Agricultural Marketing Service
Foreign Agricultural Service
Forest Service
Natural Resources Conservation Service
Foreign-Trade Zones Board
Industry and Security Bureau
International Trade Administration
National Oceanic and Atmospheric Administration
Defense Acquisition Regulations System
Pipeline and Hazardous Materials Safety Administration
Federal Energy Regulatory Commission
Centers for Disease Control and Prevention
Children and Families Administration
Food and Drug Administration
National Institutes of Health
Substance Abuse and Mental Health Services Administration
Coast Guard
Federal Emergency Management Agency
Antitrust Division
Justice Programs Office
Disability Employment Policy Office
Employee Benefits Security Administration
Employment and Training Administration
Federal Aviation Administration
Federal Motor Carrier Safety Administration
Federal Railroad Administration
Pipeline and Hazardous Materials Safety Administration
Comptroller of the Currency
Thrift Supervision Office
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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Federal Aviation Administration (FAA), DOT.
Final Rule.
This establishes, amends, suspends, or revokes Standard Instrument Approach Procedures (SIAPs) and associated Takeoff Minimums and Obstacle Departure Procedures for operations at certain airports. These regulatory actions are needed because of the adoption of new or revised criteria, or because of changes occurring in the National Airspace System, such as the commissioning of new navigational facilities, adding new obstacles, or changing air traffic requirements. These changes are designed to provide safe and efficient use of the navigable airspace and to promote safe flight operations under instrument flight rules at the affected airports.
This rule is effective August 2, 2010. The compliance date for each SIAP, associated Takeoff Minimums, and ODP is specified in the amendatory provisions.
The incorporation by reference of certain publications listed in the regulations is approved by the Director of the Federal Register as of August 2, 2010.
Availability of matters incorporated by reference in the amendment is as follows:
1. FAA Rules Docket, FAA Headquarters Building, 800 Independence Avenue, SW., Washington, DC 20591;
2. The FAA Regional Office of the region in which the affected airport is located;
3. The National Flight Procedures Office, 6500 South MacArthur Blvd., Oklahoma City, OK 73169 or,
4. The National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202-741-6030, or go to:
1. FAA Public Inquiry Center (APA-200), FAA Headquarters Building, 800 Independence Avenue, SW., Washington, DC 20591; or
2. The FAA Regional Office of the region in which the affected airport is located.
Harry J. Hodges, Flight Procedure Standards Branch (AFS-420), Flight Technologies and Programs Divisions, Flight Standards Service, Federal Aviation Administration, Mike Monroney Aeronautical Center, 6500 South MacArthur Blvd., Oklahoma City, OK 73169 (
This rule amends Title 14 of the Code of Federal Regulations, part 97 (14 CFR part 97), by establishing, amending, suspending, or revoking SIAPS, Takeoff Minimums and/or ODPS. The complete regulators description of each SIAP and its associated Takeoff Minimums or ODP for an identified airport is listed on FAA form documents which are incorporated by reference in this amendment under 5 U.S.C. 552(a), 1 CFR part 51, and 14 CFR part 97.20. The applicable FAA Forms are FAA Forms 8260-3, 8260-4, 8260-5, 8260-15A, and 8260-15B when required by an entry on 8260-15A.
The large number of SIAPs, Takeoff Minimums and ODPs, in addition to their complex nature and the need for a special format make publication in the
This amendment to 14 CFR part 97 is effective upon publication of each separate SIAP, Takeoff Minimums and ODP as contained in the transmittal. Some SIAP and Takeoff Minimums and textual ODP amendments may have been issued previously by the FAA in a Flight Data Center (FDC) Notice to Airmen (NOTAM) as an emergency action of immediate flight safety relating directly to published aeronautical charts. The circumstances which created the need for some SIAP and Takeoff Minimums and ODP amendments may require making them effective in less than 30 days. For the remaining SIAPS and Takeoff Minimums and ODPS, an effective date at least 30 days after publication is provided.
Further, the SIAPs and Takeoff Minimums and ODPS contained in this amendment are based on the criteria contained in the U.S. Standard for Terminal Instrument Procedures (TERPS). In developing these SIAPS and Takeoff Minimums and ODPs, the TERPS criteria were applied to the conditions existing or anticipated at the affected airports. Because of the close and immediate relationship between these SIAPs, Takeoff Minimums and ODPs, and safety in air commerce, I find that notice and public procedures before adopting these SIAPS, Takeoff Minimums and ODPs are impracticable and contrary to the public interest and, where applicable, that good cause exists for making some SIAPs effective in less than 30 days.
The FAA has determined that this regulation only involves an established body of technical regulations for which frequent and routine amendments are necessary to keep them operationally current. It, therefore—(1) is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034; February 26, 1979); and (3) does not warrant preparation of a regulatory evaluation as the anticipated impact is so minimal. For the same reason, the FAA certifies that this amendment will not have a significant economic impact on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
Air traffic control, Airports, Incorporation by reference, and Navigation (Air).
49 U.S.C. 106(g), 40103, 40106, 40113, 40114, 40120, 44502, 44514, 44701, 44719, 44721-44722.
Federal Aviation Administration (FAA), DOT.
Final rule.
This rule establishes, amends, suspends, or revokes Standard Instrument Approach Procedures (SIAPs) and associated Takeoff Minimums and Obstacle Departure Procedures for operations at certain airports. These regulatory actions are needed because of the adoption of new or revised criteria, or because of changes occurring in the National Airspace System, such as the commissioning of new navigational facilities, adding new obstacles, or changing air traffic requirements. These changes are designed to provide safe and efficient
This rule is effective August 2, 2010. The compliance date for each SIAP, associated Takeoff Minimums, and ODP is specified in the amendatory provisions.
The incorporation by reference of certain publications listed in the regulations is approved by the Director of the Federal Register as of August 2, 2010.
Availability of matter incorporated by reference in the amendment is as follows:
1. FAA Rules Docket, FAA Headquarters Building, 800 Independence Avenue, SW., Washington, DC 20591;
2. The FAA Regional Office of the region in which the affected airport is located;
3. The National Flight Procedures Office, 6500 South MacArthur Blvd., Oklahoma City, OK 73169; or,
4. The National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202-741-6030, or go to:
1. FAA Public Inquiry Center (APA-200), FAA Headquarters Building, 800 Independence Avenue, SW., Washington, DC 20591; or
2. The FAA Regional Office of the region in which the affected airport is located.
Harry J. Hodges, Flight Procedure Standards Branch (AFS-420) Flight Technologies and Programs Division, Flight Standards Service, Federal Aviation Administration, Mike Monroney Aeronautical Center, 6500 South MacArthur Blvd., Oklahoma City, OK 73169 (
This rule amends title 14, Code of Federal Regulations, part 97 (14 CFR part 97) by amending the referenced SIAPs. The complete regulatory description of each SIAP is listed on the appropriate FAA Form 8260, as modified by the National Flight Data Center (FDC)/Permanent Notice to Airmen (P-NOTAM), and is incorporated by reference in the amendment under 5 U.S.C. 552(a), 1 CFR part 51, and § 97.20 of Title 14 of the Code of Federal Regulations.
The large number of SIAPs, their complex nature, and the need for a special format make their verbatim publication in the
This amendment to 14 CFR part 97 is effective upon publication of each separate SIAP as amended in the transmittal. For safety and timeliness of change considerations, this amendment incorporates only specific changes contained for each SIAP as modified by FDC/P-NOTAMs.
The SIAPs, as modified by FDC P-NOTAM, and contained in this amendment are based on the criteria contained in the U.S. Standard for Terminal Instrument Procedures (TERPS). In developing these changes to SIAPs, the TERPS criteria were applied only to specific conditions existing at the affected airports. All SIAP amendments in this rule have been previously issued by the FAA in an FDC NOTAM as an emergency action of immediate flight safety relating directly to published aeronautical charts. The circumstances which created the need for all these SIAP amendments require making them effective in less than 30 days.
Because of the close and immediate relationship between these SIAPs and safety in air commerce, I find that notice and public procedure before adopting these SIAPs are impracticable and contrary to the public interest and, where applicable, that good cause exists for making these SIAPs effective in less than 30 days.
The FAA has determined that this regulation only involves an established body of technical regulations for which frequent and routine amendments are necessary to keep them operationally current. It, therefore—(1) is not a “significant regulatory action”under Executive Order 12866; (2) is not a “significant rule”under DOT regulatory Policies and Procedures (44 FR 11034; February 26, 1979); and (3) does not warrant preparation of a regulatory evaluation as the anticipated impact is so minimal. For the same reason, the FAA certifies that this amendment will not have a significant economic impact on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
Air Traffic Control, Airports, Incorporation by reference, and Navigation (Air).
49 U.S.C. 106(g), 40103, 40106, 40113, 40114, 40120, 44502, 44514, 44701, 44719, 44721-44722.
By amending: § 97.23 VOR, VOR/DME, VOR or TACAN, and VOR/DME or TACAN; § 97.25 LOC, LOC/DME, LDA, LDA/DME, SDF, SDF/DME; § 97.27 NDB, NDB/DME; § 97.29 ILS, ILS/DME, MLS, MLS/DME, MLS/RNAV; § 97.31 RADAR SIAPs; § 97.33 RNAV SIAPs; and § 97.35 COPTER SIAPs, Identified as follows:
Bureau of Industry and Security, Commerce.
Interim final rule with request for comments.
In this interim final rule, the Bureau of Industry and Security (BIS) amends the Export Administration Regulations (EAR) to clarify that commodity classification determinations and advisory opinions BIS issues or has issued under the EAR are not and may not be relied upon as U.S. Government determinations that the items described therein are subject to the EAR, as opposed to the jurisdiction of another U.S. Government agency.
This rule is effective August 2, 2010. Comments must be received October 1, 2010.
You may submit comments, identified by RIN 0694-AE94, by any of the following methods:
•
•
•
•
Sheila Quarterman, Bureau of Industry and Security, Office of Exporter Services, Regulatory Policy Division, by phone at (202) 482-2440 or by fax (202) 482-3355.
BIS has jurisdiction over only those items and activities that are “subject to the EAR” as described in §§ 734.2(a) and 734.3(a) of the EAR. Items that are exclusively controlled for export or reexport by another agency of the U.S. Government are not “subject to the EAR.” 15 CFR 734.3(b)(1). If an item is exclusively subject to the jurisdiction of another agency, for example, the Department of State's Directorate of Defense Trade Controls (DDTC), the Department of the Treasury's Office of Foreign Assets Controls (OFAC), the U.S. Nuclear Regulatory Commission (NRC), the Department of Energy (DOE), or the Patent and Trademark Office (PTO), then one must comply with the regulations administered by that agency and need not consider the provisions of the EAR. 15 CFR 732.2(a)(1) and 734.3(b)(1). In order to determine whether an item is “subject to the EAR” or whether the item is subject to the exclusive export control jurisdiction of another U.S. government agency, a person is entitled to make jurisdictional determinations with respect to particular items based on a review of the relevant regulations. A person may also seek and receive official guidance from the other U.S. Government agencies regarding whether an item is subject to the exclusive export control jurisdiction of such agencies. In particular, DDTC has a process by which one may seek and receive a “commodity jurisdiction” (CJ) determination whether an item is subject to the International Traffic in Arms Regulations (ITAR). 22 CFR 120.4.
Unlike the ITAR, the EAR does not provide authority to make commodity jurisdiction determinations. Rather, as described in § 748.3(a) of the EAR, an exporter or other party may request that BIS provide (i) an official determination—called a “commodity classification”—of which, if any, of the EAR's Export Control Classification Numbers (ECCNs) describe the items subject to the request and (ii) advisory opinions, which are official guidance regarding how BIS interprets the EAR. ECCNs are the numbers and letters that identify items on the EAR's list of items controlled for export and reexport, and are found in the Commerce Control List (CCL) in Supplement No. 1 to Part 774 of the EAR. No other agency of the U.S. Government has the authority to issue determinations about the ECCN that applies to an item. Because BIS assigns all commodity classifications a Commodity Classification Automated Tracking System (CCATS) number, classifications are sometimes called CCATS. Sections 748.3(b) and 748.3(c) of the EAR describe the procedures for submitting commodity classification and advisory opinion requests, respectively.
Because BIS does not have the authority to issue commodity jurisdiction determinations, a BIS commodity classification only reflects whether each item identified in the commodity classification request is described in the CCL. Thus, prior to seeking a commodity classification, the applicant should have already determined—through a self-determination or with the assistance of another U.S. Government agency—that the item is not subject to the exclusive export control jurisdiction of another U.S. Government agency. In issuing a commodity classification, BIS is not making a determination of whether the item is or is not subject to the EAR. Similarly, although advisory opinions (unlike commodity classifications) may opine on matters beyond the interpretation of CCL provisions, advisory opinions also may not be relied upon or cited as evidence of whether or not the pertinent items are subject to the EAR.
The purpose of this interim final rule amending § 748.3(a), (b), and (c) of the EAR is to remind the public of the long-standing principle that commodity classifications and advisory opinions are not and may not be relied upon as U.S. Government determinations that the items described therein are subject to the EAR as opposed to the jurisdiction of another U.S. Government agency.
To further the educational and compliance objectives of this amendment, BIS will begin inserting the following reminder on all commodity classifications it issues:
This commodity classification sets forth the classification of the above-listed items if they are subject to the EAR. This commodity classification is not a determination by BIS as to whether the above-listed items are “subject to the EAR.” As defined and described in sections 734.2 through 734.4 of the EAR, the term “subject to the EAR” means, among other things, that the item(s) are not exclusively controlled for export or reexport by another agency of the U.S. Government.
BIS reminds the public of the availability of a webpage where sources of publicly available information on commodity classification may be found. The public may go to the following webpages for more information:
Since August 21, 2001, the Export Administration Act has been in lapse and the President, through Executive Order 13222 of August 17, 2001 (3 CFR, 2001 Comp., p. 783 (2002)), as extended most recently by the Notice of August 13, 2009 (74 FR 41325 (August 14, 2009)), has continued the EAR in effect under the International Emergency Economic Powers Act.
1. This rule has been determined to be not significant for the purposes of Executive Order 12866 of September 30, 1993 (58 FR 1735 (October 4, 1993)).
2. Notwithstanding any other provisions of law, no person is required to respond to nor be subject to a penalty for failure to comply with a collection of information, subject to the requirements of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
3. This rule does not contain policies with Federalism implications as that term is defined under Executive Order 13132.
4. The Department finds that there is good cause under 5 U.S.C. 553(b)(B) to waive the provisions of the Administrative Procedure Act requiring prior notice and the opportunity for public comment as unnecessary. This rule only clarifies existing provisions of the EAR regarding commodity classification determinations and advisory opinions, with respect to commodity jurisdiction decisions; such decisions, in turn, are governed by existing statute. Because this rule does not implement substantive changes, but merely clarifies the agency's long-held interpretation, it is unnecessary to provide prior notice and opportunity for public comment. The 30-delay in effectiveness required by 5 U.S.C. 553(d) is not applicable because this rule is not a substantive rule. In addition, because a notice of proposed rulemaking and an opportunity for public comment are not required to be given for this rule by 5 U.S.C. 553, or by any other law, the analytical requirements of the Regulatory Flexibility Act (5 U.S.C. 601
The period for submission of comments will close October 1, 2010. The Department will consider all comments received before the close of the comment period in developing final regulations. Comments received after the end of the comment period will be considered if possible, but their consideration cannot be assured. The Department will not accept public comments accompanied by a request that a part or all of the material be treated confidentially because of its business proprietary nature or for any other reason. The Department will return such comments and materials to the persons submitting the comments and will not consider them in the development of final regulations. All public comments on these regulations will be a matter of public record and will be available for public inspection and copying. In the interest of accuracy and completeness, the Department requires comments in written form (including fax or e-mail).
Oral comments must be followed by written memoranda, which will also be a matter of public record and will be available for public review and copying. Communications from agencies of the United States Government or foreign governments will not be available for public inspection.
The Office of Administration, Bureau of Industry and Security, U.S. Department of Commerce, displays these public comments on the Federal e-Rulemaking portal at
Administrative practice and procedure, Exports, Inventions and patents, Research Science and technology.
Administrative practice and procedure, Exports, Reporting and recordkeeping requirements.
50 U.S.C. app. 2401
(d) Commodity classification determinations and advisory opinions issued by BIS are not, and may not be relied upon as, determinations that the items in question are “subject to the EAR,” as described in § 748.3 of the EAR.
50 U.S.C. app. 2401
(a)
(b) * * *
(3) BIS assigns each of its commodity classifications a Commodity Classification Automated Tracking System (CCATS) number. Neither the BIS classification nor the CCATS number may be relied upon or cited as evidence that the U.S. Government has determined that the items described in the commodity classification
(c) * * *
(4) Advisory opinions are limited in scope to BIS's interpretation of EAR provisions. Advisory opinions differ from commodity classifications in that advisory opinions are not limited to the interpretation of provisions contained in the Commerce Control List. Advisory opinions may not be relied upon or cited as evidence that the U.S. Government has determined that the items described in the advisory opinion are not subject to the export control jurisdiction of another agency of the U.S. Government (
Coast Guard, DHS.
Temporary final rule.
The U.S. Coast Guard is establishing temporary moving security zones surrounding the HMCS NANAIMO (NCSM 702), HMCS EDMONTON (NCSM 703), and the HMCS BRANDON (NCSM 710) which include all waters within 100 yards from the vessels while underway in the Puget Sound Captain of the Port (COTP) Area of Responsibility (AOR). These security zones are necessary to help ensure the security of the vessels from sabotage or other subversive acts during Seafair Fleet Week and will do so by prohibiting any person or vessel from entering or remaining in the security zones unless authorized by the COTP, Puget Sound or Designated Representative.
This rule is effective from 8 a.m. until 11:59 p.m. on August 4, 2010 unless canceled sooner by the COTP.
Documents indicated in this preamble as being available in the docket are part of docket USCG-2010-0709 and are available online by going to
If you have questions on this temporary rule, call or e-mail LTJG Ian Hanna, Sector Seattle, Waterways Management Division, US Coast Guard; telephone 206-217-6045, e-mail
The Coast Guard is issuing this 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 publishing an NPRM would be impracticable due to the inherent compromise to security resulting from advertising in advance locations of naval vessels, both foreign and domestic.
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
Seattle's Seafair Fleet Week is an annual event which brings a variety of foreign military vessels to Seattle. The event draws large crowds and a number of vessels that are under inherent security risks due to their military functions. This rule is necessary to ensure the security of visiting foreign military vessels not covered under the Naval Vessel Protection Zone (NVPZ), and provides similar security measures while these vessels are transiting Puget Sound.
The temporary security zones established by this rule will prohibit any person or vessel from entering or remaining within 100 yards of the HMCS NANAIMO (NCSM 702), HMCS EDMONTON (NCSM 703), and the HMCS BRANDON (NCSM 710) while underway in the Puget Sound COTP AOR unless authorized by the COTP, Puget Sound, or Designated Representative. The security zones will be enforced by Coast Guard personnel. The COTP may also be assisted in the enforcement of the zones by other federal, state, or local agencies.
We developed this rule after considering numerous statutes and executive orders related to rulemaking. Below we summarize our analyses based on 13 of 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, and does not require an assessment of potential costs and benefits under section 6(a)(3) of that Order. The Office of Management and Budget has not reviewed it under that Order.
The Coast Guard bases this finding on the fact that the security zones will be in place for a limited period of time and vessel traffic will be able to transit around the security zones. Maritime traffic may also request permission to transit through the zones from the COTP, Puget Sound or Designated Representative.
Under the Regulatory Flexibility Act (5 U.S.C. 601-612), we have considered whether this rule would have a significant economic impact on a substantial number of small entities. 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 may be small entities; the owners and operators of
Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Pub. L. 104-121), we offer to assist small entities in understanding the rule so that they can better evaluate its effects on them and participate in the rulemaking process.
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 calls for no 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 State or local governments and would either preempt State law or impose a substantial direct cost of compliance on them. We have analyzed this rule under that Order and have determined that it 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 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.
We have analyzed this rule under Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use. We have determined that it is not a “significant energy action” under that order 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.
The National Technology Transfer and Advancement Act (NTTAA) (15 U.S.C. 272 note) directs agencies to use voluntary consensus standards in their regulatory activities unless the agency provides Congress, through the Office of Management and Budget, with an explanation of why using these standards would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (
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 concluded 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 is categorically excluded, under figure 2-1, paragraph (34)(g), of the Instruction. This rule involves the establishment of temporary security zones. An environmental analysis checklist and a categorical exclusion will be available in the docket where indicated under
Harbors, Marine safety, Navigation (water), Reporting and recordkeeping requirements, Security measures, Waterways.
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, 160.5; Pub. L. 107-295, 116 Stat. 2064; Department of Homeland Security Delegation No. 0170.1.
(a)
(b)
(c)
(d)
Environmental Protection Agency (EPA).
Notice of Adequacy.
In this notice, EPA is notifying the public that we have found that the motor vehicle emissions budgets for volatile organic compound (VOC) and nitrogen oxides (NO
This finding is effective August 17, 2010.
Melanie Zeman, Air Programs Branch, Environmental Protection Agency—Region 2, 290 Broadway, 25th Floor, New York, New York 10007-1866, (212) 637-4022,
The finding and the response to comments will be available at EPA's conformity Web site:
On February 8, 2008, New York State submitted reasonable further progress and attainment demonstration state implementation plans to EPA for its portion of the New York-Northern New Jersey-Long Island, NY-NJ-CT and Poughkeepsie, New York, 8-hour ozone nonattainment areas. The purpose of the New York State submittal was to demonstrate both of the areas progress toward attaining the 8-hour ozone National Ambient Air Quality Standard. The submittal included motor vehicle emissions budgets (“budgets”) for 2008 and 2009 for the Poughkeepsie 8-hour ozone nonattainment area and 2008 budgets for the New York portion of the New York-Northern New Jersey-Long Island, NY-NJ-CT nonattainment area for use by the State's metropolitan planning organizations in making transportation conformity determinations. On June 12, 2008, and June 2, 2008, respectively, the availability of the New York portion of the New York-Northern New Jersey-Long Island, NY-NJ-CT 8-hour ozone nonattainment area and the Poughkeepsie, New York 8-hour ozone nonattainment area transportation conformity budgets were posted on EPA's Web site for the purpose of soliciting public comments. The adequacy public comment period closed for the New York portion of the New York-Northern New Jersey-Long Island, NY-NJ-CT area budgets on July 14, 2008, and EPA received no public comments. The public comment period closed for the Poughkeepsie, New York area budgets on July 2, 2008. EPA's response to comments received during this period is posted on the EPA adequacy Web site listed below. Today's notice is simply an announcement of a finding that EPA has already made. EPA Region 2 sent a letter to New York State Department of Environmental Conservation on June 21, 2010. The findings letter states that the 2008 motor vehicle emissions budgets in New York's SIP submissions for both the New York portion of the New York-Northern New Jersey-Long Island, NY-NJ-CT and Poughkeepsie, New York 8-hour ozone nonattainment areas are adequate because they are consistent with the required rate of progress plan. With regard to the 2009 motor vehicle emissions budgets, the findings letter states that for the Poughkeepsie, New York 8-hour ozone nonattainment area, these budgets are adequate for transportation conformity purposes because they are consistent with the plan's demonstration of attainment. EPA's finding will also be announced on EPA's conformity Web site:
For informational purposes, EPA notes that on April 4, 2008, New York submitted to EPA a request for a voluntary reclassification of the New York-Northern New Jersey-Long Island, NY-NJ-CT 8-hour ozone nonattainment area from “moderate” to “serious” pursuant to section 181(b)(3) of the Act. Related to this request, New York provided EPA with 2011 and 2012 motor vehicle emissions budgets. EPA is continuing to review New York's request for a voluntary reclassification of the New York-Northern New Jersey-Long Island, NY-NJ-CT 8-hour ozone nonattainment area and therefore is not taking action on the 2011 or 2012 budgets at this time. EPA would take action on these budgets at the same time
Transportation conformity is required by section 176(c) of the Clean Air Act. EPA's conformity rule requires that transportation plans, programs, and projects conform to SIPs and establishes the criteria and procedures for determining whether they conform. Conformity to a SIP means that transportation activities will not produce new air quality violations, worsen existing violations, or delay timely attainment of the National Ambient Air Quality Standards.
The criteria by which we determine whether a SIP's motor vehicle emission budgets are adequate for conformity purposes are specified in 40 CFR 93.118(e)(4). Please note that an adequacy review is separate from EPA's completeness review, and it also should not be used to prejudge EPA's ultimate approval of the SIP. Even if we find a budget adequate, the SIP could later be disapproved.
EPA has described its process for determining the adequacy of submitted SIP budgets in 40 CFR 93.118(f). EPA has followed this rule in making these adequacy determinations. The motor vehicle emissions budgets being found adequate today are listed in Table 1.
Environmental protection, Air pollution control, Intergovernmental relations, Nitrogen dioxide, Ozone, Reporting and recordkeeping requirements, Volatile organic compounds.
42 U.S.C. 7401-7671 q.
Federal Communications Commission.
Final rule.
In this document, the Commission amends its rules to enable the deployment of mobile broadband services in the Wireless Communications Services (WCS) while limiting the potential for harmful interference to satellite radio users, aeronautical mobile telemetry (AMT) operations, and the Deep Space Network (DSN) research facility in Goldstone, CA. In addition, the Commission establishes enhanced performance requirements to ensure that WCS licensees use the spectrum intensively in the public interest. The Commission also adopts technical rules governing the operation of Satellite Digital Audio Radio Service (SDARS) terrestrial repeaters that will not constrain their function or deployment but will limit the potential for interference to adjacent-band WCS spectrum users, a blanket licensing regime for repeaters operating up to 12 kilowatts (kW) average equivalent isotropically radiated power (EIRP) that will facilitate their deployment, and rules that will ensure that SDARS repeaters remain truly complementary to a satellite-based service and are not used to transmit local programming or advertising.
Effective September 1, 2010, except for amendments to §§ 25.144(e)(3), 25.144(e)(8), 25.144(e)(9), 25.263(b), 25.263(c), 27.14(p)(7), 27.72(b), 27.72(c), 27.73(a), and 27.73(b), which contain information collection requirements that are not effective until approved by the Office of Management and Budget. The Commission will publish a document in the
WCS technical information: Thomas Derenge,
This is a summary of the Commission's
This document adopts new or revised information collection requirements subject to the Paperwork Reduction Act of 1995 (PRA), Public Law 104-13 (44 U.S.C. 3501-3520). The requirements will be submitted to the Office of Management and Budget (OMB) for
1. The current part 27 rules effectively preclude Wireless Communications Services (WCS) licensees from providing mobile broadband services, and the current part 25 rules do not provide technical rules or a licensing regime for SDARS terrestrial repeaters, which are currently authorized pursuant to grants of special temporary authority on a non-interference basis. In the
2. Specifically, the
3. Additionally, under the new rules adopted in the
4. WCS base and fixed stations in WCS Blocks A and B (
5. The
6. The
7. The
8. The
9. The
10. SDARS repeaters are also restricted to the simultaneous retransmission of the complete programming, and only that programming, transmitted by the SDARS licensee's satellite directly to the SDARS licensee's subscribers' receivers, and may not be used to distribute any information not also transmitted to all subscribers' receivers. SDARS operators may not use SDARS repeaters to retransmit regional spot beams.
11. As part of the
12. As required by the Regulatory Flexibility Act of 1980, as amended (RFA),
13. In this
14. In this
15.
16.
17.
18. Additionally, in the
19.
20. Additionally, the Commission adopted, for WCS fixed CPE devices operating above 2 Watts per 5-megahertz average EIRP, an OOBE attenuation factor of not less than 43 + 10 log (P) dB on all frequencies between 2305-2320 MHz and on all frequencies between 2345-2360 MHz that are outside the licensed band of operation, not less than 75 + 10 log (P) dB on all frequencies in the 2320-2345 MHz band, not less than 43 + 10 log (P) dB at 2305 and 2360 MHz, not less than 55 + 10 log (P) dB at 2362.5 MHz, not less than 70 + 10 log (P) dB at 2300 and 2365 MHz, not less than 72 + 10 log (P) dB at 2287.5 and 2367.5 MHz, and not less than 75 + 10 log (P) dB below 2285 MHz and above 2370 MHz.
21. For lower power CPE devices operating at or below 2 W per 5-megahertz average EIRP, the Commission further relaxed the OOBE attenuation levels measured over a 1-meghaertz resolution bandwidth to the levels it adopted for mobile devices: not less than 43 + 10 log (P) dB in the 2305-2320 MHz and 2345-2360 MHz bands on frequencies that are outside the licensed band of operation, not less than 55 + 10 log (P) dB in the 2320-2324 MHz and 2341-2345 MHz bands, not less than 61 + 10 log (P) dB in the 2324-2328 MHz and 2337-2341 MHz bands, not less than 67 + 10 log (P) dB in the 2328-2337 MHz band, not less than not less than 43 + 10 log (P) dB at 2305 and 2360 MHz, not less than 55 + 10 log (P) dB at 2300 MHz, not less than 61 + 10 log (P) dB at 2296 MHz, not less than 67 + 10 log (P) dB at 2292 MHz, and not less than 70 + 10 log (P) dB below 2288 and above 2365 MHz.
22.
23.
24.
25. The Commission establishes alternative performance requirements for license areas where WCS licensees providing mobile or point-to-multipoint services must coordinate with aeronautical mobile telemetry (AMT) entities to serve a significant percentage of a market's total population. Specifically, in any license area where 25 percent or more the population is within an AMT zone, affected licensees must serve 25 percent (rather than 40) of the population within 42 months, and 50 percent (rather than 75) within 72 months. Because it will be easier to coordinate point-to-point systems in the vicinity of AMT receive sites, the
26. No comments were received in response to the IRFAs in the
27. The RFA directs agencies to provide a description of and, where feasible, an estimate of the number of small entities that may be affected by the rules adopted. The RFA generally defines the term “small entity” as having the same meaning as the terms “small business,” “small organization,” and “small governmental jurisdiction.”
28.
29.
30. The
31. The
32. Other than these requirements, as well as the notification obligations discussed above, there are no other specific reporting or recordkeeping requirements adopted in the
33. The RFA requires an agency to describe any significant alternatives that it has considered in reaching its proposed approach, which may include the following four alternatives: (1) The establishment of differing compliance or reporting requirements or timetables that take into account the resources available to small entities; (2) the clarification, consolidation, or simplification of compliance or reporting requirements under the rule for small entities; (3) the use of performance, rather than design standards; and (4) an exemption from coverage of the rule, or any part thereof, for small entities.
34. The Commission's principal objective in this proceeding is to enable the provision of promising mobile broadband services to the public in the WCS spectrum to the maximum extent practicable, while ensuring that satellite radio operations are not unreasonably impacted by the Commission's actions. Adopting overly stringent technical rules for WCS to protect SDARS operations from interference will preclude WCS mobile operation, while liberalizing the WCS rules too much will result in harmful interference and disruption to SDARS service. Such results would cause significant adverse economic impact on either WCS licensees, which include small entities, or on SDARS operations.
35.
36.
37. Based on its review of the record in this proceeding, the Commission determines that it should require that WCS mobile and portable devices' OOBE be attenuated below the transmitter power P by a factor of not less than 43 + 10 log (P) dB in the 2305-2317.5 MHz and 2347.5-2360 MHz bands on frequencies that are outside the licensed band of operation, not less than 55 + 10 log (P) dB in the 2320-2324 MHz and 2341-2345 MHz bands, by 61 + 10 log (P) dB in the 2324-2328 MHz and 2337-2341 MHz bands, and by 67 + 10 log (P) dB in the 2328-2337 MHz band. In addition, mobile and portable devices' OOBE must be attenuated by a factor of not less than not less than 43 + 10 log (P) dB at 2305 and 2360 MHz, not less than 55 + 10 log (P) dB at 2300 MHz, not less than 61 + 10 log (P) dB at 2296 MHz, not less than 67 + 10 log(P) dB at 2292 MHz, and not less than 70 + 10 log (P) dB below 2288 and above 2365 MHz. In adopting these factors, the Commission believes that these limits will help avoid significant adverse economic impact to the WCS industry, as well as to SDARS operations by enabling WCS licensees to provide mobile services that were not viable under the existing rules, and by permitting SDARS licensees to continue to operate without undue interference from the WCS band. In addition, these OOBE attenuation factors will limit the potential for interference to Deep Space Network (DSN) operations in the 2290-2300 MHz band and Aeronautical Mobile Telemetry operations in the 2360-2395 MHz band. In adopting the stepped OOBE limits, the Commission declines to adopt Sirius XM's request for a more restrictive OOBE limit because such limit would effectively preclude WCS licensees, including small entities, from deploying mobile service. The Commission also finds that the proposal by the WCS Coalition will provide greater overall protection to SDARS operations than the 60 + 10 log (P) dB) advocated by NextWave. Accordingly, adoption of the above-specified stepped OOBE limits into the applicable portions of the 2320-2345 MHz SDARS band best minimizes significant economic impacts on small, as well as larger, entities.
38.
39. Based on its analysis of the record and a balancing of its objectives in this proceeding, the Commission adopts, in part, the WCS Coalition's proposal regarding base station power limits for WCS Blocks A and B, and also adopts in part Sirius XM's proposal regarding base station power limits in WCS Blocks C and D. The Commission finds that it is appropriate to modify the WCS Blocks A and B base station limit to 2 kW EIRP over 5 megahertz (400 W/MHz), which will be measured on an average basis with a maximum peak-to-average power ratio (PAPR) of 13dB. The Commission finds that these measures will adequately protect SDARS operations, and concludes that the ground-level emission limits sought by Sirius XM would be overly complex and burdensome for WCS licensees, including small entities, to comply with.
40. However, while the Commission concludes that adopting the WCS proposal is desirable with respect to the A and B blocks, it retains the power limits for WCS operations in the C and D blocks at 2 kW peak EIRP over 5 megahertz (400 W/MHz). Because base station operations in WCS Blocks C and D inherently pose more risk of potential interference to satellite radio users than would base station operations in Blocks A and B, which are separated from the SDARS spectrum by at least 5 megahertz, the Commission considers maintaining the current limits appropriate in order to minimize interference into satellite radio operations.
41. The Commission expects that both approaches, combined with the 250 mW per 5 megahertz average EIRP limit for WCS mobile and portable devices and the related OOBE attenuation factors of not less than 43 + 10 log (P) dB in the 2305-2317.5 MHz and 2347.5 MHz bands on frequencies that are outside the licensed band of operation, not less than 55 + 10 log (P) dB in the 2320-2324 MHz/2341-2345 MHz bands, 61 + 10 log (P) dB in the 2324-2328 MHz/2337-2341 MHz bands, and 67 + 10 log (P) dB in the 2328-2337 MHz band, and not less than 43 + 10 log (P) dB at 2305 and 2360 MHz, not less than 55 + 10 log (P) dB at 2300 MHz, not less than 61 + 10 log (P) dB at 2296 MHz, not less than 67 + 10 log (P) dB at 2292 MHz, and not less than 70 + 10 log (P) dB below 2288 and above 2365 MHz, should provide the technical flexibility for WCS licensees to deploy mobile service, and thereby avoid the adverse economic impact to WCS licensees, including small entities, that would occur without the ability to provide such service.
42.
43. For WCS base and fixed stations, the Commission finds it in the public interest to adopt an OOBE attenuation factor of 75 + 10 log (P) dB, as measured over a 1-megahertz resolution bandwidth, on frequencies in the 2320-2345 MHz band. Both WCS and SDARS licensees urge us to lower the current 80 + 10 log (P) dB OOBE attenuation factor by 5 dB. Although Sirius XM also requests that we establish ground-level emission limits, we decline to adopt
44.
45. The Commission finds it appropriate to maintain the current mobile transmitter power limit of 20 W per 5-megahertz peak EIRP for WCS fixed CPE devices because it appears that the existing limit has not resulted in interference to SDARS operation and provides WCS licensees with operational flexibility. Also, for WCS CPE operating with an average EIRP above 2 W per 5 megahertz, the Commission adopts the 75 + 10 log (P) dB OOBE attenuation factor for frequencies in the 2320-2345 MHz band, noting that both SDARS and WCS licensees propose that limit, and SDARS licensees have indicated that they are amenable to a relaxation of the OOBE limit because WCS fixed CPE device operations pose less risk of interference and disruption to SDARS licensees. For WCS CPE operating above 2 W per 5-megahertz average EIRP, the OOBE must be attenuated by a factor of 43 + 10 log (P) dB at 2305 and 2360 MHz, not less than 55 + 10 log (P) dB at 2362.5 MHz, not less than 70 + 10 log (P) dB at 2300 and 2365 MHz, not less than 72 + 10 log (P) dB at 2287.5 and 2367.5 MHz, and not less than 75 + 10 log (P) dB below 2285 and above 2370 MHz.
46. Further, in light of the Commission's finding that applying the stepped OOBE limits to WCS mobile and portable devices will provide sufficient protection to SDARS operations, as well as the lower likelihood of interference to SDARS receivers posed by WCS fixed CPE terminals operating at or below 2 W per 5-megahertz average EIRP, the Commission adopted the stepped OOBE limit that is applicable to WCS mobile devices for these CPE as well. For WCS CPE operating at or below 2 W per 5-megahertz average EIRP, the OOBE must be attenuated by a factor of not less than 43 + 10 log (P) dB in the 2305-2320 MHz and the 2345-2360 MHz bands on frequencies that are outside the licensed band of operation, 55 + 10 log (P) dB in the 2320-2324 MHz/2341-2345 MHz bands, 61 + 10 log (P) dB in the 2324-2328 MHz/2337-2341 MHz bands, and 67 + 10 log (P) dB in the 2328-2337 MHz band, and not less than 43 + 10 log (P) dB at 2305 and 2360 MHz, 55 + 10 log (P) dB at 2300 MHz, 61 + 10 log (P) dB at 2296 MHz, 67 + 10 log (P) dB at 2292 MHz, and 70 + 10 log (P) dB below 2288 and above 2365 MHz.
47.
48.
49.
50.
51. The Regulatory Flexibility Act of 1980, as amended (RFA)
52. The rules adopted in this
53. Therefore, since only one large entity is affected by the rules adopted in this
54. Pursuant to sections 4(i), 7(a), 303(c), 303(f), 303(g), and 303(r), and 307 of the Communications Act of 1934, as amended, 47 U.S.C. 154(i), 157(a), 303(c), 303(f), 303(g), 303(r), 307, that this
55. The rules adopted herein
56. Pursuant to sections 4(i) and 303(r) of the Communications Act of 1934, as amended, 47 U.S.C. 154(i), 303(r), and § 1.115 of the Commission's rules, 47 CFR 1.115, the application for review of the Wireless Telecommunications Bureau's Horizon Order,
57. Pursuant to sections 4(i) and 303(r) of the Communications Act of 1934, as amended, 47 U.S.C. 154(i), 303(r), the applications for additional time to meet the 2.3 GHz Wireless Communications Service substantial service performance requirement listed in Appendix F
58. Pursuant to section 5(c) of the Communications Act of 1934, as amended, 47 U.S.C. 5(c), the Wireless Telecommunications Bureau
59. The International Bureau is instructed to extend all grants of STA to operate SDARS repeaters currently in effect for a period of 180 days from the effective date of this Order, or until the date on which the Commission grants blanket licenses to operate SDARS repeaters, whichever comes first.
60. The International Bureau is instructed to grant all pending requests for STA to operate SDARS terrestrial repeaters for a period of 180 days from the effective date of this Order, or until the date on which the Commission grants blanket licenses to operate
61. The petition for reconsideration filed in 12 FCC Rcd 5754, IB Docket No. 95-91, GEN Docket No. 90-357, on March 27, 1997 by the Consumer Electronics Manufacturers Association, and the petition for partial reconsideration filed in 12 FCC Rcd 5754, IB Docket No. 95-91, GEN Docket No. 90-357, on April 9, 1997 by the Cellular Phone Taskforce
62. The Commission will send a copy of this Report and Order and Second Report and Order, including the Final Regulatory Flexibility Analysis and Final Regulatory Flexibility Certification, in a report to be sent to Congress and the Government Accountability Office pursuant to the Congressional Review Act,
63. Pursuant to sections 4(i) and 303(r) of the Communications Act of 1934, as amended, 47 U.S.C. 154(i), 303(r), and §§ 1.9030(c) and 1.9035(c) of the Commission's rules, 47 CFR 1.9030(c), 1.9035(c), that all licensees and de facto transfer lessees of spectrum in the 2305-2320 MHz and 2345-2360 MHz bands are
Communications equipment, Radio.
Communications common carriers, Communications equipment, Radio, Reporting and recordkeeping requirements, Satellites, Telecommunications.
Communications common carriers, Communications equipment, Radio, Reporting and recordkeeping requirements.
47 U.S.C. 154, 302a, 303, and 336, unless otherwise noted.
US338 The following provisions shall apply in the band 2305-2320 MHz:
(a) In the sub-band 2305-2310 MHz, space-to-Earth operations are prohibited.
(b) Within 145 km of Goldstone, CA (35°25′33″ N., 116°53′23″ W.), Wireless Communications Service (WCS) licensees operating base stations in the band 2305-2320 MHz shall, prior to operation of those base stations, achieve a mutually satisfactory coordination agreement with the National Aeronautics and Space Administration (NASA).
NASA operates a deep space facility in Goldstone in the band 2290-2300 MHz.
47 U.S.C. 701-744. Interprets or applies Sections 4, 301, 302, 303, 307, 309, and 332 of the Communications Act, as amended, 47 U.S.C. Sections 154, 301, 302, 303, 307, 309, and 332, unless otherwise noted.
(a)
(2) Licenses for DBS space stations and 17/24 GHz BSS space stations licensed as broadcast facilities, and for SDARS space stations and terrestrial repeaters, will be issued for a period of 8 years. Licenses for DBS space stations not licensed as broadcast facilities will be issued for a period of 10 years.
(d) The license term for each digital audio radio service satellite and any associated terrestrial repeaters is specified in § 25.121.
(e)
(2) SDARS terrestrial repeaters will be eligible for blanket licensing only under the following circumstances:
(i) The SDARS terrestrial repeaters will comply with all applicable power limits set forth in § 25.214(d)(1) of this chapter and all applicable out-of-band emission limits set forth in § 25.202(h)(1) and (h)(2).
(ii) The SDARS terrestrial repeaters will meet all applicable requirements in part 1, subpart I, and part 17 of this chapter. Operators of SDARS terrestrial repeaters must maintain demonstrations of compliance with part 1, subpart I, of this chapter and make such demonstrations available to the Commission upon request within three business days.
(iii) The SDARS terrestrial repeaters will comply with all requirements of all applicable international agreements.
(3) After May 20, 2010, SDARS licensees shall, before deploying any new, or modifying any existing, terrestrial repeater, notify potentially affected WCS licensees pursuant to the procedure set forth in § 25.263.
(4) SDARS terrestrial repeaters are restricted to the simultaneous retransmission of the complete programming, and only that programming, transmitted by the SDARS licensee's satellite(s) directly to the SDARS licensee's subscribers' receivers, and may not be used to distribute any information not also transmitted to all subscribers' receivers.
(5) Operators of SDARS terrestrial repeaters are prohibited from using those repeaters to retransmit different transmissions from a satellite to different regions within that satellite's coverage area.
(6) Operators of SDARS terrestrial repeaters are required to comply with all applicable provisions of part 1, subpart I, and part 17 of this chapter.
(7)(i) Each SDARS terrestrial repeater transmitter utilized for operation under this paragraph must be of a type that has been authorized by the Commission under its certification procedure.
(ii) In addition to the procedures set forth in subpart J of part 2 of this chapter, power measurements for SDARS repeater transmitters may be made in accordance with a Commission-approved average power technique. Peak-to-average power ratio (PAPR) measurements for SDARS repeater transmitters should be made using either an instrument with complementary cumulative distribution function (CCDF) capabilities to determine that the PAPR will not exceed 13 dB for more than 0.1 percent of the time or another Commission approved procedure. The measurement must be performed using a signal corresponding to the highest PAPR expected during periods of continuous transmission.
(iii) Any manufacturer of radio transmitting equipment to be used in these services may request equipment authorization following the procedures set forth in subpart J of part 2 of this chapter. Equipment authorization for an individual transmitter may be requested by an applicant for a station authorization by following the procedures set forth in part 2 of this chapter.
(8) Applications for blanket authority to operate terrestrial repeaters must be filed using Form 312, except that Schedule B to Form 312 need not be filed. Such applications must also include the following information as an attachment:
(i) The space station(s) with which the terrestrial repeaters will communicate, the frequencies and emission designators of such communications, and the frequencies and emission designators used by the repeaters to re-transmit the received signals.
(ii) The maximum number of terrestrial repeaters that will be deployed under the authorization at 1) power levels equal to or less than 2-watt average EIRP, and 2) power levels greater than 2-watt average EIRP (up to 12-kW average EIRP).
(iii) A certification of compliance with the requirements of § 25.144(e)(1) through (7).
(9) SDARS terrestrial repeaters that are ineligible for blanket licensing must be authorized on a site-by-site basis. Applications for site-by-site authorization must be filed using Form 312, except that Schedule B need not be provided. Such applications must also include the following information, as an attachment:
(i) The technical information for each repeater required to be shared with potentially affected WCS licensees as part of the notification requirement set forth in § 25.263(c)(2).
(ii) The space station(s) with which the terrestrial repeaters will communicate, the frequencies and emission designators of such communications, and the frequencies and emission designators used by the repeaters to re-transmit the received signals.
(a) * * *
(6) The following frequencies are available for use by the Satellite Digital Audio Radio Service (SDARS), and for any associated terrestrial repeaters: 2320-2345 MHz (space-to-Earth)
(f)
(h)
(2) Any SDARS terrestrial repeater operating at a power level equal to or less than 2-watt average EIRP is required to attenuate its out-of-band emissions below the transmitter power P by a factor of not less than 75 + 10 log (P) dB in a 1-megahertz bandwidth outside the 2320-2345 MHz band, where P is average transmitter output power in watts.
(3) SDARS repeaters are permitted to attenuate out-of-band emissions less than the levels specified in paragraphs (h)(1) and (h)(2), of this section unless a potentially affected WCS licensee provides written notice that it intends to commence commercial service within the following 365 days. Starting 180 days after receipt of such written notice, SDARS repeaters within the area notified by the potentially affected WCS licensee must attenuate out-of-band emissions to the levels specified in paragraphs (h)(1) and (h)(2) of this section.
(4) For the purpose of this section, a WCS licensee is potentially affected if it meets any of the following criteria:
(i) The WCS licensee is authorized to operate a base station in the 2305-2315 MHz or 2350-2360 MHz bands in the same Major Economic Area (MEA) as that in which a SDARS terrestrial repeater is located.
(ii) The WCS licensee is authorized to operate a base station in the 2315-2320 MHz or 2345-2350 MHz bands in the same Regional Economic Area Grouping (REAG) as that in which a SDARS terrestrial repeater is located.
(iii) A SDARS terrestrial repeater is located within 5 kilometers of the boundary of an MEA or REAG in which the WCS licensee is authorized to operate a WCS base station.
(d)
(2) SDARS repeaters are permitted to operate at power levels above 12-kW average EIRP, unless a potentially affected WCS licensee provides written notice that it intends to commence commercial service within the following 365 days. Starting 180 days after receipt of such written notice, SDARS repeaters within the area notified by the potentially affected WCS licensee must be operated at a power level less than or equal to 12-kW average EIRP, with a maximum peak-to-average power ratio of 13 dB.
(3) For the purpose of this section, a WCS licensee is potentially affected if it meets any of the following criteria:
(i) The WCS licensee is authorized to operate a base station in the 2305-2315 MHz or 2350-2360 MHz bands in the same Major Economic Area (MEA) as that in which a SDARS terrestrial repeater is located.
(ii) The WCS licensee is authorized to operate a base station in the 2315-2320 MHz or 2345-2350 MHz bands in the same Regional Economic Area Grouping
(iii) An SDARS terrestrial repeater is located within 5 kilometers of the boundary of an MEA or REAG in which the WCS licensee is authorized to operate a WCS base station.
This section requires SDARS licensees in the 2320-2345 MHz band to share information regarding the location and operation of terrestrial repeaters with WCS licensees in the 2305-2320 MHz and 2345-2360 MHz bands. Section 27.72 of this chapter requires WCS licensees to share information regarding the location and operation of base stations in the 2305-2320 MHz and 2345-2360 MHz bands with SDARS licensees in the 2320-2345 MHz band.
(a) SDARS licensees must select terrestrial repeater sites and frequencies, to the extent practicable, to minimize the possibility of harmful interference to WCS base station operations in the 2305-2320 MHz and 2345-2360 MHz bands.
(b)
(1) For purposes of this section, a “potentially affected WCS licensee” is a WCS licensee that:
(i) Is authorized to operate a base station in the 2305-2315 MHz or 2350-2360 MHz bands in the same Major Economic Area (MEA) as that in which the terrestrial repeater is to be located;
(ii) Is authorized to operate a base station in the 2315-2320 MHz or 2345-2350 MHz bands in the same Regional Economic Area Grouping (REAG) as that in which the terrestrial repeater is to be located.
(iii) In addition to the WCS licensees identified in paragraphs (b)(1)(i) and (ii) of this section, in cases in which the SDARS licensee plans to deploy or modify a terrestrial repeater within 5 kilometers of the boundary of an MEA or REAG in which the terrestrial repeater is to be located, a potentially affected WCS licensee is one that is authorized to operate a WCS base station in that neighboring MEA or REAG within 5 kilometers of the location of the terrestrial repeater.
(2) For the purposes of this section, a business day is defined by § 1.4(e)(2) of this chapter.
(c)
(2) Regardless of the notification method, notification must specify relevant technical details, including, at a minimum:
(i) The coordinates of the proposed repeater to an accuracy of no less than ± 1 second latitude and longitude;
(ii) The proposed operating power(s), frequency band(s), and emission(s);
(iii) The antenna center height above ground and ground elevation above mean sea level, both to an accuracy of no less than ±1 meter;
(iv) The antenna gain pattern(s) in the azimuth and elevation planes that include the peak of the main beam; and
(v) The antenna downtilt angle(s).
(3) An SDARS licensee operating terrestrial repeaters must maintain an accurate and up-to-date inventory of its terrestrial repeaters operating above 2 watts average EIRP, including the information set forth in § 25.263(c)(2), which shall be available upon request by the Commission.
(d)
(e)
47 U.S.C. 154, 301, 302, 303, 307, 309, 332, 336, and 337 unless otherwise noted.
(a) AWS and WCS licensees, with the exception of WCS licensees holding authorizations for Block A in the 698-704 MHz and 728-734 MHz bands, Block B in the 704-710 MHz and 734-740 MHz bands, Block E in the 722-728 MHz band, Block C, C1, or C2 in the 746-757 MHz and 776-787 MHz bands, Block D in the 758-763 MHz and 788-793 MHz bands, Block A in the 2305-2310 MHz and 2350-2355 MHz bands, Block B in the 2310-2315 MHz and 2355-2360 MHz bands, Block C in the 2315-2320 MHz band, and Block D in the 2345-2350 MHz band, must, as a performance requirement, make a showing of “substantial service” in their license area within the prescribed license term set forth in § 27.13. “Substantial service” is defined as service which is sound, favorable and substantially above a level of mediocre service which just might minimally warrant renewal. Failure by any licensee to meet this requirement will result in forfeiture of the license and the licensee will be ineligible to regain it.
(p) This section enumerates performance requirements for licensees holding authorizations for Block A in the 2305-2310 MHz and 2350-2355 MHz bands, Block B in the 2310-2315 MHz and 2355-2360 MHz bands, Block C in the 2315-2320 MHz band, and Block D in the 2345-2350 MHz band.
(1) For mobile or point-to-multipoint systems, a licensee must provide reliable signal coverage and offer service to at least 40 percent of the license area's population by March 4, 2014, and
(2) For point-to-point fixed systems, except those deployed in the Gulf of Mexico license area, a licensee must construct and operate a minimum of 15 point-to-point links per million persons (one link per 67,000 persons) in a license area by March 4, 2014, and 30 point-to-point links per million persons (one link per 33,500 persons) in a licensed area by September 1, 2016. The exact link requirement is calculated by dividing a license area's total population by 67,000 and 33,500 for the respective milestones, and then rounding upwards to the next whole number. For a link to be counted towards these benchmarks, both of its endpoints must be located in the license area. If only one endpoint of a link is located in a license area, it can be counted as a one- half link towards the benchmarks.
(3) For point-to-point fixed systems deployed on any spectrum block in the Gulf of Mexico license area, a licensee must construct and operate a minimum of 15 point-to-point links by March 4, 2014, and a minimum of 15 point-to-point links by September 1, 2016.
(4) Under paragraph (p)(2) and (p)(3) of this section, each fixed link must provide a minimum bit rate, in bits per second, equal to or greater than the bandwidth specified by the emission designator in Hertz (
(5) If an initial authorization for a license area is granted after September 1, 2010, then the applicable benchmarks in paragraphs (p)(1), (p)(2) and (p)(3) of this section must be met within 42 and 72 months, respectively, of the initial authorization grant date.
(6) Licensees must use the most recently available U.S. Census Data at the time of measurement to meet these performance requirements.
(7) Licensees must certify compliance with the applicable performance requirements by filing a construction notification with the Commission, within 15 days of the expiration of the relevant performance milestone, pursuant to § 1.946(d) of this chapter. Each construction notification must include electronic coverage maps, supporting technical documentation, and any other information as the Wireless Telecommunications Bureau may prescribe by public notice. Electronic coverage maps must accurately depict the boundaries of each license area (Regional Economic Area Grouping, REAG, or Major Economic Area, MEA) in the licensee's service territory. Further, REAG maps must depict MEA boundaries and MEA maps must depict Economic Area boundaries. If a licensee does not provide reliable signal coverage to an entire license area, its map must accurately depict the boundaries of the area or areas within each license area not being served. Each licensee also must file supporting documentation certifying the type of service it is providing for each REAG or MEA within its service territory and the type of technology used to provide such service. Supporting documentation must include the assumptions used to create the coverage maps, including the propagation model and the signal strength necessary to provide reliable service with the licensee's technology.
(8) If a licensee fails to meet any applicable performance requirement, its authorization will terminate automatically without further Commission action as of the applicable performance milestone and the licensee will be ineligible to regain it.
(a) The following power limits and related requirements apply to stations transmitting in the 2305-2320 MHz band or the 2345-2360 MHz band.
(1)
(A) The average equivalent isotropically radiated power (EIRP) must not exceed 2,000 watts within any 5 megahertz of authorized bandwidth and must not exceed 400 watts within any 1 megahertz of authorized bandwidth.
(B) The peak-to-average power ratio (PAPR) of the transmitter output power must not exceed 13 dB. The PAPR measurements should be made using either an instrument with complementary cumulative distribution function (CCDF) capabilities to determine that PAPR will not exceed 13 dB for more than 0.1 percent of the time or other Commission approved procedure. The measurement must be performed using a signal corresponding to the highest PAPR expected during periods of continuous transmission.
(ii) For base and fixed stations transmitting in the 2315-2320 MHz band or the 2345-2350 MHz band, the peak EIRP must not exceed 2,000 watts.
(iii) Base stations supporting frequency division duplex (FDD) mobile and portable operations are restricted to transmitting in the 2345-2360 MHz bands.
(2)
(3)
(ii) Mobile and portable stations are not permitted to operate in the 2317.5-2320 MHz and 2345-2347.5 MHz bands.
(iii)
(iv)
12. Section 27.53 is amended by revising paragraphs (a) introductory text and (a)(1) through (5), removing and reserving paragraphs (a)(6) and (a)(9), and revising paragraph (a)(10) to read as follows:
(a) For operations in the 2305-2320 MHz band and the 2345-2360 MHz band, the power of any emission outside a licensee's frequency band(s) of operation shall be attenuated below the transmitter power P (with averaging performed only during periods of transmission) within the licensed band(s) of operation, in watts, by the following amounts:
(1) For base and fixed stations' operations in the 2305-2320 MHz band and the 2345-2360 MHz band:
(i) By a factor of not less than 43 + 10 log (P) dB on all frequencies between 2305 and 2320 MHz and on all frequencies between 2345 and 2360 MHz that are outside the licensed band of operation, and not less than 75 + 10 log (P) dB on all frequencies between 2320 and 2345 MHz;
(ii) By a factor of not less than: 43 + 10 log (P) dB at 2305 MHz, 70 + 10 log (P) dB at 2300 MHz, 72 + 10 log (P) dB at 2287.5 MHz, and 75 + 10 log (P) dB below 2285 MHz;
(iii) By a factor of not less than: 43 + 10 log (P) dB at 2360 MHz, 55 + 10 log (P) dB at 2362.5 MHz, 70 + 10 log (P) dB at 2365 MHz, 72 + 10 log (P) dB at 2367.5 MHz, and 75 + 10 log (P) dB above 2370 MHz.
(2) For fixed customer premises equipment (CPE) stations operating in the 2305-2320 MHz band and the 2345-2360 MHz band transmitting with more than 2 watts per 5 megahertz average EIRP:
(i) By a factor of not less than: 43 + 10 log (P) dB on all frequencies between 2305 and 2320 MHz and on all frequencies between 2345 and 2360 MHz that are outside the licensed band of operation, and not less than 75 + 10 log (P) dB) on all frequencies between 2320 and 2345 MHz.
(ii) By a factor of not less than: 43 + 10 log (P) dB) at 2305 MHz, 70 + 10 log (P) dB at 2300 MHz, 72 + 10 log (P) dB at 2287.5 MHz, and 75 + 10 log (P) dB below 2285 MHz;
(iii) By a factor of not less than: 43 + 10 log (P) dB at 2360 MHz, 55 + 10 log (P) dB at 2362.5 MHz, 70 + 10 log (P) dB at 2365 MHz, 72 + 10 log (P) dB at 2367.5 MHz, and 75 + 10 log (P) dB) above 2370 MHz.
(3) For fixed CPE stations transmitting with 2 watts per 5 megahertz average EIRP or less:
(i) By a factor of not less than 43 + 10 log (P) dB) on all frequencies between 2305 and 2320 MHz and on all frequencies between 2345 and 2360 MHz that are outside the licensed band of operation, not less than 55 + 10 log (P) dB on all frequencies between 2320 and 2324 MHz and on all frequencies between 2341 and 2345 MHz, not less than 61 + 10 log (P) dB on all frequencies between 2324 and 2328 MHz and on all frequencies between 2337 and 2341 MHz, not less than 67 + 10 log (P) dB on all frequencies between 2328 and 2337 MHz;
(ii) By a factor of not less than 43 + 10 log (P) dB at 2305 MHz, 55 + 10 log (P) dB at 2300 MHz, 61 + 10 log (P) dB at 2296 MHz, 67 + 10 log (P) dB at 2292 MHz, 70 + 10 log (P) dB below 2288 MHz.
(iii) By a factor of not less than: 43 + 10 log (P) dB at 2360 MHz and 70 + 10 log (P) dB above 2365 MHz.
(4) For mobile and portable stations operating in the 2305-2317.5 MHz and 2347.5-2360 MHz bands:
(i) By a factor of not less than: 43 + 10 log (P) dB on all frequencies between 2305 and 2317.5 MHz and on all frequencies between 2347.5 and 2360 MHz that are outside the licensed band of operation, not less than 55 + 10 log (P) dB on all frequencies between 2320 and 2324 MHz and on all frequencies between 2341 and 2345 MHz, not less than 61 + 10 log (P) dB on all frequencies between 2324 and 2328 MHz and on all frequencies between 2337 and 2341 MHz, not less than 67 + 10 log (P) dB on all frequencies between 2328 and 2337 MHz.
(ii) By a factor of not less than 43 + 10 log (P) dB at 2305 MHz, 55 + 10 log (P) dB at 2300 MHz, 61 + 10 log (P) dB at 2296 MHz, 67 + 10 log (P) dB at 2292 MHz, and 70 + 10 log (P) dB below 2288 MHz.
(iii) By a factor of not less than: 43 + 10 log (P) dB at 2360 MHz and 70 + 10 log (P) dB above 2365 MHz.
(5)
(10) The out-of-band emissions limits in paragraphs (a)(1) through (a)(3) of this section may be modified by the private contractual agreement of all affected licensees, who must maintain a copy of the agreement in their station files and disclose it to prospective assignees, transferees, or spectrum lessees and, upon request, to the Commission.
This section requires WCS licensees in the 2305-2320 MHz and 2345-2360 MHz bands to share information regarding the location and operation of base stations with Satellite Digital Audio Radio Service (SDARS) licensees in the 2320-2345 MHz band. Section 25.263 of this chapter requires SDARS licensees in the 2320-2345 MHz band to share information regarding the location and operation of terrestrial repeaters with WCS licensees in the 2305-2320 MHz and 2345-2360 MHz bands.
(a)
(b)
(c)
(2) Regardless of the notification method, it must specify relevant technical details, including, at a minimum:
(i) The coordinates of the proposed base station to an accuracy of no less than ± 1 second latitude and longitude;
(ii) The proposed operating power(s), frequency band(s), and emission(s);
(iii) The antenna center height above ground and ground elevation above mean sea level, both to an accuracy of no less than ± 1 meter;
(iv) The antenna gain pattern(s) in the azimuth and elevation planes that include the peak of the main beam; and
(v) The antenna downtilt angle(s).
(3) A WCS licensee operating base stations must maintain an accurate and up-to-date inventory of its base stations, including the information set forth in § 27.72(c)(2), which shall be available upon request by the Commission.
(d)
(e)
This section requires Wireless Communications Services (WCS) licensees in the 2345-2360 MHz band to coordinate the deployment of base stations with Aeronautical Mobile Telemetry (AMT) facilities in the 2360-2395 MHz band; and to take all practicable steps necessary to minimize the risk of harmful interference to AMT facilities.
(a) Wireless Communications Service (WCS) licensees operating base stations in the 2345-2360 MHz band shall, prior to operation of such base stations, achieve a mutually satisfactory coordination agreement with the Aerospace and Flight Test Radio Coordinating Council (AFTRCC) for any AMT receiver facility within 45 kilometers or the radio line of sight, whichever distance is larger, of the intended WCS base station location. This coordination is necessary to protect AMT receive systems consistent with Recommendation ITU-R M.1459. The locations of the current and planned Federal and non-Federal AMT receiver sites may be obtained from AFTRCC.
(b) WCS licensees operating base stations in the 2305-2320 MHz band shall, prior to operation of such base stations, achieve a mutually satisfactory coordination agreement with the National Aeronautics and Space Administration (NASA) within 145 kilometers of the Goldstone, CA earth station site (35°25′33″ N, 116°53′23″ W).
(c) After base station operations commence, upon receipt of a complaint of harmful interference, the WCS licensee(s) receiving the complaint, no matter the distance from the NASA Goldstone, CA earth station or from an AMT site, operating in the 2305-2320 or 2345-2360 MHz bands, respectively, shall take all practicable steps to immediately eliminate the interference.
(d)
Defense Acquisition Regulations System, Department of Defense (DoD).
Final rule.
DoD is issuing a final rule amending the Defense Federal Acquisition Regulation Supplement (DFARS) to implement the recurring requirement of section 807 of the Ronald W. Reagan National Defense Authorization Act for Fiscal Year 2005. Section 807 provides for adjustment every 5 years of statutory acquisition-related thresholds, except for Davis-Bacon Act, Service Contract Act, and trade agreements thresholds. This final rule also adjusts some non-statutory acquisition-related thresholds.
Ms. Amy Williams, 703-602-0328.
The first review of DFARS acquisition-related thresholds to implement section 807 of the Ronald W. Reagan National Defense Authorization Act for Fiscal Year 2005 (Pub. L. 108-375) was conducted under DFARS Case 2004-D022 during fiscal year 2005. The final DFARS rule was published in the
This is the second review of DFARS acquisition-related thresholds. DoD published a proposed rule on January 20, 2010 (75 FR 3187). The preamble to the proposed rule contained a detailed explanation of—
• What an acquisition-related threshold is;
• Which acquisition-related thresholds are not subject to escalation adjustment under this case; and
• How DoD analyzes statutory and non-statutory acquisition-related thresholds.
No public comments were received.
This rule was subject to Office of Management and Budget review under Executive Order 12866, dated September 30, 1993.
DoD certifies that this rule will not have a substantial economic impact on small business because the adjustment of acquisition-related thresholds for inflation just maintains the status quo. No comments were received regarding impact on small business.
The Paperwork Reduction Act does apply. The proposed changes to the DFARS do not impose new information collection requirements that require the approval of the Office of Management and Budget under 44 U.S.C. 3501,
Government procurement.
41 U.S.C. 421 and 48 CFR chapter 1.
(e)(1) * * *
(i) Exceed $500 million for supplies (see 217.172(d); and 217.172(f)(3)) or $625.5 million for services (see 217.171(a)(6);
(d) * * *
(10) * * *
(A) Reviewing and making recommendations for all acquisitions (including orders placed against Federal Supply Schedule contracts) over $10,000, except those under the simplified acquisition threshold that are totally set aside for small business concerns in accordance with FAR 19.502-2. Follow the procedures at PGI 219.201(d)(10) regarding such reviews.
Federal Aviation Administration (FAA), Department of Transportation (DOT).
Notice of proposed rulemaking (NPRM); correction.
This document makes a correction to a proposed airworthiness directive (AD), which was published in the
We must receive comments on this proposed AD by August 23, 2010, which is the same comment period as the originally published NPRM.
Use one of the following addresses to comment on this proposed AD:
•
•
•
•
For service information identified in this proposed AD, contact Eclipse Aerospace, Inc., 2503 Clark Carr Loop, SE., Albuquerque, New Mexico 87106;
Eric Kinney, Aerospace Engineer, 2601 Meacham Blvd., Fort Worth, Texas 76137;
On July 1, 2010, the FAA issued an NPRM (75 FR 39472, July 9, 2010), which applies to certain Eclipse Model EA500 airplanes. The NPRM proposed to require incorporating changes to the electronic flight information system and the airplane flight manuals.
In the published NPRM, we incorrectly referenced the applicability for Model EA500 airplanes with certain serial numbers (SNs) of this proposed AD as “000039 through 000104, 000113 through 000115, 000120, and 000123 through 000124, that incorporate Performance Enhancement & Drag Reduction Modification per any revision level of Eclipse SB 500-99-001” instead of “000039 through 000104, 000113 through 000115, 000120, and 000123 through 000124, that incorporate Avionics Upgrade to AVIO NG Configuration for ETT Configured Aircraft per any revision level of Eclipse SB 500-99-002.”
This correction is needed to correct the applicability for these SNs and eliminate any confusion that this NPRM may have created.
Accordingly, the publication of July 9, 2010 (75 FR 39472), of Notice of proposed rulemaking, Docket No. FAA-2010-0691, which was the subject of FR Doc. 2010-16740, is corrected as follows:
On page 39474, in the third column, lines 1 through 6, replace “000039 through 000104, 000113 through 000115, 000120, and 000123 through 000124, that incorporate Performance Enhancement & Drag Reduction Modification per any revision level of Eclipse SB 500-99-001” with “000039 through 000104, 000113 through 000115, 000120, and 000123 through 000124, that incorporate Avionics Upgrade to AVIO NG Configuration for ETT Configured Aircraft per any revision level of Eclipse SB 500-99-002.”
Environmental Protection Agency (EPA).
Notice of public hearings.
The EPA is announcing three public hearings to be held for the proposed rule “Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone” (Transport Rule) which is published elsewhere in today's issue of the
The public hearings will be held on August 19, 2010, August 26, 2010, and September 1, 2010.
The August 19, 2010 hearing will be held at the Wyndham, Chicago in the Grand Ballroom, Salon C located at 633 North St. Clair, Chicago, IL 60611;
If you would like to present oral testimony at the public hearing, please contact Ms. Pamela Long, U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Air Quality Planning Division, (C504-03), Research Triangle Park, NC 27711, telephone (919) 541-0641, fax number (919) 541-5509,
Questions concerning the August 2, 2010, proposed rule should be addressed to Mr. Tim Smith, U.S. EPA, Office of Air Quality Planning and Standards, Geographic Strategies Group, (C504-09), Research Triangle Park, NC 27711, telephone number (919) 541-4718, e-mail at
These public hearings are to provide the public with an opportunity to present oral comments regarding EPA's proposed Transport Rule, which identifies and limits emissions of nitrogen oxides and/or sulfur dioxide in 31 States and the District of Columbia that affect the ability of downwind States to attain and maintain compliance with the 1997 and 2006 fine particulate matter (PM
Commenters should notify Ms. Long if they will need specific equipment, or if there are other special needs related to providing comments at the hearings. The EPA will provide equipment for commenters to show overhead slides or make computerized slide presentations if we receive special requests in advance. Oral testimony will be limited to 5 minutes for each commenter. The EPA encourages commenters to provide EPA with a copy of their oral testimony electronically (via e-mail or CD) or in hard copy form.
The hearing schedules, including lists of speakers, will be posted on EPA's Web site
EPA will make every effort to follow the schedule as closely as possible on the day of the hearings; however, please plan for the hearing to run either ahead of schedule or behind schedule.
The EPA has established a docket for the proposed rule “Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone” under Docket ID No. EPA-HQ-OAR-2009-0491 (available at
As stated previously, the proposed rule was published in the
Environmental Protection Agency (EPA).
Proposed rule.
The Environmental Protection Agency (EPA) is proposing to determine that the New York-N. New Jersey-Long Island, NY-NJ-CT fine particle (PM
Comments must be received on or before September 1, 2010.
Submit your comments, identified by Docket ID number EPA-R02-OAR-2009-0659, by one of the following methods:
•
•
•
•
•
If you have questions concerning today's proposed action related to New York or New Jersey, please contact Henry Feingersh, Air Programs Branch, Environmental Protection Agency, 290 Broadway, 25th Floor, New York, New York 10007-1866, telephone number (212)637-3382, fax number (212) 637-3901, e-mail
If you have questions concerning today's proposed action related to Connecticut, please contact Alison C. Simcox, Air Quality Planning Unit, Environmental Protection Agency, EPA New England Regional Office, 5 Post Office Square-Suite 100, Mail Code OEP05-02, Boston, MA 02109-3912, telephone number (617) 918-1684, fax number (617) 918-0684, e-mail
For detailed information regarding this proposal, EPA prepared a Technical Support Document (TSD). The TSD can be viewed at
The following table of contents describes the format of this notice:
EPA is proposing to determine that the New York-N. New Jersey-Long Island, NY-NJ-CT PM
If this determination is made final, under the provisions of EPA's PM
As further discussed below, the proposed determination, if finalized, would: (1) Suspend the requirements for the NY-NJ-CT PM
If this rulemaking is finalized and EPA subsequently determines, after notice-and-comment rulemaking in the
The determination that EPA proposes with this
This proposed action, if finalized, is limited to a determination that the NY-NJ-CT PM
This proposed determination that the NY-NJ-CT PM
If this proposed determination is made final and the NY-NJ-CT PM
On July 18, 1997 (62 FR 38652), EPA established a health-based PM
On November 13, 2009, EPA clarified the designations for the 1997 PM
EPA has reviewed the ambient air monitoring data for PM
On the basis of that review, EPA has concluded that this area has attained the 1997 annual PM
Under EPA regulations at 40 CFR 50.7: The annual primary and secondary PM
Table 1 shows the design values by county (
EPA's review
Data handling conventions and computations necessary for determining whether areas have met the PM
The building on which the design value monitor (PS 59) for the NY-NJ-CT PM
A method was developed, therefore, to use less than complete data to determine if the design value monitor would be in attainment if it had continued to operate. The approach summarized in this section, and further described in the TSD, may or may not be appropriate for other areas with less than complete data. EPA will evaluate the appropriateness of this analytical approach for each area with less than complete data on a case-by-case basis.
EPA has determined that the PM
The method used to determine the design value for PS 59 involves establishing a linear relationship between PS 59 and another site in the NY-NJ-CT PM
EPA is proposing to determine that the NY-NJ-CT PM
This action proposes to make a determination based on air quality data, and would, if finalized, result in the suspension of certain Federal requirements. 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, Particulate matter, Reporting and recordkeeping requirements.
42 U.S.C. 7401
Environmental Protection Agency (EPA).
Proposed rule.
EPA is proposing to approve revisions to the San Joaquin Valley Unified Air Pollution Control District (SJVUAPCD) portion of the California State Implementation Plan (SIP). These revisions concern oxides of nitrogen (NO
Any comments must arrive by September 1, 2010.
Submit comments, identified by docket number EPA-R09-OAR-2010-0596, by one of the following methods:
1.
2.
3.
Idalia Pérez, EPA Region IX, (415) 972-3248,
Throughout this document, “we,” “us” and “our” refer to EPA.
Table 1 lists the rule addressed by this proposal with the date that it was adopted by the local air agency and submitted by the California Air Resources Board (CARB).
On June 8, 2010, EPA determined that the submittal for SJVUAPCD Rule 4308 met the completeness criteria in 40 CFR Part 51, Appendix V, which must be met before formal EPA review.
We approved an earlier version of Rule 4308 into the SIP on May 30, 2007 (72 FR 29886).
NO
Generally, SIP rules must be enforceable (
Guidance and policy documents that we use to evaluate enforceability, RACT and RACM requirements consistently include the following:
1. “State Implementation Plans; Nitrogen Oxides Supplement to the General Preamble; Clean Air Act Amendments of 1990 Implementation of Title I; Proposed Rule,” (the NO
2. “Issues Relating to VOC Regulation Cutpoints, Deficiencies, and Deviations,” EPA, May 25, 1988 (the Bluebook).
3. “Guidance Document for Correcting Common VOC & Other Rule Deficiencies,” EPA Region 9, August 21, 2001 (the Little Bluebook).
4. “Determination of Reasonably Available Control Technology and Best Available Retrofit Control Technology for Industrial, Institutional, and Commercial Boilers, Steam Generators, and Process Heaters,” CARB, July 18, 1991.
5. “Alternative Control Techniques Document— NO
6. “Alternative Control Techniques Document—NO
We believe this rule is consistent with the relevant policy and guidance regarding enforceability, RACT, RACM and SIP relaxations. The TSD has more information on our evaluation.
The TSD describes additional rule revisions that we recommend for the next time the local agency modifies the rule.
Because EPA believes the submitted rule fulfills all relevant requirements, we are proposing to fully approve it as described in section 110(k)(3) of the Act. We will accept comments from the public on this proposal for the next 30 days. Unless we receive convincing new information during the comment period, we intend to publish a final approval action that will incorporate this rule into the federally enforceable SIP.
Under the Clean Air Act, the Administrator is required to approve a SIP submission that complies with the provisions of the Act and applicable Federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in reviewing SIP submissions, EPA's role is to approve State choices, provided that they meet the criteria of the Clean Air Act. Accordingly, this action merely approves State law as meeting Federal requirements and does not impose additional requirements beyond those imposed by State law. For that reason, this action:
• Is not a “significant regulatory action” subject to review by the Office of Management and Budget under Executive Order 12866 (58 FR 51735, October 4, 1993);
• Does not impose an information collection burden under the provisions of the Paperwork Reduction Act (44 U.S.C. 3501
• Is certified as not having a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601
• Does not contain any unfunded mandate or significantly or uniquely affect small governments, as described in the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4);
• Does not have Federalism implications as specified in Executive Order 13132 (64 FR 43255, August 10, 1999);
• Is not an economically significant regulatory action based on health or safety risks subject to Executive Order 13045 (62 FR 19885, April 23, 1997);
• Is not a significant regulatory action subject to Executive Order 13211 (66 FR 28355, May 22, 2001);
• Is not subject to requirements of Section 12(d) of the National Technology Transfer and Advancement
• 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, Intergovernmental relations, Nitrogen dioxide, Ozone, Particulate matter, Reporting and recordkeeping requirements.
42 U.S.C. 7401
Environmental Protection Agency (EPA).
Proposed rule.
EPA is proposing a limited approval and limited disapproval of revisions to the Santa Barbara County Air Pollution Control District (SBCAPCD) portion of the California State Implementation Plan (SIP). These revisions concern oxides of nitrogen (NO
Any comments must arrive by September 1, 2010.
Submit comments, identified by docket number EPA-R09-OAR-2010-0418, by one of the following methods:
1.
2.
3.
Idalia Perez, EPA Region IX, (415) 972-3248,
Throughout this document, “we,” “us” and “our” refer to EPA.
Table 1 lists the rules addressed by this proposal with the dates that they were adopted by the local air agency and submitted by the California Air Resources Board (CARB).
On August 22, 2008, the submittal for SBCAPCD Rule 361 was found to meet the completeness criteria in 40 CFR part 51, appendix V, which must be met before formal EPA review. On November 22, 2008, the submittal for SBCAPCD 333 was found to meet the completeness criteria.
There are no previous versions of Rule 361 in the SIP. There are no previous versions of Rule 333 in the SIP, although the District submitted a previous version of this rule on June 19, 1992 and we proposed a limited approval and a limited disapproval (60 FR 6049) but did not finalize the action. The District then submitted another
NO
Generally, SIP rules must be enforceable (see section 110(a) of the Act), must require Reasonably Available Control Technology (RACT) for each category of sources covered by a Control Techniques Guidelines (CTG) document as well as each major source in nonattainment areas (see sections 182(a)(2) and 182(f)), and must not relax existing requirements (see sections 110(l) and 193). The SBCAPCD regulates an area that is classified as maintenance for the 1-hour ozone standard and is in attainment for all criteria pollutants (see 40 CFR part 81), thus, Rules 361 and 333 do not have to fulfill RACT requirements.
Guidance and policy documents that we use to evaluate enforceability consistently include the following:
1. “State Implementation Plans; Nitrogen Oxides Supplement to the General Preamble; Clean Air Act Amendments of 1990 Implementation of Title I; Proposed Rule,” (the NO
2. “Issues Relating to VOC Regulation Cutpoints, Deficiencies, and Deviations,” EPA, May 25, 1988 (the Bluebook).
3. “Guidance Document for Correcting Common VOC & Other Rule Deficiencies,” EPA Region 9, August 21, 2001 (the Little Bluebook).
4. “State Implementation Plans; General Preamble for the Implementation of Title I of the Clean Air Act Amendments of 1990”, 57 FR 13498, April 16, 1992; 57 FR 18070, April 28, 1992.
5. “State Implementation Plans (SIPs): Policy Regarding Excess Emissions During Malfunctions, Startup and Shutdown” from Steven A. Herman, Assistant Administrator for Enforcement and Compliance Assurance, and Robert Perciasepe, Assistant Administrator for Air and Radiation, September 9, 1999.
B. Do the rules meet the evaluation criteria?
Rules 361 and 333 improve the SIP by establishing more stringent emission limits. The rules are largely consistent with the relevant policy and guidance regarding enforceability and SIP relaxations. Rule provisions which do not meet the evaluation criteria are summarized below and discussed further in the TSDs.
These provisions in Rule 361 conflict with section 110(a) of the Act and prevent full approval of the SIP revision.
1. Section F.3 defines the length of the startup and shutdown intervals as “not last[ing] longer than is necessary to reach stable temperatures and conditions”. This leads to enforceability concerns due to the lack of specificity of the duration of these periods. The duration of these periods should be further specified.
2. Section G.4 states that documentation of fuel sulfur content must be kept as a record. The type of documentation required should be specified in the rule.
These provisions in Rule 333 conflict with section 110(a) of the Act and prevent full approval of the SIP revision.
1. Rule 333 includes various provisions allowing for APCO discretion without having explicit and replicable procedures that define how the discretion will be exercised to assure emission reductions.
2. Section I.1 indicates that source tests shall be performed at the engine's maximum load or under the engines' typical duty cycle as demonstrated by historical operation data. This should be constrained to the engine's maximum load or conditions specified in the Permit to Operate. The option for testing at the engine's typical duty cycle should be further defined and justified.
The TSDs describe additional rule revisions that we recommend for the next time the local agency modifies the rules but that are not the basis for disapproval at this time.
As authorized in sections 110(k)(3) and 301(a) of the Act, EPA is proposing a limited approval of the submitted rules to improve the SIP. If finalized, this action would incorporate the submitted rules into the SIP, including those provisions identified as deficient. This approval is limited because EPA is simultaneously proposing a limited disapproval of the rules under section 110(k)(3). If this disapproval is finalized, no sanctions will be imposed under section 179 of the Act because SBCAPCD is not a required to have these rules in the applicable SIP. A final disapproval would also not trigger the 2-year clock for the federal implementation plan (FIP) requirement under section 110(c). Note that the submitted rules have been adopted by the SBCAPCD, and EPA's final limited disapproval would not prevent the local agency from enforcing them.
We will accept comments from the public on the proposed limited approval and limited disapproval for the next 30 days.
The Office of Management and Budget (OMB) has exempted this regulatory action from Executive Order 12866, entitled “Regulatory Planning and Review.”
This action does not impose an information collection burden under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501
The Regulatory Flexibility Act (RFA) generally requires an agency to conduct a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small not-for-profit enterprises, and small governmental jurisdictions.
These rules will not have a significant impact on a substantial number of small entities because SIP approvals or disapprovals under section 110 and subchapter I, part D of the Clean Air Act do not create any new requirements but simply approve or disapprove requirements that the State is already imposing. Therefore, because the
Moreover, due to the nature of the Federal-State relationship under the Clean Air Act, preparation of flexibility analysis would constitute Federal inquiry into the economic reasonableness of state action. The Clean Air Act forbids EPA to base its actions concerning SIPs on such grounds.
Under sections 202 of the Unfunded Mandates Reform Act of 1995 (“Unfunded Mandates Act”), signed into law on March 22, 1995, EPA must prepare a budgetary impact statement to accompany any proposed or final rule that includes a Federal mandate that may result in estimated costs to State, local, or tribal governments in the aggregate; or to the private sector, of $100 million or more. Under section 205, EPA must select the most cost-effective and least burdensome alternative that achieves the objectives of the rule and is consistent with statutory requirements. Section 203 requires EPA to establish a plan for informing and advising any small governments that may be significantly or uniquely impacted by the rule.
EPA has determined that the limited approval/limited disapproval action proposed does not include a Federal mandate that may result in estimated costs of $100 million or more to either State, local, or tribal governments in the aggregate, or to the private sector. This Federal action proposes to approve and disapprove pre-existing requirements under State or local law, and imposes no new requirements. Accordingly, no additional costs to State, local, or tribal governments, or to the private sector, result from this action.
These rules will not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132, because it merely proposes to approve or disapprove State rules implementing a Federal standard, and does not alter the relationship or the distribution of power and responsibilities established in the Clean Air Act. Thus, the requirements of section 6 of the Executive Order do not apply to this rule.
Executive Order 13175, entitled “Consultation and Coordination with Indian Tribal Governments” (65 FR 67249, November 9, 2000), requires EPA to develop an accountable process to ensure “meaningful and timely input by tribal officials in the development of regulatory policies that have tribal implications.” These proposed rules do not have tribal implications, as specified in Executive Order 13175. They will not have substantial direct effects on tribal governments, 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. Thus, Executive Order 13175 does not apply to these rules.
EPA specifically solicits additional comment on these proposed rules from tribal officials.
EPA interprets Executive Order 13045 (62 FR 19885, April 23, 1997) as applying only to those regulatory actions that concern health or safety risks, such that the analysis required under section 5-501 of the Executive Order has the potential to influence the regulation. This rule is not subject to Executive Order 13045, because it approves state rules implementing a Federal standard.
These rules are not subject to Executive Order 13211, “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use” (66 FR 28355, May 22, 2001) because they are not a significant regulatory action under Executive Order 12866.
Section 12 of the National Technology Transfer and Advancement Act (NTTAA) of 1995 requires Federal agencies to evaluate existing technical standards when developing a new regulation. To comply with NTTAA, EPA must consider and use “voluntary consensus standards” (VCS) if available and applicable when developing programs and policies unless doing so would be inconsistent with applicable law or otherwise impractical.
The EPA believes that VCS are inapplicable to this action. Today's action does not require the public to perform activities conducive to the use of VCS.
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. The Executive Order has informed the development and implementation of EPA's environmental justice program and policies. Consistent with the
This action will not have disproportionately high and adverse human health or environmental effects on minority, low-income or Tribal 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. Specially, EPA's simultaneous limited approval and limited disapproval of Rules 361 and 333 would have the affect of strengthening environmental requirements throughout SBCAPCD, and would not relax environmental requirements in any area.
Environmental protection, Air pollution control, Intergovernmental relations, Nitrogen dioxide, Ozone, Reporting and recordkeeping requirements.
42 U.S.C. 7401
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Proposed specification; request for comments.
NMFS proposes to specify a total allowable catch (TAC) for the 2010-11 fishing year of 254,050 lb (115,235 kg) of Deep 7 bottomfish in the main Hawaiian Islands (MHI). The TAC would be set in accordance with regulations established to support long-term sustainability of Hawaii bottomfish.
Comments must be received by August 17, 2010.
Comments on this proposed specification, identified by 0648-XX15, may be sent to either of the following addresses:
• Electronic Submission: Submit all electronic public comments via the Federal e-Rulemaking Portal www.regulations.gov; or
• Mail: Mail written comments to Michael D. Tosatto, Acting Regional Administrator, NMFS, Pacific Islands Region (PIR), 1601 Kapiolani Blvd, Suite 1110, Honolulu, HI 96814-4700.
Instructions: Comments must be submitted to one of these two addresses to ensure that the comments are received, documented, and considered by NMFS. Comments sent to any other address or individual, or received after the end of the comment period, may not be considered. Comments will be posted for public viewing after thecomment period has closed. All comments received are a part of the public record and will generally be posted to
A supplemental environmental assessment (EA) was prepared that describes the impact on the human environment that would result from this proposed action. Based on the environmental impact analyses presented in the EA, NMFS prepared a finding of no significant impact (FONSI) for the proposed action. Copies of the EA and FONSI are available from
Bob Harman, NMFS PIR Sustainable Fisheries, 808-944-2271.
This
The bottomfish fishery in Federal waters around Hawaii is managed under the Hawaii fishery ecosystem plan (FEP), developed by the Western Pacific Fishery Management Council (Council) and implemented by NMFS under the authority of the Magnuson-Stevens Fishery Conservation and Management Act, 16 U.S.C. 1801
Pursuant to regulations at 50 CFR 665.211, NMFS must specify a TAC for Deep 7 bottomfish in the MHI for each fishing year (September 1 through August 31), based on a recommendation from the Council, considering the best available scientific, commercial, and other information, and taking into account the associated risk of overfishing. The Deep 7 bottomfish are onaga (
NMFS uses commercial landings data to project the date when the TAC for the year will be reached, and closes the non-commercial and commercial fisheries from that date until the end of the fishing year. During a fishery closure for Deep 7 bottomfish, no person may fish for, possess, or sell any of these fish in the MHI, except as otherwise authorized by law. Specifically, fishing for, and the resultant possession or sale of, Deep 7 bottomfish by vessels legally registered to Pacific Remote Island Area bottomfish fishing permits, and conducted in compliance with all other laws and regulations, are not affected by the closure. There is no prohibition on fishing for or selling other non-Deep 7 bottomfish species throughout the year.
For the 2009-10 fishing year, the TAC was 254,050 lb (115,235 kg) (74 FR 48422; September 23, 2009). Monitoring of the commercial fishery indicated that the TAC for the 2009-10 fishing year was projected to be reached by April 20, 2010, and, in accordance with the regulations at § 665.211, NMFS published a temporary rule closing the non-commercial and commercial MHI bottomfish fisheries on April 20, 2010 (75 FR 17070; April 5, 2010). Subsequent analyses indicated that the 2009-10 bottomfish fishery took
At its 148th meeting in Honolulu, Hawaii, held from June 28 - July 1, 2010, the Council reviewed information about the bottomfish fishery, including a 2008 stock assessment that was updated in 2009 by the NMFS Pacific Islands Fisheries Science Center (PIFSC). After considering the status of stocks, risks of overfishing, recommendations from the Council's Science and Statistical Committee and input from the public, the Council recommended a TAC of 254,050 lb (115,235 kg). The proposed TAC is associated with a zero percent risk of overfishing of Hawaiian archipelagic bottomfish stocks. The risk of localized depletion (or excess fishing mortality) of the MHI management subarea bottomfish stocks is estimated to be in the range of 33 to 38 percent. The most recent stock assessment assumed that the entire 2009-10 TAC would be caught, but because the 2009-10 fishery took less than the TAC, the associated risk of localized depletion with the 2010-11 TAC should be even less than 33 to 38 percent. These risk levels are more conservative than the 50 percent risk threshold allowed under the Magnuson-Stevens Act.
NMFS will consider the Council's recommendation, potential environmental and economic effects of the proposed TAC, and comments received during the public comment period for this proposed specification, and will announce the final TAC specification in the
Regardless of the final TAC specification, all other management measures will continue to apply in the MHI bottomfish fishery. The MHI bottomfish fishery is scheduled to re-open on September 1, 2010, and will continue until August 31, 2011, unless the fishery is closed prior to August 31 as a result of the TAC being reached.
Pursuant to section 304(b)(1)(A) of the Magnuson-Stevens Act, the NMFS Assistant Administrator for Fisheries has determined that this proposed specification is consistent with the Hawaii FEP, other provisions of the Magnuson-Stevens Act, and other applicable laws, subject to further consideration after public comment.
The Chief Counsel for Regulation of the Department of Commerce certified to the Chief Counsel for Advocacy of the Small Business Administration that this proposed rule, if adopted, would not have a significant economic impact on a substantial number of small entities.
A description of the action, why it is being considered, and the legal basis for this action are contained in the preamble to this proposed specification. In the 2009-10 fishing year (September 1, 2009, through April 20, 2010), 451 vessels engaged in the commercial harvest of MHI bottomfish. The 2009-10 average gross revenue per vessel was $3,147, based on an average price of $6.81 per lb, and harvest of 208,412 lb. In general, the relative importance of MHI bottomfish to commercial participants as a percentage of overall fishing or household income is unknown, as the total suite of fishing and other income-generating activities by individual operations across the year has not been examined. The majority of the 451 vessels comprising the affected universe were under 30 ft (9.1 m) in length overall.
Based on available information, NMFS has determined that all vessels in the current fishery are small entities under the Small Business Administration definition of a small entity, i.e., they are engaged in the business of fish harvesting, are independently owned or operated, are not dominant in their field of operation, and have annual gross receipts not in excess of $4 million. Therefore, there are no disproportionate economic impacts between large and small entities. Furthermore, there are no disproportionate economic impacts among the universe of vessels based on gear, home port, or vessel length.
Assuming an average price of $6.81 per lb and 451 participating vessels, the proposed 2010-11 TAC of 254,050 lb is expected to yield $1,730,080 in total revenue, or an average of $3,836 in revenue per vessel, compared to $3,147 per vessel realized in the 2009-10 fishery. Even though there would be a substantial number of vessels, i.e., 100 percent of the bottomfish fleet, affected by this specification, there would be no significantly adverse economic impact to individual vessels resulting from the implementation of this specification. Therefore, pursuant to the Regulatory Flexibility Act, 5 U.S.C. 605(b), NMFS has determined that this rule will not have a significant economic impact on a substantial number of small entities.
As a result, an initial regulatory flexibility analysis is not required and none has been prepared.
This action is exempt from review under the procedures of E.O. 12866.
16 U.S.C. 1801
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 should be addressed to: Desk Officer for Agriculture, Office of Information and Regulatory Affairs, Office of Management and Budget (OMB),
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 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 should be addressed to: Desk Officer for Agriculture, Office of Information and Regulatory Affairs, Office of Management and Budget (OMB),
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.
Agricultural Marketing Service, USDA.
Notice and request for comments.
In accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35), this notice announces the Agricultural Marketing Service's (AMS) intention to request approval from the Office of Management and Budget (OMB) for an extension and revision of the currently approved information collection of the Lamb Promotion, Research, and Information Program. Once approved, AMS will be requesting OMB merge this information collection into the generic collection for National Research, Promotion, and Consumer Information Programs, 0581-0093.
Comments on this notice must be received by October 1, 2010 to be assured of consideration.
Interested persons are invited to submit written comments concerning this notice of review. Comments on this proposal must be sent to
USDA requires several forms to be filed in order to enable the administration of the program. These include forms covering the selection process for industry members to serve on a board, ballots used in referenda, and assessment forms.
The timing and frequency of collecting information are intended to meet the needs of the industry while minimizing the amount of work necessary to fill out the required reports. In addition, the information included on these forms is not available from other industry sources because such information relates specifically to individuals or organizations subject to the provisions of the Act.
We estimate the paperwork and time burden of the above referenced information collection to be as follows:
All responses to this notice will be summarized and included in the request for OMB approval. All comments will become a matter of public record.
Forest Service, USDA.
Notice.
The Proposed Action would designate the location, type of vehicle and season of use for motorized vehicles across the entire Forest in order to meet the intent of the Travel Management; Designated Routes and Areas for Motor Vehicle Use, Final Rule that was published on November 9, 2005 (70 FR 216). Over-the-snow vehicles are excluded from this Proposed Action. A Forest Plan Amendment would be required to achieve the purpose and need, and implement the Proposed Action.
Under 40 CFR 1502.9(c)(4), there is no formal scoping period for this action. The Draft Supplemental Environmental Impact Statement (SEIS) is expected in October 2010 and the Final Supplemental Environmental Impact Statement is expected in March 2011.
Send electronic comments to:
Pam Olson, Rogue River-Siskiyou National Forest, 3040 Biddle Road, Medford, Oregon 97504, Telephone (541) 618-2126; FAX (541) 618-2149.
On November 9, 2005, the Forest Service published final travel management regulations in the
In June 2007, the Forest hosted a series of four open houses in southwest Oregon to provide people an opportunity to learn more about the Travel Analysis process, and, in addition, Forest representatives met with a number of individuals, groups and neighboring land management agencies to gather information for the project.
The Forest completed an inventory of existing open roads and trails. Currently, there are approximately 4,620 road miles and approximately 1,155 trail miles. Motorized trails account for approximately 15% (170 miles) of the total trail miles.
Under the Proposed Action, roads, trails and areas that are currently part of the Forest transportation system and are open to wheeled motorized vehicle travel would remain designated for such use except as described below. The Proposed Action is being carried forward in accordance with the Travel Management Rule (36 CFR Part 212). The Draft Environmental Impact Statement (DEIS) for Motorized Vehicle Use on the Rogue River-Siskiyou National Forest was released in March 2009, with the comment period ending May 11, 2009. In December 2009, the Final Environmental Impact Statement was released, and the Record of Decision was signed on December 3, 2009. Appeals were received, and there were issues that were determined to require clarification and supplementation of the previous analysis. The Record of Decision was withdrawn in April 2010 so that those issues could be addressed within a supplemental document.
Following a decision on the FSEIS, the Forest will publish a Motor Vehicle Use Map (MVUM) identifying all Forest roads, trails and areas that are designated open for motor vehicle use by the public. The MVUM shall specify the classes of vehicles and, if appropriate, the times of year for which use is authorized. It will be updated and published annually (or more frequently if needed) when changes to the Forest's transportation system are made. Future decisions associated with changes to the MVUM may trigger the need for documentation of additional environmental analysis.
The purpose for action is to enact the Travel Management Rule, which will designate roads for motorized use. Increased demand for motorized use, lack of designated areas/routes, and the inconsistent direction contained in the Forest Plans have led to the need to reduce resource damage and social impacts, user conflicts, and address safety concerns.
Based on the stated purpose and need for action and as a result of the recent Travel Analysis process, the Forest proposes to:
• Prohibit motorized public access on approximately 60-65 miles of roads currently open in order to minimize or reduce resource damage;
• Formally designate approximately 3,390 miles of road where mixed use would be allowed. Mixed use is defined as designation of a National Forest System (NFS) road for use by both highway-legal and non-highway-legal motor vehicles;
• Construct two motorized trails to provide loop route opportunities (approximately 2 miles);
• Convert approximately 20-25 miles of NFS roads to motorized trails;
• Designate two areas where off-road motorized use is allowed. This includes continued use of the Woodruff area near Prospect and the development of an additional area near Willow Lake. Both areas are located on the High Cascades Ranger District; and
• Enact Forest Plan amendments to make both plans consistent with the Travel Management Rule. The Rogue River-Siskiyou National Forest is guided by two separate Forest Plans.
Maps illustrating the Proposed Action can found at:
In addition, maps will be available for viewing at:
The Forest Supervisor, Scott D. Conroy, is the Responsible Official for making the decision and providing direction for the analysis under the National Environmental Policy Act (NEPA).
The Forest Service will use the results of supplemental analysis to determine if the analysis is sufficient to answer and clarify the issues raised during appeal.
A Draft SEIS will be prepared for comment. Comments received on the Draft SEIS will be considered in the preparation of the Final SEIS. The Draft SEIS is now expected to be filed with the Environmental Protection Agency (EPA) and to be available for public review in October 2010. The comment period on the Draft SEIS will be 45-days from the date EPA publishes the Notice of Availability in the
Forest Service, USDA.
Notice of meeting.
The Lawrence County Recource Advisory will meet in Spearfish, South Dakota. The committee is meeting as authorized under the Secure Rural Schools and Community Self-Determination Act (Pub. L 110-343) and in compliance with the Federal Advisory Committee Act. The committee has received three formal project proposals. The purpose of the meeting is to solicit additional information from project proponents and vote on project proposals.
The meeting will be held August 16, 2010 at 5 p.m.
The meeting will be held at the Northern Hills Ranger District Office at 2014 N. Main. Written comments should be sent to Rhonda O'Byrne, 2014 N. Main, Spearfish, SD 57783. Comments may also be sent via e-mail to
All comments, including names and addresses when provided, are placed in the record and are available for public inspection and copying. The public may inspect comments received at the Northern Hills Ranger District office. Visitors are encouraged to call ahead at 605-642-4622 to facilitate entry into the building.
Rhonda O'Byrne, District Ranger, Northern Hills Ranger District, 605-642-4622.
Individuals who use telecommunication devices for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339 between 8 a.m. and 8 p.m., Eastern Standard Time, Monday through Friday.
The meeting is open to the public. The following business will be conducted: gather additional information from project proponents to gain a complete understanding of proposed projects. Once committee members have enough information, they will vote on project proposals submitted to the committee for Title II. Persons who wish to bring related matters to the attention of the committee may file written statements with the committee staff before or after the meeting. Public input sessions will be provided and individuals who made written requests by Friday, August 13, 2010, will have the opportunity to address the committee at those sessions.
Forest Service, USDA.
Notice of meeting.
The El Dorado County Resource Advisory Committee will meet in Placerville, California. The committee is meeting as authorized under the Secure Rural Schools and Community Self-Determination Act (Pub. L. 110-343) and in compliance with the Federal Advisory Committee Act. The agenda for the meeting includes: Discussions and possible decisions on an El Dorado County RAC mission statement; possible criteria for project proposals (leveraging funds, monetary limit and NEPA completion,
The meeting will be held on August 16, 2010 at 6 p.m.-9 p.m.
The meeting will be held at the El Dorado Center of Folsom Lake College, Community Room, 6699 Campus Drive, Placerville, CA 95667 . Written comments should be sent to Frank Mosbacher; Forest Supervisor's Office; 100 Forni Road; Placerville, CA 95667. Comments may also be sent via e-mail to
All comments, including names and addresses when provided, are placed in the record and are available for public inspection and copying. The public may inspect comments received at 100 Forni Road; Placerville, CA 95667. Visitors are encouraged to call ahead to 530-622-5061 to facilitate entry into the building.
Frank Mosbacher, Public Affairs Officer, Eldorado National Forest Supervisors Office, (530) 621-5268.
Individuals who use telecommunication devices for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339 between 8:00 a.m. and 8:00 p.m., Eastern Standard Time, Monday through Friday.
The meeting is open to the public. The following business will be conducted: Elect a chair and vice chair, discuss RAC norms and operating guidelines, learn about successful RACs, discuss criteria for project proposals and establish methods for soliciting proposals. More information will be posted on the Eldorado National Forest Web site
Forest Service, USDA.
Announcement of meeting (Publish prior to August 9, 2010).
On August 9, 2010, the U.S Forest Service will host the first meeting of the Federally designated Secure Rural Schools Resource Advisory Committee (RAC). The public is invited to attend the meeting and provide input. A Secure Rural Schools RAC provides advice and recommendations to the Forest Service on the development and implementation of special projects as authorized under the Secure Rural Schools and Community Self-Determination Act, Public Law 110-343.
The meeting will be held on August 9, 2010 from 1:15-4:30 p.m.
The meeting location is U.S. Forest Service, 325 John Knox Road, Suite F-100, Tallahassee, FL 32303.
Denise Rains, Public Services Staff Officer, 850-523-8568, e-mail
Florida's RAC consists of 15 people selected to serve on the committee by Secretary of Agriculture Tom Vilsack. Members are from throughout the State and represent varied interests and areas of expertise. They will work collaboratively to improve working relationships among community members and national forest personnel.
Five Florida counties, Liberty, Wakulla, Columbia, Baker and Marion, elected to set aside a percentage of their Secure Rural Schools payment. Counties receive a payment annually for having National Forest lands within their boundaries. The RAC will ultimately review and recommend projects to be funded from this money. Projects approved must benefit National Forest lands. Projects can maintain infrastructure, improve the health of watersheds and ecosystems, protect communities, and strengthen local economies.
Forest Service, USDA.
Notice of meeting.
The Ontonagon Resource Advisory Committee will meet in Ontonagon, Michigan. The committee is meeting as authorized under the Secure Rural Schools and Community Self-Determination Act (Pub. L. 110-343) and in compliance with the Federal Advisory Committee Act. The purpose is to hold the first meeting of the newly formed committee.
The meeting will be held on August 31, 2010, and will begin at 4 p.m. (EST)
The meeting will be held at the Ontonagon County Courthouse, 725 Greenland Road, Ontonagon, Michigan. Written comments should be sent to Lisa Klaus, Ottawa National Forest, E6248 U.S. Hwy. 2, Ironwood, MI 49938. Comments may also be sent via e-mail to
All comments, including names and addresses when provided, are placed in the record and are available for public inspection and copying. The public may inspect comments received at Ottawa National Forest, E6248 U.S. Hwy. 2, Ironwood, MI 49938.
Lisa Klaus, RAC coordinator, USDA, Ottawa National Forest, E6248 U.S. Hwy. 2, Ironwood, MI, (906) 932-1330, ext. 328; e-mail
Individuals who use telecommunication devices for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339 between 8 a.m. and 8 p.m., Eastern Standard Time, Monday through Friday.
The meeting is open to the public. The following business will be conducted: (1) Introductions of all committee members, replacement members and Forest Service personnel. (2) Selection of a chairperson by the committee members. (3) Receive materials explaining the process for considering and recommending Title II projects; and (4) Public comment. Persons who wish to bring related matters to the attention of the Committee may file written statements with the Committee staff before or after the meeting.
Natural Resources Conservation Service, United States Department of Agriculture.
Notice of Request for Nominations.
The Secretary of Agriculture intends to reestablish the Agricultural Air Quality Task Force (AAQTF) and requests nominations for qualified persons to serve as members.
Nominations must be received in writing by September 16, 2010.
Questions, comments, and nomination package should be sent to Jeff Schmidt, Acting Designated Federal Official. Mr. Schmidt may be contacted at the Department of Agriculture, Natural Resources Conservation Service, 420 South State Road 7, Suite 160, Royal Palm Beach, Florida 33414;
As required by Section 391 of the Federal Agriculture Improvement and Reform Act of 1996, the Chief of the Natural Resources Conservation Service (NRCS) will establish a task force to review research that addresses air quality issues related to agriculture or agriculture infrastructure. The task force will provide recommendations to the Secretary of Agriculture on development and implementation of air quality policy and on air quality research needs. The requirements of the Federal Advisory Committee Act apply to this task force.
