated entities to do so. Therefore, EPA is not considering the use of any voluntary consensus standards.
Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in the United States.
EPA has determined that this proposed rule will not have disproportionately high and adverse human health or environmental effects on minority or low-income populations because it increases the level of environmental protection for all affected populations without having any disproportionately high and adverse human health or environmental effects on any population, including any minority or low-income population.
To meet the objectives of Executive Order 12898, EPA examined whether these proposed ELGs will have potential environmental justice concerns in the areas affected by steam electric plant
EPA compared demographic data from the 2010 Census for benefit regions with corresponding characteristics at the state and national levels. This analysis focuses on the spatial distribution of minority and low-income groups to determine whether these groups are more or less represented in the populations expected to benefit from the proposed ELGs. The demographic characteristics that EPA analyzed include: percent African Americans, percent Native American, Eskimo, or Aleut, percent Asian or Pacific Islander, percent of the population below the poverty level, and median income. This analysis shows that approximately 14 percent of households in affected populations are below the poverty threshold, and 25 percent of them are minority, compared with national averages of 14 percent and 36 percent, respectively. Additionally, the median household income in affected populations is $48,579, while it is $51,914 nationally.
Of the 344 benefit regions defined in the analysis (within 100 miles of an affected plant), 28 regions (8 percent) may have Environmental Justice concerns under all three metrics, 79 regions (23 percent) under two metrics, and 194 regions (56 percent) under one metric. Forty-three regions (13 percent) would not be considered has having Environmental Justice concerns under any of the metrics.
This analysis indicates that minority and low-income communities are expected to benefit as much as anyone from the proposed ELGs.
The following acronyms and abbreviations are used in this document.
Facility
Environmental protection, Electric power generation, Power plants, Waste treatment and disposal, Water pollution control.
Therefore, 40 CFR chapter I is proposed to be amended as follows:
Secs. 101; 301; 304(b), (c), (e), and (g); 306; 307; 308 and 501, Clean Water Act (Federal Water Pollution Control Act Amendments of 1972, as amended; 33 U.S.C. 1251; 1311; 1314(b), (c), (e), and (g); 1316; 1317; 1318 and 1361).
The provisions of this part apply to discharges resulting from the operation of a generating unit by an establishment whose generation of electricity is the predominant source of revenue or principal reason for operation, and which results primarily from a process utilizing fossil-type fuel (coal, oil, or gas), fuel derived from fossil fuel (e.g., petroleum coke, synthesis gas), or nuclear fuel in conjunction with a thermal cycle employing the steam water system as the thermodynamic medium. This part applies to discharges associated with both the combustion turbine and steam turbine portions of a combined cycle generating unit. Facilities defined as new sources under the 1982 new source performance standards specified in §§ 423.15(a) and 423.17(a) of this part continue to be subject to those standards. Units that qualify as 1982 new sources are also subject to revised BAT effluent limitations specified in § 423.13 of this part (for direct dischargers) or the revised pretreatment standards specified in § 423.16 of this part (for indirect dischargers). These revised limitations and standards constitute amendments to the new source performance standards applicable to 1982 new sources.
The revised and added paragraphs read as follows:
(b) The term low volume waste sources means, taken collectively as if from one source, wastewater from all sources except those for which specific limitations are otherwise established in this part. Low volume waste sources include, but are not limited to, the following: wastewaters from ion exchange water treatment systems, water treatment evaporator blowdown, laboratory and sampling streams, boiler blowdown, floor drains, cooling tower basin cleaning wastes, recirculating house service water systems, and wet scrubber air pollution control systems whose primary purpose is particulate removal. Sanitary wastes, air conditioning wastes, and wastewater from carbon capture or sequestration systems are not included in this definition.
(e) The term fly ash means the ash that is carried out of the furnace by a gas stream and collected by a capture device such as a mechanical precipitator, electrostatic precipitator, or fabric filter. Economizer ash is included in this definition when it is collected with fly ash. Ash is not included in this definition when it is collected in wet scrubber air pollution control systems whose primary purpose is particulate removal.
