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Federal Aviation Administration (FAA), DOT.
Direct final rule; request for comments.
The FAA is removing the definitions of Category IIIa, IIIb, and IIIc operations. The definitions are outdated because they are no longer used for aircraft certification or operational authorization. Removing the definitions will aid in international harmonization efforts, future landing minima reductions, and airspace system capacity improvements due to the implementation of performance based operations.
Effective April 16, 2012.
Submit comments on or before March 19, 2012. If adverse comment is received, the FAA will publish a timely withdrawal in the
You may send comments identified by docket number FAA-2012-0019 using any of the following methods:
•
•
•
•
For technical questions concerning this action, contact Bryant Welch, Flight Technologies and Procedures Division, Flight Operations Branch, AFS-410, Federal Aviation Administration, 470 L'Enfant Plaza, Suite 4102, Washington, DC 20024; telephone (202) 385-4539; email
For legal questions concerning this action, contact Nancy Sanchez, Office of the Chief Counsel, Regulations Division, AGC-200, Federal Aviation Administration, 800 Independence Avenue SW., Washington, DC 20591; telephone (202) 267-3073; email
The FAA's authority to issue rules on aviation safety is found in Title 49 of the United States Code. Subtitle I, Section 106 describes the authority of the FAA Administrator. Subtitle VII, Aviation Programs, describes in more detail the scope of the agency's authority.
This rulemaking is promulgated under the authority described in 49 U.S.C. 40103, which vests the Administrator with broad authority to prescribe regulations to assign the use of airspace necessary to ensure the safety of aircraft and the efficient use of airspace, and 49 U.S.C. 44701(a)(5), which requires the Administrator to promulgate regulations and minimum standards for other practices, methods, and procedures necessary for safety in air commerce and national security.
The FAA is adopting this direct final rule without prior notice and prior public comment because this rule is not controversial, is not expected to result in the receipt of an adverse comment, and a notice of proposed rulemaking (NPRM) is not necessary. The Category IIIa, IIIb, and IIIc operations definitions are outdated, unnecessary, and overly restrictive. The FAA does not believe we will receive an adverse comment because this rule will not affect any existing operator's aircraft certification or operational approval. The Regulatory Policies and Procedures of the Department of Transportation (DOT) (44 FR 1134) provide that to the maximum extent possible, operating administrations for the DOT should provide an opportunity for public comment on regulations issued without prior notice. Accordingly, the FAA invites interested persons to participate in this rulemaking by submitting written comments, data, or views. The agency also invites comments relating to the economic, environmental, energy, or federalism impacts that might result from adopting this final rule.
Unless a written adverse or negative comment or a written notice of intent to submit an adverse or negative comment is received within the comment period, the regulation will become effective on the date specified above. After the close of the comment period, the FAA will publish a document in the
See the “Additional Information” section for information on how to comment on this direct final rule and how the FAA will handle comments received. In addition, there is information on obtaining copies of rulemaking documents.
The FAA is removing the definitions of Category IIIa, IIIb, and IIIc operations. Category III aircraft operations are precision approach and landing operations using an Instrument Landing System (ILS) conducted in very low visibility conditions. Currently, any approach and landing with a runway visual range (RVR) below 1000 feet is considered a Category III operation.
The International Civil Aviation Organization (ICAO) established the general concepts and definition of Category III operations in 1966 in ICAO Annex 10,
In December 1971, the FAA revised the CAT IIIa criteria (AC 120-28A) by establishing initial operational approval criteria. These criteria were based on a conservative approach for reducing operating minima. However, as industry gained operational experience, the FAA determined that the AC 120-28A criteria were unnecessarily stringent. In December 1976, the U.S. certificated the first airplane for Fail Passive CAT IIIa operations. This and following certifications were based on the use of Fail Operational or Fail Passive flight control systems, but some Aircraft Flight Manuals specified that the aircraft were suitable for Category IIIa operations.