The task force will:
(1) Review research on agricultural air quality supported by Federal agencies;
(2) Provide recommendations to the Secretary of Agriculture regarding air quality and its relation to agriculture based upon sound scientific findings;
(3) Work to ensure inter-governmental (Federal, State, and local) coordination
(4) Assist, to the extent practical, Federal agencies in correcting erroneous data with respect to agricultural air quality; and
(5) Ensure that air quality research, related to agriculture, receives adequate peer review and considers economic feasibility.
The task force will be made up of United States citizens and be composed of:
(1) Individuals with expertise in agricultural air quality and agricultural production;
(2) Representatives of institutions with expertise in the impacts of air quality on human health;
(3) Representatives from agriculture interest groups having expertise in production agriculture;
(4) Representatives from State or local agencies having expertise in agriculture and air quality; and
(5) Atmospheric scientists.
Task force nominations must be in writing and provide the appropriate background documents required by the Department of Agriculture (USDA) policy, including Form AD-755. Previous nominees and current task force members who wish to be reappointed must update their nominations and provide a new background disclosure form (AD-755) to reaffirm their candidacy (
A task force member will serve for a term of 2 years. Task force members will receive no compensation from NRCS for their service as task force members except as described below.
While away from home or regular place of business as a member of the task force, the member will be eligible for travel expenses paid by NRCS, including per diem in lieu of subsistence, at the same rate as a person employed intermittently in the government service, under section 5703 of Title 5, U.S.C.
Additional information about the AAQTF may be found on the World Wide Web at
Nominations should be typed and include the following:
(1) A brief summary, of no more than two pages, explaining the nominee's qualifications to serve on the AAQTF;
(2) Resume;
(3) A completed copy of form AD-755;
(4) Any recent publications relative to air quality; and
(5) Any letters of endorsement.
Nominations should be sent to Jeff Schmidt, Acting Designated Federal Official, Natural Resources Conservation Service, 420 South State Road 7, Suite 160, Royal Palm Beach, Florida 33414 by September 16, 2010.
To ensure that recommendations of the task force take into account the needs of underserved and diverse communities served by USDA, membership will include, to the extent practicable, individuals representing minorities, women, and persons with disabilities. USDA prohibits discrimination in its programs and activities on the basis of race, color, national origin, gender, religion, age, sexual orientation, or disability. Additionally, discrimination on the basis of political beliefs and marital or family status is also prohibited by statutes enforced by USDA (not all prohibited bases apply to all programs). Persons with disabilities who require alternate means for communication of program information (Braille, large print, audio tape, etc.) should contact the USDA's Target Center at (202) 720-2600 (voice and TDD). USDA is an equal opportunity provider and employer.
Foreign Agricultural Service, USDA.
Notice.
The Administrator of the Foreign Agricultural Service (FAS) today accepted and began a review of a petition for trade adjustment assistance filed under the FY 2011 program by the New Hampshire Commercial Fishermen's Association on behalf of American lobster (
Trade Adjustment Assistance for Farmers Program Staff, FAS, USDA by
Foreign Agricultural Service, USDA.
Notice.
The Administrator, Foreign Agricultural Service (FAS), today accepted and began a review of a petition for trade adjustment assistance under the FY 2011 program, filed by the Massachusetts Lobstermen's Association on behalf of American lobster (
Trade Adjustment Assistance for Farmers Program Staff, Office of Trade Programs, USDA, at (202) 720-0638 or (202) 690-0633, or by
The Department of Commerce will submit to the Office of Management and Budget (OMB) for clearance the following proposal for collection of information under the provisions of the Paperwork Reduction Act (44 U.S.C. Chapter 35).
Marine recreational anglers are surveyed for catch and effort data, fish biology data, and angler socioeconomic characteristics. These data are required to carry out provisions of the Magnuson-Stevens Fishery Conservation and Management Act (MSA), (16 U.S.C. 1801
The marine recreational fishing catch and effort data are currently collected through a combination of telephone surveys and on-site intercept surveys with recreational anglers. Recent amendments to the MSA require the development of an improved data collection program for recreational fisheries. To meet the requirements of the MSA, NOAA's National Marine Fisheries Service is developing pilot studies to test alternative approaches for surveying recreational anglers. Studies will test the effectiveness of panel surveys for contacting anglers and collecting recreational fishing catch and effort data. The goal of these studies is to develop an efficient means of collecting fishing data while maintaining complete coverage of the angling population, as well as testing assumptions and assessing potential sources of error in ongoing recreational fishing surveys.
Copies of the above information collection proposal can be obtained by calling or writing Diana Hynek, Departmental Paperwork Clearance Officer, (202) 482-0266, Department of Commerce, Room 6616, 14th and Constitution Avenue, NW., Washington, DC 20230 (or via the Internet at
Written comments and recommendations for the proposed information collection should be sent within 30 days of publication of this notice to David Rostker, OMB Desk Officer, FAX number (202) 395-7285, or
The Department of Commerce will submit to the Office of Management and Budget (OMB) for clearance the following proposal for collection of information under the provisions of the Paperwork Reduction Act (44 U.S.C. chapter 35).
Copies of the above information collection proposal can be obtained by calling or writing Diana Hynek, Departmental Paperwork Clearance Officer, (202) 482-0266, Department of Commerce, Room 6616, 14th and Constitution Avenue, NW., Washington, DC 20230 (or via the Internet at
Written comments and recommendations for the proposed information collection should be sent within 30 days of publication of this notice to David Rostker, OMB Desk Officer, FAX number (202) 395-7285, or
Import Administration, International Trade Administration, Department of Commerce.
Sheila E. Forbes, Office of AD/CVD Operations, Customs Unit, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue, NW., Washington, DC 20230, telephone: (202) 482-4697.
Each year during the anniversary month of the publication of an antidumping or countervailing duty order, finding, or suspension of investigation, an interested party, as defined in section 771(9) of the Tariff Act of 1930, as amended (“the Act”), may request, in accordance with section 351.213 of the Department of Commerce (“the Department”) regulations, that the Department conduct an administrative review of that antidumping or countervailing duty order, finding, or suspended investigation.
In the event the Department limits the number of respondents for individual examination for administrative reviews initiated pursuant to requests made for the orders identified below, the Department intends to select respondents based on U.S. Customs and Border Protection (“CBP”) data for U.S. imports during the period of review (“POR”). We intend to release the CBP data under Administrative Protective Order (“APO”) to all parties having an APO within five days of publication of the initiation
None.
In accordance with section 351.213(b) of the regulations, an interested party as defined by section 771(9) of the Act may request in writing that the Secretary conduct an administrative review. For both antidumping and countervailing
Please note that, for any party the Department was unable to locate in prior segments, the Department will not accept a request for an administrative review of that party absent new information as to the party's location. Moreover, if the interested party who files a request for review is unable to locate the producer or exporter for which it requested the review, the interested party must provide an explanation of the attempts it made to locate the producer or exporter at the same time it files its request for review, in order for the Secretary to determine if the interested party's attempts were reasonable, pursuant to section 351.303(f)(3)(ii) of the Department's regulations.
As explained in
Six copies of the request should be submitted to the Assistant Secretary for Import Administration, International Trade Administration, Room 1870, U.S. Department of Commerce, 14th Street and Constitution Avenue, NW., Washington, DC 20230. The Department also asks parties to serve a copy of their requests to the Office of Antidumping/Countervailing Operations, Attention: Sheila Forbes, in room 3065 of the main Commerce Building. Further, in accordance with section 351.303(f)(l)(i) of the Department's regulations, a copy of each request must be served on every party on the Department's service list.
The Department will publish in the
For the first administrative review of any order, there will be no assessment of antidumping or countervailing duties on entries of subject merchandise entered, or withdrawn from warehouse, for consumption during the relevant provisional-measures “gap” period, of the order, if such a gap period is applicable for the POR.
This notice is not required by statute but is published as a service to the international trading community.
Import Administration, International Trade Administration, Department of Commerce.
Every five years, pursuant to section 751(c) of the Tariff Act of 1930, as amended (“the Act”), the Department of Commerce (“the Department”) and the International Trade Commission automatically initiate and conduct a review to determine whether revocation of a countervailing or antidumping duty order or termination of an investigation suspended under section 704 or 734 of the Act would be likely to lead to continuation or recurrence of dumping or a countervailable subsidy (as the case may be) and of material injury.
The following Sunset Reviews are scheduled for initiation in September 2010 and will appear in that month's Notice of Initiation of Five-Year Sunset Reviews.
No Sunset Review of countervailing duty orders is scheduled for initiation in September 2010.
No Sunset Review of suspended investigations is scheduled for initiation in September 2010.
The Department's procedures for the conduct of Sunset Reviews are set forth in 19 CFR 351.218. Guidance on methodological or analytical issues relevant to the Department's conduct of Sunset Reviews is set forth in the Department's Policy Bulletin 98.3—
Pursuant to 19 CFR 351.103(c), the Department will maintain and make available a service list for these proceedings. To facilitate the timely preparation of the service list(s), it is requested that those seeking recognition as interested parties to a proceeding contact the Department in writing within 10 days of the publication of the Notice of Initiation.
Please note that if the Department receives a Notice of Intent to Participate from a member of the domestic industry within 15 days of the date of initiation, the review will continue. Thereafter, any interested party wishing to participate in the Sunset Review must provide substantive comments in response to the notice of initiation no later than 30 days after the date of initiation.
This notice is not required by statute but is published as a service to the international trading community.
An application has been submitted to the Foreign-Trade Zones (FTZ) Board (the Board) by the Columbus Regional Airport Authority, grantee of FTZ 138, requesting authority to reorganize the zone under the alternative site framework (ASF) adopted by the Board (74 FR 1170, 1/12/09; correction 74 FR 3987, 1/22/09). The ASF is an option for grantees for the establishment or reorganization of general-purpose zones and can permit significantly greater flexibility in the designation of new “usage-driven” FTZ sites for operators/users located within a grantee's “service area” in the context of the Board's standard 2,000-acre activation limit for a general-purpose zone project. The application was submitted pursuant to the Foreign-Trade Zones Act, as amended (19 U.S.C. 81a-81u), and the regulations of the Board (15 CFR part 400). It was formally filed on July 21, 2010.
FTZ 138 was approved on March 13, 1987 (Board Order 351, 52 FR 9319, 3/24/87) and expanded on February 23, 1994 (Board Order 685, 59 FR 10783, 3/8/94), on November 9, 1999 (Board Order 1063, 64 FR 63786, 11/22/99), on May 29, 2001 (Board Order 1166, 66 FR 32933, 6/19/01), on December 19, 2003 (Board Order 1311, 69 FR 49, 1/2/04) and on November 2, 2007 (Board Order 1530, 72 FR 65563; 11/21/07).
The general-purpose zone currently consists of the following sites: Site 1 (3,787 acres total) -- portions of the Rickenbacker Inland Port - includes certain acreage within the Rickenbacker International Airport and Air Industrial Park, Alum Creek East Industrial Park, Alum Creek West Industrial Park, and Groveport Commerce Center, Franklin County; Site 2 (136 acres) -- Gateway Business Park, McClain Road, Lima, Allen County; Site 3 (42 acres) -- within the 90-acre Gateway Interchange Industrial Park, State Route 104 and U.S. Route 35, Chillicothe, Ross County; Site 4 (64 acres, 2 parcels) -- within the 960-acre Rock Mill Industrial Park, south of Mill Park Drive, Lancaster, Fairfield County; Site 5 (133 acres) -- within the 149-acre D.O. Hall Business Center, State Route 660 and north of Reitler Road, Cambridge, Guernsey County; Site 6 (74 acres, 2 parcels) -- within the Eagleton Industrial Park, State Route 142 and west of Spring Valley Road, London, Madison County; Site 12 (31 acres) -- Marion Industrial Park, 1110 Cheney Avenue, Marion, Marion County; Site 13 (41 acres) -- Capital Park South, 3125-3325 Lewis Centre Way, Grove City, Franklin County; Site 14 (27 acres) -- Southpointe Industrial Park, 3901 Gantz Road, Grove City, Franklin County; Site 15 (50 acres, sunset 12/31/2011) -- Columbus Industrial District, located at 4545 Fisher Road, Columbus, Franklin County; Site 16 (74 acres, expires 9/1/2010) -- located at 1809 Wilson Road, Columbus, Franklin County; Site 17 (9 acres, expires 7/31/2011) -- Quarry East Commerce Center (Drew Shoe Company), located at 252 Quarry Drive, Lancaster, Fairfield County; Site 18 (22 acres, expires 9/1/2010) -- located at 700 Manor Park, Columbus, Franklin County; and, Site 19 (1 acre, expires 9/1/2010) -- located at 330 Oak Street, Columbus, Franklin County.
The grantee's proposed service area under the ASF would be Athens, Champaign, Clark, Coshocton, Crawford, Delaware, Fairfield, Franklin, Guernsey, Highland, Hocking, Knox, Licking, Logan, Madison, Marion, Morrow, Muskingum, Perry, Pickaway, Pike, Ross, Union, Vinton and Wyandot Counties, Ohio, as described in the application. If approved, the grantee would be able to serve sites throughout the service area based on companies' needs for FTZ designation. The proposed service area is within and adjacent to the Columbus Customs and Border Protection port of entry. The grantee also proposes to retain its existing site (Site 2) in Lima (Allen County).
The applicant is requesting authority to reorganize its existing zone project to include Sites 1, 2, 4, 5, 6 and 15 as “magnet” sites and Sites 13, 14, 16, 17 and 18 as “usage-driven” sites. The ASF allows for the possible exemption of one magnet site from the “sunset” time limits that generally apply to sites under the ASF, and the applicant proposes that Site 1 be so exempted. The applicant is also requesting authority to remove 193 acres of undeveloped land from Site 1 (Alum Creek West Industrial Park), to remove 41 acres from Site 2, to delete Site 3 in its entirety, to remove 29 acres from Site 4, to remove 6 acres from Site 6, to remove 33 acres from Site 13, to remove 20 acres from Site 14, and to delete Site 19 in its entirety. Because the ASF only pertains to establishing or reorganizing a general-purpose zone, the application would have no impact on FTZ 138's authorized subzones.
In accordance with the Board's regulations, Claudia Hausler of the FTZ
Public comment is invited from interested parties. Submissions (original and 3 copies) shall be addressed to the Board's Executive Secretary at the address below. The closing period for their receipt is October 1, 2010. Rebuttal comments in response to material submitted during the foregoing period may be submitted during the subsequent 15-day period to October 18, 2010.
A copy of the application will be available for public inspection at the Office of the Executive Secretary, Foreign-Trade Zones Board, Room 2111, U.S. Department of Commerce, 1401 Constitution Avenue NW, Washington, DC 20230-0002, and in the “Reading Room” section of the Board's website, which is accessible via www.trade.gov/ftz. For further information, contact Elizabeth Whiteman at Elizabeth.Whiteman@trade.gov or (202) 482-0473.
Import Administration, International Trade Administration, Department of Commerce.
The Department of Commerce determines that certain magnesia carbon bricks (bricks) from Mexico are being, or are likely to be, sold in the United States at less-than-fair-value (LTFV), as provided in section 735 of the Tariff Act of 1930, as amended (the Act). The estimated margins of sales at LTFV are shown in the “Final Determination Margins” section of this notice.
(August 2, 2010.)
David Goldberger 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) 482-4136 and (202) 482-4929, respectively.
On March 11, 2010, the Department of Commerce (Department) published in the
On April 9, 2010, the Department issued a post-preliminary determination analysis for the respondent in this investigation, RHI-Refmex S.A. de C.V. (Refmex) in which the Department applied a quarterly costing methodology to recalculate the cost of production (COP).
During April and May 2010, we verified the sales and COP questionnaire responses of Refmex. During May 2010, we issued the COP, U.S. sales, and home market sales verification reports.
On June 8 and June 15, 2010, respectively, the petitioner in this investigation, Resco Products Inc, and Refmex each submitted case and rebuttal briefs.
The POI is July 1, 2008, to June 30, 2009. This period corresponds to the four most recent fiscal quarters prior to the month of the filing of the petition.
The merchandise under investigation consists of certain chemically-bonded (resin or pitch), magnesia carbon bricks with a magnesia component of at least 70 percent magnesia (MgO) by weight, regardless of the source of raw materials for the MgO, with carbon levels ranging from trace amounts to 30 percent by weight, regardless of enhancements (for example, magnesia carbon bricks can be enhanced with coating, grinding, tar impregnation or coking, high temperature heat treatments, anti-slip treatments or metal casing) and regardless of whether or not antioxidants are present (for example, antioxidants can be added to the mix from trace amounts to 15 percent by weight as various metals, metal alloys, and metal carbides). Certain magnesia carbon bricks that are the subject of this investigation are currently classifiable under subheadings 6902.10.1000, 6902.10.5000, 6815.91.0000, 6815.99.2000, and 6815.99.4000
All issues raised in the case and rebuttal briefs submitted by the parties to this investigation are addressed in the “Issues and Decision Memorandum for the Final Determination in the Less-Than-Fair-Value Investigation of Certain Magnesia Carbon Bricks from Mexico” from Edward C. Yang, Acting Deputy Assistant Secretary for Antidumping and Countervailing Duty Operations, to Ronald K. Lorentzen, Deputy Assistant Secretary for Import Administration (Decision Memo), dated July 26, 2010, which is hereby adopted by this notice. A list of the issues that parties have raised and to which we have responded, all of which are in the Decision Memo, is attached to this notice as an appendix. Parties can find a complete discussion of all issues raised in this investigation and the corresponding recommendations in the Decision Memo, which is on file in the Central Records Unit, Room 1117 of the Commerce Department. In addition, a complete version of the Decision Memo
As provided in section 782(i) of the Act, we verified the sales and COP information submitted by Refmex for use in our final determination. We used standard verification procedures including an examination of relevant accounting and production records, and original source documents provided by the respondent. Our sales and cost verification results are outlined in separate verification reports.
Based on our analysis of the comments received and our findings at verification, we have made certain changes to the margin calculations for Refmex. For a discussion of these changes,
In accordance with section 735(c)(1)(B) of the Act, we are directing U.S. Customs and Border Protection (CBP) to continue to suspend liquidation of all imports of subject merchandise that are entered or withdrawn from warehouse, for consumption on or after March 11, 2010, the date of publication of the preliminary determination in the
We determine that the weighted-average dumping margins are as follows:
Section 735(c)(5)(A) of the Act provides that the estimated “All Others” rate shall be an amount equal to the weighted average of the estimated weighted-average dumping margins established for exporters and producers individually investigated, excluding any zero and
We will disclose the calculations performed within five days of the date of publication of this notice to parties in this proceeding in accordance with 19 CFR 351.224(b).
In accordance with section 735(d) of the Act, we have notified the International Trade Commission (ITC) of our final determination. As our final determination is affirmative, the ITC will determine within 45 days whether imports of the subject merchandise are causing material injury, or threat of material injury, to an industry in the United States. If the ITC determines that material injury or threat of injury does not exist, the proceeding will be terminated and all securities posted will be refunded or canceled. If the ITC determines that such injury does exist, the Department will issue an antidumping duty order directing CBP to assess antidumping duties on all imports of the subject merchandise entered, or withdrawn from warehouse, for consumption on or after the effective date of the suspension of liquidation.
This notice will serve as the only reminder to parties subject to administrative protective order (APO) of their responsibility concerning the destruction 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.
We are issuing and publishing this determination and notice in accordance with sections 735(d) and 777(i) of the Act.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice; request for comments.
The Assistant Regional Administrator for Sustainable Fisheries, Northeast Region, NMFS (Assistant Regional Administrator), has made a preliminary determination that an Exempted Fishing Permit (EFP) application contains all of the required information and warrants further consideration. This EFP would allow four commercial fishing vessels to fish outside of the limited access scallop days-at-sea (DAS) program and the sea scallop access area regulations in support of research conducted by the
Regulations under the Magnuson-Stevens Fishery Conservation and Management Act require publication of this notification to provide interested parties the opportunity to comment on applications for proposed EFPs.
Comments must be received on or before August 17, 2010.
You may submit written comments by any of the following methods:
• Email:
• Mail: Patricia A. Kurkul, Regional Administrator, NMFS, NE Regional Office, 55 Great Republic Drive, Gloucester, MA 01930. Mark the outside of the envelope “Comments on CFarm 2010 RSA EFP.”
• Fax: (978) 281-9135.
Christopher Biegel, Fisheries Management Specialist, 978-281-9112, or Don Frei, Fisheries Management Specialist, 978-281-9221.
The Coonamessett Farm Foundation has been favorably reviewed for a grant through the Atlantic sea scallop research set-aside (RSA) program. This grant would fund a project titled, “Testing of Modifications to the Cfarm Turtle Excluder Dredge for Bycatch Reduction.”
The primary objective of this testing is to test bycatch rates between the experimental dredge and a standard New Bedford scallop dredge. Four commercial scallop vessels would each conduct one 7-day trip for 28 total DAS. The vessels would deploy both dredges simultaneously in 12 30-minute tows per day, at an average speed of 4.5 knots. The researchers will collect catch data from each dredge and then immediately return the catch to the sea. The vessel is expected to catch scallops 24,000 lb (10,866 kg), winter flounder 1,200 lb (544 kg), yellowtail flounder 4,700 lb (2,131 kg), summer flounder 480 lb (544 kg), fourspot flounder 1,200 lb (544 kg), monkfish 1,200 lb (544 kg), barndoor skate 1,200 lb (544 kg), and little skate 1,200 lb (544 kg). No catch will be retained or landed. The trips will be taken in August 2010 through January 31, 2011, in Closed Area I and Closed Area II.
Coonamessett Farm submitted a complete EFP application on May 26, 2010, requesting exemption allowing four commercial fishing vessels to fish outside of the limited access Atlantic sea scallop days at sea (DAS) regulations found at 50 CFR 648.53(b) and Sea Scallop Access Area regulations found at 50 CFR 648.59. Any fishing activity conducted outside the scope of the exempted fishing activity would be prohibited.
16 U.S.C. 1801
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of public meetings.
The North Pacific Fishery Management Council (Council) and its advisory committees will hold public meetings, August 16-19, 2010.
The Council will begin its plenary session at 8 a.m. on Wednesday, August 18 continuing through Thursday, August 19, 2010. The Council's Advisory Panel (AP) will begin at 8 a.m., Tuesday, August 17 and continue through Wednesday, August 18, 2010. The Scientific and Statistical Committee (SSC) will begin at 8 a.m. on Monday, August 16 and continue through Tuesday August 17, 2010. All meetings are open to the public, except executive sessions.
The meetings will be held at the Hotel Captain Cook, 939 West 5th Avenue, Anchorage, AK.
David Witherell, Council staff, telephone: (907) 271-2809.
This notice is an addendum to the previously published meeting agenda. The original notice published in the
These meetings are physically accessible to people with disabilities. Requests for sign language interpretation or other auxiliary aids should be directed to Gail Bendixen at (907) 271-2809 at least 7 working days prior to the meeting date.
International Trade Administration, Department of Commerce.
Notice: Revised Application Deadline.
Because of space limitations and the need to make travel and exhibition arrangements in advance, the Department of Commerce, International Trade Administration, U.S. and Foreign Commercial Service and the Economic Development Administration have advanced the application deadline for company participants from October 15, 2010 to September 15, 2010. The deadline for community delegates remains August 15, 2010. For the convenience of interested stakeholders, the revised mission statement is reprinted below in its entirety with the revised deadline.
The United States Department of Commerce's International Trade Administration, U.S. and Foreign Commercial Service (USFCS), and Economic Development Administration (EDA) are holding the first ever U.S. Clean Technology Trade & Investment Mission to Lyon, France, November 29-December 2, 2010 and to Brussels, Belgium, December 2-4, 2010. This joint mission will be led by senior Department of Commerce officials Brian McGowan, Deputy Assistant Secretary for Economic Development, and Karen Zens, Deputy Assistant Secretary for International Operations (OIO) of the USFCS. This mission is designed to advance President Obama's economic growth initiatives and Secretary Locke's goal of simplifying access to the Department of Commerce's diverse suite of resources—all for the purpose of employment generation. This initiative will support both bureaus' job creation goals by increasing exports and attracting foreign direct investment (FDI), placing a particular emphasis on the clean technology sector.
This mission is especially significant as it includes, for the first time ever, both U.S. companies and delegates from U.S. communities. Please see the section titled “Participation Requirements” below for more information on community delegates and selection criteria that will be used to evaluate applicants. While traditional trade missions are limited to business-to-business connections, the addition of communities in this model provides much broader access to U.S. companies by leveraging regional business networks. Community delegates will focus on clean technologies as a key component of their regional strategies for increasing exports and attracting FDI. Therefore, this new model allows the mission to advance a variety of Presidential and Department of Commerce priorities simultaneously, including job creation, export development, attracting FDI, building the green economy, and advancing regional innovation clusters.
France is an economic and political leader in the Eurozone due to its size, location, large economy, membership in European organizations, and energetic diplomacy. With a GDP of $2.865 trillion,
Both trade and investment between the U.S. and France are strong and are key factors for companies and communities to participate in the mission. On average, over 1 billion dollars in commercial transactions take place between France and the U.S. every day, with the U.S. being France's sixth largest supplier and its sixth largest customer. France ranks as the United States' eighth largest trading partner for total trade. Currently, there are approximately 2,300 French subsidiaries in the U.S. that provide more than 520,000 jobs and that generate an estimated $235 billion in turnover annually. As for investment, the U.S. is the top destination for French investments worldwide. In 2008, French direct investment inflow to the U.S. was approximately $14 billion. Foreign firms have invested in the U.S. through acquisitions and with greenfield investments. Between 2004 and 2008, France's FDI stock in the United States increased from $138 billion to over $163 billion. This makes this mission an ideal platform for companies and communities to position themselves for investment and export successes. Further, French FDI to the U.S. supports almost 500,000 jobs. Concurrently, the U.S. is the largest foreign direct investor in France, employing over 650,000 French citizens with aggregate investment estimated at $75 billion in 2008. This makes the U.S. more attractive to French investors and foreign direct investment.
France possesses vast renewable energy resources, including wind, geothermal energy, and biomass, all of which have shown substantial growth in recent years. France is also currently ranked 2nd highest in the EU in terms of biofuel production and use. A continued increase in the level of production helps consolidate the nation's position. Both tax reductions and capital grants are in place to promote biofuels. In addition, major potential exists in the area of solid biomass. Biomass accounts for two thirds of all the renewables used in France today and hydro power for another third.
As France's government sets new goals in terms of green energy, U.S. communities have a window of opportunity to promote their regional businesses to play a pivotal role in providing the means to increase renewable energy capacity. Wind and solar power especially are at the core of a new push by the French government to increase the renewable share of total energy consumption from 6.7 percent in 2004 to 20 percent by 2020. Also, installed capacity for photovoltaic (PV) power is to increase from 32.7 MW in 2006—about 100 times less than Germany—to 3,000 MW by 2020. In addition, 5 million solar thermal units are to be installed in buildings by 2020, 80 percent of these in homes. All these factors considered create a large market of potential buyers for U.S. businesses, and therefore provide strong job creation potential for U.S. communities that are working to develop regional innovation clusters focused on the cleantech sector.
One of the “best prospects” for U.S. business in France is water resources equipment and services. The total French market for water treatment equipment and related services is estimated to be worth $23 billion. A stable economy and financial institutions, stronger European Union (E.U.) regulations, and greater public awareness and the increasing costs associated with polluting have played a major role in an expanding market for water treatment equipment and services. In addition, greater interest in complying with environmental regulations by national and local government officials has stimulated this market. Despite the current financial and economic challenges, the water sector is still expected to grow at a stable rate and provide continued market opportunities in a number of areas.
Best prospects include wastewater sludge treatment; installation and maintenance of stand-alone sewage treatment tanks; remote monitoring technology; and membranes and water filters. Non point source pollution management and water conservation including leak detection and reclamation are becoming of major importance.
Pollutec is an International Exhibition of Environmental Equipment, Technology and Services for industry and local authorities. Pollutec is a key exhibition for U.S. companies and community delegates to attend as it is the world's leading event for the environmental market with 8,422 professionals from 110 countries all in search of comprehensive solutions to the environmental and economic challenges today. This creates the perfect atmosphere to meet industry professionals and key players in order to
For four days, U.S. community delegates and companies will network with potential trading and investment partners in the cleantech sector through customized one-on-one meetings with foreign companies arranged through a DOC/Pollutec partnership. Meanwhile, they will also learn about the latest cleantech trends and technologies through the Pollutec exhibition, which will feature all the techniques for prevention and treatment of various sources of pollution and more generally the preservation and implementation of environmental preservation and sustainable development. Pollutec offers an assortment of exhibition sectors including: treatment of pollutant gases; analysis, measurement and monitoring; energy and greenhouse gases; renewable energy; CO2 collection and storage; eco-management; biofuel; low consumption vehicles; electric vehicles; industrial, natural, and sanitary risks; services and sustainable development; waste treatment and services; and recycling. An outstanding conference program will also run parallel including 320 seminars, presentations, and technical conferences by experts and associations.
Densely populated Belgium is located at the heart of Europe's most industrialized region. Belgium per capita GDP ranks among the world's highest with a total of $390.2 billion in 2008. The U.S. ranks as Belgium's 5th principal trading partner; with Belgium ranked 18th for largest U.S. trading partner. The Belgian market is small enough that a huge European-wide commitment to a new product is not necessary, yet diverse and competitive enough that it offers a representative sample of potential buyers and competitors. Belgium's trade advantages are derived from its central geographic location and its highly skilled, multilingual, and productive workforce. With a total of 10.5 million people, the population density is the second highest in Europe, after the Netherlands, and is heavily reliant on international trade for its prosperity. Belgium's central location in the wealthy region of Europe makes the country an ideal gateway for exports to Europe. Within a radius of 300 miles, 140 million EU consumers can be reached (equivalent to almost 50% of the U.S. population) representing 60% of Europe's purchasing power. The government has focused its national reform program on key priorities intended to achieve long-term sustainable growth prospects, such as protecting the environment.
Belgium is one of the top 20 markets for U.S. environmental exports. U.S. green exports to Belgium grew by 50% since 2002 and in 2009, U.S. green exports reached
The total stock of Belgian FDI in the U.S. was $18.6 billion in 2008, making it the 15th largest direct investor in the U.S. The flow of FDI from Belgium to the U.S. was negative $5.8 billion in 2008, a substantial decrease from the $13.9 million inflow to the U.S. in 2007. However, overall between 2004 and 2008, Belgian FDI stock in the United States increased from $12.6 billion to $18.6 billion. Belgian FDI in the U.S. supports 141,000 jobs.
Belgium has also hosted two Department of Commerce Invest In America (IIA) events, and those events resulted in greater success than other IIA events in any other country to date. The first IIA event from just a year and a half ago has produced five investment successes in California, Indiana, Virginia and Florida. However there are other successes that have not yet been recorded making it an even larger success. The most recent IIA event held a few months ago has already produced three investments. The Council of American States in Europe (C.A.S.E.), which helps European companies locate production sites or sales and distribution operations for their products and services in the U.S., has stated emphatically that Brussels holds the most qualified participants and generates the most investment results compared with other investment roadshows. The past events have attracted participants from the Netherlands, Germany, France and the UK, and we expect similarly broad participation in this portion of the mission as well.
In 2009, 40% of U.S. environmental exports to Belgium are related to water and wastewater. This equaled over USD 200 million in products and services. Trends and best prospects for this sector are infrastructure projects to build wastewater treatment plants or more specifically small-scale “start to finish” wastewater treatment projects or water filtration systems for drinking water.
As Belgium faces numerous pollution problems, they realize that proper management of solid waste is a central pillar of forward-looking, sustainable environmental policies. As a result, it is attempting to figure out how to minimize the environmental impacts from waste treatment, while optimizing energy and material recovery and minimizing the costs.
In 2009 24% of U.S. environmental exports to Belgium were related to solid waste, recycling and soil remediation. This equaled USD 110 million in products and services. Compared to other EU countries, Belgium is at the forefront of solid waste disposal and treatment. For example, Belgium has a voluntary waste policy program. This means that municipalities, under certain agreements, can receive subsidies by achieving pre-specified residential solid waste targets. Also, through their advanced separate trash collection programs, the residual waste items in Flanders (Flemish speaking part of Belgium) have been reduced to about 160 kg per capita, per year whereas the European average for waste items is about 320 kg per capita. Best prospects for U.S. firms in this sector include but are not limited to plastic sorting technology, waste separation, selective collection systems, and waste-to-energy technologies.
It is also important to note that a trade and investment mission to Belgium does not preclude exposure and partnership opportunities with other European countries. On the contrary, groups from other countries operate a large part of the Belgian waste market, making Belgium an optimal choice for U.S. companies and communities to pursue trade and FDI opportunities.
The energy sector has long been one of Belgium's leading industries. Current shifts such as de-regulation and liberalization, the discussion on the
• Support the President's initiative to double exports during the next five years to support 2 million American jobs by connecting U.S. communities and companies with potential European trading partners.
• Promote the U.S. green economy by connecting representatives of U.S. regional innovation clusters focused on cleantech with potential foreign investors and trading partners.
• Progress in addressing cleantech market access barriers to trade and investment between participating nations.
• Increase awareness of President Obama's priorities in promoting exports.
• Welcome foreign direct investment in the cleantech sector.
• Help companies gain valuable international business experience in the rapidly growing renewable energy and cleantech market.
• Help U.S. communities strengthen their engagement in the worldwide marketplace, which will lead to increased exports and FDI, and, in turn, job creation.
Participants will gain from operating on a two track mission: Export promotion and foreign direct investment attraction. Companies will promote their products and services while communities will promote the competitiveness of their economic regions as promising investment opportunities for foreign companies. U.S. companies and communities will benefit through open opportunities via matchmaking support to facilitate discussions with international firms at Pollutec in Lyon, and in networking forums in Brussels. ITA will be able to expand its trade mission model from a “U.S. company to foreign company” to “U.S. community to foreign company” format. As each U.S. community represents many companies, this format offers the potential for exponential growth in U.S. exports and of FDI in the U.S.
• The proposed schedule allows for four days in Lyon and two days in Brussels.
• Matchmaking and networking.
• Access to VIP lounge.
• Networking receptions and luncheon (TBC).
• U.S. Pavilion exposure including promotion through shared exhibit space (literature display) and meeting point.
• Access to Pollutec trade exhibition, conference, and presentations.
• Visit to cleantech cluster in Rhone-Alps region (TBC).
All parties interested in participating in the U.S. Cleantech Trade & Investment Mission must complete and submit an application package for consideration by the Department of Commerce. All applicants will be evaluated on their ability to meet certain conditions and best satisfy the selection criteria as outlined below. A maximum of 20 companies and 20 community delegates will be considered for the mission.
All Applicants, whether a company or a community delegate, must:
• Submit a completed and signed mission application, and, if selected, a signed Participation Agreement, and a completed Market Interest Questionnaire.
• Certify that the products and services to be promoted through the mission are either produced in the United States or marketed under the name of a U.S. firm and have at least 51 percent U.S. content of the value of the finished product or service.
• 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 applications.
Companies must include adequate information on:
• The company's products and/or services, primary market objectives, and goals for participation, and previous company activities or initiatives participated in to advance regional economic development.
Community Delegates may be a:
• State or local government official,
• University official,
• Non-profit representative, or
• Representative of an EDA-recognized regional entity.
In addition, each Community Delegate must be:
• The authorized representative of the governmental entity or entities responsible for implementing a regional, State, or local economic development strategy. At the time of application, a community delegate must demonstrate that they are the authorized representative by providing documentation as follows:
• The Department of Commerce may consider applications from non-profit organizations that represent such communities on a national basis. Authorized representative documentation is not required for such organizations.
• Community Delegates must demonstrate at the time of application how their community's economic development strategy promotes increased exports and foreign direct investment in general, and the green economy in particular.
• Additional representatives accompanying community delegates must adhere to the selection criteria applicable to community delegates.
The following factors will be used to select participants:
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○ Suitability of the company's products or services for the renewable energy and cleantech market.
○ Participation in coordinated economic development strategies for their community.
○ Potential for business in France and Belgium, including the likelihood of exports resulting from the mission.
○ Consistency of the applicant's goals and objectives with the stated scope of the mission.
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○ Consistency of the community's economic strategic plan with the stated scope of this mission,
○ Broad U.S. geographic diversity,
○ Industry cluster representation related to advancing the green economy, and
○ Community economic distress levels.
Referrals from political organizations and any documents containing references to partisan political activities (including political contributions) will be removed from an applicant's submission and not considered during the selection process.
Mission recruitment will be conducted in an open and public manner, including publication in the
Information can also be obtained by contacting the mission contacts listed below.
Defense Acquisition Regulations System, Department of Defense (DoD).
Notice and request for comments regarding a proposed extension of an approved information collection requirement.
In compliance with section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995 (44 U.S.C. chapter 35), DoD announces the proposed extension of a public information collection requirement and seeks public comment on the provisions thereof. DoD invites comments on: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of DoD, including whether the information will have practical utility; (b) the accuracy of the estimate of the burden of the proposed information collection; (c) ways to enhance the quality, utility, and clarity of the information to be collected; and (d) ways to minimize the burden of the information collection on respondents, including the use of automated collection techniques or other forms of information technology. The Office of Management and Budget (OMB) has approved this information collection requirement for use through October 31, 2007. DoD proposes that OMB extend its approval for use through October 31, 2013.
DoD will consider all comments received by October 1, 2010.
You may submit comments for OMB Control Number 0704-0225, using any of the following methods:
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Comments received generally will be posted without change to
Mr. Julian Thrash, 703-602-0310.
DFARS 204.404-70(a) prescribes use of DFARS Clause 252.204-7000, Disclosure of Information, in contracts that require the contractor to access or generate unclassified information that may be sensitive and inappropriate for release to the public. The clause requires the contractor to obtain approval of the contracting officer before release of any unclassified contract-related information outside the contractor's organization, unless the information is already in the public domain. In requesting this approval, the contractor must identify the specific information to be released, the medium to be used, and the purpose for the release.
DFARS 204.7207 prescribes use of the DFARS provision 252.204-7001, Commercial and Government Entity (CAGE) Code Reporting, in solicitations when CAGE codes for potential offerors are not available to the contracting officer. The provision requires an offeror to enter its CAGE code on its offer. If an offeror does not have a CAGE code, the offeror may request one from the contracting officer, who will ask the offeror to complete section B of DD Form 2051, Request for Assignment of a Commercial and Government Entity (CAGE) Code.
Defense Acquisition Regulations System, Department of Defense (DoD).
Notice and request for comments.
In compliance with section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995 (44 U.S.C. chapter 35), DoD announces the proposed extension of a public information collection requirement and seeks public comment on the provisions thereof. DoD invites comments on: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of DoD, including whether the information will have practical utility; (b) the accuracy of the estimate of the burden of the proposed information collection; (c) ways to enhance the quality, utility, and clarity of the information to be collected; and (d) ways to minimize the burden of the information collection on respondents, including the use of automated collection techniques or other forms of information technology. The Office of Management and Budget (OMB) has approved this information collection under Control Number 0704-0232 for use through November 30, 2010. DoD is proposing that OMB extend its approval for use for three additional years.
DoD will consider all comments received by October 1, 2010.
You may submit comments, identified by OMB Control Number 0704-0232, using any of the following methods:
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Comments received generally will be posted without change to
Mr. Mark Gomersall, at 703-602-0302. The information collection requirements addressed in this notice are available on the World Wide Web at:
DoD contracting officers need the information required by DFARS 215.407-5, Estimating systems, and the related contract clause at 252.215-7002, Cost Estimating System Requirements, to determine if a contractor has an acceptable system for generating cost estimates, and to monitor the correction of any deficiencies.
DFARS 215.404-71-4, Facilities capital employed, requires the use of DD Form 1861 as a means of linking Form CASB-CMF, Facilities Capital Cost of Money Factors Computation, and DD Form 1547, Record of Weighted Guidelines Application. The contracting officer uses DD Form 1861 to record and compute contract facilities capital cost of money and facilities capital employed, and carries the facilities capital employed amount to DD Form 1547 to develop a profit objective. When the weighted guidelines method is used as one of the three structured approaches for developing a prenegotiation profit or fee objective in accordance with DFARS 215.404-4, completion of DD Form 1861 requires contractor information not included on Form CASB-CMF, i.e., distribution percentages of land, buildings, and equipment for the business unit performing the contract.
DFARS 215.407-5, Estimating systems, and the clause at 252.215-7002, Cost Estimating System Requirements, require that certain large business contractors—
○ Establish an acceptable cost estimating system and disclose the estimating system to the administrative contracting officer (ACO) in writing;
○ Maintain the estimating system and disclose significant changes in the system to the ACO on a timely basis; and
○ Respond in writing to written reports from the Government that identify deficiencies in the estimating system.
Department of Education.
The Director, Information Collection Clearance Division, Regulatory Information Management Services, Office of Management invites comments on the submission for OMB review as required by the Paperwork Reduction Act of 1995 (Pub. L. 104-13).
Interested persons are invited to submit comments on or before September 1, 2010.
Written comments should be addressed to the Office of Information and Regulatory Affairs,
Section 3506 of the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35) requires that the Office of Management and Budget (OMB) provide interested Federal agencies and the public an early opportunity to comment on information collection requests. The OMB is particularly interested in comments which:
• Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
• Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
• Enhance the quality, utility, and clarity of the information to be collected; and
• Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology.
Requests for copies of the information collection submission for OMB review may be accessed from the RegInfo.gov Web site at
Individuals who use a telecommunications device for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339.
Take notice that the following hydroelectric application has been filed with the Commission and is available for public inspection.
a.
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k. Pursuant to section 4.32(b)(7) of 18 CFR of the Commission's regulations, if any resource agency, Indian tribe, or person believes that an additional scientific study should be conducted in order to form an adequate factual basis for a complete analysis of the application on its merit, the resource agency, Indian tribe, or person must file a request for a study with the Commission not later than 60 days from the date of filing of the application, and serve a copy of the request on the applicant.
l.
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 (
m. The application is not ready for environmental analysis at this time.
n. The proposed project would utilize the existing U.S. Army Corps of Engineers' Lock & Dam No. 21, and would consist of the following facilities: (1) A new hydropower structure, located about 100 feet downstream of the existing dam and having a total of 30 generating units with a total installed capacity of 15 megawatts; (2) a new 1.57-mile-long, 69-kilovolt transmission line; (3) an existing substation; (4) a new access road; and (5) appurtenant facilities. The average annual generation would be about 74,000 megawatt-hours.
o. A copy of the application is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's Web site at
You may also register online at
p. With this notice, we are initiating consultation with the Illinois and Missouri State Historic Preservation Officers (SHPO), as required by section 106 of the National Historic Preservation Act and the regulations of the Advisory Council on Historic Preservation, 36 CFR 800.4.
q.
The Federal Energy Regulatory Commission hereby gives notice that members of the Commission and Commission staff may attend the
• August 4, 2010 (Rensselaer, NY).
• September 1, 2010 (Rensselaer, NY).
• October 6, 2010 (Rensselaer, NY).
• November 3, 2010 (Rensselaer, NY).
• August 25, 2010 (Rensselaer, NY).
• September 29, 2010 (Rensselaer, NY).
• October 21, 2010 (Rensselaer, NY).
• November 17, 2010 (Rensselaer, NY).
• December 15, 2010 (Rensselaer, NY).
• July 27, 2010 (Rensselaer, NY).
• August 9, 2010 (Rensselaer, NY).
• August 30, 2010 (Rensselaer, NY).
• September 13, 2010 (Rensselaer, NY).
• October 29, 2010 (Rensselaer, NY).
• November 9, 2010 (Rensselaer, NY).
• November 15, 2010 (Rensselaer, NY).
• December 13, 2010 (Rensselaer, NY).
• August 5, 2010 (Rensselaer, NY).
• September 2, 2010 (Rensselaer, NY).
• October 7, 2010 (Rensselaer, NY).
• November 4, 2010 (Rensselaer, NY).
• December 9, 2010 (Rensselaer, NY).
• July 29, 2010 (Rensselaer, NY).
• August 26, 2010 (Rensselaer, NY).
• September 30, 2010 (Rensselaer, NY).
• November 5, 2010 (Rensselaer, NY).
• November 16, 2010 (Rensselaer, NY).
• December 2, 2010 (Rensselaer, NY).
For additional meeting information, see:
The discussions at each of the meetings described above may address matters at issue in pending proceedings before the Commission including the following:
The meetings are open to stakeholders. For more information, contact Jesse Hensley, Office of Energy Market Regulation, Federal Energy Regulatory Commission at (202) 502-6228 or
On June 26, 2008, Idaho Power Company, licensee for the Swan Falls Hydroelectric Project, filed an Application for a New License pursuant to the Federal Power Act (FPA) and the Commission's regulations thereunder. The Swan Falls Hydroelectric Project is on the Snake River in Ada and Owyhee counties of southwestern Idaho.
The license for Project No. 503 was issued for a period ending June 30, 2010. Section 15(a)(1) of the FPA, 16 U.S.C. 808(a)(1), requires the Commission, at the expiration of a license term, to issue from year to year an annual license to the then licensee under the terms and conditions of the prior license until a new license is issued, or the project is otherwise disposed of as provided in section 15 or any other applicable section of the FPA. If the project's prior license waived the applicability of section 15 of the FPA, then, based on section 9(b) of the Administrative Procedure Act, 5 U.S.C. 558(c), and as set forth at 18 CFR 16.21(a), if the licensee of such project has filed an application for a subsequent license, the licensee may continue to operate the project in accordance with the terms and conditions of the license after the minor or minor part license expires, until the Commission acts on its application. If the licensee of such a project has not filed an application for a subsequent license, then it may be required, pursuant to 18 CFR 16.21(b), to continue project operations until the Commission issues someone else a license for the project or otherwise orders disposition of the project.
If the project is subject to section 15 of the FPA, notice is hereby given that an annual license for Project No. 503 is issued to Idaho Power Company for a period effective July 1, 2010 through June 30, 2011, or until the issuance of a new license for the project or other disposition under the FPA, whichever comes first. If issuance of a new license (or other disposition) does not take place on or before June 30, 2011, notice is hereby given that, pursuant to 18 CFR 16.18(c), an annual license under section 15(a)(1) of the FPA is renewed automatically without further order or notice by the Commission, unless the Commission orders otherwise.
If the project is not subject to section 15 of the FPA, notice is hereby given that Idaho Power Company is authorized to continue operation of the Swan Falls Hydroelectric Project, until such time as the Commission acts on its application for a subsequent license.
Take notice that on July 19, 2010, July 20, 2010, and July 23, 2010, respectively the applicants listed above submitted their baseline filing of its Statement of Operating Conditions for services provided under section 311 of the Natural Gas Policy Act of 1978 (NGPA).
Any person desiring to participate in this rate proceeding must file a motion 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 and 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 date as indicated below. Anyone filing an intervention or protest must serve a copy of that document on the Applicant. Anyone filing an intervention or protest on or before the intervention or protest date need not serve motions to intervene or protests on persons other than the Applicant.
The Commission encourages electronic submission of protests and interventions in lieu of paper using the “eFiling” link at
This filing is accessible on-line at
Take notice that on July 14, 2010, UGI Central Penn Gas, Inc. (Central Penn) filed its Statement Operating Conditions in compliance with the June 14, 2010 Letter Order approving a Stipulation and Agreement of Settlement and pursuant to section 284.123(e) of the Commission's regulations.
Any person desiring to protest this filing must file in accordance with Rule 211 of the Commission's Rules of Practice and Procedure (18 CFR 385.211). Protests to this filing 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. Such protests must be filed on or before 5 p.m. Eastern time on the specified comment date. Anyone filing a protest must serve a copy of that document on all the parties to the proceeding.
The Commission encourages electronic submission of protests in lieu of paper using the “eFiling” link at
This filing is accessible on-line at
The staff of the Federal Energy Regulatory Commission (FERC or Commission) has prepared an environmental assessment (EA) for the Northeastern Tennessee Project proposed by East Tennessee Natural Gas (ETNG) in the above referenced docket. ETNG requests authorization to construct, replace and abandon natural gas pipeline transmission facilities in southwestern Virginia and northeastern Tennessee to provide natural gas service for the Tennessee Valley Authority's recently approved John Sevier Combined Cycle Plant.
The EA assesses the potential environmental impacts resulting from construction and operation of the proposed Northeastern Tennessee Project in accordance with the requirements of the National Environmental Policy Act. The FERC staff concludes that approval of the proposed project, with appropriate mitigating measures, would not constitute a major federal action significantly affecting the quality of the human environment.
The proposed Northeastern Tennessee Project includes:
• Replacing approximately 11.5 miles of existing 12-inch- and 8-inch-diameter natural gas transmission pipeline with 24-inch-diameter natural gas transmission pipeline;
• Installing approximately 16.4 miles of new 24-inch-diameter natural gas pipeline;
• Constructing associated minor aboveground facilities; and
• Modifying piping at two existing compressor stations.
The EA has been placed in the public files of the FERC and is available for public viewing on the FERC's Web site at
Copies of the EA have been mailed to federal, state, and local government representatives and agencies; elected officials; environmental and public interest groups; Native American tribes; potentially affected landowners and other interested individuals and groups; newspapers and libraries in the project area; and parties to this proceeding.
Any person wishing to comment on the EA may do so. Your comments should focus on potential environmental impacts, reasonable alternatives, and measures to avoid or lessen environmental impacts. The more specific your comments, the more useful they will be. To ensure that your comments are properly recorded and considered prior to a Commission decision on the proposal, it is important that the FERC receives your comments in Washington, DC on or before August 23, 2010.
For your convenience, there are three methods you can use to submit your comments to the Commission. In all instances, please reference the project Docket Number CP10-89-000 with your submission. The Commission encourages electronic filing of comments and has dedicated eFiling expert staff available to assist you by phone at (202) 502-8258 or by e-mail at
(1) You may file your comments electronically by using the eComment feature, which is located on the Commission's Web site at
(2) You may file your comments electronically by using the eFiling feature, which is located on the Commission's Web site at
(3) 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.
Although your comments will be considered by the Commission, simply filing comments will not serve to make the commentor a party to the proceeding. Any person seeking to become a party to the proceeding must file a motion to intervene pursuant to Rule 214 of the Commission's Rules of Practice and Procedures (18 CFR 385.214).
Affected landowners and parties with environmental concerns may be granted intervenor status upon showing good cause by stating that they have a clear and direct interest in this proceeding which would not be adequately represented by any other parties. You do not need intervenor status to have your comments considered.
Additional information about the project is available from the Commission's Office of External Affairs, at (866) 208-FERC or on the FERC Web site (
In addition, the Commission offers a free service called eSubscription which allows you to keep track of all formal issuances and submittals in specific dockets. This can reduce the amount of time you spend researching proceedings by automatically providing you with notification of these filings, document summaries, and direct links to the documents. Go to
The staff of the Federal Energy Regulatory Commission (FERC or Commission) has prepared a final environmental impact statement (EIS) for the Apex Expansion Project proposed by Kern River Gas Transmission Company (Kern River) in the above-referenced docket. Kern River requests authorization to expand its natural gas pipeline system in Wyoming, Utah, and Nevada, to transport an additional 266 million cubic feet per day of natural gas from existing receipt points in southwestern Wyoming, to existing delivery connections in southern Nevada.
The final EIS assesses the potential environmental effects of the construction and operation of the Apex Expansion Project in accordance with the requirements of the National Environmental Policy Act of 1969 (NEPA). The FERC staff concludes that approval of the proposed project would have some adverse environmental impact; however, these impacts would be reduced to less-than-significant levels with the implementation of Kern River's proposed mitigation and the additional measures recommended in the final EIS.
The Bureau of Land Management (BLM), the Forest Service (USFS), and the Bureau of Reclamation (Reclamation) participated as cooperating agencies in the preparation of the EIS. Cooperating agencies have jurisdiction by law or special expertise with respect to resources potentially affected by the proposal and participate in the NEPA analysis. The cooperating agencies will adopt and use the EIS to consider the issuance of right-of-way grants on federally administered lands. While the conclusions and recommendations presented in the final EIS were developed with input from the cooperating agencies, the agencies will present their own conclusions and recommendations in their respective Records of Decision for the project.
The final EIS addresses the potential environmental effects of the construction and operation of the following project facilities:
• Approximately 27.6 miles of 36-inch-diameter natural gas pipeline loop
• One new 30,000-horsepower compressor station (known as the Milford Compressor Station) in Beaver County, Utah;
• Modifications to four existing compressor stations to add additional compression: The Coyote Creek Compressor Station located in Uinta County, Wyoming; the Elberta Compressor Station located in Utah County, Utah; the Fillmore Compressor Station located in Millard County, Utah; and the Dry Lake Compressor Station located in Clark County, Nevada;
• Six mainline valves; and
• Three pig
The final EIS has been placed in the public files of the FERC and is available for public viewing on the FERC's Web site at
Copies of the EIS have been mailed to federal, state, and local government representatives and agencies; elected officials; environmental and public interest groups; Native American tribes; local newspapers and libraries in the project area; parties to this proceeding; and potentially affected landowners and other interested individuals and groups. Paper copy versions of this EIS were mailed to those specifically requesting them; all others received a CD version.
Additional information about the project is available from the Commission's Office of External Affairs, at (866) 208-FERC or on the FERC (
In addition, the Commission offers a free service called eSubscription that allows you to keep track of all formal issuances and submittals in specific dockets. This can reduce the amount of time you spend researching proceedings by automatically providing you with notification of these filings, document summaries, and direct links to the documents. Go to
Take notice that on July 15, 2010, Pelico Pipeline, LLC (Pelico) filed a revised Statement of Operating conditions to modify several gas quality specifications to be consistent with the downstream pipeline specifications. In addition, the imbalance cash out section has been revised to modify the pipeline indices used for the cash out to be aligned with recent market conditions and pipeline activity and the pressure base has been updated to current practice.
Any person desiring to participate in this rate filing must file in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 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 date as indicated below. Anyone filing an intervention or protest must serve a copy of that document on the Applicant. Anyone filing an intervention or protest on or before the intervention or protest date need not serve motions to intervene or protests on persons other than the Applicant.
The Commission encourages electronic submission of protests and interventions in lieu of paper using the “eFiling” link at
This filing is accessible on-line at
Take notice that on July 15, 2010, EasTrans, LLC (EasTrans) filed to significantly modify its Statement of Operating Conditions to provide clarification and reflect the implementation of a new EasTrans nomination process.
Any person desiring to participate in this rate filing must file in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 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 date as indicated below. Anyone filing an intervention or protest must serve a copy of that document on the Applicant. Anyone filing an intervention or protest on or before the intervention or protest date need not 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
Take notice that on July 20, 2010, Kinder Morgan Interstate Gas Transmission LLC (KMIGT), PO Box 281304, Lakewood, Colorado 80228-8304, filed a prior notice request pursuant to sections 157.205, 157.208, and 157.210 of the Commission's regulations under the Natural Gas Act (NGA) for authorization to replace, construct and operate certain mainline pipeline and ancillary facilities primarily to serve a new ethanol plant in Adams County, Nebraska, all as more fully set forth in the application, which is on file with the Commission and open to public inspection. The filing may also be viewed on the Web at
KMIGT states that as a result of wrinkle bends, which have caused the pipeline to become physically deteriorated, approximately 11.4 miles of its 16-inch Franklin to Hastings Pipeline needs to be replaced. KMIGT asserts that, in response to the developing market for natural gas and to develop firm transportation to serve ethanol production facilities in the Midwest, KMIGT held an open season from July 2, 2010 through July 9, 2010 seeking support to expand its firm transportation capacity. As a result of the open season, KMIGT states that it has entered into a binding precedent agreement with Aventine Renewable Energy—Aurora West, LLC to provide up to 10,000 dekatherms per day of natural gas to serve its new ethanol plant located near Aurora, Nebraska. Accordingly, KMIGT proposes to replace 11.4 miles of the Franklin to Hastings Pipeline with 20-inch pipe to serve the increase in firm load. In addition, KMIGT proposes to construct and operate certain ancillary facilities. KMIGT estimates cost of constructing the proposed facilities is $23,511,100.
Any questions regarding the application should be directed to Robert F. Harrington, Vice President, Regulatory, Kinder Morgan Interstate Gas Transmission LLC, 370 Van Gordon Street, Lakewood, Colorado 80228-8304, by telephone (303) 763-3258, or by facsimile at (303) 984-3272, or by e-mail at
Any person may, within 60 days after the issuance of the instant notice by the Commission, file pursuant to Rule 214 of the Commission's Procedural Rules (18 CFR 385.214) a motion to intervene or notice of intervention. Any person filing to intervene or the Commission's staff may, pursuant to section 157.205 of the Commission's regulations under the NGA (18 CFR 157.205) file a protest to the request. If no protest is filed within the time allowed therefore, the proposed activity shall be deemed to be authorized effective the day after the time allowed for protest. If a protest is filed and not withdrawn within 30 days after the time allowed for filing a protest, the instant request shall be treated as an application for authorization pursuant to section 7 of the NGA.
The Commission strongly encourages electronic filings of comments, protests, and interventions via the internet in lieu of paper.
On June 25, 2010, the Commission issued an order announcing its intent to revoke the market-based rate authority of the above captioned public utilities, which had failed to file their required Electric Quarterly Reports.
In Order No. 2001, the Commission revised its public utility filing requirements and established a requirement for public utilities, including power marketers, to file Electric Quarterly Reports summarizing the contractual terms and conditions in their agreements for all jurisdictional services (including market-based power sales, cost-based power sales, and transmission service) and providing transaction information (including rates) for short-term and long-term power sales during the most recent calendar quarter.
In the June 25 Order, the Commission directed Strategic Energy Management Corp. and Solaro Energy Marketing Corporation to file the required Electric Quarterly Reports within 15 days of the date of issuance of the order or face revocation of their authority to sell power at market-based rates and termination of their electric market-based rate tariffs.
The time period for compliance with the June 25 Order has elapsed. The two companies identified in the June 25 Order (Strategic Energy Management Corp. and Solaro Energy Marketing Corporation) have failed to file their delinquent Electric Quarterly Reports.
The Commission hereby revokes the market-based rate authority and terminates the electric market-based rate tariffs of the above-captioned public utilities.
Environmental Protection Agency (EPA).
Call for Information; correction.
The Environmental Protection Agency published in the
Jennifer Jenkins, Climate Change Division, Office of Atmospheric Programs (MC-6207J), Environmental Protection Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460;
EPA published a Call for Information in the
•
In addition, the first full sentence of the third bulleted item in Section I.D (first column, page 41176) contained a typographical error. The correct text for that sentence is: “The Clean Air Act (CAA) provisions typically apply at the unit, process, or facility scale, whereas the IPCC Guidance on accounting for GHG emissions from bioenergy sources was written to be applicable at the national scale.”
Environmental Protection Agency (EPA).
Notice of peer review workshop.
EPA is announcing that Versar, Inc., an EPA contractor for external scientific peer review, will convene an independent panel of experts and organize and conduct an external peer review workshop to review the draft human health assessment titled, “Toxicological Review of Hexachloroethane: In Support of Summary Information on the Integrated Risk Information System (IRIS)” (EPA/635/R-09/007). The draft assessment was prepared by the National Center for Environmental Assessment (NCEA) within the EPA Office of Research and Development.
EPA is releasing this draft assessment solely for the purpose of pre-dissemination peer review under applicable information quality guidelines. This draft assessment has not been formally disseminated by EPA. It does not represent and should not be construed to represent any Agency policy or determination.
Versar, Inc., invites the public to register to attend this workshop as observers. In addition, Versar, Inc., invites the public to give brief oral comments and/or provide written comments at the workshop regarding the draft assessment under review. Space is limited, and reservations will be accepted on a first-come, first-served basis. In preparing a final report, EPA will consider Versar, Inc.'s report of the comments and recommendations from the external peer review workshop and any written public comments that EPA receives in accordance with this notice.
The peer review panel workshop on the draft assessment for hexachloroethane will be held on September 21, 2010, beginning at 9 a.m. and ending at 4 p.m., Eastern Daylight Time. Registration will begin at 8:30 a.m.
The draft “Toxicological Review of Hexachloroethane: In Support of Summary Information on the Integrated Risk Information System (IRIS)” is available primarily via the Internet on the NCEA home page under the Recent Additions and Publications menus at
The peer review workshop on the draft hexachloroethane assessment will be held at the Radisson Hotel Reagan National Airport, 2020 Jefferson Davis Highway, Arlington, VA 22202. To attend the workshop, register no later than September 15, 2010, via e-mail at
For information on the draft assessment, please contact, John Cowden, National Center for Environmental Assessment (B243-01), U.S. Environmental Protection Agency, 109 T.W. Alexander Drive, Research Triangle Park, NC 27709;
EPA's IRIS is a human health assessment program that evaluates quantitative and qualitative risk information on effects that may result from exposure to chemical substances found in the environment. Through the IRIS program, EPA provides the highest quality science-based human health assessments to support the Agency's regulatory activities. The IRIS database contains information for more than 540 chemical substances that can be used to support the first two steps (hazard identification and dose-response evaluation) of the risk assessment process. When supported by available data, IRIS provides oral reference doses (RfDs) and inhalation reference concentrations (RfCs) for chronic noncancer health effects and cancer assessments. Combined with specific exposure information, government and private entities use IRIS to help characterize public health risks of chemical substances in a site-specific situation and thereby support risk management decisions designed to protect public health.
The Federal Communications Commission, as part of its continuing effort to reduce paperwork burden invites the general public and other Federal agencies to take this opportunity to comment on the following information collection(s), as required by the Paperwork Reduction Act (PRA) of 1995, 44 U.S.C. 3501 - 3520. Comments are requested concerning: (a) 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; (b) the accuracy of the Commission's burden estimate; (c) ways to enhance the quality, utility, and clarity of the information collected; (d) 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 (e) ways to further reduce the information collection 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 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 currently valid OMB control number.
Written Paperwork Reduction Act (PRA) comments should be submitted on or before September 1, 2010. 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.
Direct all PRA comments to Nicholas A. Fraser, Office of Management and Budget, via fax at 202-395-5167 or via the Internet at Nicholas_A._Fraser@omb.eop.gov and to the Federal Communications Commission via email to PRA@fcc.gov. To view a copy of this information collection request (ICR) submitted to OMB: (1) Go to the web page http://reginfo.gov/public/do/PRAMain, (2) look for the section of the web page called “Currently Under Review”, (3) click on the downward-pointing arrow in the “Select Agency” box below the “Currently Under Review” heading, (4) select “Federal Communications Commission” from the list of agencies presented in the “Select Agency” box, (5) click the “Submit” button to the right of the “Select Agency” box, and (6) when the list of FCC ICRs currently under review appears, look for the title of this ICR (or its OMB Control Number, if there is one) and then click on the ICR Reference Number to view detailed information about this ICR.
Judith B. Herman, Office of Managing Director, (202) 418-0214. For additional information or copies of the information collection(s), contact Judith B. Herman, OMD, 202-418-0214 or email judith-b.herman@fcc.gov.
OMB Control Number: 3060-0806.
Title: Universal Service - Schools and Libraries Universal Service Program.
Form Numbers: FCC Forms 470 and 471.
Type of Review: Revision of a currently approved collection.
Respondents: Business or other for-profit, not-for-profit institutions, and state, local or tribal government.
Number of Respondents and Responses: 45,000 respondents; 160,000 responses.
Estimated Time per Response: 3 - 4 hours.
Frequency of Response: On occasion and annual reporting requirements, recordkeeping requirement and third party disclosure requirement.
Obligation to Respond: Required to obtain or retain benefits. Statutory authority for this information collection is contained in 47 U.S.C. sections 254 and Pub. L. No. 107-110, Leave No Child Behind Act of 2002.
Total Annual Burden: 325,000 hours.
Total Annual Cost: N/A.
Privacy Act Impact Assessment: N/A.
Nature and Extent of Confidentiality: There is no need for confidentiality.
Needs and Uses: The Commission will submit this revised information collection to the Office of Management and Budget (OMB) during this comment period to obtain the full three year clearance from them. The Commission has reduced the annual burden hours by 200,003 hours (78,573 hours program change reduction and 121,430 hours adjusted due to recalculations of the burden estimates) since this was last submitted to OMB.
The Commission is revising this collection in an effort to streamline the application process for the federal universal service schools and libraries support mechanism (also referred to as the “E-rate” program) and to remove outdated and unneeded questions. We propose revising the forms by removing questions that were originally intended to assist service providers but are no longer useful; and by removing questions that are outside the scope of the information needed for the Universal Service Administrative Company (USAC), the administrator of the federal universal service fund and to process E-rate applications. We further proposed limiting data collection to information that is not already available through other USAC forms or review processes. Finally, applicants will be required to include their FCC Registration Number (FRN) and consultants must provide their contact information, when applicable, on FCC Forms 470 and 471.
Federal Deposit Insurance Corporation (FDIC).
Notice.
The FDIC has determined that insufficient assets exist in the receivership of Downey Savings and Loan Association, F.A., Newport Beach, California, to make any distribution to general unsecured claims, and therefore such claims will recover nothing and have no value.
The FDIC made its determination on July 26, 2010.
If you have questions regarding this notice, you may contact an FDIC Claims Agent at (972) 761-8677. Written correspondence may also be mailed to FDIC as Receiver of Downey Savings and Loan Association, F.A., Attention: Claims Agent, 1601 Bryan Street, Dallas, Texas 75201.
On November 21, 2008, Downey Savings and Loan Association, F.A., Newport Beach, California (FIN #10023), was closed by the Office of Thrift Supervision and the Federal Deposit Insurance Corporation (“FDIC”) was appointed as its Receiver. In complying with its statutory duty to resolve the institution in the method that is least costly to the deposit insurance fund, see 12 U.S.C. 1823(c)(4), the FDIC facilitated a transaction with U.S. Bank, National Association, Minneapolis, Minnesota, to acquire the deposits and most of the assets of the failed institution. Section 11(d)(11)(A) of the Federal Deposit Insurance Act, 12 U.S.C. 1821(d)(11)(A), sets forth the order of priority for distribution of amounts realized from the liquidation or other resolution of an insured depository institution to pay claims. Under the statutory order of priority, administrative expenses and deposit liabilities must be paid in full before any distribution may be made to general unsecured creditors or any lower priority claims. The FDIC has determined that the assets of Downey Savings and Loan, F.A. are insufficient to make any distribution on general unsecured claims and therefore such claims, asserted or unasserted, will recover nothing and have no value.
Federal Deposit Insurance Corporation (FDIC).
Notice.
The FDIC has determined that insufficient assets exist in the receivership of PFF Bank & Trust, Pomona, California, to make any distribution to general unsecured claims, and therefore such claims will recover nothing and have no value.
The FDIC made its determination on July 26, 2010.
If you have questions regarding this notice, you may contact an FDIC Claims Agent at (972) 761-8677. Written correspondence may also be mailed to FDIC as Receiver of PFF Bank & Trust, Attention: Claims Agent, 1601 Bryan Street, Dallas, Texas 75201.
On November 21, 2008, PFF Bank & Trust, Pomona, California, (FIN # 10024) was closed by the Office of Thrift Supervision and the Federal Deposit Insurance Corporation (“FDIC”) was appointed as its Receiver. In complying with its statutory duty to resolve the institution in the method that is least costly to the deposit insurance fund,
Federal Trade Commission.
Proposed Consent Agreement.
The consent agreement in this matter settles alleged violations of
Comments must be received on or before August 27, 2010.
Interested parties are invited to submit written comments electronically or in paper form. Comments should refer to “Rite Aid, File No. 072 3121” to facilitate the organization of comments. Please note that your comment — including your name and your state — will be placed on the public record of this proceeding, including on the publicly accessible FTC website, at (
Because comments will be made public, they should not include any sensitive personal information, such as an individual’s Social Security Number; date of birth; driver’s license number or other state identification number, or foreign country equivalent; passport number; financial account number; or credit or debit card number. Comments also should not include any sensitive health information, such as medical records or other individually identifiable health information. In addition, comments should not include any “[t]rade secret or any commercial or financial information which is obtained from any person and which is privileged or confidential. . . .,” as provided in Section 6(f) of the FTC Act, 15 U.S.C. 46(f), and Commission Rule 4.10(a)(2), 16 CFR 4.10(a)(2). Comments containing material for which confidential treatment is requested must be filed in paper form, must be clearly labeled “Confidential,” and must comply with FTC Rule 4.9(c), 16 CFR 4.9(c).
Because paper mail addressed to the FTC is subject to delay due to heightened security screening, please consider submitting your comments in electronic form. Comments filed in electronic form should be submitted by using the following weblink: (
A comment filed in paper form should include the “Rite Aid, File No. 072 3121” reference both in the text and on the envelope, and should be mailed or delivered to the following address: Federal Trade Commission, Office of the Secretary, Room H-135 (Annex D), 600 Pennsylvania Avenue, NW, Washington, DC 20580. The FTC is requesting that any comment filed in paper form be sent by courier or overnight service, if possible, because U.S. postal mail in the Washington area and at the Commission is subject to delay due to heightened security precautions.
The Federal Trade Commission Act (“FTC Act”) and other laws the Commission administers permit the collection of public comments to consider and use in this proceeding as appropriate. The Commission will consider all timely and responsive public comments that it receives, whether filed in paper or electronic form. Comments received will be available to the public on the FTC website, to the extent practicable, at (
Loretta Garrison (202-326-3043) or Alain Sheer (202-326-3321), Bureau of Consumer Protection, 600 Pennsylvania Avenue, NW, Washington, D.C. 20580.
Pursuant to section 6(f) of the Federal Trade Commission Act, 38 Stat. 721, 15 U.S.C. 46(f), and § 2.34 the Commission Rules of Practice, 16 CFR 2.34, notice is hereby given that the above-captioned consent agreement containing a consent order to cease and desist, having been filed with and accepted, subject to final approval, by the Commission, has been placed on the public record for a period of thirty (30) days. The following Analysis to Aid Public Comment describes the terms of the consent agreement, and the allegations in the complaint. An electronic copy of the full text of the consent agreement package can be obtained from the FTC Home Page (for July 27, 2010), on the World Wide Web, at (
Public comments are invited, and may be filed with the Commission in either paper or electronic form. All comments should be filed as prescribed in the
The Federal Trade Commission has accepted, subject to final approval, a consent agreement from Rite Aid Corporation (“Rite Aid”).
The proposed consent order has been placed on the public record for thirty (30) days for receipt of comments by interested persons. Comments received during this period will become part of the public record. After thirty (30) days, the Commission will again review the agreement and the comments received, and will decide whether it should withdraw from the agreement and take appropriate action or make final the agreement’s proposed order.
The Commission’s proposed complaint alleges that Rite Aid is in the business of selling prescription and non-prescription medicines and supplies, as well as other products. It operates, among other things, approximately 4,900 retail pharmacy stores in the United States (collectively, “Rite Aid pharmacies”) and an online pharmacy business. The company allows consumers buying products in Rite Aid pharmacies to pay for their purchases with credit, debit and electronic benefit transfer cards; insurance cards; personal checks; or cash.
The complaint alleges that in conducting its business, Rite Aid routinely obtains information from or about its customers, including, but not limited to, name; telephone number; address; date of birth; bank account number; payment card account number and expiration date; prescription information, such as medication and dosage, prescribing physician name, address, and telephone number, health insurer name, and insurance account
The complaint further alleges that Rite Aid engaged in a number of practices that, taken together, failed to provide reasonable and appropriate security for sensitive information from consumers, employees, and job applicants. In particular, Rite Aid failed to: (1) implement policies and procedures to dispose securely of such information, including, but not limited to, policies and procedures to render the information unreadable in the course of disposal; (2) adequately train employees to dispose securely of such information; (3) use reasonable measures to assess compliance with its established policies and procedures for the disposal of such information; or (4) employ a reasonable process for discovering and remedying risks to such information.
The complaint alleges that as a result of these failures, Rite Aid pharmacies discarded materials containing sensitive information in clear readable text (such as pharmacy labels and job applications) in unsecured, publicly-accessible trash dumpsters on numerous occasions. For example, in July 2006 and continuing into 2007 and 2008, television stations and other media outlets reported finding such information in unsecured dumpsters used by Rite Aid pharmacies in at least 7 cities throughout the United States. When discarded in publicly-accessible dumpsters, such information can be obtained by individuals for purposes of identity theft or the theft of prescription medicines.
The proposed order applies to sensitive information about consumers, employees, and job applicants obtained by Rite Aid. It contains provisions designed to prevent Rite Aid from engaging in the future in practices similar to those alleged in the complaint.
Part I of the proposed order prohibits misrepresentations about the security, confidentiality, and integrity of sensitive information. Part II of the order requires Rite Aid to establish and maintain a comprehensive information security program that is reasonably designed to protect the security, confidentiality, and integrity of such information (whether in paper or electronic format) about consumers, employees, and those seeking to become employees. The order covers health and other sensitive information obtained by all Rite Aid entities, including, but not limited to, retail pharmacies. The security program must contain administrative, technical, and physical safeguards appropriate to Rite Aid’s size and complexity, the nature and scope of its activities, and the sensitivity of the information collected from or about consumers and employees. Specifically, the order requires Rite Aid to:
• Designate an employee or employees to coordinate and be accountable for the information security program.
• Identify material internal and external risks to the security, confidentiality, and integrity of sensitive information that could result in the unauthorized disclosure, misuse, loss, alteration, destruction, or other compromise of such information, and assess the sufficiency of any safeguards in place to control these risks.
• Design and implement reasonable safeguards to control the risks identified through risk assessment, and regularly test or monitor the effectiveness of the safeguards’ key controls, systems, and procedures.
• Develop and use reasonable steps to select and retain service providers capable of appropriately safeguarding sensitive information they receive from Rite Aid, and require service providers by contract to implement and maintain appropriate safeguards.
• Evaluate and adjust its information security programs in light of the results of testing and monitoring, any material changes to operations or business arrangements, or any other circumstances that it knows or has reason to know may have a material impact on its information security program.
Part III of the proposed order requires Rite Aid to obtain within one year, and on a biennial basis thereafter for a period of twenty (20) years, an assessment and report from a qualified, objective, independent third-party professional, certifying, among other things, that: (1) it has in place a security program that provides protections that meet or exceed the protections required by Part II of the proposed order; and (2) its security program is operating with sufficient effectiveness to provide reasonable assurance that the security, confidentiality, and integrity of sensitive consumer, employee, and job applicant information has been protected.
Parts IV through VIII of the proposed order are reporting and compliance provisions. Part IV requires Rite Aid to retain documents relating to its compliance with the order. For most records, the order requires that the documents be retained for a five-year period. For the third-party assessments and supporting documents, Rite Aid must retain the documents for a period of three years after the date that each assessment is prepared. Part V requires dissemination of the order now and in the future to persons with responsibilities relating to the subject matter of the order. Part VI ensures notification to the FTC of changes in corporate status. Part VII mandates that Rite Aid submit a compliance report to the FTC within 60 days, and periodically thereafter as requested. Part VIII is a provision “sunsetting” the order after twenty (20) years, with certain exceptions.
The Commission conducted its investigation jointly with the Office for Civil Rights in the Department of Health and Human Services (“OCR-HHS”). Working together, the Commission and OCR-HHS each entered into separate but coordinated agreements with Rite Aid to resolve all the issues of both agencies.
This is the Commission’s twenty-ninth case to challenge the failure by a company to implement reasonable information security practices, and the second case: (1) involving a health provider, (2) proceeding jointly with OCR-HHS, and (3) challenging the security of employee data.
The purpose of this analysis is to facilitate public comment on the proposed order. It is not intended to constitute an official interpretation of the proposed order or to modify its terms in any way.
By direction of the Commission.
Office of the Secretary, HHS.
In compliance with the requirement of section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995, the Office of the Secretary (OS), Department of Health and Human Services, is publishing the following summary of a proposed collection for public comment. Interested persons are invited to send comments regarding this burden estimate or any other aspect of this collection of information, including any of the following subjects: (1) The necessity and utility of the proposed
To obtain copies of the supporting statement and any related forms for the proposed paperwork collections referenced above, e-mail your request, including your address, phone number, OMB number, and OS document identifier, to
Office of the Secretary, HHS.
In compliance with the requirement of section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995, the Office of the Secretary (OS), Department of Health and Human Services, is publishing the following summary of a proposed collection for public comment. Interested persons are invited to send comments regarding this burden estimate or any other aspect of this collection of information, including any of the following subjects: (1) The necessity and utility of the proposed information collection for the proper performance of the agency's functions; (2) the accuracy of the estimated burden; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) the use of automated collection techniques or other forms of information technology to minimize the information collection burden.
To obtain copies of the supporting statement and any related forms for the proposed paperwork collections referenced above, e-mail your request, including your address, phone number, OMB number, and OS document identifier, to
Office of the Secretary, HHS.
In compliance with the requirement of section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995, the Office of the Secretary (OS), Department of Health and Human Services, is publishing the following summary of a proposed collection for public comment. Interested persons are invited to send comments regarding this burden estimate or any other aspect of this collection of information, including any of the following subjects: (1) The necessity and utility of the proposed information collection for the proper performance of the agency's functions; (2) the accuracy of the estimated burden; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) the use of automated collection techniques or other forms of information technology to minimize the information collection burden.
To obtain copies of the supporting statement and any related forms for the proposed paperwork collections referenced above, e-mail your request, including your address, phone number, OMB number, and OS document identifier, to
Office of the Secretary, HHS.
In compliance with the requirement of section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995, the Office of the Secretary (OS), Department of Health and Human Services, is publishing the following summary of a proposed collection for public comment. Interested persons are invited to send comments regarding this burden estimate or any other aspect of this collection of information, including any of the following subjects: (1) The necessity and utility of the proposed information collection for the proper performance of the agency's functions; (2) the accuracy of the estimated burden; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) the use of automated collection techniques or
To obtain copies of the supporting statement and any related forms for the proposed paperwork collection referenced above, e-mail your request, including your address, phone number, OMB number, and OS document identifier, to
The objective of the NBCUS is to produce reliable and accurate estimates of national and regional collections, utilization, and safety of all blood products—red blood cells, fresh frozen plasma, and platelets, as well as related cellular therapy products. This survey will significantly improve the Federal Government's capacity to understand the dynamics of blood supply, safety and availability, and to provide a quantitative basis for assessing strategic and regulatory agendas. An important purpose of the 2011 survey is to help the Federal Government continue to monitor trends in blood availability since a variety of factors have come to play that have reduced the number of people eligible to give blood and, as stated in the evolving National Strategic Plan for Blood, this information is critical to ensure an adequate supply of safe blood in the United States.
Office of the Secretary, HHS.
In compliance with the requirement of section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995, the Office of the Secretary (OS), Department of Health and Human Services, is publishing the following summary of a proposed collection for public comment. Interested persons are invited to send comments regarding this burden estimate or any other aspect of this collection of information, including any of the following subjects: (1) The necessity and utility of the proposed information collection for the proper performance of the agency's functions; (2) the accuracy of the estimated burden; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) the use of automated collection techniques or other forms of information technology to minimize the information collection burden.
To obtain copies of the supporting statement and any related forms for the proposed paperwork collections referenced above, e-mail your request, including your address, phone number, OMB number, and OS document identifier, to
Office of the Secretary, HHS.
In compliance with the requirement of section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995, the Office of the Secretary (OS), Department of Health and Human Services, is publishing the following summary of a proposed collection for public comment. Interested persons are invited to send comments regarding this burden estimate or any other aspect of this collection of information, including any of the following subjects: (1) The necessity and utility of the proposed information collection for the proper performance of the agency's functions; (2) the accuracy of the estimated burden; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) the use of automated collection techniques or other forms of information technology to minimize the information collection burden.
To obtain copies of the supporting statement and any related forms for the proposed paperwork collections referenced above, e-mail your request, including your address, phone number, OMB number, and OS document identifier, to
Office of the Secretary, HHS.
In compliance with the requirement of section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995, the Office of the Secretary (OS), Department of Health and Human Services, is publishing the following summary of a proposed collection for public comment. Interested persons are invited to send comments regarding this burden estimate or any other aspect of this collection of information, including any of the following subjects: (1) The necessity and utility of the proposed information collection for the proper performance of the agency's functions; (2) the accuracy of the estimated burden; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) the use of automated collection techniques or other forms of information technology to minimize the information collection burden.
To obtain copies of the supporting statement and any related forms for the proposed paperwork collections referenced above, e-mail your request, including your address, phone number, OMB number, and OS document identifier, to
The SF-424D is used to provide information on required assurances when applying for construction projects under Federal grants. The Federal awarding agencies use information reported on the form for the evaluation of award and general management of Federal assistance program awards. The only information collected on the form is the applicant signature, title and date submitted.
Office of the Secretary, HHS.
In compliance with the requirement of section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995, the Office of the Secretary (OS), Department of Health and Human Services, is publishing the following summary of a proposed collection for public comment. Interested persons are invited to send comments regarding this burden estimate or any other aspect of this collection of information, including any of the following subjects: (1) The necessity and utility of the proposed information collection for the proper performance of the agency's functions; (2) the accuracy of the estimated burden; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) the use of automated collection techniques or other forms of information technology to minimize the information collection burden.
To obtain copies of the supporting statement and any related forms for the proposed paperwork collections referenced above, e-mail your request, including your address, phone number, OMB number, and OS document identifier, to
In compliance with the requirement of Section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995 for opportunity for public comment on proposed data collection projects, the Centers for Disease Control and Prevention (CDC) will publish periodic summaries of proposed projects. To request more information on the proposed projects or to obtain a copy of the data collection plans and instruments, call 404-639-5960 and send comments to Maryam I. Daneshvar, CDC Reports Clearance Officer, 1600 Clifton Road, MS-D74, Atlanta, GA 30333 or send an e-mail to
Resources and Services Database of the CDC National Prevention Information Network (OMB No. 0920-0255 exp. 5/31/2010)—Reinstatement with change—National Center for HIV/AIDS, Viral Hepatitis, STD, and TB Prevention (NCHHSTP), Centers for Disease Control and Prevention (CDC).
This request is for 3 years. NCHHSTP has the primary responsibility within the CDC and the U.S. Public Health Service for the prevention and control of HIV infection, viral hepatitis, sexually transmitted diseases (STDs), and tuberculosis (TB), as well as for community-based HIV prevention activities, syphilis, and TB elimination programs. NPIN serves as the U.S. reference, referral, and distribution service for information on HIV/AIDS, viral hepatitis, STDs, and TB, supporting NCHHSTP's mission to link Americans to prevention, education, and care services. NPIN is a critical member of the network of government agencies, community organizations, businesses, health professionals, educators, and human services providers that educate the American public about the grave threat to public health posed by HIV/AIDS, viral hepatitis, STDs, and TB, and provides services for persons infected with human immunodeficiency virus (HIV).
The NPIN Resources and Services Database contains entries on approximately 10,000 organizations and is the most comprehensive listing of HIV/AIDS, viral hepatitis, STD, and TB resources and services available throughout the country. The American public can also access the NPIN Resources and Services database through the NPIN Web site. More than 29 million hits by the public to the Web site are recorded annually.
To accomplish CDC's goal of continuing efforts to maintain an up-to-date, comprehensive database, NPIN plans each year to add up to 200 newly identified organizations and to verify those organizations currently described in the NPIN Resources and Services Database each year. Organizations with access to the Internet will be given the option to complete and submit an electronic version of the questionnaire by visiting the NPIN Web site. There is no cost to the respondents other than their time.
Periodically, the Substance Abuse and Mental Health Services Administration (SAMHSA) will publish a summary of information collection requests under OMB review, in compliance with the Paperwork Reduction Act (44 U.S.C. chapter 35). To request a copy of these documents, call the SAMHSA Reports Clearance Officer on (240) 276-1243.
Statute (42 U.S.C. 290dd-2) and regulations (42 CFR part 2) require federally conducted, regulated, or directly or indirectly assisted alcohol and drug abuse programs to keep alcohol and drug abuse patient records confidential. Information requirements are (1) written disclosure to patients about Federal laws and regulations that protect the confidentiality of each patient, and (2) documenting “medical personnel” status of recipients of a disclosure to meet a medical emergency. Annual burden estimates for these requirements are summarized in the table below:
Written comments and recommendations concerning the proposed information collection should be sent by September 1, 2010 to: SAMHSA Desk Officer, Human Resources and Housing Branch, Office of Management and Budget, New Executive Office Building, Room 10235, Washington, DC 20503; due to potential delays in OMB's receipt and processing of mail sent through the U.S. Postal Service, respondents are encouraged to submit comments by fax to: 202-395-5806.
In compliance with Section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995 concerning
SAMHSA's Center for Substance Abuse Treatment (CSAT) is conducting a cross-site external evaluation of the impact of the Grants for the Benefit of Homeless Individuals (GBHI) program. GBHI is a Targeted Capacity Expansion grant program that links substance abuse and mental health treatment with housing and other needed services and expands and strengthens these services for people with substance use and co-occurring mental health problems who are homeless. The national cross-site evaluation will assess the effectiveness, efficiency and sustainability of the GBHI project services for client abstinence, housing stability, homelessness, and related employment, criminal justice and services outcomes, as well as lessons learned to inform future efforts.
The CSAT GBHI Client Interview—Baseline and the CSAT GBHI Client Interview—6-Month Follow-up have been developed to assess program impact on client outcomes based on review of the literature and consultation with a panel of national experts, GBHI grantees and SAMHSA. The CSAT GBHI Client Interview is composed of questions unique from the Government Performance and Results Act (GPRA) Tool that measure the outcomes of interest and subpopulations of focus: homelessness, housing, treatment history, readiness to change, trauma symptoms, housing and treatment choice, burden and satisfaction, military service, employment, and criminal justice involvement. Immediately following the SAMHSA-required administration of the GPRA CSAT Discretionary Services Client Level Tool, which is completed by enrolled accepted clients for each grantee project at baseline and 6-month follow-up, the paper and pencil CSAT GBHI Client Interview will be administered face-to-face by the GPRA interviewer. Questions regarding perception of care and treatment coercion will be self-administered by participating clients and returned to the interviewer in a sealed envelope to be included in the full package mailed to the cross-site evaluation coordinating center by the interviewer. Client participation is voluntary; non-cash incentives will be given at baseline worth a $10 value and at 6-month follow-up worth a $25 value. Clients will be assigned unique identifiers by local projects; responses will be recorded on a fill-in-the-bubble answer sheet, mailed by the grantee project to the cross-site evaluation coordinating center, and scanned into a secure dataset. This process will eliminate the need for data entry, reduce cost and data entry error, and ensure confidentiality for cross-site data.
The CSAT GBHI Stakeholder Survey will be conducted with GBHI program stakeholders via a web survey to assess the types of stakeholder partnerships involved in the GBHI program and the barriers and strategies developed to overcome barriers to facilitate the implementation and sustainability of project activities under the GBHI program. Each survey respondent will be issued a username and password to login to and complete the secure web-based survey. The web-based survey format will reduce burden on the respondent and minimize potential for measurement error.
Send comments to Summer King, SAMHSA Reports Clearance Officer, Room 7-1044, One Choke Cherry Road, Rockville, MD 20857
In compliance with Section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995 concerning opportunity for public comment on proposed collections of information, the Substance Abuse and Mental Health Services Administration will publish periodic summaries of proposed projects. To request more information on the proposed projects or to obtain a copy of the information collection plans, call the SAMHSA Reports Clearance Officer on (240) 276-1243.
The Substance Abuse and Mental Health Services Administration's (SAMHSA) Center for Substance Abuse Treatment (CSAT) has implemented the Assertive Adolescent and Family Treatment (AAFT) program to promote the adoption of evidence-based practices by community providers in the area of adolescent substance use treatment. The AAFT program provides evidence-based substance use services to adolescents and their families, as well as to transition-age youth (TAY), caregivers, and their families/mentors. This program is based on evidence that families/caregivers are an integral part of the treatment process and their inclusion in services increases the likelihood of successful treatment and reintegration of adolescents/TAYs into their communities following treatment. AAFT requires grantees to implement the Adolescent Community Reinforcement Approach (A-CRA) coupled with Assertive Continuing Care (ACC) to provide treatment that is context-specific, family-centered, and community-based. Grantees are also required to use the Global Appraisal of Individual Needs (GAIN) as the common assessment instrument across programs to improve intake assessment, clinical interpretation, monitoring, and data management. The GAIN is used for diagnosis and to assist in placement, treatment planning, local evaluation, and continuous quality improvement for programs. In supporting AAFT and to ensure that each implementation activity required by AAFT is implemented well and with fidelity, CSAT has provided, through Chestnut Health Systems, a package of implementation supports, including manual-assisted training in and certification for clinical staff on A-CRA and ACC, training/certification in GAIN, monitoring/coaching/mentoring/support for clinicians and supervisors, implementation calls and monthly progress reports, and topical workgroups that share ideas and resources among grantees. The overarching objective of the multi-site, Assertive Adolescent and Family Treatment (AAFT) process and outcome evaluation is to assess and document the process of implementation in the 2009 cohort of AAFT grantees and to explore the role that implementation supports play in how well these programs evolve.
CSAT is requesting approval from the Office of Management and Budget (OMB) to implement three versions of a data collection document, the AAFT Implementation Survey, to gather longitudinal data (end of each of 3 project years) from a range of grantee personnel to evaluate the implementation, expansion, and sustainability of adolescent substance use services developed under the AAFT program.
The current proposal requests implementing the AAFT Implementation Surveys to collect information in the following areas:
a. Attitudes toward evidence-based practices generally, and AAFT model components in particular (
b. Grantee involvement with the implementation supports provided by Chestnut Health Systems and their reactions to those implementation supports;
c. Perceived changes in clinical practice/behavior indicating movement toward full A-CRA/ACC implementation;
d. Perceived barriers encountered in implementation and compensatory strategies;
e. Report on project progress, including activities related to the AAFT program, changes to program plans, project accomplishments, and efforts to plan for sustainability of the program.
This information would be collected annually, at the end of each project year. The surveys three versions are tailored to address the respondents' roles in the grant (Principal Investigator/Program Director, Clinical Supervisor/Clinician, and Evaluator/Data Manager). Staffing patterns at each grantee site vary greatly; therefore, the estimate includes the total number of respondents for each category based on initial grantee proposals. The goal is to conduct surveys with approximately 21 administrators, 56 clinical staff, and 28 evaluators/data managers. The total number of respondents—105 individuals—represent project staff at three distinct levels across 14 grantee sites.
The burden estimate for completing the Annual Program Survey is as follows:
Send comments to Summer King, SAMHSA Reports Clearance Officer, OAS, Room 7-1044, 1 Choke Cherry Road, Rockville, MD 20857. Written comments should be received by October 1, 2010.
Periodically, the Substance Abuse and Mental Health Services Administration (SAMHSA) will publish a summary of information collection requests under OMB review, in compliance with the Paperwork Reduction Act (44 U.S.C. Chapter 35). To request a copy of these documents, call the SAMHSA Reports Clearance Officer on (240) 276-1243.
The Substance Abuse and Mental Health Services Administration's (SAMHSA) Center for Substance Abuse Prevention (CSAP), is proposing a revision to the information collection regarding the Assessment of the Town Hall Meetings (THMs) on Underage Drinking (UAD) Prevention. The current data collection has approval under OMB #0930-0288, which expires on January 31, 2011. Revisions were made to the Town Hall Meeting Feedback Form, now being referred to as the Organizers Survey; the data collection method; and the number of respondents. Additionally, CSAP is adding a new data collection component titled the Participants Survey, which is the data collection instrument for the participants (or attendees) of the THM events.
Under the current approval, SAMHSA/CSAP distributes a brief Town Hall Meeting Feedback Form to all CBOs participating in THM events. This paper-and-pencil based form includes 14 items about the THM event, among which—
• Where, when, and who conducted the meeting;
• Number of attendees;
• Format of the meeting;
• Participants in the presentations;
• Actions planned;
• Media coverage;
• Composition of the audience;
• Responses of the attendees;
• Materials provided;
• Indications of increased awareness; and
• Indications of increased involvement.
Under this revision, SAMHSA/CSAP will provide organizers of THM events with password-protected login information to access the Organizers Survey via the Internet. The Organizers Survey includes 36 items about the THM event. Listed below is a summary of the revisions that were made—
SAMHSA/CSAP will provide organizers of THM events with a unique URL to make available to participants of their THM event. This unique URL provides access to the Participants Survey.
The Participants Survey includes 17 items about the THM event, among which—
• When and where the THM event was held;
• Estimation of the number of attendees at the THM event;
• Perception of increased awareness;
• Indication of reach of the underage drinking prevention messages from the THM event;
• Perception of increased involvement;
• Indication of the most important underage drinking issues facing the community;
• Perception of how well the THM event addressed those issues;
• Appropriateness of the THM event in terms of length and duration;
• Overall assessment of the THM event; and
• Demographics of the participants.
The Organizers Survey will be completed by an estimated 3,400 THM event organizers and will require only one response per respondent. It will take an average of 30 minutes (0.500 hours) to review the instructions and complete the survey. This burden estimate is based on comments from several potential respondents who reviewed the survey and provided comments on how long it would take them to complete it.
The Participants Survey will be completed by an estimated nine participants per THM event and will require only one response per respondent. The estimated number of participant respondents is based on 21 percent of the average of the sum of adult (66,519) and youth (53,554) participants, as reported on the 2008 THM events feedback forms (1,492 forms reported adults as participants and 1,316 forms reported youth as participants) [(120,073/2,808 = 42.76) × 0.21 = 8.9798]. It will take an average of 10 minutes (0.167 hours) to review the instructions and complete the survey. This burden estimate is based on comments from several potential respondents who reviewed the survey and provided comments on how long it would take them to complete it.
SAMHSA/CSAP intends to support THM events every other year. The information collected will be used by SAMHSA/CSAP to help plan for these biennial events, to provide technical assistance and training to organizations that sponsor the events, and to comply with the reporting requirements of the Government Performance Results Act of 1993. The information collected will also provide a descriptive picture of the nationwide initiative, and it will indicate how the THM events were received by the community and factors that may be associated with well-received events.
Written comments and recommendations concerning the proposed information collection should be sent by September 1, 2010 to: SAMHSA Desk Officer, Human Resources and Housing Branch, Office of Management and Budget, New Executive Office Building, Room 10235, Washington, DC 20503; due to potential delays in OMB's receipt and processing of mail sent through the U.S. Postal Service, respondents are encouraged to submit comments by fax to: 202-395-5806.
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA) is announcing that a proposed collection of information has been submitted to the Office of Management and Budget (OMB) for review and clearance under the Paperwork Reduction Act of 1995.
Fax written comments on the collection of information by [
To ensure that comments on the information collection are received, OMB recommends that written comments be faxed to the Office of Information and Regulatory Affairs, OMB, Attn: FDA Desk Officer, FAX: 202-395-7285, or e-mailed to
Elizabeth Berbakos, Office of Information Management, Food and Drug Administration, 1350 Piccard Dr., PI50-400B, Rockville, MD 20850, 301-796-3792,
In compliance with 44 U.S.C. 3507, FDA has submitted the following proposed collection of information to OMB for review and clearance.
Under section 361 of the Public Health Service (PHS) Act (42 U.S.C. 264), FDA issued regulations under part 1270 (21 CFR part 1270) to prevent the transmission of human immunodeficiency virus (HIV), hepatitis B, and hepatitis C, through the use of human tissue for transplantation. The regulations provide for inspection by FDA of persons and tissue establishments engaged in the recovery, screening, testing, processing, storage, or distribution of human tissue. These facilities are required to meet provisions intended to ensure appropriate screening and testing of human tissue donors and to ensure that records are kept documenting that the appropriate screening and testing have been completed.
Section 1270.31(a) through (d) requires written procedures to be prepared and followed for the following steps: (1) All significant steps in the infectious disease testing process under § 1270.21; (2) all significant steps for obtaining, reviewing, and assessing the relevant medical records of the donor as prescribed in § 1270.21; (3) designating and identifying quarantined tissue; and (4) for prevention of infectious disease contamination or cross-contamination by tissue during processing. Section 1270.31(a) and (b) also requires recording and justification of any deviation from the written procedures. Section 1270.33(a) requires records to be maintained concurrently with the performance of each significant step in the performance of infectious disease screening and testing of human tissue donors. Section 1270.33(f) requires records to be retained regarding the determination of the suitability of the donors and such records required under § 1270.21. Section 1270.33(h) requires all records to be retained at least 10 years beyond the date of transplantation if known, distribution, disposition, or expiration of the tissue, whichever is the latest. Section 1270.35(a) through (d) requires specific records to be maintained to document the following: (1) The results and interpretation of all required infectious disease tests; (2) information on the identity and relevant medical records of the donor; (3) the receipt and/or distribution of human tissue, and (4) the destruction or other disposition of human tissue.
Respondents to this collection of information are manufacturers of human tissue intended for transplantation. Based on information from the Center for Biologics Evaluation and Research's (CBER's) database system, FDA estimates that there are approximately 257 tissue establishments of which 145 are conventional tissue banks and 112 are eye tissue banks. Based on information provided by industry, there are an estimated total of 1,959,270 conventional tissue products and 82,741 eye tissue products recovered per year with an average of 25% of the tissue discarded due to unsuitability for transplant. In addition, there are an estimated 57,275 donors of conventional tissue and 54,115 donors of eye tissue each year.
Accredited members of the American Association of Tissue Banks (AATB) and Eye Bank Association of America (EBAA) adhere to standards of those organizations that are comparable to the recordkeeping requirements in part 1270. Based on information provided by CBER's database system, 90% of the conventional tissue banks are members of AATB (145 x 90% = 130), and 77% of eye tissue banks are members of EBAA (112 x 77% = 86). Therefore, recordkeeping by these 216 establishments (130 + 86 = 216) is excluded from the burden estimates as usual and customary business activities (5 CFR 1320.3(b)(2)). The recordkeeping burden, thus, is estimated for the remaining 41 establishments, which is 16% of all establishments (257 - 216 = 41, or 41/257 = 16%).
Based on CBER's database system and information provided by industry, FDA estimates an average of two new tissue banks annually, which may be non-members of a trade association. Each new tissue bank requires an estimated 64 hours to prepare standard operating procedures (SOPs) under § 1270.31(a) through (d). The requirement for the development of these written procedures is considered an initial one-time burden. FDA assumes that all current tissue establishments have developed written procedures in compliance with part 1270. Therefore, their information collection burden is for the general review and update of written procedures estimated to take an annual average of 24 hours, and for the recording and justifying of any deviations from the written procedures for § 1270.31(a) and (b), estimated to take an annual average of 1 hour. The information collection burden for maintaining records concurrently with the performance of each significant screening and testing step and for retaining records for 10 years under § 1270.33(a), (f), and (h), include documenting the results and interpretation of all required infectious disease tests and results and the identity and relevant medical records of the donor required under § 1270.35(a) and (b). Therefore, the burden under these provisions is calculated together in table 1 of this document. The recordkeeping estimates for the number of total annual records and hours per record are based on information provided by industry and FDA experience.
In the
FDA estimates the burden of this information collection as follows:
Substance Abuse and Mental Health Services Administration, HHS.
Notice.
The Department of Health and Human Services (HHS) notifies Federal agencies of the laboratories currently certified to meet the standards of Subpart C of the Mandatory Guidelines for Federal Workplace Drug Testing Programs (Mandatory Guidelines). The Mandatory Guidelines were first published in the
A notice listing all currently certified laboratories is published in the
If any laboratory has withdrawn from the HHS National Laboratory Certification Program (NLCP) during the past month, it will be listed at the end, and will be omitted from the monthly listing thereafter.
This notice is also available on the Internet at
Mrs. Giselle Hersh, Division of Workplace Programs, SAMHSA/CSAP, Room 2-1042, One Choke Cherry Road, Rockville, Maryland 20857; 240-276-2600 (voice), 240-276-2610 (fax).
The Mandatory Guidelines were developed in accordance with Executive Order 12564 and section 503 of Public Law
Laboratories which claim to be in the applicant stage of certification are not to be considered as meeting the minimum requirements described in the HHS Mandatory Guidelines. A laboratory must have its letter of certification from HHS/SAMHSA (formerly: HHS/NIDA) which attests that it has met minimum standards.
In accordance with Subpart C of the Mandatory Guidelines dated April 13, 2004 (69 FR 19644), the following laboratories meet the minimum standards to conduct drug and specimen validity tests on urine specimens:
*The Standards Council of Canada (SCC) voted to end its Laboratory Accreditation Program for Substance
Upon finding a Canadian laboratory to be qualified, HHS will recommend that DOT certify the laboratory (
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA) is announcing the availability of a draft guidance for FDA staff entitled “Compliance Policy Guide Sec. 690.800
Although you can comment on any CPG at any time (see 21 CFR 10.115(g)(5)), to ensure that the agency considers your comment on the draft CPG before it begins work on the final version of the CPG, submit either electronic or written comments on the draft CPG by November 1, 2010.
Submit written requests for single copies of the CPG to the Division of Compliance Policy (HFC-230), Office of Enforcement, Food and Drug Administration, 5600 Fishers Lane, Rockville, MD 20857. Send two self-addressed adhesive labels to assist that office in processing your request. See the
Submit electronic comments on the draft CPG to
Kim Young, Center for Veterinary Medicine (HFV-230), Food and Drug Administration, 5100 Paint Branch Pkwy., College Park, MD 20740, 240-276-9200.
FDA is announcing the availability of a draft guidance for FDA staff entitled “Compliance Policy Guide Sec. 690.800
FDA is issuing the draft CPG as Level 1 draft guidance consistent with FDA's good guidance practices regulation (21 CFR 10.115). The draft CPG, when finalized, will represent the agency's current thinking on enforcement recommendations for certain circumstances where animal feed or feed ingredients are contaminated with
Interested persons may submit to the Division of Dockets Management (see
Persons with access to the Internet may obtain the draft CPG at either
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA) is announcing the availability of a guidance for industry and researchers entitled “The Radioactive Drug Research Committee: Human Research Without an Investigational New Drug Application.” This guidance provides information to those using radioactive drugs for certain research purposes to help determine whether research studies may be conducted under an FDA-approved radioactive drug research committee, or
Submit either electronic or written comments on agency guidances at any time.
Submit written requests for single copies of this guidance to the Division of Drug Information, Center for Drug Evaluation and Research, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 51, rm. 2201, Silver Spring, MD 20993-0002. Send one self-addressed adhesive label to assist that office in processing your requests. See the
Submit electronic comments on the guidance to
Orhan Suleiman, Center for Drug Evaluation and Research, Food and Drug Administration, 10901 New Hampshire Ave., Bldg. 22, rm. 2202, Silver Spring, MD 20993-0002, 301-796-1471.
FDA is announcing the availability of a guidance for industry and researchers entitled “The Radioactive Drug Research Committee: Human Research Without an Investigational New Drug Application.”
In a document published in the
Today, research studies with a radioactive drug or biological product may be conducted in a number of ways: (1) Under an IND (part 312), (2) exempt from IND requirements (§ 312.2), or (3) under certain conditions, with the supervision and approval of an FDA-approved Radioactive Drugs Research Committee (RDRC) (§ 361.1).
This guidance discusses the conditions under which research with a radioactive drug may be conducted under § 361.1. Appendices to the guidance answer frequently asked questions about those conditions and provide additional information on RDRCs. Appendix A of the guidance answers questions on basic science research with radioactive drugs. Appendix B addresses approval by the RDRC and the information that must be submitted by investigators to the RDRC. Appendix C discusses the limits on the pharmacological dose, and Appendix D discusses the limits on the radiation dose. Each of these appendices also includes a summary of the regulations. Appendix E provides information on the membership, functions, and reports of an RDRC. The final appendix, Appendix F, is an RDRC review criteria checklist, indicating the areas on which the RDRC will focus when considering a proposed research study.