(n) The term flue gas desulfurization (FGD) wastewater means any process wastewater generated from a wet flue gas desulfurization scrubber system, including any solids separation or solids dewatering processes.
(o) The term flue gas mercury control wastewater means any process wastewater generated from an air pollution control system installed or operated for the purpose of removing mercury from flue gas. This includes fly ash collection systems when the particulate control system follows the injection of sorbents or implementation of other controls to remove mercury from flue gas. Flue gas desulfurization systems are not included in this definition.
(p) The term transport water means any process wastewater that is used to convey fly ash or bottom ash from the ash collection equipment and has direct contact with the ash.
(q) The term gasification wastewater means any process wastewater generated from a system used to create synthesis gas from fuels such as coal or petroleum coke. Gasification wastewater includes, but is not limited to, the following: slag handling wastewater, sour/grey water (which includes condensate generated for gas cooling, as well as other wastestreams), CO
(r) The term combustion residual leachate means leachate from landfills or surface impoundments containing residuals from the combustion of fossil or fossil-derived fuel. Leachate includes liquid, including any suspended or dissolved constituents in the liquid, that has percolated through or drained from waste or other materials placed in a landfill, or that pass through the containment structure (e.g., bottom, dikes, berms) of a surface impoundment. Leachate also includes the terms seepage, leak, and leakage, which are generally used in reference to leachate from an impoundment.
(s) The term oil-fired unit means a generating unit that uses oil as the primary or secondary fuel source and does not use a gasification process or any coal or petroleum coke as a fuel source. This definition does not include units that use oil only for start up or flame-stabilization purposes.
(t) The term sufficiently sensitive analytical method means a method that ensures the sample-specific quantitation level for the wastewater being analyzed is at or below the level of the effluent limitation.
(u) The term nonchemical metal cleaning waste means any wastewater resulting from the cleaning of any metal process equipment without chemical cleaning compounds, including, but not limited to, boiler tube cleaning, boiler fireside cleaning, and air preheater cleaning.
The revised and added paragraphs read as follows:
(b) * * *
(11) The quantity of pollutants discharged in FGD wastewater, flue gas mercury control wastewater, combustion residual leachate, or gasification wastewater shall not exceed the quantity determined by multiplying the flow of the applicable wastewater times the concentration listed in the following table:
(12) At the permitting authority's discretion, the quantity of pollutant allowed to be discharged may be expressed as a concentration limitation instead of the any mass based limitations specified in paragraphs (b)(3) through (b)(11) of this section. Concentration limitations shall be those concentrations specified in this section.
(13) In the event that wastestreams from various sources are combined for treatment or discharge, the quantity of each pollutant or pollutant property controlled in paragraphs (b)(1) through (b)(12) of this section attributable to each controlled waste source shall not exceed the specified limitations for that waste source.
(f)(1) Except for those discharges to which paragraph (f)(2) of this section applies, the quantity of pollutants discharged in nonchemical metal cleaning wastes shall not exceed the quantity determined by multiplying the flow of nonchemical metal cleaning wastes times the concentration listed in the following table:
(2) For those discharges of nonchemical metal cleaning waste that are currently authorized pursuant to limitations based on requirements in § 423.12(b)(3) for low-volume waste, the quantity of pollutants discharged in nonchemical metal cleaning wastes shall not exceed the quantity determined by multiplying the flow of nonchemical metal cleaning wastes times the concentration listed in § 423.12(b)(3).
(g)(1) Except for those discharges to which paragraph (g)(2) of this section applies, dischargers must meet the effluent limitations in this paragraph by a date determined by the permitting authority that is as soon as possible within the next permit cycle beginning July 1, 2017. These effluent limitations apply to pollutants in FGD wastewater generated on or after the date the permitting authority has determined is as soon as possible. Such effluent limitations shall not allow the quantity of pollutants in FGD wastewater to exceed the quantity determined by multiplying the flow of FGD wastewater times the concentration listed in the following table:
(2) For any electric generating unit with a total nameplate capacity of less than or equal to 50 megawatts or that is an oil-fired unit, the quantity of pollutants discharged in FGD wastewater shall not exceed the quantity determined by multiplying the flow of FGD wastewater times the concentration listed in § 423.12(b)(11).