As operational experience and the capabilities of airborne equipment increased in CAT IIIa operations, the FAA and industry realized the need for CAT IIIb (RVR lower than 700 feet but no lower than 150 feet) criteria. The FAA issued the initial U.S. CAT IIIb criteria for RVR 600 operations in March 1984 (AC 120-28C). Aircraft certifications and operational approvals continued to be based on the capabilities of the aircraft's Fail Operational or Fail Passive flight control systems, but also continued to tie the certifications and approvals to the Category IIIa and IIIb definitions. CAT IIIc operations are conducted with RVR below 150 feet. The FAA has not developed the criteria for aircraft certification and operational approval for Category IIIc operations. Therefore, Category IIIc operations have not been authorized.
The FAA codified the definitions of Category IIIa, IIIb, and IIIc operations in 1996. ICAO adopted the same definitions in ICAO Annex 6,
While AC 120-28D, issued in October 1999, references the definitions of Category IIIa, IIIb, and IIIc operations, the aircraft certification and operational approval documentation no longer uses these definitions. Under AC 120-28D, aircraft certifications are based solely on the demonstrated capabilities of the aircraft to land and rollout on the runway. For example, an aircraft with Fail Operational systems may be demonstrated to automatically land and rollout at RVR 150 feet, and this capability is stated in the Aircraft Flight Manual. The operational approvals will be based on that Manual without reference to the Category IIIa, IIIb, and IIIc definitions.
An effort is underway to rationalize and standardize Category III approach minima internationally. Aircraft certification standards are essentially the same worldwide with regard to the use of Fail Operational or Fail Passive system criteria to describe landing capabilities. Operational approval criteria are also based on the aircraft system capabilities, as in the United States. However, the publication of Category III landing minima for use on the approach are still tied to the Category IIIa, IIIb, and IIIc definitions, both internationally and in the United States. The FAA is removing the CAT IIIa, IIIb, and IIIc definitions as a first step toward the universal description of Category III operations and certification in terms currently used. The FAA presented a Working Paper to the ICAO Operations Council in October, 2011 requesting the deletion of the Category IIIa, IIIb, and IIIc definitions from the ICAO Annexes. The FAA also presented a similar paper to the European Aviation Safety Agency (EASA)/FAA All Weather Operations Harmonization Working Group in October, 2011.
Category III approach charts depicting landing minima in terms of the Category IIIa, IIIb, and IIIc definitions are now unnecessary. The Category III landing minima at a particular runway are based on the demonstrated qualities and capabilities of the ILS installed on that runway. The FAA tests every installed ILS in accordance with ICAO criteria,
Once this rule is effective, the FAA will amend FAA Orders defining publication of Category III minima by removing references to Category IIIa, IIIb, and IIIc operations. The amended Orders will directly relate the ILS system classification to the allowable published minima. The approach charts will show only the lowest possible Category III landing minima on a runway. For example, the approach chart for a landing at an airport would only state that the RVR is 600 and will not make any reference to the CAT IIIb operations definition. Operators will use the published minima in conjunction with their Operations Specifications to determine the lowest landing minima allowed to them, as is currently done.
Future Category III operations may derive from new low visibility approach and landing technologies. The type of operations, landing minima and aircraft certification criteria for these future systems will not follow the Category IIIa, IIIb, and IIIc definitions. Thus, removing the Category IIIa, IIIb, and IIIc definitions will eliminate the need for future systems to comply with these outdated definitions.
Changes to Federal regulations must undergo several economic analyses. First, Executive Order 12866 and Executive Order 13563 direct that each Federal agency shall propose or adopt a regulation only upon a reasoned determination that the benefits of the intended regulation justify its costs. Second, the Regulatory Flexibility Act of 1980 (Pub. L. 96-354) requires agencies to analyze the economic impact of regulatory changes on small entities. Third, the Trade Agreements Act (Pub. L. 96-39) prohibits agencies from setting standards that create unnecessary obstacles to the foreign commerce of the United States. In developing U.S. standards, the Trade Act requires agencies to consider international standards and, where appropriate, that they be the basis of U.S. standards. Fourth, the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4) requires agencies to prepare a written assessment of the costs, benefits, and other effects of proposed or final rules that include a Federal mandate likely to result in the expenditure by State, local, or tribal governments, in the aggregate, or by the private sector, of $100 million or more annually (adjusted for inflation with base year of 1995). This portion of the preamble summarizes the FAA's analysis of the economic impacts of this final rule.