In the
This guidance is being issued consistent with FDA's good guidance practices regulation (21 CFR 10.115). The guidance represents the agency's current thinking on determining whether human research with a radioactive drug can be conducted under a radioactive drug research committee. 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.
Interested persons may submit to the Division of Dockets Management (see
Persons with access to the Internet may obtain the document at either
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meetings.
The meetings will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
This notice is being published less than 15 days prior to the meeting due to the timing limitations imposed by the review and funding cycle.
Administration for Children and Families, Department of Health and Human Services.
Notice of Meeting.
The meeting will be held on Monday, August 23, 2010, from 9:30 a.m. to 3:30 p.m.
ADDRESSES: The meeting will be held at the Administration for Children and Families, 901 D Street SW., Washington, DC 20024. To attend either in person or via teleconference, please register by 5 p.m., Eastern Time, August 18, 2010. To register, please e-mail
AGENDA: The Commission will: (1) Review and vote on the Final Report to the President and Congress; (2) Host panel discussion on the progress of children's working group activities and collaborations between Federal Emergency Management Agency, Assistant Secretary for Preparedness and Response and the Administration for Children and Families.
Written comments may be submitted electronically to
The Commission will provide an opportunity for public comments during the public meeting on August 23, 2010. Those wishing to speak will be limited to three minutes each; speakers are encouraged to submit their remarks in writing in advance to ensure their comment is received in case there is inadequate time for all comments to be heard on August 23, 2010.
The National Commission on Children and Disasters is an independent Commission that shall conduct a comprehensive study to examine and assess the needs of children as they relate to preparation for, response to, and recovery from all hazards, building upon the evaluations of other entities and avoiding unnecessary duplication by reviewing the findings, conclusions, and recommendations of these entities. The Commission shall then submit a report to the President and the Congress on the Commission's independent and specific findings, conclusions, and recommendations to address the needs of children as they relate to preparation for, response to, and recovery from all hazards, including major disasters and emergencies.
Pursuant to Public Law 92-463, notice is hereby given that the Substance Abuse and Mental Health Services Administration (SAMHSA) National Advisory Council will meet on August 17-18 at the Omni Hotel at CNN Center, Atlanta, Georgia. The meeting is open to the public.
The SAMHSA National Advisory Council was established to advise the Secretary, Department of Health and Human Services (HHS), and the Administrator, SAMHSA, to reduce the impact of substance abuse and mental illnesses in American communities. The Agenda will include a report from the SAMHSA Administrator, updates on SAMHSA's strategic initiatives, and a panel discussion on health reform and the role of peers and families in behavioral health. In addition, Council members will participate in a listening session on September 18 at the Centers for Disease Control and Prevention's Fourth National Conference on Health Communication, Marketing, and Media.
Attendance by the public will be limited to space available. Public comments are welcome. The meeting can also be accessed via webstream. To obtain the call-in numbers and access codes, to submit written or brief oral comments, or to request special accommodations for persons with disabilities, please register on-line at
Substantive program information and a roster of Council members may be obtained either by accessing the SAMHSA Committee Web site,
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
This notice is being published less than 15 days prior to the meeting due to the timing limitations imposed by the review and funding cycle.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Part C (Centers for Disease Control and Prevention) of the Statement of Organization, Functions, and Delegations of Authority of the Department of Health and Human Services (45 FR 67772-76, dated October 14, 1980, and corrected at 45 FR 69296, October 20, 1980, as amended most recently at 75 FR 38819-38821, dated July 6, 2010) is amended to reorganize the Management Analysis and Services Office, Office of the Chief Operating Officer, Centers for Disease Control and Prevention.
Section C-B, Organization and Functions, is hereby amended as follows:
Delete in their entirety the titles and functional statements for the Management Analysis and Services Office (CAJG), insert the following:
Part C (Centers for Disease Control and Prevention) of the Statement of Organization, Functions, and Delegations of Authority of the Department of Health and Human Services (45 FR 67772-76, dated October 14, 1980, and corrected at 45 FR 69296, October 20, 1980, as amended most recently at 75 FR 38819-21, dated July 6, 2010) is amended to establish the substructure for the Office of Surveillance, Epidemiology and Laboratory Services, Centers for Disease Control and Prevention.
Section C-B, Organization and Functions, is hereby amended as follows: After the title of Office of Surveillance, Epidemiology and Laboratory Services (CP), insert the following:
Retitle the Office of Surveillance, Epidemiology, and Laboratory Services (CPG) and insert the following:
Delete in its entirety item (1) of the functional statement for the Personnel Suitability and Select Agent Compliance Branch (CAJJC), within the Office of Security and Emergency Preparedness (CAJJ), and renumber the remaining items accordingly. Delete in its entirety the title and functional statement for the Office of Public Health Genomics (CUC19), within the Office of the Director (CUC1), National Center for Chronic Disease Prevention and Health Promotion (CUC).
Delete in its entirety the title and functional statement for the Behavioral Surveillance Branch (CUCEB), within the Division of Adult and Community Health (CUCE), National Center for Chronic Disease Prevention and Health Promotion (CUC).
Delete in its entirety the titles and functional statements for the Office of Workforce and Career Development (CAL), within the Office of the Director (CA), Centers for Disease Control and Prevention (C).
Coast Guard, DHS.
Notice.
The Coast Guard announces that a Certificate of Alternative Compliance was issued for the offshore supply vessel DWIGHT S. RAMSAY as required by 33 U.S.C. 1605(c) and 33 CFR 81.18.
The Certificate of Alternate Compliance was issued on June 18, 2010.
The docket for this notice is available for inspection or copying at the Docket Management Facility (M-30), U.S. Department of Transportation, West Building Ground Floor, Room W12-140, 1200 New Jersey Avenue, SE., Washington, DC 20590, between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays. You may also find this docket on the Internet by going to
If you have questions on this notice, call
A Certificate of Alternative Compliance, as allowed for under Title 33, Code of Federal Regulation, Parts 81 and 89, has been issued for the offshore supply vessel DWIGHT S. RAMSAY, O.N. 1225118. The horizontal distance between the forward and aft masthead lights may be 20'-5”. Placing the aft masthead light at the horizontal distance from the forward masthead light as required by Annex I, paragraph 3(a) of the 72 COLREGS, and Annex I, Section 84.05(a) of the Inland Rules Act, would result in an aft masthead light location directly over the cargo deck where it would interfere with loading and unloading operations.
The Certificate of Alternative Compliance allows for the horizontal separation of the forward and aft masthead lights to deviate from the requirements of Annex I, paragraph 3(a) of 72 COLREGS, and Annex I, Section 84.05(a) of the Inland Rules Act.
This notice is issued under authority of 33 U.S.C. 1605(c), and 33 CFR 81.18.
Coast Guard, DHS.
Notice.
The Coast Guard announces that a Certificate of Alternative Compliance was issued for the offshore supply vessel BETTY PFANKUCH as required by 33 U.S.C. 1605(c) and 33 CFR 81.18.
The Certificate of Alternate Compliance was issued on June 18, 2010.
The docket for this notice is available for inspection or copying at the Docket Management Facility (M-30), U.S. Department of Transportation, West Building Ground Floor, Room W12-140, 1200 New Jersey Avenue, SE., Washington, DC 20590, between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays. You may also find this docket on the Internet by going to
If you have questions on this notice, call LTJG Christine Dimitroff, District Eight, Prevention Branch, U.S. Coast Guard, telephone 504-671-2176. If you have questions on viewing or submitting material to the docket, call Renee V. Wright, Program Manager, Docket Operations, telephone 202-366-9826.
A Certificate of Alternative Compliance, as allowed for under Title 33, Code of Federal Regulation, Parts 81 and 89, has been issued for the offshore supply vessel BETTY PFANKUCH, O.N. 1225768. The horizontal distance between the forward and aft masthead lights may be 20′-5″. Placing the aft masthead light at the horizontal distance from the forward masthead light as required by Annex I, paragraph 3(a) of the 72 COLREGS, and Annex I, Section 84.05(a) of the Inland Rules Act, would result in an aft masthead light location directly over the cargo deck where it would interfere with loading and unloading operations.
The Certificate of Alternative Compliance allows for the horizontal separation of the forward and aft masthead lights to deviate from the requirements of Annex I, paragraph 3(a) of 72 COLREGS, and Annex I, Section 84.05(a) of the Inland Rules Act.
This notice is issued under authority of 33 U.S.C. 1605(c), and 33 CFR 81.18.
Federal Emergency Management Agency, DHS.
Notice.
This notice amends the notice of a major disaster declaration for the State of Minnesota (FEMA-1921-DR), dated July 2, 2010, and related determinations.
Peggy Miller, Recovery Directorate, Federal Emergency Management Agency, 500 C Street, SW., Washington, DC 20472, (202) 646-3886.
The notice of a major disaster declaration for the State of Minnesota is hereby amended to include the following areas among those areas determined to have been adversely affected by the event declared a major disaster by the President in his declaration of July 2, 2010.
Blue Earth, Brown, Houston, Kittson, Nicollet, and Sibley Counties for Public Assistance.
Federal Emergency Management Agency, DHS.
Notice.
This is a notice of the Presidential declaration of a major disaster for the Commonwealth of Kentucky (FEMA-1925-DR), dated July 23, 2010, and related determinations.
Peggy Miller, Recovery Directorate, Federal Emergency Management Agency, 500 C Street, SW., Washington, DC 20472, (202) 646-3886.
Notice is hereby given that, in a letter dated July 23, 2010, the President issued a major disaster declaration under the authority of the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121
I have determined that the damage in certain areas of the Commonwealth of Kentucky resulting from severe storms, flooding, and mudslides beginning on July 17, 2010, and continuing, is of sufficient severity and magnitude to warrant a major disaster declaration under the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121
In order to provide Federal assistance, you are hereby authorized to allocate from funds available for these purposes such amounts as you find necessary for Federal disaster assistance and administrative expenses.
You are authorized to provide Individual Assistance and Public Assistance in the designated areas and Hazard Mitigation throughout the Commonwealth. Direct Federal assistance is authorized. Consistent with the requirement that Federal assistance is supplemental, any Federal funds provided under the Stafford Act for Public Assistance, Hazard Mitigation, and Other Needs Assistance will be limited to 75 percent of the total eligible costs.
Further, you are authorized to make changes to this declaration for the approved assistance to the extent allowable under the Stafford Act.
The time period prescribed for the implementation of section 310(a), Priority to Certain Applications for Public Facility and Public Housing Assistance, 42 U.S.C. 5153, shall be for a period not to exceed six months after the date of this declaration.
The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, Douglas G. Mayne, of FEMA is appointed to act as the Federal Coordinating Officer for this major disaster.
The following areas of the Commonwealth of Kentucky have been designated as adversely affected by this major disaster:
Pike County for Individual Assistance.
Pike County for Public Assistance, including direct Federal assistance.
All counties within the Commonwealth of Kentucky are eligible to apply for assistance under the Hazard Mitigation Grant Program.
Federal Emergency Management Agency, DHS.
Notice of availability; request for comments.
The Federal Emergency Management Agency (FEMA) is accepting comments on Recovery Fact Sheet 9580.203,
Comments must be received by September 1, 2010.
Comments must be identified by docket ID FEMA-2010-0045 and may be submitted by one of the following methods:
Byron Mason, Federal Emergency Management Agency, 500 C Street, SW., Washington, DC 20472, 202-646-4368.
You may submit your comments and material by the methods specified in the
This Fact Sheet provides Public Assistance applicants with information on how to properly monitor debris removal operations to ensure compliance with Public Assistance guidelines. Specifically, the fact sheet provides information on debris monitoring roles and responsibilities, monitoring requirements by type of contract, monitoring contracts, reporting requirements and performance measures, and contract procurement requirements.
FEMA seeks comment on the proposed fact sheet, which is available
42 U.S.C. 5121-5207; 44 CFR parts 13 and 206.
Office of the Chief Information Officer, HUD.
Notice.
The proposed information collection requirement described below has been submitted to the Office of Management and Budget (OMB) for review, as required by the Paperwork Reduction Act. The Department is soliciting public comments on the subject proposal.
Information provided is a critical element and the source document by which HUD determines the cooperative member and group capacity to meet the financial requirements of a HUD-insured cooperative project.
Interested persons are invited to submit comments regarding this proposal. Comments should refer to the proposal by name and/or OMB approval Number (2502-0058) and should be sent to: HUD Desk Officer, Office of Management and Budget, New Executive Office Building, Washington, DC 20503;
Leroy McKinney, Jr., Reports Management Officer, QDAM, Department of Housing and Urban Development, 451 Seventh Street, SW., Washington, DC 20410; e-mail Leroy McKinney, Jr. at
This notice informs the public that the Department of Housing and Urban Development has submitted to OMB a request for approval of the Information collection described below. This notice is soliciting comments from members of the public and affecting agencies concerning the proposed collection of information to: (1) Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility; (2) Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information; (3) Enhance the quality, utility, and clarity of the information to be collected; and (4) Minimize the burden of the collection of information on those who are to respond; including through the use of appropriate automated collection techniques or other forms of information technology, e.g., permitting electronic submission of responses.
This notice also lists the following information:
Section 3507 of the Paperwork Reduction Act of 1995, 44 U.S.C. 35, as amended.
Office of the Chief Information Officer, HUD
Notice.
The proposed information collection requirement described below has been submitted to the Office of Management and Budget (OMB) for review, as required by the Paperwork Reduction Act. The Department is soliciting public comments on the subject proposal.
Information collected is used to request final endorsement by HUD of the credit instrument. The mortgagee/lender submits information to indicate the schedule of advances made on the project and the final advance to be disbursed immediately upon final endorsement.
Interested persons are invited to submit comments regarding this proposal. Comments should refer to the proposal by name and/or OMB approval Number (2502-0016) and should be sent to: HUD Desk Officer, Office of Management and Budget, New
Leroy McKinney Jr., Reports Management Officer, QDAM, Department of Housing and Urban Development, 451 Seventh Street, SW., Washington, DC 20410; e-mail Leroy McKinney Jr. at
This notice informs the public that the Department of Housing and Urban Development has submitted to OMB a request for approval of the Information collection described below. This notice is soliciting comments from members of the public and affecting agencies concerning the proposed collection of information to: (1) Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility; (2) Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information; (3) Enhance the quality, utility, and clarity of the information to be collected; and (4) Minimize the burden of the collection of information on those who are to respond; including through the use of appropriate automated collection techniques or other forms of information technology, e.g., permitting electronic submission of responses.
This notice also lists the following information:
Section 3507 of the Paperwork Reduction Act of 1995, 44 U.S.C. 35, as amended.
Office of the Chief Information Officer, HUD.
Notice.
The proposed information collection requirement described below has been submitted to the Office of Management and Budget (OMB) for review, as required by the Paperwork Reduction Act. The Department is soliciting public comments on the subject proposal.
Mortgagees provide information to apply for insurance benefits. HUD uses the information provided to cancel multifamily mortgage insurance contracts and payments of mortgage insurance.
Interested persons are invited to submit comments regarding this proposal. Comments should refer to the proposal by name and/or OMB approval Number (2502-0419) and should be sent to: HUD Desk Officer, Office of Management and Budget, New Executive Office Building, Washington, DC 20503;
Leroy McKinney, Jr., Reports Management Officer, QDAM, Department of Housing and Urban Development, 451 Seventh Street, SW., Washington, DC 20410; e-mail Leroy McKinney Jr. at
This notice informs the public that the Department of Housing and Urban Development has submitted to OMB a request for approval of the Information collection described below. This notice is soliciting comments from members of the public and affecting agencies concerning the proposed collection of information to: (1) Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility; (2) Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information; (3) Enhance the quality, utility, and clarity of the information to be collected; and (4) Minimize the burden of the collection of information on those who are to respond; including through the use of appropriate automated collection techniques or other forms of information technology, e.g., permitting electronic submission of responses.
Section 3507 of the Paperwork Reduction Act of 1995, 44 U.S.C. 35, as amended.
Office of the Chief Information Officer, HUD.
Notice.
The proposed information collection requirement described below has been submitted to the Office of Management and Budget (OMB) for review, as required by the Paperwork Reduction Act. The Department is soliciting public comments on the subject proposal.
Owners of insured and assisted multifamily housing projects are required to submit documentation for HUD's review and approval of new management agents.
Interested persons are invited to submit comments regarding this proposal. Comments should refer to the proposal by name and/or OMB approval Number (2502-0305) and should be sent to: HUD Desk Officer, Office of Management and Budget, New Executive Office Building, Washington, DC 20503;
Leroy McKinney Jr., Reports Management Officer, QDAM, Department of Housing and Urban Development, 451 Seventh Street, SW., Washington, DC 20410; e-mail Leroy McKinney Jr. at
This notice informs the public that the Department of Housing and Urban Development has submitted to OMB a request for approval of the Information collection described below. This notice is soliciting comments from members of the public and affecting agencies concerning the proposed collection of information to: (1) Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility; (2) Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information; (3) Enhance the quality, utility, and clarity of the information to be collected; and (4) Minimize the burden of the collection of information on those who are to respond; including through the use of appropriate automated collection techniques or other forms of information technology, e.g., permitting electronic submission of responses.
This notice also lists the following information:
Owners of insured and assisted multifamily housing projects are required to submit documentation for HUD's review and approval of new management agents.
Section 3507 of the Paperwork Reduction Act of 1995, 44 U.S.C. 35, as amended.
Office of the Chief Information Officer, HUD.
Notice.
The proposed information collection requirement described below has been submitted to the Office of Management and Budget (OMB) for review, as required by the Paperwork Reduction Act. The Department is soliciting public comments on the subject proposal.
Information is provided by contractors, mortgagors/borrowers, and mortgagees/lenders for construction of multifamily projects and to obtain approval of changes in previously approved contract drawings and/or specifications.
Interested persons are invited to submit comments regarding this proposal. Comments should refer to the proposal by name and/or OMB
Leroy McKinney Jr., Reports Management Officer, QDAM, Department of Housing and Urban Development, 451 Seventh Street, SW., Washington, DC 20410; e-mail Leroy McKinney Jr. at
This notice informs the public that the Department of Housing and Urban Development has submitted to OMB a request for approval of the Information collection described below. This notice is soliciting comments from members of the public and affecting agencies concerning the proposed collection of information to: (1) Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility; (2) Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information; (3) Enhance the quality, utility, and clarity of the information to be collected; and (4) Minimize the burden of the collection of information on those who are to respond; including through the use of appropriate automated collection techniques or other forms of information technology,
This notice also lists the following information:
Section 3507 of the Paperwork Reduction Act of 1995, 44 U.S.C. 35, as amended.
Office of the Assistant Secretary for Public and Indian Housing, HUD.
Notice.
In accordance with the American Recovery and Reinvestment Act of 2009 (Pub. L. 111-05, approved February 17, 2009) (Recovery Act), and implementing guidance of the Office of Management and Budget (OMB), this notice advises that certain exceptions to the Buy American requirement of the Recovery Act have been determined applicable for work using Capital Fund Recovery Formula and Competition (CFRFC) grant funds. Specifically, exemptions were granted to the Tampa Housing Authority for the purchase and installation of tankless hot water heaters at the North Boulevard Homes and mini-split ductless Heating, Ventilation and Air Conditioning (HVAC) systems at the Mary Bethune High Rise, and to the King County Housing Authority for the purchase of energy efficient bathroom ventilation fans.
Dominique G. Blom, Deputy Assistant Secretary for Public Housing Investments, Office of Public Housing Investments, Office of Public and Indian Housing, Department of Housing and Urban Development, 451 7th Street, SW., Room 4130, Washington, DC 20410-4000, telephone number 202-402-8500 (this is not a toll-free number). Persons with hearing- or speech-impairments may access this number through TTY by calling the toll-free Federal Information Relay Service at 800-877-8339.
Section 1605(a) of the Recovery Act provides that none of the funds appropriated or made available by the Recovery Act may be used for a project for the construction, alteration, maintenance, or repair of a public building or public work unless all of the iron, steel, and manufactured goods used in the project are produced in the United States. Section 1605(b) provides that the Buy American requirement shall not apply in any case or category in which the head of a Federal department or agency finds that: (1) Applying the Buy American requirement would be inconsistent with the public interest; (2) iron, steel, and the relevant manufactured goods are not produced in the U.S. in sufficient and reasonably available quantities or of satisfactory quality, or (3) inclusion of iron, steel, and manufactured goods will increase the cost of the overall project by more than 25 percent. Section 1605(c) provides that if the head of a Federal department or agency makes a determination pursuant to section 1605(b), the head of the department or agency shall publish a detailed written justification in the
In accordance with section 1605(c) of the Recovery Act and OMB's implementing guidance published on April 23, 2009 (74 FR 18449), this notice advises the public that on the following dates, HUD granted the following two exceptions to the Buy American requirement:
1.
2.
Office of the Chief of the Human Capital Officer, HUD.
Notice.
HUD announces the availability on its website of the application information, submission deadlines, funding criteria, and other requirements for the FY2010 Housing Counseling Grant NOFA. Approximately $79 million is made available through this NOFA, by the Consolidated Appropriations Act, 2010 (Pub. L. 111-117, approved December 16, 2009), to support the delivery of a wide variety of housing counseling services to homebuyers, homeowners, low- and moderate-income renters and the homeless. The primary objectives of the program are to improve financial literacy, expand homeownership opportunities, improve access to affordable housing, and preventing foreclosure.
The notice providing information regarding the application process, funding criteria and eligibility requirements can be found using the Department of Housing and Urban Development agency link on the Grants.gov/Find Web site at
For information concerning the Housing Counseling Program, please contact Terri Gilyard-Ames, Program Support Division, Office of Single Family Housing, Office of Housing, at 202-402-3025. Questions regarding the FY2010 General Section should be directed to the Office of Departmental Grants Management and Oversight at 202-708-0667 (this is not a toll-free number) or the NOFA Information Center at 1-800-HUD-8929 (toll-free). Persons with speech or hearing impairments may access this telephone number via TTY by calling the toll-free Federal Information Relay Service during working hours at 800-877-8339.
Office of the Secretary, Office of Healthy Homes and Lead Hazard Control
Announcement of awards funded.
In accordance with Section 102(a)(4)(C) of the Department of Housing and Urban Development Reform Act of 1989, this announcement notifies the public of funding decisions made by the Department in competitions for funding under the Office of Healthy Homes and Lead Hazard Control Grant Program Notices of Funding Availability. This announcement contains the name and address of the award recipients and the amounts of award awarded.
Mr. Matthew Ammon, Department of Housing and Urban Development, Office of Healthy Homes and Lead Hazard Control, Room 8236, 451 Seventh Street, SW., Washington, DC 20410, telephone (202) 402- 4337. Hearing-and speech-impaired persons may access the number above via TTY by calling the toll free Federal Relay Service at 1-800-877-8339.
The 2009 awards were announced December 29, 2008. These awards were the result of competitions announced in a
1. A total of $67,826,437 was awarded to 26 grantees for the Lead Based Paint Hazard Control Grant Program under the Consolidated Appropriations Act, 2009: City of Huntington Park, 6550 Miles Avenue, Huntington Park, CA 90255, $1,570,000; City of South Lake Tahoe, 1901 Airport Road, Suite 107, South Lake Tahoe, CA 96150, $1,500,000; State of Connecticut Department of Social Services, 25 Sigourney Street, Hartford, CT 06106, $3,000,000; City of Kankakee, 199 S. East Avenue, Suite 1, Kankakee, IL 60901, $3,000,000; Will County, 302 North Chicago Street, Joliet, IL 60432, $2,070,000; Health and Hospital Corporation of Marion County, 3838 North Rural Street, Indianapolis, IN 46205, $3,069,893; Indiana State Department of Health, 2 North Meridian Street, Indianapolis, IN 46204, $1,140,000; Louisville Jefferson County Metro Government, 527 West Jefferson Street, Louisville, KY 40202, $2,724,823; City of Boston, 26 Court Street, Boston, MA 02136, $3,070,000; City of Lynn Massachusetts, Office of Economic & Community Development, Lynn City Hall, Room 311, Lynn, MA 01902, $2,000,000; City of Worcester, 44 Front Street, Suite 520, Worcester, MA 01608, $3,000,754; Genesee County Health Department, 630 Saginaw Street, Suite 4, Flint, MI 48502, $2,070,000;
2. A total of $48,000,000 was awarded to 15 grantees for the Lead Hazard Reduction Demonstration Grant Program under the Consolidated Appropriations Act, 2009: State of Connecticut Department of Social Services, 25 Sigourney Street, Hartford, CT 06106, $3,000,000; City of Worcester Massachusetts, 44 Front Street, Suite 520, Worcester, MA 01608, $3,000,754; Baltimore County Maryland, 6401 York Road, Second Floor, Baltimore, MD 21212; $4,000,000; City of Detroit, 65 Cadillac Square, Suite 2300, Detroit, MI 48226, $3,525,372; Hennepin County, 417 North 5th Street, Suite 320, Minneapolis, MN 55401, $3,000,000; County of Westchester, 148 Martine Avenue, Room 414, White Plains, NY 10601, $1,150,000; Nassau County, 40 Main Street, 3rd Floor, Hempstead, NY 11550-4042, $4,000,000; Syracuse Lead Hazard and Control Program, 201 Easy Washington Street, Room 500, Syracuse, NY 13202, $2,050,000; City of Akron Ohio, 161 South High Street, Akron, OH 44308, $4,000,000; City of Portland, 421 SW Sixth Avenue, Suite 1100, Portland, OR 97204, $4,000,000; Redevelopment Authority of the City of Erie, 917 State Street, Erie, PA 16501, $4,000,000; City of San Antonio, 1400 South Flores, San Antonio, TX 78204, $2,023,874; Houston Department of Health and Human Services, 8000 North Stadium Drive, 2nd Floor, Houston, TX 77054, $2,250,000; Kenosha County Department of Human Services, 8600 Sheridan Road, Suite 600, Kenosha, WI 53143, $4,000,000; Wisconsin Department of Health Services, 1 West Wilson Street, P.O. Box 7850, Madison, WI 53707, $4,000,000.
3. A total of $6,124,128 was awarded to 7 grantees for the Healthy Homes Demonstration Grant Program under the Consolidated Appropriations Act, 2009: County of Alameda Lead Poisoning Prevention Program, 2000 Embarcadero Suite 300, Oakland, CA 94606, $875,000; City of San Diego, 9601 Ridgehaven Court, Ste. 310, San Diego, CA 92123, $874,667; Boston Public Health Commission, 1010 Massachusetts Avenue, Boston, MA 02118, $874,563; Coalition to End Childhood Lead Poisoning, 2714 Hudson Street, Baltimore, MD 21224, $875,000; Cuyahoga County Board of Health, 5550 Venture Dr., Parma, OH 44130, $875,000; Multnomah County, 426 SW Stark Street 8th floor, Portland, OR 97204, $874,898; Eastern Virginia Medical School, 358 Mowbray Arch, PO Box 1980, Norfolk, VA 23501, $875,000.
4. A total of $4,081,824 was awarded to 7 grantees for the Healthy Homes Technical Studies Grant Program under the Consolidated Appropriations Act, 2009: Boston Public Health Commission, 1010 Massachusetts Avenue, Boston, MA 02118, $799,503; City of Somerville, OSPCD, Somerville, MA 02143, $749,893; Saint Louis University, 211 North Grand Boulevard, St. Louis, MO 63103, $326,246; Washington University, 660 South Euclid Avenue, St. Louis, MO 63110, $599,937; Rutgers, The State University of New Jersey, 3 Rutgers Plaza, New Brunswick, NJ 08901, $251,453; The Trustees of Columbia University in the City of New York, 630 West 168th Street, Box 49, New York, NY 10032, $799,947; University of Cincinnati, 51 Goodman Drive, University Hall, Suite 530, PO Box 210222, Cincinnati, OH 45221, $554,845.
5. A total of $2,400,000 was awarded to 4 grantees for the Green and Healthy Homes Technical Studies Grant Program under the Consolidated Appropriations Act, 2009: Arizona Board of Regents for Arizona State University, 1711 South Rural Road, Tempe, AZ 85287, $450,000; National Center for Healthy Housing, 10320 Little Patuxent Parkway, Columbia, MD 21044, $650,000; Environmental Health Watch, 3500 Lorain Avenue, Room 301, Cleveland, OH 44113, $650,000; Rutgers, the State University of New Jersey, 3 Rutgers Plaza, New Brunswick, NJ 08901, $650,000.
6. A total of $618,060 was awarded to 7 grantees for the Lead Hazard Control Capacity Building Grant Program under the Consolidated Appropriations Act, 2009; City of Jacksonville, #1 Municipal Drive, Jacksonville, AR 72076, $60,000; Pembroke Township, 4530 South Main Street, Pembroke Township, IL 60958, $71,423; Spirit Lake Nation, PO Box 99, Fort Totten, ND 58335, $100,000; Public Health Solutions District Health Department, 995 East Highway 33, Suite 1, Crete, NE 68333, $94,577; Broome County Health Department, 225 Front Street, Broome, NY 13905, $100,000; Niagara County Department of Health, 5467 Upper Mountain Road, Lockport, NY 14094, $100,000; City of Waukesha, A Wisconsin Municipal Corporation, 201 Delafield Street, Waukesha, WI 53188, $92,060.
60-Day Notice of Information Collection Under Review: Supplemental Statement (Foreign Agents).
The Department of Justice (DOJ), National Security Division (NSD), will be submitting the following information collection request to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995. The proposed information collection is published to obtain comments from the public and affected agencies. Comments are encouraged and will be accepted for “sixty days” until October 1, 2010. This process is conducted in accordance with 5 CFR 1320.10.
If you have comments especially on the estimated public burden or associated response time, suggestions, or need a copy of the proposed information collection instrument with instructions or additional information, please write to U.S. Department of
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information are encouraged. Your comments should address one or more of the following four points:
(1)
(2)
(3)
(4)
(5)
(6)
60-Day Notice of Information Collection Under Review: Exhibit A to Registration Statement (Foreign Agents).
The Department of Justice (DOJ), National Security Division (NSD), will be submitting the following information collection request to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995. The proposed information collection is published to obtain comments from the public and affected agencies. Comments are encouraged and will be accepted for “sixty days” until October 1, 2010. This process is conducted in accordance with 5 CFR 1320.10.
If you have comments especially on the estimated public burden or associated response time, suggestions, or need a copy of the proposed information collection instrument with instructions or additional information, please write to U.S. Department of Justice, 10th & Constitution Avenue, NW., National Security Division, Counterespionage Section/Registration Unit, Bond Building—Room 9300, Washington, DC 20530. If you need a copy of the collection instrument with instructions, or have additional information, please contact the Registration Unit at 202-514-1216.
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information are encouraged. Your comments should address one or more of the following four points:
(1)
(2)
(3)
(4)
(5)
(6)
If additional information is required contact: Lynn Bryant, Department Clearance Officer, Policy and Planning Staff, Justice Management Division, Department of Justice, Two Constitution Square, Suite 2E-502, 145 N Street, NE., Washington, DC 20530.
60-Day Notice of Information Collection Under Review: Exhibit B to Registration Statement (Foreign Agents).
The Department of Justice (DOJ), National Security Division (NSD), will be submitting the following information collection request to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995. The proposed information collection is published to obtain comments from the public and affected agencies. Comments are encouraged and will be accepted for “sixty days” until October 1, 2010. This process is conducted in accordance with 5 CFR 1320.10.
If you have comments, suggestions, or additional information, especially regarding the estimated public burden or associated response time, please write to U.S. Department of Justice, 10th & Constitution Avenue, NW., National Security Division, Counterespionage Section/Registration Unit, Bond Building—Room 9300, Washington, DC 20530. If you need a copy of the proposed information collection instrument with instructions, or have additional information, please contact the Registration Unit at (202) 514-1216.
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information are encouraged. Your comments should address one or more of the following four points:
(1)
(2)
(3)
(4)
(5)
(6)
If additional information is required contact: Lynn Bryant, Department Clearance Officer, Policy and Planning Staff, Justice Management Division, Department of Justice, Two Constitution Square, Suite 2E-502, 145 N Street, NE., Washington, DC 20530.
60-Day Notice of Information Collection under Review: Registration Statement (Foreign Agents).
The Department of Justice (DOJ), National Security Division (NSD), will be submitting the following information collection request to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995. The proposed information collection is published to obtain comments from the public and affected agencies. Comments are encouraged and will be accepted for “sixty days” until October 1, 2010. This process is conducted in accordance with 5 CFR 1320.10.
If you have comments especially on the estimated public burden or associated response time, suggestions, or need a copy of the proposed information collection instrument with instructions or additional information, please write to U.S. Department of Justice, 10th & Constitution Avenue, NW., National Security Division, Counterespionage Section/Registration Unit, Bond Building—Room 9300, Washington, DC 20530. If you need a copy of the collection instrument with instructions, or have additional information, please contact the Registration Unit at 202.514.1216.
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information are encouraged. Your comments should address one or more of the following four points:
(1)
(2)
(3)
(4)
(5)
(6)
If additional information is required contact: Lynn Bryant, Department Clearance Officer, Policy and Planning Staff, Justice Management Division, Department of Justice, Two Constitution Square, Suite 2E-502, 145 N Street, NE., Washington, DC 20530.
60-Day Notice of Information Collection under Review: Short-Form Registration Statement (Foreign Agents).
The Department of Justice (DOJ), National Security Division (NSD), will be submitting the following information collection request to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995. The proposed information collection is published to obtain comments from the public and affected agencies. Comments are encouraged and will be accepted for “sixty days” until October 1, 2010. This process is conducted in accordance with 5 CFR 1320.10.
If you have comments, suggestions, or additional information, especially regarding the estimated public burden or associated response time, please write to U.S. Department of Justice, 10th & Constitution Avenue, NW., National Security Division, Counterespionage Section/Registration Unit, Bond Building—Room 9300, Washington, DC 20530. If you need a copy of the collection instrument with instructions, or have additional information, please contact the Registration Unit at 202-514-1216.
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information are encouraged. Your comments should address one or more of the following four points:
(1)
(2)
(3)
(4)
(5)
(6)
Proposed Collection; Comments Requested
60-Day Notice of Information Collection Under Review: Amendment to Registration Statement (Foreign Agents).
The Department of Justice (DOJ), National Security Division (NSD), will be submitting the following information collection request to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995. The proposed information collection is published to obtain comments from the public and affected agencies. Comments are encouraged and will be accepted for “sixty days” until October 1, 2010. This process is conducted in accordance with 5 CFR 1320.10.
If you have comments especially on the estimated public burden or associated response time, suggestions, or need a copy of the proposed information collection instrument with instructions or additional information, please write to U.S. Department of Justice, 10th & Constitution Avenue, NW., National Security Division, Counterespionage Section/Registration Unit, Bond Building—Room 9300, Washington, DC 20530. If you need a copy of the collection instrument with instructions, or have additional information, please contact the Registration Unit at (202) 514-1216.
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information are encouraged. Your comments should address one or more of the following four points:
(1)
(2)
(3)
(4)
(5)
(6)
If additional information is required contact: Lynn Bryant, Department Clearance Officer, Policy and Planning Staff, Justice Management Division, Department of Justice, Two Constitution Square, Suite 2E-502, 145 N Street, NE., Washington, DC 20530.
Notice is hereby given that, on July 1, 2010, pursuant to Section 6(a) of the National Cooperative Research and Production Act of 1993, 15 U.S.C. 4301
No other changes have been made in either the membership or planned activity of the group research project. Membership in this group research project remains open, and NCOIC intends to file additional written notifications disclosing all changes in membership.
On November 19, 2004, NCOIC filed its original notification pursuant to Section 6(a) of the Act. The Department of Justice published a notice in the
The last notification was filed with the Department on April 6, 2010. A notice was published in the
Notice is hereby given that, on June 30, 2010, pursuant to Section 6(a) of the National Cooperative Research and Production Act of 1993, 15 U.S.C. 4301
Also, Control System Technology Pty. Ltd., Peakhurst NSW, AUSTRALIA; KASHIYAMA Industries Ltd., Tokyo, JAPAN; Leuze lumiflex GmbH + Co., Fuerstenfeldbruck, GERMANY; Meggitt Airdynamics, Inc., a Division of Whittaker Controls, Meggitt PLC, Corona, CA; Moog Inc., East Aurora, NY; Riken Keiki Co., Ltd., Tokyo, JAPAN; Rockwell Automation Korea, Seoul, REPUBLIC OF KOREA; Taiyo Electric Wire & Cable Co., Ltd., Osaka, JAPAN; VAT Vacuum Valves AG, Haag, SWITZERLAND; and Vector Informatik GmbH, Stuttgart, GERMANY, have withdrawn as parties to this venture.
No other changes have been made in either the membership or planned activity of the group research project. Membership in this group research project remains open, and ODVA intends to file additional written notifications disclosing all changes in membership.
On June 21, 1995, ODVA filed its original notification pursuant to Section 6(a) of the Act. The Department of Justice published a notice in the
The last notification was filed with the Department on March 17, 2010. A notice was published in the
Notice is hereby given that, on June 11, 2010, pursuant to section 6(a) of the National Cooperative Research and Production Act of 1993, 15 U.S.C. 4301
Pursuant to Section 6(b) of the Act, the name and principal place of business of the standards development organization is Energistics Consortium, Inc., Sugar Land, TX. The nature and scope of Energistics's standards development activities are the facilitation of a neutral collaboration environment and an inclusive user community for the development, deployment, and maintenance of freely-available, standards-based, collaborative
Notice is hereby given that, on June 2, 2010, pursuant to Section 6(a) of the National Cooperative Research and Production Act of 1993, 15 U.S.C. 4301
No other changes have been made in either the membership or planned activity of the group research project. Membership in this group research project remains open, and PERF intends to file additional written notifications disclosing all changes in membership.
On February 10, 1986, PERF filed its original notification pursuant to Section 6(a) of the Act. The Department of Justice published a notice in the
The last notification was filed with the Department on February 27, 2009. A notice was published in the
Notice is hereby given that, on June 28, 2010, pursuant to Section 6(a) of the National Cooperative Research and Production Act of 1993, 15 U.S.C. 4301
On September 15, 2004, ASME filed its original notification pursuant to Section 6(a) of the Act. The Department of Justice published a notice in the
The last notification was filed with the Department on February 25, 2010. A notice was published in the
30-day notice of information collection under review: Extension of a currently approved collection: Capital punishment report of inmates under sentence of death.
The Department of Justice (DOJ), Office of Justice Programs, Bureau of Justice Statistics will be submitting the following information collection request to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995. The proposed information collected is published to obtain comments from the public and affected agencies. The proposed information collected was previously published in the
The purpose of this notice is to allow for an additional 30 days for public comment until September 1, 2010. This process is conducted in accordance with 5 CFR 1320.10.
Written comments and/or suggestions regarding the items contained in this notice, especially the estimated public burden or associated response time, should be directed to The Officer of Management and Budget, Officer of Information and Regulatory Affairs, Attention: Department of Justice Desk Officer, Washington, DC 20503. Additionally, comments may be submitted to OMB via facsimile to (202) 395-7285.
Request written comments and suggestions from the public and affected agencies concerning the proposed collection of information are encouraged. Your comments should address one or more of the following four points:
(1) Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
(2) Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
(3) Enhance the quality, utility and clarity of the information to be collected; and
(4) Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology,
(1)
(2)
(3)
(4)
(5)
(6)
If additional information is required contact: Lynn Bryant, Clearance Officer, United States Department of Justice, Justice Management Division, Policy and Planning Staff, Patrick Henry Building, Suite 1600, 601 D Street, NW., Washington, DC 20530.
The Department of Labor (DOL) hereby announces the submission of the following public information collection request (ICR) to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995 (Pub. L. 104-13, 44 U.S.C. chapter 35). A copy of the ICR, with applicable supporting documentation; including, among other things, a description of the likely respondents, proposed frequency of response, and estimated total burden may be obtained from the RegInfo.gov Web site at
Interested parties are encouraged to send comments to the Office of Information and Regulatory Affairs, Attn: OMB Desk Officer for the Department of Labor—Occupational Safety and Health Administration (OSHA), Office of Management and Budget, Room 10235, Washington, DC 20503,
The OMB is particularly interested in comments which:
• Evaluate whether the proposed information collection requirements are necessary for the proper performance of the Agency, including whether the information will have practical utility;
• Evaluate the accuracy of the Agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
• Enhance the quality, utility, and clarity of the information to be collected; and
• Minimize the burden of the collection of information on those who are 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.
For additional information, see the related 60-day preclearance notice published in the
In accordance with Section 223 of the Trade Act of 1974, as amended (“Act”), 19 U.S.C. 2273, the Department of Labor issued a Certification of Eligibility to Apply for Worker Adjustment Assistance on May 20, 2010, applicable to workers of Holcim (US) Inc., Corporate Division, including on-site leased workers from Manpower and Office Team, Dundee, Michigan. The notice was published in the
At the request of the State Agency, the Department reviewed the certification for workers of the subject firm. The workers supply administrative services for the subject firm.
The company reports that workers leased from Advance Temporary Services were employed on-site at the Dundee, Michigan location of Holcim (US) Inc., Corporate Division. The Department has determined that these workers were sufficiently under the control of the subject firm to be considered leased workers.
Based on these findings, the Department is amending this certification to include workers leased from Advance Temporary Services working on-site at the Dundee, Michigan location of Holcim (US), Inc., Corporate Division.
The amended notice applicable to TA-W-73,382 is hereby issued as follows:
All workers of Holcim (US) Inc., Corporate Division, including on-site leased workers from Manpower, Office Team Advance Temporary Services, Dundee, Michigan, who became totally or partially separated from employment on or after January 2, 2009, through May 20, 2012, and all workers in the group threatened with total or partial separation from employment on the date of certification through two years from the date of certification, are eligible to apply for adjustment assistance under Chapter 2 of Title II of the Trade Act of 1974, as amended.
In accordance with Section 223 of the Trade Act of 1974, as amended (“Act”), 19 U.S.C. 2273, the Department of Labor issued a Certification of Eligibility to Apply for Worker Adjustment Assistance on January 21, 2010, applicable to the workers of RBS Citizens, N.A., Business Services Division, at multiple locations across Rhode Island, Massachusetts, Ohio, New Jersey and Pennsylvania. The notice was published in the
At the request of a company official, the Department reviewed the certification for workers of the subject firm. The workers are engaged in activities related to the supply of internal administrative services.
New findings show that worker separations occurred at the 875 Elm Street, Manchester, New Hampshire location of the subject firm during the relevant time period.
Accordingly, the Department is amending this certification to include workers of the Manchester, New Hampshire location of RBS Citizens, N.A., Business Services.
The intent of the Department's certification is to include all workers of the subject firm who were adversely affected by a shift in the supply of internal administrative services to India and Poland.
The amended notice applicable to TA-W-72,873 is hereby issued as follows:
All workers of RBS Citizens, N.A., Business Services Division, including on-site leased workers of Manpower and Randstad, 1 Citizens Drive, Riverside, Rhode Island (TA-W-72,873); 10 Tripps Lane, Riverside, Rhode Island (TA-W-72,873A); 100 Sockanosset Cross Road, Cranston, Rhode Island (TA-W-72,873B); 20 Cabot Road, Medford, Massachusetts (TA-W-72,873C); 4780 Hinckley Industrial Parkway, Cleveland, Ohio (TA-W-72,873D); 499 Washington Boulevard, Jersey City, New Jersey (TA-W-72,873E); 1000 Lafayette Boulevard, Bridgeport, Connecticut (TA-W-72,873G); 443 Jefferson Boulevard, Warwick, Rhode Island (TA-W-72,873H); 480 Jefferson Boulevard, Warwick, Rhode Island (TA-W-72,873I); 10561 Telegraph Road, Glen Allen, Virginia (TA-W-72,873J); Citizens Bank of Pennsylvania, Business Services Division, including on-site leased workers of Manpower and Randstad, 801 Market Street, Philadelphia, Pennsylvania (TA-W-72,873F); 525 William Penn Place, Pittsburgh, Pennsylvania (TA-W-72,873K); and 875 Elm Street, Manchester, New Hampshire, who became totally or partially separated from employment on or after November 16, 2008, through January 21, 2012, and all workers in the group threatened with total or partial separation from employment on date of certification through two years from the date of certification, are eligible to apply for adjustment assistance under Chapter 2 of Title II of the Trade Act of 1974, as amended.
In accordance with Section 223 of the Trade Act of 1974, as amended (“Act”), 19 U.S.C. 2273, the Department of Labor issued a Certification of Eligibility to Apply for Worker Adjustment Assistance on March 12, 2010, applicable to workers of Premier Manufacturing Support Services, Inc., Spring Hill, Tennessee. The notice was published in the
At the request of a company official, the Department reviewed the certification for workers of the subject firm. The workers are engaged in janitorial, maintenance, hazardous waste disposal, grounds keeping, and shipping services.
The company reports that workers leased from Randstat were employed on-site at the Spring Hill, Tennessee location of Premier Manufacturing Support Services, Inc. The Department has determined that these workers were sufficiently under the control of the subject firm to be considered leased workers.
Based on these findings, the Department is amending this certification to include workers leased from Randstat working on-site at the Spring Hill, Tennessee location of Heritage Aviation.
The amended notice applicable to TA-W-72,379 is hereby issued as follows:
All workers of Premier Manufacturing Support Services, Inc., including on-site leased workers from Randstat, Spring Hill, Tennessee, who became totally or partially separated from employment on or after June 13, 2009, through March 12, 2012, and all workers in the group threatened with total or partial separation from employment on the date of certification through two years from the date of certification, are eligible to apply for adjustment assistance under Chapter 2 of Title II of the Trade Act of 1974, as amended.
Signed at Washington, DC, this 16th day of July 2010.
In accordance with Section 223 of the Trade Act of 1974, as amended (“Act”), 19 U.S.C. 2273, the Department of Labor issued a Certification of Eligibility to Apply for Worker Adjustment Assistance on August 17, 2009, applicable to workers of Stanadyne Corporation, including on-site leased workers for Infini-Staff and Staffing Now, Windsor, Connecticut. The notice was published in the
At the request of the State agency, the Department reviewed the certification for workers of the subject firm. The workers are engaged in the production of diesel engine fuel system components including fuel pumps, fuel injectors, and precision custom manufactured parts.
New information shows that workers leased from Apollo Professional Solutions were employed on-site at the Windsor, Connecticut location of Stanadyne Corporation. The Department has determined that these workers were sufficiently under the control of the subject firm to be considered leased workers.
Based on these findings, the Department is amending this certification to include workers leased from Apollo Professional Solutions working on-site at the Windsor, Connecticut location of the subject firm.
The amended notice applicable to TA-W-71,056 is hereby issued as follows:
All workers of Stanadyne Corporation, including on-site leased workers from Infini-Staff, Staffing Now and Apollo Professional Solutions, Inc., Windsor, Connecticut, who became totally or partially separated from employment on or after June 4, 2008, through August 17, 2011, and all workers in the group threatened with total or partial separation from employment on the date of certification through two years from the date of certification, are eligible to apply for adjustment assistance under Chapter 2 of Title II of the Trade Act of 1974, as amended.
In accordance with Section 223 of the Trade Act of 1974, as amended (“Act”), 19 U.S.C. 2273, the Department of Labor issued a Certification of Eligibility to Apply for Worker Adjustment Assistance on July 14, 2009, applicable to workers of Delphi Steering, including on-site leased workers from Bartech and Securitas, Saginaw, Michigan. The notice was published in the
At the request of the State agency, the Department reviewed the certification for workers of the subject firm. The workers are engaged in the production of steering systems and components such as steering columns, gears, pumps and electronic power steering systems.
New information shows that as of October 6, 2009, the Saginaw, Michigan location Delphi Steering is now known as Nexteer Automotive. Some workers separated from employment at the subject firms have their wages reported
Accordingly, the Department is amending this certification to properly reflect this matter.
The intent of the Department's certification is to include all workers of the subject firm who were adversely affected by a shift in production of steering systems and components such as steering columns, gears, pumps and electronic power steering systems to Mexico and Brazil.
The amended notice applicable to TA-W-70,460 is hereby issued as follows:
All workers of Delphi Steering, currently known as Nexteer Automotive, including on-site leased workers from Acro Services Corporation, Aerotek, Inc., Continental, Inc., Dynamic Corp., G-Tech Professional Staffing, Inc., Globaledge Technologies, Inc. (formerly Cae Tech), Gonzalez Contract Services, Integrated Partners Group LLC, Kelly Services, Manpower, Inc., Rapid Global Business Solutions, Inc., TAC Worldwide, Trialon Corp., Trison Business Solutions, Wright K Technologies, Interim Health Care, Bartech and Securitas, Saginaw, Michigan, who became totally or partially separated from employment on or after May 20, 2008 through July 14, 2011, and all workers in the group threatened with total or partial separation from employment on the date of certification through two years from the date of certification, are eligible to apply for adjustment assistance under Chapter 2 of Title II of the Trade Act of 1974, as amended.
In accordance with Section 223 of the Trade Act of 1974, as amended (“Act”), 19 U.S.C. 2273, the Department of Labor issued a Certification of Eligibility to Apply for Worker Adjustment Assistance on June 23, 2010, applicable to workers of Ingersoll-Rand, formerly known as Locknetics, Security Technologies Division, Bristol, Connecticut. The notice will be published soon in the
At the request of the State agency, the Department reviewed the certification for workers of the subject firm. The workers are engaged in the production of electronic security devices for commercial applications.
New information shows that workers leased from Monroe Staffing Services, Adecco USA, Inc., and Infinistaff, LLC, were employed at the Bristol, Connecticut location of Ingersoll-Rand/Harrow Products, Inc., formerly known as Locknetics, Security Technologies Division. The Department has determined that these workers were sufficiently under the control of Ingersoll-Rand, formerly known as Locknetics, Security Technologies Division to be considered leased workers.
Information also shows that Ingersoll-Rand purchased Harrow Products, Inc., in 1999, and as a result, some workers separated from employment at the subject firm had their wages reported under a separate unemployment insurance (UI) tax account under the name Harrow Products, Inc.
Accordingly, the Department is amending this certification to properly reflect these matters.
The intent of the Department's certification is to include all workers of the subject firm who were adversely affected by a shift in production of electronic security devices for commercial applications to Mexico.
The amended notice applicable to TA-W-73,396 is hereby issued as follows:
All workers of Ingersoll-Rand/Harrow Products, Inc., formerly known as Locknetics, Security Technologies Division including on-site leased workers from Monroe Staffing Services, Adecco USA, Inc., and Infinistaff, LLC, Bristol, Connecticut, who became totally or partially separated from employment on or after January 26, 2009 through June 23, 2012, and all workers in the group threatened with total or partial separation from employment on date of certification through two years from the date of certification, are eligible to apply for adjustment assistance under Chapter 2 of Title II of the Trade Act of 1974, as amended.
In accordance with Section 223 of the Trade Act of 1974, as amended (“Act”), 19 U.S.C. 2273, the Department of Labor issued a Certification of Eligibility to Apply for Worker Adjustment Assistance on February 4, 2010, applicable to workers of SKF Aeroengine Falconer, a subsidiary of AB SKF, including on-site leased workers from Manpower Professionals, Manpower, Inc. and Express Employment Professionals, Falconer, New York. The notice was published in the
At the request of the state, the Department reviewed the certification for workers of the subject firm. The workers are engaged in the production of precision ball and roller bearings.
The company reports that workers leased from HP Enterprise Services, were employed on-site at the Falconer, New York location of SKF Aeroengine Falconer, a subsidiary of AB SKF. The Department has determined that these workers were sufficiently under the control of the subject firm to be considered leased workers.
Based on these findings, the Department is amending this certification to include workers leased from HP Enterprise Services, working on-site at the Falconer, New York location of SKF Aeroengine Falconer, a subsidiary of AB SKF.
The amended notice applicable to TA-W-72,862 is hereby issued as follows:
All workers SKF Aeroengine Falconer, a subsidiary of AB SKF, including on-site leased workers from Manpower Professionals, Manpower, Inc., Express Employment Professionals and HP Enterprise Services, Falconer, New York, who became totally or partially separated from employment on or after November 8, 2008 through February 4, 2012, and all workers in the group threatened with total or partial separation from employment on the date of certification through two years from the date of certification, are eligible to apply for adjustment assistance under Chapter 2 of
In accordance with Section 223 of the Trade Act of 1974, as amended (19 U.S.C. 2273) the Department of Labor herein presents summaries of determinations regarding eligibility to apply for trade adjustment assistance for workers by (TA-W) number issued during the period of July 12, 2010 through July 16, 2010.
In order for an affirmative determination to be made for workers of a primary firm and a certification issued regarding eligibility to apply for worker adjustment assistance, each of the group eligibility requirements of Section 222(a) of the Act must be met.
I. Under Section 222(a)(2)(A), the following must be satisfied:
(1) A significant number or proportion of the workers in such workers' firm have become totally or partially separated, or are threatened to become totally or partially separated;
(2) The sales or production, or both, of such firm have decreased absolutely; and
(3) One of the following must be satisfied:
(A) Imports of articles or services like or directly competitive with articles produced or services supplied by such firm have increased;
(B) Imports of articles like or directly competitive with articles into which one or more component parts produced by such firm are directly incorporated, have increased;
(C) Imports of articles directly incorporating one or more component parts produced outside the United States that are like or directly competitive with imports of articles incorporating one or more component parts produced by such firm have increased;
(D) Imports of articles like or directly competitive with articles which are produced directly using services supplied by such firm, have increased; and
(4) the increase in imports contributed importantly to such workers' separation or threat of separation and to the decline in the sales or production of such firm; or
II. Section 222(a)(2)(B) all of the following must be satisfied:
(1) A significant number or proportion of the workers in such workers' firm have become totally or partially separated, or are threatened to become totally or partially separated;
(2) One of the following must be satisfied:
(A) There has been a shift by the workers' firm to a foreign country in the production of articles or supply of services like or directly competitive with those produced/supplied by the workers' firm;
(B) there has been an acquisition from a foreign country by the workers' firm of articles/services that are like or directly competitive with those produced/supplied by the workers' firm; and
(3) the shift/acquisition contributed importantly to the workers' separation or threat of separation.
In order for an affirmative determination to be made for adversely affected workers in public agencies and a certification issued regarding eligibility to apply for worker adjustment assistance, each of the group eligibility requirements of Section 222(b) of the Act must be met.
(1) a significant number or proportion of the workers in the public agency have become totally or partially separated, or are threatened to become totally or partially separated;
(2) The public agency has acquired from a foreign country services like or directly competitive with services which are supplied by such agency; and
(3) The acquisition of services contributed importantly to such workers' separation or threat of separation.
In order for an affirmative determination to be made for adversely affected secondary workers of a firm and a certification issued regarding eligibility to apply for worker adjustment assistance, each of the group eligibility requirements of Section 222(c) of the Act must be met.
(1) A significant number or proportion of the workers in the workers' firm have become totally or partially separated, or are threatened to become totally or partially separated;
(2) The workers' firm is a Supplier or Downstream Producer to a firm that employed a group of workers who received a certification of eligibility under Section 222(a) of the Act, and such supply or production is related to the article or service that was the basis for such certification; and
(3) Either—
(A) The workers' firm is a supplier and the component parts it supplied to the firm described in paragraph (2) accounted for at least 20 percent of the production or sales of the workers' firm; or
(B) A loss of business by the workers' firm with the firm described in paragraph (2) contributed importantly to the workers' separation or threat of separation.
In order for an affirmative determination to be made for adversely affected workers in firms identified by the International Trade Commission and a certification issued regarding eligibility to apply for worker adjustment assistance, each of the group eligibility requirements of Section 222(f) of the Act must be met.
(1) The workers' firm is publicly identified by name by the International Trade Commission as a member of a domestic industry in an investigation resulting in—
(A) An affirmative determination of serious injury or threat thereof under section 202(b)(1);
(B) An affirmative determination of market disruption or threat thereof under section 421(b)(1); or
(C) An affirmative final determination of material injury or threat thereof under section 705(b)(1)(A) or 735(b)(1)(A) of the Tariff Act of 1930 (19 U.S.C. 1671d(b)(1)(A) and 1673d(b)(1)(A));
(2) The petition is filed during the 1-year period beginning on the date on which—
(A) A summary of the report submitted to the President by the International Trade Commission under section 202(f)(1) with respect to the affirmative determination described in paragraph (1)(A) is published in the
(B) Notice of an affirmative determination described in subparagraph (1) is published in the
(3) The workers have become totally or partially separated from the workers' firm within—
(A) The 1-year period described in paragraph (2); or
(B) Notwithstanding section 223(b)(1), the 1-year period preceding the 1-year period described in paragraph (2).
The following certifications have been issued. The date following the company name and location of each determination references the impact
The following certifications have been issued. The requirements of Section 222(a)(2)(A) (increased imports) of the Trade Act have been met.
The following certifications have been issued. The requirements of Section 222(a)(2)(B) (shift in production or services) of the Trade Act have been met.
The following certifications have been issued. The requirements of Section 222(c) (supplier to a firm whose workers are certified eligible to apply for TAA) of the Trade Act have been met.
In the following cases, the investigation revealed that the eligibility criteria for worker adjustment assistance have not been met for the reasons specified.
The investigation revealed that the criterion under paragraph (a)(1), or (b)(1), or (c)(1) (employment decline or threat of separation) of section 222 has not been met.
The investigation revealed that the criteria under paragraphs (a)(2)(A) (increased imports) and (a)(2)(B) (shift in production or services to a foreign country) of section 222 have not been met.
After notice of the petitions was published in the
The following determinations terminating investigations were issued in cases where these petitions were not filed in accordance with the requirements of 29 CFR 90.11. Every petition filed by workers must be signed by at least three individuals of the petitioning worker group. Petitioners separated more than one year prior to the date of the petition cannot be covered under a certification of a petition under Section 223(b), and therefore, may not be part of a petitioning worker group. For one or more of these reasons, these petitions were deemed invalid.
The following determinations terminating investigations were issued because the petitioning groups of workers are covered by active certifications. Consequently, further investigation in these cases would serve no purpose since the petitioning group of workers cannot be covered by more than one certification at a time.
I hereby certify that the aforementioned determinations were issued during the period of July 12, 2010 through July 16, 2010. Copies of these determinations may be requested under the Freedom of Information Act. Requests may be submitted by fax, courier services, or mail to FOIA Disclosure Officer, Office of Trade Adjustment Assistance (ETA), U.S. Department of Labor, 200 Constitution Avenue, NW., Washington, DC 20210 or
Office of Disability Employment Policy, Department of Labor.
The U.S. Department of Labor (“DOL” or “Department”), Office of Disability Employment Policy (ODEP) announces the availability of approximately $2.3 million to fund up to four cooperative agreements with consortia ranging from $500,000 to $625,000. The objectives of this new initiative, Add Us In, are: (1) To increase the ability of targeted businesses to employ adults and youth with disabilities; (2) to develop and evaluate replicable models, strategies and policies that would ensure that youth and adults from targeted populations with disabilities have access to a broader range of employment and mentoring opportunities; and (3) to form and strengthen connections between targeted businesses, diversity-serving organizations, youth-serving organizations and disability-serving organizations, building a national and local network of experts skilled in serving individuals with disabilities. These objectives will be accomplished through the competitive funding of consortia tasked to design, implement, and evaluate innovative systems models that support integrated employment opportunities for people with disabilities within targeted businesses.
For the purposes of this solicitation, the
The full Solicitation for Grant Application is posted on
Petitions have been filed with the Secretary of Labor under Section 221(a) of the Trade Act of 1974 (“the Act”) and are identified in the Appendix to this notice. Upon receipt of these petitions, the Director of the Division of Trade Adjustment Assistance, Employment and Training Administration, has instituted investigations pursuant to Section 221(a) of the Act.
The purpose of each of the investigations is to determine whether the workers are eligible to apply for adjustment assistance under Title II, Chapter 2, of the Act. The investigations will further relate, as appropriate, to the determination of the date on which total or partial separations began or threatened to begin and the subdivision of the firm involved.
The petitioners or any other persons showing a substantial interest in the subject matter of the investigations may request a public hearing, provided such request is filed in writing with the Director, Division of Trade Adjustment Assistance, at the address shown below, not later than August 12, 2010.
Interested persons are invited to submit written comments regarding the subject matter of the investigations to the Director, Division of Trade Adjustment Assistance, at the address shown below, not later than August 12, 2010.
Copies of these petitions may be requested under the Freedom of Information Act. Requests may be submitted by fax, courier services, or mail, to FOIA Disclosure Officer, Office of Trade Adjustment Assistance (ETA), U.S. Department of Labor, 200 Constitution Avenue, NW., Washington, DC 20210 or to
On December 3, 2009, the Department issued an Affirmative Determination Regarding Application for Reconsideration for the workers and former workers of the subject firm. The Department's Notice of determination was published in the
The initial investigation resulted in a denial based on the findings that subject firm and customer imports of wood- and aluminum-clad windows and patio doors did not contribute to worker group separations and that the subject firm neither shifted to, nor acquired from, a foreign country the production of like or directly competitive articles.
In the request for reconsideration, the petitioners requested that additional customer surveys be conducted.
During the reconsideration investigation, the Department conducted a survey of six additional major declining customers of the subject firm regarding their purchases of wood- and aluminum-clad windows and patio doors during 2007, 2008, January through April 2008, and January through April 2009. The survey included one customer who accounted for 17 percent of the subject firm's total sales during 2007 and 2008, and another customer who accounted for 14 percent of the subject firm's total sales during January through May 2009. In total, the surveyed accounted for 91 percent of the decline in total subject firm sales from 2007 to 2008, and 20 percent of the decline in total subject firm sales during January through April 2009 as compared with the same four months in 2008.
The survey conducted during the reconsideration investigation revealed negligible customer imports of wood- and aluminum-clad windows and patio doors during 2007, 2008, and during January through April 2009.
After reconsideration, I affirm the original notice of negative determination of eligibility to apply for worker adjustment assistance for workers and former workers of Jeld-Wen, Inc., Hawkins Window Division, including on-site leased workers of Nicolet Staffing, Hawkins, Wisconsin.
Section 512 of the Employee Retirement Income Security Act of 1974 (ERISA), 88 Stat. 895, 29 U.S.C. 1142, provides for the establishment of an Advisory Council on Employee Welfare and Pension Benefit Plans (the Council), which is to consist of 15 members to be appointed by the Secretary of Labor (the Secretary) as follows: three representatives of employee organizations (at least one of whom shall be a representative of an organization whose members are participants in a multiemployer plan); three representatives of employers (at least one of whom shall be a representative of employers maintaining or contributing to multiemployer plans); one representative each from the fields of insurance, corporate trust, actuarial counseling, investment counseling, investment management, and accounting; and three representatives from the general public (one of whom shall be a person representing those receiving benefits from a pension plan). No more than eight members of the Council shall be members of the same political party.
Members shall be persons qualified to appraise the programs instituted under ERISA. Appointments are for terms of three years. The prescribed duties of the Council are to advise the Secretary with respect to the carrying out of his or her functions under ERISA, and to submit to the Secretary, or his or her designee, recommendations with respect thereto. The Council will meet at least four times each year.
The terms of five members of the Council expire on November 14, 2010. The groups or fields they represent are as follows: (1) Employee organizations (representing an organization whose members are participants in a multiemployer plan); (2) employers (representing employers maintaining or contributing to multiemployer plans); (3) accounting; (4) insurance; and (5) the general public. The Department of Labor is committed to equal opportunity in the workplace and seeks a broad-based and diverse ERISA Advisory Council.
Accordingly, notice is hereby given that any person or organization desiring to recommend one or more individuals for appointment to the Advisory Council on Employee Welfare and Pension Benefit Plans, to represent any of the groups or fields specified in the preceding paragraph, may submit recommendations to Larry Good, ERISA Advisory Council Executive Secretary, Frances Perkins Building, U.S. Department of Labor, 200 Constitution Avenue, NW., Suite N-5623, Washington, DC 20210, or to
Nominees will be contacted to provide information on their political affiliation and their status as registered lobbyists. Nominees should be aware of the time commitment for attending meetings and actively participating in the work of the Council. Historically, this has meant a commitment of 15-20 days per year.
Nuclear Regulatory Commission.
Notice of Issuance and Availability of Draft Regulatory Guide, DG-3030, “Nuclear Criticality Safety Standards for Fuels and Material Facilities.”
Tamara D. Powell, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001,
The U.S. Nuclear Regulatory Commission (NRC) is issuing for public comment a draft guide in the agency's “Regulatory Guide” series. This series was developed to describe and make available to the public such information as methods that are acceptable to the NRC staff for implementing specific parts of the NRC's regulations, techniques that the staff uses in evaluating specific problems or postulated accidents, and data that the staff needs in its review of applications for permits and licenses.
The draft regulatory guide (DG), entitled, “Nuclear Criticality Safety Standards for Fuels and Material Facilities,” is temporarily identified by its task number, DG-3030, which should be referenced in all related correspondence. DG-3030 is proposed Revision 2 of Regulatory Guide 3.71, dated October 2005.
Draft regulatory guide DG-3030 provides applicants, licensees and certificate holders with updated guidance concerning criticality safety standards that the U.S. Nuclear Regulatory Commission (NRC) has endorsed for use with nuclear fuels and material facilities. As such, DG-3030 describes methods that the NRC staff considers acceptable for complying with the NRC's regulations in Title 10, of the
Pursuant to 10 CFR 70.20, a specific license is required to acquire, deliver, receive, possess, use, transfer, import, or export special nuclear material, and applications for such licenses must, pursuant to 10 CFR 70.22(a)(8), include proposed procedures to avoid nuclear criticality accidents. Similarly, 10 CFR part 76 certificate holders are required by 10 CFR 76.87(c) to include in their technical safety requirements procedures and/or equipment that address criticality prevention.
The NRC staff has developed DG-3030 to provide guidance on complying with these portions of the NRC's regulations. DG-3030 describes procedures for preventing nuclear criticality accidents in operations that involve handling, processing, storing, and/or transporting special nuclear material at fuel and material facilities. DG-3030 endorses specific nuclear criticality safety standards developed by the American Nuclear Society's Standards Subcommittee 8 (ANS-8), “Operations with Fissionable Materials Outside Reactors.” DG-3030 is not intended for use by nuclear reactor licensees.
The NRC staff is soliciting comments on DG-3030. Comments may be accompanied by relevant information or supporting data and should mention DG-3030 in the subject line. Comments submitted in writing or in electronic form will be made available to the public in their entirety through the NRC's Agencywide Documents Access and Management System (ADAMS).
Because your comments will not be edited to remove any identifying or contact information, the NRC cautions you against including any information in your submission that you do not want to be publicly disclosed.
The NRC requests that any party soliciting or aggregating comments received from other persons for submission to the NRC inform those persons that the NRC will not edit their comments to remove any identifying or contact information, and therefore, they should not include any information in their comments that they do not want publicly disclosed. You may submit comments by any of the following methods:
1.
2.
3.
Comments would be most helpful if received by September 29, 2010. Comments received after that date will be considered if it is practical to do so, but the NRC is able to ensure consideration only for comments received on or before this date. Although a time limit is given, comments and suggestions in connection with items for inclusion in guides currently being developed or improvements in all published guides are encouraged at any time.
Requests for technical information about DG-3030 may be directed to the NRC contact, Tamara D. Powell at (301) 492-3211 or e-mail
Electronic copies of DG-3030 are available through the NRC's public Web site under Draft Regulatory Guides in the “Regulatory Guides” collection of the NRC's Electronic Reading Room at
In addition, regulatory guides are available for inspection at the NRC's Public Document Room (PDR) located at 11555 Rockville Pike, Rockville, Maryland. The PDR's mailing address is USNRC PDR, Washington, DC 20555-0001. The PDR can also be reached by telephone at (301) 415-4737 or (800) 397-4205, by fax at (301) 415-3548, and by e-mail to
Regulatory guides are not copyrighted, and Commission approval is not required to reproduce them.
For the Nuclear Regulatory Commission.
Nuclear Regulatory Commission (NRC).
Notice of Public Workshop.
The U.S. Nuclear Regulatory Commission (NRC) plans to conduct two public workshops to solicit public input on major issues associated with the development of a regulatory basis document that, if necessary, will form the basis of a potential rulemaking for spent nuclear fuel reprocessing facilities. The public workshops are intended to solicit the views of representatives of interests that may be affected by a potential rulemaking for reprocessing facilities. Members of the public are invited to provide written
Members of the public may provide feedback at the transcribed public workshops or may submit written comments on the issues discussed. The comment period closes on November 5, 2010. NRC plans to consider these stakeholder views in the development of a regulatory basis for a potential rulemaking on reprocessing. Written comments may be sent to the address listed in the
Submit written comments to the Cindy Bladey, Chief, Rules, Announcements, and Directives Branch, Division of Administrative Services, Office of Administration, U.S. Nuclear Regulatory Commission, Mail Stop TWB 5B01M, Washington, DC 20555-0001, and cite the publication date and page number of this
The NRC requests that any party soliciting or aggregating comments received from other persons for submission to the NRC inform those persons that the NRC will not edit their comments to remove any identifying or contact information, and therefore, they should not include any information in their comments that they do not want publicly disclosed.
Questions regarding participation in the roundtable discussions should be submitted to the facilitator, Francis Cameron, by telephone at 240-205-2091, or by e-mail at
Jose Cuadrado, Office of Nuclear Material Safety and Safeguards, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, telephone 301-492-3287; e-mail
The public may examine and have copied for a fee, publicly available documents at the Public Document Room, One White Flint North, 11555 Rockville Pike, Rockville, Maryland. Publicly available documents created or received at NRC after November 1, 1999, are available electronically at the NRC's Electronic Reading Room at
The NRC has the authority under the Atomic Energy Act to license commercial spent fuel reprocessing facilities. Currently, 10 CFR Part 50, “Domestic Licensing of Production and Utilization Facilities,” provides the licensing framework for production and utilization facilities. Although a reprocessing facility is one type of production facility, its industrial processes are more akin to fuel cycle processes. This framework was established in the 1970's to license the first US reprocessing facilities. The policy decision by the Carter Administration to cease reprocessing initiatives was based, in part, on the proliferation risks posed by the early reprocessing technology. This policy ultimately halted NRC licensing activities for commercial reprocessing facilities. While that policy was reversed during the Reagan Administration, there was no longer any commercial interest in reprocessing and thus no need to update the existing reprocessing regulatory framework in Part 50.
Although commercial reprocessing interest waned, the Department of Energy (DOE) continued to pursue reprocessing technology development through the National Laboratories. DOE has sought to decrease proliferation risk and spent fuel high level waste through developing more sophisticated reprocessing technology.
During the Bush Administration, the Global Nuclear Energy Partnership (GNEP) rekindled the interest in commercial reprocessing. GNEP sought to expand the use of civilian nuclear power globally and close the nuclear fuel cycle through reprocessing spent fuel and deploying fast reactors to burn long-lived actinides. In response to these initiatives, the Commission, in Staff Requirements Memorandum (SRM) to SECY-07-0081, “Regulatory Options for Licensing Facilities Associated with the Global Nuclear Energy Partnership,” dated June 27, 2007 (ADAMS ML071800084), directed the staff to complete an analysis of 10 CFR Chapter I to identify regulatory gaps for licensing an advanced reprocessing facility and recycling reactor.
In mid-2008, two nuclear industry companies informed the agency of their intent to seek a license for a reprocessing facility in the U.S. An additional company expressed its support for updating the regulatory framework for reprocessing, but stopped short of stating its intent to seek a license for such a facility. At the time, NRC staff also noted that progress on some Global Nuclear Energy Partnership (GNEP) initiatives had waned and it appeared appropriate to shift the focus of the staff's efforts from specific GNEP-facility regulations to a more broadly applicable framework for commercial reprocessing facilities.
In SECY-08-0134, titled, “Regulatory Structure for Spent Fuel Reprocessing,”
NRC staff performed a regulatory gap analysis and summarized it in SECY-09-0082, “Update on Reprocessing Regulatory Framework—Summary of Gap Analysis,” dated May 28, 2009 (ADAMS ML091520243). The staff's gap analysis identified 14 “high” priority gaps that must be resolved to establish an effective and efficient regulatory framework. The regulatory gaps broadly cover four main areas: (1) Reprocessing waste-related issues, (2) physical protection and material control and accounting, (3) risk, and (4) licensing issues. The NRC staff's regulatory gap analysis considered several documents in its analysis, including: NUREG-1909, a white paper authored by the Advisory Committee on Nuclear Waste and Materials (ACNW&M) titled “Background, Status and Issues Related to the Regulation of Advanced Spent Nuclear Fuel Recycle Facilities,” issued June 2008; correspondence from the Union of Concerned Scientists titled, “Revising the Rules for Materials Protection, Control and Accounting;” and an NEI white paper titled, “Regulatory Framework for an NRC Licensed Recycling Facility.”
Building on the gap analysis, efforts are currently underway to develop a regulatory (technical) basis to pursue rulemaking that would enable the effective licensing and regulation of reprocessing facilities. The status of the regulatory basis development and estimated schedule for completing the reprocessing regulatory development are summarized in a May 14, 2010, memorandum to the Commission (ADAMS ML101110444).
In advance of NRC staff's development of the regulatory basis document for reprocessing facility licensing, and, if necessary, a possible rulemaking, the NRC will conduct public workshops inviting representatives of interested stakeholders in a “roundtable” format. At these workshops, NRC plans to discuss with stakeholders the issues to be considered in the development of the regulatory basis document for reprocessing facility licensing, which, in turn, will serve as the basis for possible rulemaking. NRC plans to consider these stakeholder views in the development of the regulatory basis document. In order to have a manageable discussion, the number of participants around the table will be limited. The NRC, through the workshop facilitator, will attempt to ensure broad participation by the spectrum of interests affected by the rulemaking, including citizen and environmental groups, nuclear industry interests, state, and local governments, and experts from academia and other federal agencies. Other members of the public are welcome to attend. Those not seated at the tables, including individual members of the public, will have the opportunity to provide feedback on each of the issues slated for discussion by the roundtable participants. Questions about participation in the roundtable discussion may be directed to the facilitator.
Section 2.0 describes issues associated with the regulatory gaps in SECY-09-0082 and will broadly cover four main areas: (1) Reprocessing waste-related issues, (2) physical protection and material control and accounting, 3) risk, and (4) licensing issues.
During the public workshops, the NRC plans to solicit stakeholder comments and feedback during four separate discussion sessions. During each session, the NRC plans to discuss one of the four major categories of regulatory gaps for reprocessing facilities, as discussed in SECY-09-0082 (ADAMS ML091520243). The NRC will use a roundtable discussion format for all four discussion sessions. The four main categories of regulatory gaps are: (1) Reprocessing waste related gaps, (2) physical protection and material control and accounting gaps, (3) risk gaps, and (4) licensing gaps. Below is a brief discussion of the individual gaps in each category.
No independent waste storage options are available under 10 CFR Part 72, “Licensing Requirements for the Independent Storage of Spent Nuclear Fuel, High-Level Radioactive Waste, and Reactor-Related Greater Than Class C Waste,” to accommodate interim, commercial independent storage of solidified high-level waste (HLW) from reprocessing facilities. NRC staff is developing a technical basis to establish the regulatory framework necessary for both the onsite storage and commercial independent storage of solidified HLW. Without this basis, there are no viable regulatory options for interim storage of solidified HLW from reprocessing facilities.
The NRC lacks regulations defining certain waste streams resulting from spent fuel reprocessing as waste incidental to reprocessing, or incidental waste, rather than HLW. If the NRC does not develop an incidental waste rule, then an applicant for a reprocessing facility would face regulatory uncertainty with regard to differentiating HLW from incidental wastes produced at its facility.
The waste classification tables in 10 CFR 61.55 include many radionuclides that would be associated with reprocessing waste streams. However, a few waste streams that contain radionuclides (e.g., krypton-85 separated from gaseous effluent, noble metals and some lanthanides) were not considered in the development of 10 CFR 61.55, and are not listed in either Table 1 or Table 2. If the gap is not addressed, some wastes associated with reprocessing facilities could be classified as Class A, but they may not be suitable for near-surface disposal at some sites.
The waste confidence decision published in the
The regulation in 10 CFR 74.51, “Nuclear Material Control and Accounting for Strategic Special Nuclear Material,” currently excludes irradiated fuel reprocessing facilities from Category I material control and accounting (MC&A) requirements. Category I reprocessing facilities would not have the same MC&A requirements as other Category I facilities if the exclusion is not removed, yet comparable requirements may be needed to protect against theft and diversion of separated special nuclear material and other materials. Accordingly, it is necessary to remove this exclusion to ensure the security of material in any proposed Category I reprocessing facility.
The current type and quantity-based categorization scheme in the existing regulations may pose an undue regulatory burden in operating a reprocessing facility. Current requirements for facility processes and reprocessed fuel assemblies may result in excessive security and safeguards measures for relatively unattractive materials. Risk-informing 10 CFR Part 73, “Physical Protection of Plants and Materials,” and 10 CFR Part 74, “Material Control and Accounting of Special Nuclear Material,” is needed to prevent unintended consequences associated with a type and quantity-based material categorization scheme for potential materials resulting from a reprocessing operation.
There are no existing regulations for a diversion path analysis requirement under 10 CFR Part 74. Establishing diversion path analysis requirements would make 10 CFR Part 74 more risk-informed and would provide an effective detection and response program to mitigate potential safeguards vulnerabilities and system weaknesses. Under this requirement, affected reprocessing facilities would develop a more risk-informed safeguards program that considers a wide range of malevolent activities that might involve overt or covert adversaries. A burden would be imposed upon such facilities to conduct a diversion path analysis and address any identified vulnerability.
NRC staff is considering different changes and improvements to material inventory requirements for reprocessing facilities. Currently, 10 CFR 74.59(f) gives predefined quantity limits and timeliness requirements for Category I facilities, which must perform physical inventories every 6 months. Predefined limits on inventory difference determinations and the restriction on inventory periods could pose a regulatory challenge for reprocessing facilities, due to their large throughputs and inventories. Modern technology that has been developed or is being developed will help reprocessing facilities to meet the existing timeliness and quantity goals. Improved technology, such as near real time accounting, has been used at certain overseas reprocessing plants. This and other technologies can provide a more frequent inventory analysis without a facility shut-down, and will facilitate meeting the current timeliness and quantity goals. Additionally, incorporating a material holdup management program requirement into 10 CFR Part 74 to minimize the impact of material holdup could facilitate more accurate inventory accounting.
Certain fissile elements such as americium (Am), neptunium (Np), and others, which are constituents of spent nuclear fuel, are currently not regulated or treated as other fissile or SNM material. Some advanced fuel cycle separation methods have the ability to separate these actinides, resulting in separated and pure fissile products. However, existing regulations do not address security risks for these types of fissile material. Although such advanced fuel cycle separation methods are not industrially mature and are still being researched, if advanced fuel cycles that separate these fissile elements receive commercial interest, the Commission may consider revisiting its policy of excluding these elements as SNM.
Reprocessing facilities handle larger amounts of radioactive material than other fuel cycle facilities. These higher amounts increase the relative risk of these facilities. The NRC revised 10 CFR Part 70 in 2000 based on a limited number of lower risk fuel cycle facilities, and the revision did not consider higher risk reprocessing facilities. These higher risks are not adequately addressed in the methodology established in 10 CFR Part 70. Therefore, if left unchanged, the requirements for reprocessing facilities licensed under 10 CFR Part 70 will be the same as those for the lower risk fuel cycle facilities. The NRC is considering various qualitative and quantitative approaches for establishing new risk assessment requirements for reprocessing facilities.
The existing baseline design criteria (BDC) in 10 CFR Part 70 do not comprehensively address hazards posed by the operation of a reprocessing facility. Although Appendix A, “General Design Criteria for Nuclear Power Plants,” to 10 CFR Part 50 provides general design criteria (GDC) for nuclear power plants, none of these GDC are specific to reprocessing facilities. The regulations in 10 CFR Part 70 have a few BDC directed more toward lower risk fuel cycle facilities. The NRC will consider multiple sources in establishing appropriate BDC or GDC for reprocessing facilities. The NRC will use the terms BDC and GDC interchangeably during its discussions.
The provisions of 10 CFR Part 50 require technical specifications for reprocessing facilities. Such requirements may not be compatible with 10 CFR Part 70. For incorporation into 10 CFR Part 70, revisions will be needed to clarify the division between items relied on for safety (IROFS), which are derived from an integrated safety analysis (ISA), and technical specifications. Additionally, changes to technical specifications would require a license amendment, whereas similar changes under 10 CFR Part 70 licensed facilities could proceed under the facility change process in 10 CFR 70.72, “Facility Changes and Change Process,” if the changes meet these requirements.
Section 107 of the Atomic Energy Act of 1954, as amended, (AEA) requires production facilities to have licensed operators. However, the current criteria in 10 CFR Part 55, “Operators'
The requirements of 10 CFR Part 70 do not sufficiently address effluent controls and monitoring for reprocessing facilities [e.g., implementation of EPA regulations in 40 CFR Part 190, as required by 10 CFR 20.1301(e)]. Additional requirements for effluent controls and monitoring may be needed for reprocessing facilities because of the amounts of radioactive material that are handled in them and greater potential for emissions. Although the regulations in 10 CFR 50.34a, “Design Objectives for Equipment To Control Releases of Radioactive Material in Effluents—Nuclear Power Plants,” and 10 CFR 50.36a, “Technical Specifications on Effluents from Nuclear Power Reactors,” specify requirements for utilization facilities, these would require modification to address reprocessing and recycling facilities.
Currently, licensing a reprocessing facility under 10 CFR Part 50 would pose a significant hindrance to effective and efficient licensing. The regulations in 10 CFR Part 70, as currently written, do not provide a regulatory framework to license a reprocessing facility. Therefore, the staff is evaluating options for either revising Part 50 or Part 70, or develop regulations in a new Part 5X, or Part 7X.
There are currently no definitions of the terms “reprocessing,” “recycling,” and “vitrification.” Existing regulations in 10 CFR Parts 20, 50, 51, 60, 63, 70 and 72 use the term “reprocessing” without a definition. Accordingly, such definitions will need to be developed to describe both reprocessing and reprocessing facilities for 10 CFR Chapter I.
Currently, regulations for one-step licensing of reprocessing facilities do not exist. One-step licensing necessitates requirements to verify that the constructed facility conforms to the approved, licensed design. For reactors, 10 CFR Part 52 identifies these requirements as ITAAC. The regulations in 10 CFR Part 52 do not apply to reprocessing or other production facilities, nor do the requirements for the approval of applications set forth in 10 CFR 70.23, “Requirements for the Approval of Applications,” address reprocessing facilities. Clarity is needed in 10 CFR Part 70 to provide reasonable assurance that a reprocessing facility, undergoing a one-step licensing process, will have been constructed and will operate in conformity with the license, the AEA, and the Commission's rules and regulations.
A reprocessing facility cannot be licensed without financial protection and indemnity agreements. Price Anderson protection and indemnity fees and amounts for reprocessing facilities are currently not included in 10 CFR Part 140, “Financial Protection Requirements and Indemnity Agreements.” Additionally, several appendices to 10 CFR Part 140 do not include forms for reprocessing facilities.
The scope of 10 CFR Part 170, “Fees for Facilities, Materials, Import and Export Licenses, and Other Regulatory Services under the Atomic Energy Act of 1954, as Amended,” does not include a production facility licensed outside 10 CFR Part 50.
The regulations in 10 CFR Part 171, “Annual Fees for Reactor Licenses and Fuel Cycle Licenses and Materials Licenses, Including Holders of Certificates of Compliance, Registrations, and Quality Assurance Program Approvals and Government Agencies Licensed by the NRC,” do not include annual fees for reprocessing facility licenses. The scope of the regulation, described in 10 CFR 171.3, does not specifically include reprocessing or production facilities.
For the Nuclear Regulatory Commission.
Nuclear Regulatory Commission.
Notice of Issuance and Availability of Regulatory Guide 3.13, Revision 1, “Design, Construction, and Inspection of Embankment Retention Systems at Fuel Cycle Facilities.”
Mark Orr, Regulatory Guide Development Branch, Division of Engineering, Office of Nuclear Regulatory Research, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, telephone (301) 251-7495 or e-mail
The U.S. Nuclear Regulatory Commission (NRC) is issuing a revision to an existing guide in the agency's “Regulatory Guide” series. This series was developed to describe and make available to the public information such as methods that are acceptable to the NRC staff for implementing specific parts of the agency's regulations, techniques that the staff uses in evaluating specific problems or postulated accidents, and data that the staff needs in its review of applications for permits and licenses.
Revision 1 of Regulatory Guide 3.13, “Design, Construction, and Inspection of Embankment Retention Systems at Fuel Cycle Facilities,” was issued with a temporary identification as Draft Regulatory Guide, DG-3040. This guide describes some engineering practices and methods generally considered by the NRC to be satisfactory for the design, construction, and inspection of embankment retention systems used for retaining solid and liquid effluent from nuclear fuel cycle facility operations other than mining and milling. These practices and methods are the result of NRC review and action on a number of specific cases, and they reflect the latest general engineering approaches that are acceptable to the NRC staff. If future information results in alternative
The NRC recognizes the need for significant revision of this guide to address newer technology and environmental considerations. The NRC is revising this guidance to provide regulatory recommendations and positions that focus on more modern designs with perimeter embankments.
In February 2010, DG-3040 was published with a public comment period of 60 days from the issuance of the guide. No comments were received and the public comment period closed on April 30, 2010. Electronic copies of Regulatory Guide 3.13, Revision 1 are available through the NRC's public Web site under “Regulatory Guides” at
In addition, regulatory guides are available for inspection at the NRC's Public Document Room (PDR) located at Room O-1F21, One White Flint North, 11555 Rockville Pike, Rockville, Maryland 20852-2738. The PDR's mailing address is USNRC PDR, Washington, DC 20555-0001. The PDR can also be reached by telephone at (301) 415-4737 or (800) 397-4209, by fax at (301) 415-3548, and by e-mail to
Regulatory guides are not copyrighted, and NRC approval is not required to reproduce them.
For the Nuclear Regulatory Commission.
Nuclear Regulatory Commission.
Withdrawal of Regulatory Guide 3.44, “Standard Format and Content for the Safety Analysis Report for an Independent Spent Fuel Storage Installation (Water-Basin Type)” and Regulatory Guide 3.49, “Design of an Independent Spent Fuel Storage Installation (Water-Basin Type).”
Mark P. Orr, Regulatory Guide Development Branch, Division of Engineering, Office of Nuclear Regulatory Research, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001,
The U.S. Nuclear Regulatory Commission (NRC) is withdrawing Regulatory Guide (RG) 3.44, “Standard Format and Content for the Safety Analysis Report for an Independent Spent Fuel Storage Installation (Water-Basin Type),” dated January 1989 and RG 3.49, “Design of an Independent Spent Fuel Storage Installation (Water-Basin Type),” dated December 1981.
Regulatory Guide 3.44 provides guidance to applicants on the format and content of the safety analysis report that is required as part of an application to construct or operate a water-basin type in an independent spent fuel storage installation (ISFSI). Regulatory Guide 3.49 endorses portions of the American National Standards Institute (ANSI), American Nuclear Society (ANS) standard ANSI/ANS 57.7-1981, “Design Criteria for an Independent Spent Fuel Storage Installation (Water-Pool Type),” with exceptions and supplements, as an acceptable method of complying with the requirements of Subpart F, “General Design Criteria” of Title 10, of the
These guides do not support any active license or application; they were developed to provide guidance on the facility design and application to construct and operate a water-basin type ISFSI. The NRC has no record of either of these regulatory guides ever being used in the 20 years since they were published and no indication that any applicant or licensee is planning to submit an application for the construction and/or operation of a water-basin type ISFSI.
These guides for wet basin storage are no longer necessary because the use of dry cask storage for ISFSIs has proven to be superior to wet basin storage and, in the event that there is an industry initiative to reprocess spent fuel, any wet basin storage operation associated with the reprocessing will likely be licensed as an integral part of the reprocessing facility, rather than as an ISFSI.
The withdrawal of RG 3.44 and RG 3.49 does not alter any prior or existing licensing commitments based on their use. The guidance provided in these regulatory guides is no longer necessary. Regulatory guides may be withdrawn when their guidance no longer provides useful information, or is superseded by technological, congressional actions, or other events.
Guides are revised for a variety of reasons, and the withdrawal of a regulatory guide should be thought of as the final revision of the guide. Although a regulatory guide is withdrawn, current licensees may continue to use it, and withdrawal does not affect any existing licenses or agreements. Withdrawal means that the guide should not be used for future NRC licensing activities. Changes to existing licenses would be accomplished using other regulatory products.
Regulatory guides are available for inspection or downloading through the NRC's public Web site under “Regulatory Guides” in the NRC's Electronic Reading Room at
Regulatory guides are not copyrighted, and NRC approval is not required to reproduce them.
For the Nuclear Regulatory Commission.
Nuclear Regulatory Commission.
Notice of Issuance and Availability of Regulatory Guide 1.151, Revision 1, “Instrument Sensing Lines.”
Karl J. Sturzebecher, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, telephone (301) 251-7494 or e-mail
The U.S. Nuclear Regulatory Commission (NRC) is issuing a revision to an existing guide in the agency's “Regulatory Guide” series. This series was developed to describe and make available to the public information such as methods that are acceptable to the NRC staff for implementing specific parts of the agency's regulations, techniques that the staff uses in evaluating specific problems or postulated accidents, and data that the staff needs in its review of applications for permits and licenses.
Revision 1 of Regulatory Guide 1.151 was issued with a temporary identification as Draft Regulatory Guide, DG-1178. This guide describes a method that the staff of the NRC considers acceptable for use in complying with the agency's regulations with respect to the design and installation of safety-related instrument sensing lines in nuclear power plants. To meet these objectives, the sensing lines must serve a safety-related function to prevent the release of reactor coolant as a part of the reactor coolant pressure boundary and to provide adequate connections to the reactor coolant system for measuring process variables (
In December 2008, DG-1178 was published with a public comment period of 60 days from the issuance of the guide. The public comment period closed on February 6, 2009. The staff's responses to the comments received are located in the NRC's Agencywide Documents Access and Management System (ADAMS) under Accession No. ML092330222. The regulatory analysis may be found in ADAMS under Accession No. ML102040145. Electronic copies of Regulatory Guide 1.151, Revision 1 are available through the NRC's public Web site under “Regulatory Guides” at
In addition, regulatory guides are available for inspection at the NRC's Public Document Room (PDR) located at Room O-1F21, One White Flint North, 11555 Rockville Pike, Rockville, Maryland 20852-2738. The PDR's mailing address is USNRC PDR, Washington, DC 20555-0001. The PDR can also be reached by telephone at (301) 415-4737 or (800) 397-4209, by fax at (301) 415-3548, and by e-mail to
Regulatory guides are not copyrighted, and NRC approval is not required to reproduce them.
For the Nuclear Regulatory Commission.
U.S. Office of Personnel Management.
Notice.
The Office of Personnel Management (OPM), Employee Services proposes to add an Equal Employment Opportunity Commission (EEOC) form, Demographic Information on Applicants, OMB No. 3046-0046, which is already approved by Office of Management and Budget (OMB), to USAJOBS® in order to collect the information requested by the form in a central location for the Federal government. Completion of the form by applicants is voluntary. For those who choose to complete the form, however, the collection of the information through USAJOBS will be convenient for the applicant as well as the agency. Additionally, it is consistent with the announced purpose of the form—to assist Federal agencies in reassessing and improving their efforts to reach all segments of the population through their recruitment processes. The collection of data through this form also can be used by Federal agencies, along with other demographic information, as part of their organizational self-analyses to determine whether barriers exist that might exclude certain groups. No individual personnel selections will be made based on this information as the information must be kept separate from the application.
This change will become effective without further notice on September 1, 2010.
U.S. Office of Personnel Management, Employment Services, USAJOBS, 1900 E. Street, NW., Washington, DC 20415, Attention: Patricia Stevens or sent via electronic mail to
U.S. Office of Personnel Management, Employment Services, USAJOBS, 1900 E. Street, NW., Washington, DC 20415, Attention: Patricia Stevens or sent via electronic mail to
11 a.m., Wednesday, August 4, 2010.
The date of the meeting has been changed to Tuesday, August 3, 2010.
Stephen L. Sharfman, General Counsel,
Postal Regulatory Commission.
Notice.
The Commission is noticing a recently-filed Postal Service request to add Global Expedited Package Services—Non-published Rates to the competitive product list. The Postal Service has also filed a related contract. This notice addresses procedural steps associated with the filing.
Comments are due: August 11, 2010. Reply Comments are due: August 18, 2010.
Submit comments electronically via the Commission's Filing Online system at
Stephen L. Sharfman, General Counsel,
On July 16, 2010, the Postal Service requested that the Commission add Global Expedited Package Services—Non-published Rates to the competitive product list within the Mail Classification Schedule (MCS).
The primary difference between GEPS and GEPS—Non-published Rates is that the Governors have approved an eight-tiered rate design model that includes every possible rate between a minimum and maximum rate within cells defined by country group and weight.
The purpose of GEPS—Non-published Rates is to streamline the “process for approving GEPS agreements, while maintaining their profitability and competitive positioning in the market.”
The number of [GEPS] agreements continues to grow, and the number of renewing customers is substantial. Because the agreements typically have a term of one year, the transaction costs for developing the pricing and filing each agreement as a separate product are substantial as well. The resources of the Commission are also affected by these agreements, as the Commission and a Public Representative must review each agreement and its rates prior to determining the functional equivalence of the agreement under review in comparison to the baseline GEPS agreement.
The Postal Service further indicates that if the proposal is approved as a niche classification, “the filing of each mailer's agreement to be added to the competitive product list would no longer be necessary.”
Included with the Request are several attachments. Attachment 1 is an application for non-public treatment of portions of the Request. Attachment 2 contains the Governors' Decision and attachments thereto, including MCS language describing GEPS—Non-published Rates, rate schedules, a management analysis, and certification that prices satisfy applicable pricing criteria. Attachment 3 is a Statement of Justification by the Executive Director, Global Business Management. Attachment 4 is a representative agreement between the Postal Service and a customer of GEPS—Non-published Rates.
1. The Commission establishes Docket Nos. MC2010-29 and CP2010-72 to consider matters raised in the Postal Service's July 16, 2010 Request.
2. Comments are due August 11, 2010. Reply comments are due August 18, 2010.
3. Pursuant to 39 U.S.C. 505, the Commission appoints Steven M. Hoffer to represent the interests of the general public in this proceeding.
4. The Secretary shall arrange for publication of this order in the
By the Commission.
Postal Regulatory Commission.
Notice.
The Commission is noticing a recently-filed Postal Service request to add six Global Expedited Package Services 3 (GEPS 3) contracts to the competitive product list. This notice addresses procedural steps associated with the filing.
Comments are due: August 4, 2010.
Submit comments electronically via the Commission's
Stephen L. Sharfman, General Counsel,
On July 26, 2010, the Postal Service filed a notice announcing that it has entered into six additional Global Expedited Package Services 3 (GEPS 3) contracts.
In support of its Notice, the Postal Service filed four attachments as follows:
• Attachments 1A, 1B, 1C, 1D, 1E and 1F—redacted copies of the six contracts and applicable annexes;
• Attachments 2A, 2B, 2C, 2D, 2E and 2F—a certified statement required by 39 CFR 3015.5(c)(2) for each of the six contracts;
• Attachment 3—a redacted copy of Governors' Decision No. 08-7 which establishes prices and classifications for GEPS contracts, a description of applicable GEPS contracts, formulas for prices, an analysis and certification of the formulas and certification of the Governors' vote; and
• Attachment 4—an application for non-public treatment of materials to maintain redacted portions of the contracts and supporting documents under seal.
The Notice advances reasons why the instant GEPS 3 contracts fit within the Mail Classification Schedule language for GEPS. The Postal Service identifies customer-specific information and general contract terms that distinguish the instant contracts from the baseline GEPS 3 agreement all of which are highlighted in the Notice.
The Postal Service contends that the instant contracts are functionally equivalent to the baseline contract for GEPS 3 and share the same cost and market characteristics as the previously filed GEPS contracts.
The Postal Service concludes that its filings demonstrate that each of the new GEPS 3 contracts complies with the requirements of 39 U.S.C. 3633 and is functionally equivalent to the baseline GEPS 3 contract. Therefore, it requests that the instant contracts be included within the GEPS 3 product.
The Commission establishes Docket Nos. CP2010-78, CP2010-79, CP2010-80, CP2010-81, CP2010-82 and CP2010-83 for consideration of matters related to the contracts identified in the Postal Service's Notice.
These dockets are addressed on a consolidated basis for purposes of this order. Filings with respect to a particular contract should be filed in that docket.
Interested persons may submit comments on whether the Postal Service's contracts are consistent with the policies of 39 U.S.C. 3632, 3633 or 3642. Comments are due no later than August 4, 2010. The public portions of these filings can be accessed via the Commission's Web site (
The Commission appoints Paul L. Harrington to serve as Public Representative in the captioned proceedings.
1. The Commission establishes Docket Nos. CP2010-78, CP2010-79, CP2010-80, CP2010-81, CP2010-82 and CP2010-83 for consideration of matters raised by the Postal Service's Notice.
2. Comments by interested persons in these proceedings are due no later than August 4, 2010.
3. Pursuant to 39 U.S.C. 505, Paul L. Harrington is appointed to serve as the officer of the Commission (Public Representative) to represent the interests of the general public in these proceedings.
4. The Secretary shall arrange for publication of this order in the
By the Commission.
Postal Regulatory Commission.
Notice.
The Commission is noticing a recently-filed Postal Service request to add two additional Global Expedited Package Services 3 contracts to the competitive product list. This notice addresses procedural steps associated with the filing.
Comments are due: July 29, 2010.
Submit comments electronically via the Commission's
Stephen L. Sharfman, General Counsel,
On July 20, 2010, the Postal Service filed a notice announcing that it has entered into two additional Global Expedited Package Services 3 (GEPS 3) contracts.
In support of its Notice, the Postal Service filed four attachments as follows:
• Attachments 1A and 1B—redacted copies of the two contracts and applicable annexes;
• Attachments 2A and 2B—a certified statement required by 39 CFR 3015.5(c)(2) for each contract;
• Attachment 3—a redacted copy of Governors' Decision No. 08-7 which establishes prices and classifications for GEPS contracts, a description of applicable GEPS contracts, formulas for prices, an analysis and certification of the formulas and certification of the Governors' vote; and
• Attachment 4—an application for non-public treatment of materials to maintain redacted portions of the contracts and supporting documents under seal.
The Notice advances reasons why the instant GEPS 3 contracts fit within the Mail Classification Schedule language for GEPS. The Postal Service identifies customer-specific information and general contract terms that distinguish the instant contracts from the baseline GEPS 3 agreement all of which are highlighted in the Notice.
The Postal Service contends that the instant contracts are functionally equivalent to the baseline contract for GEPS 3 and share the same cost and market characteristics as the previously filed GEPS contracts.
The Postal Service also contends that its filings demonstrate that each of the new GEPS 3 contracts complies with the requirements of 39 U.S.C. 3633. It requests that the contracts be included within the GEPS 3 product.
The Commission establishes Docket Nos. CP2010-73 and CP2010-74 for consideration of matters related to the contracts identified in the Postal Service's Notice.
These dockets are addressed on a consolidated basis for purposes of this order. Filings with respect to a particular contract should be filed in that docket.
Interested persons may submit comments on whether the Postal Service's contracts are consistent with the policies of 39 U.S.C. 3632, 3633 or 3642. Comments are due no later than July 29, 2010. The public portions of these filings can be accessed via the Commission's Web site (
The Commission appoints Paul L. Harrington to serve as Public Representative in the captioned proceedings.
1. The Commission establishes Docket Nos. CP2010-73 and CP2010-74 for consideration of matters raised by the Postal Service's Notice.
2. Comments by interested persons in these proceedings are due no later than July 29, 2010.
3. Pursuant to 39 U.S.C. 505, Paul L. Harrington is appointed to serve as officer of the Commission (Public Representative) to represent the interests of the general public in these proceedings.
4. The Secretary shall arrange for publication of this order in the
By the Commission.
Postal Regulatory Commission.
Notice.
The Commission is noticing a recently-filed Postal Service request to add Priority Mail Contract 25 to the competitive product list. The Postal Service has also filed a related contract. This notice addresses procedural steps associated with the filing.
Comments are due: August 2, 2010.
Submit comments electronically via the Commission's Filing Online system at
Stephen L. Sharfman, General Counsel,
Pursuant to 39 U.S.C. 3642 and 39 CFR 3020.30
The Postal Service contemporaneously filed a contract related to the proposed new product pursuant to 39 U.S.C. 3632(b)(3) and 39 CFR 3015.5. The contract has been assigned Docket No. CP2010-75.
• Attachment A—a redacted copy of the Governor's Decision No. 09-6, originally filed in Docket No. MC2009-25, authorizing certain Priority Mail contracts;
• Attachment B—a redacted copy of the contract;
• Attachment C—a proposed change in the Mail Classification Schedule competitive product list;
• Attachment D—a Statement of Supporting Justification as required by 39 CFR 3020.32;
• Attachment E—a certification of compliance with 39 U.S.C. 3633(a); and
• Attachment F—an application for non-public treatment of materials to maintain redacted portions of the contract and supporting document under seal.
In the Statement of Supporting Justification, Brian G. Denneny, Acting Manager, Sales and Communication, Expedited Shipping, asserts that the service to be provided under the contract will cover its attributable costs, make a positive contribution to institutional costs, and increase contribution toward the requisite 5.5 percent of the Postal Service's total institutional costs.
The Postal Service filed much of the supporting materials, including the specific Priority Mail Contract 25, under seal. It maintains that the contract and related financial information, including the customer's name and the accompanying analyses that provide prices, terms, conditions, cost data, and financial projections should remain under seal.
The Commission establishes Docket Nos. MC2010-30 and CP2010-75 for consideration of the Request pertaining to the proposed Priority Mail Contract 25 product and the related contract, respectively. In keeping with practice, these dockets are addressed on a consolidated basis for purposes of this order. However, future filings should be made in the specific docket in which issues being addressed pertain.
Interested persons may submit comments on whether the Postal Service's filings in the captioned dockets are consistent with the policies of 39 U.S.C. 3632, 3633, or 3642 and 39 CFR part 3015 and 39 CFR 3020, subpart B. Comments are due no later than August 2, 2010. The public portions of these filings can be accessed via the Commission's Web site (
The Commission appoints Paul L. Harrington to serve as Public Representative in these dockets.
1. The Commission establishes Docket Nos. MC2010-30 and CP2010-75 for consideration of the matter raised in each docket.
2. Pursuant to 39 U.S.C. 505, Paul L. Harrington is appointed to serve as officer of the Commission (Public Representative) to represent the interests of the general public in these proceedings.
3. Comments by interested persons in these proceedings are due no later than August 2, 2010.
4. The Secretary shall arrange for publication of this order in the
By the Commission.
U.S. Small Business Administration.
Notice.
This is a Notice of the Presidential declaration of a major disaster for the Commonwealth of Kentucky (FEMA-1925-DR), dated 07/23/2010.
Submit completed loan applications to: U.S. Small Business Administration, Processing And Disbursement Center, 14925 Kingsport Road, Fort Worth, TX 76155.
A. Escobar, Office of Disaster Assistance, U.S. Small Business Administration, 409 3rd Street, SW., Suite 6050, Washington, DC 20416
Notice is hereby given that as a result of the
The following areas have been determined to be adversely affected by the disaster:
The Interest Rates are:
The number assigned to this disaster for physical damage is 12242B and for economic injury is 122430.
U.S. Small Business Administration.
Notice.