(3) A discharger must demonstrate compliance with the effluent limitations in paragraph (g)(1) of this section, as applicable, by monitoring for all pollutants (except pH) at a point prior to use of the FGD wastewater in any other plant process or commingling of the FGD wastewater with any water or other process wastewater, except for any combustion residual leachate or any other FGD wastewater. Compliance with the effluent limitations must reflect results obtained from sufficiently sensitive analytical methods.
All proposed revisions to § 423.13(g) reflect proposed Option 4a, Option 3, and Option 3b (for units located at facilities with a total wet-scrubbed capacity of 2,000 MW or more), only. Under proposed Option 3a and Option 3b (for units located at facilities with a total wet-scrubbed capacity of less than 2,000 MW), BAT would continue to need to be determined on a site-specific basis using best professional judgment.
(h)(1) Except for those discharges to which paragraph (h)(2) of this section applies, dischargers must meet the discharge prohibition in this paragraph by a date determined by the permitting authority that is as soon as possible within the next permit cycle beginning July 1, 2017. There shall be no discharge of wastewater pollutants from fly ash transport water generated on or after the date the permitting authority determines is as soon as possible. Whenever fly ash transport water is used in any other plant process or is sent to a treatment system at the plant, the resulting effluent must comply with the discharge prohibition in this paragraph.
(2) For any electric generating unit with a total nameplate generating capacity of less than or equal to 50 megawatts or that is an oil-fired unit, the quantity of pollutants discharged in fly ash transport water shall not exceed the quantity determined by multiplying the flow of fly ash transport water times the concentration listed in § 423.12(b)(4).
(i)(1) Except for those discharges to which paragraph (i)(2) of this section applies, dischargers must meet the discharge prohibition in this paragraph by a date determined by the permitting authority that is as soon as possible within the next permit cycle beginning July 1, 2017. There shall be no discharge of wastewater pollutants from flue gas mercury control wastewater generated on or after the date the permitting authority determines is as soon as possible. Whenever flue gas mercury control wastewater is used in any other plant process or is sent to a treatment system at the plant, the resulting effluent must comply with the discharge prohibition in this paragraph.
(2) For any electric generating unit with a total nameplate generating capacity of less than or equal to 50 megawatts or that is an oil-fired unit, the quantity of pollutants discharged in flue gas mercury control wastewater shall not exceed the quantity determined by multiplying the flow of flue gas mercury control wastewater times the concentration listed in § 423.12(b)(11).
(j)(1) Except for those discharges to which paragraph (j)(2) of this section applies, dischargers must meet the effluent limitations in this paragraph by a date determined by the permitting authority that is as soon as possible within the next permit cycle beginning July 1, 2017. Such effluent limitations shall not allow the quantity of pollutants in gasification wastewater to exceed the quantity determined by multiplying the flow of gasification wastewater times the concentration listed in the following table:
(2) For any electric generating unit with a total nameplate generating capacity of less than or equal to 50 megawatts or that is an oil-fired unit, the quantity of pollutants discharged in gasification wastewater shall not exceed the quantity determined by multiplying the flow of gasification wastewater times the concentration listed in § 423.12(b)(11).
(3) A discharger must demonstrate compliance with the effluent limitations in paragraph (j)(1) of this section, as applicable, by monitoring for all pollutants (except pH) at a point prior to use of the gasification wastewater in any other plant process or commingling of the gasification wastewater with water or any other process wastewater. Compliance with the effluent limitations must reflect results obtained from sufficiently sensitive analytical methods.
(k)(1) Except for those discharges to which paragraph (k)(2) of this section applies, dischargers must meet the discharge prohibition in this paragraph by a date determined by the permitting authority that is as soon as possible within the next permit cycle beginning July 1, 2017. There shall be no discharge of wastewater pollutants from bottom ash transport water generated on or after the date the permitting authority determines is as soon as possible. Whenever bottom ash transport water is used in any other plant process or is sent to a treatment system at the plant, the resulting effluent must comply with the discharge prohibition in this paragraph.
(2) For any electric generating unit with a total nameplate generating capacity of less than or equal to 400 megawatts or that is an oil-fired unit, the quantity of pollutants discharged in bottom ash transport water shall not exceed the quantity determined by multiplying the flow of the applicable wastewater times the concentration in § 423.12(b)(4).
All proposed revisions to § 423.13(k) reflect proposed Option 4a, only. Under proposed Option 3, Option 3a, and Option 3b, § 423.13(k) would be revised to specify that the quantity of pollutants discharged in bottom ash transport water shall not exceed the quantity determined by multiplying the flow of the applicable wastewater times the concentration in § 423.12(b)(4).
(l) The quantity of pollutants discharged in combustion residual leachate shall not exceed the quantity determined by multiplying the flow of leachate times the concentration listed in § 423.12(b)(11).
(m) At the permitting authority's discretion, the quantity of pollutant allowed to be discharged may be expressed as a concentration limitation instead of any mass based limitations specified in paragraphs (b) through (l) of this section. Concentration limitations shall be those concentrations specified in this section.
(n) In the event that wastestreams from various sources are combined for treatment or discharge, the quantity of each pollutant or pollutant property controlled in paragraphs (a) through (m) of this section attributable to each controlled waste source shall not exceed the specified limitation for that waste source.
(a) 1982 New source performance standards. Any new source as of November 19, 1982, subject to this subpart, must achieve the following new source performance standards and the revised requirements of § 423.13 of this part, published on [insert date of publication of final rule]:
(1) The pH of all discharges, except once through cooling water, shall be within the range of 6.0–9.0.
(2) There shall be no discharge of polychlorinated biphenyl compounds such as those commonly used for transformer fluid.
(3) The quantity of pollutants discharged from low volume waste sources shall not exceed the quantity determined by multiplying the flow of low volume waste sources times the concentration listed in the following table:
(4) The quantity of pollutants discharged in chemical metal cleaning wastes shall not exceed the quantity determined by multiplying the flow of chemical metal cleaning wastes times the concentration listed in the following table:
(5) [Reserved].
(6) The quantity of pollutants discharged in bottom ash transport water shall not exceed the quantity determined by multiplying the flow of the bottom ash transport water times the concentration listed in the following table:
(7) There shall be no discharge of wastewater pollutants from fly ash transport water. Whenever fly ash transport water is used in any other plant process or is sent to a treatment system at the plant, the resulting effluent must comply with the discharge prohibition in this paragraph.
(8)(i) For any plant with a total rated electric generating capacity of 25 or more megawatts, the quantity of pollutants discharged in once through cooling water from each discharge point shall not exceed the quantity determined by multiplying the flow of once through cooling water from each discharge point times the concentration listed in the following table:
(ii) Total residual chlorine may not be discharged from any single generating unit for more than two hours per day unless the discharger demonstrates to the permitting authority that discharge for more than two hours is required for macroinvertebrate control. Simultaneous multi-unit chlorination is permitted.
(9)(i) For any plant with a total rated generating capacity of less than 25 megawatts, the quantity of pollutants discharged in once through cooling water shall not exceed the quantity determined by multiplying the flow of once through cooling water sources times the concentration listed in the following table:
(ii) Neither free available chlorine nor total residual chlorine may be discharged from any unit for more than two hours in any one day and not more than one unit in any plant may discharge free available or total residual chlorine at any one time unless the utility can demonstrate to the Regional Administrator or State, if the State has NPDES permit issuing authority, that the units in a particular location cannot operate at or below this level of chlorination.
(10)(i) The quantity of pollutants discharged in cooling tower blowdown shall not exceed the quantity determined by multiplying the flow of cooling tower blowdown times the concentration listed below:
(ii) Neither free available chlorine nor total residual chlorine may be discharged from any unit for more than two hours in any one day and not more than one unit in any plant may discharge free available or total residual chlorine at any one time unless the utility can demonstrate to the Regional Administrator or State, if the State has NPDES permit issuing authority, that the units in a particular location cannot operate at or below this level of chlorination.