This is a Notice of the Presidential declaration of a major disaster for Public Assistance Only for the Commonwealth of KENTUCKY (FEMA-1925-DR), dated 07/23/2010.
Submit completed loan applications to: U.S. Small Business Administration, Processing and Disbursement Center, 14925 Kingsport Road, Fort Worth, TX 76155.
A. Escobar, Office of Disaster Assistance, U.S. Small Business Administration, 409 3rd Street, SW., Suite 6050, Washington, DC 20416.
Notice is hereby given that as a result of the President's major disaster declaration on 07/23/2010, Private Non-Profit organizations that provide essential services of governmental nature may file disaster loan applications at the address listed above or other locally announced locations.
The following areas have been determined to be adversely affected by the disaster:
The number assigned to this disaster for physical damage is 12244B and for economic injury is 12245B.
Notice is hereby given that Escalate Capital Partners SBIC I, L.P., 300 W. 6th Street, Suite 2250, Austin, TX 78701, a Federal Licensee under the Small Business Investment Act of 1958, as amended (“the Act”), in connection with the financing of a small concern, has sought an exemption under Section 312 of the Act and Section 107.730, Financings which Constitute Conflicts of Interest of the Small Business Administration (“SBA”) Rules and Regulations (13 CFR 107.730). Escalate Capital Partners SBIC I, L.P. proposes to provide equity financing to Century Payments, Inc. (“Century”), 2601 Network Boulevard, Frisco, TX 75034. The financing is contemplated to fund the ongoing operating needs of the business.
The financing is brought within the purview of § 107.730(a)(1) of the Regulations because AV-EC Partners I, L.P., is an Associate of Escalate Capital Partners SBIC I, L.P., owns more than ten percent of Century, and therefore Century is considered an Associate of Escalate Capital Partners SBIC I, L.P. as detailed in § 107.50 of the Regulations.
Notice is hereby given that any interested person may submit written comments on the transaction to the Associate Administrator for Investment, U.S. Small Business Administration, 409 Third Street, SW., Washington, DC 20416.
Notice is hereby given that, pursuant to the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
The title for the collection of information is “Rule 204A-1 (17 CFR 275.204A-1) under the Investment Advisers Act of 1940” (15 U.S.C.
The purposes of the information collection requirements is: (i) To ensure that advisers maintain codes of ethics applicable to their supervised persons; (ii) to provide advisers with information about the personal securities transactions of their access persons for purposes of monitoring such transactions; (iii) to provide advisory clients with information with which to evaluate advisers' codes of ethics; and (iv) to assist the Commission's examination staff in assessing the adequacy of advisers' codes of ethics and assessing personal trading activity by advisers' supervised persons.
The respondents to this information collection are investment advisers registered with the Commission. The Commission has estimated that compliance with rule 204A-1 imposes a burden of approximately 118 hours per adviser annually for an estimated total annual burden of 1,391,456 hours.
An agency may not conduct or sponsor, and a person is not required to respond to a collection of information unless it displays a currently valid control number.
Please direct your written comments to Charles Boucher, Director/CIO, Securities and Exchange Commission, C/O Shirley Martinson, 6432 General Green Way, Alexandria, VA 22312; or send an e-mail to:
Securities and Exchange Commission (“Commission”).
Notice of application to amend a prior order under section 12(d)(1)(J) of the Investment Company Act of 1940 (“Act”) for an exemption from sections 12(d)(1)(A) and (B) of the Act and under sections 6(c) and 17(b) of the Act for an exemption from section 17(a) of the Act.
Secretary, U.S. Securities and Exchange Commission, 100 F Street, NE., Washington, DC 20549-1090; Applicants, c/o Kevin J. Carr, Esq., Virtus Investment Advisers, Inc., 100 Pearl Street, Hartford, CT 06103.
Emerson S. Davis, Sr., Senior Counsel, at (202) 551-6868, or Julia Kim Gilmer, Branch Chief, at (202) 551-6821 (Division of Investment Management, Office of Investment Company Regulation).
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 Trust is a Delaware statutory trust registered as an open-end management investment company under the Act, and currently offers
2. The Prior Order permits Funds (each a “Fund of Funds”) to invest in: (a) Other Funds in the same group of investment companies as the Fund of Funds (“Affiliated Funds”); and/or (b) registered open-end management investment companies (“Unaffiliated Management Companies”) and UITs (“Unaffiliated Trusts”) that are not part of the “same group of investment companies” as defined in Section 12(d)(1)(G)(ii) of the Act as the Fund of Funds (“Unaffiliated Funds,” and together with the Affiliated Funds, the “Underlying Funds”). The Prior Order also permits the Underlying Funds, their principal underwriters, and any broker or dealer registered under the Securities Exchange Act of 1934 (“Exchange Act”) to sell shares of an Underlying Fund to a Fund of Funds. Certain of the Unaffiliated Funds may be “exchange-traded funds” that are registered under the Act as UITs or open-end management investment companies and have received exemptive relief to sell their shares on a national securities exchange at negotiated prices (“ETFs”). Any investment adviser to a Fund of Funds that meets the definition of section 2(a)(20)(A) of the Act is referred to as a “Manager.”
3. The Amended Order would amend and supersede the Prior Order by deleting condition 2, which prohibited a Fund of Funds or its Manager, sub-adviser, promoter, principal underwriter and any person controlling, controlled by or under common control with any of these entities (each, a “Fund of Funds Affiliate”) from receiving from an Unaffiliated Fund or its investment adviser(s), sponsor, promoter, principal underwriter and any person controlling, controlled by or under common control with any of these entities (each, an “Unaffiliated Fund Affiliate”) any consideration in connection with any services, transactions or the investment by the Fund of Funds in the Unaffiliated Fund. The Amended Order will subject applicants to certain other conditions governing the payment of such consideration consistent with recent Commission precedent.
4. Each Fund of Funds may also make investments in securities or instruments that are not issued by registered investment companies and that are consistent with its investment objective, including money market instruments. Applicants state that the requested relief will provide an efficient and simple method of allowing investors to create a comprehensive asset allocation program.
1. Section 12(d)(1)(A) of the Act 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 or dealer from selling the shares of the investment company to another investment company if the sale will cause the acquiring company to own more than 3% of the acquired company's voting stock, or if the sale will cause more than 10% of the acquired company's 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 from the limitations of sections 12(d)(1)(A) and (B) of the Act to the extent necessary to permit the Funds of Funds to acquire shares of Underlying Funds and to permit the Underlying Funds, their principal underwriters and any broker or dealer registered under the Exchange Act to sell shares of the Underlying Funds to the Funds of Funds.
3. Applicants state that 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 continues to be consistent with the public interest and the protection of investors.
4. Applicants state that the proposed structure will not result in the exercise of undue influence by a Fund of Funds or its affiliated persons over the Underlying Funds. The concern about undue influence does not arise in connection with a Fund of Funds' investment in the Affiliated Funds since they are part of the same group of investment companies. To limit the control a Fund of Funds or its affiliated persons may have over an Unaffiliated Fund, applicants remain subject to a condition prohibiting: (a) A Manager and any person controlling, controlled by or under common control with such Manager, and any investment company and any issuer that would be an investment company but for section 3(c)(1) or section 3(c)(7) of the Act advised or sponsored by the Manager or any person controlling, controlled by or under common control with the Manager (collectively, a “Group”); and (b) any other investment adviser within the meaning of section 2(a)(20)(B) of the Act to a Fund of Funds (a “Sub-Adviser”), any person controlling, controlled by or under common control with a Sub-Adviser, and any investment company or issuer that would be an investment company but for section 3(c)(1) or 3(c)(7) of the Act (or portion of such investment company or issuer) advised by the Sub-Adviser or any person controlling, controlled by or under common control with the Sub-Adviser (collectively, a “Sub-Adviser Group”) from controlling (individually or in the aggregate) an Unaffiliated Fund within the meaning of section 2(a)(9) of the Act.
5. Applicants further state that proposed condition 2 precludes a Fund of Funds or a Fund of Funds Affiliate from taking advantage of an Unaffiliated Fund with respect to transactions between a Fund of Funds or a Fund of Funds Affiliate, and the Unaffiliated Fund or an Unaffiliated Fund Affiliate. 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 Management Company or sponsor to an Unaffiliated
6. To further assure that an Unaffiliated Management Company understands the implications of an investment by a Fund of Funds under the requested Amended Order, prior to its investment in an Unaffiliated Management Company in excess of the limit in section 12(d)(1)(A)(i), a Fund of Funds and Unaffiliated Management Company will execute an agreement stating, without limitation, that their boards of directors or trustees and their investment advisers understand the terms and conditions of the Amended Order and agree to fulfill their responsibilities under the Amended Order (“Participation Agreement”). Applicants note that an Unaffiliated Fund (other than an ETF whose shares are purchased by a Fund of Funds in the secondary market) will retain the right to reject an investment by a Fund of Funds.
7. Applicants state that they do not believe that the proposed arrangement will involve excessive layering of fees. To assure that the investment advisory fees are not duplicative, applicants state that, prior to reliance on the requested order and subsequently in connection with the approval of any investment advisory contract under section 15 of the Act, the board of directors or trustees (“Board”) of each Fund of Funds, including a majority of the directors or trustees who are not “interested persons,” as defined in section 2(a)(19) of the Act (“Independent Trustees”), will find that the advisory fees charged under a Fund of Fund's advisory contract(s) are based on services provided that are in addition to, rather than duplicative of, services provided pursuant to any Underlying Fund's advisory contract(s). Applicants further state that a Manager 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 Fund pursuant to rule 12b-1 under the Act) received from an Unaffiliated Fund by the Manager, or an affiliated person of the Manager, other than any advisory fees paid to the Manager or an affiliated person of the Manager by the Unaffiliated Fund, in connection with the investment by the Fund of Funds in the Unaffiliated Fund.
8. Applicants state that with respect to Registered Separate Accounts that invest in a Fund of Funds, no sales load will be charged at the Fund of Funds level or at the Underlying Fund level. Other sales charges and service fees, as defined in Rule 2830 of the Conduct Rules of the National Association of Securities Dealers (“NASD Conduct Rule 2830”), if any, will only be charged at the Fund of Funds level or at the Underlying Fund level, not both. With respect to other investments in a Fund of Funds, any sales charges and/or service fees charged with respect to shares of a Fund of Funds will not exceed the limits applicable to funds of funds set forth in NASD Conduct Rule 2830.
9. Applicants represent that each Fund of Funds will represent in the Participation Agreement that no insurance company sponsoring a Registered Separate Account funding variable insurance contracts will be permitted to invest in the Fund of Funds unless the insurance company has certified to the Fund of Funds that the aggregate of all fees and charges associated with each contract that invests in the Fund of Funds, including fees and charges at the Separate Account, Fund of Funds, and Underlying Fund levels, will be reasonable in relation to the services rendered, the expenses expected to be incurred, and the risks assumed by the insurance company.
10. Applicants state that the proposed arrangement will not create an overly complex fund structure. Applicants note that an Underlying Fund will be prohibited from acquiring 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), except in certain circumstances identified in condition 12 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 the Funds of Funds and the Affiliated Funds might be deemed to be under common control of the Manager, and therefore affiliated persons of one another. Applicants also state that the Funds of Funds and the Underlying Funds might be deemed to be affiliated persons of one another if a Fund of Funds acquires 5% or more of an Underlying Fund's outstanding voting securities. In light of these 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 person 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 arrangement satisfies the standards for relief under sections 17(b) and 6(c) of the Act as the terms of the arrangement are fair and reasonable and do not involve overreaching. Applicants state that the terms upon which an Underlying Fund will sell its shares to or purchase its shares from a Fund of Funds will be based on the net asset value of each Underlying Fund.
Applicants agree that any Amended Order granting the requested relief shall be subject to the following conditions:
1. The members of a Group will not control (individually or in the aggregate) an Unaffiliated Fund within the meaning of section 2(a)(9) of the Act. The members of a Sub-Adviser Group will not control (individually or in the aggregate) an Unaffiliated Fund within the meaning of section 2(a)(9) of the Act. If, as a result of a decrease in the outstanding voting securities of an Unaffiliated Fund, a Group or a Sub-Adviser Group, each in the aggregate, becomes a holder of more than 25% of the outstanding voting securities of the Unaffiliated Fund, it (except for any member of the Group or the Sub-Adviser Group that is a Separate Account) will vote its shares of the Unaffiliated Fund in the same proportion as the vote of all other holders of the Unaffiliated Fund's shares. This condition will not apply to a Sub-Adviser Group with respect to an Unaffiliated Fund for which the Sub-Adviser or a person controlling, controlled by, or under common control with the Sub-Adviser acts as the investment adviser within the meaning of section 2(a)(20)(A) of the Act (in the case of an Unaffiliated Management Company) or as the sponsor (in the case of an Unaffiliated Trust).
A Registered Separate Account will seek voting instructions from its Contract holders and will vote its shares of an Unaffiliated Fund in accordance with the instructions received and will vote those shares for which no instructions were received in the same proportion as the shares for which instructions were received. An Unregistered Separate Account will either: (i) Vote its shares of the Unaffiliated Fund in the same proportion as the vote of all other holders of the Unaffiliated Fund's shares; or (ii) seek voting instructions from its Contract holders and vote its shares in accordance with the instructions received and vote those shares for which no instructions were received in the same proportion as the shares for which instructions were received.
2. No Fund of Funds or Fund of Funds Affiliate will cause any existing or potential investment by the Fund of Funds in 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 assure that the Manager and any Sub-Adviser 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 Management Company exceeds the limit of section 12(d)(1)(A)(i) of the Act, the Board of the Unaffiliated Management Company, including a majority of the Independent Trustees, will determine that any consideration paid by the Unaffiliated Management 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 Management Company; (b) is within the range of consideration that the Unaffiliated Management 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 Management 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 Management 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 Management Company, including a majority of the Independent Trustees, will adopt procedures reasonably designed to monitor any purchases of securities by the Unaffiliated Management Company in an Affiliated Underwriting once an investment by a Fund of Funds in the securities of the Unaffiliated Management 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 Management 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 Management Company. The Board of the Unaffiliated Management Company will consider, among other things: (a) Whether or not the purchases were consistent with the investment objectives and policies of the Unaffiliated Management 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 or not the amount of securities purchased by the Unaffiliated Management Company in Affiliated Underwritings and the amount purchased directly from an Underwriting Affiliate have changed significantly from prior years. The Board of the Unaffiliated Management Company will take any appropriate actions based on its review, including, if appropriate, the institution of procedures designed to assure that purchases of securities in Affiliated Underwritings are in the best interest of shareholders.
7. Each Unaffiliated Management Company will 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 will maintain and preserve for a period of not less than six years from the end of the fiscal year in which any purchase from an Affiliated Underwriting occurred, the first two
8. Prior to its investment in shares of an Unaffiliated Management Company in excess of the limit set forth in section 12(d)(1)(A)(i) of the Act, the Fund of Funds and the Unaffiliated Fund will execute a Participation Agreement stating, without limitation, that their boards of directors or trustees 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 Management Company in excess of the limit set forth in section 12(d)(1)(A)(i), a Fund of Funds will notify the Unaffiliated Management Company of the investment. At such time, the Fund of Funds will also transmit to the Unaffiliated Management Company a list of the names of each Fund of Funds Affiliate and Underwriting Affiliate. The Fund of Funds will notify the Unaffiliated Management Company of any changes to the list as soon as reasonably practicable after a change occurs. The Unaffiliated Management 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 the advisory contract are based on services provided that are in addition to, rather than duplicative of, services provided under the advisory contract(s) of any Underlying Fund in which the Fund of Funds may invest. Such finding, and the basis upon which the finding was made, will be recorded fully in the minute books of the appropriate Fund of Funds.
10. Each Manager 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 Fund pursuant to rule 12b-1 under the Act) received from an Unaffiliated Fund by the Manager, or an affiliated person of the Manager, other than any advisory fees paid to the Manager or its affiliated person by the Unaffiliated Fund, in connection with the investment by the Fund of Funds in the Unaffiliated Fund. Any Sub-Adviser will waive fees otherwise payable to the Sub-Adviser, directly or indirectly, by the Fund of Funds in an amount at least equal to any compensation received by the Sub-Adviser, or an affiliated person of the Sub-Adviser, from an Unaffiliated Fund, other than any advisory fees paid to the Sub-Adviser or its affiliated person by the Unaffiliated Fund, in connection with the investment by the Fund of Funds in the Unaffiliated Fund made at the direction of the Sub-Adviser. In the event that the Sub-Adviser waives fees, the benefit of the waiver will be passed through to the Fund of Funds.
11. With respect to Registered Separate Accounts that invest in a Fund of Funds, no sales load will be charged at the Fund of Funds level or at the Underlying Fund level. Other sales charges and service fees, as defined in NASD Conduct Rule 2830, if any, will only be charged at the Fund of Funds level or at the Underlying Fund level, not both. With respect to other investments in a Fund of Funds, any sales charges and/or service fees charged with respect to shares of a Fund of Funds will not exceed the limits applicable to funds of funds set forth in NASD Conduct Rule 2830.
12. 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) 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 (b) 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.
For the Commission, by the Division of Investment Management, pursuant to delegated authority.
Pursuant to Section 19(b)(1)
The Exchange proposes to delete Rule 123G—NYSE Amex Equities and adopt new Rule 5290—NYSE Amex Equities to correspond with rule changes filed by the Financial Industry Regulatory Authority, Inc. (“FINRA”) and approved by the Commission.
In its filing with the Commission, the self-regulatory organization included statements concerning the purpose of,
The purpose of the proposed rule changes is to delete Rule 123G—NYSE Amex Equities (Order Entry Practices) and adopt new Rule 5290 (Order Entry and Execution Practices) to correspond with rule changes filed by FINRA and approved by the Commission.
On July 30, 2007, FINRA's predecessor, the National Association of Securities Dealers, Inc. (“NASD”), and NYSE Regulation, Inc. (“NYSER”) consolidated their member firm regulation operations into a combined organization, FINRA. Pursuant to Rule 17d-2 under the Act, the New York Stock Exchange LLC (“NYSE”), NYSER and FINRA entered into an agreement (the “Agreement”) to reduce regulatory duplication for their members by allocating to FINRA certain regulatory responsibilities for certain NYSE rules and rule interpretations (“FINRA Incorporated NYSE Rules”). The Exchange became a party to the Agreement effective December 15, 2008.
As part of its effort to reduce regulatory duplication and relieve firms that are members of FINRA, NYSE and NYSE Amex of conflicting or unnecessary regulatory burdens, FINRA is now engaged in the process of reviewing and amending the NASD and FINRA Incorporated NYSE Rules in order to create a consolidated FINRA rulebook.
Rule 123G—NYSE Amex Equities provides that a member, member organization, principal executive, approved person, or registered or non-registered employee thereof, may not engage in conduct that has the intent or effect of unbundling or splitting orders for execution in order to maximize a monetary or in-kind payment received as a result of the execution of such orders. For purposes of the Rule, “monetary or in-kind amounts” include commissions, gratuities, payments for or rebate of fees, or any similar payments of value resulting from the entry of such orders.
In December 2009, FINRA adopted NASD Rule 3380 (Order Entry and Execution Practices), which governs certain order entry and/or execution practices, as consolidated FINRA Rule 5290, subject to certain modifications.
Consolidated FINRA Rule 5290 is substantially the same as Rule 123G—NYSE Amex Equities; however, consolidated FINRA Rule 5290 applies to the unbundling or splitting of both orders and executions, whereas Rule 123G—NYSE Amex Equities applies only to order entry and not execution.
Even though Rule 123G—NYSE Amex Equities is not part of the Common Rules subject to the rulebook consolidation and harmonization process governed by the Agreement, the Exchange hereby proposes to delete Rule 123G—NYSE Amex Equities and replace it with proposed Rule 5290—NYSE Amex Equities, which is substantially similar to the new FINRA Rule.
As proposed, Rule 5290—NYSE Amex Equities adopts the same language as FINRA Rule 5290, except for substituting for or adding to, as needed, the term “member organization” for the term “member”, and making corresponding technical changes. In addition, in order to ensure that both proposed Rule 5290—NYSE Amex Equities and FINRA Rule 5290 are fully harmonized, the Exchange also proposes to add Supplementary Material .01 to Rule 5290—NYSE Amex Equities to provide that, for the purposes of the rule, the term “associated person” shall have the same meaning as the terms “person associated with a member” or “associated person of a member” as defined in Article I (rr) of the FINRA By-Laws.
The Exchange also notes that, upon adoption of proposed Rule 5290—NYSE Amex Equities, it intends to add the Rule to the Agreement as a Common Rule for dual NYSE Amex/FINRA members.
The Exchange believes that the proposed rule changes are consistent with Section 6(b) of the Act,
The Exchange believes that the proposed rule changes support the objectives of the Act by providing greater harmonization between NYSE Amex Equities Rules and FINRA Rules of similar purpose, resulting in less burdensome and more efficient regulatory compliance for joint members. To the extent the Exchange has proposed changes that differ from the FINRA version of the Rules, such changes are technical in nature and do not change the substance of the proposed NYSE Amex Equities Rules.
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act.
No written comments were solicited or received with respect to the proposed rule change.
The Exchange has filed the proposed rule change pursuant to Section 19(b)(3)(A)(iii) of the Act
A proposed rule change filed under Rule 19b-4(f)(6)
Accordingly, the Commission waives the 30-day operative delay requirement and designates the proposed rule change as operative upon filing with the Commission. At any time within 60 days of the filing of the proposed rule change, the Commission may summarily abrogate such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an e-mail to
• Send paper comments in triplicate to Elizabeth M. Murphy, Secretary, Securities and Exchange Commission, 100 F Street, NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
On June 9, 2010 and June 10, 2010 respectively, the New York Stock Exchange LLC (“NYSE”) and NYSE Amex LLC (“NYSE Amex” and, with NYSE, each an “Exchange” and collectively, the “Exchanges”) each filed with the Securities and Exchange Commission (the “Commission”), pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The Exchanges seek to amend their rules to incorporate the receipt and execution of odd-lot interest into the round lot market and decommission the
In order to incorporate interest for fewer than 100 shares into the round lot market, the new unit of trading for all securities would be one share.
In order to incorporate odd-lot interest and the odd-lot portion of PRL interest into the round lot market, the Exchanges propose to amend their rules governing order handling, execution, and allocation to reflect that odd-lot quantities would not be displayed as the respective Exchange quotation and odd-lot executions would not be published to the Consolidated Tape.
Display Book would aggregate all interest at each price point, including odd-lot interest and the odd-lot portion of PRL interest. Aggregated interest would be quoted and published by Display Book if it were equal to or greater than a round lot when the price point becomes the respective Exchange best bid or best offer (“Exchange BBO”). Although a bid or offer may be the aggregation of odd-lot interest and the odd-lot portion of PRL interest, the sum of which is equal to or greater than a round lot,
Because odd-lot interest and the odd-lot portion of PRL interest would be eligible for inclusion in the respective Exchange BBO, such interest would be considered “displayable” interest for the purposes of execution and allocation.
In addition, consistent with the current logic of priority and parity, incoming single odd-lot interest would never be eligible to be the Priority Interest because it can never be the only interest quoted at the price point. Similarly, single odd-lot interest at a price point may not prevent single displayable round lot or PRL interest from establishing itself as Priority Interest. When single round lot or PRL interest joins odd-lot interest at a price point and the sum of all such odd-lot interest is less than a round lot, the single round lot or PRL that is published as the Exchange BBO would be considered the setting interest and have established priority at that price point.
As the matching engine for each Exchange, Display Book would be responsible for the execution of all incoming interest regardless of the share size. All incoming interest would be eligible to be executed against eligible contra side interest.
DMM CCS interest would not be accessed to fill or partially fill an incoming odd-lot order, but only in reaction to incoming contra side interest that is equal to or greater than one round lot.
Executions would be printed to the Consolidated Tape in round lots or PRL quantities. Transactions that result in executions of less than a round lot would not: (i) Print to the Consolidated Tape; (ii) be considered the last sale; or (iii) elect buy minus, sell plus, or stop interest for execution.
Display Book would continue to allocate executed shares in round lots; however, if the quantity of shares to be allocated to a specific participant were for a quantity less than a round lot, the Display Book would allocate to the participant the specific number of shares bid or offered.
The system changes required to decommission the Odd-lot System would enable the Exchanges to expand their price fields. The Exchanges propose to amend Rule 62 (“Variations”) to remove the requirement that $.10 be the minimum variation for securities priced at or greater than $100,000 and replace it with a requirement that the minimum price variation for quoting and entry of interest in securities priced at or greater than $1.00 be a penny (“$.01”).
In addition, the incorporation of odd-lot interest and the odd-lot portion of PRL interest into Display Book would provide the Exchanges' market data systems access to odd-lot volumes.
The Exchanges intend to progressively implement these systemic changes on a security-by-security basis as it gains experience with the new technology until it is operative in all securities traded on the Floor. During the implementation, the Exchanges would identify on their Web sites which securities have been transitioned to the new system. In addition, the Exchanges would provide information to their constituents about any modifications to the start or end date related to the implementation of such proposal via their Trader Update Notices that are sent via e-mail to subscribers and posted on the Exchanges' Web sites.
The Commission finds that the proposed rule changes are consistent with the requirements of the Act and the rules and regulations thereunder applicable to a national securities exchange.
The Commission notes that Display Book would aggregate all interest at each price point, including odd-lot interest and the odd-lot portion of PRL interest. Because such interest would be eligible for inclusion in the respective Exchange's BBO, it would be considered “displayable” interest for the purposes of execution and allocation, unless designated as excluded interest. Aggregated displayable interest at a given price point would be quoted if its size is equal to or greater than one round lot when that price point becomes the respective Exchange BBO. Due to restrictions in the Consolidated Tape Plan, however each respective Exchange's quote would continue to only be disseminated in round lots. However, all interest at the BBO would participate at that price point, even where the aggregate interest is rounded down for dissemination. Thus, the proposal should increase market liquidity and efficiency by making odd lot interest available for execution in Display Book.
The Commission also notes that incoming odd-lot orders would never be eligible to be the priority interest. Even if received earlier, undisplayed odd lot interest would not prevent a displayable round lot or PRL order from establishing itself as priority interest when such interest is the sole independently displayable order at that price point if it becomes the BBO. Odd-lot orders could never be the only interest quoted at a specific price point under the Exchange's rules. However, PRL interest that is established as priority interest would have priority for the full quantity of the PRL interest. As a result, the proposal should not reduce the incentive to quote aggressively to narrow the BBO that is provided by the Priority Interest rule.
The Commission notes that, as a result of the proposed rule change, DMMs would no longer act in the capacity of odd-lot dealer and would no longer be the designated contra-party to all odd-lot executions. However, the DMM would be obligated to be the contra party to any unpaired odd-lot size interest that is to be executed in the opening, re-opening, and closing transactions. In addition, DMM CCS interest would be available to incoming contra side interest that is equal to or greater than one round lot, but not to incoming odd-lot orders. The DMM would be allowed to enter CCS interest in PRL quantities, but, as is currently the case, DMM CCS interest entered at each price point must be for a minimum of one round lot. Since the one round lot minimum size requirement is maintained both for CCS interest and for incoming interest that may execute against CCS interest, the Commission believes that the changes to the rules regarding the CCS do not materially alter the operation of the CCS or the benefits afforded to DMMs by the CCS.
The Commission further notes that Display Book would allocate executed shares in round lots or the size of the order, if less than one round lot. Odd-lot allocations would not move the allocation wheel to the next participant unless such odd-lot allocation completely fills the interest of the participant who received it. Executions would be printed to the Consolidated Tape in round lots or PRL quantities. Again, due to restrictions in the Consolidated Tape Plan, odd-lot quantities would not be printed to the Consolidated Tape. The incorporation of odd-lot and PRL interest into Display Book would allow the odd-lot volumes to be included in each Exchange's market data, which should enhance the transparency of odd-lot and PRL executions on the Exchanges. The Commission believes this is a reasonable integration of Display Book's new capacity for odd lot interest with the Exchanges' rules regarding allocation and reporting.
The Commission believes that the proposed changes are consistent with the Act because, taken as a whole, they should enhance efficiency, transparency, and fairness in the treatment of odd-lot and partial round lot customer orders, without significantly altering the benefits and obligations of DMMs and other market participants.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1)
The Exchange proposes to delete NYSE Rule 123G and adopt new Rule 5290 to correspond with rule changes filed by the Financial Industry Regulatory Authority, Inc. (“FINRA”) and approved by the Commission.
In its filing with the Commission, the self-regulatory organization included statements concerning the purpose of, and basis for, the proposed rule change and discussed any comments it received on the proposed rule change. The text of those statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant parts of such statements.
The purpose of the proposed rule changes is to delete NYSE Rule 123G (Order Entry Practices) and adopt new Rule 5290 (Order Entry and Execution Practices) to correspond with rule changes filed by FINRA and approved by the Commission.
On July 30, 2007, FINRA's predecessor, the National Association of Securities Dealers, Inc. (“NASD”), and NYSE Regulation, Inc. (“NYSER”) consolidated their member firm regulation operations into a combined organization, FINRA. Pursuant to Rule 17d-2 under the Act, NYSE, NYSER and FINRA entered into an agreement (the “Agreement”) to reduce regulatory duplication for their members by allocating to FINRA certain regulatory responsibilities for certain NYSE rules and rule interpretations (“FINRA Incorporated NYSE Rules”). NYSE Amex LLC (“NYSE Amex”) became a party to the Agreement effective December 15, 2008.
As part of its effort to reduce regulatory duplication and relieve firms that are members of FINRA, NYSE and NYSE Amex of conflicting or unnecessary regulatory burdens, FINRA is now engaged in the process of reviewing and amending the NASD and FINRA Incorporated NYSE Rules in order to create a consolidated FINRA rulebook.
NYSE Rule 123G provides that a member, member organization, allied member (principal executive),
In December 2009, FINRA adopted NASD Rule 3380 (Order Entry and Execution Practices), which governs certain order entry and/or execution practices, as consolidated FINRA Rule 5290, subject to certain modifications.
Consolidated FINRA Rule 5290 is substantially the same as NYSE Rule 123G; however, consolidated FINRA Rule 5290 applies to the unbundling or splitting of both orders and executions, whereas NYSE Rule 123G applies only to order entry and not execution.
Even though NYSE Rule 123G is not part of the Common Rules subject to the rulebook consolidation and harmonization process governed by the Agreement, the Exchange hereby proposes to delete Rule 123G and replace it with proposed NYSE Rule 5290, which is substantially similar to the new FINRA Rule.
As proposed, NYSE Rule 5290 adopts the same language as FINRA Rule 5290, except for substituting for or adding to, as needed, the term “member organization” for the term “member”, and making corresponding technical changes. In addition, in order to ensure that both proposed NYSE Rule 5290 and FINRA Rule 5290 are fully harmonized, the Exchange also proposes to add Supplementary Material .01 to NYSE Rule 5290 to provide that, for the
The Exchange also notes that, upon adoption of proposed Rule 5290, it intends to add the Rule to the Agreement as a Common Rule for dual NYSE/FINRA members.
The Exchange believes that the proposed rule changes are consistent with Section 6(b) of the Act,
The Exchange believes that the proposed rule changes support the objectives of the Act by providing greater harmonization between NYSE Rules and FINRA Rules (including Common Rules) of similar purpose, resulting in less burdensome and more efficient regulatory compliance for Dual Members. To the extent the Exchange has proposed changes that differ from the FINRA version of the Rules, such changes are technical in nature and do not change the substance of the proposed NYSE Rules.
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act.
No written comments were solicited or received with respect to the proposed rule change.
The Exchange has filed the proposed rule change pursuant to Section 19(b)(3)(A)(iii) of the Act
A proposed rule change filed under Rule 19b-4(f)(6)
Accordingly, the Commission waives the 30-day operative delay requirement and designates the proposed rule change as operative upon filing with the Commission. At any time within 60 days of the filing of the proposed rule change, the Commission may summarily abrogate such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an e-mail to
• Send paper comments in triplicate to Elizabeth M. Murphy, Secretary, Securities and Exchange Commission, 100 F Street, NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
The Social Security Administration (SSA) publishes a list of information collection packages requiring clearance by the Office of Management and Budget (OMB) in compliance with Public Law (Pub. L.) 104-13, the Paperwork Reduction Act of 1995, effective October 1, 1995. This notice includes revisions of OMB-approved information collections.
SSA is soliciting comments on the accuracy of the agency's burden estimate; the need for the information; its practical utility; ways to enhance its quality, utility, and clarity; and ways to minimize burden on respondents, including the use of automated collection techniques or other forms of information technology. Mail, e-mail, or fax your comments and recommendations on the information collection(s) to the OMB Desk Officer and SSA Reports Clearance Officer to the following addresses or fax numbers.
I. The information collections below are pending at SSA. SSA will submit them to OMB within 60 days from the date of this notice. To be sure we consider your comments, we must receive them no later than October 1, 2010. Individuals can obtain copies of the collection instruments by calling the SSA Reports Clearance Officer at 410-965-8783 or by writing to the above e-mail address.
1. Request for Corrections of Earnings Record—20 CFR 404.820 and 20 CFR 422.125—0960-0029. Individuals alleging inaccurate earnings records that SSA maintains for them use Form SSA-7008 to provide the information SSA needs to check earnings posted, and as necessary, initiate development to resolve any inaccuracies. The respondents are individuals who request correction of earnings posted to their Social Security earnings record.
2. Missing and Discrepant Wage Reports Letter and Questionnaire—26 CFR 31.6051-2—0960-0432. Each year employers report the wage amounts they paid their employees to the Internal Revenue Service (IRS) for tax purposes, and separately to SSA for retirement and disability coverage purposes. These reported amounts should equal each other. However, each year some employer wage reports SSA receives are less than the wage amounts employers report to the IRS. SSA uses Forms SSA-L93-SM, SSA-L94-SM, SSA-95-SM, and SSA-97-SM to ensure employees receive full credit for their wages. Respondents are employers who reported lower wage amounts to SSA than they reported to the IRS.
3. Appointment of Representative—20 CFR 404.1707, 4041720, 404.1725, 410.684 and 416.1507—0960-0527. Persons claiming benefits under the Social Security Act must notify SSA in writing when they appoint an individual to represent them in dealings with SSA. SSA collects the information on Form SSA-1696-U4 to verify the appointment of such representatives. The SSA-1696-U4 also allows SSA to inform representatives of items affecting the recipient's claim and allows claimants to give permission to their appointed representatives to designate a person to copy claims files. Respondents are applicants/recipients of Social Security benefits or Supplemental Security Income (SSI) payments who are notifying SSA they have appointed a person to represent them in their dealings with SSA.
4. Appeal of Determination for Help with Medicare Prescription Drug Plan Costs—0960-0695. Public Law 108-173, the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (MMA) established the Medicare Part D program for voluntary prescription drug coverage for certain low-income individuals. The MMA stipulates subsidies must be available for individuals who are eligible for the program and who meet eligibility criteria for help with premium, deductible, and/or co-payment costs. Form SSA-1021, Appeal of Determination for Help with Medicare Prescription Drug Plan Costs, obtains information from individuals who appeal SSA's decisions regarding eligibility or continuing eligibility for a Medicare Part D subsidy. The respondents are applicants who are appealing SSA's eligibility or continuing eligibility decisions.
5. Consent Based Social Security Number Verification Process—20 CFR 400.100—0960-0760. The Consent-Based Social Security Number (SSN) Verification (CBSV) process is a fee-based automated SSN verification service available to private businesses
Under the CBSV process, the requesting party does not submit the consent forms of the number holders to SSA. SSA requires each requesting party to retain a valid consent form for each SSN verification request. The requesting party retains the consent forms in either electronic or paper format.
To ensure the integrity of the CBSV process, SSA added a strong audit component that requires audits (called “compliance reviews”) at the discretion of the agency with all audit costs borne by the requesting party. Independent certified public accountants (CPA) conduct these reviews to ensure compliance with all the terms and conditions of the party's agreement with SSA, including a review of the consent forms. CPAs conduct the review at the requesting party's place of business to ensure the integrity of the process. In addition, SSA reserves the right to perform unannounced onsite inspections of the entire process, including review of the technical systems that maintain the data and transaction records. The respondents to the CBSV collection are the participating companies, members of the public who consent to the SSN verification, and CPAs who provide compliance review services.
People whose SSNs SSA Will Verify:
The public burden cost is dependent upon the number of companies and transactions. SSA based the cost estimates below upon 115 participating companies submitting 986,585 transactions. The total cost for developing the system was $5.6 million. SSA has already expended $3.0 million that we will recoup over the depreciable life of the system based on the fee-per-transaction model.
One-Time per Company Registration Fee—$5,000.
Estimated per SSN Transaction Fee—$5.
Estimated per Company Cost to Build Web Service—$200,000.
Estimated per Company Cost to Store Consent Forms—$300.
Estimated per Company Cost To Contract with CPA for Audit—$8,000.
II. SSA has submitted the information collections listed below to OMB for clearance. Your comments on the information collections would be most useful if OMB and SSA receive them
1. Request to be Selected as a Payee—20 CFR 404.2010-404.2055, 416.601-416.665—0960-0014. An individual applying to be a representative payee for a Social Security or SSI recipient completes Form SSA-11-BK. SSA obtains information from applicant payees regarding their relationship to the beneficiary; personal qualifications; their concern for the beneficiary's well-being; and their intended use of benefits if appointed as payee. The respondents are individuals, private sector businesses and institutions, and state and local government institutions and agencies.
Individuals/Households (90%):
Private Sector (9%):
State/Local/Tribal Government (1%):
2. Representative Payee Evaluation Report—20 CFR 404.2065 & 416.665—0960-0069. Sections 205(j) and 1631(a)(2) of the Social Security Act state that SSA may appoint a representative payee to receive Title II benefits and/or Title XVI payments on behalf of individuals unable to manage or direct the management of those funds themselves. SSA requires the appointed representative payees to report once per year on how they used or conserved those funds. When a representative payee fails to report adequately to SSA as required, SSA conducts a face-to-face interview with the payee and completes Form SSA-624, Representative Payee Evaluation Report, to determine the continued suitability of the representative payee to serve as a payee. The respondents are individuals or organizations serving as representative payees for individuals receiving Title II benefits and/or Title XVI payments who fail to comply with SSA's statutory annual reporting requirement.
3. Waiver of Your Right to Personal Appearance before an Administrative Law Judge—20 CFR 404.948(b)(l)(i) and 416.1448(b)(l)(i)—0960-0284. Applicants for Social Security benefits and SSI payments have the statutory right to appear in person (or through a representative) and present evidence about their claims at a hearing before an administrative law judge (ALJ). If claimants wish to waive this right to appear before an ALJ, they must complete a written request. The applicants may use SSA Form HA-4608 for this purpose. The ALJ uses the information to document an individual's claim to show that an oral hearing is not preferred in the appellate process. Respondents are claimants or their representatives for Title II benefits and/or Title XVI payments who request to waive their right to appear in person before an ALJ.
4. Request for Change in Time/Place of Disability Hearing—20 CFR 404.914(c)(2) and 416.1414(c)(2)—0960-0348. At the request of claimants or their representatives, SSA schedules evidentiary hearings at the reconsideration level for claimants of Title II benefits and/or Title XVI payments when we deny their claims for disability. When claimants or their representatives find they are unable to attend the scheduled hearing, they complete Form SSA-769 to request a change in time or place of the hearing. SSA uses the information as a basis for granting or denying requests for changes and for rescheduling disability hearings. Respondents are claimants or their representatives who wish to request a change in the time and/or place of their hearing.
5. Agency/Employer Government Pension Offset Questionnaire—20 CFR 404.408(a)—0960-0470. When an individual is concurrently receiving Social Security spousal or surviving spousal benefits and a government pension, the individual may have the amount of Social Security benefits reduced by the government pension amount. We call this the Government Pension Offset (GPO). SSA uses Form SSA-L4163 to collect accurate pension information from the Federal or state government agency paying the pension for purposes of applying the pension-offset provision. We only use the form when: (1) The claimant does not have the information; and (2) the pension-paying agency has not cooperated with the claimant. Respondents are state government agencies that have information SSA needs to determine if the GPO applies and/or the amount of offset.
6. Child Care Dropout Questionnaire—20 CFR 404.211(e)(4)—0960-0474. The Social Security Act and SSA's regulations permit the exclusion, from a disability computation period, of the years an individual was caring for his or her (or the spouse's) child under age 3 if he or she had no earnings in the benefit computation years. We call this the child-care dropout exclusion. SSA uses Form SSA-4162 to determine if an individual qualifies for this exclusion. Respondents are applicants for Title II disability benefits.
7. Function Report—Child: Birth to 1st Birthday (SSA-3375), Age 1 to 3rd Birthday (SSA 3376), Age 3 to 6th Birthday (SSA-3377), Age 6 to 12th Birthday (SSA-3378), and Age 12 to 18th Birthday (SSA-3379)—20 CFR 416.912—0960-0542. Forms SSA-3375-BK through SSA-3379-BK request information from the child's parent about the child's day-to-day functioning. The five different versions of the form contain questions about functioning appropriate to a particular age group; thus, respondents use only one version for each child.
The adjudicative team (disability examiners and medical/psychological consultants) of state Disability Determination Services offices collect the information on the appropriate version of this form (in conjunction with medical and other evidence) to form a complete picture of the children's ability to function and their impairment-related limitations. The adjudicative team uses the completed profile to determine whether each child's impairment(s) results in marked and severe functional limitations and whether each child is disabled. The respondents are parents and/or guardians of child applicants for SSI payments.
8. Registration for Appointed Representative Services and Direct Payment—0960-0732. SSA uses Form SSA-1699 to register appointed representatives of claimants before SSA who:
• Want to register for direct payment of fees;
• Registered for direct payment of fees prior to 10/31/09, but need to update their information;
• Registered as appointed representatives on or after 10/31/09, but need to update their information; and/or
• Received a notice from SSA instructing them to complete this form.
By registering these individuals, SSA: (1) Authenticates and authorizes them to do business with us; (2) allows them access to our records for the claimants they represent; (3) facilitates direct payment of authorized fees to appointed representatives; and (4) collects the information we will need to meet IRS requirements to issue specific IRS forms if we pay these representatives in excess of a specific amount ($600).
In February 2010, we received emergency clearance for a new, simplified version of this form. We are now seeking full clearance for this simplified version. The respondents are appointed representatives who want to use Form SSA-1699 for any of the purposes cited in this notice.
9. Government-to-Government Services Online Web site Registration; Government-to-Government Services Online Web site Account Modification/Deletion Form—20 CFR 401.45—0960-0757. The Government-to-Government Services Online (GSO) Web site allows various external organizations to submit files to a variety of SSA systems and, in some cases, receive return files. The users include state/local government agencies, other Federal agencies, and some private sector business entities. The SSA systems that process data transferred via GSO include, but are not limited to, systems responsible for disability processing and benefit determination or termination. A sponsor within SSA who knows the requestor completes the registration form, SSA-118, and submits the information to SSA's User Interface Team (UIT). SSA uses the information on Form SSA-118 (GSO Web site Registration Form) to maintain the identity of the requestor within GSO. Once this is completed, SSA provides the requestor with the new password and conducts a walkthrough of the GSO Web site as necessary. The organization can also modify its online account (
This is a correction notice. SSA published this information with the incorrect form name on May 13, 2010 at 75 FRN 27036. We are correcting this error here.
Also, Form SSA-118 is now Form SSA-159, and Form SSA-119 is now Form SSA-160.
10. Technical Updates to Applicability of the Supplemental Security Income (SSI) Reduced Benefit Rate for Individuals Residing in Medical Treatment Facilities—20 CFR 416.708(k)—0960-0758. Section 1611(e)(1)(A) of the Social Security Act states no resident of a public institution is eligible for SSI payments. However, Sections 1611(e)(1)(B) and (G) list certain exceptions to this provision that make it necessary for SSA to collect information about any SSI recipient who enters or leaves a medical treatment facility, or other public or private institution. SSA's regulation 20 CFR 416.708(k) establishes the reporting guidelines that implement this legislative requirement. SSA collects the information to determine eligibility for SSI and the payment amount. The respondents are SSI recipients who enter or leave an institution.
This is a correction notice: SSA published the incorrect CFR number for this collection at 75 FR 27036, on 5/13/10. We are correcting this error here.
11. Statement for Certificate of Election for Reduced Widow(er)'s and Surviving Divorced Spouse's Benefits—20 CFR 404.335—0960-0759. Section 202(q) of the Social Security Act provides the authority to reduce benefits under certain conditions when a Title II beneficiary elects to do so. However, reduced benefits are not payable to an already entitled spouse (or divorced spouse) who:
• Is at least age 62 and under full retirement age in the month of the number holder's death; and,
• Is receiving reduced spouse's (or divorced spouse's) benefits, and either retirement or disability benefits in the month before the month of the number holder's death.
To elect reduced widow(er) benefits, a recipient completes Form SSA-4111. SSA collects the information on Form SSA-4111 to pay a qualified dually entitled widow(er) (or surviving divorced spouse) who elects to receive a reduced widow(er) benefit. The respondents are qualified dually entitled widow(er)s (or surviving divorced spouse) who elect to receive a reduced widow(er) benefit.
12. Questionnaire about Special Veterans Benefits—0960-NEW. SSA will use the information collected on the SSA-2010 to determine continuing eligibility for Social Security Special Veterans Benefits (SVB), and to determine how much (if any) of a foreign pension we may use to reduce or increase the amount of Social Security SVB. The respondents will complete the SSA-2010 biannually so SSA can determine if we should increase, decrease, suspend, or terminate benefits based on the data we collect. The respondents are beneficiaries receiving Social Security SVB.
Notice is hereby given of the following determinations: Pursuant to the authority vested in me by the Act of October 19, 1965 (79 Stat. 985; 22 U.S.C. 2459), Executive Order 12047 of March 27, 1978, the Foreign Affairs Reform and Restructuring Act of 1998 (112 Stat. 2681,
For further information, including a list of the exhibit objects, contact Paul W. Manning, Attorney-Adviser, Office of the Legal Adviser, U.S. Department of State (
Notice is hereby given of the following judicial immunity determinations: Pursuant to the authority vested in me by the Act of October 19, 1965 (79 Stat. 985; 22 U.S.C. 2459), Executive Order 12047 of March 27, 1978, the Foreign Affairs Reform and Restructuring Act of 1998 (112 Stat. 2681,
For further information, including a list of the exhibit objects, contact Paul W. Manning, Attorney-Adviser, Office of the Legal Adviser, U.S. Department of State (
Pipeline and Hazardous Materials Safety Administration (PHMSA), DOT.
List of applications for modification of special permits.
In accordance with the procedures governing the application for, and the processing of, special permits from the Department of Transportation's Hazardous Material Regulations (49 CFR Part 107, Subpart B), notice is hereby given that the Office of Hazardous Materials Safety has received the applications described herein. This notice is abbreviated to expedite docketing and public notice. Because the sections affected, modes of transportation, and the nature of application have been shown in earlier
Comments must be received on or before August 17, 2010.
Comments should refer to the application number and be submitted in triplicate. If confirmation of receipt of comments is desired, include a self-addressed stamped postcard showing the special permit number.
Copies of the applications are available for inspection in the Records Center, East Building, PHH-30, 1200 New Jersey Avenue Southeast, Washington, DC, or at
This notice of receipt of applications for modification of special permit is published in accordance with Part 107 of the Federal hazardous materials transportation law (49 U.S.C. 5117(b); 49 CFR 1.53(b)).
The Federal Aviation Administration (FAA), lead Federal agency and United States Air Force, cooperating agency.
Notice of Availability of Final SEA and FONSI.
In accordance with National Environmental Policy Act of 1969 (NEPA), as amended (42 U.S.C. 4321
The FAA has posted the Final SEA and FONSI on the FAA Office of Commercial Space Transportation Web site at
Under the Proposed Action, the FAA would issue a Launch Site Operator License to Space Florida to operate LC-36 and LC-46 as a commercial space launch site for vertical launches of both solid and liquid propellant launch vehicles. The proposed activities at LC-46 remain consistent with those analyzed in the 2008 EA which analyzed the potential environmental impacts of the FAA issuing a Launch Site Operator License to Space Florida to operate a commercial space launch site at LC-46. The 2008 EA analyzed the operation of several types of vertical launch vehicles from LC-46, including
The Proposed Action also includes construction and operation activities to redevelop LC-36 into commercial space launch site. The Final SEA expands on the analysis provided in the 2008 EA to include an analysis of the potential environmental impacts of the construction and operation activities associated with the redevelopment of LC-36 into a commercial space launch site. Redeveloping LC-36 into a multi-use commercial space launch site involves construction of facilities to launch a Generic Launch Vehicle (GLV), which is a conceptual (or “surrogate”) liquid propellant medium class launch vehicle with a solid propellant second stage, and a bipropellant third stage, used for the purposes of the environmental review. Redevelopment activities at LC-36 would include building access roads; erecting a security fence; reconstituting several existing facilities; constructing an elevated launch deck, associated flame ducts, water storage tank, and water deluge containment pool; and installing electrical, communication, and air systems. Redevelopment would occur in phases dictated by costs and schedule, and facility construction or modifications would take place only on previously disturbed ground. The only alternative to the Proposed Action is the No Action Alternative. Under this alternative, the FAA would not issue a Launch Site Operator License to Space Florida for commercial launches from LC-36 and LC-46 at CCAFS.
Resource areas were considered to provide a context for understanding and assessing the potential environmental effects of the Proposed Action, with attention focused on key issues. The resource areas considered in the Final SEA included air quality; biological resources (terrestrial vegetation and wildlife, marine species, and protected species); compatible land use (land use, light emissions, visual resources, and coastal resources); cultural resources and Section 4(f) properties; hazardous materials, solid waste, and pollution prevention; noise; socioeconomic resources; and water resources (surface water, groundwater, floodplains, and wetlands). Potential cumulative impacts of the Proposed Action are also addressed in the Final SEA.
The FAA published a Notice of Availability of the Draft SEA in the
Mr. Daniel Czelusniak, Environmental Specialist, Federal Aviation Administration, 800 Independence Avenue, SW., Suite 331, Washington, DC 20591, by e-mail at
Federal Railroad Administration (FRA), United States Department of Transportation (DOT).
Notice of Buy America waiver request and request for comment.
FRA is issuing this notice to advise the public that the Northern New England Passenger Rail Authority (NNEPRA) is seeking a waiver from FRA's Buy America requirement—49 U.S.C. 24405(a). NNEPRA was awarded $35 million in an America Recovery and Reinvestment Act (“Recovery Act”) grant to extend Amtrak's Downeaster passenger service from its existing route of Boston, Massachusetts to Portland, Maine further north to Brunswick, Maine with a stop in Freeport, Maine. The project requires the purchase and use of 3,340 AREMA specified carbon steel standard 1
Written comments on NNEPRA's Buy America waiver request should be provided to the FRA on or before August 12, 2010.
Please submit your comments by one of the following means, identifying your submissions by docket number FRA-2010-0122. All electronic submissions must be made to the U.S. Government electronic site at
(1)
(2)
(3)
(4)
For questions about this notice, please contact Ms. Linda Martin, Attorney-Advisor, FRA Office of Chief Counsel, (202) 493-6062 or via e-mail at
The Recovery Act requires FRA to apply the Buy America provisions contained in the Passenger Rail Investment and Improvement Act of 2008 (PRIIA), at 49 U.S.C. 24405(a), to grants obligated with Recovery Act funds. 49 U.S.C. 24405(a)(1) authorizes the Secretary of Transportation (“Secretary”) to obligate grant funds only if the steel, iron, and manufactured goods used in the project are produced in the United States. However, 49 U.S.C. 24405(a)(2) also permits the Secretary to waive the Buy America requirements if he finds that: (A) Applying paragraph (1) would be inconsistent with the public interest; (B)
If the Secretary determines that it is necessary to waive the Buy American provisions, 49 U.S.C. 24405(a)(4) requires that the Secretary provide public notice of such a finding and provide an opportunity for comment. In addition, PRIIA requires a detailed written justification for the decision be published in the
NNEPRA was awarded a $35,000,000 Recovery Act grant to extend Amtrak Downeaster passenger service from its existing route of Boston, Massachusetts to Portland, Maine further north on to Brunswick, Maine with a stop in Freeport, Maine. The Project includes the rehabilitation of existing rail lines owned by Pan Am Railways, construction of two passenger platforms, the rehabilitation of 36 grade crossings, upgrades to signals, the installation of signals on the Brunswick Branch, and other right-of-way improvements.
NNEPRA has requested the waiver pursuant to 49 U.S.C. 24405(a)(2)(B) because it believes that for the reasons set forth in this notice the manufactured goods, 3,340 AREMA Specified Carbon Steel Standard 1
With this information in mind and in order to completely understand the facts surrounding NNEPRA's request, FRA seeks comment from all interested parties regarding the availability of domestically manufactured track nuts as described, and the potential Buy America waiver.
Federal Motor Carrier Safety Administration (FMCSA), DOT.
Notice of renewal of exemption; request for comments.
FMCSA renews an exemption from the requirement to hold a commercial driver's license (CDL) submitted by Volvo Trucks North America (Volvo) on behalf of an employee. Volvo requested renewal of the CDL exemption for a Swedish engineer employed by the company to enable this individual to continue test-driving commercial motor vehicles (CMVs) in the United States. This individual holds a valid Swedish CDL. FMCSA believes that the training program and knowledge and skills testing that drivers must undergo to obtain a Swedish CDL ensure a level of safety equivalent to, or greater than, the level of safety that would be obtained by complying with the U.S. requirement for a CDL.
Comments must be received on or before September 1, 2010. Effective date of the exemption is June 18, 2010 to June 18, 2012.
You may submit comments identified by Federal Docket Management System Number FMCSA-2006-25756 by any of the following methods:
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Ms. Christine Hydock, FMCSA Driver and Carrier Operations Division, Office of Bus and Truck Standards and Operations,
Under 49 U.S.C. 31136(e) and 31315, FMCSA may renew an exemption from the CDL requirements of 49 CFR 383.23 for a maximum 2-year period if it finds “such exemption would likely achieve a level of safety that is equivalent to, or greater than, the level that would be achieved absent such exemption.” The procedures for requesting an exemption (including renewals) are prescribed in 49 CFR part 381.
Volvo applied for a 2-year renewal of an exemption from 49 CFR 383.23, the CDL requirement for drivers operating CMVs, for Andreas Hamsten. A copy of the request for renewal, dated May 12, 2010, is in the docket identified at the beginning of this notice.
FMCSA initially granted an exemption to three Swedish engineers and technicians employed by Volvo on June 18, 2008 (73 FR 34828). Detailed information about the qualifications and experience of each of the three drivers, including Mr. Hamsten, was provided by Volvo in its original application, a copy of which is in the docket referenced above. Volvo is seeking a renewal of this exemption because Mr. Hamsten is a citizen and resident of Sweden, and cannot easily obtain a non-resident CDL, given the small number of States willing to issue such a license. Renewal of the exemption will enable Mr. Hamsten to operate CMVs in the U.S. and continue to support Volvo's field tests to meet future clean air standards, to test drive prototype vehicles at their test site, and to deliver the vehicles, if necessary. It is estimated that he will drive approximately 2,500 miles per year on U.S. roads. Mr. Hamsten is an experienced CMV operator holding a valid Swedish-issued CDL. He has received extensive CMV training, and has satisfied strict regulations in Sweden in order to obtain a CDL. Volvo explained in detail in earlier exemption requests the rigorous training program and knowledge and skills tests that applicants for a Swedish CDL must undergo. Volvo also argued in prior exemption requests that the Swedish knowledge and skills tests and training program ensure that Volvo's drivers operating under the exemption will achieve a level of safety that is equivalent to, or greater than, the level of safety obtained by complying with the U.S. requirement for a CDL.
FMCSA has previously determined that the process for obtaining a Swedish CDL is comparable to, or as effective as, the requirements of Part 383, and adequately assesses the driver's ability to operate CMVs in the U.S. In the past 2 years, FMCSA has published several notices of similar Volvo exemption requests; the most recent Agency notice of final disposition was published on June 14, 2010, granting an exemption to 2 Volvo drivers for 2 years (75 FR 33662).
FMCSA has evaluated Volvo's application for renewal of Mr. Hamsten's exemption and decided to grant it for an additional 2-year period, i.e., from June 18, 2010, through June 18, 2012. Mr. Hamsten's exemption is renewed subject to the following terms and conditions: (1) This exemption is valid only when Mr. Hamsten is acting within the scope of his employment by Volvo; (2) He and Volvo must adhere to drug and alcohol regulations, including testing, as provided by in 49 CFR part 382; (3) He and Volvo must adhere to driver disqualification rules under 49 CFR parts 383 and 391 that apply to other CMV drivers in the United States; (4) He is subject to all other provisions of the Federal Motor Carrier Safety Regulations (FMCSRs) (49 CFR 390-397) unless specifically exempted herein; (5) He must keep a copy of the exemption on the vehicle at all times for presentation to a duly authorized Federal, State, or local enforcement official; (6) Volvo must notify FMCSA in writing of any accident, as defined in 49 CFR 390.5, involving this exempted driver; and (7) Volvo must notify FMCSA in writing if this driver is convicted of a disqualifying offense described in sections 383.51 or 391.15 of the FMCSRs.
This exemption will be valid for 2 years unless rescinded earlier by FMCSA. Mr. Hamsten's exemption will be rescinded if: (1) He fails to comply with the terms and conditions of the exemption; (2) The exemption has resulted in a lower level of safety than was maintained before it was granted; or (3) Continuation of the exemption would not be consistent with the goals and objectives of 49 U.S.C. 31136(e) and 31315.
In accordance with 49 U.S.C. 31136(e) and 31315(b)(4), FMCSA requests public comment on the renewal of Mr. Hamsten's exemption from the requirements of 49 CFR 383.23. The Agency requests that interested parties with specific data concerning Mr. Hamsten's safety record submit comments by September 1, 2010. FMCSA will review all comments received by this date and determine whether renewal of the exemption is consistent with the requirements of 49 U.S.C. 31136(e) and 31315.
FMCSA believes the requirements for renewal of an exemption under 49 U.S.C. 31136(e) and 31315 can be satisfied by granting the renewal and then requesting and subsequently evaluating comments submitted by interested parties. As indicated above, on one prior occasion, the Agency determined that providing an exemption for this Volvo driver does not compromise the level of safety that would exist if the exemption were not granted. The prior FMCSA decision was based on careful consideration of the comments received, and on the merits of each driver's demonstrated knowledge and skills about the safe operation of CMVs. Interested parties or organizations possessing information that would show that Mr. Hamsten is not currently achieving the requisite statutory level of safety should immediately notify FMCSA. The Agency will evaluate any adverse information submitted and, if safety is being compromised or if the continuation of the exemption is not consistent with 49 U.S.C. 31136(e) and 31315(b)(4), FMCSA will take immediate steps to revoke the exemption.
Federal Motor Carrier Safety Administration (FMCSA), DOT.
Notice of final disposition.
FMCSA renews an exemption held by 22 drivers of Rotel North American Tours, LLC (Rotel) to enable them to operate commercial motor vehicles (CMVs) in the U.S. with German commercial driver's licenses (CDLs) and without CDLs issued by one of the States. Rotel conducts tours of the U.S. on a seasonal basis for Europeans. It uses motor coaches that are equipped with onboard sleeping and eating facilities. The drivers, in addition to operating the CMVs, provide oral commentary in German. Rotel previously was able to conduct these operations without exemption because its drivers were able to obtain (and renew) non-resident CDLs from certain States. However, there are currently no States willing to issue non-resident CDLs.
This exemption is effective from July 31, 2010, through July 30, 2012.
Mr. Robert F. Schultz, Jr., FMCSA Driver and Carrier Operations Division, Office of Bus and Truck Standards and Operations.
Under 49 CFR part 383, operators of CMVs are required to possess a valid CDL issued by one of the States of the U.S. (49 CFR 383.23). Under 49 U.S.C. 31315 and 31136(e), FMCSA may grant an exemption from certain regulatory requirements, including the CDL requirements of 49 CFR part 383 for a 2-year period if it finds “such exemption would likely achieve a level of safety that is equivalent to, or greater than, the level of safety that would be achieved absent such exemption” (49 CFR 381.305(a)).
Rotel, headquartered in Terre Haute, Indiana, conducts bus tours of the United States, Canada, and Mexico for Europeans from the end of March through the middle of October each year. It currently has 22 bus drivers and 11 customized buses dedicated to these operations. Rotel states that it offers a unique touring experience in that each of its buses is equipped with a galley that allows Rotel to offer dining with European cuisine. In addition, each bus is equipped with sleeping accommodations for the passengers.
Rotel drivers operate the buses and deliver oral commentary in German during the tour. The Rotel buses are CMVs as defined in 49 CFR 383.5. Therefore, the operators of the buses must possess a valid U.S. CDL (49 CFR 383.23). At one time, Rotel's German drivers could obtain a non-resident CDL in most States. However, Rotel reports that because of heightened security concerns across the U.S., no State currently issues non-resident CDLs. Rotel requests that FMCSA continue to exempt its 22 bus drivers from the requirement that they possess a CDL issued by a State, so that the drivers may operate these 11 buses without a U.S. CDL on a seasonal basis for a period of 2 years.
Rotel's drivers are residents and citizens of Germany. They hold German CDLs, but the German CDL is not recognized in the U.S. Rotel prefers to use native German drivers to conduct the tours. Rotel experimented with using other drivers, but found that the quality of its tour service was affected adversely.
Rotel believes that each of these drivers possesses sufficient knowledge, skills, and experience to ensure a level of safety that is equivalent to, or greater than, the level of safety that would be obtained by complying with the requirement for a U.S. CDL. A copy of Rotel's application for exemption is available for review in the docket for this notice.
Drivers applying for a German-issued CDL must undergo a training program and pass knowledge and skills tests. FMCSA has previously determined in this matter that the process for obtaining a German-issued CDL adequately assesses the driver's ability to operate CMVs in the U.S. safely. Therefore, the process for obtaining a German-issued CDL is considered to be comparable to, or as effective as, the requirements of 49 CFR part 383 for obtaining a CDL in the U.S.
On June 14, 2010, FMCSA published notice of this application for renewal, and asked for public comment (75 FR 33661). No comments were received in the public docket by the close of the comment period.
The FMCSA has evaluated Rotel's application for renewal, and believes that Rotel's overall safety performance as reflected in its 2010 FMCSA “satisfactory” rating, as well as the knowledge and skills possessed by these drivers as a result of the training program to which all German CDL applicants are exposed, ensure that each of these 22 drivers will likely achieve a level of safety that is equivalent to, or greater than, the level of safety achieved without the exemption (49 CFR 381.305(a)). The Agency has granted the exemption for a two-year period, from July 31, 2010, through July 30, 2012, for the following Rotel drivers: Josef Dangl, Reinfried Dangl, Herbert Erber, Helmut Erbersdobler, Wilhelm Fuchs, Ludwig Gerlsberger, Christian Hafner, Peter Hess, Michael Huber, Gerhard Kinateder, Hermann Lichtenauer, Franz Manzinger, Fabian Maurer, Jens Radloff, Rudolf Ramsl, Paul Schlögl, Walter Schreiner, Josef Stockinger, Josef Vogl, Klaus Weber, Markus Wölfl, and Norbert Zechmeister.
This exemption is subject to the following terms and conditions: (1) That each driver is subject to the drug and alcohol regulations of 49 CFR part 382, including testing, (2) that each driver is subject to the same driver disqualification rules under 49 CFR parts 383 and 391 that apply to other CMV drivers in the United States, (3) that each driver keep a copy of the exemption on the vehicle at all times, (4) that Rotel notify FMCSA in writing of any accident, as defined in 49 CFR 390.5, involving these drivers, (5) that Rotel notify FMCSA in writing if any of these drivers is convicted of a disqualifying offense identified in section 383.51 or 391.15 of the FMCSRs.
In accordance with 49 U.S.C. 31315 and 31136(e), the exemption will be valid for 2 years unless earlier revoked by the FMCSA. The exemption will be revoked if: (1) The Rotel drivers fail to comply with the terms and conditions of the exemption, (2) the exemption results in a lower level of safety than was maintained before it was granted or (3) the exemption becomes inconsistent with the goals and objectives of 49 U.S.C. 31315 and 31136. Interested parties possessing information that would demonstrate that any or all of these drivers are not achieving the requisite statutory level of safety should immediately notify FMCSA. The Agency will evaluate any such
During the period the exemption is in effect, no State shall enforce any law or regulation that conflicts with or is inconsistent with the exemption with respect to a person operating under the exemption (49 U.S.C. 31315(d)).
Office of the Comptroller of the Currency (OCC), Treasury; Board of Governors of the Federal Reserve System (Board); Federal Deposit Insurance Corporation (FDIC); and Office of Thrift Supervision (OTS), Treasury.
Notice of information collection to be submitted to OMB for review and approval under the Paperwork Reduction Act of 1995.
In accordance with the requirements of the Paperwork Reduction Act of 1995 (44 U.S.C. chapter 35), the OCC, the Board, the FDIC, and the OTS (the “agencies”) may not conduct or sponsor, and the respondent is not required to respond to, an information collection unless it displays a currently valid Office of Management and Budget (OMB) control number. On May 21, 2010, the agencies, under the auspices of the Federal Financial Institutions Examination Council (FFIEC), requested public comment for 60 days on a proposal to extend, with revision, the Consolidated Reports of Condition and Income (Call Report) for banks, the Thrift Financial Report (TFR) for savings associations, the Report of Assets and Liabilities of U.S. Branches and Agencies of Foreign Banks (FFIEC 002), and the Report of Assets and Liabilities of a Non-U.S. Branch that is Managed or Controlled by a U.S. Branch or Agency of a Foreign (Non-U.S.) Bank (FFIEC 002S), all of which are currently approved collections of information. After responding to the one comment received on this proposal, which sought reporting guidance, the FFIEC and the agencies will implement the revision to the reports identified above as proposed.
Comments must be submitted on or before September 1, 2010.
Interested parties are invited to submit written comments to any or all of the agencies. All comments, which should refer to the OMB control number(s), will be shared among the agencies.
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Additionally, commenters may send a copy of their comments to the OMB desk officer for the agencies by mail to the Office of Information and Regulatory Affairs, U.S. Office of Management and Budget, New Executive Office Building, Room 10235, 725 17th Street, NW., Washington, DC 20503, or by fax to (202) 395-6974.
For further information about the revisions discussed in this notice, please contact any of the agency clearance officers whose names appear below. In addition, copies of the Call Report, FFIEC 002, and FFIEC 002S forms can be obtained at the FFIEC's Web site (
The agencies are proposing to revise and extend for three years the Call Report, the TFR, the FFIEC 002, and the FFIEC 002S, which are currently approved collections of information.
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The estimated time per response for the Call Report is an average that varies by agency because of differences in the composition of the institutions under each agency's supervision (e.g., size distribution of institutions, types of activities in which they are engaged, and existence of foreign offices). The average reporting burden for the Call Report is estimated to range from 16 to 655 hours per quarter, depending on an individual institution's circumstances.
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These information collections are mandatory: 12 U.S.C. 161 (for national banks), 12 U.S.C. 324 (for State member banks), 12 U.S.C. 1817 (for insured State nonmember commercial and savings banks), 12 U.S.C. 1464 (for savings associations), and 12 U.S.C. 3105(c)(2), 1817(a), and 3102(b) (for U.S. branches and agencies of foreign banks). Except for selected data items, the Call Report, the TFR, and the FFIEC 002 are not given confidential treatment. The FFIEC 002S is given confidential treatment [5 U.S.C. 552(b)(4)].
In October 2008, the FDIC Board of Directors adopted the Temporary Liquidity Guarantee Program (TLGP) following a determination of systemic risk by the Secretary of the Treasury (after consultation with the President) that was supported by recommendations from the FDIC and the Board. The TLGP is part of an ongoing and coordinated effort by the FDIC, the U.S. Department of the Treasury, and the Board to address unprecedented disruptions in the financial markets and preserve confidence in the American economy.
To facilitate the FDIC's administration of the TLGP, the FDIC Board approved an interim rule on October 23, 2008,
The TAG program originally was set to expire on December 31, 2009. The FDIC Board recognized that the TAG program was contributing significantly to improvements in the financial sector, and also noted that many parts of the country were still suffering from the effects of economic turmoil. As a result, on August 26, 2009, following a public notice and comment period, the FDIC Board extended the TAG program through June 30, 2010, with certain modifications to the program.
Since its inception, the TAG program has been an important source of stability for many banks with large transaction account balances. In the second quarter of 2010, over 6,300 insured depository institutions, representing approximately 80 percent of all FDIC-insured institutions, were participating in the TAG program and continued to benefit from the guarantee provided by the FDIC. These institutions held an estimated $356 billion of deposits in accounts currently subject to the FDIC's guarantee as of March 31, 2010. Of these, $280 billion represented amounts above the insured deposit limit and guaranteed by the FDIC through its TAG program.
To provide additional stability for participating insured depository institutions and enhance the likelihood of a continuing and sustainable economic recovery in the financial sector, on April 13, 2010, the FDIC Board adopted an interim rule (with a request for comment) extending the TAG program for six months through December 31, 2010, with the possibility of an additional 12-month extension, through December 31, 2011, without further rulemaking upon a determination by the FDIC Board that continuing economic difficulties warrant such an extension.
Following the public comment period for the April 2010 interim rule extending the TAG program, the FDIC Board adopted a final rule addressing the program on June 22, 2010, that is almost identical to the interim rule.
At present, institutions participating in the TAG program report the amount and number of qualifying noninterest-bearing transaction accounts of more than $250,000 as of the quarter-end report date in Call Report Schedule RC-O, Memorandum items 4.a and 4.b; TFR Schedule DI, items DI570 and DI575; and FFIEC 002 Schedule O, Memorandum items 4.a and 4.b. By the very nature of these transaction accounts, the account balances are volatile, fluctuating greatly on any given day due to the operational nature of the deposits, such as for payrolls, and withdrawals made by typical business customers. Therefore, in response to the modification of the basis upon which a participating institution's assessment is calculated from quarter-end reporting to average daily balance reporting for TAG program-related accounts that is contained in the FDIC's April 2010 interim rule, the agencies requested comment on May 21, 2010, on a proposal to change the basis for reporting in the items identified above.
The agencies received one comment on the proposed revision of the TAG program reporting requirements. The commenter, a bank consultant, sought information concerning the calculation of TAG program average daily balances and was directed to the guidance on this subject, including an example, that had been posted on the FDIC's Web site.
The agencies also note that Section 343 of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Pub. L. 111-203, July 21, 2010) contains provisions amending the Federal Deposit Insurance Act with respect to the insurance coverage of noninterest-bearing transaction accounts. These provisions take effect December 31, 2010, and will affect the FDIC's TAG program. Should there be a need to further revise the TAG program-related data collected in the Call Report, the TFR, and the FFIEC 002 as a result of the recently enacted legislation and any subsequent rulemaking by the FDIC, the agencies will implement these revisions in accordance with the requirements of the Paperwork Reduction Act of 1995.
Public comment is requested on all aspects of this joint notice. Comments are invited on:
(a) Whether the proposed revisions to the collections of information that are the subject of this notice are necessary for the proper performance of the agencies' functions, including whether the information has practical utility;
(b) The accuracy of the agencies' estimates of the burden of the information collections as they are proposed to be revised, 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 information collections on respondents, including through the use of automated collection techniques or other forms of information technology; and
(e) Estimates of capital or start up costs and costs of operation, maintenance, and purchase of services to provide information.
Comments submitted in response to this joint notice will be shared among the agencies. All comments will become a matter of public record.
Board of Governors of the Federal Reserve System, July 26, 2010.
Office of Thrift Supervision (OTS), Treasury.
Notice and request for comment.
The proposed information collection request (ICR) described below has been submitted to the Office of Management and Budget (OMB) for review and approval, as required by the Paperwork Reduction Act of 1995. OTS is soliciting public comments on the proposal.
Submit written comments on or before September 1, 2010. A copy of this ICR, with applicable supporting documentation, can be obtained from RegInfo.gov at
Send comments, referring to the collection by title of the proposal or by OMB approval number, to OMB and OTS at these addresses: Office of Information and Regulatory Affairs, Attention: Desk Officer for OTS, U.S. Office of Management and Budget, 725—17th Street, NW., Room 10235, Washington, DC 20503, or by fax to (202) 395-6974; and Information Collection Comments, Chief Counsel's Office, Office of Thrift Supervision, 1700 G Street, NW., Washington, DC 20552, by fax to (202) 906-6518, or by e-mail to
For further information or to obtain a copy of the submission to OMB, please contact Ira L. Mills at,
OTS may not conduct or sponsor an information collection, and respondents are not required to respond to an information collection, unless the information collection displays a currently valid OMB control number. As part of the approval process, we invite comments on the following information collection.
Veterans Benefits Administration, Department of Veterans Affairs.
Notice.
The Veterans Benefits Administration (VBA), 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 October 1, 2010.
Submit written comments on the collection of information through Federal Docket Management System (FDMS) at
Nancy J. Kessinger at (202) 461-9769 or FAX (202) 275-5947.
Under the PRA of 1995 (Pub. L. 104-13; 44 U.S.C. 3501-3521), Federal agencies must obtain approval from 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, VBA invites comments on: (1) Whether the proposed collection of information is necessary for the proper performance of VBA's functions, including whether the information will have practical utility; (2) the accuracy of VBA'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.
By direction of the Secretary.
Veterans Benefits Administration, Department of Veterans Affairs.
Notice.
The Veterans Benefits Administration (VBA) is announcing an
Written comments and recommendations on the proposed collection of information should be received on or before October 1, 2010.
Submit written comments on the collection of information through Federal Docket Management System (FDMS) at
Nancy J. Kessinger at (202) 461-9769 or FAX (202) 275-5947.
Under the PRA of 1995 (Pub. L. 104-13; 44 U.S.C. 3501-3521), Federal agencies must obtain approval from 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, VBA invites comments on: (1) Whether the proposed collection of information is necessary for the proper performance of VBA's functions, including whether the information will have practical utility; (2) the accuracy of VBA'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.
By direction of the Secretary.
Veterans Health Administration, Department of Veterans Affairs.
Notice.
The Veterans Health Administration (VHA) 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 September 1, 2010.
Submit written comments on the collection of information through Federal Docket Management System (FDMS) at
Mary Stout (202) 461-5867 or FAX (202) 273-9381.
Under the PRA of 1995 (Pub. L. 104-13; 44 U.S.C. 3501-3521), 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, VHA invites comments on: (1) Whether the proposed collection of information is necessary for the proper performance of VHA's functions, including whether the information will have practical utility; (2) the accuracy of VHA'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. Veterans Application for Assistance in Acquiring Home Improvement and Structural Alterations, VA Form 10-0103.
b. Application for Adaptive Equipment Motor Vehicle, VA Form 10-1394.
c. Prosthetic Authorization for Items or Services, VA Form 10-2421.
d. Prosthetic Service Card Invoice, VA Form 10-2520.
e. Prescription and Authorization for Fee Basis Eyeglasses, VA Form 10-2914.
f. Request to Submit Quotation, Form Letter 10-90.
a. VA Form 10-0103 is used to determine eligibility/entitlement and reimbursement of individual claims for home improvement and structural alterations.
b. VA Form 10-1394 is used to determine eligibility/entitlement and reimbursement of individual claims for automotive adaptive equipment.
c. VA Form 10-2421 is used for the direct procurement of new prosthetic appliances and/or services.
d. VA Form 10-2520 is used by the vendors as an invoice and billing document. The form standardizes repair/treatment invoices for prosthetic services rendered and standardizes the verification of these invoices. The veteran certifies that the repairs were necessary and satisfactory. This form is furnished to vendors upon request.
e. VA Form 10-2914 is used as a combination prescription, authorization and invoice as well as to purchase eyeglasses directly for Veterans.
f. VA Form Letter 10-90 is used to obtain to a quotation price for prosthetic devices.
a. VA Form 10-0103—583.
b. VA Form 10-1394—1,000.
c. VA Form 10-2421—67.
d. VA Form 10-2520—47.
e. VA Form 10-2914—3,333.
f. Form Letter 10-90—708.
a. VA Form 10-0103—5 minutes.
b. VA Form 10-1394—15 minutes.
c. VA Form 10-2421—4 minutes.
d. VA Form 10-2520—4 minutes.
e. VA Form 10-2914—4 minutes.
f. Form Letter 10-90—5 minutes.
a. VA Form 10-0103—7,000.
b. VA Form 10-1394—4,000.
c. VA Form 10-2421—1,000.
d. VA Form 10-2520—700.
e. VA Form 10-2914—50,000.
f. Form Letter 10-90—8,500.
By direction of the Secretary.
Veterans Health Administration, Department of Veterans Affairs.
Notice.
The Veterans Health Administration (VHA), 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 October 1, 2010.
Submit written comments on the collection of information through the Federal Docket Management System (FDMS) at
Mary Stout (202) 461-5867 or FAX (202) 273-9387.
Under the PRA of 1995 (Pub. L. 104-13; 44 U.S.C. 3501-3521), Federal agencies must obtain approval from 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, VHA invites comments on: (1) Whether the proposed collection of information is necessary for the proper performance of VHA's functions, including whether the information will have practical utility; (2) the accuracy of VHA'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.
By direction of the Secretary.
Veterans Benefits Administration, Department of Veterans Affairs.
Notice.
In compliance with the Paperwork Reduction Act (PRA) of 1995 (44 U.S.C. 3501-3521), this notice announces that the Veterans Benefits Administration (VBA), Department of Veterans Affairs, will submit the collection of information abstracted below to the Office of Management and Budget (OMB) for review and comment. The PRA submission describes the nature of the information collection and its expected cost and burden; it includes the actual data collection instrument.
Comments must be submitted on or before September 1, 2010.
Submit written comments on the collection of information through
Denise McLamb, Enterprise Records Service (005R1B), Department of
An agency may not conduct or sponsor, and a person is not required to respond to a collection of information unless it displays a currently valid OMB control number. The
By direction of the Secretary.
Environmental Protection Agency (EPA).
Proposed rule.
EPA is proposing to limit the interstate transport of emissions of nitrogen oxides (NO
Submit your comments, identified by Docket ID No. EPA-HQ-OAR-2009-0491 by one of the following methods:
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Mr. Tim Smith, Air Quality Policy Division, Office of Air Quality Planning and Standards (C539-04), Environmental Protection Agency, Research Triangle Park, NC 27711; telephone number: (919) 541-4718; fax number: (919) 541-0824; e-mail address:
The following are abbreviations of terms used in the preamble.
This rule affects EGUs, and regulates the following groups:
This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be regulated by this action. This table lists the types of entities that EPA is aware of that could potentially be regulated. Other types of entities not listed in the table could also be regulated. To determine whether your facility would be regulated by the proposed rule, you should carefully examine the applicability criteria in proposed §§ 97.404, 97.504, 97,604, and 97.704.
In addition to being available in the docket, an electronic copy of this proposal will also be available on the World Wide Web. Following signature by the EPA Administrator, a copy of this action will be posted on the transport rule Web site
1.
2.
• Identify the rulemaking by docket number and other identifying information (subject heading,
• 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.
• Explain why you agree or disagree; suggest alternatives and substitute language for your requested changes.
• Describe any assumptions and provide any technical information and/or data that you used.
• If you estimate potential costs or burdens, explain how you arrived at your estimate in sufficient detail to allow for it to be reproduced.
• Provide specific examples to illustrate your concerns, and suggest alternatives.
• Explain your views as clearly as possible, avoiding the use of profanity or personal threats.
• Make sure to submit your comments by the comment period deadline identified.
The EPA will hold three public hearings on this proposal. The dates, times and locations of the pubic hearings will be announced separately. Oral testimony will be limited to 5 minutes per commenter. The EPA encourages commenters to provide written versions of their oral testimonies either electronically or in paper copy. Verbatim transcripts and written statements will be included in the rulemaking docket. If you would like to present oral testimony at one of the hearings, please notify Ms. Pamela S. Long, Air Quality Policy Division (C504-03), U.S. EPA, Research Triangle Park, NC 27711, telephone number (919) 541-0641; e-mail:
CAA section 110(a)(2)(D)(i)(I) requires states to prohibit emissions that contribute significantly to nonattainment in, or interfere with maintenance by, any other state with respect to any primary or secondary NAAQS. In this notice, EPA proposes to find that emissions of SO
With respect to the annual average PM
With respect to the 1997 ozone NAAQS, this proposal requires emissions reductions in 26 states. For 16 of these states, we propose that the required reductions represent their full significant contribution and interference with maintenance for the ozone NAAQS. For an additional 10 states, the required NO
This proposed rule would achieve substantial near-term emissions reductions from the power sector. EPA projects that with the proposed rule, EGU SO
EPA is committed to fulfilling its responsibility to ensure that downwind states receive the relief from upwind emissions guaranteed under CAA section 110(a)(2)(D) For the 24-hour PM
In the case of ozone, EPA must determine whether further NO
This proposed rule is the first of several EPA rules to be issued over the next 2 years that will yield substantial health and environmental benefits for the public through regulation of power plants. Fossil-fuel-fired power plants contribute a large and substantial fraction of the emissions of several key air pollutants, and the agency has statutory or judicial obligations to make several regulatory determinations on power plant emissions. The Administrator in January established improved air quality as an Agency priority and announced plans to promote a cleaner and more efficient power sector and have strong but achievable reduction goals for SO
In addition to this rule, other anticipated actions include a section 112(d) rule for electric utilities to be proposed by March 2011, potential rules to address pollution transport under revised NAAQS, revisions to new source performance standards for coal and oil-fired utility electric generating units, and best available retrofit technology (BART) and regional haze program requirements to protect visibility. These actions, and their relationship to this rule, are discussed further in section III.E.
Ongoing reviews of the ozone and PM
With this proposal, EPA is also responding to the remand of the CAIR by the Court in 2008. CAIR, promulgated May 12, 2005 (70 FR 25162) requires 28 states and the District of Columbia to adopt and submit revisions to their State Implementation Plans (SIPs) to eliminate SO
As described more fully in the remainder of this preamble, the approaches used in this proposed rule to measure and address each state's significant contribution to downwind nonattainment and interference with maintenance are guided by and consistent with the Court's opinion in
In this action, EPA proposes to both identify and address emissions within states in the eastern United States that significantly contribute to nonattainment or interfere with maintenance by other downwind states. As discussed in sections III and VII in this preamble and described in greater detail in two separate
As described in section IV in this preamble, EPA is proposing a state-specific methodology to identify specific reductions that states in the eastern United States must make to satisfy the CAA section 110(a)(2)(D)(i)(I) prohibition on emissions that significantly contribute to nonattainment or interfere with maintenance in a downwind state. The proposed methodology uses state-specific inputs and focuses on the emissions reductions available in each individual state to address the Court's concern that the approach used in CAIR (which identified a single level of emissions achievable by the application of highly cost effective controls in the region) was insufficiently state specific. The proposed methodology uses air quality analysis to determine whether a state's contribution to downwind air quality problems is above specific thresholds. If a state's contribution does not exceed those thresholds, its contribution is found to be insignificant and it is no longer considered in the analysis. If a state's contribution exceeds those thresholds, EPA takes a second step that uses a multi-factor analysis that takes into account both air quality and cost considerations to identify the portion of a state's contribution that is significant or that interferes with maintenance. Section 110(a)(2)(D) requires states to eliminate the emissions that constitute this “significant contribution” and “interference with maintenance.”
This proposed methodology for determining upwind state emission reduction responsibility is designed to be applicable to current and potential future ozone and PM
To facilitate implementation of the requirement that significant contribution and interference with maintenance be eliminated, EPA developed state emissions budgets. By tying these budgets directly to EPA's quantification of each individual state's significant contribution and interference with maintenance, EPA directly linked the budgets to the mandate in section 110(a)(2)(D)(i)(I), and thus addressed the Court's concerns about the development of budgets for the CAIR. EPA also addressed these concerns by completely eschewing any consideration or reliance on Fuel Adjustment Factors and the existing allocation of Title IV allowances.
These new emissions budgets are based on the Agency's state-by-state analysis of each upwind state's significant contribution to nonattainment and interference with maintenance downwind. A state's emissions budget is the quantity of emissions that would remain after elimination of the part of significant contribution and interference with maintenance that EPA has identified in an average year (
EPA recognizes that baseline emissions from a state can be affected by changing weather patterns, demand growth, or disruptions in electricity supply from other units. As a result, emissions could vary from year to year in a state where covered sources have installed all controls and taken all measures necessary to eliminate the state's significant contribution and interference with maintenance. As described in detail in section IV of this preamble, EPA proposes to account for the inherent variability in power system operations through “assurance provisions” based on state variability limits which extend above the state emissions budgets.
EPA is also proposing FIPs to immediately implement the emission reduction requirements identified and quantified by EPA in this action. For some covered states, these FIPs will completely satisfy the emissions reductions requirements of 110(a)(2)(D)(i)(I) with respect to the 1997 and 2006 PM
The emissions reductions requirements (
The proposed FIPs would regulate EGUs in the 32 covered states. EPA is proposing to regulate these sources through a program that uses state-specific budgets and allows intrastate and limited interstate trading. EPA is also taking comment on two alternative regulatory options. All options would achieve the emissions reductions necessary to address the emissions transport requirements in section 110(a)(2)(D)(i)(I) of the CAA.
The option EPA is proposing for the FIPs (“State Budgets/Limited Trading”) would use state-specific emissions budgets and allow for intrastate and limited interstate trading. This approach would assure environmental results while providing some limited flexibility to covered sources. The approach would also facilitate the transition from CAIR to the Transport Rule for implementing agencies and covered sources.
The first alternative remedy option for which EPA requests comment would use state-specific emissions budgets and allow intrastate trading, but prohibit interstate trading. The second alternative remedy option, for which EPA also requests comment, would use state-specific budgets and emissions rate limits. See section V for further discussion of the remedy options.
The proposed remedy option and the first alternative, both of which are cap-and-trade approaches, would use new allowance allocations developed on a different basis from CAIR. Allowance allocations, like the state budgets described previously, would be developed based on the methodology used by EPA to quantify each state's significant contribution and interference with maintenance.
In this action, EPA proposes to require reductions in SO
EPA proposes to require reductions in SO
EPA also proposes to require reductions in ozone season NO
As discussed previously, EPA also is proposing FIPs to directly regulate EGU SO
In response to the Court's opinion in
As discussed previously, EPA is proposing new SO
As discussed in detail in section IV, the proposed approach to significant contribution to nonattainment and interference with maintenance would group the 28 states covered for the 24-hour and/or annual PM
The proposed stringent SO
As discussed previously, EPA proposes to require an initial phase of reductions starting in 2012 (covering 2012 and 2013) requiring SO
For the 15 states in the stringent SO
The 2014 annual NO
With respect to the ozone NAAQS, EPA is proposing a single phase of reductions which begins in 2012. Thus, the rule does not call for any adjustment to be made to the 2012 ozone season NO
Tables III.A-2 and III.A-3 show projected Transport Rule emissions reductions for EGUs in all states that EPA proposes to cover.
In
Table III.A-4 compares projected EGU emissions with the Transport Rule to projected EGU emissions with CAIR.
In addition to discussion of EPA's proposed regulatory approach (discussed in sections IV and V), this preamble also covers the stakeholder outreach EPA conducted (section VI), SIP submissions (section VII), permitting (section VIII), projected benefits of the proposed rule (section IX), economic impacts (section X), end-use energy efficiency (section XI), and statutory and executive order reviews (section XII).
Table III.A-5 shows the results of the cost and benefits analysis for the proposed and alternate remedies. Further discussion of these results is contained in preamble section XII-A and in the Regulatory Impacts Analysis. A listing of health and welfare effects is provided in RIA Table 1-6. Estimates here are subject to uncertainties discussed further in the body of the document. The social costs are the loss of household utility as measured in Hicksian equivalent variation. The capital costs spent for pollution controls installed for CAIR were not included in the annual social costs since the Transport Rule did not lead to their installation. Those CAIR-related capital investments are roughly estimated to have an annual social cost less than $1.15 to $ 1.29 billion (under the two discount rates.)
Most of the estimated PM-related benefits in this rule accrue to populations exposed to higher levels of PM
The statutory authority for this action is provided by the CAA, as amended (42 U.S.C. 7401
Section 110(a)(2)(D) of the CAA, often referred to as the “good neighbor” provision of the Act, requires states to prohibit certain emissions because of their impact on air quality in downwind states. Specifically, it requires all states, within 3 years of promulgation of a new or revised NAAQS, to submit SIPs that:
(D) Contain adequate provisions—
(i) Prohibiting, consistent with the provisions of this subchapter, any source or other type of emissions activity within the State from emitting any air pollutant in amounts which will—
(I) 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 standard, or
(II) Interfere with measures required to be included in the applicable implementation plan for any other State under part C of this subchapter to prevent significant deterioration of air quality or to protect visibility.
(ii) Insuring compliance with the applicable requirements of sections 7426 and 7415 of this title (relating to interstate and international pollution abatement). 42 U.S.C. 7410(a)(2)(D).
This proposal addresses the requirement in section 110(a)(2)(D)(i)(I) regarding the prohibition of emissions within a state that significantly contribute to nonattainment or interfere with maintenance of the NAAQS in any other state. As discussed in greater detail later, EPA has previously issued two rules interpreting and clarifying the requirements of section 110(a)(2)(D)(i)(I). The NO
Section 301(a)(1) of the CAA gives the Administrator of EPA general authority to “prescribe such regulations as are necessary to carry out [her] functions under this chapter.” 42 U.S.C. 7601(a)(1). Pursuant to this section, EPA has authority to clarify the applicability of CAA requirements. In this action,
Section 110(a) of the CAA assigns to each state both the primary responsibility for attaining and maintaining the NAAQS within such state, 42 U.S.C. 7410(a)(1), and the primary responsibility for prohibiting emissions activity within the state which will significantly contribute to nonattainment or interfere with maintenance in a downwind area. 42 U.S.C. 7410(a)(2)(D)(i)(I). States fulfill these CAA obligations through the SIP process described in section 110(a) of the Act.
Section 110(c)(1) of the Act, however, requires EPA to act when a state has not been able to or has not fulfilled its obligation to submit a SIP that meets the requirements of the Act. Specifically, section 110(c)(1) provides that: The Administrator shall promulgate a Federal implementation plan at any time within 2 years after the Administrator—
(A) Finds that a State has failed to make a required submission or finds that the plan or plan revision submitted by the State does not satisfy the minimum criteria established under subsection (k)(1)(A) of this section, or
(B) Disapproves a State implementation plan submission in whole or part, unless the State corrects the deficiency, and the Administrator approves the plan or plan revision, before the Administrator promulgates such Federal implementation plan.
42 U.S.C. 7410(c)(1). Section 110(k)(1)(A), in turn, calls for the Administrator to establish criteria for determining whether SIP submissions are complete. 42 U.S.C. 7410(k)(1)(A).
As discussed in greater detail in section VII, for all states covered by the FIPs proposed in this action, EPA either has taken, has proposed to take, or believes it may need to take one of the following actions with respect to the 1997 ozone NAAQS, the 1997 PM
Fine particles are associated with a number of serious health effects including premature mortality, aggravation of respiratory and cardiovascular disease (as indicated by increased hospital admissions, emergency room visits, health-related absences from school or work, and restricted activity days), lung disease, decreased lung function, asthma attacks, and certain cardiovascular problems.
In addition to effects on public health, fine particles are linked to a number of public welfare effects. First, PM
In 1997, EPA revised the NAAQS for PM to add new annual average and 24-hour standards for fine particles, using PM
In the preamble to the final rule for CAIR in May 2005, EPA discussed ambient monitoring for 2001-2003, the most recent 3-year period available at the time. These results showed widespread exceedances of the 15 μg/m
The PM
The PM
EPA believes that a great deal of the improvement in PM
As required by the CAA, and in response to litigation over the 2006 standards, EPA is currently conducting a review of the 2006 PM
Short-term (1- to 3-hour) and prolonged (6- to 8-hour) exposures to ambient ozone have been linked to a number of adverse health effects. At sufficient concentrations, short-term exposure to ozone can irritate the respiratory system, causing coughing, throat irritation, and chest pain. Ozone can reduce lung function and make it more difficult to breathe deeply. Breathing may become more rapid and shallow than normal, thereby limiting a person's normal activity. Ozone also can aggravate asthma, leading to more asthma attacks that may require a doctor's attention and the use of additional medication. Increased hospital admissions and emergency room visits for respiratory problems have been associated with ambient ozone exposures. Longer-term ozone exposure can inflame and damage the lining of the lungs, which may lead to permanent changes in lung tissue and irreversible reductions in lung function. A lower quality of life may result if the inflammation occurs repeatedly over a long time period (such as months, years, or a lifetime). There is also recent epidemiological evidence indicating that there is a correlation between short-term ozone exposure and premature mortality.
People who are particularly susceptible to the effects of ozone include people with respiratory diseases, such as asthma. Those who are exposed to higher levels of ozone include adults and children who are active outdoors. This rule, and the NAAQS which it is related to, consider the effects of ozone on vulnerable populations (
In addition to causing adverse health effects, ozone affects vegetation and ecosystems, leading to reductions in agricultural crop and commercial forest yields; reduced growth and survivability of tree seedlings; and increased plant susceptibility to disease, pests, and other environmental stresses (
In 1997, at the same time we revised the PM
At the time EPA published the CAIR and the CAIR FIP rulemakings, wide geographic areas, including most of the nation's major population centers, experienced ozone levels that violated the 1997 NAAQS of 8-hour ozone 0.08 ppm (effectively 0.084 ppm as a result of rounding). These areas included much of the eastern part of the United States and large areas of California. The EPA published the 8-hour ozone attainment and nonattainment designations in the
Second, mobile source emissions standards for onroad gasoline and vehicle emissions standards began to reduce mobile source emissions as the fleet began turning over vehicles to meet tightened NO
On March 12, 2008, EPA published a revision to the 8-hour ozone standard, lowering the level from 0.08 ppm to 0.075 ppm. On September 16, 2009, EPA announced it would reconsider these 2008 ozone standards. The purpose of the reconsideration is to ensure that the ozone standards are clearly grounded in science, protect public health with an adequate margin of safety, and are sufficient to protect the environment. EPA proposed revisions to the standards on January 19, 2010 (75 FR 2938) and will issue final standards soon. Information on the 2008 revisions to the ozone standard, and on all subsequent activity based on the reconsideration, is available at:
This proposed action addresses the requirements of CAA section 110(a)(2)(D)(i)(I) as they relate to:
(1) The 1997 annual PM
(2) The 2006 daily PM
(3) The 1997 ozone standards
The original CAIR and CAIR FIP rules, which pre-dated the 2006 standards, addressed the 1997 ozone and PM
For this proposal, EPA fully addresses the requirements of CAA section 110(a)(2)(D)(i)(I) for the annual PM
This action does not address the CAA section 110(a)(2)(D)(i)(I) requirements for the revised ozone standards promulgated in 2008. These standards are currently under reconsideration. We are, however, actively conducting the technical analyses and other work needed to address interstate transport for the reconsidered ozone standard as soon as possible. We intend to issue as soon as possible a proposal to address the transport requirements with respect to the reconsidered standard.
For almost 40 years, Congress has focused major efforts on curbing ground-level ozone. In 1970, Congress amended the CAA to require, in Title I, that EPA issue and periodically review and, if necessary, revise NAAQS for ubiquitous air pollutants (sections 108 and 109). Congress required the states to submit SIPs to attain and maintain those NAAQS, and Congress included, in section 110, a list of minimum requirements that SIPs must meet. Congress anticipated that areas would attain the NAAQS by 1975.
In 1977, Congress amended the CAA by providing, among other things, additional time for areas that were not attaining the ozone NAAQS to do so, as well as by imposing specific SIP requirements for those nonattainment areas. These provisions first required the designation of areas as attainment, nonattainment, or unclassifiable, under section 107; and then required that SIPs for ozone nonattainment areas include the additional provisions set out in part D of Title I, as well as demonstrations of attainment of the ozone NAAQS by either 1982 or 1987 (section 172).
In addition, the 1977 Amendments included two provisions focused on interstate transport of air pollutants: the predecessor to current section 110(a)(2)(D), which requires SIPs for all areas to constrain emissions with certain adverse downwind effects; and section 126, which, in general, authorizes a downwind state to petition EPA to impose limits directly on upwind sources found to adversely affect that state. Section 110(a)(2)(D)(i)(I), which is key to the present action, is described in more detail later.
In 1990, Congress amended the CAA to better address, among other things, continued nonattainment of the 1-hour ozone NAAQS, the requirements that would apply if EPA revised the 1-hour standard, and transport of air pollutants across state boundaries (Pub. L. 101-549, Nov. 15, 1990, 104 Stat. 2399, 42 U.S.C. 7401-7671q).
As amended in 1990, the CAA further requires EPA to designate areas as attainment, nonattainment, and unclassifiable under a revised NAAQS (section 107(d)(1); section 6103, Pub. L. 105-178). The CAA authorizes EPA to classify areas that are designated nonattainment under the new NAAQS and to establish for those areas attainment dates that are as expeditious as practicable, but not to exceed 10 years from the date of designation (section 172(a)).
All areas are required to submit SIPs within certain timeframes (section 110(a)(1)), and those SIPs must include specified provisions, under section 110(a)(2). In addition, SIPs for nonattainment areas are generally required to include additional specified control requirements, as well as controls providing for attainment of any revised NAAQS and periodic reductions providing “reasonable further progress” in the interim (section 172(c)). If states do not submit SIPs in a timely or approvable manner, EPA has the authority to make findings of failure to submit or impose FIPs on specific sources in the state that contribute to downwind nonattainment and interference with maintenance. Significant contribution and interference with maintenance are discussed in detail in section IV later.
The 1990 Amendments reflect general awareness by Congress that ozone is a regional, and not merely a local, problem. Ozone and its precursors may be transported long distances across state lines, thereby exacerbating ozone problems downwind. Ozone transport is recognized as a major reason for the persistence of the ozone problem, notwithstanding the imposition of numerous controls, both Federal and State, across the country.
The CAA further addresses interstate transport of pollution in section 126, which Congress revised slightly in 1990. Subsection (b) of that provision authorizes each state (or political subdivision) to petition EPA for a finding designed to protect that entity from upwind sources of air pollutants.
In addition, the 1990 Amendments added section 184, which delineates a multi-state ozone transport region (OTR) in the Northeast, requires specific additional controls for all areas (not only nonattainment areas) in that region, and establishes the Ozone Transport Commission (OTC) for the purpose of recommending to EPA regionwide controls affecting all areas in that region. At the same time, Congress added section 176A, which authorized the formation of transport regions for other pollutants and in other parts of the country.
In September 1994, the Northeast OTC states signed a Memorandum of Understanding (MOU) committing to reduce NO
Separate from activity in the OTC, EPA and the Environmental Council of the States (ECOS) formed the OTAG in 1995. This workgroup brought together interested states and other stakeholders, including industry and environmental groups. Its primary objective was to assess the ozone transport problem and develop a strategy for reducing ozone pollution throughout the eastern half of the United States.
Notwithstanding significant efforts, the states generally were not able to meet the November 15, 1994 statutory deadline for the attainment demonstration and rate of progress (ROP) SIP submissions required under section 182(c). The major reason for this failure was that at that time, states with downwind nonattainment areas were not able to address transport from upwind areas. As a result, EPA recognized that development of the necessary technical information, as well as the control measures necessary to achieve the large level of reductions likely to be required, had been particularly difficult for the states affected by ozone transport.
Accordingly, as an administrative remedial matter, EPA established new timeframes for the required SIP submittals. To allow time for states to incorporate the results of the OTAG
OTAG was established to address transport issues associated with meeting the 1-hour standard. The EPA did not promulgate the 8-hour standard until shortly after OTAG concluded; thus, OTAG did not recommend strategies to address the 8-hour NAAQS. However, because EPA had proposed an 8-hour standard, OTAG did examine the impacts of different strategies on 8-hour average ozone predictions. They found that ozone transport caused problems for downwind areas under either the 1-hour or 8-hour standard.
The EPA published a supplemental notice of proposed rulemaking (SNPR) dated May 11, 1998 (63 FR 25902), which proposed a model NO
The pre-existing 1-hour secondary ozone standard was replaced by an 8-hour standard identical to the new primary standard. The new secondary standard provided increased protection to the public welfare against ozone-induced effects on vegetation.
Based on the findings of OTAG, EPA proposed a rulemaking known as the NO
In response to litigation over EPA's final NO
The NO
It was also EPA's goal to ensure that sufficient regional reductions were achieved to mitigate ozone transport in the eastern half of the United States and thus, in conjunction with local controls, enable nonattainment areas to attain and maintain the ozone NAAQS.
This NO
The SIP requirements permitted each state to determine what measures to adopt to prohibit the significant amounts and hence meet the necessary emissions budget. Consistent with OTAG's recommendations to achieve decreased NO
Several petitioners challenged the NO
The decision resolved only issues involving the 1-hour ozone NAAQS and did not resolve any issues involving the 8-hour NAAQS, which provided another basis for the rule.
The NBP was a market-based cap and trade program created to reduce the regional transport of emissions of NO
EPA stopped administering the NBP at the conclusion of 2008 control period activities. States still have the emissions reductions requirement and could use the CAIR NO
Following promulgation of the new NAAQS in 1997, the CAA required all states, regardless of whether they have attainment air quality in all areas, to submit SIPs containing provisions specified under section 110(a)(2). In addition, states are required to submit SIPs for nonattainment areas which are generally required to include additional emissions controls providing for attainment of the NAAQS.
As described previously, section 110(a)(2)(D)(i)(I) provides a tool for addressing the problem of transported pollution that significantly contributes to downwind nonattainment and maintenance problems. Under section 110(a)(2)(D), a SIP must contain adequate provisions prohibiting sources in the state from emitting air pollutants in amounts that would contribute significantly to nonattainment or interfere with maintenance in one or more downwind states. Section 110(k)(5) authorizes EPA to find that a SIP is substantially inadequate to meet any CAA requirement. If EPA makes such a finding, it is to require the state
Sulfur dioxide and NO
The CAA contains a number of requirements to address nonattainment of the PM
In the CAIR, promulgated on May 12, 2005 (70 FR 25162), EPA required SIP revisions in 28 states and the District of Columbia, within 18 months after publication of the notice of final rulemaking, to ensure that certain emissions of SO
The CAIR built on EPA's efforts in the NO
CAIR was designed to provide significant air quality attainment, health, and environmental improvements across the eastern U.S. in a highly cost-effective manner by reducing SO
In addition to promulgating findings of significant contribution to nonattainment, EPA assigned emissions reductions requirements for SO
Section V.D.1 discusses the approach taken in CAIR using three model multi-state cap and trade programs for SO
The requirements in the CAIR were intended to address regional interstate transport of air pollution. EPA recognized, however, that additional local reductions might be necessary to bring some areas into attainment even after significantly contributing upwind emissions were eliminated. 70 FR 25165-66, May 12, 2005. In addition, states that shared an interstate nonattainment area were expected to work together in developing the nonattainment SIP for that area, reducing emissions that contributed to local-scale interstate transport problems.
As the control strategy for the FIPs, EPA adopted the model cap and trade programs that it provided in the CAIR as a control option for states, with minor changes to account for federal, rather than state, implementation. The FIPs required power plants in affected states to participate in one or more of three separate emissions cap and trade programs that cover: (1) Annual SO
The FIPs also provided states with an option to submit abbreviated SIPs to meet CAIR. Under this option, states could save the time and resources needed to develop the complete trading program SIP, while still being able to make key decisions, such as the methodology for allocating annual and/or ozone season NO
(6) Legal Challenges to the CAIR
Petitions for review challenging various aspects of the CAIR were filed in the U.S. Court of Appeals for the DC Circuit. In
Although the entire rule was remanded, important parts of EPA's rulemaking were upheld by the Court in its July 2008 ruling. The Court upheld key aspects of the air quality modeling portion of EPA's significant contribution analysis. It upheld EPA's decision to consider upwind states for inclusion in the CAIR only if those states contributed to projected nonattainment in 2010.