(iii) At the permitting authority's discretion, instead of the monitoring in 40 CFR 122.11(b), compliance with the limitations for the 126 priority pollutants in paragraph (a)(10)(i) of this section may be determined by engineering calculations which demonstrate that the regulated pollutants are not detectable in the final discharge by the analytical methods in 40 CFR part 136.
(11) Subject to the provisions of § 423.15(a)(12), the quantity or quality of pollutants or pollutant parameters discharged in coal pile runoff shall not exceed the limitations specified below:
(12) Any untreated overflow from facilities designed, constructed, and operated to treat the coal pile runoff which results from a 10 year, 24 hour rainfall event shall not be subject to the limitations in § 423.15(a)(11).
(13) At the permitting authority's discretion, the quantity of pollutant allowed to be discharged may be expressed as a concentration limitation instead of any mass based limitations specified in paragraphs (a)(3) through (a)(10) of this section. Concentration limits shall be based on the concentrations specified in this section.
(14) In the event that wastestreams from various sources are combined for treatment or discharge, the quantity of each pollutant or pollutant property controlled in paragraphs (a)(1) through (a)(13) of this section attributable to each controlled waste source shall not exceed the specified limitation for that waste source.
(The information collection requirements contained in paragraphs (a)(8)(ii), (a)(9)(ii), and (a)(10)(ii) were approved by the Office of Management and Budget under control number 2040–0040. The information collection requirements contained in paragraph (a)(10)(iii) were approved under control number 2040–0033.)
(b) 2014 New source performance standards. Any new source as of [insert date of publication of final rule], subject
(1) The pH of all discharges, except once through cooling water, shall be within the range of 6.0–9.0.
(2) There shall be no discharge of polychlorinated biphenyl compounds such as those commonly used for transformer fluid.
(3) The quantity of pollutants discharged from low volume waste sources shall not exceed the quantity determined by multiplying the flow of low volume waste sources times the concentration listed in the following table:
(4) The quantity of pollutants discharged in chemical metal cleaning wastes shall not exceed the quantity determined by multiplying the flow of chemical metal cleaning wastes times the concentration listed in the following table:
(5) The quantity of pollutants discharged in nonchemical metal cleaning wastes shall not exceed the quantity determined by multiplying the flow of nonchemical metal cleaning wastes times the concentration listed in the following table:
(6) There shall be no discharge of wastewater pollutants from bottom ash transport water. Whenever bottom ash transport water is used in any other plant process or is sent to a treatment system at the plant, the resulting effluent must comply with the discharge prohibition in this paragraph.
(7) There shall be no discharge of wastewater pollutants from fly ash transport water. Whenever fly ash transport water is used in any other plant process or is sent to a treatment system at the plant, the resulting effluent must comply with the discharge prohibition in this paragraph.
(8)(i) For any plant with a total rated electric generating capacity of 25 or more megawatts, the quantity of pollutants discharged in once through cooling water from each discharge point shall not exceed the quantity determined by multiplying the flow of once through cooling water from each discharge point times the concentration listed in the following table:
(ii) Total residual chlorine may not be discharged from any single generating
(9)(i) For any plant with a total rated generating capacity of less than 25 megawatts, the quantity of pollutants discharged in once through cooling water shall not exceed the quantity determined by multiplying the flow of once through cooling water sources times the concentration listed in the following table:
(ii) Neither free available chlorine nor total residual chlorine may be discharged from any unit for more than two hours in any one day and not more than one unit in any plant may discharge free available or total residual chlorine at any one time unless the utility can demonstrate to the Regional Administrator or State, if the State has NPDES permit issuing authority, that the units in a particular location cannot operate at or below this level of chlorination.