The Court also found significant flaws in EPA's approach. The Court emphasized the importance of individual state contributions to downwind nonattainment areas and held that EPA had failed to adequately measure significant contribution from sources within an individual state to downwind nonattainment areas in other states.
The Court further rejected the state budgets for SO
Building on the emissions reductions under the NBP and Acid Rain Program (ARP), CAIR was designed to permanently lower emissions of SO
In developing this proposed rule, EPA was guided by a number of goals and guiding principles, as discussed in this section of the preamble.
Most importantly, this proposal responds to the remand of the CAIR by the Court. As noted previously, the Court granted several petitions for review of the CAIR, finding fatal flaws with the rule; yet, it ultimately decided to remand the rule without vacatur to preserve the environmental benefits of the rule.
The action EPA is proposing would respond to the July and December 2008 opinions of the DC Circuit and correct the flaws in the CAIR methodology that were identified by the Court. The action responds to the Court's concerns in numerous ways. The methodology used to measure each state's significant contribution emphasizes air quality considerations and uses state specific data and information. The methodology also gives independent meaning to the interfere with maintenance prong of section 110(a)(2)(D)(i)(I). The state budgets for SO
The action would also propose FIPs which would replace the remanded CAIR FIPs. The proposed FIPs would apply to all states covered by the rule, including those for which EPA had previously approved SIPs under the remanded CAIR. If finalized as proposed, these FIPs would eliminate or, at a minimum, make measurable progress towards eliminating emissions of SO
This proposed rule is designed to address the requirements of section 110(a)(2)(D)(i)(I) of the CAA as they
States are obligated to submit SIPs to EPA addressing the provisions of section 110(a)(2), including the transport provisions of section 110(a)(2)(D)(i)(I), within 3 years of the promulgation of a new or revised NAAQS. For the 1997 NAAQS, these SIPs were due in 2000. On April 25, 2005 (effective May 25, 2005) EPA issued findings that states had failed to submit SIPs to satisfy the requirements of section 110(a)(2)(D)(i) of the Act under the 1997 ozone and PM
Revisions to the 1997 PM
This proposed rule, in concert with other actions, largely eliminates upwind state emissions that contribute significantly to nonattainment in, or interfere with maintenance by, any other state with respect to the 1997 8-hour ozone NAAQS. EPA will issue a subsequent proposal for the 1997 8-hour ozone NAAQS to address fully the requirements of CAA Section 110(a)(2)(D)(i)(I). EPA's goal is to fully address transport requirements for the 1997 ozone standards as soon as possible.
In addressing the Court remand in a way that satisfies the CAA transport requirements, EPA is also mindful of the need to ensure a smooth transition from the existing requirements. Substantial improvements in air quality have resulted from those requirements with associated health benefits. It is important not to lose those benefits as the new requirements move forward. It is also important to move quickly with those portions of the new requirements that provide the greatest benefits.
Emissions from upwind states can, alone or in combination with local emissions, result in air quality levels that exceed the NAAQS and jeopardize the health of residents in downwind communities. Each upwind state is required by the “good neighbor provision” to eliminate its individual significant contribution to downwind state nonattainment and to eliminate emissions that interfere with downwind states” maintenance of the air quality standards. The Act does not require upwind states to eliminate all emissions that affect downwind air quality or shift responsibility for attaining the NAAQS to the upwind states. Instead, the “good neighbor provision” requires each upwind state to, within 3 years of promulgation or revision of a NAAQS, submit a SIP to prohibit those emissions that significantly contribute to nonattainment or interfere with maintenance downwind. The prohibition on these emissions is intended to assist downwind states as they design strategies for ensuring that the NAAQS are attained and maintained.
In practice, it is very complex for individual states to address the transport requirements. Generally for transport of ozone, and for transport of sulfate and nitrate fine particles, each downwind area is affected by emissions from multiple upwind states. In addition, in many cases states are simultaneously both upwind and downwind of one another. Further, only emissions that will significantly contribute to nonattainment or interfere with maintenance in another state are prohibited. Thus, an upwind state's obligations are affected by the air quality downwind. Downwind air quality, in turn, is affected by both local emissions and the cumulative impact of emissions from all of the contributing upwind states.
The problem of interstate transport is thus extremely complex and any remedy must acknowledge the inherent complexity of the problem. It is appropriate for EPA in developing such a remedy to be mindful of the interaction between upwind emissions controls and local emissions controls.
The EPA continues to conclude, as it did in developing the CAIR, that it would be difficult if not impossible for many nonattainment areas to reach attainment through local measures alone, and EPA finds no information developed subsequent to development of CAIR to alter this conclusion. At the time of the proposed CAIR rule, EPA conducted a local measures analysis representing an ambitious set of measures and emissions reductions that may in fact be difficult to achieve in practice. (Ref: Section IX of Technical Support Document for the Interstate Air Quality Rule Air Quality Modeling Analyses, January 2004). This analysis was intended to provide illustrative examples of the nature of location measures and possible reductions. This analysis was not intended to precisely identify local emissions control measures that may be available in a particular area. The EPA continues to believe that a strategy based on adopting cost effective controls on sources of transported pollutants as a first step will produce a more reasonable, equitable, and optimal strategy than one beginning with local controls. The local measures analyses we conducted were not, however, intended to develop a specific or “optimal” regional and local attainment strategy for any given area. Rather, the analysis was intended to evaluate whether, in light of available
In conclusion, EPA believes that the proposed rule represents the best approach for identifying upwind state emissions that significantly contribute to nonattainment in, or interfere with maintenance by, downwind states.
The proposed Transport Rule would, by 2012, cap emissions of SO
Another important goal in developing the proposed requirements is to provide requirements that can, as a practical matter, be implemented by both EPA and state air quality agencies. Both EPA and state resources are limited and EPA recognizes the importance of developing requirements that make efficient use of limited EPA and state resources. EPA also notes that the air quality improvements brought about by reducing transport can greatly assist states in the development of SIPs and attainment demonstrations.
EPA recognizes that requirements for EGUs must be mindful of the variability in the operation of the power grid, and that any requirements for broad reductions should be structured in a way that ensures a reliable power supply.
EPA believes that is important to keep both cost-effectiveness and air quality objectives in mind in addressing the CAA transport requirements.
EPA seeks to provide approaches that provide regulated owners/operators of sources with the incentive to achieve all cost-effective reductions. EPA's experience shows that providing this incentive, and the flexibility to seek alternatives to less cost-effective controls, provides for greater environmental protection at reduced cost.
For this proposal, we identified a 37 state region for the technical analysis, including all states east of the Rockies, from the Dakotas through Texas eastward. Western states also need to address the requirements of section 110(a)(2)(D)(i)(I) of the CAA. However, the transport issues in the eastern United States are analytically distinct and this rule focuses only on that subset of the 110(a)(2)(D)(i)(I) issues.
First, interstate transport of PM
Second, in developing the CAIR, EPA found that interstate transport (particularly for anthropogenic emissions) made much smaller contributions to exceedances of the 1997 PM
Technical information developed for EPA's recently completed nonattainment designations suggests that interstate emissions transport makes a relatively small contribution to exceedances in the western United States under the 2006 PM
On January 12, 2010, the EPA Administrator outlined seven priorities for the Agency. One of them is to improve air quality. In her description of this priority she said, “EPA will develop a comprehensive strategy for a cleaner and more efficient power sector, with strong but achievable reduction goals for SO
The rules under the CAA will substantially reduce the emissions of SO
The major CAA rules that will drive these compliance investments are: (1) This transport rule; (2) potential future rules that may be needed to address transport under future revised ozone or fine particle health standards; (3) the
A brief explanation of these major CAA rulemakings and activities follows.
If more protective NAAQS are promulgated, further emissions reductions would likely be needed in states where pollution levels exceed air quality standards, and in upwind states with emissions that significantly contribute to the air quality problems in another state. This may result in additional emission reduction requirements for facilities in the power sector, as well as for other sectors. The reconsideration of the March 2008 ozone air quality standards will be completed soon, and the review of particulate matter air quality standards by October 2011. SIP deadlines and attainment deadlines would flow from those dates.
EPA plans to make expeditious determinations of upwind state emissions reduction responsibilities for NAAQS for which interstate transport is an issue. This approach will lead to earlier emissions reductions to protect public health, as well as provide other benefits. In the
If a more protective ozone NAAQS is issued in August, EPA would plan to propose an interstate pollution transport rule for that NAAQS in 2011. We would expect work on that proposal to proceed in parallel with efforts to finalize this Transport Rule for the 1997 and 2006 NAAQS. A final rule to address interstate pollution transport for a reconsidered ozone NAAQS would be anticipated in 2012. In view of the implementation schedule for a reconsidered ozone NAAQS, compliance dates would be later than the compliance dates proposed for this Transport Rule, and would take into account attainment dates for that NAAQS and other factors such, as control cost and installation time. For any revised PM
A revised SO
In developing these rules, EPA will endeavor to proceed in a way that provides all stakeholders and other Federal, State and local decision-makers with ongoing, up-to-date information about the full suite of environmental responsibilities that the power sector must undertake. This, in turn, will enable power companies and others whose policies and decisions affect their investment choice to adopt compliance strategies that take full advantage of co-control opportunities and efficiencies and other approaches to maximizing the cost-effectiveness and leveraging benefits of their investments.
EPA does not have sole responsibility for the development of energy policy to promote efficiency. To facilitate this component of the power sector's compliance strategy, EPA intends to engage with other federal, state, and local agencies whose policies and actions can make it easier for power companies to adopt, or benefit from, energy efficiency investments in their compliance strategies. EPA will continue to use its authorities to advance energy efficiency by providing incentives for energy efficiency in our regulatory programs (
All of these entities will need to work in concert to achieve a truly efficient, reliable, cost-effective electric power system. EPA is committed to meeting this challenge.
As a first step to carrying out its commitment to promote and facilitate the most cost-effective and forward-looking compliance investments and strategies on the part of the power sector, EPA will conduct extensive outreach concerning the full range of the upcoming environmental responsibilities of the sector as it proposes the Transport Rule. Upon this proposal, the Agency will begin an outreach effort with the public, the regulated community, state air regulators, and others to (1) describe the Transport Rule proposal, and (2) provide information on the 2011 section 112 standards for utility units and other upcoming EPA rulemakings affecting the power sector. The intent will be to inform all stakeholders of the industry's obligations and opportunities for the industry to use investments in SO
At the same time EPA also intends to expand its outreach to others—who can play a significant role in promoting or requiring investment in energy efficiency. EPA intends to continue these efforts over time as more information becomes available in the development of the various rulemakings under development for the power sector.
This section describes EPA's proposed approach to define emissions that significantly contribute to nonattainment or interfere with maintenance of the PM
Two rules EPA promulgated that address interstate transport of pollutants are the NO
In the first step, EPA applied an air quality threshold to determine a set of upwind states whose potential for significant contribution should be evaluated further. That is, EPA compared the contributions that individual upwind states make to downwind receptors and identified states whose contributions were greater than the specified threshold amount. EPA referred to these states as significant contributors but did not rely on this first step to quantify or measure the states’ significant contribution.
In the second step, EPA determined the quantity of emissions that the states collectively could remove using highly cost-effective controls. EPA defined this quantity of emissions as the “significant contribution.” The approach used in each rule is described in more detail, later.
EPA determined the amount of emissions that significantly contribute to downwind nonattainment from sources in a particular upwind state by: (i) Evaluating, with respect to each upwind state, several air quality related factors, including determining that all emissions from the state have a sufficiently great impact downwind (in the context of the collective contribution nature of the ozone problem); and (ii) determining the amount of that state's emissions that can be eliminated through the application of cost-effective controls (63 FR 57403).
EPA specifically considered three air quality factors with respect to each upwind state:
• The overall nature of the ozone problem (
• The extent of the downwind nonattainment problems to which the upwind state's emissions are linked, including the ambient impact of controls required under the CAA or otherwise implemented in the downwind areas; and
• The ambient impact of the emissions from the upwind state's sources on the downwind nonattainment problems (63 FR 57376).
EPA explained the first factor, collective contribution, by noting,
[V]irtually every nonattainment problem is caused by numerous sources over a wide geographic area * * * [. This] factor suggest[s] that the solution to the problem is the implementation over a wide area of controls on many sources, each of which may have a small or immeasurable ambient impact by itself (63 FR 57377).
The second air quality factor is the extent of downwind nonattainment problems. EPA considered the then-current air quality of the area, the predicted future air quality (assuming implementation of required controls but not the transport requirements that were the subject of the NO
EPA applied the third air quality factor by projecting the amount of the upwind state's entire inventory of anthropogenic emissions to the year 2007, and then quantifying the impact of those emissions on downwind nonattainment through the appropriate air quality modeling techniques.
EPA established $2,000 per ton (1990$) in average cost-effectiveness for summer ozone season emissions reductions as, at least directionally, the highly cost-effective amount. Identifying this amount on an ozone season basis was appropriate because the NO
In the NO
After ascertaining the controls that qualified as highly cost-effective, EPA developed a methodology for calculating the amount of NO
To quantify the amounts of emissions that contribute significantly to nonattainment, EPA explained in the CAIR that the Agency primarily focused on the air quality factor reflecting the upwind state's ambient impact on downwind nonattainment areas, and the cost factor of highly cost-effective controls.
As in the NO
This level reflects the fact that PM
EPA used the same threshold amounts and metrics for 8-hour ozone that it used in the NO
Section 110(a)(2)(D)(i)(I) requires that SIPs for national primary and secondary air quality standards contain adequate provisions prohibiting emissions in amounts that “interfere with maintenance by any other state” of any such standard.
In the NO
After an area has reached attainment of the 8-hour NAAQS, that area is obligated to maintain that NAAQS. (See sections 110(a)(1) and 175A.) Emissions from sources in an upwind area may interfere with that maintenance. The EPA proposes to apply much the same approach in analyzing the first component of the “interfere-with-maintenance” issue, which is identifying the downwind areas whose maintenance of the NAAQS may suffer interference due to upwind emissions. The EPA has analyzed the “interfere-with-maintenance” issue for the 8-hour NAAQS by examining areas whose current air quality is monitored as attaining the 8-hour NAAQS [or which have no current air quality monitoring], but for which air quality modeling shows nonattainment in the year 2007. This result is projected to occur, notwithstanding the imposition of certain controls required under the CAA, because of projected increases in emissions due to growth in emissions generating activity. Under these circumstances, emissions from upwind areas may interfere with the downwind area's ability to attain. Ascertaining the impact on the downwind area's air quality of the upwind area's emissions aids in determining whether the upwind emissions interfere with maintenance (62 FR 60326).
In today's action, EPA is taking the same positions with respect to the interfere-with-maintenance test as described in the notice of proposed rulemaking.
In addition, the NO
This [interfere-with-maintenance] requirement * * * does not, by its terms, incorporate the qualifier of “significantly.” Even so, EPA believes that for present purposes, the term “interfere” should be interpreted much the same as the term “contribute significantly,” that is, through the same weight-of-evidence approach.
In responding to comments on the CAIR proposal, we also used this interpretation of the maintenance provision to help support the need for Phase II CAIR reductions. For ozone, we conducted an analysis that looked at (1) the amount by which receptor locations were projected to attain in 2015 and (2) the year-to-year variability in ozone levels due to weather and other factors based on a review of historical monitoring data. This analysis concluded that areas within 3-5 ppb of the standard, and sometimes greater (
In
Specifically, the court rejected the regional scope of EPA's analysis. It reasoned that “because EPA evaluated whether its proposed emissions were ‘highly cost effective’ at the regionwide level assuming a trading program, it never measured the ‘significant contribution’ from sources within an individual state to downwind nonattainment areas.”
In
In the CAIR case, the Court also rejected EPA's approach to the second prong of section 110(a)(2)(D)(i)(I), holding that EPA's failure to give independent meaning to the term “interfere with maintenance” was inconsistent with the statutory mandate.
In this section, EPA will explain how it proposes to identify which states are significantly contributing to downwind non-attainment and/or interfering with maintenance of the NAAQS at downwind sites and to quantify what that contribution is.
In this action, EPA is proposing to use a two step approach to measuring each state's significant contribution. The methodology used is based on the approach used in CAIR and the NO
EPA considers that the maintenance concept has two components: Year-to-year variability in emissions and air quality, and continued maintenance of the air quality standard over time. Both components of maintenance are addressed in this proposal.
In step one of this proposed approach, EPA analyzes emissions from 37 states to quantify the impact of those emissions on downwind nonattainment and maintenance sites in 2012 (
A key step in the process of developing a 110(a)(2)(D)(i)(I) rule involves analyzing existing (base case) emissions to determine which states significantly contribute to downwind nonattainment and maintenance areas. EPA cannot prejudge at this stage which states will be affected by the rule. For example, a state affected by CAIR may not be affected by the new rule and after the new rule goes into effect, the CAIR requirements will no longer apply. For a state covered by CAIR but not covered by the new rule, the CAIR requirements would not be replaced with new requirements, and therefore an increase in emissions relative to present levels could occur in that state. More fundamentally, the court has made clear that, due to legal flaws, the CAIR rule cannot remain in place and must be replaced. If EPA's base case analysis
Following this logic, the 2012 base case shows emissions higher than current levels in some states. Because EPA has been directed to replace CAIR, EPA believes that for many states, the absence of the CAIR NO
In step two, EPA identifies the portion of each state's contributing emissions that constitute the emissions from that state that “significantly contribute to, or interfere with maintenance by” another state. To do so with respect to the 1997 ozone NAAQS, EPA analyzes the costs and associated air quality impacts of reductions in ozone-season NO
While we believe it is important to consider cost, we also recognize that we can't “just pick a cost for the region and deem ‘significant’ any emissions that sources can eliminate more cheaply.”
These thresholds are then applied on a state-specific basis to quantify each individual state's significant contribution.
The remainder of this section provides further detail on the specific methodology developed by EPA and the application of this methodology to identify emissions that significantly contribute to or interfere with maintenance of the 1997 ozone NAAQS and the 1997 and 2006 PM
This section describes EPA's proposal to require reductions in upwind emissions of SO
The EPA assessed individual upwind states” 2012 projected ambient impacts on downwind nonattainment and maintenance receptors for a 37-state region in the eastern U.S., and established threshold values for PM
As noted previously, EPA considers that the maintenance concept has two components: Year-to-year variability in emissions and air quality, and continued maintenance of the air quality standard over time. The way that EPA defined maintenance based on year-to-year variability is discussed in section IV.C., and directly affects the proposed requirements of this rule. EPA also considered whether further reductions were necessary to ensure continued lack of interference with maintenance of the NAAQS over time. EPA concluded that in light of projected emission trends, and also considering the emissions reductions from this proposed rule, no further reductions are required solely for this purpose at PM and ozone receptors for which we are partially or fully determining significant contribution for the current NAAQS. (
Section II of the January 2004 CAIR proposal summarized key scientific and technical aspects of the occurrence, formation, and origins of PM
(1) Fine particles (measured as PM
(2) Examination of urban and rural monitors indicate that in the eastern U.S., sulfates, carbonaceous material, nitrates, and ammonium associated with sulfates and nitrates are typically the largest components of transported PM
(3) Atmospheric interactions among particulate ammonium sulfates and nitrates and gas phase nitric acid and ammonia vary with temperature, humidity, and location. Both ambient observations and modeling simulations suggest that regional SO
(4) Reductions in ammonia can reduce the ammonium, but not the sulfate portion of sulfate particles. The relative efficacy of reducing nitrates through NO
(5) Much less is known about the sources of regional transport of carbonaceous material. Key uncertainties include how much of this material is due to biogenic as compared to anthropogenic sources, and how much is directly emitted as compared to formed in the atmosphere.
Based on the understanding of current scientific and technical information, as well as EPA's air quality modeling, as summarized in the CAIR proposal, EPA concluded that it was both appropriate and necessary to focus on control of SO
For the CAIR, the EPA did not include emissions controls that affect other components of PM
In the notice of proposed rulemaking for the CAIR, EPA provided the following characterization of the origin and distribution of 8-hour ozone air quality problems:
The ozone present at ground level as a principal component of photochemical smog is formed in sunlit conditions through atmospheric reactions of two main classes of precursor compound: VOCs and NO
Studies conducted in the 1970s established that ozone occurs on a regional scale (
In the notice of proposed rulemaking for CAIR, EPA noted that we continue to rely on the assessment of ozone
More recent assessments of ozone, for example those conducted for the Regulatory Impact Analysis for the ozone standards in 2008, continue to show the importance of NO
For addressing interstate ozone transport in the CAIR, EPA addressed NO
In the CAIR, EPA used as the metric for identifying a state as significantly contributing (depending upon further consideration of costs) to downwind nonattainment, the predicted change, due to the upwind state's NO
This metric addresses how much each state contributes to a downwind neighbor. EPA does not believe that a particular upwind state must contribute to multiple downwind receptors to be required to make emissions reductions under CAA section 110(a)(2)(D). Under this provision, an upwind state must include in the SIP adequate provisions that prohibit that state's emissions that “contribute significantly to nonattainment in * * * any other State * * *” 42 U.S.C. 7410(a)(2)(D)(i)(I). Our interpretation of this provision is that the emphasized terms make clear that the upwind state's emissions must be controlled as long as they contribute significantly to a single nonattainment area.
As discussed in section II of the preamble to the final CAIR, EPA's approach to evaluating a state's impact on downwind nonattainment considered the entirety of the state's SO
In the CAIR proposal, EPA proposed to establish a state-level annual average PM
In the case of PM
As a result, to address the transport affecting a given nonattainment or maintenance area, many upwind states must reduce their emissions, even though their individual contributions may be relatively small. As a result, for the CAIR EPA determined that a relatively low value for the PM
For the CAIR ozone program, in assessing the contribution of upwind states to downwind 8-hour ozone nonattainment, EPA followed the approach used in the NO
The air quality modeling approach we proposed to quantify the impact of upwind emissions included two different methodologies: Zero-out and source apportionment. EPA applied each methodology to estimate the impact of all of the upwind state's anthropogenic NO
The EPA's first step in evaluating the results of these methodologies was to remove from consideration those states whose upwind contributions were very low. Specifically, EPA considered an upwind state not to contribute significantly to a downwind nonattainment area if the state's maximum contribution to the area was either (1) less than 2 ppb; or (2) less than one percent of total nonattainment in the downwind area; as indicated by either of the two modeling techniques.
If the upwind state's impact exceeded these thresholds, then EPA conducted a further evaluation to determine if the impact was high enough to meet the air quality portion of the “contribute significantly” standard. In doing so, EPA organized the outputs of the two modeling techniques into a set of “metrics.” The metrics reflect three key contribution factors:
• The magnitude of the contribution (actual amount of ozone contributed by emissions in the upwind state to nonattainment in the downwind area);
• The frequency of the contribution (how often contributions above certain thresholds occur); and
• The relative amount of the contribution ( the total ozone
For the proposed rule, EPA believes that the conclusions and findings in the final CAIR regarding the nature of pollutant contributions are still appropriate. EPA proposes to continue to focus the PM
EPA recognizes that, in some circumstances, the state's NO
For the proposed rule, as for CAIR, EPA uses air quality thresholds to identify states whose contributions do not warrant transport requirements. We propose air quality thresholds for annual PM
As we found at the time of the CAIR, EPA's analysis of base case PM
A second reason that low threshold values are warranted, as EPA discussed in the notices for the CAIR, is that there are adverse health impacts associated with ambient PM
For annual PM
Annual PM
Because the design value is to be reported only to the nearest 0.1 μg/m
For the 24-hour standard of 35 μg/m
24-hour PM
One percent of the 24-hour standard is 0.35 μg/m
For the proposed rule, EPA proposes to decouple the precision of the air quality thresholds with the monitoring reporting requirements, and to use 2-digit values representing one percent of the NAAQS, that is, 0.15 μg/m
For the proposal, EPA is proposing to take a more straightforward approach to air quality thresholds for ozone than the multi-factor approach we used for the NO
EPA seeks comment on the pollutants and air quality thresholds used for identifying states to be included under the proposed rule. In particular, EPA requests comment on alternatives to the 1 percent threshold. In addition, EPA requests comment on whether EPA should use the same rounding
In this section, we describe the air quality modeling performed to support the proposed rule. We used air quality modeling to (1) identify locations where we expect there to be nonattainment or maintenance problems for annual average PM
To support the proposal, air quality modeling was performed for four emissions scenarios: A 2005 base year, a 2012 “no CAIR” base case, a 2014 “no CAIR” base case, and a 2014 control case that reflects the emissions reductions expected from the proposed FIPs. The remedy proposed for inclusion in the FIPs is described in section V.D. The modeling for 2005 was used as the base year for projecting air quality for each of the 3 future year scenarios. The 2012 base case modeling was used to identify future nonattainment and maintenance locations and to quantify the contributions of emissions in upwind states to annual average and 24-hour PM
For CAIR, EPA used the Comprehensive Air Quality Model with Extensions (CAMx) version 5
Both CAMx and CMAQ contain certain source apportionment tools that are designed to quantify the contribution of emissions from various sources and areas to ozone and PM
The 2005-based air quality modeling platform used for the proposal includes 2005 base year emissions and 2005 meteorology for modeling ozone and PM
Emissions estimates were made for a 2005 base year and for 2012 and 2014. All inventories include emissions from EGUs, nonEGU point sources, stationary nonpoint sources, onroad mobile sources, and nonroad mobile sources. When emissions were only available at annual or monthly temporal resolutions, emissions modeling steps were applied to estimate hourly emissions. Point source emissions were assigned to modeling grid cells based on latitude and longitude in the inventory, and county total emissions were allocated to grid cells. Emissions of NO
Emissions inventory inputs representing the year 2005 were developed to provide a base year for forecasting future air quality, described in section IV.C.2. The 2005 National Emission Inventory (NEI), version 2 from October 6, 2008, was the starting point for the U.S. inventories used for the 2005 air quality modeling. This inventory includes 2005-specific data for point and mobile sources, while most nonpoint data were carried forward from version 3 of the 2002 NEI. In addition, a 2006 Canadian inventory and a 1999 Mexican inventory were used for the portions of Canada and Mexico within the modeling domains. Additional details on these inventories and the augmentation described here are available from the Emissions Inventory Technical Support Document (EITSD) for the Transport Rule.
The onroad and nonroad emissions were primarily based on the National Mobile Inventory Model (NMIM) monthly, county, process level emissions from the 2005 NEI v2. The 2005 onroad mobile emissions were augmented for onroad gasoline emissions sources with emissions based on a draft version of the Motor Vehicle Emissions Simulator (MOVES) for carbon monoxide (CO), NO
The annual NO
For the 2005 base year, the annual EGU NEI emissions were allocated to hourly emissions values needed for modeling based on the 2004, 2005, and 2006 CEM data. The NO
Other significant augmentations were also made to the 2005 NEI and include the following. The nonpoint inventory was augmented with the oil and gas exploration inventory
Tables IV.C-1 and IV.C-2 provide summaries of SO
The future base case scenarios represent predicted emissions in the absence of any further controls beyond those federal measures already promulgated. For EGUs, all state and other programs available at the time of modeling have been included. For mobile sources, all national measures available at the time of modeling have been included. For nonEGU point and nonpoint stationary sources, any local control programs that may be necessary for areas to attain the annual PM
Tables IV.C-3 through IV.C-6 provide 2012 and 2014 summaries of emissions data for 2012 and 2014 modeling for all sectors for SO
Future year 2012 and 2014 base case EGU emissions used for the air quality modeling runs that predicted ozone and PM
Mobile source inventories of onroad and nonroad mobile emissions were created for 2012 and 2015 using a combination of the NMIM and draft MOVES models. Mobile source emissions were further interpolated between 2012 and 2015 to estimate 2014 emissions. Emissions for these years reflect onroad mobile control programs including the Light-Duty Vehicle Tier 2 Rule, the Onroad Heavy-Duty Rule, and the Mobile Source Air Toxics (MSAT) final rule. Nonroad mobile emissions reductions for these years include reductions to locomotives, various nonroad engines including diesel engines and various marine engine types, fuel sulfur content, and evaporative emissions standards. A more comprehensive list of control programs included for mobile sources is available in the EITSD.
The onroad emissions were primarily based on the NMIM monthly, county, process level emissions. For both 2012 and 2015, emissions from onroad gasoline sources were augmented with emissions based on the same preliminary version of MOVES as was used for 2005. MOVES-based emissions were computed for CO, NO
Nonroad mobile emissions were created only with NMIM using a consistent approach as was used for 2005, but emissions were calculated using NMIM future-year equipment population estimates and control programs for 2012 and 2014. Emissions from 2012 and 2015 were used for locomotives and category 1 and 2 (C1 and C2) commercial marine vessels, based on emissions published in OTAQ's Locomotive Marine Rule, Regulatory Impact Assessment, Chapter 3. For category 3 (C3) commercial marine vessels, a coordination strategy of emissions reductions is ongoing that includes NO
Other inventory sources include nonEGU point sources, stationary nonpoint sources, and emissions in Canada and Mexico. Emissions from Canada and Mexico for all source sectors (including EGUs) in these countries were held constant for all cases. This approach reflects the unavailability of future-year emissions from Canada and Mexico for the future years of interest in time to support the modeling for this proposal.
The future year emissions for other sectors are described next. For all sector projections, EPA seeks comment on growth and control approaches, particularly where a control measure has not been included. The EITSD provides more details on these projections for additional review and we have included in the EITSD a table for the public to provide more detailed control data to EPA.
For nonEGU point sources, emissions were projected by including emissions reductions and increases from a variety of sources. For nonEGUs, emissions were not grown using economic growth projections and emissions reductions were applied through plant closures, refinery and other consent decrees, and reductions stemming from several MACT standards. Since aircraft at airports were treated as point emissions sources in the 2005 NEI v2, we also applied projection factors based on activity growth projected by the Federal Aviation Administration Terminal Area Forecast (TAF) system, published December 2008. Controls from the NO
For stationary nonpoint sources, refueling emissions were projected using the refueling results from the NMIM runs performed for the onroad mobile sector. Portable fuel container emissions were projected using estimates from previous OTAQ rulemaking inventories. Emissions of ammonia and dust from animal operations were projected based on animal population data from the Department of Agriculture and EPA. Residential wood combustion was projected by replacement of obsolete woodstoves with new woodstoves and a 1 percent annual increase in fireplaces. Landfill emissions were projected using MACT controls. All other nonpoint sources were held constant between 2005 and the future years.
The annual and summer day emissions inventory files were processed through the Sparse Matrix Operator Kernel Emissions (SMOKE) Modeling System version 2.6 to produce the gridded model-ready emissions for input to CAMx. Emissions processing using SMOKE was performed to create the hourly, gridded data of CAMx species required for air quality modeling for all sectors, including biogenic emissions. Additional information on the development of the emissions data sets for modeling is provided in the EITSD. Details about preparation of emissions for contribution modeling are described in the Transport Rule AQ Modeling TSD.
The gridded meteorological input data for the entire year of 2005 were derived from simulations of the Pennsylvania State University/National Center for Atmospheric Research Mesoscale Model. This model, commonly referred to as MM5, is a limited-area, nonhydrostatic, terrain-following system that solves for the full set of physical and thermodynamic equations which govern atmospheric motions.
The 2005 MM5 meteorological predictions for selected variables were compared to measurements as part of several performance evaluations of the predicted data. The evaluation approach included a combination of qualitative and quantitative analyses to assess the adequacy of the MM5 simulated fields. The qualitative aspects involved comparisons of the model-estimated synoptic patterns against observed patterns from historical weather chart archives. Additionally, the evaluations compared spatial patterns of monthly average rainfall and monthly maximum planetary boundary layer (PBL) heights. The operational evaluation included
As noted previously, the CAMx simulations for this proposal were performed using a spatial resolution of 12 x 12 km. The concentrations of pollutants transported into this eastern U.S. modeling region were obtained from air quality model simulations performed at coarser 36 x 36 km resolution for a modeling domain covering the lower 48 states and portions of northern Mexico and southern Canada. The 12 x 12 km model simulations were also initialized with air quality predictions from the coarse scale modeling. Pollutant concentrations at the boundaries of the coarse scale modeling domain were obtained from a three-dimensional global atmospheric chemistry model, the GEOSChem
The 2005 base year model predictions for ozone and fine particulate sulfate, nitrate, organic carbon, elemental carbon, and crustal material were compared to measured concentrations in order to evaluate the performance of the modeling platform for replicating observed concentrations. This evaluation was comprised principally of statistical assessments of paired modeled and observed data. Details on the evaluation methodology and the calculation of performance statistics are provided in the AQMTSD. The results indicate that, overall, the predicted patterns and day-to-day variations in regional ozone levels are similar to what was observed with measured data. The normalized mean bias for 8-hour daily maximum ozone concentrations was −2.9 percent and the normalized mean error was 13.2 percent for the months of May through September 2005, based on an aggregate of observed-predicted pairs within the 12 km modeling domain. The two PM
In this section we describe the approach for projecting future concentrations of ozone and PM
In this analysis we use measurements of ambient ozone and PM
In order to use the ambient data, the raw measurements must be processed into a form pertinent for useful interpretations. For this action, the ozone data were processed consistent with the formats associated with the NAAQS for ozone. The resulting estimates are used to indicate the level of air quality relative to the NAAQS. For ozone air quality indicators, we developed estimates for the 1997 8-hour ozone standard. The level of the 1997 8-hour O3 NAAQS is 0.08 ppm. The 8-hour ozone standard is not met if the 3-year average of the annual 4th highest daily maximum 8-hour O3 concentration is greater than 0.08 ppm (0.085 ppm when rounded up). This 3-year average is referred to as the design value.
The PM
The 24-hour average standard is met when the 3-year average of the annual 98th percentile PM
As described later, the approach for projecting future ozone and PM
The procedures for projecting annual average PM
Annual PM
In general, the projection methodology involves using the model in a relative sense to estimate the change in PM
Concentrations of PM
The 5-year weighted average concentrations were used to project concentrations for the 2012 base case in order to determine which monitoring sites are expected to be nonattainment in this future year. We projected 2012 design values for each of 3 year periods (
For the analysis of both nonattainment and maintenance, monitoring sites were included in the analysis if they had at least one complete design value in the 2003-2007 period.
EPA followed the procedures recommended in the modeling guidance for projecting PM
The following is a brief summary of the future year annual PM
We are using the base period (
The preceding procedures for determining future year PM
Table IV.C-7 contains the 2003-2007 base case period average and maximum annual PM
The following is a brief summary of the procedures used for calculating future year 24-hour PM
Both the annual PM
The following are the steps followed for calculating the 2012 base case 24-hour PM
The preceding procedures for determining future year 24-hour PM
Table IV.C-9 contains the 2003-2007 base period average and maximum 24-hour PM
The following is a brief summary of the future year 8-hour average ozone calculations. Additional details are provided in the modeling guidance, MATS documentation, and the AQMTSD.
We are using the base period 2003-2007 ambient ozone design value data for projecting future year design values. The ozone projection procedure is relatively simple, since ozone is a single species. It is not necessary to interpolate ambient ozone data, since ambient ozone design values and gridded, modeled ozone is all that is needed for the projections.
To project 8-hour ozone design values we used the 2005 base year and 2012 future base case model-predicted ozone concentrations to calculate relative response factors. The methodology we followed is consistent with the attainment demonstration modeling guidance. The RRFs were applied to the 2003-2007 ozone design values through the following steps:
The preceding procedures for determining future year 8-hour average ozone design values were applied for each ozone monitoring site. The future year design values are truncated to integers in units of ppb. This approach is consistent with the truncation and rounding procedures for the 8-hour ozone NAAQS. Future year design values that are greater than or equal to 85 ppb are considered to be violating the NAAQS. Sites with future year 5-year weighted average design values of 85 ppb or greater are predicted to be nonattainment. Sites with future year maximum design values of 85 ppb or greater are predicted to be future year maintenance sites. Note that, as described previously for the annual and 24-hour PM
Table IV.C-11 contains the 2003-2007 base period average and maximum 8-hour ozone design values and the 2012 base case average and maximum design values for sites projected to be 2012 nonattainment of the 8-hour ozone NAAQS in 2012. Table IV.C-12 contains this same information for projected 2012 8-hour ozone maintenance sites.
This section documents the procedures used by EPA to quantify the impact of emissions in specific upwind states on air quality concentrations in projected downwind nonattainment and maintenance locations for annual PM
EPA used CAMx photochemical source apportionment modeling to quantify the impact of emissions in specific upwind states on projected downwind nonattainment and maintenance receptors for both PM
CAMx employs enhanced source apportionment techniques which track the formation and transport of ozone and particulate matter from specific emissions sources and calculates the contribution of sources and precursors to ozone and PM
Source apportionment is an alternative approach to zero-out modeling
The EPA performed source apportionment modeling for both ozone and PM
In contrast to CAIR, all contributions to downwind nonattainment and maintenance receptors for the Transport Rule were calculated using a relative approach. This is similar to the approach used to calculate future year design values, as described in section IV.C.2.a. In CAIR we used absolute and relative metrics to examine air quality contributions. Although absolute contributions are useful for certain applications, there are advantages of examining the relative contributions for both ozone and PM
EPA used the CAMx Particulate Source Apportionment Technique (PSAT) to calculate downwind PM
In the PSAT simulation NO
We developed and applied several post-processing steps to transform the PSAT modeling outputs to PM
EPA used the CAM
All anthropogenic sources of NO
The previous steps provide the details for calculating 8-hour ozone and annual and 24-hour PM
For each upwind state, the maximum contribution to nonattainment is calculated based on the single largest
In this section, we present the interstate contributions from emissions in upwind states to downwind nonattainment and maintenance sites for the annual PM
For annual PM
Based on the state-by-state contribution analysis, there are 22 states and the District of Columbia
There are 19 states and the District of Columbia
For 24-hour PM
Based on the state-by-state contribution analysis, there are 24 states and the District of Columbia
There are 23 states and the District of Columbia which contribute 0.35 μg/m
In this section, we present the interstate contributions from emissions in upwind states to downwind nonattainment and maintenance sites for the ozone NAAQS. As described previously in section IV.B., states which contribute 0.8 ppb or more to 8-hour ozone nonattainment or maintenance in another state are identified as states with contributions to downwind attainment and maintenance sites large enough to warrant further analysis. We performed air quality modeling to quantify the contributions to 8-hour ozone from emissions in each of the following 37 states individually: Alabama, Arkansas, Connecticut, Delaware, Florida, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana, Maine, Maryland combined with the District of Columbia, Massachusetts, Michigan, Minnesota, Mississippi, Missouri, Nebraska, New Hampshire, New Jersey, New York, North Carolina, North Dakota, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, South Dakota, Tennessee, Texas, Vermont, Virginia, West Virginia, and Wisconsin.
We calculated each state's contribution to each of the 11 monitoring sites that are projected to be nonattainment and each of 14
Based on the state-by-state contribution analysis, there are 22 states and the District of Columbia
There are 22 states and the District of Columbia which contribute 0.8 ppb or more to downwind 8-hour ozone maintenance. These states are: Alabama, Arkansas, Connecticut, Delaware, the District of Columbia, Florida, Georgia, Indiana, Kansas, Kentucky, Louisiana, Maryland, Mississippi, New Jersey, New York, North Carolina, Ohio, Oklahoma, Pennsylvania, South Carolina, Tennessee, Virginia, and West Virginia. In Table IV.C-21, we provide a list of the downwind nonattainment counties to which each upwind state contributes 0.8 ppb or more (i.e., the upwind state to downwind nonattainment “linkages”).
In this section, EPA explains its general approach to quantifying the amount of emissions that represent significant contribution and interference with maintenance. EPA then applies that approach for the three different NAAQS being addressed in today's notice: The 1997 ozone NAAQS, the 1997 annual PM
With respect to the 1997 ozone NAAQS, we apply this methodology to fully quantify the significant contribution and interference with maintenance for 16 states. We also use the methodology to quantify, for 10 additional states, NO
With respect to the annual PM
With respect to the 24-hour PM
After using air quality analysis to identify upwind states that are “linked” to downwind air quality monitoring sites with nonattainment and maintenance problems because the upwind states' emissions contribute one percent or more to the air quality value at the downwind site, EPA quantifies the portion of each state's contribution that constitutes its “significant contribution” and “interference with maintenance.”
This section describes the methodology developed by EPA for this analysis and then explains how that methodology is applied to measure significant contribution and interference with maintenance with respect to the PM
The methodology takes into account both the DC Circuit Court's determination that EPA may consider cost when measuring significant contribution,
The methodology defines each state's significant contribution and interference with maintenance as the emissions that can be eliminated for a specific cost. Unlike the NO
In step one, EPA identifies what emissions reductions are available at various costs, quantifying emissions reductions that would occur within each state at ascending costs per ton of emissions reductions. For purposes of this discussion, we refer to these as “cost curves”.
In step two, EPA uses an air quality assessment tool to estimate the impact that the combined reductions available from upwind contributing states and the downwind state, at different cost-per-ton levels, would have on air quality at downwind monitor sites that had nonattainment and/or maintenance problems.
In step three, EPA examines cost and air quality information to identify cost “breakpoints.” Breakpoints are the places where there is a noticeable change on one of the cost curves, such as a point where a large reduction occurs because a certain type of emissions control becomes cost-effective. EPA then uses a multi-factor assessment to determine the amount of emissions that represents significant contribution to nonattainment and interference with maintenance. The factors considered include both the air quality and cost considerations used in developing the breakpoints along with additional air quality and cost considerations. This assessment is performed for each transported NAAQS pollutant or precursor which EPA has concluded must be regulated due to its impact on downwind receptors. In this rule, as discussed in section IV.B, EPA is proposing to regulate SO
In step four, EPA quantifies the emissions reductions available in each “linked” state at the appropriate cost threshold. This information is then used to develop a state “budget,” representing the remaining emissions for the state in an average year, and to identify a variability limit associated with that budget. These budgets and variability limits are used to develop enforceable requirements under the proposed and two alternative remedy options. State emissions budgets are discussed in section IV.E and the variability limit is discussed in section IV.F.
EPA's proposed methodology considers both cost and air quality factors to address complex circumstances. We believe it is important to consider both factors because circumstances related to different downwind receptors can vary and consideration of multiple factors can help EPA appropriately identify each state's significant contribution under different circumstances. For instance, there may be cases when upwind states contributing to a specific downwind nonattainment area have already done a great deal to reduce emissions while the downwind state in which the nonattainment area is located has done very little. Conversely, the downwind state may have made large reductions while one or more contributing upwind states may have done very little. There may be cases where some states (upwind or downwind) have large emissions (and a correspondingly large impact downwind) not because their sources are poorly controlled, but because they have a greater number of sources—the operation of which is critical to the reliability of the electric grid. Conversely, there may be cases where a state (upwind or downwind) contributes less in total emissions because it has a smaller number of plants, but those plants are poorly controlled and could be better controlled at a relatively low cost.
Air quality factors alone are not able to discern these types of differences. Using both air quality and cost factors allows EPA to consider the full range of circumstances and state-specific factors that affect the relationship between upwind emissions and downwind nonattainment and maintenance problems. For example, considering cost takes into account the extent to which existing plants are already controlled as well as the potential for, and relative difficulty of, additional emissions reductions. Therefore, EPA believes that it is appropriate to consider both cost and air quality metrics when quantifying each state's significant contribution.
This methodology is consistent with the statutory mandate in section 110(a)(2)(D)(i)(I) which requires upwind states to prohibit emissions that significantly contribute to nonattainment or interfere with maintenance in another state, but does not shift the responsibility for achieving or maintaining the NAAQS to the upwind state.
In developing and implementing this methodology, EPA was cognizant of a number of factors. First, in many areas, transported emissions are a key component of the downwind air quality problem. Second, there are large amounts of low cost emission reduction opportunities in upwind states. Third, EPA recognizes that section 110(a)(2)(D) does not grant EPA authority to require emissions reductions solely because they provide large health and environmental benefits: reductions required pursuant to section 110(a)(2)(D)(i)(I) must be related to the goal of eliminating upwind state emissions that significantly contribute to nonattainment or interfere with maintenance of the NAAQS in downwind areas.
Fourth, EPA is cognizant of the relationship between the upwind and downwind state requirements in the Act. The Act requires upwind states to eliminate significant interstate pollution transport under section 110(a)(2)(D). It also requires each state to assure attainment and maintenance of the NAAQS within its borders. Thus, a downwind state must adopt controls to demonstrate timely attainment of the NAAQS despite any pollution transport from upwind states that is not eliminated under section 110(a)(2)(D).
There are several reasons that EPA believes upwind state sources contributing to air quality degradation in a downwind state should bear substantial responsibility to control their emissions. First, the plain language of this good neighbor provision requires upwind states to prohibit emissions that significantly contribute to nonattainment or interfere with maintenance in a downwind state. Second, interstate pollution transport increases pollution levels and health risks in the downwind state. Third, the influx of pollution from upwind states raises the pollution level in a downwind state, making it necessary for the downwind state to obtain deeper pollution reductions to attain and maintain air quality standards, which increases costs of control in the downwind state. Fourth, from the standpoint of a downwind state, the pollution contribution of each upwind state adds up to a larger, cumulative degradation of the downwind state's air quality. Fifth, reducing interstate pollution enhances prospects that attainment in downwind states can be achieved within the Act's deadlines and as expeditiously as practicable. All of these points support the position that upwind state sources should bear substantial responsibility to control their emissions.
On the other hand, the proposed methodology ensures that upwind states are not required to shoulder the entire responsibility for the downwind state's attainment and maintenance of the NAAQS. Among other things, our methodology implicitly assumes controls at the same cost per ton level in the downwind state as in the upwind contributing states.
The proposed methodology also directly ties each state's reduction requirements to EPA's analysis of that state's significant contribution and interference with maintenance. The required reductions would provide very substantial air quality improvements. For the annual PM
The first step in EPA's methodology for determining the quantity of emissions that represents each state's significant contribution is to identify reductions available at different costs. To do so, EPA developed a set of cost curves that show, at various cost increments, the available emissions reductions for EGUs in a state. In other words, EPA determined for specific cost per ton thresholds, the emissions reductions that would be achieved in a state if all EGUs in that state used all emission controls and emission reduction measures available at that cost threshold. The zero point of the curve shows what emissions would occur absent any additional investment in emissions reductions (
Although the cost curves presented in this proposal only include EGU reductions, EPA also conducted a preliminary assessment of reductions available for source categories other than EGUs. This preliminary assessment suggested that there likely would be very large emissions reductions available from EGUs before costs reach the point for which non-EGU sources have available reductions. EPA therefore initially created cost curves based solely on reductions from EGUs and determined appropriate cost thresholds based on that analysis. EPA then re-examined non-EGUs to determine the accuracy of its initial assumptions that there were little or no reductions available from non-EGUs at costs lower than the thresholds that EPA had chosen. EPA's analysis of the costs of and opportunities for non-EGU emissions reductions is discussed in more detail in section IV.D.3, later. For the reasons explained in that section, EPA believes there are little or no non-EGU reductions available at the cost thresholds used in this rule. Therefore, EPA believes it is reasonable at this time to use cost curves that include only EGU reductions. However, EPA is continuing to conduct analyses and believes that it will be necessary to further consider non-EGU emission reduction opportunities in future transport rules.
To develop cost curves, emissions available at various costs were assessed in 2012 for ozone season NO
There are approximately 30 months between mid-2011 (when the Agency anticipates finalizing this rule) and January 2014 (the proposed Phase 2 compliance deadline). EPA believes this is sufficient time for sources to install the advanced emissions controls projected to be retrofit. EPA expects about 14 GW of FGD and less than 1 GW of SCR capacity to be retrofit for Phase 2 of this rule. This is significantly less than the capacity that was retrofit in the same length of time after CAIR was finalized. EPA is not aware of problems or issues with sources meeting the CAIR compliance deadlines, either in equipment deliveries or labor availability. EPA believes the proposed Transport Rule compliance deadlines are reasonable, and will result in emissions reductions as quickly as practicable, delivering health benefits to the public and aiding states with NAAQS attainment deadlines.
EPA requests comment on the schedule for scrubber and SCR installations, the availability of boilermaker labor, and any comment on whether there might be alternative post-combustion cost-effective technologies that could reduce SO
Unlike add-on pollution controls such as scrubbers and SCRs, EPA believes that low-NO
EPA also believes that sources can switch coals by 2012. Eastern bituminous coals used for power generation typically have more than sufficient sulfur content to facilitate highly efficient collection of fly ash in a cold-side electrostatic precipitator (ESP). Some ESPs that operate at acceptably high collection efficiency when using a high-or medium-sulfur bituminous coal may experience some loss in collection efficiency when a lower sulfur coal is used. Whether this occurs on a specific unit, and the extent to which it occurs, would depend on the design margins built into the existing ESP, the percentage change in coal sulfur content, and other factors. Relatively inexpensive practices to maintain high ESP performance on lower sulfur bituminous coals are available and are being used successfully where necessary. These include a range of upgrades to ESP components and flue gas conditioning.
EPA assumes in the Transport Rule analysis that it will not be necessary for units that switch from higher to lower sulfur bituminous to make a costly replacement of the ESP. EPA's analysis therefore does not add capital or operations and maintenance costs for coal switching from higher to lower sulfur bituminous coals.
EPA's analysis does not allow a unit designed for bituminous to switch to (very low sulfur) subbituminous coal unless the unit has demonstrated that capability in the past. EPA assumes units with that capability have already made any investments needed to handle a switch to subbituminous coals. EPA therefore assumes that any modeled coal switching from bituminous to subbituminous has no cost or schedule impact.
EPA requests comment on the reasonableness of EPA's assumption that coal switching within the bituminous coal grades will have relatively little cost or schedule impact on most units.
In the second step, EPA uses an air quality assessment tool to estimate the impact of the upwind emissions reductions on downwind ambient concentrations.
c. Step 3. Identifying Appropriate Cost Thresholds
In the third step of this analysis, EPA examines the information developed in the first two steps to identify potential cost thresholds. It then uses a multi-factor assessment to identify which cost
This step of the analysis begins with an examination of the cost and air quality data to identify breakpoints on the emissions reductions cost curves developed in steps 1 and 2 related to (1) air quality (
Because upwind state sources should bear substantial responsibility for controlling emissions that contribute to air quality degradation in downwind states, EPA believes that cost per ton levels that are consistent with widely deployed existing controls, or are within the cost per ton range of controls already required by existing and proposed Federal and State rules (
Based on this multi-factor assessment, EPA identifies a specific cost per ton threshold for quantifying the amount of significant contribution from each state for each precursor pollutant. While we continue to believe that under certain circumstances it may be appropriate for us to use a single uniform cost per ton threshold to quantify significant contribution for all states, we believe it is also important to retain the flexibility to use multiple cost thresholds. For example, we believe it is appropriate to use multiple thresholds where one group of states can, for a lower cost, eliminate nonattainment and maintenance for all the downwind nonattainment and maintenance areas to which they are linked.
In the final step of this analysis, EPA uses the cost thresholds identified in the previous step to determine, on a state-by-state basis, the amount of emissions that could be reduced at a specific cost. The results of this analysis are used to develop the state budgets and variability limits, which are in turn used to implement the requirements to eliminate significant contribution and interference with maintenance.
The discussion that follows explains how the methodology described previously was applied to quantify significant contribution with respect to the 1997 and 2006 PM
All of the air quality considerations included in the multi-factor assessment are based on analysis using the air quality assessment tool. EPA believes that it is appropriate to use this tool because of the advantages it has over more refined air quality modeling to perform analysis of a large number of scenarios very quickly (more refined air quality modeling can take several months, while multiple scenarios can be evaluated using the air quality assessment tool in a single day). EPA has done more refined air quality modeling of the proposed emissions budgets. The more refined air quality modeling confirms EPA's overall methodology, but does suggest that, in the case of daily PM
For this reason, EPA is also requesting comment on whether we should modify our conclusions regarding the amount of specific states' significant contribution and interference with maintenance; whether there are ways to use our air quality modeling in conjunction with the air quality assessment tool to carry out the significant contribution analysis in a way that would not extend the time needed to complete this rulemaking; and whether there are ways to improve the air quality assessment tool.
EPA's significant contribution analysis for PM
This subsection provides more detail on the cost curves that EPA developed to assess the costs of reducing SO
To measure significant contribution and interference with maintenance with respect to the PM
Table IV.D-1 shows the annual NO
Before applying the information in the cost curves in step 3 of the analysis, EPA evaluated the cost curves to better understand how reductions at various cost levels reflect changes in the generation mix (
The cost curves demonstrate that many of these sources would operate their SCR units when emissions reductions that cost $500/ton are required. In addition, at this $500/ton level some additional units would likely install advanced combustion control technology. Below $500/ton, there are very few other NO
The cost curves for SO
Table IV.D-2 shows that in 2014 there are increased SO
After developing cost curves to show the state-by-state cost-effective emissions reductions available, EPA used the air quality assessment tool to evaluate the impact these upwind reductions would have on air quality in “linked” downwind nonattainment and maintenance areas. This section summarizes the results of that evaluation and provides analysis that informs EPA's multi-factor assessment, explained in step 3, later.
EPA performed air quality analysis for each downwind receptor with a nonattainment and/or maintenance problem. For each receptor, EPA assessed the air quality improvement resulting when a group of states, consisting of the upwind states that are “linked” to the downwind receptor (
The percent emissions reductions (and percent air quality improvement)
EPA determines the cumulative air quality improvement that could be expected at a particular downwind receptor by multiplying each upwind state's percent reduction by its air quality contribution and summing the results for all upwind states. In EPA's air quality analysis of each downwind receptor, all air quality improvements are measured relative to baseline emissions and air quality contributions in 2012.
Figures IV.D-1 through IV.D-4 show that at increased costs, there are substantial increased emissions reductions. As explained previously, each decrease in emissions is assumed to lead to a corresponding improvement in downwind air quality. These changes apply to both the daily and annual PM
EPA also identified the overall air quality reductions projected by the air quality assessment tool at downwind nonattainment and maintenance receptor locations. As explained previously, the multi-factor assessment in step 3 analyzed the results from the downwind receptor analysis in step 2 for the annual and daily PM
A number of conclusions can be drawn from Tables IV.D-3 and IV.D-4. Very low cost SO
For PM
EPA did not consider additional cost thresholds for NO
First EPA assessed $2,000/ton. Reductions at $2,000/ton would improve air quality at several locations with nonattainment and/or maintenance problems. We also believe that, as explained in the introduction to this section, it is reasonable to require a substantial level of control of upwind state emissions that significantly contribute to nonattainment or maintenance problems in another state. We believe that $2,000/ton is reasonable for SO
While analysis with the air quality assessment tool shows that a site in Allegheny County, Pennsylvania would be in nonattainment and two other sites—Lake County, Indiana and Cook County, Illinois—would have maintenance problems, if we assume reductions at $2,000/ton and additional reductions made by states because of their contribution to other downwind sites that do not contribute to these three problem areas, the maintenance problems in Lake County, Indiana and Cook County, Illinois would be resolved and only Allegheny County, Pennsylvania, would continue to have a nonattainment/maintenance problem. Because reductions at $2,000/ton continue to have significant air quality benefit for downwind sites with nonattainment and/or maintenance problems, it has been demonstrated historically that the amount of control equipment that is projected to be needed at $2,000/ton could be installed in the timeframe required and these costs are reasonable when compared to other options to reduce SO
Because our analysis shows that one area (Allegheny County, Pennsylvania) would have continuing nonattainment and maintenance problems, EPA continued to perform its multi-factor assessment for the higher $2,400/ton breakpoint to see if any additional emissions should also be considered significant. For this receptor monitor, EPA considered the local circumstances in the Liberty-Clairton area in Allegheny County that were leading to continued nonattainment. It is well-established that, in addition to being impacted by regional sources, the Liberty-Clairton area is significantly affected by a large increment of local emissions from a sizable coke production facility and other nearby sources. (
Because the remaining PM
After determining that the amount of emissions that could be reduced for $2,000/ton in 2014 is an appropriate quantification of a state's significant contribution, EPA considered whether any of these emissions reductions could be achieved prior to 2014. For the reasons that follow, EPA concluded that significant reductions could be achieved by 2012 and that it is important to require all such reductions by 2012 to ensure that they are achieved as expeditiously as practicable. While EPA believes that it is not possible to require the installation of post-combustion SO
Table IV.D.4, previously, shows that for large numbers of monitoring sites where there are nonattainment and or maintenance problems, those problems are fully resolved before all states achieve all of the emissions reductions that could be achieved at or below $2,000/ton. EPA used the air quality assessment tool to analyze the impact of requiring all states linked to the downwind state site with an air quality problem, as well as the downwind state, to reduce emissions consistent with the levels discussed for 2012 in section IV.D.2.a(2), previously. The air quality assessment tool shows that those 2012 reductions will resolve the nonattainment and maintenance problems for all of the areas to which the following states are linked: Alabama, Connecticut, Delaware, the District of Columbia, Florida, Kansas, Louisiana, Maryland, Massachusetts, Minnesota, Nebraska, New Jersey and South Carolina (referred to as group 2 states). EPA also assessed whether, in 2014, the combination of this level of reduction from the group 2 states and the remaining states (referred to as group 1 states) continued to result in all downwind areas—except for Allegheny County, Pennsylvania—fully addressing their nonattainment and or/maintenance problems, and determined that it did.
The states in group 1 and group 2 are rationally grouped considering air quality and cost. EPA proposes that it would not be appropriate to assign the same cost per ton to group 2 and group 1 states because a significantly lower cost per ton was sufficient to resolve air quality problems at all downwind receptors linked to the group 2 states. Although states are linked to different sets of downwind receptors, our analysis indicated that the cost per ton needed to resolve downwind air quality problems varied only to a limited extent among states within group 1 and among states within group 2. The cost per ton did vary greatly between the group 1 and group 2 states. Limitations on the accuracy of our cost and air quality analyses, and the ruling in the
After completing the process to propose appropriate state-by-state cost thresholds, EPA used these thresholds to develop the specific state-by-state budgets. This step in the process is fully described in section IV.E.
EPA believes that the methodology described previously is a sound and analytically efficient approach to addressing the requirements of 110(a)(2)(D)(i)(I) for the PM
As discussed previously, EPA uses a simplified air quality assessment tool, rather than actual air quality modeling, to identify air quality impacts of the options considered. This assessment tool enables efficient evaluation of multiple options quickly. We did, however, conduct more refined air quality modeling of the select emissions budgets and this more detailed modeling serves as a check on the appropriateness of the method. This check confirmed the directional conclusions of the air quality assessment tool and largely confirmed the more detailed results of the air quality assessment tool, but raised several issues on which EPA is requesting comment.
For the annual PM
For the 24-hour PM
EPA has completed some preliminary analysis of the difference between the air quality assessment tool and CAMx results (
Because the CAMx results indicate additional nonattainment and maintenance areas compared to the air quality assessment tool, EPA requests comment on whether the $2,000/ton cost cutoff for SO
Additionally, EPA is requesting comment on whether some group 2 states should be moved to group 1. These group 2 states are: Connecticut, Kansas, Maryland, Massachusetts, Minnesota, Nebraska, and New Jersey. These states were all placed in group two because the air quality assessment tool indicates that the 2012 reductions will resolve the nonattainment or maintenance problems at all areas to which they are linked. However, for these states, the CAMx modeling indicates that one or more of the states to which they are linked will have continuing nonattainment and
EPA also notes that during the winter, PM
Finally, EPA requests comment on how and whether EPA should incorporate the use of detailed models such as CAMx into our methodology for significant contribution and interference with maintenance.
EPA also evaluated whether the proposed rule could cause changes in operation of electric generating units in states not regulated under the proposal (that is states not listed in table IV.D-5). Specifically, EPA evaluated whether such changes could lead to increases in emissions in those states, potentially affecting whether they would exceed the 1 percent contribution thresholds used to identify linkages between upwind and downwind states. (
Further analysis with the air quality assessment tool indicates that these projected increases in the Texas SO
EPA takes very seriously its responsibility to ensure that upwind reductions are made in a timely way so that downwind states can meet their attainment obligations.
EPA recognizes, as discussed previously, that while this proposal fully addresses the annual PM
Based on the information that EPA currently has, EPA believes there are a number of possible outcomes of this further study. Possible outcomes include:
(1) Identification of the additional amount of SO
(2) Identification of the additional amount of NO
(3) Identification of another pollutant that should be considered part of significant contribution and interference with maintenance for states that
(4) Determination that the reductions proposed in today's rulemaking would fully address significant contribution and interference with maintenance at these sites.
If EPA determines that more SO
To the extent that EPA determines that more NO
EPA plans to move forward aggressively in the event that these further reductions are needed. We do not, however, intend to delay the reductions in this proposed rule because those reductions have a substantial impact on states' abilities to attain the NAAQS in the required time period and have large health benefits.
This section discusses, for the 1997 ozone standards, how EPA applies its multi-step methodology for defining each state's significant contribution. For some aspects of the methodology, further work is needed to complete the methodology for ozone and this further work will be completed in a separate proposal.
In this subsection, we discuss how EPA identifies for ozone the years to analyze for eliminating significant contribution. Similar to the previous discussion for PM
As noted earlier, the 2012 ozone season is the last ozone season before the 2013 attainment deadline for ozone areas classified as “serious” for the 1997 ozone air quality standards. Thus, for any states “linked” to “serious area” locations for which 2012 is the latest ozone season prior to their attainment deadline, EPA believes that 2012 is the appropriate year for eliminating significant contribution, to the extent that purpose can be achieved given the short time period. Because this proposed rule would not be finalized until 2011, the year 2012 also represents the earliest time by which emissions reductions could be achieved, which is consistent with statutory provisions calling for downwind states to achieve attainment “as expeditiously as practicable.” This also is relevant for certain other areas with lower ozone classifications that are projected in our analysis to have continuing air quality problems and to be affected by transported pollution from certain upwind states in amounts greater than the 1 percent threshold.
EPA is concerned that the timing of this rule presents difficult challenges in eliminating significant contribution and interference with maintenance with regard to the 1997 ozone NAAQS by the attainment date. For states with a 2012 (or earlier) attainment date for which we project continuing ozone problems, we are concerned that strict adherence to a 2012 date for reductions could be viewed as an artificial constraint on our ability to require appropriate reductions. EPA believes that the current situation for ozone, involving a transport rulemaking within months of the attainment date (and in a number of cases, after the current attainment date) is a unique situation created by the Court's remand of the CAIR. Under normal circumstances adhering to the CAA schedule for addressing transport within 3 years after a NAAQS is promulgated, transport requirements would be in place years before the attainment date. For purposes of our analysis of ozone for areas with a 2012 attainment date, EPA proposes that we should not be constrained to only considering those reductions that are possible by 2012.
Another reason that it would be inappropriate to limit upwind state responsibility based on the downwind area's current attainment date is that the statute contains provisions for extension of attainment dates. To the extent that downwind states have continuing ozone air quality problems after 2012, the Act requires that they be reclassified, which allows the downwind area to qualify for a later attainment date that is as expeditious as practicable but no later than 2019 (2018 emissions year).
If in determining upwind state reduction responsibilities EPA were to automatically assume that downwind states will attain on time despite pollution transport, this assumption would have the effect of absolving the upwind state of responsibility for any reductions in pollution transport that could not be achieved by the downwind area's current attainment date. EPA does not believe this would be appropriate. This would transfer emissions control responsibility from the upwind state to the downwind state in any case when the area did not attain by its current attainment date, and could delay for years the date when the public would breathe air that meets health-based standards.
Accordingly, for all the reasons discussed previously, we address both 2012 and 2014 in our analysis, and we do not believe that examining 2012 only would be appropriate. EPA has chosen to examine 2014 air quality results because, based on a conservative estimate, 2014 is the earliest year for which significantly more stringent NO
One area in the eastern half of the U.S. covered by this proposal, Houston,
Using IPM, EPA developed cost curves for 2012 for ozone season NO
For some states (particularly those which are not regulated by the NO
As discussed in section IV.D.3 later, little or no ozone season NO
For this reason, we are not addressing in this proposal whether cost per ton levels higher than $500/ton are justified for some upwind states and downwind receptors for ozone purposes. However, we are presenting the information we have on potential EGU reductions at higher cost levels for informational purposes. EPA intends to develop similar emissions reductions and cost information for sources other than EGUs and, in a future rulemaking, to consider whether or not reductions at a higher cost per ton are warranted for EGUs and other source categories.
EPA developed EGU emissions reductions cost curves for 2014 as well as 2012. EPA believes it is useful to understand and display emissions reductions capabilities for 2014, the first year for which further emissions reductions could be achieved through the installation of add-on controls such as SCR. These 2014 ozone season
EPA uses an air quality assessment tool for ozone to assess the effect of NO
EPA also includes in Table IV.D-9 results for 2014 before and after the imposition of currently installed controls (that is, for the base case or zero dollars per ton, and for the case for which all controls are applied up to $500/ton). Because there are substantial reductions in ozone season NO
Using the multi-factor cost and air quality methodology described in section IV.D.1, EPA identifies, for a number of states, the 2012 emissions reductions that eliminate the significant contribution to nonattainment of the 1997 ozone NAAQS and interference with maintenance to the 1997 ozone NAAQS.
As discussed previously, $500/ton represents the cost level for which EPA has complete information across source categories and represents the level for which significant emissions reductions are available in 2012. Large additional reductions in 2012 cannot be achieved given the insufficient amount of time for sources to install controls. Compared to NO
Considering the upwind-downwind state policy considerations discussed previously, $500/ton NO
EPA believes that on purely reasonableness or highly cost effective grounds, a value considerably greater than $500/ton could be justified. EPA notes that the $2,000/ton threshold for highly cost effective ozone season NO
Using the air quality assessment tool, EPA determined that emissions reductions from ozone season NO
EPA proposes, as discussed previously, that EPA is not artificially constrained in considering reductions beyond 2012 and that it is relevant to address possible air quality impacts of additional emissions reductions that could be achieved by 2014, the first year for significant additional controls. At the same time, EPA proposes that while 2014 is a relevant year to consider, it is also relevant to consider the nature of the air quality problem in 2014 even in the absence of further transport controls that could be achieved by that date. Taking all of these 2014 considerations into account, the air quality assessment tool results show that in 2014 ozone problems remain only for locations in Houston and Baton Rouge. Thus, EPA believes that additional post-2012 controls, beyond the $500/ton reductions that are justified based on 2012, are possibly warranted for states that are linked to Houston and Baton Rouge. (See also discussion later on the issue regarding New York City raised by air quality modeling results.)
Based on the cost and air quality considerations, EPA proposes $500/ton as the appropriate cost threshold for the following states which contribute to downwind nonattainment and/or maintenance problems in 2012, but which are not linked to ozone air quality problems in either Houston or Baton Rouge: Connecticut, Delaware, the District of Columbia, Indiana, Iowa, Kansas, Maryland, Massachusetts, New Jersey, New York, North Carolina, Ohio, Oklahoma, Pennsylvania, South Carolina, Virginia, and West Virginia.
For states linked to ozone air quality problems in Houston or Baton Rouge, EPA has not yet identified a cost threshold for eliminating significant contribution. EPA does, however, propose to find that those states must make at least all of the reductions that can be achieved for $500/ton in 2012. These states are: Alabama, Arkansas, Florida, Georgia, Illinois, Kentucky, Louisiana, Mississippi, Tennessee, and Texas. For these states, the $500/ton threshold represents emissions reductions that EPA believes are an essential part of the ultimate emissions reductions amount that will be required to eliminate the significant contribution and interference with maintenance. This level does not represent a complete significant contribution determination for these states because neither the analysis of costs up to $500/ton, nor the analysis of air quality impacts of the corresponding emissions reductions, suggest that those reductions necessarily represent all reasonable upwind state reductions. For the reasons stated previously in subsection 2.b, EPA believes it is appropriate and consistent with the statutory mandate to consider whether section 110(a)(2)(D)(i)(I) requires further reductions from these states after 2012 for purposes of the 1997 ozone standard.
To determine whether further reductions are warranted, EPA is expeditiously conducting further analysis. EPA is continuing to develop and evaluate NO
As in the case of PM
Previously in this section (see discussion in IV.D.2 previously) EPA discusses its proposed cost criteria for identifying SO
As described previously, EPA is proposing to define significant contribution on the basis of cost informed by air quality impacts, and to conclude $2,000/ton represents the highest cost value necessary for SO
For the CAIR, EPA included a technical support document
For ICI boilers, most of the SO
For Portland cement manufacturing, information from a 2006 report prepared by the Lake Michigan Air Directors Consortium (LADCO) estimated costs for SO
For petroleum refining, the largest sources of SO
For sulfuric acid manufacturing, the SO
This information shows that few if any SO
Because sulfur content of both gasoline and diesel fuel are now subject to very stringent sulfur requirements, EPA believes there are no available on-road and nonroad engine measures to reduce mobile source SO
For NO
For the CAIR, the technical support document
EPA has not identified additional non-EGU controls that can be achieved at $500/ton or less. For example, available information
For the NO
EPA has not identified further controls for stationary nonpoint sources or mobile source NO
As described later, EPA used the cost thresholds identified for each covered state in the previous section and applied them to state-specific data to develop individual state emissions budgets. These budgets facilitate implementation of the requirement that significant contribution and interference with maintenance be eliminated. A state's emissions budget is the quantity of emissions that would remain in that state from covered sources after elimination of that portion of each state's significant contribution and interference with maintenance that EPA has identified in today's proposal, before accounting for the inherent variability in power system operations (
Because the budget represents emissions that would remain without accounting for variability, it also represents the amount of emissions that would remain after significant contribution and interference with maintenance have been addressed, in an average year. In a year when base case emissions would have been higher than average (
For group 1 states required to make deeper emissions reductions in 2014, EPA based each state's 2014 budgets on the same projections from IPM that were used as inputs into the cost curves explained in section IV.D.2.a previously. For SO
For 2012 NO
For
Ozone season NO
These budgets are based on a 5 month ozone season (May 1 through September 30). Consistent with the approach taken by the OTAG, the NO
In this section, EPA discusses the inherent variability in electric power system operation and presents proposed variability limits for each state. As explained below, EPA proposes to calculate variability limits for each state and to use those variability limits in conjunction with the budgets (which are based on expected average conditions) to provide limited flexibility (within the limits allowed by the variability provisions) to address years in which more fossil generation occurs than projected in the average base case year. This section also presents projected emission reduction results.
Historically, power sector emissions have varied over time. Factors, such as fuel switching and installing new emissions controls, which can lead to significant decreases in emissions, primarily affect emissions rates rather than generation and change largely as a result of pollution regulation.
Even when emissions rates do not change from year to year, overall emissions can change because of factors including power demand, timing of maintenance activities, and unexpected shutdowns of units. Extreme weather conditions, sudden economic shocks, and other unpredictable events can also significantly impact power generation from fossil units. These factors relate directly to heat input, generation, and the routine operation of power plants to supply our electricity, and thus affect total emissions.
As discussed previously, EPA has identified a specific amount of emissions that must be prohibited by each state to satisfy the requirements of CAA section 110(a)(2)(D)(i)(I). EPA has also developed state budgets based on its projections of state emissions in an average year after the elimination of such emissions. However, because of the unavoidable variability in baseline emissions—resulting from the inherent variability in power plant operations—state-level emissions may vary somewhat after all significant contribution and interference with maintenance that EPA has identified in this proposal are eliminated. This occurs even when the emissions rates of the units within the state do not change. For this reason, EPA has determined that it is appropriate to develop variability limits for each state budget. These limits are used to identify the range of emissions that EPA believes may occur in each state following the elimination of all significant contribution and interference with maintenance.
For the proposed rule, EPA proposes to factor this variability explicitly in its consideration of how to control emissions. The Agency believes that because baseline emissions are variable, emissions after the elimination of all significant contribution are also variable and thus it is appropriate to take this variability into account.
As discussed in detail in section V, EPA proposes and considers specific regulatory remedies that are designed to meet the emissions budget in an average year. Because base case emissions may vary from projections, EPA believes these same remedies may incorporate provisions that account for variability. This variability, however, must be limited to provide downwind states with assurance that necessary reductions will be made in upwind states. This section describes how EPA calculated variability limits for each state to achieve this goal.
Remedies (
In all these cases, variability limits can be used to retain the flexibilities that the various remedies provide to deal with real-world variability in the operating system, while still providing downwind states reasonable certainty about the level of upwind emissions.
EPA also notes that explicit consideration of variability in the emissions resulting from a remedy is consistent with removing a state's “significant contribution.” As noted previously, even if the emissions result is variable from year to year, there is still a similar increment of emissions reductions. For example, because increased emissions in the control case would also correspond to increased emissions in the base case, the increment of emissions representing significant contribution and interference with maintenance would still be removed. Finally, as is explained more below in IV.F.b, the variability limits (as applied, for instance, in the State Budgets/Limited Trading remedy in section V.D.4) are relatively low and thus the total amount of variability allowed is very small compared to total EGU emissions and even smaller when considering all of the emissions within a state. It is also worth noting that in the proposed State Budgets/Limited Trading remedy, variability is taken into account in such a way that does not allow an overall increase in emissions. Under this remedy, an individual state could emit up to its budget plus variability limit. However, the requirement that all sources hold allowances to cover emissions, and the fact that those allowances are allocated based on state-specific budgets absent variability, would ensure that total emissions do not increase. This remedy, therefore, ensures not only that total emissions do not increase above state budgets, but also that reductions occur in each and every state.
EPA determined 1-year variability limits and 3-year rolling average variability limits for each state. First, EPA determined 1-year variability limits based on historical variability in heat input. Second, EPA determined 3-year rolling average variability limits using statistical methods to convert the 1-year variability into 3-year variability. The approaches EPA used to determine the
The focus of the analysis is on quantifying the magnitude of the inherent variability in the baseline emissions (on both a 1-year and a 3-year basis). The goals of this analysis, therefore, are to determine the typical variability in emissions that is due to changes in generation, and not due to changes in emission limits, and to set emissions criteria limits that can be used as part of a remedy to ensure that states are eliminating their significant contribution and interference with maintenance to protect air quality.
EPA used statewide average emissions rates projected using IPM to convert historical heat input variability into corresponding emissions variability limits. The approach assessed the variability in state-level heat input over a 7-year time period (2002 through 2008) using the standard deviation and then determined the difference in emissions from the 95th percent two-tailed confidence level and the mean.
From the state-by-state tonnage and percentage emission variability values, EPA identified a single set of variability levels (that is, a tonnage and a percentage) based on the historic variability. EPA made the decision to adopt a single, uniform tonnage and percentage level pairing to apply to all states in order to make the application of the variability limits straightforward rather than developing state-by-state percentage variability values. The effect of the pairing is to ensure that each state is allowed adequate variability while minimizing the total amount of emissions allowed. Using, for all states, only a constant percentage (reflecting emissions variability in smaller states with a greater range of emissions in percentage terms) would result in large states being allowed greater variability than needed. Conversely, using only a constant tonnage (reflecting emissions variability in larger states with a greater range of emissions in tonnage terms) would result in small states being allowed greater variability than needed. To ensure adequate variability limits—even in states with small numbers of units where expected variability would be more pronounced in percentage terms, and in large states where expected variability would be more pronounced in absolute tonnage terms—EPA derived variability limits both as a percentage and in terms of absolute emissions (tons) that serve to minimize the total amount of emissions allowed under this combination variability limit approach.
For the tonnage and percentage limit criteria, EPA looked at a wide range of percentage and tonnage combinations, and chose for further investigation combinations that provided states sufficient variability limits (based on historic variability) and fit the requirement of minimizing the allowed emissions. Power plants in states that were close to the variability limits were evaluated more closely to ensure the modeling reflected all controls known to operate. EPA believes that the chosen limits would not be tighter than these states could be expected to meet.
This approach (identifying both a tonnage and a percentage) addresses the difficulty that smaller states with fewer units could face if only percentages were used to set the limits. For instance, in a small state with a budget of 5,000 tons of SO
For both annual NO
EPA assigned each state one of these values—either the tonnage limit or the percent limit, whichever was greater for that state. For instance, 10 percent of Connecticut's SO
While the year-to-year variability in emissions could lead to variability in 3-year rolling averages, inherent variability is lower over a 3-year time period than over a 1-year period and thus a state's 3-year variability limit will be lower than the state's 1-year variability limit. Establishing such 3-year limits thus provides an opportunity to ensure that the variability limits do not allow greater fluctuation in emissions than justified based on historic variability. EPA estimated the variability in a state's emissions over a 3-year time period based on the expected variability in emissions for a single year.
As summarized later and described in the Power Sector Variability TSD, the Agency used statistical methods to estimate the 3-year variability based on 1-year variability. The average variability of a multi-year sample is the average variability of a single year divided by the square root of the number of years in the multi-year sample.
Proposed 3-year variability limits for each covered state are shown in the tables in section IV.F.2, later.
As explained previously, EPA determined variability limits for each state. EPA then applied these variability limits on a state-by-state basis to calculate state-specific emissions budgets with variability limits. EPA calculated state budgets with both 1-year and 3-year variability limits.
Table IV.F-1 shows proposed variability limits by state on SO
EPA also requests comment on an alternative calculation method for variability. The alternative method would use the results of the proposed method but add a ceiling based on the maximum percentage of variability among covered states as observed in the historic heat input data described previously. For both NO
For instance, although Connecticut's proposed 1-year variability limit of 1,700 tons is greater than 10 percent of its SO
The NO
Using that approach, the resulting ozone season 1-year variability limits are 2,100 tons and 10 percent of a state's budget. EPA assigned each state one of these values-either the tonnage limit or the percentage limit, whichever was greater for that state—using the same approach as for the SO
EPA did not explicitly model ozone season variability limits because it was assumed that the NO
As with the SO
EPA requests comments on the NO
As discussed in section V.D, the proposed FIPs would apply the 1-year variability limits commencing in 2014 and the 3-year variability limits commencing in 2016, noting that application of the 3-year average limits in 2016 would serve to limit each state's emissions in 2014 and 2015. The Agency also requests comment on whether the remedy in the proposed FIPs should be modified so that the limits would apply starting in 2012 instead of 2014. In addition, the direct control remedy option on which EPA requests comments includes assurance provisions based on these variability limits that would apply starting in 2012. Thus, EPA also explains later what variability limits would apply in 2012 and 2013. The 1-year variability limits for 2012 and 2013 would be the same as the variability limits for 2014 and later in Tables IV.F-1, IV.F-2, and IV.F-3 for all state budgets except for the SO
If EPA finalizes a remedy that uses the 2012 and 2013 variability limits, EPA would also start applying the 3-year variability limits in 2014 (for all state budgets except group 1 SO
In this alternative approach, the 15 SO
Additionally, commencing in 2013, EPA would apply in these 15 states a distinct 2-year average variability limit on SO
For an alternative approach where variability limits start in 2012 instead of 2014, EPA considered—instead of two-year average limits on SO
Table IV.F-4 includes 1-year and 2-year variability limits calculated according to the proposed methodology. The 2-year limits are the 1-year limits divided by the square root of two. The table does not include separate columns with variability limits calculated according to the alternative calculation method (
Table IV.F-5 presents projected power sector emissions in the base case (
The methodology described previously quantifies states' significant contribution and interference with maintenance in a manner that is consistent with the decisions of the DC Circuit. As discussed in section III previously, the DC Circuit has issued two significant decisions addressing the requirements of 110(a)(2)(D)(i)(I). The first opinion largely upheld the NO
In
For this proposed transport rule, EPA uses a first step similar to that used in the CAIR to identify the states with relatively large contributions. However, in contrast to the CAIR, it then uses a state-specific analysis. Instead of identifying a single emissions level that could be achieved by the application of highly cost effective controls in the region, EPA determines, on a state-by-state basis what reductions could effectively be achieved by sources in that state. EPA's new approach does not, as the CAIR methodology did, establish a regional cap on emissions that is then divided into state budgets that set the emission reduction requirements for each state. Instead, EPA develops, for each covered state, emissions budgets based on the reductions achievable at a particular cost per ton in that particular state, taking into account the need to ensure reliability of the electric generating system. The selected cost/ton levels reflect consideration of both cost factors and air quality factors including the estimated impact of upwind states' emissions on each downwind receptor.
In addition, in developing this approach, EPA was guided by the Court's holdings regarding the use of cost to identify significant contribution. Specifically, the Court held in
For these reasons, EPA determined that it was appropriate in this rulemaking to consider the cost of controls to determine what portion of a state's contribution is its “significant contribution.” However, EPA also heeded the
In addition, the methodology used in this rulemaking gives independent meaning to the interfere with maintenance prong of section 110(a)(2)(D)(i)(I). In
EPA applied this methodology using available information and data to measure the emissions from states in the eastern United States that significantly contribute to nonattainment or interfere with maintenance in downwind areas with regard to the 1997 and 2006 PM
EPA evaluated a number of alternative approaches to defining significant contribution and interference with maintenance in addition to the approach proposed in this rule. Stakeholders suggested a variety of ideas. EPA considered all suggested approaches.
EPA evaluated approaches including those based solely on air quality, based solely on cost with a uniform cost in all states, based on cost per air quality impact (
EPA is not proposing any of the alternative approaches listed here. However, the proposed approach (described in section IV.D) incorporates some elements from these approaches.
This section describes the proposed emissions control requirements in detail. The section starts with V.A which discusses the pollutants included in the proposal, followed by V.B which discusses the source categories covered. Section V.C discusses the timing of the proposed emissions control requirements. Section V.D describes the proposed approach to implement the emission reduction requirements, starting with a description of the NO
In this action, EPA is proposing FIPs to directly regulate upwind emissions of SO
EPA is proposing to require emissions reductions from the power sector. This section discusses EPA's rationale for proposing to control power sector emissions, and our rationale for not proposing to control emissions from other source categories at this time.
The proposed Transport Rule FIPs would require EGUs with capacity greater than 25 MWe in the covered states to reduce emissions of SO
Electric generating units are important sources of SO
EPA has previously conducted extensive analyses of the cost and emissions impacts of SO
Based on these analyses, EPA believes that there exist reasonable means for EGUs to make substantial reductions in emissions of SO
In these proposed FIPs, EPA is not proposing to include emission reduction requirements for sources other than EGUs.
In the proposed FIPs to address the section 110(a)(2)(D)(i)(I) requirements with respect to the 1997 and 2006 PM
In the FIPs for this proposed rule, EPA is only proposing to require reductions from EGUs to address emissions from those source categories that significantly contribute to or interfere with maintenance of the 1997 ozone NAAQS. As discussed previously in section IV.D, EPA's review of the costs of EGU and non-EGU controls resulted in a conclusion that significant NO
For future ozone and PM
EPA is proposing an initial phase of reductions in 2012 followed by a second phase in 2014. Sources will be required to comply with the annual SO
For all areas designated as nonattainment with respect to the 1997 PM
Upwind emissions reductions achieved by the 2014 emissions year will help areas that failed to meet the April 2010 deadline, to meet the April 2015 deadline for the 1997 PM
Further, a deadline of January 1, 2014 also provides adequate and reasonable time for sources to plan for compliance with the Transport Rule and install any necessary controls. EPA believes that this deadline is as expeditious as practicable for the installation of the controls needed for compliance (
Ozone nonattainment areas must attain permissible levels of ozone “as expeditiously as practicable,” but no later than the date assigned by EPA in the ozone implementation rule (40 CFR part 51). The areas designated nonattainment in 2004 with respect to the 1997 8-hour ozone NAAQS in the eastern United States were assigned maximum attainment dates corresponding to the end of the 2006, 2009, and 2012 ozone seasons. Many areas have already attained due in part to CAIR, federal mobile source standards, and other local, state, and federal measures. Those that have not yet attained the standard have maximum attainment dates ranging from 2010 (these are the 2009 areas that have been granted a 1-year extension due to clean data in 2009) to 2018. Areas designated “serious” nonattainment areas have a June 2013 maximum attainment deadline. The proposed Transport Rule's first phase of reductions in 2012 will help the remaining areas with June 2013 maximum attainment deadlines attain the 1997 8-hour ozone NAAQS by their deadline. The reductions will also improve air quality in areas with later deadlines.
EPA is requiring an initial phase of reductions by 2012. These reductions are necessary to ensure that significant contribution and interference with maintenance are eliminated as expeditiously as practicable. This will in turn assist downwind states to achieve attainment as expeditiously as practicable as required by the CAA.
Because the proposed rule, if finalized, will replace the CAIR, EPA cannot assume that after this rule is finalized, EGUs would continue to emit at the reduced emissions levels achieved by CAIR. Instead, it is the emissions reductions requirements in the proposed FIPs that will determine the level of EGU emissions in the eastern United States. For these reasons, EPA is proposing to require an initial phase of reductions by 2012 which would ensure that existing and planned SO
As directed by the Court in
The 2012 deadline for compliance with the limits on ozone-season NO
The 2014 deadline for compliance with the limits on annual NO
In addition, the 2012 compliance deadline for the first-phase of annual NO
As noted, in a January 19, 2010, notice of proposed rulemaking, EPA proposed to strengthen the NAAQS for ozone. In that notice, EPA proposed levels for the ozone standard to a level within the range of 0.060 to 0.070 parts per million. EPA also proposed in this same notice to establish a distinct cumulative, seasonal “secondary” standard, designed to protect sensitive vegetation and ecosystems, including forests, parks, wildlife refuges and wilderness areas.
EPA expects to finalize the revised NAAQS for ozone in August 2010. After the NAAQS are finalized, EPA will be able to identify areas that are expected to have difficulty attaining and maintaining those standards and will evaluate and analyze the impact of upwind state emissions in those areas with regard to those standards. EPA has already begun the technical background work necessary to allow it to move quickly, once the revised ozone standards are promulgated, with a proposal to address upwind emissions that significantly contribute to nonattainment of or interfere with maintenance of those standards. Because that analysis will take some time, and because EPA recognizes the urgency of responding to the concerns raised by the Court in
EPA is also on a schedule to review and, if necessary update the PM
In this rule, EPA is proposing FIPs to eliminate the significant contribution and interference with maintenance EPA has identified in this action. We are proposing one “remedy” option to implement the necessary emissions reductions and taking comment on two other options. Before presenting these options we briefly summarize the approaches used in the NO
In the NO
By notice dated October 27, 1998 (63 FR 57356), EPA took final action to require states to prohibit specified amounts of emissions of one of the main precursors of ground-level ozone, NO
In the final regulation, EPA offered to administer a multi-state NO
The NO
In CAIR, EPA offered states optional regionwide cap and trade programs, which were similar to the SO
The U.S. Court of Appeals granted several petitions for review of the CAIR and remanded the rule to EPA. Because the Court decided to remand the rule without vacatur, however, CAIR remains in effect. This proposed rule would replace the CAIR upon final promulgation.
Challenges to both the NO
Petitioners' second objection to the use of uniform controls was that it failed to take into account the fact that the location of emissions reductions may affect the impact of those reductions on downwind nonattainment areas. Petitioners argued that because reductions closer to the nonattainment area have a greater benefit, EPA's use of a highly-cost-effective standard and region-wide emissions trading did not guarantee that it would have secured the rule's health benefits at the lowest cost.
Petitioners challenging the CAIR also raised issues related to EPA's use of an interstate trading program to satisfy the requirements of section 110(a)(2)(D)(i)(I). Petitioners challenged both the trading program itself and the state budgets. These budgets were used to determine the number of emission allowances allocated to sources in each state or, if the state chose not to participate in the trading programs, the specific emission reduction requirements for that state.
The Court concluded, in
The Court also emphasized that section 110(a)(2)(D)(i)(I) “prohibits sources ‘
In developing options to eliminate the emissions identified as constituting all or part of a state's significant contribution and interference with maintenance, EPA has been mindful of the direction provided by the Court. As discussed in greater detail later, EPA believes that each of the remedy options presented is consistent with the Court's opinions interpreting the requirements of section 110(a)(2)(D)(i)(I).
EPA is proposing one “remedy” option to implement the emissions reductions requirements and taking comment on two alternatives. This section provides a brief overview of the proposed remedy and the two alternatives. Sections V.D.4, V.D.5, and V.D.6, later, describe the proposed remedy and the alternatives in detail.
EPA considered a full range of remedy options in developing this proposal. Among other things, EPA considered variations of direct control options, intrastate cap and trade, interstate cap and trade, hybrids of these approaches, and simple state emissions caps. Stakeholders have suggested a variety of remedy options for EPA's consideration. A TSD in the docket entitled “Other Remedy Options Evaluated” describes other options that EPA evaluated.
Based on its consideration of a range of options, EPA is proposing one remedy option and requesting comment on two alternatives. The proposed remedy option, discussed later, is a hybrid approach that combines limited interstate trading with other requirements. The alternative remedies on which EPA requests comment include an intrastate trading option and a direct control option. The proposed and alternative remedy options would regulate SO
The remedy option EPA is proposing would use state-specific control budgets and allow for intrastate and limited interstate trading of emissions allowances allocated to EGUs. This approach would assure environmental results while providing some limited flexibility to covered sources consistent with the Court decision as described later. The approach would also help ease the transition for implementing agencies and covered sources from CAIR to the Transport Rule. Based on consideration of a range of options, EPA believes that the proposed option is the best approach, for the reasons discussed in section V.D.4.
The Agency is also presenting other alternative remedies for comment. The first alternative for which EPA requests comment would use state-specific control budgets and allow intrastate trading of emissions allowances allocated to EGUs, but no interstate
EPA recognizes there could be cost savings from an approach that uses aless restrictiveinterstate trading option. EPA also recognizes that unrestricted trading programs including the NO
In this action, EPA is not proposing such an unrestricted trading program, because EPA does not believe that such an option could provide assurance that each state achieves emissions reductions within the state, as required by the
In addition to considering unrestricted trading, EPA also considered whether there were other ways that a trading program could be structured to address the Court's concerns. In particular, EPA reviewed a methodology that had been investigated during the development of the NO
In the SIP Call, EPA did not ultimately propose this methodology for several reasons. First, the Stratus Consulting study (“Development and Evaluation of a Targeted Emission Reduction Scenario for NO
In addition, in considering this approach in the original SIP Call, it took close to a year to perform the underlying analysis to develop ratios for 1 pollutant (NO
EPA requests comment on the trading ratios approach, including whether: The trading ratio approach described above would be consistent with the Court opinion in
Analysis from the SIP Call suggests that the trading ratios approach might have the potential to slightly reduce costs. However, the approach, as envisioned, appears to be in tension with EPA's mandate under section 110(a)(2)(D)(i)(I) to assure that significant contribution is fully addressed in each upwind state. While such an approach would ensure reductions on a region-wide basis, EPA has not been able to identify a way that the trading ratio approach could be modified to assure a specific set of downwind emissions reductions from all states. Under such an approach, there is the potential that some upwind states might make reductions that are larger than their significant contribution, while other states might make reductions that are less than their significant contribution. Because the state budgets have been designed to achieve all reductions available at a given cost, trading ratios other than one to one, although providing equivalent improvements in downwind air quality would lead to emissions reductions that were inconsistent with the initial budgets.
Because EPA recognizes the potential cost savings and potential improvements in program effectiveness associated with less restricted trading options, EPA is also requesting comment on the appropriateness of the assurance provisions that have been proposed, including whether they are adequate to assure that significant contribution and interference with maintenance are addressed in each state, whether they are overly restrictive, and whether there are less restrictive options that would provide adequate assurance that the statutory mandate is satisfied while providing more flexibility. Alternative approaches could potentially include: Using the basic methodology proposed with a higher or lower variability limitation or using an alternative to the approach to assure that state emissions budgets are met (
EPA specifically requests that any commenter suggesting a less restrictive approach address how the commenter's preferred approach would satisfy the statutory mandate in section 110(a)(2)(D)(i)(I) of the Clean Air Act and be consistent with the decision of the DC Circuit in
As discussed in section IV.E, EPA is proposing new state budgets developed on a different basis from the CAIR budgets. The intrastate and interstate trading remedy options would use new allowance allocations, also developed on a different basis from the CAIR FIP allowance allocations.
As discussed in section IV.F, EPA believes that inherent variability in power system operations affects each state's baseline emissions and thus also affects a state's emissions after elimination of all significant contribution and interference with maintenance. Thus, emissions may vary somewhat after implementation of the remedies under consideration. This includes the proposed remedy option (State Budgets/Limited Trading), the intrastate trading alternative, and the direct control alternative. Sections V.D.4, V.D.5, and V.D.6 describe variability approaches for the proposed remedy and each of the alternative remedies.
EPA also considered only establishing state emissions caps. Such an approach would define what must be done to eliminate all (or in some cases part) of each state's significant contribution and interference with maintenance, but it would not implement specific requirements to eliminate those emissions. As described in section III.C in this preamble, EPA decided to implement the emission reduction requirements through FIPs. To do so, EPA recognized that it needed to do more than establish simple state emissions caps. For this reason, EPA rejected the simple state emission cap option.
As with any FIP that EPA issues, a covered state may submit, for review and approval, a state implementation plan (SIP) that replaces the Federal requirements with state requirements that would achieve the required reductions. A state's SIP submission to replace the Transport Rule FIP might propose to use any remedy of the state's choosing that actually eliminates the emissions that significantly contribute to nonattainment or interfere with maintenance downwind. Section VII in this preamble further discusses SIP submissions.
In this action, EPA is proposing FIPs that would establish state-specific emission control requirements using state budgets starting in 2012 in 32 states.
The proposed FIPs would address the elimination of significant contribution and interference with maintenance by 2014. A first phase of reductions would be required by 2012 to assure that significant contribution and interference with maintenance are eliminated as expeditiously as practicable.
To directly eliminate the portion of each state's significant contribution and interference with maintenance that EPA has identified in this action, the proposed remedy utilizes the state budgets with variability limits described in section IV. The budgets without variability limits are used to determine the number of allowances issued to sources in each state. Each affected source must hold, and surrender to EPA, allowances equal to its emissions during the compliance period. In addition, assurance provisions under the proposed remedy cap each state's EGU emissions at a state-specific budget with a variability limit to ensure that every state actually reduces, within the state, all emissions necessary to eliminate the portion of its significant contribution and interference with maintenance that EPA has identified in today's proposal.
For the 2012-2013 transition period, EPA is taking comment on whether the assurance provisions used to limit interstate trading are needed, since the state-specific budgets are based on known air pollution controls and thus a high level of certainty exists about where reductions will occur. As described later, the proposed FIPs include penalty provisions that are adequate to ensure that the budget including a variability limit will not be exceeded so that each state eliminates the portion of its significant contribution and interference with maintenance that EPA has identified in today's proposed action.
The proposed remedy establishes four interstate trading programs starting in 2012: Two for annual SO
New emissions allowances based on the new state budgets without variability would be allocated to individual sources, as described later. Four sets of allowances would be allocated, one for each of the four trading programs (SO
Sources would be allowed to trade allowances. However, the assurance provisions would limit total emissions from each state, restricting the variability of emissions from any particular state to the variability associated with its baseline emissions prior to the elimination of all or part of the state's significant contribution or interference with maintenance.
Allowance banking is permitted. Banking (or saving) allowances for future use in any given year allows sources flexibility in compliance planning. Banking lowers costs and helps reduce market volatility. Banking also acts as an incentive to reduce emissions early and accumulate allowances that can be used for compliance in future periods. Because the early reductions encouraged by the ability to bank allowances would result in the reduction of emissions below allowable levels earlier than required, the environmental and human health benefits of the reductions would accrue sooner.
The requirements in the proposed FIPs would apply to large EGUs. Specifically, a covered source would be any stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine serving at any time, since the later of November 15, 1990 or the start-up of the unit's combustion device, a generator with nameplate capacity of more than 25 MWe producing electricity for sale. The term “fossil fuel” is defined as including natural gas, petroleum, coal, or any form of fuel derived from such material. This is the same definition that was used in CAIR and would include all material derived from natural gas, petroleum, or coal, regardless of the purpose for which such material is derived. For example, with regard to consumer products that are made of materials derived from natural gas, petroleum, or coal, are used by consumers and then used as fuel, these materials in the consumer products would qualify as fossil fuel.
Certain cogeneration units or solid waste incinerators otherwise covered by this general category of covered units would be exempt from the FIP requirements. These proposed applicability requirements are essentially the same as those in the CAIR model trading rules and CAIR FIPs (reflecting the revised cogeneration unit definition promulgated in October 2007 (72 FR 59195; October 19, 2007)), with some technical corrections to the exemptions.
These proposed elements of the “cogeneration unit” definition are very similar to the definition used in CAIR. However, there are two technical differences. First, under the definition used in CAIR to qualify as a “cogeneration unit,” a unit had to meet
As discussed previously, the operating and efficiency standards in the “cogeneration” definition must be met every year. However, EPA is concerned whether these annual standards should be applied to a calendar year when the unit involved did not operate at all. For such a year, the unit would be unable to meet the operating and efficiency standards but also would not have any emissions. EPA therefore requests comment on whether it should exclude, from the requirement to meet the operating and efficiency standards, calendar years (if any) during which a unit does not operate at all.
If a unit meets the definition of cogeneration unit (including the efficiency and operating standards), then it may qualify for the proposed cogeneration unit exemption depending on whether it meets additional criteria concerning the amount of electricity sales from the unit. In order to qualify for the exemption, a cogeneration unit would need to supply in any calendar year—starting the later of November 15, 1990 or the start-up of the unit's combustion chamber—no more than one-third of its potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale. EPA requests comment on whether it may be problematic to obtain sufficiently detailed information about the disposition of a unit's generation (
Further, analogous to the approach proposed for the cogeneration unit exemption, the proposed solid waste incineration unit exemption would apply to units that qualify as solid waste incineration units every year starting the later of November 15, 1990 or the date the unit first produces electricity. EPA requests comment on whether it may be problematic to obtain sufficiently detailed information about whether a unit qualified as a solid waste incineration unit back to November 15, 1990 and whether the qualification requirement should be restricted to more recent years by imposing the qualification requirement every year starting the later of a date (
EPA also proposes to make explicit in the FIPs an interpretation that the Agency adopted in applying CAIR, namely that—solely for purposes of applying the fossil-fuel use limitation in the solid waste incineration unit exemption—the term “fossil fuel” is limited to natural gas, petroleum, coal, or any form of fuel derived from such material “for the purpose of creating useful heat.” For example, this means that consumer products made from natural gas, petroleum, or coal are not fossil fuel, for purposes of determining qualification under the limitation on fossil-fuel use, because the products (
Specifically, the proposed opt-in provisions would allow a non-covered unit to enter a proposed trading program voluntarily and obtain an allocation of
The proposed opt-in provisions would establish the following procedures, which are similar to those set forth in the CAIR FIPs. A unit would be eligible to opt into one of the proposed trading programs if the unit: (1) Is an operating boiler, combustion turbine, or other stationary combustion device; (2) is in a facility that is located in a state subject to that proposed trading program; (3) vents all its emissions through a stack or duct; and (4) would be able to meet the monitoring, reporting, and recordkeeping requirements for covered units under the proposed trading program. The owners and operators, through a designated representative, of a source with a unit seeking to opt in would submit to EPA an opt-in application, which must include an emissions monitoring plan for the unit. If EPA approved the monitoring plan, the unit would operate, monitor, and report emissions in accordance with the monitoring plan and monitoring and reporting requirements under Part 75, for at least one or for up to 3 full calendar years (or full ozone seasons, in the case of an opt-in unit in the proposed NO
After the monitoring period, EPA would review the opt-in application and either approve the application (including an allowance allocation for the first year of approved opt-in status), effective January 1 (May 1 for the NO
After the opt-in unit was in the program for at least four years, the owners and operators could request to withdraw the opt-in unit at the end of a control period if the unit met the requirement to hold allowances covering emissions for that control period and if any allowances already allocated for a subsequent control period were surrendered. However, the owners and operators could not submit a new opt-in application for the withdrawn unit until at least 4 years after the last control period before the withdrawal. An opt-in unit that had a change in regulatory status during a control period and would then meet the general applicability requirements for covered units would immediately lose its status as an opt-in unit. Having lost its opt-in unit status, the unit would have to surrender to EPA the allocated opt-in allowances attributable to the portion of any control period during which the unit no longer qualified as an opt-in unit.
In addition to a general request for comment on all aspects of this opt-in requirement, EPA requests comment on three specific aspects of the proposed opt-in provisions. First, EPA requests commenters to explain how much interest they believe owners and operators of noncovered sources would have in using these proposed provisions to opt into one or more of the proposed trading programs and what types of sources would be most likely to opt in. Commenters on this aspect of the proposed provisions should consider what effect (if any) future emission reduction requirements under upcoming, new regulations (
Second, EPA requests comment on whether it is necessary to take steps to identify in this application process whether emissions reductions identified by these facilities are reductions units would not have made for other reasons unrelated to the opt in. Comments on this issue would be especially useful if they discussed how the proposed opt-in provisions could be revised in order to ensure that opt-in units would not be credited for emissions reductions that the units would make even if they did not opt in. For example, a unit that, for business or other reasons, was already planning to take actions that would have the effect of reducing emissions (
In the Northeast, a large number of EGUs serving generators with a nameplate capacity equal to or less than 25 MWe contribute NO
EPA proposes to distribute, to sources in each state, a number of emissions allowances equal to the SO
In the SO
In each of the four trading programs, a covered source would be required to hold sufficient allowances to cover the emissions from all covered units at the source during the control period. EPA proposes to assess compliance with these allowance-holding requirements at the source (
This section explains how EPA proposes to allocate to two sets of units in a state, existing units and new units. This section also describes the new unit set asides in each state, allocations to units that are not operating, and the recording of allowance allocations in facility accounts.
EPA proposes to base allocations to existing units on projected emissions from these units after elimination of some or all significant contribution and interference with maintenance (
EPA requests comment on all aspects of the allocation method, such as the overall state budgets, the need to have existing unit and new unit allowance allocations, the proposed allocation methodology for existing units, and the proposed allocation methodology for new units. EPA believes the proposed approach is consistent at the state budget and unit level with the Court's direction and also addresses the new unit issue. The proposed methodology for allocating allowances does not consider heat input or fuel adjustment factors. Note that in light of the Court decision, EPA also is not proposing any allocation methodologies that rely on Title IV existing allowances.
EPA requests comment on whether there are alternative allocation methods EPA should consider that are consistent with the Court decision. EPA asks that commenters present any such approaches in detail to enable thorough evaluation and that they provide a legal analysis demonstrating how the approach is consistent with the Court's opinions and the statutory mandate of section 110(a)(2)(D).
For states with lower SO
The proposed FIPs are designed to remove emissions from each upwind state that significantly contributes to nonattainment or interferes with maintenance downwind. The allocation method is consistent with the proposed approach for determining each upwind state's significant contribution and interference with maintenance (described in section IV) because the allocations would be based on the projected remaining emissions from each covered source in each upwind state after removal of the state's significant contribution and interference with maintenance.
EPA proposes to allocate to existing units one time, before the Transport
The proposed unit-level allocations for existing EGUs for Phases I and II are set forth in the “State Budgets, Unit Allocations, and Unit Emissions Rates” TSD in the docket for this rule, but EPA proposes to include them in the final rule in an Appendix A to each set of trading program regulations (
EPA believes it is important to have a small new unit set-aside in each state to cover new units within the budget that was set aside to address the state's significant contribution and interference with maintenance. To create new unit set-asides, EPA would distribute to existing EGUs a quantity of allowances less than the entire state emissions budgets. EPA would hold back, for the new unit set-aside for a state, 3 percent of the state budget. Three percent was established based on the total amount of new unit emissions projected for all the covered states (See “State Budgets, Unit Allocations, and Unit Emissions Rates” TSD). In this way, new units could be allocated some allowances for their emissions, which are part of the the state's contribution to downwind nonattainment or interference with maintenance.
For every control period after the control period in which a new unit commences commercial operation or, in the case of an existing unit that did not operate for three consecutive years, resumes operation, EPA would allocate to the unit from the new unit set-asides based on the unit's reported emissions from the previous control period. EPA would not allocate to a new unit for the control period during which the unit commences commercial operation because the unit would have no actual emissions data on which to base such an allocation.
EPA proposes that, for the first control period for which the new unit wants an allowance allocation from the new unit set aside (after the first year of operation), the designated representative of the source that includes the new unit would submit to EPA a request for a new unit allocation.
For each control period, any allowances remaining in a state's new unit set-aside (after allocations are made to new units that requested allowances) would be distributed to the existing units in that state in proportion to the existing unit's original allocations. This ensures that total allocations to units in the state would equal the state budget.
For each control period, if the size of the new unit set-aside were insufficient to provide allocations for all new units requesting allowances, then allocations to all new units would be proportionally reduced.
EPA requests comment on the proposed allocation approach for new units. EPA also requests comment on alternative allocation approaches that would provide allowances to new units for the control period during which the unit commences commercial operation.
EPA proposes to continue allocating allowances to non-operating units during the 3 consecutive years of non-operation plus an additional 3-year period to reduce the incentive for owners to keep units operating simply to avoid losing the allowance allocations for those units. Other options that EPA considered include continuing to allocate allowances for an unlimited period of time, or
Continuing allocations to non-operating units has the benefit of reducing the incentive to keep units in operation that should otherwise be, for instance, permanently retired due to age and inefficiency. EPA believes there will be less incentive to continue running old, inefficient EGUs if at least some allowances would still be received after retirement. On the other hand, stopping allocations for non-operating units realigns allowance allocations with the sources that actually need such allowances. Non-operating units obviously are no longer emitting and so do not need allowances. Moreover, additional allowances may be needed for the new unit set-aside to accommodate new units coming on line in the future. Allocating allowances for a specified, but limited, period after the unit ceases operating for 3 consecutive years, as EPA proposes to do, would be a middle ground approach to this issue.
EPA requests comment on the proposed approach for allocating allowances to non-operating units. EPA requests comment on simplifying allocations by not allocating at all to non-operating units. EPA also requests comment on maintaining perpetual allocations to non-operating units, similar to the treatment of non-operating units in the title IV Acid Rain Program.
EPA proposes to record initial allowances for existing units in facility accounts by September 1, 2011, for the control periods in 2012, 2013, and 2014. EPA proposes to record allowances for existing units by July 1, 2012 and July 1 of each year thereafter, for the control periods in the third year after the year the allowances are recorded. For example, EPA would record existing unit allowances by July 1, 2012 for control periods in 2015. Recording allowances several years in advance supports the development of the allowance trading markets and provides time for covered sources to plan for compliance.
As discussed previously, EPA proposes to determine allocations to a new unit based on the unit's reported emissions the prior year. Although the last quarter of emissions data for a year must be submitted to EPA in the fourth quarterly emissions report by January 30 of the next year, the emissions data in that report may be revised based on EPA's review and may not be finalized until May or June after receipt of that report. Consequently, EPA proposes to determine new unit allocations by July 1 of the year for which the allocation is determined. (Because, for an ozone season ending September 30, emissions data may not be finalized until the following February or March, EPA proposes to determine new unit allocations by April 1.) For example, EPA would determine a new unit's allocations for control periods in 2012 by July 1, 2012. EPA proposes to make the new unit allocation determinations available to the public through a notice of data availability. Under the proposal, objections to the notice could be submitted, and EPA would issue a second notice of data availability referencing any necessary adjustments of the new unit allocations.
EPA proposes to record allowances for new units by September 1, 2012 and September 1 of each year thereafter, for the control periods in the year that the allowances are recorded. (For the units in the NO
EPA requests comment on the proposed schedule for determining and recording emissions allowances, especially administratively-practical ways to record allowances as soon as possible, so facilities have information useful in compliance planning.
As discussed in section IV, the state emissions budgets are determined based on EPA's analysis of significant contribution and interference with maintenance in each upwind state. EPA believes that it is appropriate to develop individual unit allowances consistent with this approach. In the proposed approach, EPA does this by allocating down to the individual unit level using all of the same assumptions used in developing the proposed budgets. Under this approach all units are allocated allowances consistent with their projected emissions; this means that a unit that installs control equipment receives fewer allowances than a similar unit that did not install control equipment.
EPA is taking comment on an alternative methodology that still links unit allowances directly to the way state budgets were developed (and thus, significant contribution was defined). In the alternative, all units within a state would be treated as a single group. The allocation method would distribute allowances equal to a state's emissions budget without variability to each covered source in the state (in effect, distributing the responsibility for eliminating significant contribution and interference with maintenance) based on each source's proportional share of total state heat input. The state heat input would be as projected for the initial year of the program. In other words, this alternative method for distributing allowances would have the effect of distributing the responsibility for eliminating all or part of a state's overall significant contribution and interference with maintenance to individual units based on each unit's share of projected heat input.
There are other approaches to allocation. For example, EPA could identify groups of units in each state that are capable of having similar emissions characteristics (e.g., grouped by size, fuel type, or age). EPA would distribute a state's emissions budget without variability to each group of units in the state (in effect, distributing the responsibility for eliminating all or part of significant contribution) perhaps based on each group's proportional share of the state budget as projected in the initial year of the program. After apportioning a state's budget to the groups of units, under such an approach EPA could distribute allocations to individual sources within each group based on each source's proportional share of projected heat input. Like the first alternative allocation method described previously, this approach distributes each state's significant contribution and interference with maintenance to individual sources in the state. By determining groups and then distributing allocations within the groups based on proportional shares, this approach would treat units within the categories equally (
EPA requests comment on the proposed allocation approach, the alternative approach, and on any other approaches that are consistent with the Court decision. EPA asks that commenters present any such approaches in detail to enable thorough evaluation and that they provide a legal analysis demonstrating how the approach is consistent with the Court's opinions and the statutory mandate of section 110(a)(2)(D).
EPA proposes that the State Budgets/Limited Trading remedy include an allowance management system (AMS) operated essentially the same as the existing allowance management systems that are currently in use for CAIR and the Acid Rain Program under Title IV. Under the proposed State Budgets/Limited Trading remedy, the SO
EPA proposes to require that Transport Rule-covered sources monitor and report SO
Consistent, complete, and accurate measurement of emissions, as Part 75 requires, ensures that, for a given pollutant, one ton of reported emissions from one source is equivalent to one ton of reported emissions from another source. Thus, each allowance represents one ton of emissions, regardless of the source for which the emissions are measured and reported. This establishes the integrity of each allowance, which instills confidence in the underlying market mechanisms that are central to providing sources with flexibility in achieving compliance.
EPA proposes to require monitoring of SO
Specifically, a new unit must install and certify its monitoring system within 180 days of the commencement of commercial operation. While, under the Acid Rain Program and CAIR, the deadline was the earlier of 90 operating days or 180 calendar days after commencement of commercial operation, EPA intends to propose that part 75 be revised to use only the 180-day deadline. EPA believes that using only the 180-day deadline would ensure that new units have sufficient time to complete installation and certification of monitoring systems without having to request extensions of time and would facilitate compliance by making the monitoring deadline clearer for owners and operators and easier for EPA to apply.
EPA also proposes to require designated representatives to submit quarterly reports that would include emissions and related data and proposes to establish a procedure for resubmission of quarterly reports where appropriate. Specifically, the proposed reporting provisions would include the same requirement to submit quarterly reports as the requirement in Part 75. In addition, the proposed provisions would include language that would make explicit a process that is implicit under, and has been in continuous use in, the Acid Rain, NO
To ensure that the proposed FIPs require the elimination of all emissions that EPA has identified that significantly contribute to nonattainment or interfere with maintenance within each individual state, we are proposing to establish assurance provisions, as described later, in addition to the requirement that sources hold allowances sufficient to cover their emissions. These assurance provisions limit emissions from each state to an amount equal to that state's budget with the variability limit for state budgets, discussed in section IV. As described therein, this variability limit takes into account the inherent variability in baseline EGU emissions and recognizes that state emissions may vary somewhat after all significant contribution is eliminated. This approach also provides sources with flexibility to manage growth and electric reliability requirements, thereby ensuring the country's electric demand will be met while meeting the statutory requirement of eliminating significant contribution.
Starting in 2014, EPA is proposing as part of the FIPs to establish limits on the total emissions that may be emitted from EGUs at sources in each state. For
In other words, in addition to covered sources being required to hold allowances sufficient to cover their emissions, the total sum of EGU emissions in a particular state cannot exceed the state budget with the state's 1-year variability limit in any one year, and the state's annual average emissions for any 3-year period can not exceed, on average, the state budget with the state's 3-year variability limit. The fact of the 3-year variability limit would further assure that emissions are constrained during the two preceding years.
For example, a hypothetical state has a budget of 100,000 tons, a 1-year variability limit of 10,000 tons, and a 3-year variability limit of 5,800 tons.
• In the first year, collective emissions from covered EGUs in the state are 120,000 tons, 10,000 tons over the budget with 1-year variability limit of 110,000 tons, triggering the assurance provisions in that year.
• In the second year, collective emissions from covered EGUs in the state are 97,500 tons, below the state budget with 1-year variability limit of 110,000 tons. Assurance provisions are not triggered.
• In the third year, collective emissions from covered EGUs in the state are 109,000 tons, below the state budget with 1-year variability limit of 110,000 tons. Assurance provisions are not triggered for the 1-year variability limit. But after three years, the state emissions are computed against the 3-year variability limit. The 3-year rolling average (adding the last 3 years of emissions and dividing that by three) computes to 108,833 and determines that the 3-year variability limit of 105,800 tons is exceeded, even though in any one year, the 1-year variability limit may not have been exceeded.
• In the fourth year, collective emissions from covered EGUs in the state are 99,000 tons, below the state budget with 1-year variability limit of 110,000 tons. Assurance provisions are not triggered for the 1-year variability limit. The 3-year rolling average of the last 3 years is 101,833, which is less than the 3-year variability limit of 105,800. Assurance provisions are not triggered for the 3-year variability limit.
The variability limits for each state are shown in Tables IV.F-1 through IV.F-3 in section IV. The basis for the variability limits is also described in section IV.F. Additional details may be found in the “Power Sector Variability” TSD in the docket to this rule.
To implement this requirement, EPA would first evaluate whether any state's total EGU emissions in a control period exceeded the state's budget with 1-year variability limit. Next, EPA would evaluate whether any state's total EGU emissions in a control period exceeded the state's budget with the 3-year variability limit (once the program is in effect for 3 years, and each year thereafter). If any state's EGU emissions in a control period exceeded either of these limits, then EPA would apply additional criteria to determine which source owners in the state would be subject to an allowance surrender requirement. The proposed allowance surrender requirement that owners surrender allowances under the assurance provisions would be triggered only for owners of units in a state where the total state EGU emissions for a control period exceed the applicable state budget with the variability limit. Moreover, only an owner whose units” emissions exceed the owner's share of the state budget with the variability limit would be subject to the allowance surrender requirement.
In applying the additional criteria, EPA would evaluate which source owners in the state had emissions exceeding the respective owner's share of the state budget with the variability limit (regardless of whether the source had enough allowances to cover its emissions). An owner's share would equal the sum of the allocations of its EGUs in the state, plus its proportional share of the amount of the variability limit that, when included with the state budget, was exceeded by the state's EGU emissions during the year involved. If the state emissions exceeded both the state budget with the 1-year and with the 3-year variability limit, then the 3-year variability limit would be used in determining the owner's share of the state budget.
On the other hand, if the state's total EGU emissions for a control period in a given year did not exceed the state budget with the state's 1-year variability limit and did not exceed, on a 3-year rolling average basis, the state budget with the state's 3-year variability limit, then the additional criteria concerning the emissions of each owner's sources in the state would not apply. For more details see subsection V.D.4.i, later, and the rule text at the end of this preamble (§§ 97.425, 97.525, 97.625, and 97.725—Compliance with assurance provisions).
As discussed previously, EPA would not allocate emissions allowances to a new unit for the control period during which the unit commences commercial operation. In the case where assurance provisions for a state are triggered in the year that a new unit first operates, the owner's share—if calculated as the sum of the allocations of its EGUs plus its proportional share of the variability limit—would necessarily be zero because the new unit would have no allocation for that year. Instead, EPA would use a specific surrogate emissions number to calculate the maximum amount the unit could emit in that year before being required to surrender allowances under the assurance provisions. The surrogate emissions number would apply only if the state's assurance provisions were triggered and only in the first year of the new unit's operation.
The surrogate emissions number would be calculated by multiplying the unit's allowable emissions rate (in lbs/MWe) by the unit's maximum hourly load (in MWe/hr) and a default capacity factor specific to the unit type. The default capacity factors would be: 84 percent for coal-fired units, 66 percent for gas-fired combined cycle units, and 15 percent for combustion turbines in the NO
These assurance provisions are above and beyond the fundamental requirement for each source to hold enough allowances to cover its emissions in the control period. Failure to hold enough allowances to cover emissions is a violation of the CAA, subject to an automatic penalty and discretionary civil penalties, as described later.
EPA believes the likelihood of triggering assurance provisions is low. The State Budgets/Limited Trading programs have a regional cap that limits overall emissions; state-specific budgets that are the basis for allocating emissions allowances in each state; assurance provisions that each state eliminates the excess emissions leading to significant contribution and interference with maintenance that EPA has identified in this proposed action; and additional allowance surrender requirements for not meeting emissions reductions requirements. As discussed in section e, later, the underlying mechanism of cap and trade, even without assurance provisions, has succeeded in reducing emissions below allowance levels. The accumulated data, history, and experience from these programs underscore that emissions reductions requirements and environmental and public health goals of the programs were met. However, unlike earlier cap and trade programs (
The existence of these assurance provisions will limit incentives to trade and ensure that state emissions will stay below the level of the budget with the variability limit. An example of a circumstance that might result in emissions approaching the variability limit is an extended nuclear unit outage that causes a company to run its fossil units harder to meet demand. Increased emissions under such a scenario would not result from the ability to trade across state boundaries, or because the fossil units were not controlled, but because the units were operated more. In this type of scenario, emissions would also be higher in a rate-based program that did not allow interstate trading.
EPA is setting two criteria to determine if a state has exceeded its budget using the state budget with the 1-year variability limit on an annual basis, and the state budget with the 3-year variability limit on a 3-year rolling average basis. EPA proposes that emissions from an owner's EGUs in excess of the owner's share of the state budget with the variability limit would not be a violation of the regulation or the CAA. But the owner would be required to make an allowance surrender of one allowance for each ton emitted over the owner's proportional share of the amount by which state emissions exceed the state budget with the variability limit.
This allowance surrender requirement is significant, and EPA believes sufficient, to ensure that the state emissions will not exceed the budgets plus the variability limit. The allowance surrender requirement, however, is less severe than the penalties (discussed later) that apply if a source fails to comply with the requirement to hold an allowance for each ton emitted by EGUs at the source. However, failing to hold sufficient allowances to meet the allowance surrender requirement would be a violation of the regulations and the CAA.
EPA requests comment on whether the allowance surrender requirement should be different (either more or less) than one allowance per ton emitted over the owner's proportional share of the state budget with the variability limit. In addition, EPA requests comment on whether the exceedance of total emissions by an owner's sources over the owner's share of the state budget with the variability limit should be a violation of the CAA and thus subject to discretionary penalties. Finally, EPA requests comment on all aspects of the proposed assurance provisions in the proposed FIPs.
All covered sources must hold an allowance for each ton of SO
Each source must hold in its compliance account in the AMS enough allowances issued for the respective annual trading program (SO
For the ozone season control program, the same provisions apply as for an annual program, except that the control period (and averaging period) is the ozone season, not a calendar year. Consequently, the relevant allowances and emissions are for an ozone season.
EPA requests comment on the amount of allowances required for the automatic penalties.
For the 2012-2013 transition period, EPA is proposing the State Budgets/Limited Trading remedy without the previously-described assurance provisions (penalty provisions would remain in effect), but taking comment on whether the assurance provisions should be in force during that period.
New state-specific control budgets (developed as described in section IV) and new allowances would be allocated to sources in the Transport Rule region. These state budgets would reflect the operation of all existing and planned emission control devices. Under EPA's proposed approach, for 2012 and 2013, intrastate and interstate trading, without the assurance provisions, would be allowed.
The locations of existing and planned air pollution control retrofits on EGUs are known, and this knowledge provides greater certainty of where reductions will occur and how these reductions should impact air quality in downwind areas. There would not be sufficient time to complete construction of additional control retrofits or entirely new, controlled EGUs before 2014.
Consequently, EPA believes that there is a high level of certainty that emissions reductions projected for
The 2012-2013 transition period would provide time for sources to migrate to the new rule requirements in 2014, such as preparing for the imposition of the assurance provisions and, for some states, tighter SO
The State Budgets/Limited Trading remedy is not a risk to electric reliability. The option for sources to trade across state borders and to emit up to the specified state budget with variability limit gives ISOs (Independent System Operators) the flexibility to manage regional electricity generation so that reliability is maintained. For example, the operations of the electricity generation sector under the State Budgets/Limited Trading remedy, as compared to the option allowing only intrastate trading, would be less constrained by state borders and have greater flexibility to handle unexpected events such as extreme weather or the loss of generating capacity for extended periods of time.
Even absent assurance provisions, cap and trade programs have resulted in broad-based emissions reductions distributed across the entire covered area, with the reductions coming where emissions were highest and most cost effective. The national SO
• Phases and reductions.
○ An emissions cap is established and the programs are phased in, with increasing stringency to lower emissions.
• Allowance allocation.
○ Authorizations to emit,
• Allowance trading.
○ Markets enable sources to trade allowances.
• Flexible compliance.
○ Sources have the flexibility to choose the most efficient way to comply including adding emission control technologies, updating control technologies, optimizing existing controls, switching fuels, and buying allowances.
• Annual reconciliation.
○ At the end of every compliance period, each source must surrender sufficient allowances to cover its emissions. Excess allowances may be sold or banked for future use.
• Penalties and enforcement.
○ There are automatic penalties and potentially discretionary civil penalties for program noncompliance.
• Stringent monitoring and reporting.
○ Sources must use approved monitoring methods under EPA's stringent monitoring requirements (40 CFR part 75) to monitor and report emissions.
• Data transparency.
○ The data on key program elements, such as emissions, allocations, and allowance trades, are publicly available on EPA's web site and in annual progress reports.
About 50 government staff operate these cap and trade programs. They have been successful in achieving the emissions reductions goals at reasonable costs with virtually 100 percent program compliance. In the following paragraphs, specific results from the programs are described. These results are documented in program progress reports that are available on EPA's Web site (
Since program implementation in 1995, the ARP has reduced SO
• SO
• NO
The largest reductions have occurred in the states with the highest power plant emissions. These high emitting areas were upwind of major populations centers and areas of environmental and ecological concern. Emissions reductions have led to improvements in air quality with significant benefits to sensitive ecosystems and human health.
• Between the 1989 to 1991 and 2006 to 2008 observation periods, decreases in wet sulfate deposition averaged more than 30 percent for the eastern U.S.
• Acid Neutralizing Capacity (ANC), the ability of water bodies to neutralize acid deposition, increased significantly from 1990 to 2008 in lake and stream long-term monitoring sites in New England, the Adirondacks, and the Northern Appalachian Plateau.
• Recently updated assessments of U.S. PM
• In 2008, NBP ozone season NO
• The average NO
• The largest NO
• Noticeable improvements in ambient concentrations of ozone have been measured across the region.
• Of the 104 areas in the eastern United States designated to be in nonattainment for the 1997 8-hour ozone NAAQS in 2004, 88 areas (85 percent) had ozone air quality better than the level of the 1997 standard in 2008. 8-hour ozone concentrations were 10 percent lower in 2008 than in 2001. This decline is largely due to reductions in NO
Over the past several years a series of studies
EPA stopped administering the NBP at the conclusion of 2008 control period. States still have the emissions reductions requirements under the NO
Allowance prices and trading activity under the trading programs were reduced in 2008 in response to the Court's July 2008 decision in North Carolina v. EPA granting petitions for review of CAIR. However, the allowance markets remained active. For a recent assessment on allowance markets,
In fact, few empirical studies on transaction costs have been done. EPA has searched the literature and compiled a list of anecdotal discussions on transaction costs, including a study of the ARP's SO
Tietenberg, in his book,
Tietenberg defines transactions costs as “the costs, other than price, incurred in the process of exchanging goods and services. These include the costs of researching the market, finding buyers or sellers, negotiating and enforcing contracts for permit transfers, completing all the regulatory paperwork, and making and collecting payments.”
Tietenberg contrasts EPA's earlier credit-based trading programs in the
All the features Tietenberg highlights comprise fundamental aspects of EPA's cap and trade program design. Program design remains one of the principle ways to ensure lower transaction costs. Over the last 15 years, EPA's state-of-the-art information management system has evolved in parallel with the advancement of technology in order to offer platforms for reporting and receiving data and for public access. EPA provides dedicated assistance for sources, states, and regions around the country on program operations and monitoring and reporting, specifically. With limited oversight of transactions, EPA focuses on recording data and information accurately, including allowance transfers, as well as “true-up”, where actual emissions are reconciled with allowances held in accounts for compliance.
These features of EPA's program management lead to low transaction costs. EPA is attuned to trying to keep requirements as simple and straightforward as possible, and offers substantial and routine training to ensure successful program implementation and regulatory compliance. While some have equated the length of EPA's trading program rules with higher transaction costs, in fact, the detailed regulatory sections, such as for allocations and the stringent monitoring requirements, form the basis of what actually allows the programs to function with limited oversight, virtually 100 percent compliance, public transparency, and nominal transaction costs.
For the ARP, NO
EPA research found no indications that transaction costs have been a problem. From discussions with a leading industry consultant we learned that there is enough competition among the approximately fifteen brokerage houses that any attempt at charging fees in excess of market standards will be bid down through competition.
In summary, EPA believes its cap and trade programs functioned efficiently and did not result in high transaction costs for several reasons. First, in developing the regulations for the trading programs, EPA strove to make the programs as transparent as possible in order to ensure that relevant data were available to the market, to minimize regulatory oversight of trading activity, and to let the market work unhampered. Strong markets exist that have seen upwards of 273 million SO
Further, EPA is not aware of any source participating in the trading programs over the past 15 years that expressed concern about the costs of making allowance transfers. For example, EPA has received no comment in the rulemaking proceedings for the trading programs raising concern about the level of transactions costs for allowance transfers under these programs, and no party challenged the allowance transfer provisions on appeal of any of the trading program rules.
In addition, all available information indicates that actual transactions costs are very low. For a list of some articles written by scholars and economists over the past 15 years on transaction costs, see the docket for this rule.
The proposed remedy discussed in this section effectuates the statutory goal of prohibiting sources within the state from contributing to nonattainment or interfering with maintenance in any other state.
A state's “significant contribution” is the portion of emissions that must be eliminated.
In addition, the requirement that all sources hold emissions allowances (and the fact that the total number of emissions allowances allocated will be equal to the sum of all state budgets without variability) ensures that the use of variability limits both takes into account the inherent variability of baseline EGU emissions in individual states (
The variability of emissions across a larger region is not as large as the variability of emissions in a single state for several reasons. Increased EGU emissions in one state in one control period often are offset by reduced EGU emissions in another state within the control region in the same control period. In a larger region that includes multiple states, factors that affect electricity generation, and thus EGU emissions levels, are more likely to vary significantly within the region so that resulting emissions changes in different parts of the region are more likely to offset each other. For example, a broad region can encompass states with differing weather patterns, with the result that increased electricity demand and emissions due to weather in one state may be offset by decreased demand and emissions due to weather in another state. By further example, a broad region can encompass states with differing types of industrial and commercial electricity end-users, with the result that changes in electricity demand and emissions among the states due to the effect of economic changes on industrial and commercial companies may be offsetting. Similarly, because states in a broad region may vary in their degree of dependence on fossil-fuel-based electric generation, the impact of an outage of non-fossil-fuel-based generation (
For these reasons, the fact that the proposed use of state budgets with the variability limit may allow limited shifting of emissions between states is not inconsistent with the Court's holding that emissions reductions must occur “within the state.”
The FIPs that EPA is proposing use the State Budgets/Limited Trading remedy to eliminate all of the significant contribution and interference with maintenance that EPA has identified. This remedy—which would use state budgets (
In the first phase (2012 and 2013), the proposed remedy would provide a new interstate trading program that would ensure existing and planned pollution controls operate. Units would be required to run their existing, or already planned, pollution control devices when the units are operating. The State Budgets/Limited Trading remedy would use the new state budgets described in section IV and allocate allowances to individual sources using a methodology directly related to the methodology used to identify emissions that significantly contribute to nonattainment or interfere with maintenance in downwind areas. EPA believes that because the location of existing and already planned pollution controls for 2012 and 2013 is known, the use of these budgets, even without the added assurance provisions, would assure that the necessary emissions reductions would occur in each state under the trading programs during those years. The impact of the resulting emissions reductions on atmospheric concentrations of particulate matter and other pollution, and subsequent benefits for the environment and human health, would be significant and are described in sections III.B and IX. The proposed remedy would offer the most expeditious approach practicable for compliance in 2012-2013, given the short time available for sources, states, and EPA to implement a transition from CAIR. While there is some uncertainty about how quickly units potentially capable of switching fuels would actually be able to implement such fuel switching, the banking provisions of the State Budgets/Limited Trading approach would provide incentives to reduce emissions as quickly and early as possible. The trading provisions would provide flexibility for sources to purchase allowances in the meantime, without the risks of unexpected high costs, non-compliance, or the inability to operate if unable to switch fuels. The remedy would be relatively easy for sources and states to understand and follow as they transition from prior trading programs to a new regime, beginning in 2014, that would include limits on interstate trading.
The second phase would begin in 2014 with tighter state-specific SO
The limited interstate trading permitted in this proposed remedy would address some of the problematic issues identified in the alternative options discussed later, such as, under the intrastate trading option, concerns about the administrative burden and needed resources associated with administering 82 new trading programs (with 82 new sets of allowances),
In addition, the proposed State Budgets/Limited Trading remedy provides reductions at a lower cost than the direct control option described later and is flexible enough to accommodate unit-specific circumstances. In contrast, the direct control option described later would involve a complex process of determining unit-by-unit emissions limits that might need to take account of unit-specific circumstances. Moreover, this option would be roughly $600 million (2006$) more expensive than the proposed remedy in 2012. See section V.E for more details on projected costs and emissions.
In summary, EPA believes that interstate trading, although limited by the assurance provisions, would allow source owners to choose among several compliance options to achieve required emissions reductions in the most cost-effective manner, such as installing controls, changing fuels, reducing utilization, buying allowances, or any combination of these actions. Interstate trading with assurance provisions would also allow the electricity sector to continue to operate as an integrated, interstate system able to provide electric reliability. Compared to the alternative options, EPA believes the State Budgets/Limited Trading remedy would provide the greatest flexibility to companies complying with the rules and is the approach most likely to achieve the goals and principles outlined in section III.C.
The proposed remedy provides intrastate and interstate trading components that simplify implementation for EPA (and, where applicable, states) and sources and results in cost-effective achievement of required emissions reductions. Resource needs for EPA and sources to implement the proposed remedy are expected to be comparable to the resources necessary to implement CAIR.
EPA believes the State Budgets/Limited Trading proposed remedy provides more assurance that the emissions levels necessary to address NAAQS nonattainment are not exceeded than most previous regulatory programs such as rate-based direct control programs and even nonattainment plans, none of which places an absolute cap on emissions. EPA has pointed out, in contrast, that the results from cap and trade programs such as the Acid Rain and NO
Additionally, this remedy approach and the method EPA proposes for determining significant contribution together provide a workable regulatory structure for not only dealing with the transport problem for the existing NAAQS, but also would be usable in the years ahead when EPA considers further revisions of the NAAQS, notably for ozone and fine particles. EPA requests comment on the State Budgets/Limited Trading proposed remedy. EPA is also requesting comment on the two options described later in sections V.D.5 and V.D.6.
EPA considered a range of ways to create an interstate-trading-with-limitations option consistent with the direction provided by the Court. One option considered was to put in place simultaneously intrastate trading with direct control requirements and interstate trading with direct control requirements. The challenges associated with developing direct control requirements are discussed in section V.D.6 later.
EPA also considered interstate trading with backstop provisions, which were rejected as not workable. EPA considered a backstop provision that prohibited the units in a state from future participation in the interstate trading program if the state's emissions in a control period in any year exceeded the state's budget with variability. In that event, the units would be limited to intrastate trading only in the control period of the next year. This is not EPA's proposed option because data on annual emissions are not final until several months into the next year, making it hard for the units in a state to know early enough whether they would be in the interstate trading program or an intrastate trading program for that next year. This would make compliance planning and implementation of compliance plans extremely difficult and adversely affect allowance markets.
In summary, EPA rejected these alternatives as more complicated and perhaps problematic to implement. Instead, EPA is proposing the State Budgets/Limited Trading remedy, which is similar in many ways to the approaches implemented in the past that have succeeded in reducing emissions. However, in order to address the Court's concerns about trading, the proposed remedy includes assurance provisions to ensure that the remedy removes each upwind state's significant contribution and interference with maintenance. The “Other Remedy Options Evaluated” TSD in the docket contains greater detail on the deliberations undertaken to evaluate other options for this rulemaking.
This preamble section describes the structure and key elements of the proposed Transport Rule trading program rules for the State Budgets/Limited Trading remedy in the proposed FIPs. Proposed regulatory text that would be added to the Code of Federal Regulations if this option is finalized appears at the end of this notice. EPA requests comment on the structure and key elements of the program as well as on the proposed regulatory text.
In order to make the proposed FIP trading program rules as simple and consistent as possible, EPA designed them so that the proposed rules for each of the trading programs (
The definitions and measurements, abbreviations, and acronyms would be the same in all four proposed Transport Rule trading programs, except where necessary to reflect the different pollutants (NO
Some definitions would be similar to those used in prior EPA-administered trading programs but with some substantive differences. For example, the definitions of “cogeneration unit” and “fossil-fuel-fired,” used in the applicability provisions and discussed in this section of the preamble, would be similar to those in prior trading programs but with changes to minimize the need for data concerning individual units or combustion devices for periods before 1990.
A few new definitions would be included to reflect unique provisions of the proposed Transport Rule trading programs. For example, the terms, “owner's assurance level” and “owner's share”, would be used in the Transport Rule assurance provisions and defined in the proposed Transport Rule trading program rules. The assurance provisions are discussed previously in section V.D.4.b.
The applicability provisions would be the same for each of the proposed Transport Rule trading programs, except that the provisions would reflect (through the definition of “state”) differences in the specific states whose EGUs are covered by the respective Transport Rule trading programs (as discussed in section IV.D of this preamble). In general, the proposed Transport Rule trading programs would cover fossil fuel-fired boilers and combustion turbines serving an electrical generator with a nameplate capacity exceeding 25 MWe and producing power for sale, with the exception of certain cogeneration units and solid waste incineration units. The applicability provisions are discussed previously in section V.D.4.b.
The provisions exempting permanently retired units from most of the requirements of the Transport Rule trading programs would be the same for each of the trading programs. The purpose of the retired units” exemption would be to avoid requiring units that are permanently retired to continue to operate and maintain emission monitoring systems, to report quarterly emissions, and to hold allowances, as of the allowance transfer deadline, sufficient to cover their emissions determined in accordance with the monitoring and reporting requirements. Consequently, the retired unit provisions would exempt these units from the rule sections imposing the relevant monitoring, recordkeeping, and reporting requirements and allowance-holding requirements. However, an owner would include each of these permanently retired units that it owns in determining whether and, if so, how many allowances the owner would be required to surrender in compliance with the assurance provisions. As discussed earlier in this section, while these units would have zero emissions once they are permanently retired, the units could continue to receive allowance allocations for several years thereafter. Consequently, an owner would include these units in determining whether the owner's share of total emissions of covered units in a state exceeded its share (generally based on the allowances allocated to its units) of the state budget with the variability limit and thus whether the owner would have to surrender allowances under the assurance provisions.
The exemption for a retired unit would begin on the day the unit is permanently retired. The unit's designated representative (
The retired unit exemption provisions would not directly address any permit-related matters concerning these units. This would be consistent with the general approach under the Transport Rule trading program rules of leaving permitting matters largely to be addressed by the existing, applicable state and federal title V permit programs. Permitting is discussed in section VIII of this preamble.
The basic requirements applicable to owners and operators of units and sources covered by the proposed Transport Rule trading programs and presented as standard requirements would include: Designated representative requirements; emissions monitoring, reporting, and recordkeeping requirements; emissions requirements comprising emissions limitations and assurance provisions; permit requirements; additional recordkeeping and reporting requirements; liability provisions; and provisions describing the effect of the Transport Rule trading program requirements on other Act provisions. The paragraphs, in the standard requirements section, that would address designated representative requirements and emissions monitoring, reporting, and recordkeeping
The paragraphs addressing emissions requirements would describe these requirements in detail and reference other sections that would set forth the procedures for determining compliance with the emissions limitations and assurance provisions. These paragraphs would also explain that: Transport Rule NO
The remaining paragraphs in the standard requirements section concern permitting, recordkeeping and reporting, liability provisions, and the effect on other CAA provisions. As discussed in section VIII of this preamble, the paragraphs concerning permitting requirements would be limited to stating that no title V permit revisions would be necessary to account for allowance allocation, holding, deduction, or transfer and that the minor permit modification procedures could be used to add or change general descriptions in the title V permits of the monitoring and reporting approach used by the units covered by each title V permit. The paragraphs on recordkeeping and reporting would generally require owners and operators to keep on site for 5 years copies (which could be electronic) of certificates of representation, emissions monitoring information (including quarterly emissions data), and submissions and records demonstrating compliance with the proposed Transport Rule trading programs. The paragraphs on liability would state that each covered source and covered unit would be required to meet the Transport Rule trading program requirements, any provision applicable to a source or designated representative would be applicable to the source and unit owners and operators, and any provision applicable to a unit or designated representative would be applicable to the unit owners and operators. The paragraph on the effect on other CAA provisions would state that the Transport Rule trading programs do not exempt or exclude owners and operators from any other requirements under the CAA, an approved SIP, or a federally enforceable permit.
These sections would clarify how to determine the deadlines referenced in the proposed Transport Rule trading program rules. For example, deadlines falling on a weekend or holiday are extended to the next business day. These are the same computation-of-time provisions used in prior EPA-administered trading programs.
Final decisions of the Administrator under the proposed Transport Rule trading program rules would be appealable to EPA's Environmental Appeals Board under the regulations that are set forth in part 78 (40 CFR part 78) and are proposed to be revised to accommodate such appeals. Specifically, the list in § 78.1 of the types of final decisions that could be appealed under Part 78 would be expanded to include specific types of decisions under the proposed Transport Rule trading program rules.
Further, under the approach in the existing part 78, an “interested person” (in addition to the official representative of owners and operators or an allowance account involved in a matter) may petition for an administrative appeal of a final decision of the Administrator. In order to expand the “interested person” definition (which is currently in part 72 of the ARP regulations) and make the definition more readily accessible to readers of part 78, the definition would be removed from § 72.2, added in § 78.2, and expanded in a way that would cover the proposed trading program rules. Provisions concerning public availability of information, and provisions concerning computation of time (revised to be consistent with the requirements for computation of time used by the Environmental Appeals Board in other types of administrative proceedings), would also be moved to § 78.2. In particular, the revised “interested person” definition would include, with regard to a decision appealable under Part 78, any person who—in connection with the Administrator's process of making that decision—submitted comments, testified at a public hearing, submitted objections, or submitted their name to be included by the Administrator in an interested persons list.
In addition, § 78.3 would be revised to allow for petitions for administrative appeal of decisions of the Administrator under the proposed Transport Rule trading programs. Further, § 78.4 would be expanded to state that filings on behalf of owners and operators of a covered source or unit under the proposed Transport Rule trading programs would have to be signed by the designated representative of the source or unit. Filings on behalf of persons with an interest in allowances in an account in the proposed programs would have to be signed by the authorized account representative of the account.
Sections 97.410 through 97.412, 97.510 through 97.512, 97.610 through 97.612, and 97.710 through 97.712 would set forth: Certain information related to allowance allocation and for implementation of the assurance provisions; the timing for allocation of allowances to existing and new units; and the procedures for new unit allocations. In particular, these sections would include tables providing, for each state covered by the particular proposed Transport Rule trading program and for each year, the state trading budget (without the variability limit), new unit set-aside, and one-year and three-year variability limits. With regard to existing units, these sections would also state that existing units would be allocated the allowances set forth in appendix A of the relevant Transport Rule trading program rules. These allocations would be permanent (taking into account the reductions in allocations, for the Transport Rule SO
With regard to new units (as well as units whose allocations are subject to the requirement that the Administrator not record them or that the Administrator deduct the amount of the allocation and units that lost their allocations after not operating and that subsequently began operating again), the owner and operator of such units could request, by a specified deadline each year, an allocation from the new unit set-aside for that year and each year thereafter. The allocation would equal that unit's emissions—as determined in accordance with part 75 (40 CFR part 75)—for the control period (annual or ozone season, depending on the Transport Rule trading program involved) in the preceding year. The Administrator would determine whether the total number of properly requested allowance allocations for all units in a state for a control period would exceed the amount in the new unit set-aside for the state for the control period. If not, the Administrator would allocate consistent with all proper requests. If the total number would exceed the new unit set-aside, the Administrator would allocate to each properly requesting unit its proportionate share of the new unit set-aside. The Administrator would provide notice of these determinations (which would reflect these calculations rather than any exercise of discretion on the part of the Administrator) through issuance of a notice of data availability to which parties could submit objections and a second notice addressing any objections. Any unallocated allowances in the new unit set-aside would be allocated to existing units in proportion to their current allocations.
If a unit that was not really a covered unit or a unit that was not subject to the allowance-holding requirement were allocated allowances, the proposed provisions set forth a process under which the allocation would not be recorded or the amount of the recorded allocation would be deducted, with one exception. The exception would be if the process of determining compliance with the emission limitation for the source that includes the unit were already completed, in which case no action would be taken to account for the erroneous allocation for the control period involved.
Sections 97.413 through 97.418, 97.513 through 97.518, 97.613 through 97.618, and 97.713 through 97.718 would establish the procedures for certifying and authorizing the designated representative, and alternate designated representative, of the owners and operators of a source and the units at the source and for changing the designated representative and alternate designated representative. These sections would also describe the designated representative's and alternate designated representative's responsibilities and the process through which he or she could delegate to an agent the authority to make electronic submissions to the Administrator. These provisions would be patterned after the provisions concerning designated representatives and alternates in prior EPA-administered trading programs.
The designated representative would be the individual authorized to represent the owners and operators of each covered source and covered unit at the source in matters pertaining to all Transport Rule trading programs to which the source and units were subject. This approach would ensure that one individual was required to be knowledgeable about the requirements of, and responsible for compliance with, all Transport Rule trading programs. One alternate designated representative could be selected to act on behalf of, and legally bind, the designated representative and thus the owners and operators. Because the actions of the designated representative and alternate would legally bind the owners and operators, the designated representative and alternate would have to submit a certificate of representation certifying that each was selected by an agreement binding on all such owners and operators and was authorized to act on their behalf.
The designated representative and alternate would be authorized upon receipt by the Administrator of the certificate of representation. This document, in a format prescribed by the Administrator, would include: Specified identifying information for the covered source and covered units at the source and for the designated representative and alternate; the name of every owner and operator of the source and units; and certification language and signatures of the designated representative and alternate. All submissions (
In order to change the designated representative or alternate, a new certificate of representation would have to be received by the Administrator. A new certificate of representation would also have to be submitted to reflect changes in the owners and operators of the source and units involved. However, new owners and operators would be bound by the existing certificate of representation even in the absence of such a submission.
In addition to the flexibility provided by allowing an alternate to act for the designated representative (
The Transport Rule trading program rules listed later would establish the procedures and requirements for using and operating the Allowance Management System (which is the electronic data system through which the Administrator would handle allowance allocation, holding, transfer, and deduction), and for determining compliance with the emissions limitations and assurance provisions, in an efficient and transparent manner. The Allowance Management System would also provide the allowance markets with a record of ownership of allowances, dates of allowance transfers, buyer and seller information, and the serial numbers of allowances transferred. Consistent with the approach in prior EPA-administered trading program, allowance price
The Allowance Management System would contain two types of accounts: compliance accounts, one of which the Administrator would establish for each covered source upon receipt of the certificate of representation for the source; and general accounts, which could be established by any entity upon receipt by the Administrator of an application for a general account. A compliance account would be the account in which any allowances used by the covered source for compliance with the emissions limitations and assurance provisions would have to be held. The designated representative and alternate for the source would also be the authorized account representative and alternate for the compliance account. Using source-level, rather than unit-level accounts, would provide owners and operators more flexibility in managing their allowances for compliance, without jeopardizing the environmental goals of the Transport Rule trading programs, because the source-level approach would avoid situations where a unit would hold insufficient allowances and would be in violation of allowance-holding requirements even though units at the same source had more than enough allowances to meet these requirements for the entire source.
General accounts could be used by any person or group for holding or trading allowances. However, allowances could not be used for compliance with emissions limitations or assurance provisions so long as the allowances were held in, and not properly and timely transferred out of, a general account. To open a general account, a person or group would have to submit an application for a general account, which would be similar in many ways to a certificate of representation. The application would include, in a format prescribed by the Administrator: The name and identifying information of the individual who would be the authorized account representative and of any individual who would be the alternate authorized account representative; an identifying name for the account; the names of all persons with an ownership interest with the respect to allowances held in the account; and certification language and signatures of the authorized account representative and alternate. The authorized account representative and alternate would be authorized upon receipt of the application by the Administrator. The provisions for changing the authorized account representative and alternate, for changing the application to take account of changes in the persons having an ownership interest with respect to allowances, and for delegating authority to make electronic submissions would be analogous to those applicable to comparable matters for designated representatives and alternates.
By September 1, 2011, the Administrator would record allowance allocations for existing units, based on Appendix A to each proposed Transport Rule trading program rule, for 2012 through 2014. By June 1, 2012 and June 1 of each year thereafter, the Administrator would record such allowance allocations for each proposed Transport Rule trading program for the third year after the year of the recordation deadline,
The process for transferring allowances from one account to another would be quite simple. A transfer would be submitted providing, in a format prescribed by the Administrator, the account numbers of the accounts involved, the serial numbers of the allowances involved, and the name and signature of the transferring authorized account representative or alternate. If the transfer form containing all the required information were submitted to the Administrator and, when the Administrator attempted to record the transfer, the transferor account included the allowances identified in the form, the Administrator would record the transfer by moving the allowances from the transferor account to the transferee account within 5 business days of the receipt of the transfer form.
Once a control period has ended (
If a source were to fail to hold sufficient allowances for compliance, then the owners and operators would have to provide, for deduction by the Administrator, 2 allowances allocated for the control period in the next year for every allowance that the owners and operators failed to hold as required to cover emissions. In addition, the owners and operators would be subject to discretionary civil penalties for each violation, with each ton of unauthorized emissions and each day of the control
EPA believes that it is important to include a requirement for an automatic deduction of allowances. The deduction of one allowance per allowance that the owners and operators failed to hold would offset this failure. The deduction of another allowance per allowance that the owners and operators failed to hold would provide an automatic penalty that could not be avoided, regardless of any explanation provided by the owners and operators for their failure, and would therefore provide a strong incentive for compliance with the allowance-holding requirement by ensuring that non-compliance would be a significantly more expensive option than compliance.
EPA proposes to include assurance provisions in the Transport Rule trading programs in order to ensure that each state would eliminate that part of its significant contribution and interference with maintenance that EPA has identified in today's proposed action (
The process of determining, for a given control period, which states would have total EGU emissions sufficient to trigger the allowance surrender requirement, which owners would be subject to the allowance surrender, and whether those owners were in compliance would be implemented in a series of steps. (The dates summarized later apply to the proposed annual programs; the dates for the proposed ozone season program would be earlier.)
First, the Administrator would perform the calculations necessary to determine whether any states had total state EGU emissions for a control period greater than the state budget with the variability limit, applying both the 1-year and the 3-year variability limits discussed earlier. By June 1 (starting in 2015), the Administrator would promulgate a notice of availability of the results of these calculations and provide an opportunity for submission of objections. By August 1, the Administrator would promulgate a second notice of availability of any necessary adjustments to the calculations and the reasons for accepting or rejecting any properly submitted objections.
Second, by August 15, the designated representative of every Transport Rule source in a state identified in the August 1 notice as having control period emissions in excess of the budget with the variability limit would make a submission to the Administrator that would identify: Each person having (as of the last day of the control period) a legal, equitable, leasehold, or contractual reservation or entitlement in the Transport Rule units at the source; and the percentage of each such person's reservation or entitlement.
Third, by September 15, the Administrator would calculate, for each state identified in the August 1 notice and for each owner of covered units in the state, the owner's share of emissions, the owner's share of the state budget with the variability limit, and the amount (if any) that the owner would be required to hold for surrender under the assurance provisions (
By December 1, each owner identified in the November 15 notice as being required to hold allowances for surrender under the assurance provisions would designate a compliance account of one of its covered units in the state, and the authorized account representative of the compliance account would submit to the Administrator a statement designating the compliance account, as the account in which the required allowances would be held.
As of midnight of December 15, the owner would have to have in its designated compliance account, or have a properly submitted transfer that would move into that compliance account, the amount of allowances (usable for compliance) that the Administrator determined (in the calculations referenced in the November 15 notice) were required to be held by the owner for surrender. The authorized account representative could identify specific allowances to be deducted but, in the absence of such identification or in the case of a partial identification, the Administrator would deduct allowances on a first-in, first-out basis.
The potential effect of subsequent data revisions that would otherwise change the data used in and the results of the Administrator's calculations referenced in the August 1 or November 15 notices discussed previously would be limited. If data used in a notice applying the assurance provisions to a given year were revised as a result of a decision in, or settlement of, litigation (such as an administrative appeal resulting in such decision or settlement or an administrative appeal whose results were in turn appealed in a judicial proceeding resulting in such decision or settlement) initiated within 30 days of the promulgation of the notice involved, then the Administrator would use the revised data for the calculations in the respective notice. Any other data revisions would not be used to revise the calculations. The revised data could be used, if relevant, in the Administrator's calculations in future notices promulgated for a later year. If the revised calculations increased the amount of allowances that an owner was required to hold for surrender, the Administrator would set a new, reasonable deadline for the owner to hold the additional allowances in the owner's designated compliance account. The Administrator believes that this limitation on the effect of data revisions on the calculation of the amount of allowances owners would have to surrender under the assurance provisions is necessary. Because an owner's surrender obligation would be calculated using large amounts of data involving all the covered units in a state (including potentially many units owned by other owners), each owner would face the potential that changes in data outside of the owner's responsibility and control could change—after the December 15 allowance-holding deadline—in a way that would increase his surrender obligation after that deadline and put him in violation of the regulations and the Act. EPA believes that this potential risk would be significant enough that it could make many owners reluctant to consider any compliance options involving even the limited interstate trading allowed under the proposed remedy. The proposal would limit this risk by having the Administrator only take account of data revisions resulting from decisions in, or settlement of, litigation initiated soon after promulgation of the notice involved.
As discussed previously, it would not be a violation of the CAA for total state EGU emissions to exceed the state budget with the variability limit or for an owner to become subject to allowance surrender under the assurance provisions. However, the failure of an owner to hold in the designated compliance account a sufficient amount of allowances to satisfy this allowance surrender would violate the CAA and be subject to discretionary penalties, with each required allowance that was not held and each day of the control period involved constituting a violation. EPA believes that the allowance surrender requirement alone—and certainly when coupled with the potential for large discretionary penalties—would ensure that owners would take actions to avoid having total state EGU emissions exceed the level that would trigger the allowance surrender.
These sections would allow banking of the allowances issued in the Transport Rule trading programs,
These sections also would provide that the Administrator could, at his or her discretion and on his or her own motion, correct any type of error that he or she finds in an account in the Allowance Management System. In addition, the Administrator could review any submission under the Transport Rule trading programs, make adjustments to the information in the submission, and deduct or transfer allowances based on such adjusted information.
Sections 97.430 through 97.435, 97.530 through 97.535, 97.630 through 97.635, and 97.730 through 97.735 would establish emissions monitoring, recordkeeping, and reporting requirements for Transport Rule units that would result in clear, consistent, rigorous, and transparent monitoring and reporting of all emissions. Such monitoring and reporting would be the basis for holding sources accountable for their emissions and would be essential to the success of the Transport Rule trading programs. This is because consistent and accurate measurement of emissions would be necessary to ensure that each allowance would actually represent one ton of emissions and that one ton of reported emissions from one source would be equivalent to one ton of reported emissions from another source. This would establish the integrity of each allowance and instill confidence in the underlying market mechanisms that would be central to providing sources with flexibility in achieving compliance. Moreover, given the variation in the type, operation, and fuel mix of sources covered by the proposed Transport Rule trading programs, EPA believes that emissions would need to be monitored continuously in order to ensure the precision, reliability, accuracy, and timeliness of emissions data supporting the trading programs.
In §§ 97.430 through 97.435, 97.530 through 97.535, 97.630 through 97.635, and 97.730 through 97.735, EPA proposes the monitoring, recordkeeping, and reporting requirements for the Transport Rule NO
Part 75 was originally developed for the ARP and addressed SO
The proposed monitoring and reporting provisions for the Transport Rule trading programs would allow use of these same options and petition procedures and would reference the applicable provisions in Part 75. Existing Transport Rule units would be required to install and certify monitoring systems by the beginning of the relevant Transport Rule trading program. New Transport Rule units have separate deadlines based upon the date of commencement of commercial operation. Recognizing that many of the Transport Rule units are already monitoring NO
The quality assurance (QA) requirements for the ARP that were mandated by Congress under CAA Title IV are codified in Appendices A and B of Part 75. Part 75 specifies that each CEMS must undergo rigorous initial certification testing and periodic quality assurance testing thereafter, including the use of relative accuracy test audits (RATAs) and daily calibrations. A standard set of data validation rules apply to all of the monitoring methodologies. These stringent requirements result in an accurate accounting of the mass emissions from each unit, and EPA provides prompt feedback if the monitoring system is not operating properly. In addition, when the monitoring system is not operating
Part 75 requires electronic submission, to the Administrator and in a format prescribed by the Administrator, of a quarterly emissions report containing all of the emissions data specified in the recordkeeping provisions of Part 75. EPA has found that centralized, electronic reporting using a consistent format is necessary to ensure consistent review and public posting of the emissions data for covered units, which contribute to the integrity, efficiency, and transparency of trading programs. Further, the inclusion of all emissions data in a single quarterly report for each unit means that, if the same data are needed for multiple trading programs, the unit only needs to report it once in the form of one comprehensive report. The reporting provisions in the proposed Transport Rule trading program regulations would contain the same requirements for submission to the Administrator of electronic, comprehensive quarterly reports as in Part 75. As discussed above, the reporting provisions would also include a process for resubmission of quarterly reports where appropriate.
As noted earlier in this preamble, in addition to the remedy option included in the proposed FIPs, EPA is taking comment on two alternative options for eliminating all or part of the emissions in upwind states that significantly contribute to nonattainment or interfere with maintenance in downwind states. The first of these alternative options is the State Budgets/Intrastate Trading option described below. EPA is considering the relative merits of this option and requests comment on whether it should be included in the final FIPs. EPA also identifies below a number of disadvantages that raise concerns for EPA and are explained later in this section. EPA requests comment on these issues and their impacts on and significance for any final rule.
The State Budgets/Intrastate Trading option would set state-specific caps for SO
Under this option, EPA would allocate allowances to the covered sources within each state, and sources in the state could use for compliance only allowances issued for the same state. Even a company that operates EGUs in multiple states would not be permitted to use for compliance for one of its sources allowances issued to another of its sources in a different state. In essence, this approach, if implemented, would result in 28 separate trading programs for NO
Unlike the remedy option in the proposed FIPs or the other alternative remedy option, this option does not include assurance provisions based on the variability limits described in section IV. This option includes a “hard” cap for each state equal to its budget, which provides assurance that reductions will occur in each state and which EPA believes makes additional assurance provisions unnecessary. The State Budgets/Intrastate Trading option does allow banking and the use of banked allowances to provide sources with some degree of operational flexibility in complying with the program. Because this option includes provisions for banking emissions allowances (as does the proposed State Budgets/Limited Trading remedy), limited year-to-year (temporal) emissions variability is allowed. EPA requests comment on this approach to providing for emissions variability. EPA also requests comment on whether assurance provisions based on variability limits should be included in this option.
Applicability would be the same for the proposed remedy and for the two alternative options, including this one. Refer to section V.D.4 above for detailed discussion on applicability.
While the general approach for calculating allowance allocations would be the same as described above for State Budgets/Limited Trading, EPA would not distribute all of the allowances into the source accounts each period. The distribution of allowances would be modified because of the concentrated nature of numerous state power markets, which would be reflected in the state allowance markets if all allowances were distributed in each state based on factors reflecting generation in that state. The electric power sector tends to be highly concentrated, and, within a state, the majority of generation is often owned by a relatively small number of companies. This assessment of state electricity markets is supported by analysis using the Herfindahl-Hirschman Index, a way to measure the size of firms in relation to the industry and an indicator of the amount of competition among them (see Electric Generation Ownership, Market Concentration and Auction Size Technical Support Document). To address this potential issue concerning the allowance markets in many states, under this option some allowances would be withheld from certain sources in each state that control a large share of fossil-fueled power generation and
The reason for including this provision is that the dominant power generation companies in each state would likely receive a large share of the allocated allowances and as a result might be able to exert control over allowance prices in the state's allowance market. This market power and potential for allowance price manipulation could pose a threat to the transparency and liquidity of allowance markets and put small owners of fossil-fuel fired generation at a disadvantage regarding their compliance costs unless the owners were given sufficient access to allowances other than through direct purchase from the state's dominant companies. Some of these owners of a small share of generation might already face higher control costs, higher transaction costs, and less flexibility regarding compliance options.
Moreover, the use of allowance market power to manipulate prices could have wider impacts on electricity markets as a whole, electricity prices, and electricity reliability both within and across state borders. Therefore, the State Budgets/Intrastate Trading approach needs to address the potential for excessive market power and ensure that allowances would be available to all covered sources at reasonable market prices.
In order to address the potential market power issue, under this option, not all allowances would be allocated using the allocation method described above in section V.D.4. Rather, a small portion of allowances would be withheld from companies with a large share of a state's total fossil-fuel fired electricity generation. These allowances would be made available for purchase by companies with a small share of generation through an annual auction.
EPA is soliciting comments on whether a potential market power problem could arise or reasons why market manipulation would not be a concern under this alternative remedy. EPA is also soliciting comments on whether the approach of using an annual auction to make allowances available to small generators would satisfactorily address this potential issue. This approach is detailed in subsection (3) below.
The approach described for new unit set-asides and allocations to non-operating units above for State Budgets/Limited Trading in section V.D.4 would remain the same for this option.
The use of an annual allowance auction would ensure that companies with a small market share in a state would have access to additional allowances, if needed, other than through direct purchase from a large owner of generation and would reduce the opportunity for market price manipulation by dominant companies. This means that EPA would hold a total of 82 auctions every year to separately auction SO
EPA would use auctions to address market power concerns rather than other options it considered. The Agency considered using a different allowance allocation method that would take into account an owner's share of total generation and distribute proportionally more allowances to owners of a small share of the total generation in each state. This would also ensure that small owners had sufficient allowances without relying on the open markets. However, EPA opted to use an allocation methodology based directly on the approach used to quantify each state's significant contribution to ensure that a direct link exists between allocations and significant contribution to nonattainment or interference with maintenance. EPA also considered direct sales of allowances withheld from dominant sources but believes that auctions would be better suited for determining the appropriate prices for allowances than EPA would be at setting fixed allowance prices for all trading programs in all states. For these reasons, EPA believes the use of auctions would be the best method to address the issue of potential allowance market manipulation.
EPA prefers to use the single-round, uniform-price, sealed bid format because it is simple for all participants to understand, relatively simple to implement and administer, and deters collusion among bidders. In addition, the utility sector already is familiar with this type of format, and EPA has several years of experience running single-round, sealed-bid auctions for Title IV SO
Entities that meet the following criteria would be eligible to participate in the allowance auction: (1) They are required to hold allowances in the state for compliance; and (2) they own no more than 10 percent of the total fossil-fuel fired generation within the state based on EPA's modeled generation for 2014. EPA considered a range from 5 to 20 percent share of ownership for all states and believes that 10 percent ownership is appropriate for determining what constitutes a small market share for this rule. EPA believes that by limiting the auction to entities that own no more than 10 percent of the fossil-fuel fired generation in a state, it would ensure that each auction has enough participants to make auctions viable and competitive and also ensure that the allowances are available only to those companies that may be at a disadvantage in the open markets. Companies with more than a 10 percent share of generation tend to operate several units, have more flexibility, receive a significant share of allowances, and face lower control and transaction costs. EPA is requesting comment on the share of electric generation used as a threshold for determining participation in auctions and also the percentage of allowances available through auctions.
To implement this option, EPA would withhold 2 to 5 percent of the allowances that would be allocated to companies with more than 10 percent of the generation in order to supply allowances for auction each period. This amount is small enough not to have a significant impact on those EGUs from which the allowances are withheld and large enough to provide a sufficient number of allowances for auction. In more highly concentrated states where few companies control much of the generation, a relatively greater number of allowances would be available through the auction to the smaller, potentially disadvantaged companies. Conversely, in states where the electricity sector is less concentrated, there is less threat of market manipulation and greater likelihood of liquid markets. Thus, in these states relatively fewer allowances would be withheld for auction.
Another variation on this alternative option would be to divide companies in each state into three groups, instead of
The allowance management system for the State Budgets/Intrastate Trading option would be consistent with the allowance management system for the State Budgets/Limited Trading programs described above, and with the data system structure EPA has developed for allowance management under its existing cap and trade programs such as the CAIR and the Acid Rain Program.
Monitoring and reporting provisions would require complete, quality-assured monitoring, and timely reporting of emissions to assure accountability and provide public access to data, and would be the same for EPA's proposed remedy and the State Budgets/Intrastate Trading option. Refer to section V.D.4 above for detailed discussion on monitoring and reporting requirements.
Under the State Budgets/Intrastate Trading option for an annual control program (
The state budgets/intrastate trading remedy, by establishing state-specific caps on annual or ozone-season EGU emissions, directly implements the section 110(a)(2)(D)(i)(I) requirement that emissions from sources that 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 standard be prohibited. Of the three remedy options considered, this option provides the most certainty regarding total annual or ozone-season emissions from each state. For this reason, it most directly addresses the statutory mandate that the emissions reductions occur “within the State.”
To implement this remedy option, EPA would use the state budgets without variability limits, developed in accordance with the procedures described in sections IV.D and IV.E. These budgets represent EPA's projection of each affected state's EGU emissions in an average year (before accounting for the inherent variability in power system operations) after the elimination of all emissions that EPA has identified as significantly contributing to nonattainment or interference with maintenance.
The number of allowances in each state budget would be distributed or made available (through an auction or otherwise) to sources in that state. Only allowances distributed or made available to sources in a particular state could be used by sources in that state to satisfy the requirement to hold one allowance for every ton of emissions. Thus, annual (or ozone season) emissions in the state would be capped at the level of the state budget. The limited variability due to banking of emissions could allow limited temporal shifting of emissions, but would not alter the requirement that reductions occur within the state. This remedy is thus sufficient to ensure that all significant contribution and interference with maintenance identified by EPA in today's action is eliminated.
EPA requests comments about whether the State Budgets/Intrastate Trading alternative option could have adverse consequences for electric reliability. The grid regions, and the movement of electricity within each grid region, do not correspond with, and are not limited by, state borders. For example, an increase in electricity demand (
Although companies in one state obtain electricity from sources in multiple states, the State Budgets/Intrastate Trading option would establish emissions budgets on a state basis and would not allow sources in one state to use allowances issued to sources in other states. A source could use, in covering emissions for the current year, both allowances allocated for the current year and banked allowances issued by its state for a past year. However, this option would provide sources less trading flexibility than the proposed State Budgets/Limited Trading remedy. The other remedy options allow for emissions variability, which should largely address electric reliability concerns.
EPA requests comment on whether the State Budgets/Intrastate Trading alternative would provide sufficient flexibility for reliable operation of the integrated grid and, if not, whether there would be ways of preventing or reducing adverse effects such as including additional emissions variability provisions in this option or other approaches. EPA requests comment on approaches to provide additional emissions variability, or other approaches to increasing flexibility, in this option that would be consistent with eliminating all or part of the significant contribution and interference with maintenance that EPA has identified.
These examples of small trading programs below are relevant to further understanding of the State Budgets/Intrastate Trading remedy option. While small trading programs can succeed, they can also have serious consequences for allowance and electricity markets. Budgets and caps, allowance availability, and prices all can have a profound impact on generation and energy prices for consumers in addition to any air quality benefits. In addition, states range in size and number of potential program participants making each state's circumstances unique and more challenging for EPA to monitor.
EPA has approved a NO
The MECT program establishes a hard cap for NO
Allowances can be traded in one of four ways: Vintage trades, current year trades, individual future year trades, or stream trades. Vintage trades involve the immediate transfer of vintage allowances. Current year trades involve the immediate transfer of current allowances. Individual future year and stream trades involve the transfer of future allowances, with stream trades involving a transfer of allowances in perpetuity. Analysis conducted by the Texas Commission on Environmental Quality of the MECT program trading history shows that approximately 20 percent of the allowances allocated each year are traded and that nearly 50 percent of all program participants have participated in allowance trading. Allowance prices are set by market demand. Prices of individual year allowances have steadily increased as the program has progressed, showing that the value of the allowances increases as the cap tightens. Stream trade prices have fluctuated throughout the program, but have steadily increased as the final cap level has been reached.
In comparison to MECT, RECLAIM is a small trading program that has faced a number of challenges due to initial program design decisions. In 1994, RECLAIM established a cap and trade program for NO
RECLAIM Trading Credits (RTC) prices for NO
The operation of the RECLAIM market also contributed to the high prices in the overall power markets. During this period, generators would pay excessively high prices for RTCs in order to raise the price of southern California generation needed to meet demand in the California Independent System Operator (CAISO). Subsequently, generation with high RTC costs in the RECLAIM area would be used to set the electricity price for all of California. The result was that generators could then collect excessive profits on their generation located outside the RECLAIM area. In addition, RECLAIM's overlapping compliance cycles and assignment of facilities to one of two compliance cycles appears to have contributed to some confusion among the participants in the markets.
According to the audit report for the 2007 compliance period, total aggregate NO
As explained above, EPA is requesting comment on a State Budgets/Intrastate Trading remedy as an alternative option because this option would provide certainty regarding emissions from each state. However, this option would be more resource intensive, more complex, less flexible, and potentially more susceptible to market manipulation than the other options on which EPA is taking comment.
Although this remedy may be perceived as relatively easy to understand and follow, it would actually be more burdensome to administer due to the number of trading programs that would be required to operate simultaneously and annual auctions that would be held every year to address the issues of market power within states. It would also result in a greater burden for participants operating EGUs in several states. Finally, EPA is asking for comment on whether this option raises electric reliability issues since sources would have less flexibility and fewer options for compliance. EPA is requesting comments on this approach, specifically on alterations that could address the drawbacks identified above or on any other weaknesses of this option not identified by EPA. EPA also welcomes comments regarding the validity of the concerns with this approach identified above.
The second alternative option on which EPA is requesting comment is the direct control option described in this section. EPA is considering the relative merits of this option and requests comment on whether a direct control remedy option should be included in the final FIPs.
There are a variety of ways to construct a direct control option. The approach that EPA is presenting as an alternative to the remedy in the proposed FIPs would assign emissions rate limits to individual sources. Emissions limits would take the form of input-based emissions rate limits (lb/mmBtu).
EPA requests comments on the direct control remedy summarized later and the approach for determining emissions rate limits, which is described in greater detail in the “State Budgets, Unit Allocations, and Unit Emissions Rates” TSD in the docket for this rulemaking. Specifically, EPA requests comment on the general use of a direct control remedy as well as the specific rate-based direct control approach described later. EPA also requests comment on the potential weakness of this remedy option identified in the discussion later. In addition, EPA requests comment on alternate methodologies which could be used to implement a direct control remedy.
Unlike the proposed remedy option (State Budgets/Limited Trading) and the other alternative remedy option (Intrastate Trading) discussed previously, which both use flexible cap-and-trade approaches, a direct control remedy would directly regulate individual sources. Under this direct control remedy alternative, each owner of EGUs would be required to meet specified average emissions rate limits covering all of its EGUs in each covered state. In a state covered for the 24-hour and/or annual PM
While emissions rates in all states would be set on a unit-by-unit level, a company would be allowed to average the emissions at its units within each state to meet the specified within-the-state rate limits. Company-level average rates would be calculated as company-level total emissions divided by company-level total heat input in each state. Analogously, allowable company-level average rates would be calculated using unit-specific rate limits and the heat inputs used to determine those allowable rates (as discussed in 6.b.1). A company that exceeded the applicable average rate limits would be subject to penalties (described later).
In addition, to address the potential variability in annual emissions associated with emissions rate limits (
If total EGU emissions in a state exceed either of these limits (
To implement this remedy option, EPA would determine unit-level emissions rate limits for SO
An alternative direct control approach would be to create individual unit-level annual emissions caps (
To implement this remedy option, EPA would determine unit-level emissions rate limits for SO
For units where EPA is aware that SO
For those EGUs which did not report a first, second, third, and fourth quarter of SO
For those units that did not report data for a given pollutant and time frame combination and also were not included in IPM modeling, EPA would need to determine permissible rates based on unit characteristics (
EPA is also taking comment on an alternative approach for setting emissions rate limits for those units which did not report a first, second, third, and fourth quarter of SO
EPA has calculated specific emissions rate limits for each existing unit that would be covered under this direct control remedy option. These unit-level emissions rate limits appear in a table entitled “Phase I and Phase II unit-level emissions rate limits” located in the “State Budgets, Unit Allocations, and Unit Emissions Rates” TSD in the docket for this rulemaking. More detailed description of the approach is also provided in the TSD. EPA is requesting comment on this approach for determining the emissions rate limits described in the TSD and on the limits themselves.
Applicability would be the same for all three remedies. Refer to section V.D.4 previously for detailed discussion on applicability.
Monitoring provisions would be the same for all three remedies. The direct control option would require minor changes to the reporting and record keeping requirements due to the need to collect information on both emissions rates and mass. The provisions would require complete, accurate measurement and timely reporting of emissions to assure accountability and provide public access to data. Refer to section V.D.4 previously for detailed discussion on monitoring and reporting requirements.
As discussed previously, starting in 2012, the direct control remedy alternative would include assurance provisions designed to assure that emissions in each covered state do not exceed the state's emissions budget with variability limit. The state's EGU emissions would not be permitted to
Note that for EGUs in states that are in SO
If total EGU emissions in a state exceed either the state's budget with 1-year variability limit in any year, or budget with 3-year variability limit (or 2-year limit, as appropriate) on average, then each company with units in the state whose emissions in the state exceeded its share of the state budget with variability limit would be subject to a penalty for its share of emissions above the budget with variability limit.
In the State Budgets/Limited Trading remedy described previously, the proposed assurance provisions include an allowance surrender requirement. Those assurance provisions would require a company to surrender one allowance for each ton of the company's proportional share of the amount the state's EGU emissions exceed the budget with variability limit. This allowance surrender requirement is in addition to the trading program requirement to surrender one allowance for every ton emitted.
In the direct control alternative, however, allowances are not allocated to units therefore an allowance surrender requirement is not feasible. Instead, for this alternative, a company with emissions over its share of the budget with variability limit would be in violation of the CAA and subject to discretionary penalties. The tonnage amount of the company's violation,
In this direct control remedy alternative, a company's share of the state budget with variability limit would be determined using the same approach described in the State Budgets/Limited Trading option, previously. That approach is based on allowance allocations; although the direct control remedy would not allocate allowances to sources, this remedy would use the allocation method described in State Budgets/Limited Trading in determining a company's share of the state budget.
The assurance provisions would commence in 2012 for this direct control option. In contrast and for the reasons explained in section V.D.4, for the proposed State Budgets/Limited Trading remedy, EPA is proposing to start applying the assurance provisions in 2014. The combination of circumstances for State Budgets/Limited Trading—known locations of controls and a price on each ton emitted—provides greater certainty of where reductions will occur during 2012 and 2013 than would be provided by the direct control program. In contrast to the State Budgets/Limited Trading remedy, the direct control program does not put a price on emitting SO
EPA requests comment on these assurance provisions.
As explained previously, under this direct control remedy approach, each owner of EGUs within a covered state would be required to meet specified average emissions rate limits for SO
The excess emissions of the owner's EGUs would be calculated as the EGUs” actual annual average emissions rate minus the applicable annual average emissions rate limit, with the difference multiplied by the EGUs” total actual annual heat input. Each ton of excess emissions, as well as each day in the averaging period (
For the ozone season NO
In addition, any company with EGU emissions exceeding its share of the state budget with variability limit for SO
EPA requests comment on the penalty provisions.
The direct control remedy option would implement the section 110(a)(2)(D)(i)(I) requirement that “emissions from sources that contribute significantly and interfere with maintenance in downwind nonattainment areas” be prohibited. It would do so by establishing for covered EGUs specific emissions rate limits, with company-wide within state averaging. Emissions rates in all states would be set on a unit-by-unit basis at levels such that, if the units operated at the levels assumed in determining the state budgets, total emissions from these units would sum to each state's emissions budgets without the variability limits. A company could average the emissions at its units within each state to meet specified within-the-state rate limits. This approach would directly limit emissions from EGUs in each covered state, providing assurance that emissions reductions would occur within each state consistent with the mandate of section 110(a)(2)(D)(i)(I).
Because individual EGUs would be required to meet specific emissions rate limits (with within-state company-wide averaging), this option would ensure that required controls and measures are installed and implemented within the state. The fact that emissions, after implementation of all controls required to meet the emissions rate limits, may vary based on the amount of generation in each state is not inconsistent with the section 110(a)(2)(D)(i)(I) requirement that all significant contribution and interference with maintenance be eliminated. As noted previously, changes in generation due to changing meteorology, demand growth, or disruptions in electricity supply from other units can all affect the amount of generation needed in a specific state and thus the baseline emissions from that state. Because baseline emissions are variable, emissions after the elimination of all significant contribution are also somewhat variable.
Further, any such variation in emissions would be limited. As with the State Budgets/Limited Trading option described previously, no state's EGU emissions would be permitted to exceed the state budget with variability limit in any year (or ozone season, as applicable). Nor would any state's EGU emissions be permitted, on average, to exceed the budget plus a specified portion of the state's variability limit, evaluated as a 3-year rolling annual (or ozone season) average (or, in SO
The risk to electric reliability is considered low under the direct control remedy option. Specifically, the provisions for the variability limits and company averaging within each state help to alleviate electric reliability concerns. Therefore, EGUs are expected to be able to both comply with their emissions rate limits and reliably provide electricity to customers. EPA requests comment on electric reliability issues.
As explained previously, EPA is requesting comment on the merits and weaknesses of this direct control remedy option. EPA did not include this remedy option in the proposed FIPs; however, we continue to consider this option and are taking comment on whether this option should be included in the FIPs. This option would provide assurance that companies in each state are meeting specific emissions rate limits and would also ensure that annual emissions from each state are capped. Additionally, the direct control option may be perceived as easy to understand and follow. Nonetheless, at this time, EPA believes the direct control option is inferior to the preferred approach. EPA requests comments on the validity of EPA's concerns regarding this option and alternative methods for addressing those concerns.
EPA modeling projects fewer emissions reductions under the direct control alternative than the proposed State Budgets/Limited Trading remedy. Additionally, the reductions would be achieved at a higher cost than the proposed remedy.
A direct control program must account for outliers,
Within the direct control approach on which EPA is taking comment, the assurance provisions (which limit a company's emissions within a state to its share of the budget with the variability limit if the state's budget with variability limit is exceeded) may also put an owner with a small number of units at a disadvantage compared to an owner with a larger number of units within a state. EPA seeks comment on this issue.
A direct control program based on emissions rate limits does not cap annual emissions; if there is growth in fossil generation within a state, a rate-based approach alone could allow emissions increases. In the direct control approach on which EPA requests comment, the assurance provisions provide some assurance of achieving required reductions.
Notably, the direct control approach described herein restricts compliance options more than a trading approach. EPA generally believes that granting more flexibility to companies in meeting an emissions reductions goal results in the ability of those companies to meet that goal at a lower cost and decreases reliability risks in the electric power system. While some portion of this effect is captured in IPM modeling (
Emission and cost projections for the three remedies discussed previously come from the Integrated Planning Model (IPM), a dynamic linear programming model of electric generation in the contiguous U.S. For each remedy, projected costs relative to the base case appear in Table V.E-1. The following section explains these projections in light of how the remedies differ and how they were represented in the model. The emissions projections below comprise fossil generation above 25 megawatts of capacity, the units that would be subject to the rule. More detail on the modeling of costs and emissions can be found in the Regulatory Impact Analysis for the proposed Transport Rule and in the IPM Documentation.
The proposed remedy of State Budgets/Limited Trading was modeled with regional emissions caps beginning in 2012 and state-specific emissions limits beginning in 2014. The state-specific emissions limits represent state budgets plus 3-year average variability limits. Because banking early reductions beyond the budget levels is allowed, 2012 SO
Though based on the same state budgets as State Budgets/Limited trading, the alternative remedy of State Budgets/Intrastate Trading costs approximately 0.5 billion 2006 dollars more in 2012 and achieves slightly more SO
The direct control alternative remedy consists of source-specific emissions rate limits commensurate with those used in the derivation of state budgets (see sections IV.D and IV.E). To represent assurance provisions, the emissions from each state were also constrained to the state's budget plus 3-year average variability limit beginning in 2012. For states with more stringent SO
Compared to the proposed remedy of State Budgets/Limited Trading, the direct control alternative costs approximately 0.6 billion 2006 dollars more and results in less SO
Tables V.E-5, V.E-6, and V.E-7 show projected emissions at the state
This proposed Transport Rule would replace the CAIR rule and its associated trading programs. This section elaborates on some of the areas of the CAIR program that would need to be addressed in the transition to the new program. EPA is taking comment on how the transition would occur.
The CAIR, CAIR SIPs, and CAIR FIPs would be replaced entirely by the Transport Rule provisions. If this proposed Transport Rule is finalized in 2011, the CAIR, CAIR SIPs, and CAIR FIPs would sunset at the completion of all 2011 control period activities.
In order to implement the sunsetting of the CAIR and CAIR FIPs, the proposed rule includes several revisions of the CAIR, §§ 51.123 and 51.124, and the CAIR FIPs, §§ 52.35 and 52.36. First, sunsetting the CAIR and CAIR FIPs in 2011 would mean that the requirements of the CAIR and CAIR FIPs would not apply to control periods after 2011. Specifically, the CAIR would be revised to rescind, with regard to any control period beginning after December 31, 2011, the findings that states must revise their SIPs to meet CAIR requirements. Similarly, the CAIR FIPs would be revised to state that, with regard to any post-December 31, 2011 control period, CAIR FIP requirements would not be applicable.
Second, the sunsetting in 2011 would mean that the CAIR trading programs would not continue past 2011. Consequently, the proposed revisions of the CAIR and CAIR FIPs would state that, with regard to any post-December 31, 2011 control period, the Administrator would not carry out any of the functions established for the Administrator in the CAIR model trading rule, the CAIR FIPs, or any state trading programs approved under the CAIR.
Third, the sunsetting in 2011 would mean that CAIR allowances allocated for control periods after 2011—which have already been recorded by the Administrator in the Allowance Management System compliance accounts of sources in many states—would not be usable in the CAIR trading programs for control periods ending before 2012. Specifically, under the existing CAIR trading programs, a source that fails to hold sufficient allowances to cover emissions for the 2011 control period (whether annual or ozone season) must provide for surrender to the Administrator three allowances (one as an offset and two as an automatic penalty) allocated for the 2012 control period for every one
As a result of these proposed revisions of the CAIR and CAIR FIP rules, there would be no offset or automatic penalty deducted for a source that failed to hold sufficient allowances to cover its 2011 control period emissions unless the state SIPs are revised. In order to preserve the deductions for offsets and automatic penalties for 2011 control periods, the CAIR SIPs for most states (
Moreover, any excess emissions for the 2011 control periods would be violations of the state SIPs (or of CAIR FIPs in those states with CAIR FIPs) and of the Clean Air Act and, therefore would be subject to discretionary civil penalties under CAA Section 113. Each ton of excess emissions, and each day in the control period involved (
In addition to the previously-described, proposed revisions to §§ 51.123, 51.124, 52.35, and 52.36, certain provisions in part 52 that reflect, state by state, the CAIR SIP revisions and CAIR FIP requirements applicable to each state would need to be revised to implement the sunsetting of the CAIR, CAIR SIPs, and CAIR FIPs. However, the timing for proposal and adoption of revisions to part 52 is necessarily different for the part 52 provisions addressing CAIR SIP revisions and those addressing revisions of the CAIR and the CAIR FIPs themselves.
The part 52 provisions addressing CAIR SIP revisions for the individual states reflect EPA's approval of CAIR SIP revisions adopted and submitted to EPA by the respective states. The first step toward sunsetting those part 52 provisions would be that, if and after the proposed Transport Rule was finalized, the respective states would change their SIPs in order to, among other things, make the CAIR provisions in the SIPs inapplicable to any control period that starts after December 31, 2011. After the submittal by the respective states of these SIP revisions, EPA would review and approve such changes. Consequently, the rule text approving such CAIR SIP revisions would not be included in either the proposed Transport Rule or any final rule based on the proposed Transport Rule, but rather would be proposed and adopted only after the respective states revised their SIPs. As EPA did when transitioning from the NO
In contrast, the part 52 provisions adopting CAIR FIPs for individual states could be revised, as part of the proposed Transport Rule, to sunset these CAIR FIPs because no state action would be required to accomplish this sunsetting. EPA proposes to revise each state-specific part 52 provision adopting a CAIR FIP—whether for NO
The states covered by the proposed Transport Rule differ slightly from states covered by the CAIR. Namely, as compared with the states covered by the CAIR NO
Consequently, sources in some states that would be covered by the proposed Transport Rule would have new allowance holding requirements beginning in 2012, but would not have been subject to the CAIR trading programs. Conversely, sources in some states covered by the CAIR or CAIR FIPs would not be subject to the proposed Transport Rule. To the extent that the CAIR reductions were needed or relied upon to satisfy other SIP requirements, states might need to find alternative ways to satisfy requirements for their SIPs. EPA will work with individual states to identify state-specific options to ensure that necessary reductions needed for other SIP requirements can continue.
Except for the changes in the states covered, the general applicability provisions of the proposed Transport Rule would be essentially the same as the CAIR general applicability provisions, with a few exceptions. First, the proposed Transport Rule does not allow any units to opt into the trading programs. In contrast, under CAIR, states could elect to allow boilers, combustion turbines, and other combustion devices to opt into the CAIR trading programs under opt-in provisions specified by EPA, and a number of states adopted these opt-in provisions. However, currently no units have opted into the CAIR trading programs, and, even in the Acid Rain Program, where opt-in provisions have been in place since 1995, very few units have actually opted in.
Second, under the CAIR trading programs, a state subject to the NO
There are several factors underlying this difference between the proposed Transport Rule and the CAIR. First, in determining which states are contributing significantly or interfering with maintenance of the ozone NAAQS, the Transport Rule does not cover some states subject to the NO
Substantial emissions reductions have occurred as a result of the CAIR programs. These reductions are greater than were expected when the rule was promulgated. This is evidenced in the banks of allowances that exist in each of the CAIR programs.
The bank of Title IV allowances was more than 12 million tons at the end of 2009. This bank is the result of emissions reductions for Title IV where allowances are used for compliance with the requirement to hold allowances covering emissions and early reductions for the CAIR SO
EPA evaluated whether the Title IV allowance bank could be used in the proposed Transport Rule SO
EPA proposes that the Transport Rule provisions not allow the use of Title IV allowances either as the basis for allocating Transport Rule SO
Assuming that NO
EPA has identified several possible approaches for handling banked pre-2012 CAIR NO
The second approach might be to allow only a limited amount of banked pre-2012 CAIR allowances to be brought into the Transport Rule programs. This could be accomplished by allowing all such banked allowances to be used, but at a tonnage authorization level significantly lower than one ton per allowance, in the Transport Rule NO
The third option might be to try to factor the bank into the calculation of state budgets by reducing the state budgets to take account of the banked pre-2012 CAIR allowances. This might allow these allowances to be used in the Transport Rule NO
A final approach would simply be to not allow the use of any banked pre-2012 CAIR allowances in the Transport Rule NO
Monitoring and reporting using 40 CFR part 75 provisions is required for all units subject to the CAIR programs and would also be required for all units subject to the proposed Transport Rule programs. In states covered by both the CAIR and the proposed Transport Rule, units would generally have no changes to their monitoring and reporting requirements and would continue to monitor and submit reports as they have under the CAIR. The exceptions are units in: CAIR states subject to CAIR NO
Units in the following states monitor and report both SO
Non-Acid Rain units in Connecticut and Massachusetts (about 15 units total) that currently monitor and report NO
Non-Acid Rain units in Mississippi (about 4 units) and Texas (about 52 units) are currently monitoring and reporting NO
In states not covered by the CAIR but covered by the proposed Transport Rule, some units would have to meet new monitoring and reporting requirements under part 75. Kansas, Minnesota, and Nebraska are not covered by the CAIR and are covered by the Transport Rule, and units there would need to monitor and report NO
Units that have not been covered by part 75 monitoring and reporting in the past would likely have less than one year to install, certify, and operate the required monitoring systems. EPA believes that these units would reasonably be able to comply with this requirement because the monitoring equipment needed is not extensive or is largely in place already for the purpose of meeting other requirements. Quality assurance and reporting provisions and data system upgrades may be necessary, but there would be sufficient time to accomplish this.
Promulgation of a Transport Rule would not affect any Acid Rain Program requirements. Any Title IV sources that are subject to final Transport Rule provisions would still need to continue to comply with all Acid Rain provisions. Acid Rain requirements are established independently in Title IV of the Clean Air Act and would not be replaced by the Transport Rule. In contrast with the CAIR, the proposed Transport Rule would not allow Title IV SO
Compliance with the Transport Rule would reduce SO
There would likely be changes to emissions at some Acid Rain sources outside of the Transport Rule area as a result of the transition from CAIR to the Transport Rule. Namely, emissions at some non-Transport Rule Acid Rain sources may increase because of the change in the Title IV allowance price. This would be expected to occur mainly in the states that border the Transport Rule states. Overall, SO
States affected by both the NO
Many of the states using the NBP used the CAIR NO
Therefore, the NBP states would need to achieve their NO
States that were part of the CAIR NO
In early 2009, EPA began its efforts to coordinate activities with state regulatory partners and other stakeholders on the new transport rule to replace CAIR. To establish open lines of communication and ensure transparency in the regulatory process, EPA participated in a series of “listening sessions” in March and April, 2009 with states, nongovernmental organizations, and industry. EPA also participated in tribal teleconferences. The same agenda was set for each of the ten meetings. Meeting notes were developed and distributed for concurrence and to ensure accuracy. Subsequent to these sessions, EPA received post-meeting comments and additional detailed suggestions and analyses on ways to address some of the issues that the court cited, most notably from state regional organizations in the eastern U.S. All the stakeholder-related materials may be found in the EPA docket for the transport rule (EPA-HQ-OAR-2009-0491).
Following the remand of CAIR to EPA in December 2008, 17 states in the East and Midwest, under the umbrellas of the OTC and Lake Michigan Air Directors Consortium (LADCO) with support from southeastern states, worked to develop recommendations for EPA to consider in crafting a new transport rule to replace CAIR. The comprehensive framework presented the consensus approach the states reached but noted that certain regional differences would be addressed in separate letters with additional recommendations and supporting materials.
EPA has considered and appreciates all the ideas and recommendations provided by the states. We are employing the technical work that they submitted as part of the data set we are using in this and later transport rules.
Topics addressed in the listening sessions, where EPA asked stakeholders and regulatory partners for their thoughts on particular issues, included:
• Analysis and baselines.
• Linkages between a state's significant contribution and downwind nonattainment/interference with maintenance.
• Remedies.
• Attainment planning.
• Other areas.
EPA continued to provide updates to regulatory partners and stakeholders through monthly conference calls with states, hosted by,
Several of the options presented in this proposal were influenced by feedback received from stakeholders and regulatory partners, including:
• 2012 baseline used in the calculation of each state's significant contribution and interference with maintenance.
• The “tiered” approach to SO
• Threshold (1 percent of the NAAQS) used for linking upwind areas to downwind nonattainment and maintenance receptors.
• Approach used to give independent meaning to the interfere with maintenance prong of section 110(a)(2)(D)(i)(I).
• Level of reductions required.
• Use of limited interstate trading.
• Correlated and coordinated requirements and timing for the power industry.
EPA looks forward to the public comment period of this rulemaking and is committed to establishing and maintaining close working relationships with a broad range of public and private sector organizations.
All states have an obligation to submit SIPs that address the requirements of CAA section 110(a)(2) within 3 years of promulgation or revision of a NAAQS. With respect to the 1997 ozone and PM
The 2005 findings of failure to submit also remain in force for many states not covered by the original CAIR. Some of these states have not yet submitted 110(a)(2)(D)(i)(I) SIPs and thus the findings remain in force. However, several states that were not covered by the CAIR have since 2005 submitted SIP revisions to satisfy the requirements of section 110(a)(2)(D)(i) for the 1997 8-hour ozone and PM
For the states that have now been identified to be contributing significantly to nonattainment or interfering with maintenance under this proposed rule and whose 110(a)(2)(D)(i)(I) SIPs with respect to the 1997 ozone and PM
For states which are not included in a final FIP under this proposed transport rule and that have not submitted a 110(a)(2)(D)(i)(I) SIP to address the 1997 ozone and PM
EPA has approved the 110(a)(2)(D)(i) submission from the state of Kansas for the 1997 ozone and PM
With respect to the 2006 24-hour PM
EPA also notes that, by promulgating these Transport Rule FIPs, EPA would in no way affect the right of states to submit, for review and approval, a SIP that replaces the federal requirements of the FIP with state requirements. In order to replace the FIP in a state, the state's SIP must provide adequate provisions to prohibit NO
For each upwind state covered by the proposed Transport Rule, EPA proposes state-specific emissions reductions requirements with respect to one or more of three air quality standards—the 1997 annual PM
In the states for which EPA is proposing to require reductions with respect to both the 24-hour PM
EPA is taking comment on all aspects of how a state could replace the Transport Rule FIP with a SIP and on what the SIP approval criteria should be.
EPA's proposed FIPs would not establish any permitting requirements independent of those under Title V of the CAA and the regulations implementing title V, 40 CFR parts 70 and 71.
EPA anticipates that, given the nature of the units covered by the proposed FIPs, most of the sources at which they are located would be subject to Title V permitting requirements. For sources subject to Title V, the requirements applicable to them under the proposed FIPs would be “applicable requirements” under Title V and therefore would need to be included in the Title V permits. For example, requirements under the proposed FIPs concerning designated representatives, monitoring, reporting, and recordkeeping, the requirement to hold allowances covering emissions, the assurance provisions, and liability would be “applicable requirements” and necessary to include in the permits.
The Title V permits program includes, among other things, provisions for permit applications, permit content, and permit revisions that would address the applicable requirements under the proposed FIPs in a manner that would provide the flexibility necessary to implement a market-based program such as the one that EPA is proposing. For example, the Title V regulations provide that a permit issued under Title V must include, for any “approved * * * emissions trading and other similar programs or processes” applicable to the source, a provision stating that no permit revision is required “for changes that are provided for in the permit.” 40 CFR 70.6(a)(8) and 71.6(a)(8). The trading program regulations for the proposed FIPs would include a provision stating that no permit revision is necessary for the allocation, holding, deduction, or transfer of allowances. Consistent with the Title V regulations, this provision would also be included in each Title V permit for a covered source. As a result, allowances could be traded (or allocated, held, or deducted) under the FIPs without a revision of the Title V permit of any of the sources involved.
As a further example of flexibility under Title V, the Title V regulations allow the use of the minor permit modification procedures for permit modifications “involving the use of economic incentives, marketable permits, emissions trading, and other similar approaches, to the extent that such minor permit modification procedures are explicitly provided for in an applicable implementation plan or in applicable requirements promulgated by EPA.” 40 CFR 70.7(e)(2)(i)(B) and 40 CFR 71.7(e)(1)(i)(B). The trading program regulations for the proposed FIPs would include provisions requiring unit owners and operators to submit monitoring system certification applications (or, for alternative monitoring systems, petitions) to EPA establishing the monitoring and reporting approach to be used by the unit. These applications and petitions are subject to EPA review and approval to ensure consistency in monitoring and reporting among all trading program participants. As provided in the proposed regulations, EPA would only allow use of approaches that would result in emissions data with an appropriate level of precision, reliability, accessibility, and timeliness. The proposed regulations would also include a provision stating that a description of the general approach that each covered unit is required to use for monitoring and reporting emissions (
As new applicable requirements under Title V, the requirements for covered units under the final FIPs would be incorporated into covered sources’ existing Title V permits either pursuant to the provisions for reopening for cause (40 CFR 70.7(f) and 40 CFR 71.7(f)) or the permit renewal provisions (40 CFR 70.7(c) and 71.7(c)).
EPA recognizes that pollution control projects, including pollution control projects constructed to comply with the proposed rule, have the potential to trigger new source review (NSR) permitting.
On December 20, 2005, the EPA agreed to reconsider one specific aspect of the CAIR. In that notice, EPA granted reconsideration and sought comment on the potential impact of a judicial opinion,
Because GHG was not considered by EPA to be a “pollutant”, let alone a “regulated pollutant,” at the time of CAIR, GHG was not addressed in the previous analysis. GHG requirements related to the component of new source review concerning the Prevention of Significant Deterioration (“PSD”) program have recently been addressed in EPA's “Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs,” 75 FR 17004 (April 2, 2010), and “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule,” 75 FR (June 3, 2010) (“Tailoring Rule”). Generally, as discussed in those actions, once the PSD requirements for GHG take effect on January 2, 2011, major stationary sources will be required to address GHG emissions as part of the PSD program if these sources emit GHG in amounts that equal or
Consistent with EPA's previous analysis and EPA's conclusions for GHG, EPA does not believe that there are significant impacts from NSR for any pollution control projects resulting from the proposed rule such as low-NO
In this section, we present the results of EPA's analysis of the benefits of the emissions reductions in this proposal on PM
Implementation of this rule will very substantially lower the extent of nonattainment and maintenance problems for the annual and 24-hour PM
A key step in the process of developing a 110(a)(2)(D)(i)(I) rule involves analyzing existing (base case) emissions to determine which states significantly contribute to downwind nonattainment and maintenance areas. EPA cannot prejudge at this stage which states will be affected by the rule. For example, a state affected by CAIR may not be affected by the new rule and after the new rule goes into effect, the CAIR requirements will no longer apply. For a state covered by CAIR but not covered by the new rule, the CAIR requirements would not be replaced with new requirements, and therefore an increase in emissions relative to present levels could occur in that state. More fundamentally, the court has made clear that, due to legal flaws, the CAIR rule cannot remain in place and must be replaced. If EPA's base case analysis were to ignore this fact and assume that reductions from CAIR would continue indefinitely, areas that are in attainment solely due to controls required by CAIR would again face nonattainment problems because the existing protection from upwind pollution would not be replaced. For these reasons, EPA cannot assume in its base case analysis, that the reductions required by CAIR will continue to be achieved.
Following this logic, the 2012 base case shows emissions higher than current levels in some states. Because EPA has been directed to replace CAIR, EPA believes that for many states, the absence of the CAIR NO
The air quality modeling platform described in section IV.C. was used by EPA to model the impacts of the proposed SO
The projected 2014 concentrations of annual PM
The information in Table IX-1 shows that there will be significant reductions in the extent of nonattainment and maintenance problems for annual PM
For 24-hour PM
The emissions reductions in this proposal will result in considerable progress toward attainment and maintenance at the 28 sites that remain as nonattainment and/or maintenance for the 24-hour PM
Thus, the SO
Based on the 2012 base air quality modeling for ozone, 27 sites in the East are projected to be nonattainment or have problems maintaining the 1997 ozone standard. The initial phase of summer NO
To estimate the human health benefits of the proposed Transport Rule, we used the BenMAP model to quantify the changes in PM
Table IX-3 presents the primary estimates of reduced incidence of PM
Ozone health-related benefits are expected to occur during the summer ozone season (usually ranging from May to September in the eastern U.S.). Based upon modeling for 2014, annual ozone related health benefits are expected to include between 50 and 230 fewer premature mortalities, 690 fewer hospital admissions for respiratory illnesses, 230 fewer emergency room admissions for asthma, 300,000 fewer days with restricted activity levels, and 110,000 fewer days where children are absent from school due to illnesses. When adding the PM and ozone-related mortalities together, we find that the proposed Transport Rule will yield between 14,000 and 36,000 fewer premature mortalities. The following references are used in providing our estimates of ozone health-related benefits:
Bell, M.L.,
Laden, F., J. Schwartz, F.E. Speizer, and D.W. Dockery. 2006. Reduction in Fine Particulate Air Pollution and Mortality. American Journal of Respiratory and Critical Care Medicine 173:667-672. Estimating the Public Health Benefits of Proposed Air Pollution Regulations. Washington, DC: The National Academies Press.
Levy JI, Baxter LK, Schwartz J. 2009. Uncertainty and variability in health-related damages from coal-fired power plants in the United States. Risk Anal. doi: 10.1111/j.1539-6924.2009.01227.x [Online 9 Apr 2009]
Pope, C.A., III, R.T. Burnett, M.J. Thun, E.E. Calle, D. Krewski, K. Ito, and G.D. Thurston. 2002. Lung Cancer, Cardiopulmonary Mortality, and Long-term Exposure to Fine Particulate Air Pollution. Journal of the American Medical Association 287:1132-1141.
Only a subset of the expected visibility benefits—those for Class I areas—are included in the monetary benefits estimates we project for this rule. We anticipate improvement in visibility in residential areas where people live, work and recreate within the Transport Rule region for which we are currently unable to monetize benefits. For the Class I areas we estimate annual benefits of $3.4 billion beginning in 2014 for visibility improvements. Methodological limitations prevented us from quantifying the visibility benefits of the alternate remedies. The value of visibility benefits in areas where we were unable to monetize benefits could also be substantial.
When fully implemented in 2014, the proposed Transport Rule would reduce emissions of CO
Table IX-4 presents the estimated monetary value of reductions in the incidence of health and welfare effects. These estimates account for increases in the value of risk reduction over time. As the table indicates, total benefits are driven primarily by the reduction in premature fatalities each year, which account for over 90 percent of total benefits.
Table IX-5 presents the total monetized net benefits for 2014. A listing of the benefit categories that could not be quantified or monetized in our benefit estimates are provided in Table IX-6.
The estimated annual private costs to implement the emission reduction requirements of the proposed rule for the Transport Rule region are $3.7 billion in 2012 and $2.8 billion in 2014 (2006$) for the proposed remedy option, $4.2 billion in 2012 and $2.7 billion in 2014 for the State Budgets/Intrastate Trading remedy option, and $4.3 billion in 2012 and $3.4 billion in 2014 for the direct control remedy option. These costs are the annual incremental electric generation production costs that are expected to occur with the Transport Rule. The EPA uses these costs as compliance cost estimates in developing cost-effectiveness estimates.
In estimating the net benefits of regulation, the appropriate cost measure is “social costs.” Social costs represent the welfare costs of the rule to society. These costs do not consider transfer payments (such as taxes) that are simply redistributions of wealth. The social costs of this rule (thus reflecting the proposed remedy option) are estimated to be approximately $2.0 billion in 2014 assuming a 3 percent discount rate. These costs become $2.2 billion in 2014, if one assumes a 7 percent discount rate. Thus, the net benefit (social benefits minus social costs) as will be shown in Table IX-5 for the proposed remedy option is approximately $120 to 292 billion or $109 to 264 billion (3 percent and 7 percent discount rates) in 2014. Implementation of the rule is expected to provide society with a substantial net gain in social welfare based on economic efficiency criteria.
The annualized regional cost of the proposed rule, as quantified here, is EPA's best assessment of the cost of implementing the proposed option. These costs are generated from rigorous economic modeling of changes in the power sector expected from the proposed rule. This type of analysis using IPM has undergone peer review and been upheld in federal courts. The direct cost includes, but is not limited to, capital investments in pollution controls, operating expenses of the pollution controls, investments in new generating sources, and additional fuel expenditures. The EPA believes that these costs reflect, as closely as possible, the additional costs of the proposed option to industry. The relatively small cost associated with monitoring emissions, reporting, and recordkeeping for affected sources is not included in these annualized cost estimates, but EPA has done a separate analysis and estimated the cost to less than $28 million (see section XII.B., Paperwork Reduction Act). However, there may exist certain costs that EPA has not quantified in these estimates. These costs may include costs of transitioning to this rule, such as the costs associated with the retirement of smaller or less efficient EGUs, employment shifts as workers are retrained at the same company or re-employed elsewhere in the economy, and certain relatively small permitting costs associated with Title V that new program entrants face.
An optimization model was employed that assumes cost minimization. Costs may be understated if the regulated community chooses not to minimize its compliance costs in the same manner to comply with the rules. Although EPA has not quantified these costs, the Agency believes that they are small compared to the quantified costs of the program on the power sector. However, EPA's experience and results of independent evaluation suggests that costs are likely to be lower by some degree (
Every benefit-cost analysis examining the potential effects of a change in environmental protection requirements is limited to some extent by data gaps, limitations in model capabilities (such as geographic coverage), and uncertainties in the underlying scientific and economic studies used to configure the benefit and cost models. Gaps in the scientific literature often result in the inability to estimate quantitative changes in health and environmental effects. Gaps in the economics literature often result in the inability to assign economic values even to those health and environmental outcomes that can be quantified. While uncertainties in the underlying scientific and economics literatures (that may result in overestimation or underestimation of benefits) are discussed in detail in the economic analyses and its supporting documents and references, the key uncertainties which have a bearing on the results of the benefit-cost analysis of this rule include the following:
• EPA's inability to quantify potentially significant benefit categories;
• Uncertainties in population growth and baseline incidence rates;
• Uncertainties in projection of emissions inventories and air quality into the future;
• Uncertainty in the estimated relationships of health and welfare effects to changes in pollutant concentrations including the shape of the C-R function, the size of the effect estimates, and the relative toxicity of the many components of the PM mixture;
• Uncertainties in exposure estimation; and
• Uncertainties associated with the effect of potential future actions to limit emissions.
Despite these uncertainties, we believe the benefit-cost analysis provides a reasonable indication of the expected economic benefits of the rulemaking in future years under a set of reasonable assumptions. This approach calculates a mean value across VSL estimates derived from 26 labor market and contingent valuation studies published between 1974 and 1991. The mean VSL across these studies is $6.3 million (2000$).
As Table IX-4 indicates, total benefits are driven primarily by the reduction in premature mortalities each year. Some key assumptions underlying the primary estimate for the premature mortality category include the following:
(1) EPA assumes inhalation of fine particles is causally associated with premature death at concentrations near those experienced by most Americans on a daily basis. Plausible biological mechanisms for this effect have been hypothesized for the endpoints included in the primary analysis and the weight of the available epidemiological evidence supports an assumption of causality.
(2) EPA assumes all fine particles, regardless of their chemical composition, are equally potent in causing premature mortality. This is an important assumption, because the proportion of certain components in the PM mixture produced via precursors emitted from EGUs may differ significantly from direct PM released from automotive engines and other industrial sources, but no clear scientific grounds exist for supporting differential effects estimates by particle type.
(3) We assume that the health impact function for fine particles is linear down to the lowest air quality levels modeled in this analysis. Thus, the estimates include health benefits from reducing fine particles in areas with varied concentrations of PM
The EPA recognizes the difficulties, assumptions, and inherent uncertainties in the overall enterprise. The analyses upon which the Transport Rule is based were selected from the peer-reviewed scientific literature. We used up-to-date assessment tools, and we believe the results are highly useful in assessing this rule.
There are a number of health and environmental effects that we were unable to quantify or monetize. A complete benefit-cost analysis of the Transport Rule requires consideration of all benefits and costs expected to result from the rule, not just those benefits and costs which could be expressed here in dollar terms. A listing of the benefit categories that were not quantified or monetized in our estimate are provided in Table IX-6.
Important benefits beyond the human health and welfare benefits resulting from reductions in ambient levels of PM
Atmospheric deposition of sulfur and nitrogen, often referred to as acid rain, occurs when emissions of SO
The extent of adverse effects of acid deposition on freshwater and forest ecosystems depends largely upon the ecosystem's ability to neutralize the acid. The neutralizing ability [key indicator is termed Acid Neutralizing Capacity (ANC)] depends largely on the watershed's physical characteristics, such as geology, soils, and size. Acidic conditions occur more frequently during rainfall and snowmelt that cause high flows of water and less commonly during low-flow conditions, except where chronic acidity conditions are severe. Biological effects are primarily attributable to a combination of low pH and high inorganic aluminum
Acidifying deposition has altered major biogeochemical processes in the U.S. by increasing the nitrogen and sulfur content of soils, accelerating nitrate and sulfate leaching from soil to drainage waters, depleting base cations (especially calcium and magnesium) from soils, and increasing the mobility of aluminum. Inorganic aluminum is toxic to some tree roots. Plants affected by high levels of aluminum from the soil often have reduced root growth, which restricts the ability of the plant to take up water and nutrients, especially calcium (U.S. EPA, 2008f). These direct effects can, in turn, influence the response of these plants to climatic stresses such as droughts and cold temperatures. They can also influence the sensitivity of plants to other stresses, including insect pests and disease (Joslin
Both coniferous and deciduous forests throughout the eastern U.S. are experiencing gradual losses of base cation nutrients from the soil due to accelerated leaching for acidifying deposition. This change in nutrient availability may reduce the quality of forest nutrition over the long term. Evidence suggests that red spruce and sugar maple in some areas in the eastern U.S. have experienced declining health because of this deposition. For red spruce (
This regulatory action will decrease acid deposition in the transport region and is likely to have positive effects on the health and productivity of forest systems in the region.
Since 1990, a large amount of research has been conducted on the impact of nitrogen deposition to coastal waters. Nitrogen is often the limiting nutrient in coastal ecosystems. Increasing the levels of nitrogen in coastal waters can cause significant changes to those ecosystems. In recent decades, human activities have accelerated nitrogen nutrient inputs, causing excessive growth of algae and leading to degraded water quality and associated impairments of estuarine and coastal resources.