(10)(i) The quantity of pollutants discharged in cooling tower blowdown shall not exceed the quantity determined by multiplying the flow of cooling tower blowdown times the concentration listed below:
(ii) Neither free available chlorine nor total residual chlorine may be discharged from any unit for more than two hours in any one day and not more than one unit in any plant may discharge free available or total residual chlorine at any one time unless the utility can demonstrate to the Regional Administrator or State, if the State has NPDES permit issuing authority, that the units in a particular location cannot operate at or below this level of chlorination.
(iii) At the permitting authority's discretion, instead of the monitoring in 40 CFR 122.11(b), compliance with the limitations for the 126 priority pollutants in paragraph (b)(10)(i) of this section may be determined by engineering calculations which demonstrate that the regulated pollutants are not detectable in the final discharge by the analytical methods in 40 CFR part 136.
(11) Subject to the provisions of § 423.15(b)(12), the quantity or quality of pollutants or pollutant parameters discharged in coal pile runoff shall not exceed the limitations specified below:
(12) Any untreated overflow from facilities designed, constructed, and operated to treat the coal pile runoff which results from a 10 year, 24 hour rainfall event shall not be subject to the limitations in § 423.15(b)(11).
(13)(i) The quantity of pollutants discharged in FGD wastewater shall not exceed the quantity determined by multiplying the flow of FGD wastewater times the concentration listed in the following table:
(ii) A discharger must demonstrate compliance with the standards in paragraph (b)(13)(i) of this section, as applicable, by monitoring for all pollutants (except pH) at a point prior to use of the FGD wastewater in any other plant process or commingling of the FGD wastewater with any water or other process wastewater, except for any combustion residual leachate or any other FGD wastewater. Compliance with the standards must reflect results obtained from sufficiently sensitive analytical methods.
(14) There shall be no discharge of wastewater pollutants from flue gas mercury control wastewater. Whenever flue gas mercury control wastewater is used in any other plant process or is sent to a treatment system at the plant, the resulting effluent must comply with the discharge prohibition in this paragraph.
(15)(i) The quantity of pollutants discharged in gasification wastewater shall not exceed the quantity determined by multiplying the flow of gasification wastewater times the concentration listed in the following table:
(ii) A discharger must demonstrate compliance with the standards in paragraph (b)(15)(i) of this section, as applicable, by monitoring for all pollutants (except pH) prior to use of the gasification wastewater in any other plant process or commingling of the gasification wastewater with any water or other process wastewater. Compliance with the standards must reflect results obtained from sufficiently sensitive analytical methods.
(16)(i) The quantity of pollutants discharged in combustion residual leachate shall not exceed the quantity determined by multiplying the flow of combustion residual leachate times the concentration listed in the following table:
(ii) A discharger must demonstrate compliance with the standards in paragraph (b)(16)(i) of this section, as applicable, by monitoring for all pollutants (except pH) at a point prior to use of the combustion residual leachate in any other plant process or commingling of the combustion residual leachate with any water or other process wastewater, except for any FGD wastewater or any other combustion residual leachate. Compliance with the effluent limitations must reflect results obtained from sufficiently sensitive analytical methods.
(17) At the permitting authority's discretion, the quantity of pollutant allowed to be discharged may be expressed as a concentration limitation instead of any mass based limitations specified in paragraphs (b)(3) through (b)(16) of this section. Concentration limits shall be based on the concentrations specified in this section.
(18) In the event that wastestreams from various sources are combined for treatment or discharge, the quantity of each pollutant or pollutant property controlled in paragraphs (b)(1) through (b)(16) of this section attributable to each controlled waste source shall not exceed the specified limitation for that waste source.
(c) Except for those discharges of nonchemical metal cleaning waste that are currently authorized without meeting standards for copper, the pollutants discharged in nonchemical metal cleaning wastes shall not exceed
(e)(1) For any electric generating unit with a total nameplate generating capacity of more than 50 megawatts and that is not an oil-fired unit, dischargers must meet the standards in this paragraph by a date determined by the control authority that is as soon as possible beginning July 1, 2017. These standards apply to pollutants in FGD wastewater generated on or after a date determined by the control authority that is as soon as possible beginning July 1, 2017. Such effluent limitations shall not allow the quantity of pollutants in FGD wastewater to exceed the quantity determined by multiplying the flow of FGD wastewater times the concentration listed in the following table:
(2) A discharger must demonstrate compliance with the standards in paragraph (e)(1) of this section, as applicable, by monitoring for all pollutants (except pH) at a point prior to use of the FGD wastewater in any other plant process or commingling of the FGD wastewater with any water or other process wastewater, except for any combustion residual leachate or FGD wastewater. Compliance with the effluent limitations must reflect results obtained from sufficiently sensitive analytical methods.