Atmospheric deposition of nitrogen is a significant source of nitrogen to many estuaries. The amount of nitrogen entering estuaries due to atmospheric deposition varies widely, depending on the size and location of the estuarine watershed and other sources of nitrogen in the watershed. A recent assessment of 141 estuaries nationwide by the National Oceanic and Atmospheric Administration (NOAA) concluded that 19 estuaries (13 percent) suffered from moderately high or high levels of eutrophication due to excessive inputs of both N and phosphorus, and a majority of these estuaries are located in the coastal area from North Carolina to Massachusetts (NOAA, 2007). For estuaries in the Mid-Atlantic region, the contribution of atmospheric distribution to total N loads is estimated to range between 10 percent and 58 percent (Valigura
Eutrophication in estuaries is associated with a range of adverse ecological effects. The conceptual framework developed by NOAA emphasizes four main types of eutrophication effects—low dissolved oxygen (DO), harmful algal blooms (HABs), loss of submerged aquatic vegetation (SAV), and low water clarity. Low DO disrupts aquatic habitats, causing stress to fish and shellfish, which, in the short-term, can lead to episodic fish kills and, in the long-term, can damage overall growth in fish and shellfish populations. Low DO also degrades the aesthetic qualities of surface water. In addition to often being toxic to fish and shellfish, and leading to fish kills and aesthetic impairments of estuaries, HABs can, in some instances, also be harmful to human health. SAV provides critical habitat for many aquatic species in estuaries and, in some instances, can also protect shorelines by reducing wave strength; therefore, declines in SAV due to nutrient enrichment are an important source of concern. Low water clarity is the result of accumulations of both algae and sediments in estuarine waters. In addition to contributing to declines in SAV, high levels of turbidity also degrade the aesthetic qualities of the estuarine environment.
Estuaries in the eastern United States are an important source of food production, in particular fish and shellfish production. The estuaries are capable of supporting large stocks of resident commercial species, and they serve as the breeding grounds and interim habitat for several migratory species.
This rule is anticipated to reduce nitrogen deposition in the Transport Rule region. Thus, reductions in the levels of nitrogen deposition will have a positive impact upon current eutrophic conditions in estuaries and coastal areas in the region.
Mercury is a highly neurotoxic contaminant that enters the food web as a methylated compound, methylmercury (U.S. EPA, 2008d). The contaminant is concentrated in higher trophic levels, including fish eaten by humans. Experimental evidence has established that only inconsequential amounts of methylmercury can be produced in the absence of sulfate. Current evidence indicates that in watersheds where mercury is present, increased SO
Ozone causes discernible injury to a wide array of vegetation (U.S. EPA, 2006; Fox and Mickler, 1996). In terms of forest productivity and ecosystem diversity, ozone may be the pollutant with the greatest potential for regional-scale forest impacts (U.S. EPA, 2006). Studies have demonstrated repeatedly that ozone concentrations commonly observed in polluted areas can have substantial impacts on plant function (De Steiguer
Assessing the impact of ground-level ozone on forests in the eastern United States involves understanding the risks to sensitive tree species from ambient ozone concentrations and accounting for the prevalence of those species within the forest. As a way to quantify the risks to particular plants from ground-level
Urban ornamentals are an additional vegetation category likely to experience some degree of negative effects associated with exposure to ambient ozone levels. Because ozone causes visible foliar injury, the aesthetic value of ornamentals (such as petunia, geranium, and poinsettia) in urban landscapes would be reduced (U.S. EPA, 2007). Sensitive ornamental species would require more frequent replacement and/or increased maintenance (fertilizer or pesticide application) to maintain the desired appearance because of exposure to ambient ozone (U.S. EPA, 2007). In addition, many businesses rely on healthy-looking vegetation for their livelihoods (e.g., horticulturalists, landscapers, Christmas tree growers, farmers of leafy crops, etc.) and a variety of ornamental species have been listed as sensitive to ozone (Abt Associates, 1995).
In contrast to the additional benefits of the proposed rule discussed above, it is also possible that this rule will result in disbenefits in some areas of the region. Current levels of nitrogen deposition in these areas may provide passive fertilization for forest and terrestrial ecosystems where nutrients are a limiting factor and for some croplands. The effects of ozone and PM on radiative transfer in the atmosphere can also lead to effects of uncertain magnitude and direction on the penetration of ultraviolet light and climate. Ground level ozone makes up a small percentage of total atmospheric ozone (including the stratospheric layer) that attenuates penetration of ultraviolet-b (UVb) radiation to the ground. The EPA's past evaluation of the information indicates that potential disbenefits would be small, variable, and with too many uncertainties to attempt quantification of relatively small changes in average ozone levels over the course of a year (EPA, 2005a). The EPA's most recent provisional assessment of the currently available information indicates that potential but unquantifiable benefits may also arise from ozone-related attenuation of UVb radiation (EPA, 2005b). Sulfate and nitrate particles also scatter UVb, which can decrease exposure of horizontal surfaces to UVb, but increase exposure of vertical surfaces. In this case as well, both the magnitude and direction of the effect of reductions in sulfate and nitrate particles are too uncertain to quantify (EPA, 2004). Ozone is a greenhouse gas, and sulfates and nitrates can reduce the amount of solar radiation reaching the earth, but EPA believes that we are unable to quantify any net climate-related disbenefit or benefit associated with the combined ozone and PM reductions in this rule.
Additionally, from analyses of the benefits of the Acid Rain Program, EPA has seen that substantial health and environmental benefits that are likely to occur for Canadians because 80 percent of the Canadian population lives within 40 miles of the US-Canada border.
For the affected region, the projected annual private incremental costs of the proposed remedy option to the power industry are $3.7 billion in 2012 and $2.8 billion in 2014. For the State Budgets/Intrastate Trading remedy, projected annual private incremental costs are $4.2 billion in 2012 and $2.7 billion in 2014. Finally, for the direct control remedy, the projected annual private incremental costs are $4.3 billion in 2012 and $3.4 billion in 2014. These costs represent the private compliance cost to the electric generating industry of reducing NO
In estimating the net benefits of regulation, the appropriate cost measure is “social costs.” Social costs represent the welfare costs of the rule to society. These costs do not consider transfer payments (such as taxes) that are simply redistributions of wealth. The social costs of this rule for the proposed remedy option are estimated to be approximately $2.0 billion in 2014 assuming a 3 percent discount rate. These costs become $2.2 billion in 2014 assuming a 7 percent discount rate. For the State Budgets/Intrastate Trading remedy, social costs are estimated to be approximately $2.5 billion in 2014 assuming a 3 percent discount rate and $2.7 billion in 2014 assuming a 7 percent discount rate. Finally, for the direct control remedy, social costs are estimated to be approximately $2.7 billion in 2014 assuming a 3 percent discount rate and $2.9 billion in 2014 assuming a 7 percent discount rate.
Overall, the economic impacts of the Transport Rule proposal are modest in 2014, particularly in light of the large benefits ($122 to $294 billion annually at a 3 percent discount rate and $111 to $266 billion annually at a 7 percent discount rate) we expect as shown earlier in this preamble (
For this proposed rule, EPA analyzed the costs using the Integrated Planning Model (IPM). The IPM is a dynamic linear programming model that can be used to examine the economic impacts of air pollution control policies for SO
Documentation for IPM can be found in the docket for this rulemaking or at
Also note that as explained in section IV.A.3, the baseline used in this analysis assumes no CAIR. If EPA's base case analysis were to assume that reductions from CAIR would continue indefinitely, areas that are in attainment solely due to controls required by CAIR would again face nonattainment problems because the existing protection from upwind pollution would not be replaced. As explained in that section, EPA believes that this is the most appropriate baseline to use for purposes of determining whether an upwind state has an impact on a downwind monitoring site in violation of section 110(a)(2)(D).
EPA believes that achievement of energy efficiency improvements in homes, buildings, and industry is an important component of achieving emissions reductions from the power sector while minimizing associated compliance costs. By reducing electricity demand, energy efficiency avoids emissions of all pollutants associated with electricity generation, including emissions of NO
End-use energy efficiency (hereafter, “energy efficiency”) in the context of this proposed rule refers to activities that reduce the demand for electricity from EGUs in affected states. Energy
EPA recognizes that significant opportunity remains for energy efficiency improvements in businesses, homes, and industry. However, there are several informational and market barriers that limit investment in cost-effective energy efficient practices. Several federal programs authorized under the Act, including ENERGY STAR, are designed to address these barriers.
By reducing the demand for electricity energy efficiency reduces the need for investments in EGU emissions control technologies in order to meet the limits of an established state emissions budget and can often be implemented at a lower cost than traditional control technologies. Section III.E in this preamble further discusses the importance of electricity demand reductions as a component of EPA's broader air quality improvement strategy for the power sector.
EPA is available to assist states in quantifying the reduction in compliance costs of air regulatory programs, including the proposed rule, that can be realized through effective energy efficiency policies and programs.
By requiring reductions in the emissions of NO
Congress, EPA, and states have all recognized the value of incorporating energy efficiency into air regulatory programs. Several allowance-based programs—including the Acid Rain Program, EPA's NO
As discussed previously, EPA believes that increasing end-use energy efficiency can be an effective approach for reducing compliance costs of the proposed rule, as well as for reducing EGU emissions that are not the target of this rule including mercury, other toxics, and carbon dioxide. While EPA believes the proposed rule will make energy efficiency investments more competitive, the Agency is seeking comments on additional ways in which this rule could further encourage these investments.
As discussed previously, allowance-based programs (such as the proposed State Budgets/Limited Trading remedy and the alternative State Budgets/Intrastate Trading remedy) of EPA and states have supported energy efficiency projects through the use of auction revenues or the award of allowances. EPA considered these options in developing this proposal but, for the reasons described later, decided not to include either option in this proposal.
The emissions reductions requirements of the proposed rule are implemented through proposed FIPs. This means, among other things, that EPA allocates the emission allowances directly to individual sources. In contrast, when allowance based programs are implemented through SIPs, states may have significant flexibility to determine the methodology used to allocate or auction allowances in their budgets. Under the proposed FIPs, EPA would allocate allowances to sources in a manner consistent with the methodology used to determine each state's budget. EPA believes this approach is appropriate because of the link between the allowance allocation methodology and the significant contribution determinations. EPA requests comment on whether EPA has authority to and whether it would be appropriate for EPA to consider energy efficiency considerations in developing the allowance allocation methodology.
In addition, because the emission reduction requirements are implemented through FIPs, any auction of allowances would be conducted by EPA. As discussed previously in section V.D.5.b, pursuant to the Miscellaneous Receipts Act, any revenues from a federal auction of allowances must go to the U.S. Treasury. This precludes the use of proceeds from such an auction to reward energy efficiency projects.
In addition, and as also discussed previously in sections III.A and III.B.3, EPA anticipates further revisions to the PM
EPA is seeking comment on the discussion within this section and the use of these and other approaches for encouraging energy efficiency within the proposed rule.
Under section 3(f)(1) of Executive Order 12866 (58 FR 51735, October 4,
When estimating the PM
When characterizing uncertainty in the PM-mortality relationship, EPA has historically presented a sensitivity analysis applying alternate assumed thresholds in the PM concentration-response relationship. In its synthesis of the current state of the PM science, EPA's 2009 Integrated Science Assessment (ISA) for Particulate Matter concluded that a no-threshold log-linear model most adequately portrays the PM-mortality concentration-response relationship. In the RIA accompanying this rule, rather than segmenting out impacts predicted to be associated levels above and below a ‘bright line’ threshold, EPA includes a “lowest-measured-level (LML)” that illustrates the increasing uncertainty that characterizes impacts attributed to levels of PM
Table XII.A-1 shows the results of the cost and benefits analysis for the proposed and alternate remedies.
The information collection requirements in the proposed rule have been submitted for approval to OMB under the Paperwork Reduction Act, 44 U.S.C. 3501
The information collection activities in this proposed rule include monitoring and the maintenance of records. The information generated by these activities will be used by EPA to ensure that affected facilities comply with the emission limits and other requirements. Records and reports are necessary to enable EPA or states to identify affected facilities that may not be in compliance with the requirements. Based on reported information, EPA
The record-keeping and reporting burden to sources resulting from states choosing to participate in a regional cap-and-trade program is approximately $28 million annually. This estimate includes the annualized cost of installing and operating appropriate SO
An Agency may not conduct or sponsor, and a person is not required to respond to a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9. When this ICR is approved by OMB, the Agency will publish a technical amendment to 40 CFR part 9 in the
The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions.
For purposes of assessing the impacts of this proposed rule on small entities, small entity is defined as: (1) A small business as defined by the Small Business Administration's (SBA) regulations at 13 CFR 121.201. For the electric power generation industry, the small business size standard is an ultimate parent entity defined as having a total electric output of 4 million megawatt-hours (MW-hr) or less in the previous fiscal year.
(2) A small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and
(3) A small organization that is any not-for-profit enterprise which is independently owned and operated and is not dominant in its field.
After considering the economic impacts of this proposed rule on small entities, EPA is certifying that this action will not have a significant economic impact on a substantial number of small entities. This certification is based on the economic impact of this proposed action to all affected small entities across all industries affected. EPA has assessed the potential impact of this action on small entities and found that approximately 550 of the estimated 4,700 EGUs potentially affected by today's proposal are owned by the 81 potentially affected small entities identified by EPA's analysis. EPA estimates that 30 of the 81 identified small entities will have annualized costs greater than 1 percent of their revenues, and the other 51 are projected to incur costs less than 1 percent of revenues. While there are costs greater than 1 percent of revenues for a number of small entities, EPA is certifying No SISNOSE for several reasons. First, of the 30 entities projected to have costs greater than 1 percent of revenues, around 75 percent of them operate in cost of service regions and would generally be able to pass any increased costs along to rate-payers. This is one of the primary reasons given in the Regulatory Impact Assessment for the Final Clean Air Interstate Rule (EPA-452/R-05-002 March 2005) that supported EPA's “No SISNOSE” certification in the final CAIR FIP rule on April 28, 2006 (71 FR 25366). Furthermore, of the approximately 550 units identified by EPA as being potentially owned by small entities, approximately two-thirds of the units that have higher costs are not expected to make operational changes as a result of this rule (
For more information on the small entity impacts associated with the proposed rule, please refer to the Economic Impact and Small Business Analyses in the public docket. These analyses can be found in the Regulatory Impact Analysis for this proposed rule. Finally, although EPA believes that the proposed rule would not have a significant economic impact on a
We continue to be interested in the potential impacts of the proposed rule on small entities and welcome comments on issues related to such 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 later.
Consistent with section 205, EPA has identified and considered a reasonable number of regulatory alternatives. In today's action, EPA has included three remedy options that it considered when developing this proposed rule: (1) The proposed remedy of State Budgets/Limited Trading, (2) State Budgets/Intrastate Trading, and (3) Direct Controls. Moreover, section 205 allows EPA to adopt an alternative other than the least costly, most cost-effective or least burdensome alternative if the Administrator publishes with the final rule an explanation why that alternative was not adopted.
EPA examined the potential economic impacts on state and municipality-owned entities associated with this rulemaking based on assumptions of how the affected states will implement control measures to meet their emissions. Although EPA does not conclude that the requirements of the UMRA apply to the Transport Rule, these impacts have been calculated to provide additional understanding of the nature of potential impacts and additional information.
According to EPA's analysis, of the 84 government entities considered in this analysis and the 482 government entities in the Transport Rule region that are included in EPA's modeling, 27 may experience compliance costs in excess of 1 percent of revenues in 2014, based on our assumptions of how the affected states implement control measures to meet their emissions budgets as set forth in this rulemaking.
Government entities projected to experience compliance costs in excess of 1 percent of revenues have some potential for significant impact resulting from implementation of the Transport Rule. However, as noted previously, it is EPA's position that because these government entities can pass on their costs of compliance to rate-payers, they will not be significantly affected. Furthermore, the decision to include only units greater than 25 MW in size exempts 380 government entities that would otherwise be potentially affected by the Transport Rule. For more information on the impacts estimated for this analysis, please refer to the RIA for this proposed rule.
In addition, before EPA establishes any regulatory requirements that may significantly or uniquely affect small governments, including tribal governments, it must have developed under section 203 of the UMRA, a small government agency plan. The plan must provide for notifying potentially affected small governments, enabling officials of affected small governments to have meaningful and timely input in the development of EPA regulatory proposals with significant Federal intergovernmental mandates, and informing, educating, and advising small governments on compliance with the regulatory requirements. Consistent with the intergovernmental consultation provisions of section 204 of the UMRA, EPA has initiated consultations with governmental entities affected by this rule.
The EPA has determined that this rule contains a Federal mandate that may result in expenditures of $100 million or more in 1 year. EPA has determined that this rule contains no regulatory requirements that might significantly or uniquely affect small governments and that development of a small government plan under section 203 of the Act is not required. The costs of compliance will be borne predominately by sources in the private sector although a small number of sources owned by state and local governments may also be impacted. The requirements in this action do not distinguish EGUs based on ownership, either for those units that are included within the scope of the rule or for those units that are exempted by the generating capacity cut-off. Therefore, 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.
This proposed rule does not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. The proposed rule primarily affects private industry, and does not impose significant economic costs on state or local governments. Thus, Executive Order 13132 does not apply to the proposed rule.
In the spirit of Executive Order 13132, and consistent with EPA policy to promote communications between EPA and state and local governments, EPA will specifically solicit comment on the proposed rule 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 will not have substantial direct effects on tribal governments, on the relationship between the Federal government and Indian tribes, or on the distribution of power and responsibilities between the federal government and Indian tribes, as specified in Executive Order 13175. Thus, Executive Order 13175 does not apply to the final rule.
EPA interprets Executive Order 13045 (62 FR 19885, April 23, 1997) as applying to those regulatory actions that concern health or safety risks, such that the analysis required under section 5-501 of the Order has the potential to influence the regulation. This action is not subject to Executive Order 13045 because it does not involve decisions on environmental health or safety risks that may disproportionately affect children. The EPA believes that the emissions reductions from the strategies in this rule will further improve air quality and will further improve children's health.
Executive Order 13211 (66 FR 28355, May 22, 2001) provides that agencies shall prepare and submit to the Administrator of the Office of Regulatory Affairs, OMB, a Statement of Energy Effects for certain actions identified as “significant energy actions.” Section 4(b) of Executive Order 13211 defines “significant energy
Under the provisions of this proposed rule, EPA projects that approximately 1.2 GW of coal-fired generation may be removed from operation by 2014. In practice, however, the units projected to be uneconomic to maintain may be “mothballed,” retired, or kept in service to ensure transmission reliability in certain parts of the grid. These units are predominantly small and infrequently used generating units dispersed throughout the area affected by the rule. Assumptions of higher natural gas prices or electricity demand would create a greater incentive to keep these units operational. The EPA projects that the average retail electricity price could increase nationally by less than 2.5 percent in 2012 and 1.5 percent in 2014. This is generally less of an increase than often occurs with fluctuating fuel prices and other market factors. Related to this, delivered coal prices increase by about 7 percent in 2012 and 4 percent in 2014 as a result of higher demand for lower-sulfur coals. The EPA also projects that natural gas prices will increase by less than 1.7 percent in 2012 and 0.5 percent in 2014 and that natural gas use for electricity generation will increase by less than 73 million mcf by 2014. The price increase is also within the range we regularly see in delivered natural gas prices. Finally, the EPA projects coal production for use by the power sector, a large component of total coal production, will decrease by 3 million tons in 2012 and 9 million tons in 2014. The EPA does not believe that this rule will have any other impacts that exceed the significance criteria.
The EPA believes that a number of features of the proposed rulemaking serve to reduce its impact on energy supply. First, the trading programs in State Budgets/Limited Trading provide considerable flexibility to the power sector and enable industry to comply with the emission reduction requirements in the most cost-effective manner, thus minimizing overall costs and the ultimate impact on energy supply. Second, the more stringent budgets for SO
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 (
This proposed rule would require all sources to meet the applicable monitoring requirements of 40 CFR part 75. Part 75 already incorporates a number of voluntary consensus standards.
Consistent with the Agency's Performance Based Measurement System (PBMS), Part 75 sets forth performance criteria that allow the use of alternative methods to the ones set forth in Part 75. The PBMS approach is intended to be more flexible and cost-effective for the regulated community; it is also intended to encourage innovation in analytical technology and improved data quality. At this time, EPA is not recommending any revisions to Part 75; however, EPA periodically revises the test procedures set forth in Part 75.
When EPA revises the test procedures set forth in Part 75 in the future, EPA will address the use of any new voluntary consensus standards that are equivalent. Currently, even if a test procedure is not set forth in Part 75, EPA is not precluding the use of any method, whether it constitutes a voluntary consensus standard or not, as long as it meets the performance criteria specified; however, any alternative methods must be approved through the petition process under 40 CFR 75.66 before they are used.
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, low-income, and Tribal populations in the United States.
In the rulemaking process, EPA considers whether there are positive or negative impacts of the action that appear to affect low-income, minority, or Tribal communities disproportionately, and, regardless of whether a disproportionate effect exists, whether there is a chance for these communities to meaningfully participate in the rulemaking process. EPA expects that this rule, “Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone,” will provide significant health and environmental benefits to, among others, people with asthma, people with heart disease, and people living in ozone or fine particle (PM
This rule is replacing an earlier rule (the 2005 Clean Air Interstate Rule (CAIR)) that was first vacated and then remanded to EPA by the U.S. Court of Appeals for the District of Columbia Circuit. CAIR was vacated by the U.S. Court of Appeals for the District of Columbia Circuit in July 2008 in a case known as
It is important to note that CAA section 110(a)(2)(d), which addresses transport of criteria pollutants between states and is the authority for this rule, is only one of many provisions of the CAA that provide EPA, states, and local governments with authorities to reduce exposure to ozone and PM
This proposed rule is one of a group of regulatory actions that EPA will take over the next several years to respond to statutory and judicial mandates that will reduce exposure to ozone and PM
Beyond this action and any additional efforts undertaken in response to comment, other rules that will drive the creation of a clean, efficient and completely modern power sector include: CAA section 112(d) standards (one of which is often referred to as a Maximum Achievable Control Technology (MACT) standard) to reduce emissions of air toxics, including mercury, and particles from coal- and oil-fired power plants; new National Ambient Air Quality Standards (NAAQS) for ozone, PM
Together, these rules and actions will have substantial and long-term effects on both the U.S. power industry and on communities currently breathing dirty air. Therefore, we anticipate significant interest in many, if not most, of these actions from environmental justice communities, among many others. EPA intends to provide multiple opportunities for comment on these actions, including during the comment process for this rule, and encourages environmental justice communities to review and comment on them.
There are several considerations to take into account when assessing the effects of this proposed rule on minority, low-income, and tribal populations. These include: Amount of emissions reductions and where they take place (including any potential for areas of increased emissions); the changes in ambient concentrations across the affected area; and the health benefits expected from the rules.
Ozone and PM
The proposed remedy option for this rule would use a limited emissions trading mechanism among power plants to achieve significant emissions reductions in states covered by the rule. EPA recognizes that many environmental justice communities have voiced concerns about emissions trading and any resulting potential for any emissions increases in any location.
This proposed rule uses EPA's authority in CAA § 110(a)(2)(d) to require states to eliminate emissions from power plants in their state that contribute significantly to downwind PM
Any emissions above the state's allocated level must be offset by emissions reductions from another state in the region below that state's budget or by using extra “banked” allowances from earlier years. All sources must hold enough allowances to cover their emissions; therefore, if they emit more than their allocation they must buy allowances from another source that emitted less than its allocation. PM
It is important to recognize that the section of the Clean Air Act providing authority for this rule, 110(a)(2)(D), unlike some other provisions, does not dictate levels of control for particular facilities. None of EPA's alternatives within this proposal can ensure there will be no emission increases at any facility. Under the direct control alternative, the emissions rate for each facility is reduced but each facility could emit more by increasing their power output in order to meet electricity reliability or other goals. Under the intrastate trading option, state emissions must stay constant but individual facilities within each state could increase their emissions as long as another facility in the state had decreased theirs. By strictly setting state budgets to eliminate significant contributions to non-attainment and maintenance areas that EPA has identified in this action, by limiting the amount of interstate trading possible and by requiring any emissions above the level of the allocations to be offset by emission decreases elsewhere in the region, the proposed remedy options reduce ambient concentrations where they are most needed.
EPA's emissions modeling data indicate that nationwide SO
EPA's modeling does project that some states not covered by one or more aspects of the program may experience increases of SO
With the exception noted above, EPA is not proposing for the SO
EPA's emissions modeling data indicates that nationwide ozone season NO
EPA anticipates that this proposed action will significantly reduce, but not eliminate, the number of nonattainment and maintenance areas for the 1997 ozone and PM
As a result of these SO
The modeling suggests also that there may be some small increases in PM
EPA's air quality modeling also indicates that concentrations of ozone will decline in much of the eastern U.S. These reductions are largest along much of the Gulf Coast and in Florida and in a region encompassing western Wisconsin, Iowa, Kansas, Missouri, Arkansas, and northeastern Oklahoma. These areas with the largest reductions are roughly the area immediately outside the boundaries of the NO
As is common when modeling many NO
We estimate that in 2014 the PM-related annual benefits of the proposed remedy option include approximately 14,000 to 36,000 fewer premature mortalities, 9,200 fewer cases of chronic bronchitis, 22,000 fewer non-fatal heart attacks, 11,000 fewer hospitalizations (for respiratory and cardiovascular disease combined), 10 million fewer days of restricted activity due to respiratory illness and approximately 1.8 million fewer lost work days. We also estimate substantial health improvements for children in the form of fewer cases of upper and lower respiratory illness, acute bronchitis, and asthma attacks.
Ozone health-related benefits are expected to occur during the summer ozone season (usually ranging from May to September in the eastern U.S.). Based upon modeling for 2014, annual ozone related health benefits are expected to include between 50 and 230 fewer premature mortalities, 690 fewer hospital admissions for respiratory illnesses, 230 fewer emergency room admissions for asthma, 300,000 fewer days with restricted activity levels, and 110,000 fewer days where children are absent from school due to illnesses. When adding the PM and ozone-related mortalities together, we find that the proposed remedy option for this rule will yield between 14,000 and 36,000 fewer premature mortalities. EPA has also estimated the benefits of the alternate remedies in this proposal using a benefit-per-ton estimation approach and found they would provide similar benefits.
It should be noted that, as discussed in the RIA for this action, there are other benefits to the emissions reductions discussed here, such as improved visibility and, indirectly, reduced mercury deposition. Additional benefits of reducing emissions of SO
As EPA began considering approaches to address the court remand of the 2005 Clean Air Interstate Rule, the agency also began gathering input from a larger range of stakeholders. In the spring of 2009, EPA held a series of listening
Upon proposal of this action, the Agency will begin an outreach effort with environmental justice communities, the public, the regulated community, state air regulators, and others to (1) describe the Transport Rule proposal, (2) provide information on the 2011 CAA Section 112 (d) and other upcoming EPA rulemakings affecting the power sector, and (3) listen to comments from stakeholders. The intent will be to inform all stakeholders of the industry's obligations and opportunities for the industry to use investments in SO
During the comment period for this proposed rule, EPA intends to reach out specifically to environmental justice communities and organizations to notify them of the opportunity to provide comments on this rule and to solicit their comments on both this rule and the upcoming actions described above and in section III.E. EPA will hold public hearings on this rule; see the information at the very beginning of this preamble for locations, times and dates. Comments can also be submitted in writing or electronically by following the instructions at the beginning of this preamble.
EPA believes that the vast majority of communities and individuals in areas covered by this rule, including numerous low-income, minority, and Tribal communities in both rural areas and inner cities in the East, will see significant improvements in air quality and resulting improvements in health. EPA also recognizes that there is the potential for a number of communities or individuals outside the region covered by this rule to experience slightly worse air quality as an indirect result of emissions reductions required under this proposal. EPA requests comment on the impacts of this proposed action on low income, minority, and Tribal communities. EPA will further analyze environmental justice issues related to the impacts of the rule on those communities based both on additional data that may be developed and on comments on those issues prior to final action on this rule.
Administrative practice and procedure, Air pollution control, Intergovernmental relations, Nitrogen oxides, Ozone, Particulate matter, Regional haze, Reporting and recordkeeping requirements, Sulfur dioxide.
Administrative practice and procedure, Air pollution control, Intergovernmental relations, Nitrogen oxides, Ozone, Particulate matter, Regional haze, Reporting and recordkeeping requirements, Sulfur dioxide.
Acid rain, Administrative practice and procedure, Air pollution control, Electric utilities, Intergovernmental relations, Nitrogen oxides, Reporting and recordkeeping requirements, Sulfur dioxide.
Acid rain, Administrative practice and procedure, Air pollution control, Electric utilities, Intergovernmental relations, Nitrogen oxides, Reporting and recordkeeping requirements, Sulfur dioxide.
Administrative practice and procedure, Air pollution control, Electric utilities, Nitrogen oxides, Reporting and recordkeeping requirements, Sulfur dioxide.
For the reasons set forth in the preamble, parts 51, 52, 72, 78, and 97 of chapter I of title 40 of the Code of Federal Regulations are proposed to be amended as follows:
1. The authority citation for Part 51 continues to read as follows:
23 U.S.C. 101; 42 U.S.C. 7401-7671q.
2. Section 51.121 is amended by revising paragraph (r)(2) by removing the words “§ 51.123(bb)” and adding, in their place, the words “§ 51.123(bb) with regard to an ozone season that occurs before January 1, 2012”.
3. Section 51.123 is amended by adding a new paragraph (ff) to read as follows:
(ff) Notwithstanding any provisions of paragraphs (a) through (ee) of this section, subparts AA through II and AAA through III of part 96 of this chapter, subparts AA through II and AAAA through IIII of part 97 of this chapter, and any State's SIP to the contrary:
(1) With regard to any control period that begins after December 31, 2011, the Administrator:
(i) Rescinds the determination in paragraph (a) of this section that the States identified in paragraph (c) of this section must submit a SIP revision with respect to the fine particles (PM
(ii) Will not carry out any of the functions set forth for the Administrator in subparts AA through II and AAAA through IIII of part 96 of this chapter, subparts AA through II and AAAA through IIII of part 97 of this chapter, or in any emissions trading program provisions in a State's SIP approved under this section; and
(2) The Administrator will not deduct for excess emissions any CAIR NO
4. Section 51.124 is amended by adding a new paragraph (s) to read as follows:
(s) Notwithstanding any provisions of paragraphs (a) through (r) of this section, subparts AAA through III of part 96 of this chapter, subparts AAA through III of part 97 of this chapter, and any State's SIP to the contrary:
(1) With regard to any control period that begins after December 31, 2011, the Administrator:
(i) Rescinds the determination in paragraph (a) of this section that the States identified in paragraph (c) of this section must submit a SIP revision with respect to the fine particles (PM
(ii) Will not carry out any of the functions set forth for the Administrator in subparts AAA through III of part 96 of this chapter, subparts AAA through III of part 97 of this chapter, or in any emissions trading program in a State's SIP approved under this section; and
(2) The Administrator will not deduct for excess emissions any CAIR SO
5. Section 51.125 is removed and reserved.
6. The authority citation for Part 52 continues to read as follows:
42 U.S.C. 7401,
7. Section 52.35 is amended by adding a new paragraph (f) to read as follows:
(f) Notwithstanding any provisions of paragraphs (a) through (d) of this section, subparts AA through II and AAAA through IIII of part 97 of this chapter, and any State's SIP to the contrary:
(1) With regard to any control period that begins after December 31, 2011,
(i) The provisions in paragraphs (a) through (d) of this section relating to NO
(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AA through II and AAAA through IIII of part 97 of this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR NO
8. Section 52.36 is amended by adding a new paragraph (e) to read as follows:
(e) Notwithstanding any provisions of paragraphs (a) through (c) of this section, subparts AAA through III of part 97 of this chapter and any State's SIP to the contrary:
(1) With regard to any control period that begins after December 31, 2011,
(i) The provisions of paragraphs (a) through (e) of this section relating to SO
(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AAA through III of part 97 of this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR SO
9. Subpart A is amended by adding §§ 52.37 and 52.38 to read as follows:
(a)(1) The TR NO
(2) The provisions of subpart AAAAA of part 97 of this chapter, regarding the TR NO
(3) Following promulgation of an approval by the Administrator of a State's SIP as correcting the SIP's deficiency that is the basis for this Federal Implementation Plan, the provisions of paragraph (a)(2) of this section will no longer apply to the sources in the State, unless the Administrator's approval of the SIP is partial or conditional.
(4) Notwithstanding the provisions of paragraph (a)(3) of this section, if, at the time of such approval of the State's SIP, the Administrator has already allocated any TR NO
(b)(1) The TR NO
(2) The provisions of subpart BBBBB of part 97 of this chapter, regarding the TR NO
(3) Following promulgation of an approval by the Administrator of a State's SIP as correcting the SIP's deficiency that is the basis for this Federal Implementation Plan, the provisions of paragraph (b)(2) of this section will no longer apply to sources in the State, unless the Administrator's approval of the SIP is partial or conditional.
(4) Notwithstanding the provisions of paragraph (b)(3) of this section, if, at the time of such approval of the State's SIP, the Administrator has already allocated any TR NO
(a) The TR SO
(b) The provisions of subpart CCCCC of part 97 of this chapter, regarding the TR SO
(c) The provisions of subpart DDDDD of part 97 of this chapter, regarding the TR SO
(d) Following promulgation of an approval by the Administrator of a State's SIP as correcting the SIP's deficiency that is the basis for this Federal Implementation Plan, the provisions of paragraph (b) and (c) of this section, as applicable, will no longer apply to sources in the State, unless the Administrator's approval of the SIP is partial or conditional.
(e) Notwithstanding the provisions of paragraph (d) of this section, if, at the time of such approval of the State's SIP, the Administrator has already allocated any TR SO
10. Section 52.440 is amended by adding a new paragraph (c) to read as follows:
(c) Notwithstanding any provisions of paragraphs (a) and (b) of this section and subparts AA through II and AAAA through IIII of part 97 of this chapter to the contrary:
(1) With regard to any control period that begins after December 31, 2011,
(i) The provisions in paragraphs (a) and (b) of this section relating to NO
(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AA through II and AAAA through IIII of part 97 of this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR NO
11. Section 52.441 is amended by designating the introductory text as paragraph (a) and adding a new paragraph (b) to read as follows:
(b) Notwithstanding any provisions of paragraph (a) of this section and subparts AAA through III of part 97 of this chapter and any State's SIP to the contrary:
(1) With regard to any control period that begins after December 31, 2011,
(i) The provisions of paragraph (a) of this section relating to SO
(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AAA through III of part 97 of this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR SO
12. Section 52.484 is amended by adding a new paragraph (c) to read as follows:
(c) Notwithstanding any provisions of paragraphs (a) and (b) of this section and subparts AA through II and AAAA through IIII of part 97 of this chapter to the contrary:
(1) With regard to any control period that begins after December 31, 2011,
(i) The provisions in paragraphs (a) and (b) of this section relating to NO
(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AA through II and AAAA through IIII of part 97 of this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR NO
13. Section 52.485 is amended by designating the introductory text as paragraph (a) and adding a new paragraph (b) to read as follows:
(b) Notwithstanding any provisions of paragraph (a) of this section and subparts AAA through III of part 97 of this chapter and any State's SIP to the contrary:
(1) With regard to any control period that begins after December 31, 2011,
(i) The provisions of paragraph (a) of this section relating to SO
(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AAA through III of part 97 of this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR SO
14. Section 52.789 is amended by adding a new paragraph (c) to read as follows:
(c) Notwithstanding any provisions of paragraphs (a) and (b) of this section and subparts AA through II and AAAA through IIII of part 97 of this chapter to the contrary:
(1) With regard to any control period that begins after December 31, 2011,
(i) The provisions in paragraphs (a) and (b) of this section relating to NO
(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AA through II and AAAA through IIII of part 97 of this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR NO
15. Section 52.790 is amended by designating the introductory text as
(b) Notwithstanding any provisions of paragraph (a) of this section and subparts AAA through III of part 97 of this chapter and any State's SIP to the contrary:
(1) With regard to any control period that begins after December 31, 2011,
(i) The provisions of paragraph (a) of this section relating to SO
(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AAA through III of part 97 of this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR SO
16. Section 52.984 is amended by adding a new paragraph (c) to read as follows:
(c) Notwithstanding any provisions of paragraphs (a) and (b) of this section and subparts AA through II and AAAA through IIII of part 97 of this chapter to the contrary:
(1) With regard to any control period that begins after December 31, 2011,
(i) The provisions in paragraphs (a) and (b) of this section relating to NO
(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AA through II and AAAA through IIII of part 97 of this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR NO
17. Section 52.1186 is amended by adding a new paragraph (c) to read as follows:
(c) Notwithstanding any provisions of paragraphs (a) and (b) of this section and subparts AA through II and AAAA through IIII of part 97 of this chapter to the contrary:
(1) With regard to any control period that begins after December 31, 2011,
(i) The provisions in paragraphs (a) and (b) of this section relating to NO
(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AA through II and AAAA through IIII of part 97 of this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR NO
18. Section 52.1187 is amended by designating the introductory text as paragraph (a) and adding a new paragraph (b) to read as follows:
(b) Notwithstanding any provisions of paragraph (a) of this section and subparts AAA through III of part 97 of this chapter and any State's SIP to the contrary:
(1) With regard to any control period that begins after December 31, 2011,
(i) The provisions of paragraph (a) of this section relating to SO
(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AAA through III of part 97 of this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR SO
19. Section 52.1584 is amended by adding a new paragraph (c) to read as follows:
(c) Notwithstanding any provisions of paragraphs (a) and (b) of this section and subparts AA through II and AAAA through IIII of part 97 of this chapter to the contrary:
(1) With regard to any control period that begins after December 31, 2011,
(i) The provisions in paragraphs (a) and (b) of this section relating to NO
(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AA through II and AAAA through IIII of part 97 of this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR NO
20. Section 52.1185 is amended by designating the introductory text as paragraph (a) and adding a new paragraph (b) to read as follows:
(b) Notwithstanding any provisions of paragraph (a) of this section and subparts AAA through III of part 97 of this chapter and any State's SIP to the contrary:
(1) With regard to any control period that begins after December 31, 2011,
(i) The provisions of paragraph (a) of this section relating to SO
(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AAA through III of part 97 of this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR SO
21. Section 52.2240 is amended by adding a new paragraph (c) to read as follows:
(c) Notwithstanding any provisions of paragraphs (a) and (b) of this section and subparts AA through II and AAAA through IIII of part 97 of this chapter to the contrary:
(1) With regard to any control period that begins after December 31, 2011,
(i) The provisions in paragraphs (a) and (b) of this section relating to NO
(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AA through II and AAAA through IIII of part 97 of this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR NO
22. Section 52.2241 is amended by designating the introductory text as paragraph (a) and adding a new paragraph (b) to read as follows:
(b) Notwithstanding any provisions of paragraph (a) of this section and subparts AAA through III of part 97 of this chapter and any State's SIP to the contrary:
(1) With regard to any control period that begins after December 31, 2011,
(i) The provisions of paragraph (a) of this section relating to SO
(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AAA through III of part 97 of this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR SO
23. Section 52.2283 is amended by adding a new paragraph (c) to read as follows:
(c) Notwithstanding any provisions of paragraphs (a) and (b) of this section and subparts AA through II of part 97 of this chapter to the contrary:
(1) With regard to any control period that begins after December 31, 2011,
(i) The provisions in paragraph (a) of this section relating to NO
(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AA through II of part 97 of this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR NO
24. Section 52.2284 is amended by designating the introductory text as paragraph (a) and adding a new paragraph (b) to read as follows:
(b) Notwithstanding any provisions of paragraph (a) of this section and subparts AAA through III of part 97 of this chapter and any State's SIP to the contrary:
(1) With regard to any control period that begins after December 31, 2011,
(i) The provisions of paragraph (a) of this section relating to SO
(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AAA through III of part 97 of this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR SO
25. Section 52.8587 is amended by adding a new paragraph (c) to read as follows:
(c) Notwithstanding any provisions of paragraphs (a) and (b) of this section and subparts AA through II and AAAA through IIII of part 97 of this chapter to the contrary:
(1) With regard to any control period that begins after December 31, 2011,
(i) The provisions in paragraphs (a) and (b) of this section relating to NO
(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AA through II and AAAA through IIII of part 97 of this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR NO
26. Section 52.8588 is amended by designating the introductory text as paragraph (a) and adding a new paragraph (b) to read as follows:
(b) Notwithstanding any provisions of paragraph (a) of this section and subparts AAA through III of part 97 of this chapter and any State's SIP to the contrary:
(1) With regard to any control period that begins after December 31, 2011,
(i) The provisions of paragraph (a) of this section relating to SO
(ii) The Administrator will not carry out any of the functions set forth for the Administrator in subparts AAA through III of part 97 of this chapter; and
(2) The Administrator will not deduct for excess emissions any CAIR SO
27. The authority citation for Part 72 is revised to read as follows:
42 U.S.C. 7401, 7403, 7410, 7411, 7426, 7601,
28. Section 72.2 is amended by removing the definition of “interested person”.
29. The authority citation for Part 78 continues to read as follows:
42 U.S.C. 7401, 7403, 7410, 7411, 7426, 7601,
30. Section 78.1 is amended by adding paragraphs (b)(13) through (b)(16) to read as follows:
(b) * * *
(13) Under subpart AAAAA of part 97 of this chapter,
(i) The decision on allocation of TR NO
(ii) The decision on the transfer of TR NO
(iii) The decision on the deduction of TR NO
(iv) The correction of an error in an Allowance Management System account under § 97.427 of this chapter.
(iv) The adjustment of information in a submission and the decision on the deduction and transfer of TR NO
(vi) The finalization of control period emissions data, including retroactive adjustment based on audit.
(vii) The approval or disapproval of a petition under § 97.435 of this chapter.
(viii) The approval or disapproval of a TR opt-in application, the approval or disapproval of a request to withdraw, the decision on allocation of TR NO
(14) Under subpart BBBBB of part 97 of this chapter, (i) The decision on allocation of TR NO
(ii) The decision on the transfer of TR NO
(iii) The decision on the deduction of TR NO
(iv) The correction of an error in an Allowance Management System account under § 97.527 of this chapter.
(iv) The adjustment of information in a submission and the decision on the deduction and transfer of TR NO
(vi) The finalization of control period emissions data, including retroactive adjustment based on audit.
(vii) The approval or disapproval of a petition under § 97.535 of this chapter.
(viii) The approval or disapproval of a TR opt-in application, the approval or disapproval of a request to withdraw, the decision on allocation of TR NO
(15) Under subpart CCCCC of part 97 of this chapter,
(i) The decision on allocation of TR SO
(ii) The decision on the transfer of TR SO
(iii) The decision on the deduction of TR SO
(iv) The correction of an error in an Allowance Management System account under § 97.627 of this chapter.
(iv) The adjustment of information in a submission and the decision on the deduction and transfer of TR SO
(vi) The finalization of control period emissions data, including retroactive adjustment based on audit.
(vii) The approval or disapproval of a petition under § 97.635 of this chapter.
(viii) The approval or disapproval of a TR opt-in application, the approval or disapproval of a request to withdraw, the decision on allocation of TR SO
(16) Under subpart DDDDD of part 97 of this chapter,
(i) The decision on allocation of TR SO
(ii) The decision on the transfer of TR SO
(iii) The decision on the deduction of TR SO
(iv) The correction of an error in an Allowance Management System account under § 97.727 of this chapter.
(iv) The adjustment of information in a submission and the decision on the deduction and transfer of TR SO
(vi) The finalization of control period emissions data, including retroactive adjustment based on audit.
(vii) The approval or disapproval of a petition under § 97.735 of this chapter.
(viii) The approval or disapproval of a TR opt-in application, the approval or disapproval of a request to withdraw, the decision on allocation of TR SO
31. Section 78.2 is revised to read as follows:
(a)
(2)
(b)
(c)
(2) Where a document is served by first class mail or commercial delivery service, but not by overnight or same-day delivery, 5 days shall be added to the time prescribed or allowed under this part for the filing of a responsive document or for otherwise responding.
32. Section 78.3 is amended by:
a. In paragraphs (a)(1)(iii), (a)(3)(ii), (a)(4)(ii), (a)(5)(ii), (a)(6)(ii), (a)(7)(ii), (a)(8)(ii), and (a)(9)(ii), adding, after the word “person”, the words “with regard to the decision”.
b. Adding paragraph (a)(10);
c. In paragraph (b)(3)(i), removing the words “paragraph (a)(1) and (2)” and adding, in their place, the words “paragraph (a)(1), (2), and (10)”; and
d. Adding paragraph (d)(11) to read as follows:
(a) * * *
(10) The following persons may petition for administrative review of a decision of the Administrator that is made under subparts AAAAA, BBBBB, CCCCC, and DDDDD of part 97 of this chapter:
(i) The designated representative for a unit or source, or the authorized account representative for any Allowance Management System account, covered by the decision; or
(ii) Any interested person with regard to the decision.
(d) * * *
(11) Any provision or requirement of subparts AAAAA, BBBBB, CCCCC, or DDDDD of part 97 of this chapter, including the standard requirements under § 97.406, § 97.506, § 97.606, or § 97.706 of this chapter and any emission monitoring or reporting requirements.
33. Section 78.4 is amended by:
a. Revising paragraph (a) by:
i. Removing the first, second, third, fourth, fifth, and last sentences;
ii. In the sixth and seventh sentences, removing the words “interest in” and adding, in their place, the words “ownership interest with respect to”; and
iii. Redesignating the paragraph as paragraph (a)(1)(iii); and
b. Adding paragraphs (a)(1) introductory text, (a)(1)(i), (a)(1)(ii) and (a)(2) to read as follows:
(a)(1) All original filings made under this part shall be signed by the person making the filing or by an attorney or authorized representative, in accordance with the following requirements:
(i) Any filings on behalf of owners and operators of a affected unit or affected source, TR NO
(ii) Any filings on behalf of owners and operators of a NO
(2) The name, address, e-mail address (if any), telephone number, and facsimile number (if any) of the person making the filing shall be provided with the filing.
34. The authority citation for part 97 continues to read as follows:
42 U.S.C. 7401, 7403, 7410, 7426, 7601, and 7651,
35. Part 97 is amended by adding subpart AAAAA to read as follows:
This subpart sets forth the general, designated representative, allowance, and monitoring provisions for the Transport Rule (TR) NO
The terms used in this subpart shall have the meanings set forth in this section as follows:
(1) Any organic material grown for the purpose of being converted to energy;
(2) Any organic byproduct of agriculture that can be converted into energy; or
(3) Any material that can be converted into energy and is nonmerchantable for other purposes, that is segregated from other material that is nonmerchantable for other purposes, and that is;
(i) A forest-related organic resource, including mill residues, precommercial thinnings, slash, brush, or byproduct from conversion of trees to merchantable material; or
(ii) A wood material, including pallets, crates, dunnage, manufacturing and construction materials (other than pressure-treated, chemically-treated, or painted wood products), and landscape or right-of-way tree trimmings.
(1) For a corporation, a president, secretary, treasurer, or vice-president or the corporation in charge of a principal business function or any other person who performs similar policy or decision-making functions for the corporation;
(2) For a partnership or sole proprietorship, a general partner or the proprietor respectively; or
(3) For a local government entity or State, federal, or other public agency, a principal executive officer or ranking elected official.
(1) Operating as part of a cogeneration system; and
(2) Producing during the later of 1990 or the 12-month period starting on the date that the unit first produces electricity and during each calendar year after the later of 1990 or the calendar year in which the unit first produces electricity—
(i) For a topping-cycle unit,
(A) Useful thermal energy not less than 5 percent of total energy output; and
(B) Useful power that, when added to one-half of useful thermal energy produced, is not less then 42.5 percent of total energy input, if useful thermal energy produced is 15 percent or more of total energy output, or not less than 45 percent of total energy input, if useful thermal energy produced is less than 15 percent of total energy output.
(ii) For a bottoming-cycle unit, useful power not less than 45 percent of total energy input;
(3) Provided that the total energy input under paragraphs (2)(i)(B) and (2)(ii) of this definition shall equal the unit's total energy input from all fuel, except biomass if the unit is a boiler; and
(4) Provided that, if a topping-cycle unit is operated as part of a cogeneration system during a calendar year and the cogeneration system meets on a system-wide basis the requirement in paragraph (2)(i)(B) of this definition, the topping-cycle unit shall be deemed to meet such requirement during that calendar year.
(1) If the device is simple cycle, a compressor, a combustor, and a turbine and in which the flue gas resulting from the combustion of fuel in the combustor passes through the turbine, rotating the turbine; and
(2) If the device is combined cycle, the equipment described in paragraph (1) of this definition and any associated duct burner, heat recovery steam generator, and steam turbine.
(1) To have begun to produce steam, gas, or other heated medium used to generate electricity for sale or use, including test generation, except as provided in § 97.405.
(i) For a unit that is a TR NO
(ii) For a unit that is a TR NO
(2) Notwithstanding paragraph (1) of this definition and except as provided in § 97.405, for a unit that is not a TR NO
(i) For a unit with a date for commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that subsequently undergoes a physical change (other than replacement of the unit by a unit at the same source), such date shall remain the date of commencement of commercial operation of the unit, which shall continue to be treated as the same unit.
(ii) For a unit with a date for commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that is subsequently replaced by a unit at the same source, such date shall remain the replaced unit's date of commencement of commercial operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of commercial operation as defined in paragraph (1) or (2) of this definition as appropriate.
(1) To have begun any mechanical, chemical, or electronic process, including start-up of the unit's combustion chamber.
(2) For a unit that undergoes a physical change (other than replacement of the unit by a unit at the same source) after the date the unit commences operation as defined in paragraph (1) of this definition, such date shall remain the date of commencement of operation of the unit, which shall continue to be treated as the same unit.
(3) For a unit that is replaced by a unit at the same source after the date the unit commences operation as defined in paragraph (1) of this definition, such date shall remain the replaced unit's date of commencement of operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of operation as defined in paragraph (1), (2), or (3) of this definition as appropriate.
(1) A flow monitoring system, consisting of a stack flow rate monitor and an automated data acquisition and handling system and providing a permanent, continuous record of stack gas volumetric flow rate, in standard cubic feet per hour (scfh);
(2) A NO
(3) A NO
(4) A moisture monitoring system, as defined in § 75.11(b)(2) of this chapter and providing a permanent, continuous record of the stack gas moisture content, in percent H
(5) A CO
(6) An O
(1) Natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material; or
(2) For purposes of applying §§ 97.404(b)(2)(i)(B), 97.404(b)(2)(ii)(B), and 97.404(b)(2)(iii), natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat.
(1) For the life of the unit;
(2) For a cumulative term of no less than 30 years, including contracts that permit an election for early termination; or
(3) For a period no less than 25 years or 70 percent of the economic useful life of the unit determined as of the time the unit is built, with option rights to purchase or release some portion of the nameplate capacity and associated energy generated by the unit at the end of the period.
(1) Any holder of any portion of the legal or equitable title in a TR NO
(2) Any holder of a leasehold interest in a TR NO
(3) Any purchaser of power from a TR NO
(4) Provided that, for purposes of applying the TR NO
(1) With regard to a State and control period for which the State assurance level is exceeded as described in § 97.406(c)(2)(iii)(A) and not as described in § 97.406(c)(2)(iii)(B), the owner's share of the State NO
(2) With regard to a State and control period for which the State assurance level is exceeded as described in § 97.406(c)(2)(iii)(B), the owner's share of the State NO
(1) With regard to a total amount of NO
(2) With regard to a State NO
(3) With regard to a State NO
(4) Provided that, in the case of a unit with more than one owner, the amount of tonnage of NO
(5) Provided that, where two or more units emit through a common stack that is the monitoring location from which NO
(i) The amount (rounded to the nearest ton) of NO
(ii) An amount determined in accordance with a methodology that the Administrator determines is consistent with the purposes of this definition and whose adverse effect (if any) the Administrator determines will be
(iii) An amount approved by the Administrator in response to a petition for an alternative requirement submitted in accordance with § 97.435; and
(6) Provided that, in the case of a unit that operates during, but is allocated no TR NO
(i) The unit's allowable NO
(ii) For a unit listed in appendix A to this subpart, the sum of the unit's NO
(1) For a topping-cycle unit, the use of reject heat from electricity production in a useful thermal energy application or process; or
(2) For a bottoming-cycle unit, the use of reject heat from useful thermal energy application or process in electricity production.
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or transmission and delivery;
(4) Provided that compliance with any “submission” or “service” deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt.
(1) Have been recorded by the Administrator in the account or transferred into the account by a correctly submitted, but not yet recorded, TR NO
(2) Have not been transferred out of the account by a correctly submitted, but not yet recorded, TR NO
(1) Made available to an industrial or commercial process (not a power production process), excluding any heat contained in condensate return or makeup water;
(2) Used in a heating application (
(3) Used in a space cooling application (
Measurements, abbreviations, and acronyms used in this subpart are defined as follows:
(a) Except as provided in paragraph (b) of this section:
(1) The following units in a State shall be TR NO
(2) If a stationary boiler or stationary combustion turbine that, under paragraph (a)(1) of this section, is not a TR NO
(b) Any unit in a State that otherwise is a TR NO
(1)(i) Any unit:
(A) Qualifying as a cogeneration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a cogeneration unit; and
(B) Not serving at any time, since the later of November 15, 1990 or the start-up of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe supplying in any calendar year more than one-third of the unit's potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.
(ii) If a unit qualifies as a cogeneration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and meets the requirements of paragraphs (b)(1)(i) of this section for at least one calendar year, but subsequently no longer meets such qualification and requirements, the unit shall become a TR NO
(2)(i) Any unit commencing operation before January 1, 1985:
(A) Qualifying as a solid waste incineration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a solid waste incineration unit; and
(B) With an average annual fuel consumption of fossil fuel for 1985-1987 less than 20 percent (on a Btu basis) and an average annual fuel consumption of fossil fuel for any 3 consecutive calendar years after 1990 less than 20 percent (on a Btu basis).
(ii) Any unit commencing operation on or after January 1, 1985:
(A) Qualifying as a solid waste incineration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a solid waste incineration unit; and
(B) With an average annual fuel consumption of fossil fuel for the first 3 calendar years of operation less than 20 percent (on a Btu basis) and an average annual fuel consumption of fossil fuel for any 3 consecutive calendar years after 1990 less than 20 percent (on a Btu basis).
(iii) If a unit qualifies as a solid waste incineration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and meets the requirements of paragraph (b)(2)(i) or (ii) of this section for at least 3 consecutive calendar years, but subsequently no longer meets such qualification and requirements, the unit shall become a TR NO
(c) A certifying official of an owner or operator of any unit or other equipment may submit a petition (including any supporting documents) to the Administrator at any time for a determination concerning the applicability, under paragraphs (a) and (b) of this section, of the TR NO
(1)
(2)
(a)(1) Any TR NO
(2) The exemption under paragraph (a)(1) of this section shall become effective the day on which the TR NO
(b)
(2) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under paragraph (a) of this section shall retain, at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired.
(3) The owners and operators and, to the extent applicable, the designated representative of a unit exempt under paragraph (a) of this section shall comply with the requirements of the TR NO
(4) A unit exempt under paragraph (a) of this section shall lose its exemption on the first date on which the unit resumes operation. Such unit shall be treated, for purposes of applying allocation, monitoring, reporting, and recordkeeping requirements under this subpart, as a unit that commences commercial operation on the first date on which the unit resumes operation.
(a)
(b)
(2) The emissions data determined in accordance with §§ 97.430 through 97.435 shall be used to calculate allocations of TR NO
(c)
(ii) If a TR NO
(A) The owners and operators of the source and each TR NO
(B) Each ton of such excess emissions and each day of such control period shall constitute a separate violation of this subpart and the Clean Air Act.
(2) TR NO
(A) The quotient (rounded to the nearest whole number) of the amount by which the owner's share of such NO
(B) The amount by which total NO
(ii) The owner shall hold the TR NO
(iii) The total amount of NO
(A) If such total amount of NO
(B) If, with regard to a control period in 2016 or any year thereafter, the sum, divided by three, of such total amount of NO
(C) Provided that the amount by which such total amount of NO
(iv) It shall not be a violation of this subpart or of the Clean Air Act if the total amount of NO
(v) To the extent an owner fails to hold TR NO
(A) The owner shall pay any fine, penalty, or assessment or comply with any other remedy imposed under the Clean Air Act; and
(B) Each TR NO
(3)
(i) Under paragraph (c)(1) of this section for the control period starting on the later of January 1, 2012 or the deadline for meeting the unit's monitor certification requirements under § 97.430(b) and for each control period thereafter; and
(ii) Under paragraph (c)(2) of this section for the control period starting on the later of January 1, 2014 or the deadline for meeting the unit's monitor certification requirements under § 97.430(b) and for each control period thereafter.
(4)
(5)
(6)
(ii) Notwithstanding any other provision of this subpart, the Administrator has the authority to terminate or limit such authorization to the extent the Administrator determines is necessary or appropriate to implement any provision of the Clean Air Act.
(7)
(d)
(2) A description of whether a unit is required to monitor and report NO
(e)
(i) The certificate of representation under § 97.416 for the designated representative for the source and each TR NO
(ii) All emissions monitoring information, in accordance with this subpart.
(iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under, or to demonstrate compliance with the requirements of, the TR NO
(2) The designated representative of a TR NO
(f)
(2) Any provision of the TR NO
(g)
(a) Unless otherwise stated, any time period scheduled, under the TR NO
(b) Unless otherwise stated, any time period scheduled, under the TR NO
(c) Unless otherwise stated, if the final day of any time period, under the TR NO
The administrative appeal procedures for decisions of the Administrator under the TR NO
(a) The State NO
(b) The States' one-year and three-year variability limits for the State NO
(a)
(2) Notwithstanding paragraph (a)(1) of this section, if a unit listed in appendix A to this subpart as being allocated TR NO
(b)
(2) For each notice of data availability required in paragraph (b)(1) of this section, the Administrator will provide an opportunity for submission of objections to the calculations referenced in such notice.
(i) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing whether the calculations are in accordance with § 97.412 and §§ 97.406(b)(2) and 97.430 through 97.435.
(ii) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i) of this section. By September 1 immediately after the promulgation of such notice, the Administrator will promulgate a notice of availability of any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(i) of this section.
(c)
(1) Except as provided in paragraph (c)(2) or (3) of this section, the Administrator will not record such TR NO
(2) If the Administrator already recorded such TR NO
(3) If the Administrator already recorded such TR NO
(4) The Administrator will transfer the TR NO
(a) For each control period in 2012 and thereafter, the Administrator will allocate, in accordance with the following procedures, TR NO
(1) The Administrator will establish a separate new unit set-aside for each State for each control period in a given year. Each new unit set-aside will be allocated TR NO
(2) The designated representative of such TR NO
(i) The request must be submitted on or before May 1 of the first control period for which TR NO
(ii) For each control period for which an allocation is sought, the request must be for TR NO
(3) The Administrator will review each TR NO
(i) After May 1 of such control period, the Administrator will determine the sum of the TR NO
(ii) If the amount of TR NO
(iii) If the amount of TR NO
(iv) The Administrator will notify, through the promulgation of the notices of data availability described in § 97.411(b), each designated representative that submitted an allowance allocation request of the amount of TR NO
(b) If, after completion of the procedures under paragraph (a)(4) of this section for a control period, any unallocated TR NO
(a) Except as provided under § 97.415, each TR NO
(1) The designated representative shall be selected by an agreement binding on the owners and operators of the source and all TR NO
(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.416:
(i) The designated representative shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of the source and each TR NO
(ii) The owners and operators of the source and each TR NO
(b) Except as provided under § 97.415, each TR NO
(1) The alternate designated representative shall be selected by an agreement binding on the owners and operators of the source and all TR NO
(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.416:
(i) The alternate designated representative shall be authorized;
(ii) Any representation, action, inaction, or submission by the alternate designated representative shall be deemed to be a representation, action, inaction, or submission by the designated representative; and
(iii) The owners and operators of the source and each TR NO
(c) Except in this section, § 97.402, and §§ 97.414 through 97.418, whenever the term “designated representative” is used in this subpart, the term shall be construed to include the designated representative or any alternate designated representative.
(a) Except as provided under § 97.418 concerning delegation of authority to make submissions, each submission under the TR NO
(b) The Administrator will accept or act on a submission made for a TR NO
(a)
(b)
(c)
(2) Within 30 days after any change in the owners and operators of a TR NO
(a) A complete certificate of representation for a designated representative or an alternate designated representative shall include the following elements in a format prescribed by the Administrator:
(1) Identification of the TR NO
(2) The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any alternate designated representative.
(3) A list of the owners and operators of the TR NO
(4) The following certification statements by the designated representative and any alternate designated representative—
(i) “I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the source and each TR NO
(ii) “I certify that I have all the necessary authority to carry out my duties and responsibilities under the TR NO
(iii) “Where there are multiple holders of a legal or equitable title to, or a leasehold interest in, a TR NO
(5) The signature of the designated representative and any alternate designated representative and the dates signed.
(b) Unless otherwise required by the Administrator, documents of agreement referred to in the certificate of representation shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(a) Once a complete certificate of representation under § 97.416 has been submitted and received, the Administrator will rely on the certificate of representation unless and until a superseding complete certificate of representation under § 97.416 is received by the Administrator.
(b) Except as provided in § 97.415(a) or (b), no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission, of a designated representative or alternate designated representative shall affect any representation, action, inaction, or submission of the designated representative or alternate designated representative or the finality of any decision or order by the Administrator under the TR NO
(c) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representative, including private legal disputes concerning the proceeds of TR NO
(a) A designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(b) An alternate designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(c) In order to delegate authority to make an electronic submission to the Administrator in accordance with paragraph (a) or (b) of this section, the designated representative or alternate designated representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(1) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such designated representative or alternate designated representative;
(2) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to as an “agent”);
(3) For each such natural person, a list of the type or types of electronic submissions under paragraph (a) or (b) of this section for which authority is delegated to him or her; and
(4) The following certification statements by such designated representative or alternate designated representative:
(i) “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.418(d) shall be deemed to be an electronic submission by me.”
(ii) “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.418(d), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 97.418 is terminated.”
(d) A notice of delegation submitted under paragraph (c) of this section shall
(e) Any electronic submission covered by the certification in paragraph (c)(4)(i) of this section and made in accordance with a notice of delegation effective under paragraph (d) of this section shall be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation.
(a)
(b)
(i) Any person may apply to open a general account, for the purpose of holding and transferring TR NO
(A) The authorized account representative and alternate authorized account representative shall be selected by an agreement binding on the persons who have an ownership interest with respect to TR NO
(B) The agreement by which the alternate authorized account representative is selected shall include a procedure for authorizing the alternate authorized account representative to act in lieu of the authorized account representative.
(ii) A complete application for a general account shall include the following elements in a format prescribed by the Administrator:
(A) Name, mailing address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the authorized account representative and any alternate authorized account representative;
(B) An identifying name for the general account;
(C) A list of all persons subject to a binding agreement for the authorized account representative and any alternate authorized account representative to represent their ownership interest with respect to the TR NO
(D) The following certification statement by the authorized account representative and any alternate authorized account representative: “I certify that I was selected as the authorized account representative or the alternate authorized account representative, as applicable, by an agreement that is binding on all persons who have an ownership interest with respect to TR NO
(E) The signature of the authorized account representative and any alternate authorized account representative and the dates signed.
(iii) Unless otherwise required by the Administrator, documents of agreement referred to in the application for a general account shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(2)
(B) Any alternate authorized account representative shall be authorized, and any representation, action, inaction, or submission by any alternate authorized account representative shall be deemed to be a representation, action, inaction, or submission by the authorized account representative.
(C) Each person who has an ownership interest with respect to TR NO
(ii) Except as provided in paragraph (b)(5) of this section concerning delegation of authority to make submissions, each submission concerning the general account shall be made, signed, and certified by the authorized account representative or any alternate authorized account representative for the persons having an ownership interest with respect to TR NO
(iii) Except in this section, whenever the term “authorized account representative” is used in this subpart, the term shall be construed to include the authorized account representative or
(3)
(ii) The alternate authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (b)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new alternate authorized account representative, the authorized account representative, and the persons with an ownership interest with respect to the TR NO
(iii)(A) In the event a person having an ownership interest with respect to TR NO
(B) Within 30 days after any change in the persons having an ownership interest with respect to NO
(4)
(ii) Except as provided in paragraph (b)(3)(i) or (ii) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account shall affect any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative or the finality of any decision or order by the Administrator under the TR NO
(iii) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account, including private legal disputes concerning the proceeds of TR NO
(5)
(ii) An alternate authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(iii) In order to delegate authority to make an electronic submission to the Administrator in accordance with paragraph (b)(5)(i) or (ii) of this section, the authorized account representative or alternate authorized account representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(A) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such authorized account representative or alternate authorized account representative;
(B) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to as an “agent”);
(C) For each such natural person, a list of the type or types of electronic submissions under paragraph (b)(5)(i) or (ii) of this section for which authority is delegated to him or her;
(D) The following certification statement by such authorized account representative or alternate authorized account representative: “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am an authorized account representative or alternate authorized representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.420(b)(5)(iv) shall be deemed to be an electronic submission by me.”; and
(E) The following certification statement by such authorized account representative or alternate authorized account representative: “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.420(b)(5)(iv), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 97.420(b)(5) is terminated.”.
(iv) A notice of delegation submitted under paragraph (b)(5)(iii) of this section shall be effective, with regard to the authorized account representative or alternate authorized account representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such authorized account representative or alternate authorized account representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(v) Any electronic submission covered by the certification in paragraph (b)(5)(iii)(D) of this section and made in accordance with a notice of delegation effective under paragraph (b)(5)(iv) of this section shall be deemed to be an electronic submission by the designated
(6)(i) The authorized account representative or alternate authorized account representative of a general account may submit to the Administrator a request to close the account. Such request shall include a correctly submitted TR NO
(ii) If a general account has no TR NO
(c)
(d)
(a) By September 1, 2011, the Administrator will record in each TR NO
(b) By June 1, 2012 and June 1 of each year thereafter, the Administrator will record in each TR NO
(c) By September 1, 2012 and September 1 of each year thereafter, the Administrator will record in each TR NO
(d) When recording the allocation of TR NO
(a) An authorized account representative seeking recordation of a TR NO
(b) A TR NO
(1) The transfer includes the following elements, in a format prescribed by the Administrator:
(i) The account numbers established by the Administrator for both the transferor and transferee accounts;
(ii) The serial number of each TR NO
(iii) The name and signature of the authorized account representative of the transferor account and the date signed; and
(2) When the Administrator attempts to record the transfer, the transferor account includes each TR NO
(a) Within 5 business days (except as provided in paragraph (b) of this section) of receiving a TR NO
(b)(1) A TR NO
(2) A TR NO
(c) Where a TR NO
(d) Within 5 business days of recordation of a TR NO
(e) Within 10 business days of receipt of a TR NO
(1) A decision not to record the transfer, and
(2) The reasons for such non-recordation.
(a)
(1) Were allocated for the control period in the year or a prior year; and
(2) Are held in the source's compliance account as of the allowance transfer deadline for such control period.
(b)
(1) Until the amount of TR NO
(2) If there are insufficient TR NO
(c)(1)
(2)
(i) Any TR NO
(ii) Any TR NO
(d)
(e)
(a)
(1) Were allocated for the control period in the year or a prior year; and
(2) Are held in a compliance account, designated by the owner in accordance with paragraph (b)(4)(ii) of this section, of one of the owner's TR NO
(b)
(1) By June 1, 2015 and June 1 of each year thereafter, the Administrator will:
(i) Calculate, separately for each State, the total amount of NO
(ii) Promulgate a notice of availability of the results of the calculations required in paragraph (b)(1)(i) of this section, including separate calculations of the NO
(2) The Administrator will provide an opportunity for submission of objections to the calculations referenced by each notice described in paragraph (b)(1) of this section.
(i) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing whether the calculations for each TR NO
(ii) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i) of this section. By August 1 immediately after the promulgation of such notice, the Administrator will promulgate a notice of availability of any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(i) of this section.
(3) For each notice of data availability required in paragraph (b)(2)(ii) of this section and for any State identified in such notice as having TR NO
(i) By August 15 immediately after the promulgation of such notice, the designated representative of each TR NO
(A) Listing all the owners of each TR NO
(B) For each TR NO
(ii) By September 15 immediately after the promulgation of such notice, the Administrator will calculate, for each such State and each owner of one or more TR NO
(iii) The Administrator will provide an opportunity for submission of objections to the calculations referenced by the notice of data availability
(A) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing whether the calculations for each owner for the control period in the year involved are consistent with the NO
(B) The Administrator will adjust the calculations to the extent necessary to ensure that they are consistent with the data and provisions referenced in paragraph (b)(3)(iii)(A) of this section. By November 15 immediately after the promulgation of such notice, the Administrator will promulgate a notice of availability of any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(3)(iii)(A) of this section.
(4) By December 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(3)(iii)(B) of this section:
(i) Each owner identified, in such notice, as owning one or more TR NO
(ii) The authorized account representative for the compliance account designated under paragraph (b)(4)(i) of this section shall submit to the Administrator a statement, in a format prescribed by the Administrator, making this designation.
(5)(i) As of midnight of December 15 immediately after the promulgation of each notice of data availability required in paragraph (b)(3)(iii)(B) of this section, each owner described in paragraph (b)(4)(i) of this section shall hold in the compliance account designated by the owner in accordance with paragraph (b)(4)(ii) of this section the total amount of TR NO
(ii) Notwithstanding the allowance-holding deadline specified in paragraph (b)(5)(i) of this section, if December 15 is not a business day, then such allowance-holding deadline shall be midnight of the first business day thereafter.
(6) After December 15 (or the date described in paragraph (b)(5)(ii) of this section) immediately after the promulgation of each notice of data availability required in paragraph (b)(3)(iii)(B) of this section and after the recordation, in accordance with § 97.423, of TR NO
(i) Until the amount of TR NO
(ii) If there are insufficient TR NO
(7) Notwithstanding any other provision of this subpart and any revision, made by or submitted to the Administrator after the promulgation of the notices of data availability required in paragraphs (b)(2)(ii) and (b)(3)(iii)(B) of this section respectively for a control period, of any data used in making the calculations referenced in such notice, the amount of TR NO
(i) If any such data are revised by the Administrator as a result of a decision in or settlement of litigation concerning such data on appeal under part 78 of this chapter of such notice, or on appeal under section 307 of the Clean Air Act of a decision rendered under part 78 of this chapter on appeal of such notice, then the Administrator will use the data as so revised to recalculate the amounts of TR NO
(A) With regard to such litigation involving such notice required in paragraph (b)(2)(ii) of this section, such litigation under part 78 of this chapter, or the proceeding under part 78 of this chapter that resulted in the decision appealed in such litigation under section 307 of the Clean Air Act, was initiated no later than 30 days after promulgation of such notice required in paragraph (b)(2)(ii) of this section; and
(B) With regard to such litigation involving such notice required in paragraph (b)(3)(iii) of this section, such litigation under part 78 of this chapter, or the proceeding under part 78 of this chapter that resulted in the decision appealed in such litigation under section 307 of the Clean Air Act, was initiated no later than 30 days after promulgation of such notice required in paragraph (b)(3)(iii) of this section.
(ii) If any such data are revised by the owners and operators of a source whose designated representative submitted such data under paragraph (b)(3)(i) of this section, as a result of a decision in or settlement of litigation concerning such submission, then the Administrator will use the data as so revised to recalculate the amounts of TR NO
(iii) If the revised data are used to recalculate, in accordance with paragraphs (b)(7)(i) and (b)(7)(ii) of this section, the amount of TR NO
(A) Where the amount of TR NO
(B) For an owner for which the amount of TR NO
(C) Each TR NO
(c)(1)
(2)
(i) Any TR NO
(ii) Any TR NO
(d)
(a) A TR NO
(b) Any TR NO
The Administrator may, at his or her sole discretion and on his or her own motion, correct any error in any Allowance Management System account. Within 10 business days of making such correction, the Administrator will notify the authorized account representative for the account.
(a) The Administrator may review and conduct independent audits concerning any submission under the TR NO
(b) The Administrator may deduct TR NO
The owners and operators, and to the extent applicable, the designated representative, of a TR NO
(a)
(1) Install all monitoring systems required under this subpart for monitoring NO
(2) Successfully complete all certification tests required under § 97.431 and meet all other requirements of this subpart and part 75 of this chapter applicable to the monitoring systems under paragraph (a)(1) of this section; and
(3) Record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section.
(b)
(1) For the owner or operator of a TR NO
(2) For the owner or operator of a TR NO
(i) January 1, 2012; or
(ii) 180 calendar days, whichever occurs first, after the date on which the unit commences commercial operation;
(3) For the owner or operator of a TR NO
(4) Notwithstanding the dates in paragraphs (b)(1) and (2) of this section, for the owner or operator of a unit for which a TR opt-in application is submitted and not withdrawn and is not yet approved or disapproved, by the date specified in § 97.441(c); and
(5) Notwithstanding the dates in paragraphs (b)(1) and (2) of this section, for the owner or operator of a TR NO
(c)
(d)
(2) No owner or operator of a TR NO
(3) No owner or operator of a TR NO
(4) No owner or operator of a TR NO
(i) During the period that the unit is covered by an exemption under § 97.405 that is in effect;
(ii) The owner or operator is monitoring emissions from the unit with another certified monitoring system approved, in accordance with the applicable provisions of this subpart and part 75 of this chapter, by the Administrator for use at that unit that provides emission data for the same pollutant or parameter as the retired or discontinued monitoring system; or
(iii) The designated representative submits notification of the date of certification testing of a replacement monitoring system for the retired or discontinued monitoring system in accordance with § 97.431(d)(3)(i).
(e)
(a) The owner or operator of a TR NO
(1) The monitoring system has been previously certified in accordance with part 75 of this chapter; and
(2) The applicable quality-assurance and quality-control requirements of § 75.21 of this chapter and appendices B, D, and E to part 75 of this chapter are fully met for the certified monitoring system described in paragraph (a)(1) of this section.
(b) The recertification provisions of this section shall apply to a monitoring system under § 97.430(a)(1) that is exempt from initial certification requirements under paragraph (a) of this section.
(c) If the Administrator has previously approved a petition under § 75.17(a) or (b) of this chapter for apportioning the NO
(d) Except as provided in paragraph (a) of this section, the owner or operator of a TR NO
(1)
In addition, whenever the owner or operator installs a monitoring system to meet the requirements of this subpart in a location where no such monitoring system was previously installed, initial certification in accordance with § 75.20 of this chapter is required.
(2)
(3)
(i)
(ii)
(iii)
(iv)
(A)
(B)
(C)
(D)
(v)
(A) The owner or operator shall substitute the following values, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(g)(7), or § 75.21(e) of this chapter and continuing until the applicable date and hour specified under § 75.20(a)(5)(i) or (g)(7) of this chapter:
(
(
(
(
(
(B) The designated representative shall submit a notification of certification retest dates and a new certification application in accordance with paragraphs (d)(3)(i) and (ii) of this section.
(C) The owner or operator shall repeat all certification tests or other requirements that were failed by the monitoring system, as indicated in the Administrator's notice of disapproval, no later than 30 unit operating days after the date of issuance of the notice of disapproval.
(e) The owner or operator of a unit qualified to use the low mass emissions (LME) excepted methodology under § 75.19 of this chapter shall meet the applicable certification and recertification requirements in §§ 75.19(a)(2) and 75.20(h) of this chapter. If the owner or operator of such
(f) The designated representative of each unit for which the owner or operator intends to use an alternative monitoring system approved by the Administrator under subpart E of part 75 of this chapter shall comply with the applicable notification and application procedures of § 75.20(f) of this chapter.
(a)
(b)
The designated representative of a TR NO
(a)
(b)
(c)
(d)
(1) The designated representative shall report the NO
(i) For a unit that commences commercial operation before July 1, 2011, the calendar quarter covering January 1, 2012 through March 31, 2012;
(ii) For a unit that commences commercial operation on or after July 1, 2011, the calendar quarter corresponding to the earlier of the date of provisional certification or the applicable deadline for initial certification under § 97.430(b), unless that quarter is the third or fourth quarter of 2011, in which case reporting shall commence in the quarter covering January 1, 2012 through March 31, 2012;
(iii) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, for a unit for which a TR opt-in application is submitted and not withdrawn and is not yet approved or disapproved, the calendar quarter corresponding to the date specified in § 97.441(c); and
(iv) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, for a TR NO
(2) The designated representative shall submit each quarterly report to the Administrator within 30 days after the end of the calendar quarter covered by the report. Quarterly reports shall be submitted in the manner specified in § 75.73(f) of this chapter.
(3) For TR NO
(4) The Administrator may review and conduct independent audits of any quarterly report in order to determine whether the quarterly report meets the requirements of this subpart and part 75 of this chapter, including the requirement to use substitute data.
(i) The Administrator will notify the designated representative of any determination that the quarterly report fails to meet any such requirements and specify in such notification any corrections that the Administrator believes are necessary to make through resubmission of the quarterly report and a reasonable time period within which the designated representative must respond. Upon request by the designated representative, the Administrator may specify reasonable extensions of such time period. Within the time period (including any such extensions) specified by the Administrator, the designated representative shall resubmit the quarterly report with the corrections specified by the Administrator, except to the extent the designated representative provides information demonstrating that a specified correction is not necessary because the quarterly report already meets the requirements of this subpart and part 75 of this chapter that are relevant to the specified correction.
(ii) Any resubmission of a quarterly report shall meet the requirements applicable to the submission of a quarterly report under this subpart and part 75 of this chapter, except for the deadline set forth in paragraph (d)(2) of this section.
(e)
(1) The monitoring data submitted were recorded in accordance with the applicable requirements of this subpart and part 75 of this chapter, including the quality assurance procedures and specifications; and
(2) For a unit with add-on NO
(a) The designated representative of a TR NO
(b) A petition submitted under paragraph (a) of this section shall include sufficient information for the evaluation of the petition, including, at a minimum, the following information:
(i) Identification of each unit and source covered by the petition;
(ii) A detailed explanation of why the proposed alternative is being suggested in lieu of the requirement;
(iii) A description and diagram of any equipment and procedures used in the proposed alternative;
(iv) A demonstration that the proposed alternative is consistent with the purposes of the requirement for which the alternative is proposed and with the purposes of this subpart and part 75 of this chapter and that any adverse effect of approving the alternative will be
(v) Any other relevant information that the Administrator may require.
(c) Use of an alternative to any requirement referenced in paragraph (a) of this section is in accordance with this subpart only to the extent that the petition is approved in writing by the Administrator and that such use is in accordance with such approval.
(a) A TR NO
(1) Is located in a State;
(2) Is not a TR NO
(3) Is not covered by a retired unit exemption under § 72.8 of this chapter that is in effect; and
(4) Vents all of its emissions to a stack and can meet the monitoring, recordkeeping, and reporting requirements of this subpart.
(b) A TR NO
(c) Solely for purposes of applying the requirements of §§ 97.413 through 97.418 and §§ 97.430 through 97.435, a unit for which a TR opt-in application is submitted and not withdrawn and is not yet approved or disapproved under § 97.442 shall be deemed to be a TR NO
(d) Any TR NO
A unit meeting the requirements for a TR NO
(a)
(1) Identification of the unit and the source where the unit is located, including source name, source category and NAICS code (or, in the absence of a NAICS code, an equivalent code), State, plant code, county, latitude and longitude, and unit identification number and type;
(2) A certification that the unit:
(i) Is not a TR NO
(ii) Is not covered by a retired unit exemption under § 72.8 of this chapter that is in effect;
(iii) Vents all of its emissions to a stack; and
(iv) Has documented heat input (greater than 0 mmBtu) for more than 876 hours during the 6 months immediately preceding submission of the TR opt-in application;
(3) A monitoring plan in accordance with §§ 97.430 through 97.435;
(4) A statement that the unit, if approved to become a TR NO
(5) A statement that the unit, if approved to become a TR NO
(6) A complete certificate of representation under § 97.416 consistent with § 97.440, if no designated representative has been previously designated for the source that includes the unit; and
(7) The signature of the designated representative and the date signed.
(b) Interim review of monitoring plan. The Administrator will determine, on an interim basis, the sufficiency of the monitoring plan submitted under paragraph (a)(3) of this section. The monitoring plan is sufficient, for purposes of interim review, if the plan appears to contain information demonstrating that the NO
(c) Monitoring and reporting. (1)(i) If the Administrator determines that the monitoring plan is sufficient under paragraph (b) of this section, the owner or operator of the unit shall monitor and report the NO
(ii) The monitoring and reporting under paragraph (c)(1)(i) of this section shall cover the entire control period immediately before the date on which the unit enters the TR NO
(2) To the extent the NO
(d)
(e)
(1) If the unit's NO
(2) If the unit's NO
(f)
(1) If the unit's NO
(2) If the unit's NO
(3) If the unit's NO
(g)
(1) After the designated representative submits the complete TR opt-in application, quarterly reports, and statement required in paragraphs (a), (c), and (d) of this section and if the Administrator determines that the designated representative shows that the unit meets the requirements for a TR NO
(2) Notwithstanding paragraphs (a) through (f) of this section, if, at any time before the TR opt-in application is approved under paragraph (g)(1) of this section, the Administrator determines that the unit cannot meet the requirements for a TR NO
(h)
A TR NO
(a)
(b)
(1) For the control period ending on the date on which the withdrawal is to be effective, the source that includes the TR NO
(2) After the requirement under paragraph (b)(1) of this section is met, the Administrator will deduct from the compliance account of the source that includes the TR NO
(c)
(2) If the requirements for withdrawal under paragraphs (a) and (b) of this section are not met, the Administrator will issue a written disapproval of the request to withdraw. The unit covered by the request shall continue to be a TR NO
(d)
(e)
(a)
(b)
(i) Any TR NO
(ii) If the date on which the TR NO
(A) Multiplied by the ratio of the number of days, in the control period, starting with the date on which the TR NO
(B) Rounded to the nearest allowance.
(2) The designated representative shall ensure that the compliance account of the source that includes the TR NO
(3)(i) For control periods starting after the date on which the TR NO
(ii) If the date on which the TR NO
(A) The amount of TR NO
(B) Multiplied by the ratio of the number of days, in the control period, starting with the date on which the TR NO
(a)
(2) By no later than October 31 of the control period after the control period in which a TR NO
(b)
(1) The heat input (in mmBtu) used for calculating the TR NO
(i) The TR NO
(ii) The TR NO
(2) The NO
(i) The TR NO
(ii) The most stringent State or Federal NO
(3) The Administrator will issue TR NO
(c)
(2) By December 1 of the control period after the control period in which a TR NO
36. Part 97 is amended by adding subpart BBBBB to read as follows:
This subpart sets forth the general, designated representative, allowance, and monitoring provisions for the Transport Rule (TR) NO
The terms used in this subpart shall have the meanings set forth in this section as follows:
(1) Any organic material grown for the purpose of being converted to energy;
(2) Any organic byproduct of agriculture that can be converted into energy; or
(3) Any material that can be converted into energy and is nonmerchantable for other purposes, that is segregated from other material that is nonmerchantable for other purposes, and that is;
(i) A forest-related organic resource, including mill residues, precommercial thinnings, slash, brush, or byproduct from conversion of trees to merchantable material; or
(ii) A wood material, including pallets, crates, dunnage, manufacturing and construction materials (other than pressure-treated, chemically-treated, or painted wood products), and landscape or right-of-way tree trimmings.
(1) For a corporation, a president, secretary, treasurer, or vice-president or the corporation in charge of a principal business function or any other person who performs similar policy or decision-making functions for the corporation;
(2) For a partnership or sole proprietorship, a general partner or the proprietor respectively; or
(3) For a local government entity or State, federal, or other public agency, a principal executive officer or ranking elected official.
(1) Operating as part of a cogeneration system; and
(2) Producing during the later of 1990 or the 12-month period starting on the date that the unit first produces electricity and during each calendar year after the later of 1990 or the calendar year in which the unit first produces electricity—
(i) For a topping-cycle unit,
(A) Useful thermal energy not less than 5 percent of total energy output; and
(B) Useful power that, when added to one-half of useful thermal energy produced, is not less then 42.5 percent of total energy input, if useful thermal energy produced is 15 percent or more of total energy output, or not less than 45 percent of total energy input, if useful thermal energy produced is less than 15 percent of total energy output.
(ii) For a bottoming-cycle unit, useful power not less than 45 percent of total energy input;
(3) Provided that the total energy input under paragraphs (2)(i)(B) and (2)(ii) of this definition shall equal the unit's total energy input from all fuel, except biomass if the unit is a boiler; and
(4) Provided that, if a topping-cycle unit is operated as part of a cogeneration system during a calendar year and the cogeneration system meets on a system-wide basis the requirement in paragraph (2)(i)(B) of this definition, the topping-cycle unit shall be deemed to meet such requirement during that calendar year.
(1) If the device is simple cycle, a compressor, a combustor, and a turbine and in which the flue gas resulting from the combustion of fuel in the combustor passes through the turbine, rotating the turbine; and
(2) If the device is combined cycle, the equipment described in paragraph (1) of this definition and any associated duct burner, heat recovery steam generator, and steam turbine.
(1) To have begun to produce steam, gas, or other heated medium used to generate electricity for sale or use, including test generation, except as provided in § 97.505.
(i) For a unit that is a TR NO
(ii) For a unit that is a TR NO
(2) Notwithstanding paragraph (1) of this definition and except as provided in § 97.505, for a unit that is not a TR NO
(i) For a unit with a date for commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that subsequently undergoes a physical change (other than replacement of the unit by a unit at the same source), such date shall remain the date of commencement of commercial operation of the unit, which shall continue to be treated as the same unit.
(ii) For a unit with a date for commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that is subsequently replaced by a unit at the same source, such date shall remain the replaced unit's date of commencement of commercial operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of commercial operation as defined in paragraph (1) or (2) of this definition as appropriate.
(1) To have begun any mechanical, chemical, or electronic process, including start-up of the unit's combustion chamber.
(2) For a unit that undergoes a physical change (other than replacement of the unit by a unit at the same source)
(3) For a unit that is replaced by a unit at the same source after the date the unit commences operation as defined in paragraph (1) of this definition, such date shall remain the replaced unit's date of commencement of operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of operation as defined in paragraph (1), (2), or (3) of this definition as appropriate.
(1) A flow monitoring system, consisting of a stack flow rate monitor and an automated data acquisition and handling system and providing a permanent, continuous record of stack gas volumetric flow rate, in standard cubic feet per hour (scfh);
(2) A NO
(3) A NO
(4) A moisture monitoring system, as defined in § 75.11(b)(2) of this chapter and providing a permanent, continuous record of the stack gas moisture content, in percent H
(5) A CO
(6) An O
(1) Natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material; or
(2) For purposes of applying §§ 97.504(b)(2)(i)(B), 97.504(b)(2)(ii)(B), and 97.504(b)(2)(iii), natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat.
(1) For the life of the unit;
(2) For a cumulative term of no less than 30 years, including contracts that permit an election for early termination; or
(3) For a period no less than 25 years or 70 percent of the economic useful life of the unit determined as of the time the unit is built, with option rights to purchase or release some portion of the nameplate capacity and associated energy generated by the unit at the end of the period.
(1) Any holder of any portion of the legal or equitable title in a TR NO
(2) Any holder of a leasehold interest in a TR NO
(3) Any purchaser of power from a TR NO
(4) Provided that, for purposes of applying the TR NO
(1) With regard to a State and control period for which the State assurance level is exceeded as described in § 97.506(c)(2)(iii)(A) and not as described in § 97.506(c)(2)(iii)(B), the owner's share of the State NO
(2) With regard to a State and control period for which the State assurance level is exceeded as described in § 97.506(c)(2)(iii)(B), the owner's share of the State NO
(1) With regard to a total amount of NO
(2) With regard to a State NO
(3) With regard to a State NO
(4) Provided that, in the case of a unit with more than one owner, the amount of tonnage of NO
(5) Provided that, where two or more units emit through a common stack that is the monitoring location from which NO
(i) The amount (rounded to the nearest ton) of NO
(ii) An amount determined in accordance with a methodology that the Administrator determines is consistent with the purposes of this definition and whose adverse effect (if any) the Administrator determines will be de minimis; or
(iii) An amount approved by the Administrator in response to a petition for an alternative requirement submitted in accordance with § 97.535; and
(6) Provided that, in the case of a unit that operates during, but is allocated no TR NO
(i) The unit's allowable NO
(ii) For a unit listed in appendix A to this subpart, the sum of the unit's NO
(1) For a topping-cycle unit, the use of reject heat from electricity production in a useful thermal energy application or process; or
(2) For a bottoming-cycle unit, the use of reject heat from useful thermal energy application or process in electricity production.
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or transmission and delivery;
(4) Provided that compliance with any “submission” or “service” deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt.
(1) Have been recorded by the Administrator in the account or transferred into the account by a correctly submitted, but not yet recorded, TR NO
(2) Have not been transferred out of the account by a correctly submitted, but not yet recorded, TR NO
(1) Made available to an industrial or commercial process (not a power production process), excluding any heat contained in condensate return or makeup water;
(2) Used in a heating application (e.g., space heating or domestic hot water heating); or
(3) Used in a space cooling application (i.e., in an absorption chiller).
Measurements, abbreviations, and acronyms used in this subpart are defined as follows:
(a) Except as provided in paragraph (b) of this section:
(1) The following units in a State shall be TR NO
(2) If a stationary boiler or stationary combustion turbine that, under paragraph (a)(1) of this section, is not a TR NO
(b) Any unit in a State that otherwise is a TR NO
(1)(i) Any unit:
(A) Qualifying as a cogeneration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a cogeneration unit; and
(B) Not serving at any time, since the later of November 15, 1990 or the start-up of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe supplying in any calendar year more than one-third of the unit's potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.
(ii) If a unit qualifies as a cogeneration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and meets the requirements of paragraphs (b)(1)(i) of this section for at least one calendar year, but subsequently no longer meets such qualification and requirements, the unit shall become a TR NO
(2)(i) Any unit commencing operation before January 1, 1985:
(A) Qualifying as a solid waste incineration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a solid waste incineration unit; and
(B) With an average Ozone Season fuel consumption of fossil fuel for 1985-1987 less than 20 percent (on a Btu basis) and an average Ozone Season fuel consumption of fossil fuel for any 3 consecutive calendar years after 1990 less than 20 percent (on a Btu basis).
(ii) Any unit commencing operation on or after January 1, 1985:
(A) Qualifying as a solid waste incineration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a solid waste incineration unit; and
(B) With an average Ozone Season fuel consumption of fossil fuel for the first 3 calendar years of operation less than 20 percent (on a Btu basis) and an average Ozone Season fuel consumption of fossil fuel for any 3 consecutive calendar years after 1990 less than 20 percent (on a Btu basis).
(iii) If a unit qualifies as a solid waste incineration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and meets the requirements of paragraph (b)(2)(i) or (ii) of this section for at least 3 consecutive calendar years, but subsequently no longer meets such qualification and requirements, the unit shall become a TR NO
(c) A certifying official of an owner or operator of any unit or other equipment may submit a petition (including any supporting documents) to the Administrator at any time for a determination concerning the applicability, under paragraphs (a) and (b) of this section, of the TR NO
(1)
(2)
(a)(1) Any TR NO
(2) The exemption under paragraph (a)(1) of this section shall become effective the day on which the TR NO
(b)
(2) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under paragraph (a) of this section shall retain, at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired.
(3) The owners and operators and, to the extent applicable, the designated representative of a unit exempt under paragraph (a) of this section shall comply with the requirements of the TR NO
(4) A unit exempt under paragraph (a) of this section shall lose its exemption on the first date on which the unit resumes operation. Such unit shall be treated, for purposes of applying allocation, monitoring, reporting, and recordkeeping requirements under this subpart, as a unit that commences commercial operation on the first date on which the unit resumes operation.
(a)
(b)
(2) The emissions data determined in accordance with §§ 97.530 through 97.535 shall be used to calculate allocations of TR NO
(c)
(ii) If a TR NO
(A) The owners and operators of the source and each TR NO
(B) Each ton of such excess emissions and each day of such control period shall constitute a separate violation of this subpart and the Clean Air Act.
(2) TR NO
(A) The quotient (rounded to the nearest whole number) of the amount by which the owner's share of such NO
(B) The amount by which total NO
(ii) The owner shall hold the TR NO
(iii) The total amount of NO
(A) If such total amount of NO
(B) If, with regard to a control period in 2016 or any year thereafter, the sum, divided by three, of such total amount of NO
(C) Provided that the amount by which such total amount of NO
(iv) It shall not be a violation of this subpart or of the Clean Air Act if the total amount of NO
(v) To the extent an owner fails to hold TR NO
(A) The owner shall pay any fine, penalty, or assessment or comply with any other remedy imposed under the Clean Air Act; and
(B) Each TR NO
(3)
(i) Under paragraph (c)(1) of this section for the control period starting on the later of September 1, 2012 or the deadline for meeting the unit's monitor certification requirements under § 97.530(b) and for each control period thereafter; and
(ii) Under paragraph (c)(2) of this section for the control period starting on the later of September 1, 2014 or the deadline for meeting the unit's monitor certification requirements under § 97.530(b) and for each control period thereafter.
(4)
(5)
(6)
(ii) Notwithstanding any other provision of this subpart, the Administrator has the authority to terminate or limit such authorization to the extent the Administrator determines is necessary or appropriate to implement any provision of the Clean Air Act.
(7)
(d)
(2) A description of whether a unit is required to monitor and report NO
(e)
(1) Unless otherwise provided, the owners and operators of each TR NO
(i) The certificate of representation under § 97.516 for the designated representative for the source and each TR NO
(ii) All emissions monitoring information, in accordance with this subpart.
(iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under, or to demonstrate compliance with the requirements of, the TR NO
(2) The designated representative of a TR NO
(f)
(2) Any provision of the TR NO
(g)
(a) Unless otherwise stated, any time period scheduled, under the TR NO
(b) Unless otherwise stated, any time period scheduled, under the TR NO
(c) Unless otherwise stated, if the final day of any time period, under the TR NO
The administrative appeal procedures for decisions of the Administrator under the TR NO
(a) The State NO
(b) The States' one-year and three-year variability limits for the State NO
(a)
(2) Notwithstanding paragraph (a)(1) of this section, if a unit listed in appendix A to this subpart as being allocated TR NO
(b)
(2) For each notice of data availability required in paragraph (b)(1) of this section, the Administrator will provide an opportunity for submission of objections to the calculations referenced in such notice.
(i) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing whether the calculations are in accordance with § 97.512 and §§ 97.506(b)(2) and 97.530 through 97.535.
(ii) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i) of this section. By June 1 immediately after the promulgation of such notice, the Administrator will promulgate a notice of availability of any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(i) of this section.
(c)
(1) Except as provided in paragraph (c)(2) or (3) of this section, the Administrator will not record such TR NO
(2) If the Administrator already recorded such TR NO
(3) If the Administrator already recorded such TR NO
(4) The Administrator will transfer the TR NO
(a) For each control period in 2012 and thereafter, the Administrator will allocate, in accordance with the following procedures, TR NO
(1) The Administrator will establish a separate new unit set-aside for each State for each control period in a given year. Each new unit set-aside will be allocated TR NO
(2) The designated representative of such TR NO
(i) The request must be submitted on or before February 1 immediately preceding the first control period for which TR NO
(ii) For each control period for which an allocation is sought, the request must be for TR NO
(3) The Administrator will review each TR NO
(i) After February 1 immediately preceding such control period, the Administrator will determine the sum of the TR NO
(ii) If the amount of TR NO
(iii) If the amount of TR NO
(iv) The Administrator will notify, through the promulgation of the notices of data availability described in § 97.511(b), each designated representative that submitted an allowance allocation request of the amount of TR NO
(b) If, after completion of the procedures under paragraph (a)(4) of this section for a control period, any unallocated TR NO
(a) Except as provided under § 97.515, each TR NO
(1) The designated representative shall be selected by an agreement binding on the owners and operators of the source and all TR NO
(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.516:
(i) The designated representative shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of the source and each TR NO
(ii) The owners and operators of the source and each TR NO
(b) Except as provided under § 97.515, each TR NO
(1) The alternate designated representative shall be selected by an agreement binding on the owners and operators of the source and all TR NO
(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.516,
(i) The alternate designated representative shall be authorized;
(ii) Any representation, action, inaction, or submission by the alternate designated representative shall be deemed to be a representation, action, inaction, or submission by the designated representative; and
(iii) The owners and operators of the source and each TR NO
(c) Except in this section, § 97.502, and §§ 97.514 through 97.518, whenever the term “designated representative” is used in this subpart, the term shall be construed to include the designated representative or any alternate designated representative.
(a) Except as provided under § 97.518 concerning delegation of authority to make submissions, each submission under the TR NO
(b) The Administrator will accept or act on a submission made for a TR NO
(a)
(b)
(c)
(2) Within 30 days after any change in the owners and operators of a TR NO
(a) A complete certificate of representation for a designated representative or an alternate designated representative shall include the following elements in a format prescribed by the Administrator:
(1) Identification of the TR NO
(2) The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any alternate designated representative.
(3) A list of the owners and operators of the TR NO
(4) The following certification statements by the designated representative and any alternate designated representative—
(i) “I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the source and each TR NO
(ii) “I certify that I have all the necessary authority to carry out my duties and responsibilities under the TR NO
(iii) “Where there are multiple holders of a legal or equitable title to, or a leasehold interest in, a TR NO
(5) The signature of the designated representative and any alternate designated representative and the dates signed.
(b) Unless otherwise required by the Administrator, documents of agreement referred to in the certificate of representation shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(a) Once a complete certificate of representation under § 97.516 has been submitted and received, the Administrator will rely on the certificate of representation unless and until a superseding complete certificate of representation under § 97.516 is received by the Administrator.
(b) Except as provided in § 97.515(a) or (b), no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission, of a designated representative or alternate designated representative shall affect any representation, action, inaction, or submission of the designated representative or alternate designated representative or the finality of any decision or order by the Administrator under the TR NO
(c) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representative, including private legal disputes concerning the proceeds of TR NO
(a) A designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(b) An alternate designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(c) In order to delegate authority to make an electronic submission to the Administrator in accordance with paragraph (a) or (b) of this section, the designated representative or alternate designated representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(1) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such designated representative or alternate designated representative;
(2) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to as an “agent”);
(3) For each such natural person, a list of the type or types of electronic submissions under paragraph (a) or (b) of this section for which authority is delegated to him or her; and
(4) The following certification statements by such designated representative or alternate designated representative:
(i) “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.518(d) shall be deemed to be an electronic submission by me.”
(ii) “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.518(d), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 97.518 is terminated.”.
(d) A notice of delegation submitted under paragraph (c) of this section shall be effective, with regard to the designated representative or alternate designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such designated representative or alternate designated representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(e) Any electronic submission covered by the certification in paragraph (c)(4)(i) of this section and made in accordance with a notice of delegation effective under paragraph (d) of this section shall be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation.
(a)
(b)
(A) The authorized account representative and alternate authorized account representative shall be selected by an agreement binding on the persons who have an ownership interest with respect to TR NO
(B) The agreement by which the alternate authorized account representative is selected shall include a procedure for authorizing the alternate authorized account representative to act in lieu of the authorized account representative.
(ii) A complete application for a general account shall include the following elements in a format prescribed by the Administrator:
(A) Name, mailing address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the authorized account representative and any alternate authorized account representative;
(B) An identifying name for the general account;
(C) A list of all persons subject to a binding agreement for the authorized account representative and any alternate authorized account representative to represent their ownership interest with respect to the TR NO
(D) The following certification statement by the authorized account representative and any alternate authorized account representative: “I certify that I was selected as the authorized account representative or the alternate authorized account representative, as applicable, by an agreement that is binding on all persons who have an ownership interest with respect to TR NO
(E) The signature of the authorized account representative and any alternate authorized account representative and the dates signed.
(iii) Unless otherwise required by the Administrator, documents of agreement referred to in the application for a general account shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(2)
(A) The authorized account representative of the general account shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each person who has an ownership interest with respect to TR NO
(B) Any alternate authorized account representative shall be authorized, and any representation, action, inaction, or submission by any alternate authorized account representative shall be deemed to be a representation, action, inaction, or submission by the authorized account representative.
(C) Each person who has an ownership interest with respect to TR NO
(ii) Except as provided in paragraph (b)(5) of this section concerning delegation of authority to make submissions, each submission concerning the general account shall be made, signed, and certified by the authorized account representative or any alternate authorized account representative for the persons having an ownership interest with respect to TR NO
(iii) Except in this section, whenever the term “authorized account representative” is used in this subpart, the term shall be construed to include the authorized account representative or any alternate authorized account representative.
(3)
(ii) The alternate authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (b)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new
(iii)(A) In the event a person having an ownership interest with respect to TR NO
(B) Within 30 days after any change in the persons having an ownership interest with respect to NO
(4)
(ii) Except as provided in paragraph (b)(3)(i) or (ii) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account shall affect any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative or the finality of any decision or order by the Administrator under the TR NO
(iii) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account, including private legal disputes concerning the proceeds of TR NO
(5)
(ii) An alternate authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(iii) In order to delegate authority to make an electronic submission to the Administrator in accordance with paragraph (b)(5)(i) or (ii) of this section, the authorized account representative or alternate authorized account representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(A) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such authorized account representative or alternate authorized account representative;
(B) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to as an “agent”);
(C) For each such natural person, a list of the type or types of electronic submissions under paragraph (b)(5)(i) or (ii) of this section for which authority is delegated to him or her;
(D) The following certification statement by such authorized account representative or alternate authorized account representative: “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am an authorized account representative or alternate authorized representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.520(b)(5)(iv) shall be deemed to be an electronic submission by me.”; and
(E) The following certification statement by such authorized account representative or alternate authorized account representative: “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.520(b)(5)(iv), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 97.520(b)(5) is terminated.”.
(iv) A notice of delegation submitted under paragraph (b)(5)(iii) of this section shall be effective, with regard to the authorized account representative or alternate authorized account representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such authorized account representative or alternate authorized account representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(v) Any electronic submission covered by the certification in paragraph (b)(5)(iii)(D) of this section and made in accordance with a notice of delegation effective under paragraph (b)(5)(iv) of this section shall be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation.
(6)(i) The authorized account representative or alternate authorized account representative of a general account may submit to the Administrator a request to close the account. Such request shall include a correctly submitted TR NO
(ii) If a general account has no TR NO
(c)
(d)
(a) By September 1, 2011, the Administrator will record in each TR NO
(b) By June 1, 2012 and June 1 of each year thereafter, the Administrator will record in each TR NO
(c) By June 1, 2012 and June 1 of each year thereafter, the Administrator will record in each TR NO
(d) When recording the allocation of TR NO
(a) An authorized account representative seeking recordation of a TR NO
(b) A TR NO
(1) The transfer includes the following elements, in a format prescribed by the Administrator:
(i) The account numbers established by the Administrator for both the transferor and transferee accounts;
(ii) The serial number of each TR NO
(iii) The name and signature of the authorized account representative of the transferor account and the date signed; and
(2) When the Administrator attempts to record the transfer, the transferor account includes each TR NO
(a) Within 5 business days (except as provided in paragraph (b) of this section) of receiving a TR NO
(b)(1) A TR NO
(2) A TR NO
(c) Where a TR NO
(d) Within 5 business days of recordation of a TR NO
(e) Within 10 business days of receipt of a TR NO
(1) A decision not to record the transfer, and
(2) The reasons for such non-recordation.
(a)
(1) Were allocated for the control period in the year or a prior year; and
(2) Are held in the source's compliance account as of the allowance transfer deadline for such control period.
(b)
(1) Until the amount of TR NO
(2) If there are insufficient TR NO
(c)(1)
(2)
(i) Any TR NO
(ii) Any TR NO
(d)
(e)
(a)
(1) Were allocated for the control period in the year or a prior year; and
(2) Are held in a compliance account, designated by the owner in accordance with paragraph (b)(4)(ii) of this section, of one of the owner's TR NO
(b)
(1) By March 1, 2015 and March 1 of each year thereafter, the Administrator will:
(i) Calculate, separately for each State, the total amount of NO
(ii) Promulgate a notice of availability of the results of the calculations required in paragraph (b)(1)(i) of this section, including separate calculations of the NO
(2) The Administrator will provide an opportunity for submission of objections to the calculations referenced by each notice described in paragraph (b)(1) of this section.
(i) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing whether the calculations for each TR NO
(ii) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i) of this section. By May 1 immediately after the promulgation of such notice, the Administrator will promulgate a notice of availability of any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(i) of this section.
(3) For each notice of data availability required in paragraph (b)(2)(ii) of this section and for any State identified in such notice as having TR NO
(i) By May 15 immediately after the promulgation of such notice, the designated representative of each TR NO
(A) Listing all the owners of each TR NO
(B) For each TR NO
(ii) By June 15 immediately after the promulgation of such notice, the Administrator will calculate, for each such State and each owner of one or more TR NO
(iii) The Administrator will provide an opportunity for submission of objections to the calculations referenced by the notice of data availability required in paragraph (b)(3)(ii) of this section.
(A) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing whether the calculations for each owner for the control period in the year involved are consistent with the NO
(B) The Administrator will adjust the calculations to the extent necessary to ensure that they are consistent with the data and provisions referenced in paragraph (b)(3)(iii)(A) of this section.
(4) By September 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(3)(iii)(B) of this section:
(i) Each owner identified, in such notice, as owning one or more TR NO
(ii) The authorized account representative for the compliance account designated under paragraph (b)(4)(i) of this section shall submit to the Administrator a statement, in a format prescribed by the Administrator, making this designation.
(5)(i) As of midnight of September 15 immediately after the promulgation of each notice of data availability required in paragraph (b)(3)(iii)(B) of this section, each owner described in paragraph (b)(4)(i) of this section shall hold in the compliance account designated by the owner in accordance with paragraph (b)(4)(ii) of this section the total amount of TR NO
(ii) Notwithstanding the allowance-holding deadline specified in paragraph (b)(5)(i) of this section, if September 15 is not a business day, then such allowance-holding deadline shall be midnight of the first business day thereafter.
(6) After September 15 (or the date described in paragraph (b)(5)(ii) of this section) immediately after the promulgation of each notice of data availability required in paragraph (b)(3)(iii)(B) of this section and after the recordation, in accordance with § 97.523, of TR NO
(i) Until the amount of TR NO
(ii) If there are insufficient TR NO
(7) Notwithstanding any other provision of this subpart and any revision, made by or submitted to the Administrator after the promulgation of the notices of data availability required in paragraphs (b)(2)(ii) and (b)(3)(iii)(B) of this section respectively for a control period, of any data used in making the calculations referenced in such notice, the amount of TR NO
(i) If any such data are revised by the Administrator as a result of a decision in or settlement of litigation concerning such data on appeal under part 78 of this chapter of such notice, or on appeal under section 307 of the Clean Air Act of a decision rendered under part 78 of this chapter on appeal of such notice, then the Administrator will use the data as so revised to recalculate the amounts of TR NO
(A) With regard to such litigation involving such notice required in paragraph (b)(2)(ii) of this section, such litigation under part 78 of this chapter, or the proceeding under part 78 of this chapter that resulted in the decision appealed in such litigation under section 307 of the Clean Air Act, was initiated no later than 30 days after promulgation of such notice required in paragraph (b)(2)(ii) of this section; and
(B) With regard to such litigation involving such notice required in paragraph (b)(3)(iii) of this section, such litigation under part 78 of this chapter, or the proceeding under part 78 of this chapter that resulted in the decision appealed in such litigation under section 307 of the Clean Air Act, was initiated no later than 30 days after promulgation of such notice required in paragraph (b)(3)(iii) of this section.
(ii) If any such data are revised by the owners and operators of a source whose designated representative submitted such data under paragraph (b)(3)(i) of this section, as a result of a decision in or settlement of litigation concerning such submission, then the Administrator will use the data as so revised to recalculate the amounts of TR NO
(iii) If the revised data are used to recalculate, in accordance with paragraphs (b)(7)(i) and (b)(7)(ii) of this section, the amount of TR NO
(A) Where the amount of TR NO
(B) For an owner for which the amount of TR NO
(C) Each TR NO
(c)(1)
(2)
(i) Any TR NO
(ii) Any TR NO
(d)
(a) A TR NO
(b) Any TR NO
The Administrator may, at his or her sole discretion and on his or her own motion, correct any error in any Allowance Management System account. Within 10 business days of making such correction, the Administrator will notify the authorized account representative for the account.
(a) The Administrator may review and conduct independent audits concerning any submission under the TR NO
(b) The Administrator may deduct TR NO
The owners and operators, and to the extent applicable, the designated representative, of a TR NO
(a)
(1) Install all monitoring systems required under this subpart for monitoring NO
(2) Successfully complete all certification tests required under § 97.531 and meet all other requirements of this subpart and part 75 of this chapter applicable to the monitoring systems under paragraph (a)(1) of this section; and
(3) Record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section.
(b)
(1) For the owner or operator of a TR NO
(2) For the owner or operator of a TR NO
(i) 180 calendar days, whichever occurs first, after the date on which the unit commences commercial operation; or
(ii) May 1, 2012.
(3) For the owner or operator of a TR NO
(i) 180 calendar days, whichever occurs first, after the date on which the unit commences commercial operation; or
(ii) If the compliance date under paragraph (b)(3)(i) of this section is not during a control period, May 1 immediately after the compliance date under paragraph (b)(3)(i) of this section.
(4) For the owner or operator of a TR NO
(5) For the owner or operator of a TR NO
(i) 90 unit operating days or 180 calendar days, whichever occurs first, after the date on which emissions first exit to the atmosphere through the new stack or flue or add-on NO
(ii) If the compliance date under paragraph (b)(5)(i) of this section is not during a control period, May 1 immediately after the compliance date under paragraph (b)(5)(i) of this section.
(6) Notwithstanding the dates in paragraphs (b)(1), (2), and (3) of this section, for the owner or operator of a unit for which a TR opt-in application is submitted and not withdrawn and is not yet approved or disapproved, by the date specified in § 97.541(c).
(7) Notwithstanding the dates in paragraphs (b)(1), (2), and (3) of this section, for the owner or operator of a TR NO
(c)
(d)
(2) No owner or operator of a TR NO
(3) No owner or operator of a TR NO
(4) No owner or operator of a TR NO
(i) During the period that the unit is covered by an exemption under § 97.505 that is in effect;
(ii) The owner or operator is monitoring emissions from the unit with another certified monitoring system approved, in accordance with the applicable provisions of this subpart and part 75 of this chapter, by the Administrator for use at that unit that provides emission data for the same pollutant or parameter as the retired or discontinued monitoring system; or
(iii) The designated representative submits notification of the date of certification testing of a replacement monitoring system for the retired or discontinued monitoring system in accordance with § 97.531(d)(3)(i).
(e)
(a) The owner or operator of a TR NO
(1) The monitoring system has been previously certified in accordance with part 75 of this chapter; and
(2) The applicable quality-assurance and quality-control requirements of § 75.21 of this chapter and appendices B, D, and E to part 75 of this chapter are fully met for the certified monitoring system described in paragraph (a)(1) of this section.
(b) The recertification provisions of this section shall apply to a monitoring system under § 97.530(a)(1) exempt from initial certification requirements under paragraph (a) of this section.
(c) If the Administrator has previously approved a petition under § 75.17(a) or (b) of this chapter for apportioning the NO
(d) Except as provided in paragraph (a) of this section, the owner or operator of a TR NO
(1)
(2)
(3)
(i)
(ii)
(iii)
(iv)
(A)
(B)
(C)
(D)
(v)
(A) The owner or operator shall substitute the following values, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(g)(7), or § 75.21(e) of this chapter and continuing until the applicable date and hour specified under § 75.20(a)(5)(i) or (g)(7) of this chapter:
(1) For a disapproved NO
(2) For a disapproved NO
(3) For a disapproved moisture monitoring system and disapproved diluent gas monitoring system, respectively, the minimum potential moisture percentage and either the maximum potential CO
(4) For a disapproved fuel flowmeter system, the maximum potential fuel
(5) For a disapproved excepted NO
(B) The designated representative shall submit a notification of certification retest dates and a new certification application in accordance with paragraphs (d)(3)(i) and (ii) of this section.
(C) The owner or operator shall repeat all certification tests or other requirements that were failed by the monitoring system, as indicated in the Administrator's notice of disapproval, no later than 30 unit operating days after the date of issuance of the notice of disapproval.
(e) The owner or operator of a unit qualified to use the low mass emissions (LME) excepted methodology under § 75.19 of this chapter shall meet the applicable certification and recertification requirements in §§ 75.19(a)(2) and 75.20(h) of this chapter. If the owner or operator of such a unit elects to certify a fuel flowmeter system for heat input determination, the owner or operator shall also meet the certification and recertification requirements in § 75.20(g) of this chapter.
(f) The designated representative of each unit for which the owner or operator intends to use an alternative monitoring system approved by the Administrator under subpart E of part 75 of this chapter shall comply with the applicable notification and application procedures of § 75.20(f) of this chapter.
(
(
The designated representative of a TR NO
(
(
(
(
(1) If the TR NO
(i) For a unit that commences commercial operation before July 1, 2011, the calendar quarter covering May 1, 2012 through June 30, 2012;
(ii) For a unit that commences commercial operation on or after July 1, 2011, the calendar quarter corresponding to the earlier of the date of provisional certification or the applicable deadline for initial certification under § 97.530(b), unless that quarter is the third or fourth quarter of 2011 or the first quarter of 2012, in which case reporting shall commence in the quarter covering May 1, 2012 through June 30, 2012;
(2) If the TR NO
(i) Meet the requirements of subpart H of part 75 (concerning monitoring of NO
(ii) Meet the requirements of subpart H of part 75 for the control period (including the requirements in § 75.74(c) of this chapter) and report NO
(A) For a unit that commences commercial operation before July 1, 2011, the calendar quarter covering May 1, 2012 through June 30, 2012;
(B) For a unit that commences commercial operation on or after July 1, 2011, the calendar quarter corresponding to the earlier of the date of provisional certification or the applicable deadline for initial certification under § 97.530(b), unless that date is not during a control period, in which case reporting shall commence in the quarter that includes May 1 through June 30 of the first control period after such date;
(3) Notwithstanding paragraphs (d)(1) and (2) of this section, for a unit for which a TR opt-in application is submitted and not withdrawn and is not yet approved or disapproved, the calendar quarter corresponding to the date specified in § 97.541(c); and
(4) Notwithstanding paragraphs (d)(1) and (2) of this section, for a TR NO
(5) The designated representative shall submit each quarterly report to the Administrator within 30 days after the end of the calendar quarter covered by the report. Quarterly reports shall be submitted in the manner specified in § 75.73(f) of this chapter.
(6) For TR NO
(7) The Administrator may review and conduct independent audits of any quarterly report in order to determine whether the quarterly report meets the requirements of this subpart and part 75 of this chapter, including the requirement to use substitute data.
(i) The Administrator will notify the designated representative of any determination that the quarterly report fails to meet any such requirements and specify in such notification any corrections that the Administrator believes are necessary to make through resubmission of the quarterly report and a reasonable time period within which the designated representative must respond. Upon request by the designated representative, the Administrator may specify reasonable extensions of such time period. Within the time period (including any such extensions) specified by the Administrator, the designated representative shall resubmit the quarterly report with the corrections specified by the Administrator, except to the extent the designated representative provides information demonstrating that a specified correction is not necessary because the quarterly report already meets the requirements of this subpart and part 75 of this chapter that are relevant to the specified correction.
(8) Any resubmission of a quarterly report shall meet the requirements applicable to the submission of a quarterly report under this subpart and part 75 of this chapter, except for the deadline set forth in paragraph (d)(5) of this section.
(
(1) The monitoring data submitted were recorded in accordance with the applicable requirements of this subpart and part 75 of this chapter, including the quality assurance procedures and specifications;
(2) For a unit with add-on NO
(3) For a unit that is reporting on a control period basis under paragraph (d)(2)(ii) of this section, the NO
(a) The designated representative of a TR NO
(b) A petition submitted under paragraph (a) of this section shall include sufficient information for the evaluation of the petition, including, at a minimum, the following information:
(i) Identification of each unit and source covered by the petition;
(ii) A detailed explanation of why the proposed alternative is being suggested in lieu of the requirement;
(iii) A description and diagram of any equipment and procedures used in the proposed alternative;
(iv) A demonstration that the proposed alternative is consistent with the purposes of the requirement for which the alternative is proposed and with the purposes of this subpart and part 75 of this chapter and that any adverse effect of approving the alternative will be
(v) Any other relevant information that the Administrator may require.
(c) Use of an alternative to any requirement referenced in paragraph (a) of this section is in accordance with this subpart only to the extent that the petition is approved in writing by the Administrator and that such use is in accordance with such approval.
(a) A TR NO
(1) Is located in a State;
(2) Is not a TR NO
(3) Is not covered by a retired unit exemption under § 72.8 of this chapter that is in effect; and
(4) Vents all of its emissions to a stack and can meet the monitoring, recordkeeping, and reporting requirements of this subpart.
(b) A TR NO
(c) Solely for purposes of applying the requirements of §§ 97.513 through 97.518 and §§ 97.530 through 97.535, a unit for which a TR opt-in application is submitted and not withdrawn and is not yet approved or disapproved under § 97.542 shall be deemed to be a TR NO
(d) Any TR NO
A unit meeting the requirements for a TR NO
(a)
(1) Identification of the unit and the source where the unit is located,
(2) A certification that the unit:
(i) Is not a TR NO
(ii) Is not covered by a retired unit exemption under § 72.8 of this chapter that is in effect;
(iii) Vents all of its emissions to a stack; and
(iv) Has documented heat input (greater than 0 mmBtu) for more than 876 hours during the 6 months immediately preceding submission of the TR opt-in application;
(3) A monitoring plan in accordance with §§ 97.530 through 97.535;
(4) A statement that the unit, if approved to become a TR NO
(5) A statement that the unit, if approved to become a TR NO
(6) A complete certificate of representation under § 97.516 consistent with § 97.540, if no designated representative has been previously designated for the source that includes the unit; and
(7) The signature of the designated representative and the date signed.
(b)
(c)
(ii) The monitoring and reporting under paragraph (c)(1)(i) of this section shall cover the entire control period immediately before the date on which the unit enters the TR NO
(2) To the extent the NO
(d)
(e)
(1) If the unit's NO
(2) If the unit's NO
(f)
(1) If the unit's NO
(2) If the unit's NO
(3) If the unit's NO
(g)
(1) After the designated representative submits the complete TR opt-in application, quarterly reports, and statement required in paragraphs (a), (c), and (d) of this section and if the Administrator determines that the designated representative shows that the unit meets the requirements for a TR NO
(2) Notwithstanding paragraphs (a) through (f) of this section, if, at any time before the TR opt-in application is approved under paragraph (g)(1) of this section, the Administrator determines that the unit cannot meet the requirements for a TR NO
(h) Date of entry into TR NO
A TR NO
(a)
(b)
(1) For the control period ending on the date on which the withdrawal is to be effective, the source that includes the TR NO
(2) After the requirement under paragraph (b)(1) of this section is met, the Administrator will deduct from the compliance account of the source that includes the TR NO
(c)
(2) If the requirements for withdrawal under paragraphs (a) and (b) of this section are not met, the Administrator will issue a written disapproval of the request to withdraw. The unit covered by the request shall continue to be a TR NO
(d)
(e)
(a)
(b)
(i) Any TR NO
(ii) If the date on which the TR NO
(A) Multiplied by the ratio of the number of days, in the control period, starting with the date on which the TR NO
(B) Rounded to the nearest allowance.
(2) The designated representative shall ensure that the compliance account of the source that includes the TR NO
(3)(i) For control periods starting after the date on which the TR NO
(ii) If the date on which the TR NO
(A) The amount of TR NO
(B) Multiplied by the ratio of the number of days, in the control period, starting with the date on which the TR NO
(C) Rounded to the nearest allowance.
(a)
(2) By no later than July 30 of the control period after the control period in which a TR NO
(b)
(1) The heat input (in mmBtu) used for calculating the TR NO
(i) The TR NO
(ii) The TR NO
(2) The NO
(i) The TR NO
(ii) The most stringent State or Federal NO
(3) The Administrator will issue TR NO
(c)
(2) By September 1 of the control period after the control period in which a TR NO
37. Part 97 is amended by adding subpart CCCCC to read as follows:
This subpart sets forth the general, designated representative, allowance, and monitoring provisions for the Transport Rule (TR) SO
The terms used in this subpart shall have the meanings set forth in this section as follows:
(1) Any organic material grown for the purpose of being converted to energy;
(2) Any organic byproduct of agriculture that can be converted into energy; or
(3) Any material that can be converted into energy and is nonmerchantable for other purposes, that is segregated from other material that is nonmerchantable for other purposes, and that is;
(i) A forest-related organic resource, including mill residues, precommercial thinnings, slash, brush, or byproduct from conversion of trees to merchantable material; or
(ii) A wood material, including pallets, crates, dunnage, manufacturing and construction materials (other than pressure-treated, chemically-treated, or painted wood products), and landscape or right-of-way tree trimmings.
(1) For a corporation, a president, secretary, treasurer, or vice-president or the corporation in charge of a principal business function or any other person who performs similar policy or decision-making functions for the corporation;
(2) For a partnership or sole proprietorship, a general partner or the proprietor respectively; or
(3) For a local government entity or State, federal, or other public agency, a principal executive officer or ranking elected official.
(1) Operating as part of a cogeneration system; and
(2) Producing during the later of 1990 or the 12-month period starting on the date that the unit first produces electricity and during each calendar year after the later of 1990 or the calendar year in which the unit first produces electricity—
(i) For a topping-cycle unit,
(A) Useful thermal energy not less than 5 percent of total energy output; and
(B) Useful power that, when added to one-half of useful thermal energy produced, is not less then 42.5 percent of total energy input, if useful thermal energy produced is 15 percent or more of total energy output, or not less than 45 percent of total energy input, if useful thermal energy produced is less than 15 percent of total energy output.
(ii) For a bottoming-cycle unit, useful power not less than 45 percent of total energy input;
(3) Provided that the total energy input under paragraphs (2)(i)(B) and (2)(ii) of this definition shall equal the unit's total energy input from all fuel, except biomass if the unit is a boiler; and
(4) Provided that, if a topping-cycle unit is operated as part of a cogeneration system during a calendar year and the cogeneration system meets on a system-wide basis the requirement in paragraph
(1) If the device is simple cycle, a compressor, a combustor, and a turbine and in which the flue gas resulting from the combustion of fuel in the combustor passes through the turbine, rotating the turbine; and
(2) If the device is combined cycle, the equipment described in paragraph (1) of this definition and any associated duct burner, heat recovery steam generator, and steam turbine.
(1) To have begun to produce steam, gas, or other heated medium used to generate electricity for sale or use, including test generation, except as provided in § 97.605.
(i) For a unit that is a TR SO
(ii) For a unit that is a TR SO
(2) Notwithstanding paragraph (1) of this definition and except as provided in § 97.605, for a unit that is not a TR SO
(i) For a unit with a date for commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that subsequently undergoes a physical change (other than replacement of the unit by a unit at the same source), such date shall remain the date of commencement of commercial operation of the unit, which shall continue to be treated as the same unit.
(ii) For a unit with a date for commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that is subsequently replaced by a unit at the same source, such date shall remain the replaced unit's date of commencement of commercial operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of commercial operation as defined in paragraph (1) or (2) of this definition as appropriate.
(1) To have begun any mechanical, chemical, or electronic process, including start-up of the unit's combustion chamber.
(2) For a unit that undergoes a physical change (other than replacement of the unit by a unit at the same source) after the date the unit commences operation as defined in paragraph (1) of this definition, such date shall remain the date of commencement of operation of the unit, which shall continue to be treated as the same unit.
(3) For a unit that is replaced by a unit at the same source after the date the unit commences operation as defined in paragraph (1) of this definition, such date shall remain the replaced unit's date of commencement of operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of operation as defined in paragraph (1), (2), or (3) of this definition as appropriate.
(1) A flow monitoring system, consisting of a stack flow rate monitor and an automated data acquisition and handling system and providing a permanent, continuous record of stack gas volumetric flow rate, in standard cubic feet per hour (scfh);
(2) A SO
(3) A moisture monitoring system, as defined in § 75.11(b)(2) of this chapter and providing a permanent, continuous record of the stack gas moisture content, in percent H
(4) A CO
(5) An O
(1) Natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material; or
(2) For purposes of applying §§ 97.604(b)(2)(i)(B), 97.604(b)(2)(ii)(B), and 97.604(b)(2)(iii), natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat.
(1) For the life of the unit;
(2) For a cumulative term of no less than 30 years, including contracts that permit an election for early termination; or
(3) For a period no less than 25 years or 70 percent of the economic useful life of the unit determined as of the time the unit is built, with option rights to purchase or release some portion of the nameplate capacity and associated energy generated by the unit at the end of the period.
(1) Any holder of any portion of the legal or equitable title in a TR SO
(2) Any holder of a leasehold interest in a TR SO
(3) Any purchaser of power from a TR SO
(4) Provided that, for purposes of applying the TR SO
(1) With regard to a State and control period for which the State assurance level is exceeded as described in § 97.606(c)(2)(iii)(A) and not as described in § 97.606(c)(2)(iii)(B), the owner's share of the State SO
(2) With regard to a State and control period for which the State assurance level is exceeded as described in § 97.606(c)(2)(iii)(B), the owner's share of the State SO
(1) With regard to a total amount of SO
(2) With regard to a State SO
(3) With regard to a State SO
(4) Provided that, in the case of a unit with more than one owner, the amount of tonnage of SO
(5) Provided that, where two or more units emit through a common stack that is the monitoring location from which SO
(i) The amount (rounded to the nearest ton) of SO
(ii) An amount determined in accordance with a methodology that the Administrator determines is consistent with the purposes of this definition and whose adverse effect (if any) the Administrator determines will be
(iii) An amount approved by the Administrator in response to a petition for an alternative requirement submitted in accordance with § 97.635; and
(6) Provided that, in the case of a unit that operates during, but is allocated no TR SO
(i) The unit's allowable SO
(ii) For a unit listed in appendix A to this subpart, the sum of the unit's SO
(1) For a topping-cycle unit, the use of reject heat from electricity production in a useful thermal energy application or process; or
(2) For a bottoming-cycle unit, the use of reject heat from useful thermal energy application or process in electricity production.
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or transmission and delivery;
(4) Provided that compliance with any “submission” or “service” deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt.
(1) Have been recorded by the Administrator in the account or transferred into the account by a correctly submitted, but not yet recorded, TR SO
(2) Have not been transferred out of the account by a correctly submitted, but not yet recorded, TR SO
(1) Made available to an industrial or commercial process (not a power production process), excluding any heat contained in condensate return or makeup water;
(2) Used in a heating application (e.g., space heating or domestic hot water heating); or
(3) Used in a space cooling application (i.e., in an absorption chiller).
Measurements, abbreviations, and acronyms used in this subpart are defined as follows:
(a) Except as provided in paragraph (b) of this section:
(1) The following units in a State shall be TR SO
(2) If a stationary boiler or stationary combustion turbine that, under paragraph (a)(1) of this section, is not a TR SO
(b) Any unit in a State that otherwise is a TR SO
(1)(i) Any unit:
(A) Qualifying as a cogeneration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a cogeneration unit; and
(B) Not serving at any time, since the later of November 15, 1990 or the start-up of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe supplying in any calendar year more than one-third of the unit's potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.
(ii) If a unit qualifies as a cogeneration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and meets the requirements of paragraphs (b)(1)(i) of this section for at least one calendar year, but subsequently no longer meets such qualification and requirements, the unit shall become a TR SO
(2)(i) Any unit commencing operation before January 1, 1985:
(A) Qualifying as a solid waste incineration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a solid waste incineration unit; and
(B) With an average annual fuel consumption of fossil fuel for 1985-1987 less than 20 percent (on a Btu basis) and an average annual fuel consumption of fossil fuel for any 3 consecutive calendar years after 1990 less than 20 percent (on a Btu basis).
(ii) Any unit commencing operation on or after January 1, 1985:
(A) Qualifying as a solid waste incineration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a solid waste incineration unit; and
(B) With an average annual fuel consumption of fossil fuel for the first 3 calendar years of operation less than 20 percent (on a Btu basis) and an average annual fuel consumption of fossil fuel for any 3 consecutive calendar years after 1990 less than 20 percent (on a Btu basis).
(iii) If a unit qualifies as a solid waste incineration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and meets the requirements of paragraph (b)(2)(i) or (ii) of this section for at least 3 consecutive calendar years, but subsequently no longer meets such qualification and requirements, the unit shall become a TR SO
(c) A certifying official of an owner or operator of any unit or other equipment may submit a petition (including any supporting documents) to the Administrator at any time for a determination concerning the applicability, under paragraphs (a) and (b) of this section, of the TR SO
(1)
(2)
(a)(1) Any TR SO
(2) The exemption under paragraph (a)(1) of this section shall become effective the day on which the TR SO
(b)
(2) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under paragraph (a) of this section shall retain, at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired.
(3) The owners and operators and, to the extent applicable, the designated representative of a unit exempt under paragraph (a) of this section shall comply with the requirements of the TR SO
(4) A unit exempt under paragraph (a) of this section shall lose its exemption on the first date on which the unit resumes operation. Such unit shall be treated, for purposes of applying allocation, monitoring, reporting, and recordkeeping requirements under this subpart, as a unit that commences commercial operation on the first date on which the unit resumes operation.
(a)
(b)
(2) The emissions data determined in accordance with §§ 97.630 through 97.635 shall be used to calculate allocations of TR SO
(c)
(ii) If a TR SO
(A) The owners and operators of the source and each TR SO
(B) Each ton of such excess emissions and each day of such control period shall constitute a separate violation of this subpart and the Clean Air Act.
(2)
(A) The quotient (rounded to the nearest whole number) of the amount by which the owner's share of such SO
(B) The amount by which total SO
(ii) The owner shall hold the TR SO
(iii) The total amount of SO
(A) If such total amount of SO
(B) If, with regard to a control period in 2016 or any year thereafter, the sum, divided by three, of such total amount of SO
(C) Provided that the amount by which such total amount of SO
(iv) It shall not be a violation of this subpart or of the Clean Air Act if the total amount of SO
(v) To the extent an owner fails to hold TR SO
(A) The owner shall pay any fine, penalty, or assessment or comply with any other remedy imposed under the Clean Air Act; and
(B) Each TR SO
(3)
(i) Under paragraph (c)(1) of this section for the control period starting on the later of January 1, 2012 or the deadline for meeting the unit's monitor certification requirements under § 97.630(b) and for each control period thereafter; and
(ii) Under paragraph (c)(2) of this section for the control period starting on the later of January 1, 2014 or the deadline for meeting the unit's monitor certification requirements under § 97.630(b) and for each control period thereafter.
(4)
(5)
(6)
(ii) Notwithstanding any other provision of this subpart, the Administrator has the authority to terminate or limit such authorization to the extent the Administrator determines is necessary or appropriate to implement any provision of the Clean Air Act.
(7)
(d)
(2) A description of whether a unit is required to monitor and report SO
(e)
(i) The certificate of representation under § 97.616 for the designated representative for the source and each TR SO
(ii) All emissions monitoring information, in accordance with this subpart.
(iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under, or to demonstrate compliance with the requirements of, the TR SO
(2) The designated representative of a TR SO
(f)
(2) Any provision of the TR SO
(g)
(a) Unless otherwise stated, any time period scheduled, under the TR SO
(b) Unless otherwise stated, any time period scheduled, under the TR SO
(c) Unless otherwise stated, if the final day of any time period, under the TR SO
The administrative appeal procedures for decisions of the Administrator under the TR SO
(a) The State SO
(b) The States' one-year and three-year variability limits for the State SO
(a)
(2) Notwithstanding paragraph (a)(1) of this section, if a unit listed in appendix A to this subpart as being allocated TR SO
(b)
(2) For each notice of data availability required in paragraph (b)(1) of this section, the Administrator will provide an opportunity for submission of objections to the calculations referenced in such notice.
(i) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing whether the calculations are in accordance with § 97.612 and §§ 97.606(b)(2) and 97.630 through 97.635.
(ii) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i) of this section. By September 1 immediately after the promulgation of such notice, the Administrator will promulgate a notice of availability of any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(i) of this section.
(c)
(1) Except as provided in paragraph (c)(2) or (3) of this section, the Administrator will not record such TR SO
(2) If the Administrator already recorded such TR SO
(3) If the Administrator already recorded such TR SO
(4) The Administrator will transfer the TR SO
(a) For each control period in 2012 and thereafter, the Administrator will allocate, in accordance with the following procedures, TR SO
(1) The Administrator will establish a separate new unit set-aside for each State for each control period in a given year. Each new unit set-aside will be allocated TR SO
(2) The designated representative of such TR SO
(i) The request must be submitted on or before May 1 of the first control period for which TR SO
(ii) For each control period for which an allocation is sought, the request must be for TR SO
(3) The Administrator will review each TR SO
(i) After May 1 of such control period, the Administrator will determine the sum of the TR SO
(ii) If the amount of TR SO
(iii) If the amount of TR SO
(iv) The Administrator will notify, through the promulgation of the notices of data availability described in § 97.611(b), each designated representative that submitted an allowance allocation request of the amount of TR SO
(b) If, after completion of the procedures under paragraph (a)(4) of this section for a control period, any unallocated TR SO
(a) Except as provided under § 97.615, each TR SO
(1) The designated representative shall be selected by an agreement binding on the owners and operators of the source and all TR SO
(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.616:
(i) The designated representative shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of the source and each TR SO
(ii) The owners and operators of the source and each TR SO
(b) Except as provided under § 97.615, each TR SO
(1) The alternate designated representative shall be selected by an agreement binding on the owners and operators of the source and all TR SO
(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.616,
(i) The alternate designated representative shall be authorized;
(ii) Any representation, action, inaction, or submission by the alternate designated representative shall be deemed to be a representation, action,
(iii) The owners and operators of the source and each TR SO
(a) Except as provided under § 97.618 concerning delegation of authority to make submissions, each submission under the TR SO
(b) The Administrator will accept or act on a submission made for a TR SO
(a)
(b)
(c)
(2) Within 30 days after any change in the owners and operators of a TR SO
(a) A complete certificate of representation for a designated representative or an alternate designated representative shall include the following elements in a format prescribed by the Administrator:
(1) Identification of the TR SO
(2) The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any alternate designated representative.
(3) A list of the owners and operators of the TR SO
(4) The following certification statements by the designated representative and any alternate designated representative—
(i) “I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the source and each TR SO
(ii) “I certify that I have all the necessary authority to carry out my duties and responsibilities under the TR SO
(iii) “Where there are multiple holders of a legal or equitable title to, or a leasehold interest in, a TR SO
(5) The signature of the designated representative and any alternate designated representative and the dates signed.
(b) Unless otherwise required by the Administrator, documents of agreement referred to in the certificate of representation shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(a) Once a complete certificate of representation under § 97.616 has been submitted and received, the Administrator will rely on the certificate of representation unless and until a superseding complete certificate of representation under § 97.616 is received by the Administrator.
(b) Except as provided in § 97.615(a) or (b), no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission, of a designated representative or alternate designated representative shall affect any representation, action, inaction, or submission of the designated representative or alternate designated representative or the finality of any decision or order by the Administrator under the TR SO
(c) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representative, including private legal disputes concerning the proceeds of TR SO
(a) A designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(b) An alternate designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(c) In order to delegate authority to make an electronic submission to the Administrator in accordance with paragraph (a) or (b) of this section, the designated representative or alternate designated representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(1) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such designated representative or alternate designated representative;
(2) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to as an “agent”);
(3) For each such natural person, a list of the type or types of electronic submissions under paragraph (a) or (b) of this section for which authority is delegated to him or her; and
(4) The following certification statements by such designated representative or alternate designated representative:
(i) “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.618(d) shall be deemed to be an electronic submission by me.”
(ii) “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.618(d), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 97.618 is terminated.”.
(d) A notice of delegation submitted under paragraph (c) of this section shall be effective, with regard to the designated representative or alternate designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such designated representative or alternate designated representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(e) Any electronic submission covered by the certification in paragraph (c)(4)(i) of this section and made in accordance with a notice of delegation effective under paragraph (d) of this section shall be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation.
(a)
(b)
(A) The authorized account representative and alternate authorized account representative shall be selected by an agreement binding on the persons who have an ownership interest with respect to TR SO
(B) The agreement by which the alternate authorized account representative is selected shall include a procedure for authorizing the alternate authorized account representative to act in lieu of the authorized account representative.
(ii) A complete application for a general account shall include the following elements in a format prescribed by the Administrator:
(A) Name, mailing address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the authorized account representative and any alternate authorized account representative;
(B) An identifying name for the general account;
(C) A list of all persons subject to a binding agreement for the authorized account representative and any alternate authorized account representative to
(D) The following certification statement by the authorized account representative and any alternate authorized account representative: “I certify that I was selected as the authorized account representative or the alternate authorized account representative, as applicable, by an agreement that is binding on all persons who have an ownership interest with respect to TR SO
(E) The signature of the authorized account representative and any alternate authorized account representative and the dates signed.
(iii) Unless otherwise required by the Administrator, documents of agreement referred to in the application for a general account shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(2)
(A) The authorized account representative of the general account shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each person who has an ownership interest with respect to TR SO
(B) Any alternate authorized account representative shall be authorized, and any representation, action, inaction, or submission by any alternate authorized account representative shall be deemed to be a representation, action, inaction, or submission by the authorized account representative.
(C) Each person who has an ownership interest with respect to TR SO
(iii) Except in this section, whenever the term “authorized account representative” is used in this subpart, the term shall be construed to include the authorized account representative or any alternate authorized account representative.
(3)
(ii) The alternate authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (b)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new alternate authorized account representative, the authorized account representative, and the persons with an ownership interest with respect to the TR SO
(iii)(A) In the event a person having an ownership interest with respect to TR SO
(B) Within 30 days after any change in the persons having an ownership interest with respect to SO
(4)
(ii) Except as provided in paragraph (b)(3)(i) or (ii) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any
(iii) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account, including private legal disputes concerning the proceeds of TR SO
(5)
(ii) An alternate authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(iii) In order to delegate authority to make an electronic submission to the Administrator in accordance with paragraph (b)(5)(i) or (ii) of this section, the authorized account representative or alternate authorized account representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(A) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such authorized account representative or alternate authorized account representative;
(B) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to as an “agent”);
(C) For each such natural person, a list of the type or types of electronic submissions under paragraph (b)(5)(i) or (ii) of this section for which authority is delegated to him or her;
(D) The following certification statement by such authorized account representative or alternate authorized account representative: “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am an authorized account representative or alternate authorized representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.620(b)(5)(iv) shall be deemed to be an electronic submission by me.”; and
(E) The following certification statement by such authorized account representative or alternate authorized account representative: “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.620(b)(5)(iv), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 97.620(b)(5) is terminated.”.
(iv) A notice of delegation submitted under paragraph (b)(5)(iii) of this section shall be effective, with regard to the authorized account representative or alternate authorized account representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such authorized account representative or alternate authorized account representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(v) Any electronic submission covered by the certification in paragraph (b)(5)(iii)(D) of this section and made in accordance with a notice of delegation effective under paragraph (b)(5)(iv) of this section shall be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation.
(6)(i) The authorized account representative or alternate authorized account representative of a general account may submit to the Administrator a request to close the account. Such request shall include a correctly submitted TR SO
(ii) If a general account has no TR SO
(c)
(d)
(a) By September 1, 2011, the Administrator will record in each TR SO
(b) By June 1, 2012 and June 1 of each year thereafter, the Administrator will record in each TR SO
(c) By September 1, 2012 and September 1 of each year thereafter, the Administrator will record in each TR SO
(d) When recording the allocation of TR SO
(a) An authorized account representative seeking recordation of a TR SO
(b) A TR SO
(1) The transfer includes the following elements, in a format prescribed by the Administrator:
(i) The account numbers established by the Administrator for both the transferor and transferee accounts;
(ii) The serial number of each TR SO
(iii) The name and signature of the authorized account representative of the transferor account and the date signed; and
(2) When the Administrator attempts to record the transfer, the transferor account includes each TR SO
(a) Within 5 business days (except as provided in paragraph (b) of this section) of receiving a TR SO
(b)(1) A TR SO
(2) A TR SO
(c) Where a TR SO
(d) Within 5 business days of recordation of a TR SO
(e) Within 10 business days of receipt of a TR SO
(1) A decision not to record the transfer, and
(2) The reasons for such non-recordation.
(a)
(1) Were allocated for the control period in the year or a prior year; and
(2) Are held in the source's compliance account as of the allowance transfer deadline for such control period.
(b)
(1) Until the amount of TR SO
(2) If there are insufficient TR SO
(c)(1)
(2)
(i) Any TR SO
(ii) Any TR SO
(d)
(e)
(a)
(1) Were allocated for the control period in the year or a prior year; and
(2) Are held in a compliance account, designated by the owner in accordance
(b)
(1) By June 1, 2015 and June 1 of each year thereafter, the Administrator will:
(i) Calculate, separately for each State, the total amount of SO
(ii) Promulgate a notice of availability of the results of the calculations required in paragraph (b)(1)(i) of this section, including separate calculations of the SO
(2) The Administrator will provide an opportunity for submission of objections to the calculations referenced by each notice described in paragraph (b)(1) of this section.
(i) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing whether the calculations for each TR SO
(ii) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i) of this section. By August 1 immediately after the promulgation of such notice, the Administrator will promulgate a notice of availability of any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(i) of this section.
(3) For each notice of data availability required in paragraph (b)(2)(ii) of this section and for any State identified in such notice as having TR SO
(i) By August 15 immediately after the promulgation of such notice, the designated representative of each TR SO
(A) Listing all the owners of each TR SO
(B) For each TR SO
(ii) By September 15 immediately after the promulgation of such notice, the Administrator will calculate, for each such State and each owner of one or more TR SO
(iii) The Administrator will provide an opportunity for submission of objections to the calculations referenced by the notice of data availability required in paragraph (b)(3)(ii) of this section.
(A) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing whether the calculations for each owner for the control period in the year involved are consistent with the SO
(B) The Administrator will adjust the calculations to the extent necessary to ensure that they are consistent with the data and provisions referenced in paragraph (b)(3)(iii)(A) of this section. By November 15 immediately after the promulgation of such notice, the Administrator will promulgate a notice of availability of any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(3)(iii)(A) of this section.
(4) By December 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(3)(iii)(B) of this section:
(i) Each owner identified, in such notice, as owning one or more TR SO
(ii) The authorized account representative for the compliance account designated under paragraph (b)(4)(i) of this section shall submit to the Administrator a statement, in a format prescribed by the Administrator, making this designation.
(5)(i) As of midnight of December 15 immediately after the promulgation of each notice of data availability required in paragraph (b)(3)(iii)(B) of this section, each owner described in paragraph (b)(4)(i) of this section shall hold in the compliance account designated by the owner in accordance with paragraph (b)(4)(ii) of this section the total amount of TR SO
(ii) Notwithstanding the allowance-holding deadline specified in paragraph (b)(5)(i) of this section, if December 15 is not a business day, then such allowance-holding deadline shall be midnight of the first business day thereafter.
(6) After December 15 (or the date described in paragraph (b)(5)(ii) of this section) immediately after the promulgation of each notice of data availability required in paragraph (b)(3)(iii)(B) of this section and after the recordation, in accordance with § 97.623, of TR SO
(i) Until the amount of TR SO
(ii) If there are insufficient TR SO
(7) Notwithstanding any other provision of this subpart and any revision, made by or submitted to the Administrator after the promulgation of the notices of data availability required in paragraphs (b)(2)(ii) and (b)(3)(iii)(B) of this section respectively for a control period, of any data used in making the calculations referenced in such notice, the amount of TR SO
(i) If any such data are revised by the Administrator as a result of a decision in or settlement of litigation concerning such data on appeal under part 78 of this chapter of such notice, or on appeal under section 307 of the Clean Air Act of a decision rendered under part 78 of this chapter on appeal of such notice, then the Administrator will use the data as so revised to recalculate the amounts of TR SO
(A) With regard to such litigation involving such notice required in paragraph (b)(2)(ii) of this section, such litigation under part 78 of this chapter, or the proceeding under part 78 of this chapter that resulted in the decision appealed in such litigation under section 307 of the Clean Air Act, was initiated no later than 30 days after promulgation of such notice required in paragraph (b)(2)(ii) of this section; and
(B) With regard to such litigation involving such notice required in paragraph (b)(3)(iii) of this section, such litigation under part 78 of this chapter, or the proceeding under part 78 of this chapter that resulted in the decision appealed in such litigation under section 307 of the Clean Air Act, was initiated no later than 30 days after promulgation of such notice required in paragraph (b)(3)(iii) of this section.
(ii) If any such data are revised by the owners and operators of a source whose designated representative submitted such data under paragraph (b)(3)(i) of this section, as a result of a decision in or settlement of litigation concerning such submission, then the Administrator will use the data as so revised to recalculate the amounts of TR SO
(iii) If the revised data are used to recalculate, in accordance with paragraphs (b)(7)(i) and (b)(7)(ii) of this section, the amount of TR SO
(A) Where the amount of TR SO
(B) For an owner for which the amount of TR SO
(C) Each TR SO
(c)(1)
(2)
(i) Any TR SO
(ii) Any TR SO
(d)
(a) A TR SO
(b) Any TR SO
The Administrator may, at his or her sole discretion and on his or her own motion, correct any error in any Allowance Management System account. Within 10 business days of making such correction, the Administrator will notify the authorized account representative for the account.
(a) The Administrator may review and conduct independent audits concerning any submission under the TR SO
(b) The Administrator may deduct TR SO
The owners and operators, and to the extent applicable, the designated representative, of a TR SO
(a)
(1) Install all monitoring systems required under this subpart for monitoring SO
(2) Successfully complete all certification tests required under § 97.631 and meet all other requirements of this subpart and part 75 of this chapter applicable to the monitoring systems under paragraph (a)(1) of this section; and
(3) Record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section.
(b)
(1) For the owner or operator of a TR SO
(2) For the owner or operator of a TR SO
(i) January 1, 2012; or
(ii) 180 calendar days, whichever occurs first, after the date on which the unit commences commercial operation.
(3) For the owner or operator of a TR SO
(4) Notwithstanding the dates in paragraphs (b)(1) and (2) of this section, for the owner or operator of a unit for which a TR opt-in application is submitted and not withdrawn and is not yet approved or disapproved, by the date specified in § 97.641(c).
(5) Notwithstanding the dates in paragraphs (b)(1) and (2) of this section, for the owner or operator of a TR SO
(c)
(d)
(2) No owner or operator of a TR SO
(3) No owner or operator of a TR SO
(4) No owner or operator of a TR SO
(i) During the period that the unit is covered by an exemption under § 97.605 that is in effect;
(ii) The owner or operator is monitoring emissions from the unit with another certified monitoring system approved, in accordance with the applicable provisions of this subpart and part 75 of this chapter, by the Administrator for use at that unit that provides emission data for the same
(iii) The designated representative submits notification of the date of certification testing of a replacement monitoring system for the retired or discontinued monitoring system in accordance with § 97.631(d)(3)(i).
(e)
(a) The owner or operator of a TR SO
(1) The monitoring system has been previously certified in accordance with part 75 of this chapter; and
(2) The applicable quality-assurance and quality-control requirements of § 75.21 of this chapter and appendices B and D to part 75 of this chapter are fully met for the certified monitoring system described in paragraph (a)(1) of this section.
(b) The recertification provisions of this section shall apply to a monitoring system under § 97.630(a)(1) exempt from initial certification requirements under paragraph (a) of this section.
(c) [Reserved]
(d) Except as provided in paragraph (a) of this section, the owner or operator of a TR SO
(1)
(2)
(3)
(i)
(ii)
(iii)
(iv)
(A)
(B)
(C)
(D)
(v)
(A) The owner or operator shall substitute the following values, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(g)(7), or § 75.21(e) of this chapter and continuing until the applicable date and hour specified under § 75.20(a)(5)(i) or (g)(7) of this chapter:
(1) For a disapproved SO
(2) For a disapproved moisture monitoring system and disapproved diluent gas monitoring system, respectively, the minimum potential moisture percentage and either the maximum potential CO
(3) For a disapproved fuel flowmeter system, the maximum potential fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 of this chapter.
(B) The designated representative shall submit a notification of certification retest dates and a new certification application in accordance with paragraphs (d)(3)(i) and (ii) of this section.
(C) The owner or operator shall repeat all certification tests or other requirements that were failed by the monitoring system, as indicated in the Administrator's notice of disapproval, no later than 30 unit operating days after the date of issuance of the notice of disapproval.
(e) The owner or operator of a unit qualified to use the low mass emissions (LME) excepted methodology under § 75.19 of this chapter shall meet the applicable certification and recertification requirements in §§ 75.19(a)(2) and 75.20(h) of this chapter. If the owner or operator of such a unit elects to certify a fuel flowmeter system for heat input determination, the owner or operator shall also meet the certification and recertification requirements in § 75.20(g) of this chapter.
(f) The designated representative of each unit for which the owner or operator intends to use an alternative monitoring system approved by the Administrator under subpart E of part 75 of this chapter shall comply with the applicable notification and application procedures of § 75.20(f) of this chapter.
(a)
(b)
The designated representative of a TR SO
(a)
(b)
(c)
(d)
(1) The designated representative shall report the SO
(i) For a unit that commences commercial operation before July 1, 2011, the calendar quarter covering January 1, 2012 through March 31, 2012;
(ii) For a unit that commences commercial operation on or after July 1, 2011, the calendar quarter corresponding to the earlier of the date of provisional certification or the applicable deadline for initial certification under § 97.630(b), unless that quarter is the third or fourth quarter of 2011, in which case reporting shall
(iii) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, for a unit for which a TR opt-in application is submitted and not withdrawn and is not yet approved or disapproved, the calendar quarter corresponding to the date specified in § 97.641(c); and
(iv) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, for a TR SO
(2) The designated representative shall submit each quarterly report to the Administrator within 30 days after the end of the calendar quarter covered by the report. Quarterly reports shall be submitted in the manner specified in § 75.64 of this chapter.
(3) For TR SO
(4) The Administrator may review and conduct independent audits of any quarterly report in order to determine whether the quarterly report meets the requirements of this subpart and part 75 of this chapter, including the requirement to use substitute data.
(i) The Administrator will notify the designated representative of any determination that the quarterly report fails to meet any such requirements and specify in such notification any corrections that the Administrator believes are necessary to make through resubmission of the quarterly report and a reasonable time period within which the designated representative must respond. Upon request by the designated representative, the Administrator may specify reasonable extensions of such time period. Within the time period (including any such extensions) specified by the Administrator, the designated representative shall resubmit the quarterly report with the corrections specified by the Administrator, except to the extent the designated representative provides information demonstrating that a specified correction is not necessary because the quarterly report already meets the requirements of this subpart and part 75 of this chapter that are relevant to the specified correction.
(ii) Any resubmission of a quarterly report shall meet the requirements applicable to the submission of a quarterly report under this subpart and part 75 of this chapter, except for the deadline set forth in paragraph (d)(2) of this section.
(e)
(1) The monitoring data submitted were recorded in accordance with the applicable requirements of this subpart and part 75 of this chapter, including the quality assurance procedures and specifications; and
(2) For a unit with add-on SO
(a) The designated representative of a TR SO
(b) A petition submitted under paragraph (a) of this section shall include sufficient information for the evaluation of the petition, including, at a minimum, the following information:
(i) Identification of each unit and source covered by the petition;
(ii) A detailed explanation of why the proposed alternative is being suggested in lieu of the requirement;
(iii) A description and diagram of any equipment and procedures used in the proposed alternative;
(iv) A demonstration that the proposed alternative is consistent with the purposes of the requirement for which the alternative is proposed and with the purposes of this subpart and part 75 of this chapter and that any adverse effect of approving the alternative will be
(v) Any other relevant information that the Administrator may require.
(c) Use of an alternative to any requirement referenced in paragraph (a) of this section is in accordance with this subpart only to the extent that the petition is approved in writing by the Administrator and that such use is in accordance with such approval.
(a) A TR SO
(1) Is located in a State;
(2) Is not a TR SO
(3) Is not covered by a retired unit exemption under § 72.8 of this chapter that is in effect; and
(4) Vents all of its emissions to a stack and can meet the monitoring, recordkeeping, and reporting requirements of this subpart.
(b) A TR SO
(c) Solely for purposes of applying the requirements of §§ 97.613 through 97.618 and §§ 97.630 through 97.635, a unit for which a TR opt-in application is submitted and not withdrawn and is not yet approved or disapproved under § 97.642 shall be deemed to be a TR SO
(d) Any TR SO
A unit meeting the requirements for a TR SO
(a)
(1) Identification of the unit and the source where the unit is located,
(2) A certification that the unit:
(i) Is not a TR SO
(ii) Is not covered by a retired unit exemption under § 72.8 of this chapter that is in effect;
(iii) Vents all of its emissions to a stack; and
(iv) Has documented heat input (greater than 0 mmBtu) for more than 876 hours during the 6 months immediately preceding submission of the TR opt-in application;
(3) A monitoring plan in accordance with §§ 97.630 through 97.635;
(4) A statement that the unit, if approved to become a TR SO
(5) A statement that the unit, if approved to become a TR SO
(6) A complete certificate of representation under § 97.616 consistent with § 97.640, if no designated representative has been previously designated for the source that includes the unit; and
(7) The signature of the designated representative and the date signed.
(b)
(c)
(ii) The monitoring and reporting under paragraph (c)(1)(i) of this section shall cover the entire control period immediately before the date on which the unit enters the TR SO
(2) To the extent the SO
(d)
(e)
(1) If the unit's SO
(2) If the unit's SO
(f)
(1) If the unit's SO
(2) If the unit's SO
(3) If the unit's SO
(g)
(1) After the designated representative submits the complete TR opt-in application, quarterly reports, and statement required in paragraphs (a), (c), and (d) of this section and if the Administrator determines that the designated representative shows that the unit meets the requirements for a TR SO
(2) Notwithstanding paragraphs (a) through (f) of this section, if, at any time before the TR opt-in application is approved under paragraph (g)(1) of this section, the Administrator determines that the unit cannot meet the requirements for a TR SO
(h)
A TR SO
(a)
(b)
(1) For the control period ending on the date on which the withdrawal is to be effective, the source that includes the TR SO
(2) After the requirement under paragraph (b)(1) of this section is met, the Administrator will deduct from the compliance account of the source that includes the TR SO
(c)
(2) If the requirements for withdrawal under paragraphs (a) and (b) of this section are not met, the Administrator will issue a written disapproval of the request to withdraw. The unit covered by the request shall continue to be a TR SO
(d)
(e)
(a)
(b)
(i) Any TR SO
(ii) If the date on which the TR SO
(A) Multiplied by the ratio of the number of days, in the control period, starting with the date on which the TR SO
(B) Rounded to the nearest allowance.
(2) The designated representative shall ensure that the compliance account of the source that includes the TR SO
(3)(i) For control periods starting after the date on which the TR SO
(ii) If the date on which the TR SO
(A) The amount of TR SO
(B) Multiplied by the ratio of the number of days, in the control period, starting with the date on which the TR SO
(C) Rounded to the nearest allowance.
(a)
(2) By no later than October 31 of the control period after the control period in which a TR SO
(b)
(1) The heat input (in mmBtu) used for calculating the TR SO
(i) The TR SO
(ii) The TR SO
(2) The SO
(i) The TR SO
(ii) The most stringent State or Federal SO
(3) The Administrator will issue TR SO
(c)
(2) By December 1 of the control period after the control period in which a TR SO
38. Part 97 is amended by adding subpart DDDDD to read as follows:
This subpart sets forth the general, designated representative, allowance, and monitoring provisions for the Transport Rule (TR) SO
The terms used in this subpart shall have the meanings set forth in this section as follows:
(1) Any organic material grown for the purpose of being converted to energy;
(2) Any organic byproduct of agriculture that can be converted into energy; or
(3) Any material that can be converted into energy and is nonmerchantable for other purposes, that is segregated from other material that is nonmerchantable for other purposes, and that is;
(i) A forest-related organic resource, including mill residues, precommercial thinnings, slash, brush, or byproduct from conversion of trees to merchantable material; or
(ii) A wood material, including pallets, crates, dunnage, manufacturing and construction materials (other than pressure-treated, chemically-treated, or painted wood products), and landscape or right-of-way tree trimmings.
(1) For a corporation, a president, secretary, treasurer, or vice-president or the corporation in charge of a principal business function or any other person who performs similar policy or decision making functions for the corporation;
(2) For a partnership or sole proprietorship, a general partner or the proprietor respectively; or
(3) For a local government entity or State, federal, or other public agency, a principal executive officer or ranking elected official.
(1) Operating as part of a cogeneration system; and
(2) Producing during the later of 1990 or the 12-month period starting on the date that the unit first produces electricity and during each calendar year after the later of 1990 or the calendar year in which the unit first produces electricity—
(i) For a topping-cycle unit,
(A) Useful thermal energy not less than 5 percent of total energy output; and
(B) Useful power that, when added to one-half of useful thermal energy produced, is not less then 42.5 percent of total energy input, if useful thermal energy produced is 15 percent or more of total energy output, or not less than 45 percent of total energy input, if useful thermal energy produced is less than 15 percent of total energy output.
(ii) For a bottoming-cycle unit, useful power not less than 45 percent of total energy input;
(3) Provided that the total energy input under paragraphs (2)(i)(B) and (2)(ii) of this definition shall equal the unit's total energy input from all fuel, except biomass if the unit is a boiler; and
(4) Provided that, if a topping-cycle unit is operated as part of a cogeneration system during a calendar year and the cogeneration system meets on a system-wide basis the requirement in paragraph (2)(i)(B) of this definition, the topping-cycle unit shall be deemed to meet such requirement during that calendar year.
(1) If the device is simple cycle, a compressor, a combustor, and a turbine and in which the flue gas resulting from the combustion of fuel in the combustor passes through the turbine, rotating the turbine; and
(2) If the device is combined cycle, the equipment described in paragraph (1) of this definition and any associated
(1) To have begun to produce steam, gas, or other heated medium used to generate electricity for sale or use, including test generation, except as provided in § 97.705.
(i) For a unit that is a TR SO
(ii) For a unit that is a TR SO
(2) Notwithstanding paragraph (1) of this definition and except as provided in § 97.705, for a unit that is not a TR SO
(i) For a unit with a date for commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that subsequently undergoes a physical change (other than replacement of the unit by a unit at the same source), such date shall remain the date of commencement of commercial operation of the unit, which shall continue to be treated as the same unit.
(ii) For a unit with a date for commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that is subsequently replaced by a unit at the same source, such date shall remain the replaced unit's date of commencement of commercial operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of commercial operation as defined in paragraph (1) or (2) of this definition as appropriate.
(1) To have begun any mechanical, chemical, or electronic process, including start-up of the unit's combustion chamber.
(2) For a unit that undergoes a physical change (other than replacement of the unit by a unit at the same source) after the date the unit commences operation as defined in paragraph (1) of this definition, such date shall remain the date of commencement of operation of the unit, which shall continue to be treated as the same unit.
(3) For a unit that is replaced by a unit at the same source after the date the unit commences operation as defined in paragraph (1) of this definition, such date shall remain the replaced unit's date of commencement of operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of operation as defined in paragraph (1), (2), or (3) of this definition as appropriate.
(1) A flow monitoring system, consisting of a stack flow rate monitor and an automated data acquisition and handling system and providing a permanent, continuous record of stack gas volumetric flow rate, in standard cubic feet per hour (scfh);
(2) A SO
(3) A moisture monitoring system, as defined in § 75.11(b)(2) of this chapter and providing a permanent, continuous record of the stack gas moisture content, in percent H
(4) A CO
(5) An O
(1) Natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material; or
(2) For purposes of applying §§ 97.704(b)(2)(i)(B), 97.704(b)(2)(ii)(B), and 97.704(b)(2)(iii), natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat.
(1) For the life of the unit;
(2) For a cumulative term of no less than 30 years, including contracts that permit an election for early termination; or
(3) For a period no less than 25 years or 70 percent of the economic useful life of the unit determined as of the time the unit is built, with option rights to purchase or release some portion of the nameplate capacity and associated energy generated by the unit at the end of the period.
(1) Any holder of any portion of the legal or equitable title in a TR SO
(2) Any holder of a leasehold interest in a TR SO
(3) Any purchaser of power from a TR SO
(4) Provided that, for purposes of applying the TR SO
(1) With regard to a State and control period for which the State assurance level is exceeded as described in § 97.706(c)(2)(iii)(A) and not as described in § 97.706(c)(2)(iii)(B), the owner's share of the State SO
(2) With regard to a State and control period for which the State assurance level is exceeded as described in § 97.706(c)(2)(iii)(B), the owner's share of the State SO
(1) With regard to a total amount of SO
(2) With regard to a State SO
(3) With regard to a State SO
(4) Provided that, in the case of a unit with more than one owner, the amount of tonnage of SO
(5) Provided that, where two or more units emit through a common stack that is the monitoring location from which SO
(i) The amount (rounded to the nearest ton) of SO
(ii) An amount determined in accordance with a methodology that the Administrator determines is consistent with the purposes of this definition and whose adverse effect (if any) the Administrator determines will be
(iii) An amount approved by the Administrator in response to a petition for an alternative requirement submitted in accordance with § 97.735; and
(6) Provided that, in the case of a unit that operates during, but is allocated no TR SO
(i) The unit's allowable SO
(ii) For a unit listed in appendix A to this subpart, the sum of the unit's SO
(1) For a topping-cycle unit, the use of reject heat from electricity production in a useful thermal energy application or process; or
(2) For a bottoming-cycle unit, the use of reject heat from useful thermal energy application or process in electricity production.
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or transmission and delivery;
(4) Provided that compliance with any “submission” or “service” deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt.
(1) Have been recorded by the Administrator in the account or transferred into the account by a correctly submitted, but not yet recorded, TR SO
(2) Have not been transferred out of the account by a correctly submitted, but not yet recorded, TR SO
(1) Made available to an industrial or commercial process (not a power production process), excluding any heat contained in condensate return or makeup water;
(2) Used in a heating application (
(3) Used in a space cooling application (
Measurements, abbreviations, and acronyms used in this subpart are defined as follows:
(a) Except as provided in paragraph (b) of this section:
(1) The following units in a State shall be TR SO
(2) If a stationary boiler or stationary combustion turbine that, under paragraph (a)(1) of this section, is not a TR SO
(b) Any unit in a State that otherwise is a TR SO
(1)(i) Any unit:
(A) Qualifying as a cogeneration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a cogeneration unit; and
(B) Not serving at any time, since the later of November 15, 1990 or the start-up of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe supplying in any calendar year more than one-third of the unit's potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.
(ii) If a unit qualifies as a cogeneration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and meets the requirements of paragraphs (b)(1)(i) of this section for at least one calendar year, but subsequently no longer meets such qualification and requirements, the unit shall become a TR SO
(2)(i) Any unit commencing operation before January 1, 1985:
(A) Qualifying as a solid waste incineration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a solid waste incineration unit; and
(B) With an average annual fuel consumption of fossil fuel for 1985-1987 less than 20 percent (on a Btu
(ii) Any unit commencing operation on or after January 1, 1985:
(A) Qualifying as a solid waste incineration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a solid waste incineration unit; and
(B) With an average annual fuel consumption of fossil fuel for the first 3 calendar years of operation less than 20 percent (on a Btu basis) and an average annual fuel consumption of fossil fuel for any 3 consecutive calendar years after 1990 less than 20 percent (on a Btu basis).
(iii) If a unit qualifies as a solid waste incineration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and meets the requirements of paragraph (b)(2)(i) or (ii) of this section for at least 3 consecutive calendar years, but subsequently no longer meets such qualification and requirements, the unit shall become a TR SO
(c) A certifying official of an owner or operator of any unit or other equipment may submit a petition (including any supporting documents) to the Administrator at any time for a determination concerning the applicability, under paragraphs (a) and (b) of this section, of the TR SO
(1)
(2)
(a)(1) Any TR SO
(2) The exemption under paragraph (a)(1) of this section shall become effective the day on which the TR SO
(b)
(2) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under paragraph (a) of this section shall retain, at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired.
(3) The owners and operators and, to the extent applicable, the designated representative of a unit exempt under paragraph (a) of this section shall comply with the requirements of the TR SO
(4) A unit exempt under paragraph (a) of this section shall lose its exemption on the first date on which the unit resumes operation. Such unit shall be treated, for purposes of applying allocation, monitoring, reporting, and recordkeeping requirements under this subpart, as a unit that commences commercial operation on the first date on which the unit resumes operation.
(a)
(b)
(2) The emissions data determined in accordance with §§ 97.730 through 97.735 shall be used to calculate allocations of TR SO
(c)
(ii) If a TR SO
(A) The owners and operators of the source and each TR SO
(B) Each ton of such excess emissions and each day of such control period shall constitute a separate violation of this subpart and the Clean Air Act.
(2)
(A) The quotient (rounded to the nearest whole number) of the amount by which the owner's share of such SO
(B) The amount by which total SO
(ii) The owner shall hold the TR SO
(iii) The total amount of SO
(A) If such total amount of SO
(B) If, with regard to a control period in 2016 or any year thereafter, the sum, divided by three, of such total amount of SO
(C) Provided that the amount by which such total amount of SO
(iv) It shall not be a violation of this subpart or of the Clean Air Act if the total amount of SO
(v) To the extent an owner fails to hold TR SO
(A) The owner shall pay any fine, penalty, or assessment or comply with any other remedy imposed under the Clean Air Act; and
(B) Each TR SO
(3)
(i) Under paragraph (c)(1) of this section for the control period starting on the later of January 1, 2012 or the deadline for meeting the unit's monitor certification requirements under § 97.730(b) and for each control period thereafter; and
(ii) Under paragraph (c)(2) of this section for the control period starting on the later of January 1, 2014 or the deadline for meeting the unit's monitor certification requirements under § 97.730(b) and for each control period thereafter.
(4)
(5)
(6)
(ii) Notwithstanding any other provision of this subpart, the Administrator has the authority to terminate or limit such authorization to the extent the Administrator determines is necessary or appropriate to implement any provision of the Clean Air Act.
(7)
(d)
(2) A description of whether a unit is required to monitor and report SO
(e)
(i) The certificate of representation under § 97.716 for the designated representative for the source and each TR SO
(ii) All emissions monitoring information, in accordance with this subpart.
(iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under, or to demonstrate compliance with the requirements of, the TR SO
(2) The designated representative of a TR SO
(f)
(2) Any provision of the TR SO
(g)
(a) Unless otherwise stated, any time period scheduled, under the TR SO
(b) Unless otherwise stated, any time period scheduled, under the TR SO
(c) Unless otherwise stated, if the final day of any time period, under the TR SO
The administrative appeal procedures for decisions of the Administrator under the TR SO
(a) The State SO
(b) The States' one-year and three-year variability limits for the State SO
(a)
(2) Notwithstanding paragraph (a)(1) of this section, if a unit listed in appendix A to this subpart as being allocated TR SO
(b)
(2) For each notice of data availability required in paragraph (b)(1) of this section, the Administrator will provide an opportunity for submission of objections to the calculations referenced in such notice.
(i) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing whether the calculations are in accordance with § 97.712 and §§ 97.706(b)(2) and 97.730 through 97.735.
(ii) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i) of this section. By September 1 immediately after the promulgation of such notice, the Administrator will promulgate a notice of availability of any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(i) of this section.
(c)
(1) Except as provided in paragraph (c)(2) or (3) of this section, the Administrator will not record such TR SO
(2) If the Administrator already recorded such TR SO
(3) If the Administrator already recorded such TR SO
(4) The Administrator will transfer the TR SO
(a) For each control period in 2012 and thereafter, the Administrator will allocate, in accordance with the following procedures, TR SO
(1) The Administrator will establish a separate new unit set-aside for each State for each control period in a given year. Each new unit set-aside will be allocated TR SO
(2) The designated representative of such TR SO
(i) The request must be submitted on or before May 1 of the first control period for which TR SO
(ii) For each control period for which an allocation is sought, the request must be for TR SO
(3) The Administrator will review each TR SO
(i) After May 1 of such control period, the Administrator will determine the sum of the TR SO
(ii) If the amount of TR SO
(iii) If the amount of TR SO
(iv) The Administrator will notify, through the promulgation of the notices of data availability described in § 97.711(b), each designated representative that submitted an allowance allocation request of the amount of TR SO
(b) If, after completion of the procedures under paragraph (a)(4) of this section for a control period, any unallocated TR SO
(a) Except as provided under § 97.715, each TR SO
(1) The designated representative shall be selected by an agreement binding on the owners and operators of the source and all TR SO
(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.716:
(i) The designated representative shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of the source and each TR SO
(ii) The owners and operators of the source and each TR SO
(b) Except as provided under § 97.715, each TR SO
(1) The alternate designated representative shall be selected by an agreement binding on the owners and operators of the source and all TR SO
(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.716,
(i) The alternate designated representative shall be authorized;
(ii) Any representation, action, inaction, or submission by the alternate designated representative shall be deemed to be a representation, action,
(iii) The owners and operators of the source and each TR SO
(c) Except in this section, § 97.702, and §§ 97.714 through 97.718, whenever the term “designated representative” is used in this subpart, the term shall be construed to include the designated representative or any alternate designated representative.
(a) Except as provided under § 97.718 concerning delegation of authority to make submissions, each submission under the TR SO
(b) The Administrator will accept or act on a submission made for a TR SO
(a)
(b)
(c)
(2) Within 30 days after any change in the owners and operators of a TR SO
(a) A complete certificate of representation for a designated representative or an alternate designated representative shall include the following elements in a format prescribed by the Administrator:
(1) Identification of the TR SO
(2) The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any alternate designated representative.
(3) A list of the owners and operators of the TR SO
(4) The following certification statements by the designated representative and any alternate designated representative—
(i) “I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the source and each TR SO
(ii) “I certify that I have all the necessary authority to carry out my duties and responsibilities under the TR SO
(iii) “Where there are multiple holders of a legal or equitable title to, or a leasehold interest in, a TR SO
(5) The signature of the designated representative and any alternate designated representative and the dates signed.
(b) Unless otherwise required by the Administrator, documents of agreement referred to in the certificate of representation shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(a) Once a complete certificate of representation under § 97.716 has been submitted and received, the Administrator will rely on the certificate of representation unless and until a superseding complete certificate of representation under § 97.716 is received by the Administrator.
(b) Except as provided in § 97.715(a) or (b), no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission, of a designated representative or alternate designated representative shall affect any representation, action, inaction, or submission of the designated representative or alternate designated representative or the finality of any decision or order by the Administrator under the TR SO
(c) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representative, including private legal disputes concerning the proceeds of TR SO
(a) A designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(b) An alternate designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(c) In order to delegate authority to make an electronic submission to the Administrator in accordance with paragraph (a) or (b) of this section, the designated representative or alternate designated representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(1) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such designated representative or alternate designated representative;
(2) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to as an “agent”);
(3) For each such natural person, a list of the type or types of electronic submissions under paragraph (a) or (b) of this section for which authority is delegated to him or her; and
(4) The following certification statements by such designated representative or alternate designated representative:
(i) “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.718(d) shall be deemed to be an electronic submission by me.”
(ii) “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.718(d), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 97.718 is terminated.”.
(d) A notice of delegation submitted under paragraph (c) of this section shall be effective, with regard to the designated representative or alternate designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such designated representative or alternate designated representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(e) Any electronic submission covered by the certification in paragraph (c)(4)(i) of this section and made in accordance with a notice of delegation effective under paragraph (d) of this section shall be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation.
(a)
(b)
(A) The authorized account representative and alternate authorized account representative shall be selected by an agreement binding on the persons who have an ownership interest with respect to TR SO
(B) The agreement by which the alternate authorized account representative is selected shall include a procedure for authorizing the alternate authorized account representative to act in lieu of the authorized account representative.
(ii) A complete application for a general account shall include the following elements in a format prescribed by the Administrator:
(A) Name, mailing address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the authorized account representative and any alternate authorized account representative;
(B) An identifying name for the general account;
(C) A list of all persons subject to a binding agreement for the authorized account representative and any alternate authorized account representative to
(D) The following certification statement by the authorized account representative and any alternate authorized account representative: “I certify that I was selected as the authorized account representative or the alternate authorized account representative, as applicable, by an agreement that is binding on all persons who have an ownership interest with respect to TR SO
(E) The signature of the authorized account representative and any alternate authorized account representative and the dates signed.
(iii) Unless otherwise required by the Administrator, documents of agreement referred to in the application for a general account shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(2)
(A) The authorized account representative of the general account shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each person who has an ownership interest with respect to TR SO
(B) Any alternate authorized account representative shall be authorized, and any representation, action, inaction, or submission by any alternate authorized account representative shall be deemed to be a representation, action, inaction, or submission by the authorized account representative.
(C) Each person who has an ownership interest with respect to TR SO
(ii) Except as provided in paragraph (b)(5) of this section concerning delegation of authority to make submissions, each submission concerning the general account shall be made, signed, and certified by the authorized account representative or any alternate authorized account representative for the persons having an ownership interest with respect to TR SO
(iii) Except in this section, whenever the term “authorized account representative” is used in this subpart, the term shall be construed to include the authorized account representative or any alternate authorized account representative.
(3)
(ii) The alternate authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (b)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new alternate authorized account representative, the authorized account representative, and the persons with an ownership interest with respect to the TR SO
(iii)(A) In the event a person having an ownership interest with respect to TR SO
(B) Within 30 days after any change in the persons having an ownership interest with respect to SO
(4)
(ii) Except as provided in paragraph (b)(3)(i) or (ii) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any
(iii) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account, including private legal disputes concerning the proceeds of TR SO
(5)
(ii) An alternate authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(iii) In order to delegate authority to make an electronic submission to the Administrator in accordance with paragraph (b)(5)(i) or (ii) of this section, the authorized account representative or alternate authorized account representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(A) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such authorized account representative or alternate authorized account representative;
(B) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to as an “agent”);
(C) For each such natural person, a list of the type or types of electronic submissions under paragraph (b)(5)(i) or (ii) of this section for which authority is delegated to him or her;
(D) The following certification statement by such authorized account representative or alternate authorized account representative: “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am an authorized account representative or alternate authorized representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.720(b)(5)(iv) shall be deemed to be an electronic submission by me.”; and
(E) The following certification statement by such authorized account representative or alternate authorized account representative: “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.720(b)(5)(iv), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 97.720(b)(5) is terminated.”.
(iv) A notice of delegation submitted under paragraph (b)(5)(iii) of this section shall be effective, with regard to the authorized account representative or alternate authorized account representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such authorized account representative or alternate authorized account representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(v) Any electronic submission covered by the certification in paragraph (b)(5)(iii)(D) of this section and made in accordance with a notice of delegation effective under paragraph (b)(5)(iv) of this section shall be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation.
(6)(i) The authorized account representative or alternate authorized account representative of a general account may submit to the Administrator a request to close the account. Such request shall include a correctly submitted TR SO
(ii) If a general account has no TR SO
(c)
(d)
(a) By September 1, 2011, the Administrator will record in each TR SO
(b) By June 1, 2012 and June 1 of each year thereafter, the Administrator will record in each TR SO
(c) By September 1, 2012 and September 1 of each year thereafter, the Administrator will record in each TR SO
(d) When recording the allocation of TR SO
(a) An authorized account representative seeking recordation of a TR SO
(b) A TR SO
(1) The transfer includes the following elements, in a format prescribed by the Administrator:
(i) The account numbers established by the Administrator for both the transferor and transferee accounts;
(ii) The serial number of each TR SO
(iii) The name and signature of the authorized account representative of the transferor account and the date signed; and
(2) When the Administrator attempts to record the transfer, the transferor account includes each TR SO
(a) Within 5 business days (except as provided in paragraph (b) of this section) of receiving a TR SO
(b)(1) A TR SO
(2) A TR SO
(c) Where a TR SO
(d) Within 5 business days of recordation of a TR SO
(e) Within 10 business days of receipt of a TR SO
(1) A decision not to record the transfer, and
(2) The reasons for such non-recordation.
(a)
(1) Were allocated for the control period in the year or a prior year; and
(2) Are held in the source's compliance account as of the allowance transfer deadline for such control period.
(b)
(1) Until the amount of TR SO
(2) If there are insufficient TR SO
(c)(1)
(2)
(i) Any TR SO
(ii) Any TR SO
(d)
(e)
(a)
(1) Were allocated for the control period in the year or a prior year; and
(2) Are held in a compliance account, designated by the owner in accordance with paragraph (b)(4)(ii) of this section,
(b)
(1) By June 1, 2015 and June 1 of each year thereafter, the Administrator will:
(i) Calculate, separately for each State, the total amount of SO
(ii) Promulgate a notice of availability of the results of the calculations required in paragraph (b)(1)(i) of this section, including separate calculations of the SO
(2) The Administrator will provide an opportunity for submission of objections to the calculations referenced by each notice described in paragraph (b)(1) of this section.
(i) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing whether the calculations for each TR SO
(ii) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i) of this section. By August 1 immediately after the promulgation of such notice, the Administrator will promulgate a notice of availability of any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(i) of this section.
(3) For each notice of data availability required in paragraph (b)(2)(ii) of this section and for any State identified in such notice as having TR SO
(i) By August 15 immediately after the promulgation of such notice, the designated representative of each TR SO
(A) Listing all the owners of each TR SO
(B) For each TR SO
(ii) By September 15 immediately after the promulgation of such notice, the Administrator will calculate, for each such State and each owner of one or more TR SO
(iii) The Administrator will provide an opportunity for submission of objections to the calculations referenced by the notice of data availability required in paragraph (b)(3)(ii) of this section.
(A) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing whether the calculations for each owner for the control period in the year involved are consistent with the SO
(B) The Administrator will adjust the calculations to the extent necessary to ensure that they are consistent with the data and provisions referenced in paragraph (b)(3)(iii)(A) of this section. By November 15 immediately after the promulgation of such notice, the Administrator will promulgate a notice of availability of any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(3)(iii)(A) of this section.
(4) By December 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(3)(iii)(B) of this section:
(i) Each owner identified, in such notice, as owning one or more TR SO
(ii) The authorized account representative for the compliance account designated under paragraph (b)(4)(i) of this section shall submit to the Administrator a statement, in a format prescribed by the Administrator, making this designation.
(5)(i) As of midnight of December 15 immediately after the promulgation of each notice of data availability required in paragraph (b)(3)(iii)(B) of this section, each owner described in paragraph (b)(4)(i) of this section shall hold in the compliance account designated by the owner in accordance with paragraph (b)(4)(ii) of this section the total amount of TR SO
(ii) Notwithstanding the allowance-holding deadline specified in paragraph (b)(5)(i) of this section, if December 15 is not a business day, then such allowance-holding deadline shall be midnight of the first business day thereafter.
(6) After December 15 (or the date described in paragraph (b)(5)(ii) of this section) immediately after the promulgation of each notice of data availability required in paragraph (b)(3)(iii)(B) of this section and after the recordation, in accordance with § 97.723, of TR SO
(i) Until the amount of TR SO
(ii) If there are insufficient TR SO
(7) Notwithstanding any other provision of this subpart and any revision, made by or submitted to the Administrator after the promulgation of the notices of data availability required in paragraphs (b)(2)(ii) and (b)(3)(iii)(B) of this section respectively for a control period, of any data used in making the calculations referenced in such notice, the amount of TR SO
(i) If any such data are revised by the Administrator as a result of a decision in or settlement of litigation concerning such data on appeal under part 78 of this chapter of such notice, or on appeal under section 307 of the Clean Air Act of a decision rendered under part 78 of this chapter on appeal of such notice, then the Administrator will use the data as so revised to recalculate the amounts of TR SO
(A) With regard to such litigation involving such notice required in paragraph (b)(2)(ii) of this section, such litigation under part 78 of this chapter, or the proceeding under part 78 of this chapter that resulted in the decision appealed in such litigation under section 307 of the Clean Air Act, was initiated no later than 30 days after promulgation of such notice required in paragraph (b)(2)(ii) of this section; and
(B) With regard to such litigation involving such notice required in paragraph (b)(3)(iii) of this section, such litigation under part 78 of this chapter, or the proceeding under part 78 of this chapter that resulted in the decision appealed in such litigation under section 307 of the Clean Air Act, was initiated no later than 30 days after promulgation of such notice required in paragraph (b)(3)(iii) of this section.
(ii) If any such data are revised by the owners and operators of a source whose designated representative submitted such data under paragraph (b)(3)(i) of this section, as a result of a decision in or settlement of litigation concerning such submission, then the Administrator will use the data as so revised to recalculate the amounts of TR SO
(iii) If the revised data are used to recalculate, in accordance with paragraphs (b)(7)(i) and (b)(7)(ii) of this section, the amount of TR SO
(A) Where the amount of TR SO
(B) For an owner for which the amount of TR SO
(C) Each TR SO
(c)(1)
(2)
(i) Any TR SO
(ii) Any TR SO
(d)
(a) A TR SO
(b) Any TR SO
The Administrator may, at his or her sole discretion and on his or her own motion, correct any error in any Allowance Management System account. Within 10 business days of making such correction, the Administrator will notify the authorized account representative for the account.
(a) The Administrator may review and conduct independent audits concerning any submission under the TR SO
(b) The Administrator may deduct TR SO
The owners and operators, and to the extent applicable, the designated representative, of a TR SO
(1) Install all monitoring systems required under this subpart for monitoring SO
(2) Successfully complete all certification tests required under § 97.731 and meet all other requirements of this subpart and part 75 of this chapter applicable to the monitoring systems under paragraph (a)(1) of this section; and
(3) Record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section.
(1) For the owner or operator of a TR SO
(2) For the owner or operator of a TR SO
(i) January 1, 2012; or
(ii) 180 calendar days, whichever occurs first, after the date on which the unit commences commercial operation.
(3) For the owner or operator of a TR SO
(4) Notwithstanding the dates in paragraphs (b)(1) and (2) of this section, for the owner or operator of a unit for which a TR opt-in application is submitted and not withdrawn and is not yet approved or disapproved, by the date specified in § 97.741(c).
(5) Notwithstanding the dates in paragraphs (b)(1) and (2) of this section, for the owner or operator of a TR SO
(2) No owner or operator of a TR SO
(3) No owner or operator of a TR SO
(4) No owner or operator of a TR SO
(i) During the period that the unit is covered by an exemption under § 97.705 that is in effect;
(ii) The owner or operator is monitoring emissions from the unit with another certified monitoring system approved, in accordance with the applicable provisions of this subpart and part 75 of this chapter, by the Administrator for use at that unit that provides emission data for the same
(iii) The designated representative submits notification of the date of certification testing of a replacement monitoring system for the retired or discontinued monitoring system in accordance with § 97.731(d)(3)(i).
(a) The owner or operator of a TR SO
(1) The monitoring system has been previously certified in accordance with part 75 of this chapter; and
(2) The applicable quality-assurance and quality-control requirements of § 75.21 of this chapter and appendices B and D to part 75 of this chapter are fully met for the certified monitoring system described in paragraph (a)(1) of this section.
(b) The recertification provisions of this section shall apply to a monitoring system under § 97.730(a)(1) exempt from initial certification requirements under paragraph (a) of this section.
(c) [Reserved]
(d) Except as provided in paragraph (a) of this section, the owner or operator of a TR SO
(1)
(2)
(3)
(i)
(ii)
(iii)
(iv)
(A)
(B)
(C)
(D)
(v)
(A) The owner or operator shall substitute the following values, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(g)(7), or § 75.21(e) of this chapter and continuing until the applicable date and hour specified under § 75.20(a)(5)(i) or (g)(7) of this chapter:
(1) For a disapproved SO
(2) For a disapproved moisture monitoring system and disapproved diluent gas monitoring system, respectively, the minimum potential moisture percentage and either the maximum potential CO
(3) For a disapproved fuel flowmeter system, the maximum potential fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 of this chapter.
(B) The designated representative shall submit a notification of certification retest dates and a new certification application in accordance with paragraphs (d)(3)(i) and (ii) of this section.
(C) The owner or operator shall repeat all certification tests or other requirements that were failed by the monitoring system, as indicated in the Administrator's notice of disapproval, no later than 30 unit operating days after the date of issuance of the notice of disapproval.
(e) The owner or operator of a unit qualified to use the low mass emissions (LME) excepted methodology under § 75.19 of this chapter shall meet the applicable certification and recertification requirements in §§ 75.19(a)(2) and 75.20(h) of this chapter. If the owner or operator of such a unit elects to certify a fuel flowmeter system for heat input determination, the owner or operator shall also meet the certification and recertification requirements in § 75.20(g) of this chapter.
(f) The designated representative of each unit for which the owner or operator intends to use an alternative monitoring system approved by the Administrator under subpart E of part 75 of this chapter shall comply with the applicable notification and application procedures of § 75.20(f) of this chapter.
(a)
(b)
The designated representative of a TR SO
(1) The designated representative shall report the SO
(i) For a unit that commences commercial operation before July 1, 2011, the calendar quarter covering January 1, 2012 through March 31, 2012;
(ii) For a unit that commences commercial operation on or after July 1, 2011, the calendar quarter corresponding to the earlier of the date of provisional certification or the applicable deadline for initial certification under § 97.730(b), unless that quarter is the third or fourth quarter of 2011, in which case reporting shall
(iii) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, for a unit for which a TR opt-in application is submitted and not withdrawn and is not yet approved or disapproved, the calendar quarter corresponding to the date specified in § 97.741(c); and
(iv) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, for a TR SO
(2) The designated representative shall submit each quarterly report to the Administrator within 30 days after the end of the calendar quarter covered by the report. Quarterly reports shall be submitted in the manner specified in § 75.64 of this chapter.
(3) For TR SO
(4) The Administrator may review and conduct independent audits of any quarterly report in order to determine whether the quarterly report meets the requirements of this subpart and part 75 of this chapter, including the requirement to use substitute data.
(i) The Administrator will notify the designated representative of any determination that the quarterly report fails to meet any such requirements and specify in such notification any corrections that the Administrator believes are necessary to make through resubmission of the quarterly report and a reasonable time period within which the designated representative must respond. Upon request by the designated representative, the Administrator may specify reasonable extensions of such time period. Within the time period (including any such extensions) specified by the Administrator, the designated representative shall resubmit the quarterly report with the corrections specified by the Administrator, except to the extent the designated representative provides information demonstrating that a specified correction is not necessary because the quarterly report already meets the requirements of this subpart and part 75 of this chapter that are relevant to the specified correction.
(ii) Any resubmission of a quarterly report shall meet the requirements applicable to the submission of a quarterly report under this subpart and part 75 of this chapter, except for the deadline set forth in paragraph (d)(2) of this section.
(e)
(1) The monitoring data submitted were recorded in accordance with the applicable requirements of this subpart and part 75 of this chapter, including the quality assurance procedures and specifications; and
(2) For a unit with add-on SO
(a) The designated representative of a TR SO
(b) A petition submitted under paragraph (a) of this section shall include sufficient information for the evaluation of the petition, including, at a minimum, the following information:
(i) Identification of each unit and source covered by the petition;
(ii) A detailed explanation of why the proposed alternative is being suggested in lieu of the requirement;
(iii) A description and diagram of any equipment and procedures used in the proposed alternative;
(iv) A demonstration that the proposed alternative is consistent with the purposes of the requirement for which the alternative is proposed and with the purposes of this subpart and part 75 of this chapter and that any adverse effect of approving the alternative will be
(v) Any other relevant information that the Administrator may require.
(c) Use of an alternative to any requirement referenced in paragraph (a) of this section is in accordance with this subpart only to the extent that the petition is approved in writing by the Administrator and that such use is in accordance with such approval.
(a) A TR SO
(1) Is located in a State;
(2) Is not a TR SO
(3) Is not covered by a retired unit exemption under § 72.8 of this chapter that is in effect; and
(4) Vents all of its emissions to a stack and can meet the monitoring, recordkeeping, and reporting requirements of this subpart.
(b) A TR SO
(c) Solely for purposes of applying the requirements of §§ 97.713 through 97.718 and §§ 97.730 through 97.735, a unit for which a TR opt-in application is submitted and not withdrawn and is not yet approved or disapproved under § 97.742 shall be deemed to be a TR SO
(d) Any TR SO
A unit meeting the requirements for a TR SO
(a)
(1) Identification of the unit and the source where the unit is located,
(2) A certification that the unit:
(i) Is not a TR SO
(ii) Is not covered by a retired unit exemption under § 72.8 of this chapter that is in effect;
(iii) Vents all of its emissions to a stack; and
(iv) Has documented heat input (greater than 0 mmBtu) for more than 876 hours during the 6 months immediately preceding submission of the TR opt-in application;
(3) A monitoring plan in accordance with §§ 97.730 through 97.735;
(4) A statement that the unit, if approved to become a TR SO
(5) A statement that the unit, if approved to become a TR SO
(6) A complete certificate of representation under § 97.716 consistent with § 97.740, if no designated representative has been previously designated for the source that includes the unit; and
(7) The signature of the designated representative and the date signed.
(b)
(c)
(ii) The monitoring and reporting under paragraph (c)(1)(i) of this section shall cover the entire control period immediately before the date on which the unit enters the TR SO
(2) To the extent the SO
(d)
(e)
(1) If the unit's SO
(2) If the unit's SO
(f)
(1) If the unit's SO
(2) If the unit's SO
(3) If the unit's SO
(g)
(1) After the designated representative submits the complete TR opt-in application, quarterly reports, and statement required in paragraphs (a), (c), and (d) of this section and if the Administrator determines that the designated representative shows that the unit meets the requirements for a TR SO
(2) Notwithstanding paragraphs (a) through (f) of this section, if, at any time before the TR opt-in application is approved under paragraph (g)(1) of this section, the Administrator determines that the unit cannot meet the requirements for a TR SO
(h)
A TR SO
(a)
(b)
(1) For the control period ending on the date on which the withdrawal is to be effective, the source that includes the TR SO
(2) After the requirement under paragraph (b)(1) of this section is met, the Administrator will deduct from the compliance account of the source that includes the TR SO
(c)
(2) If the requirements for withdrawal under paragraphs (a) and (b) of this section are not met, the Administrator will issue a written disapproval of the request to withdraw. The unit covered by the request shall continue to be a TR SO
(d)
(e)
(a)
(b)
(i) Any TR SO
(ii) If the date on which the TR SO
(A) Multiplied by the ratio of the number of days, in the control period, starting with the date on which the TR SO
(B) Rounded to the nearest allowance.
(2) The designated representative shall ensure that the compliance account of the source that includes the TR SO
(3)(i) For control periods starting after the date on which the TR SO
(ii) If the date on which the TR SO
(A) The amount of TR SO
(B) Multiplied by the ratio of the number of days, in the control period, starting with the date on which the TR SO
(C) Rounded to the nearest allowance.
(a)
(2) By no later than October 31 of the control period after the control period in which a TR SO
(b)
(1) The heat input (in mmBtu) used for calculating the TR SO
(i) The TR SO
(ii) The TR SO
(2) The SO
(i) The TR SO
(ii) The most stringent State or Federal SO
(3) The Administrator will issue TR SO
(c)
(2) By December 1 of the control period after the control period in which a TR SO
Import Administration, International Trade Administration, Department of Commerce.
On March 12, 2010, the Department of Commerce (the “Department”) published the
Paul Walker or Dana Griffies, AD/CVD Operations, Office 9, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue, NW., Washington, DC 20230; telephone: (202) 482-0413 or (202) 482-3023, respectively.
On April 1, 2010, Liaoning Mayerton Refractories Co., Ltd. and Dalian Mayerton Refractories Co., Ltd. (collectively, “Mayerton”) stated that it would no longer participate in the investigation.
For RHI, the Department conducted sales verification from April 12-16, 2010 and factors of production (“FOP”) verification May 17-20, 2010.
Between June 14, 2010 and July 14, 2010, the Department placed labor wage rate data on the record and invited parties to comment on the Department's labor wage rate methodology.
Between June 18, 2010 and July 16, 2010, we received case and rebuttal briefs from the Petitioner,
All issues raised in the case and rebuttal briefs by parties to this investigation are addressed in the “Investigation of Magnesia Carbon Bricks from the People's Republic of China: Issues and Decision Memorandum for the Final Determination” (“I&D Memo”), dated concurrently with this notice and which is hereby adopted by this notice. A list of the issues which parties raised, and to which we respond in the I&D Memo, are attached to this notice as Appendix I. The I&D Memo is a public document and is on file in the Central Records Unit (“CRU”), Room 1117, and is accessible on the World Wide Web at
Based on our analysis of information on the record of this investigation, we have made changes to RHI's margin calculation for the final determination. For the final determination, we have adjusted the surrogate value for fused magnesia to exclude certain aberrational data and adopted a new methodology for calculating the surrogate value for labor.
Regarding Mayerton, for the final determination, we have applied total adverse facts available (“AFA”) for its failure to participate and included it as part of the PRC-wide entity. For more information
The merchandise under investigation consists of certain chemically-bonded (resin or pitch), magnesia carbon bricks with a magnesia component of at least 70 percent magnesia (“MgO”) by weight, regardless of the source of raw materials for the MgO, with carbon levels ranging from trace amounts to 30 percent by weight, regardless of enhancements (for example, magnesia carbon bricks can be enhanced with coating, grinding, tar impregnation or coking, high temperature heat treatments, anti-slip treatments or metal casing) and regardless of whether or not antioxidants are present (for example, antioxidants can be added to the mix from trace amounts to 15 percent by weight as various metals, metal alloys, and metal carbides). Certain magnesia carbon bricks that are the subject of this
Section 776(a)(2) of the Act provides that if an interested party: (A) Withholds information that has been requested by the Department; (B) fails to provide such information in a timely manner or in the form or manner requested, subject to subsections 782(c)(1) and (e) of the Act; (C) significantly impedes a determination under the antidumping statute; or (D) provides such information but the information cannot be verified, the Department shall, subject to subsection 782(d) of the Act, use facts otherwise available in reaching the applicable determination.
Section 782(c)(1) of the Act provides that if an interested party “promptly after receiving a request from {the Department} for information, notifies {the Department} that such party is unable to submit the information in the requested form and manner, together with a full explanation and suggested alternative form in which such party is able to submit the information,” the Department may modify the requirements to avoid imposing an unreasonable burden on that party.
Section 782(d) of the Act provides that, if the Department determines that a response to a request for information does not comply with the request, the Department will inform the person submitting the response of the nature of the deficiency and shall, to the extent practicable, provide that person the opportunity to remedy or explain the deficiency. If that person submits further information that continues to be unsatisfactory, or this information is not submitted within the applicable time limits, the Department may, subject to section 782(e), disregard all or part of the original and subsequent responses, as appropriate.
Section 782(e) of the Act states that the Department shall not decline to consider information deemed “deficient” under section 782(d) if: (1) The information is submitted by the established deadline; (2) the information can be verified; (3) the information is not so incomplete that it cannot serve as a reliable basis for reaching the applicable determination; (4) the interested party has demonstrated that it acted to the best of its ability; and (5) the information can be used without undue difficulties.
Furthermore, section 776(b) of the Act states that if the administering authority finds that an interested party has not acted to the best of its ability to comply with a request for information, the administering authority may, in reaching its determination, use an inference that is adverse to that party. The adverse inference may be based upon: (1) The petition, (2) a final determination in the investigation under this title, (3) any previous review under section 751 of the Act or determination under section 753 of the Act, or (4) any other information placed on the record.
As noted above, Mayerton withdrew from the instant investigation. By ceasing to participate in the investigation, Mayerton prevented the Department from verifying the accuracy of its information as provided by section 782(i) of the Act, and thus, failed to demonstrate eligibility for a separate rate.
As provided in section 782(i) of the Act, we conducted verification of the information submitted by RHI, New Century and Fengchi for use in our final determination.
In the
In the
No other information has been placed on the record since the
In proceedings involving non-market-economy (“NME”) countries, the Department begins with a rebuttable presumption that all companies within the country are subject to government control and, thus, should be assigned a single antidumping duty deposit rate. It is the Department's policy to assign all exporters of merchandise subject to an investigation in an NME country this single rate unless an exporter can
While the Petitioner has commented on RHI's eligibility for a separate rate, which we have addressed in Comment 3 of the I&D Memo, we continue to find that RHI is eligible for a separate rate. Accordingly, for the final determination, we continue to find that the evidence placed on the record of this investigation by RHI demonstrates both a
In the
Section 776(c) of the Act provides that, when the Department relies on secondary information rather than on information obtained in the course of an investigation as facts available, it must, to the extent practicable, corroborate that information from independent sources reasonably at its disposal. Secondary information is described as “information derived from the petition that gave rise to the investigation or review, the final determination concerning merchandise subject to this investigation, or any previous review under section 751 concerning the merchandise subject to this investigation.”
The AFA rate that the Department used is from the Petition, however, we have updated the labor wage rate used to calculate the Petition rates. The Department's practice is not to recalculate dumping margins provided in petitions, but rather to corroborate the applicable petition rate when applying that rate as adverse facts available.
Petitioner's methodology for calculating the United States price and normal value in the Petition is discussed in the
We determine that the following percentage weighted-average margins exist for the following entities for the POI:
We will disclose the calculations performed within five days of the date of publication of this notice to parties in this proceeding in accordance with section 351.224(b) of the Department's regulations.
Pursuant to section 735(c)(1)(B) of the Act, and consistent with our finding of critical circumstances for RHI, the separate rate companies and the PRC-wide entity, pursuant to section 733(e)(2) of the Act, we will instruct U.S. Customs and Border Protection (“CBP”) to continue to suspend liquidation of all entries of the merchandise under consideration from the PRC entered, or withdrawn from warehouse, for consumption on or after December 12, 2009, which is 90 days prior to the date of publication of the
Additionally, the Department determined in its final determination for the companion countervailing duty (“CVD”) investigation that RHI's merchandise benefited from export subsidies.
With respect to the companies receiving a separate rate, we note that the rate applied in this proceeding as a separate rate is the calculated rate received by RHI. In the companion countervailing duty investigation, the Department found that RHI merchandise benefited from export subsidies during the POI, and, consequently, all other exporters (besides RHI and Mayerton) were found to have benefited from export subsidies based upon RHI results. Therefore, we will instruct CBP to require a cash deposit or posting of a bond equal to the weighted-average amount by which normal value exceeds U.S. price for RHI, as indicated above, minus the amount determined to constitute an export subsidy.
With respect to the PRC-wide entity, as AFA, we applied to highest rate form the petition that we were able to corroborate.
In accordance with section 735(d) of the Act, we have notified the International Trade Commission (“ITC”) of our final determination of sales at LTFV. As our final determination is affirmative, in accordance with section 735(b)(2) of the Act, within 45 days the ITC will determine whether the domestic industry in the United States is materially injured, or threatened with material injury, by reason of imports or sales (or the likelihood of sales) for importation of the merchandise under consideration. If the ITC determines that material injury or threat of material injury does not exist, the proceeding will be terminated and all securities posted will be refunded or canceled. If the ITC determines that such injury does exist, the Department will issue an antidumping duty order directing CBP to assess antidumping duties on all imports of the subject merchandise entered, or withdrawn from warehouse, for consumption on or after the effective date of the suspension of liquidation.
This notice also serves as a reminder to the parties subject to administrative protective order (“APO”) of their responsibility concerning the
This determination and notice are issued and published in accordance with sections 735(d) and 777(i)(1) of the Act.
Import Administration, International Trade Administration, Department of Commerce
The Department of Commerce (the Department) has reached a final determination that countervailable subsidies are being provided to producers/exporters of magnesia carbon bricks (MCBs) from the People's Republic of China (PRC). For information on the estimated subsidy rates, see the “Suspension of Liquidation” section of this notice.
Summer Avery or Toni Page, AD/CVD Operations, Office 6, Import Administration, International Trade Administration, U.S. Department of Commerce, Room 7866, 14th Street and Constitution Avenue, NW., Washington, DC 20230; telephone: (202) 482-4052 or (202) 482-1398, respectively.
The following events have occurred since the preliminary determination.
On January 7, 2010, Petitioner
On January 22, 2010, the GOC filed a request for a hearing for the instant investigation.
The Department issued three supplemental questionnaires to the Government of the People's Republic of China (GOC) on December 8, 2009, February 22, 2010, and March 26, 2010, respectively. The GOC submitted responses on January 5, 2010, March 15, 2010, March 22, 2010, and April 2, 2010.
The Department issued two supplemental questionnaires to Liaoning Mayerton Refractories (LMR) and its cross-owned affiliate Dalian Mayerton Refractories Co. Ltd. (DMR) (collectively, Mayerton) on December 8, 2009 and February 22, 2010, respectively. Mayerton submitted a response on January 5, 2010 for the first supplemental questionnaire but did not respond to the Department's second supplemental questionnaire. On April 1, 2010, Mayerton filed a letter with the Department informing us that that they would no longer be participating in this investigation.
The Department issued two supplemental questionnaires to RHI Refractories Liaoning Co., Ltd. (RHIL) as well as its cross-owned affiliates RHI Refractories (Dalian) Co., Ltd. (RHID) and Liaoning RHI Jinding Magnesia Co., Ltd. (RHIJ) (collectively, RHI) on December 8, 2009 and February 22, 2010, respectively. RHI submitted responses to the Department's questionnaires on January 5, 2010, March 15, 2010, and March 22, 2010. Public versions of all questionnaires and responses, as well as the various memoranda cited below, are available in the Department's Central Records Unit (CRU), Room 1117 in the HCHB building of the Commerce Department.
From May 4 through May 7, 2010, we conducted verification of the questionnaire responses submitted by RHI. We issued the verification report for RHI on June 1, 2010.
On May 6, 2010, the Department issued its post-preliminary determination regarding two programs, “Export Restraints of Raw Materials” and the “Provision of Electricity for Less than Adequate Remuneration.”
The Department received case briefs from Petitioner, the GOC, and RHI on June 10, 2010 and rebuttal briefs from the same parties on June 17, 2010. On June 17, 2010, the GOC withdrew its hearing request.
The merchandise under investigation consists of certain chemically-bonded (resin or pitch), magnesia carbon bricks with a magnesia component of at least 70 percent magnesia (“MgO”) by weight, regardless of the source of raw materials for the MgO, with carbon levels ranging from trace amounts to 30 percent by weight, regardless of enhancements (for example, magnesia carbon bricks can be enhanced with coating, grinding, tar impregnation or coking, high temperature heat treatments, anti-slip treatments or metal casing) and regardless of whether or not antioxidants are present (for example, antioxidants can be added to the mix from trace amounts to 15 percent by weight as various metals, metal alloys, and metal carbides). Certain magnesia carbon bricks that are the subject of this investigation are currently classifiable under subheadings 6902.10.1000, 6902.10.5000, 6815.91.0000,
On September 8, 2009, Pilkington North America Inc. (PNA), a U.S. importer of magnesia bricks from the People's Republic of China (PRC) and Mexico, filed timely comments concerning the scope of the AD and CVD investigations of certain magnesia carbon bricks from the PRC and the AD investigation of certain magnesia carbon bricks from Mexico.
In its submission, PNA requested that the Department amend the scope of these investigations to exclude ceramic bonded magnesia bricks with or without trace amounts of carbon or clarify that this product is outside the scope of these investigations. According to PNA, the ceramic bonded magnesia bricks it imports are clearly not within the intended scope of these investigations. Petitioner did not submit comments on PNA's submission; however, in a telephone conversation with a Department official, Petitioner stated that it agreed that the bricks at issue were outside the scope of these investigations.
After reviewing PNA's comments, the Department determined that the scope of these investigations does not include the bonded MCBs imported by PNA. However, because the language in the scope is clear that only chemically bonded magnesia carbon bricks are covered, the Department concluded that it was not necessary to amend or clarify the existing scope language in these investigations in response to PNA's request.
A respondent in the companion AD investigation of MCBs from Mexico, RHI-Refmex S.A. de C.V. (Refmex), argued in its case brief that the Department should expressly hold that resin-bonded magnesia carbon functional refractory products, as opposed to magnesia carbon brick products, are not within the scope of the MCBs under investigation. The Department has decided not to amend the scope of the MCB investigations to include a specific exclusion for such products because the current description of the scope of these investigations adequately limits the scope to bricks. A full summary of Refmex's comments and the Department's position are at Comment 1 of the Issues and Decision Memorandum for the AD Mexico investigation and Comment 5 of the Issues and Decision Memorandum for the AD PRC investigation.
All issues raised in the case and rebuttal briefs by parties to this investigation are addressed in the Memorandum to Ronald K. Lorentzen, Deputy Assistant Secretary for Import Administration, from Edward C. Yang, Acting Deputy Assistant Secretary for Antidumping and Countervailing Duty Operations, entitled “Issues and Decision Memorandum for the Final Affirmative Countervailing Duty Determination: Certain Magnesia Carbon Bricks from the People's Republic of China,” dated concurrently with this notice (hereinafter,
For purposes of this final determination, we continue to rely on facts available and have drawn adverse inferences, in accordance with sections 776(a) and (b) of the Act, with regard to RHI's receipt of countervailable subsidies under the “Provision of Electricity for Less than Adequate Remuneration” and “Export Restraints of Raw Materials” programs. In addition, pursuant to sections 776(a)(2)(A) and (C) of the Act, we have based the CVD rate for Mayerton on facts otherwise available and drawn adverse inferences. A full discussion of our decision to apply adverse facts available (AFA) is presented in the
In accordance with section 705(c)(1)(B)(i)(I) of the Act, we have calculated an individual rate for the mandatory respondent still participating in this investigation, RHI. Section 705(c)(5)(A)(i) of the Act states that for companies not investigated, we will determine an “all others” rate equal to the weighted-average countervailable subsidy rates established for exporters and producers individually investigated, excluding any zero and
In accordance with section 705(c)(1)(C) of the Act, we are directing U.S. Customs and Border Protection (CBP) to suspend liquidation of all imports of the subject merchandise from the PRC that are entered, or withdrawn from warehouse, for consumption on or after the date of publication of this notice in the
If the International Trade Commission (ITC) issues a final affirmative injury determination, we will issue a countervailing duty order and order CBP to continue the suspension of liquidation of entries of MCBs and to require a cash deposit on all such entries equal to the subsidy rate listed above. If the ITC determines that material injury, or threat of material injury, does not exist, this proceeding will be terminated and all deposits or securities posted as a result of the suspension of liquidation will be refunded or canceled.
In accordance with section 705(d) of the Act, we will notify the ITC of our determination. In addition, we are making available to the ITC all non-privileged and non-proprietary information related to this investigation. We will allow the ITC access to all privileged and business proprietary information in our files, provided the ITC confirms that it will not disclose such information, either publicly or under an APO, without the written consent of the Assistant Secretary for Import Administration.
In the event that the ITC issues a final negative injury determination, this notice will serve as the only reminder to parties subject to an administrative protective order (APO) of their responsibility concerning the destruction of proprietary information disclosed under APO in accordance with 19 CFR 351.305(a)(3). Timely written notification of the return/destruction of APO materials or conversion to judicial protective order is hereby requested. Failure to comply with the regulations and terms of an APO is a violation which is subject to sanction.
This determination is issued and published pursuant to sections 705(d) and 777(i) of the Act.