All proposed revisions to section 423.16(e) reflect proposed Option 4a, Option 3, and Option 3b (for units located a facilities with a total wet-scrubbed capacity of 2,000 MW or more), only. Under proposed Option 3a and Option 3b (for units located at facilities with a total wet-scrubbed capacity of less than 2,000 MW), POTWS would need to develop local limits to address the introduction of pollutants found in FGD wastewater by steam electric plants to the POTWs that cause pass through or interference, as specified in 40 CFR 403.5(c)(2).
(f) For any electric generating unit with a total nameplate generating capacity of more than 50 megawatts and that is not an oil-fired unit, there shall be no discharge of wastewater pollutants from fly ash transport water generated on or after a date determined by the control authority that is as soon as possible beginning July 1, 2017. Whenever fly ash transport water is used in any other plant process or is sent to a treatment system at the plant, the resulting effluent must comply with the discharge prohibition in this paragraph.
(g) For any electric generating unit with a total nameplate generating capacity of more than 400 megawatts and that is not an oil-fired unit, there shall be no discharge of wastewater pollutants from bottom ash transport water generated on or after a date determined by the control authority that is as soon as possible beginning July 1, 2017. Whenever bottom ash transport water is used in any other plant process or is sent to a treatment system at the plant, the resulting effluent must comply with the discharge prohibition in this paragraph.
All proposed revisions to section 423.16(g) reflect proposed Option 4a, only. For proposed Option 3, Option 3a, and Option 3b, the regulations would not specify a PSES for bottom ash transport water.
(h) For any electric generating unit with a total nameplate generating capacity of more than 50 megawatts and that is not an oil-fired unit, there shall be no discharge of wastewater pollutants from flue gas mercury control wastewater generated on or after a date determined by the control authority that is as soon as possible beginning July 1, 2017. Whenever flue gas mercury control wastewater is used in any other plant process or is sent to a treatment system at the plant, the resulting effluent must comply with the discharge prohibition in this paragraph.
(i)(1) For any electric generating unit with a total nameplate generating capacity of more than 50 megawatts and that is not an oil-fired unit, dischargers must meet the standards in this paragraph by a date determined by the control authority that is as soon as possible beginning July 1, 2017. These standards apply to pollutants in gasification wastewater generated on or after a date determined by the control authority that is as soon as possible beginning July 1, 2017. Such effluent limitations shall not allow the quantity of pollutants in gasification wastewater to exceed the quantity determined by multiplying the flow of gasification wastewater times the concentration listed in the following table:
(2) A discharger must demonstrate compliance with the standards in paragraph (i)(1) of this section, as applicable, by monitoring for all pollutants (except pH) at a point prior to use of the gasification wastewater in any other plant process or commingling of the gasification wastewater with any water or other process wastewater. Compliance with the standards must reflect results obtained from sufficiently sensitive analytical methods.
(a) 1982 Pretreatment standards for new sources. Except as provided in 40 CFR 403.7, any new source as of November 19, 1982, subject to this subpart, which introduces pollutants into a publicly owned treatment works must comply with 40 CFR part 403 and the following pretreatment standards for new sources (PSNS), and the revised requirements of § 423.16 of this part, published on [insert date of publication of final rule]:
(1) There shall be no discharge of polychlorinated biphenyl compounds such as those used for transformer fluid.
(2) The pollutants discharged in chemical metal cleaning wastes shall not exceed the concentration listed in the following table:
(3) [Reserved].
(4)(i) The pollutants discharged in cooling tower blowdown shall not exceed the concentration listed in the following table:
(ii) At the permitting authority's discretion, instead of the monitoring in 40 CFR 122.11(b), compliance with the limitations for the 126 priority pollutants in paragraph (a)(4)(i) of this section may be determined by engineering calculations which demonstrate that the regulated pollutants are not detectable in the final discharge by the analytical methods in 40 CFR part 136.
(5) There shall be no discharge of wastewater pollutants from fly ash transport water. Whenever fly ash transport water is used in any other plant process or is sent to a treatment system at the plant, the resulting effluent must comply with the discharge prohibition in this paragraph.
(b) 2014 Pretreatment standards for new sources. Except as provided in 40 CFR 403.7, any new source as of [insert date of publication of final rule], subject to this subpart, which introduces pollutants into a publicly owned treatment works must comply with 40 CFR part 403 and the following pretreatment standards for new sources (PSNS):
(1) There shall be no discharge of polychlorinated biphenyl compounds such as those used for transformer fluid.
(2) The pollutants discharged in chemical metal cleaning wastes shall not exceed the concentration listed in the following table:
(3) The pollutants discharged in nonchemical metal cleaning wastes shall not exceed the concentration listed in the following table:
(4)(i) The pollutants discharged in cooling tower blowdown shall not exceed the concentration listed in the following table:
(ii) At the permitting authority's discretion, instead of the monitoring in 40 CFR 122.11(b), compliance with the limitations for the 126 priority pollutants in paragraph (b)(4)(i) of this section may be determined by engineering calculations which demonstrate that the regulated pollutants are not detectable in the final discharge by the analytical methods in 40 CFR part 136.
(5) There shall be no discharge of wastewater pollutants from fly ash transport water. Whenever fly ash transport water is used in any other plant process or is sent to a treatment system at the plant, the resulting effluent must comply with the discharge prohibition in this paragraph.
(6)(i) The quantity of pollutants discharged in FGD wastewater shall not exceed the quantity determined by multiplying the flow of FGD wastewater times the concentration listed in the following table:
(ii) A discharger must demonstrate compliance with the standards in paragraph (b)(6)(i) of this section, as applicable, by monitoring for all pollutants (except pH) at a point prior to use of the FGD wastewater in any other plant process or commingling of the FGD wastewater with any water or other process wastewater, except for any combustion residual leachate or any other FGD wastewater. Compliance with the standards must reflect results obtained from sufficiently sensitive analytical methods.
(7) There shall be no discharge of wastewater pollutants from flue gas mercury control wastewater. Whenever flue gas mercury control wastewater is used in any other plant process or is sent to a treatment system at the plant, the resulting effluent must comply with the discharge prohibition in this paragraph.
(8) There shall be no discharge of wastewater pollutants from bottom ash transport water. Whenever bottom ash transport water is used in any other plant process or is sent to a treatment system at the plant, the resulting effluent must comply with the discharge prohibition in this paragraph.
(9)(i) The quantity of pollutants discharged in gasification wastewater shall not exceed the quantity determined by multiplying the flow of gasification wastewater times the concentration listed in the following table:
(ii) A discharger must demonstrate compliance with the standards in paragraph (b)(9)(i) of this section, as applicable, by monitoring for all pollutants (except pH) at a point prior to use of the gasification wastewater in any other plant process or commingling of the gasification wastewater with any water or other process wastewater. Compliance with the standards must reflect results obtained from sufficiently sensitive analytical methods.
(10)(i) The quantity of pollutants discharged in combustion residual leachate shall not exceed the quantity determined by multiplying the flow of combustion residual leachate times the concentration listed in the following table:
(ii) A discharger must demonstrate compliance with the standards in paragraph (b)(10)(i) of this section, as applicable, by monitoring for all pollutants (except pH) at a point prior to use of the combustion residual leachate in any other plant process or commingling of the combustion residual leachate with any water or other process wastewater, except for any FGD wastewater or any other combustion residual leachate. Compliance with the effluent limitations must reflect results obtained from sufficiently sensitive analytical methods.