Department of Transportation Order DOT 2100.5 prescribes policies and procedures for simplification, analysis, and review of regulations. If the expected cost impact is so minimal that a proposed or final rule does not warrant a full evaluation, this order permits that a statement to that effect and the basis for it be included in the preamble if a full regulatory evaluation of the cost and benefits is not prepared. Such a determination has been made for this final rule.
The FAA is removing the definitions of Category IIIa, IIIb, and IIIc operations. Since this final rule removes outdated and unnecessary definitions, the expected outcome will be a minimal impact with positive net benefits, and a regulatory evaluation was not prepared. The FAA requests comments with supporting justification about the FAA determination of minimal impact.
The FAA has, therefore, determined that this final rule is not a “significant regulatory action” as defined in section 3(f) of Executive Order 12866, and is not “significant” as defined in DOT's Regulatory Policies and Procedures.
The Regulatory Flexibility Act of 1980 (Pub. L. 96-354) (RFA) establishes “as a principle of regulatory issuance that agencies shall endeavor, consistent with the objectives of the rule and of applicable statutes, to fit regulatory and informational requirements to the scale of the businesses, organizations, and governmental jurisdictions subject to regulation. To achieve this principle, agencies are required to solicit and consider flexible regulatory proposals and to explain the rationale for their actions to assure that such proposals are given serious consideration.” The RFA covers a wide-range of small entities, including small businesses, not-for-profit organizations, and small governmental jurisdictions.
Agencies must perform a review to determine whether a rule will have a significant economic impact on a substantial number of small entities. If the agency determines that it will, the agency must prepare a regulatory flexibility analysis as described in the RFA. However, if any agency determines that a rule is not expected to have a significant economic impact on a substantial number of entities, section 605(b) of RFA provides that the head of the agency may so certify and a regulatory flexibility analysis is not required. The certification must include a statement providing the factual basis for this determination, and the reasoning should be clear.
As noted above, the changes to § 1.1 are cost relieving because the FAA is removing the definitions of Category IIIa, IIIb, and IIIc operations. The definitions are outdated and no longer used for aircraft certification or operational authorization. Therefore, as the FAA Acting Administrator, I certify that this rule will not have a significant economic impact on a substantial number of small entities.
The Trade Agreements Act of 1979 (Pub. L. 96-39), as amended by the Uruguay Round Agreements Act (Pub. L. 103-465), prohibits Federal agencies from establishing standards or engaging in related activities that create unnecessary obstacles to the foreign commerce of the United States. Pursuant to these Acts, the establishment of standards is not considered an unnecessary obstacle to the foreign commerce of the United States, so long as the standard has a legitimate domestic objective, such as the protection of safety, and does not operate in a manner that excludes imports that meet this objective. The statute also requires consideration of international standards and, where appropriate, that they be the basis for U.S. standards. The FAA has assessed the potential effect of this final rule and determined that it is neither considered an unnecessary obstacle nor a promotion to international trade and therefore it will have no impact on international trade.
Title II of the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4) requires each Federal agency to prepare a written statement assessing the effects of any Federal mandate in a proposed or final agency rule that may result in an expenditure of $100 million or more (in 1995 dollars) in any one year by State, local, and tribal governments, in the aggregate, or by the private sector; such a mandate is deemed to be a “significant regulatory action.” The FAA currently uses an inflation-adjusted value of $143.1 million in lieu of $100 million. This final rule does not contain such a mandate; therefore, the requirements of Title II of the Act do not apply.
The Paperwork Reduction Act of 1995 (44 U.S.C. 3507(d)) requires that the FAA consider the impact of paperwork and other information collection burdens imposed on the public. The FAA has determined that there is no new requirement for information collection associated with this direct final rule.
In keeping with U.S. obligations under the Convention on International Civil Aviation, it is FAA policy to conform to ICAO Standards and Recommended Practices to the maximum extent practicable. The FAA has reviewed the corresponding ICAO Standards and Recommended Practices and has identified the following difference. Once this rule is effective, the FAA's regulations will no longer include the definitions of Category IIIa, IIIb, and IIIc operations. This differs from ICAO Standards and Recommended Practices because ICAO's Annex 6 and Annex 10 include the Category IIIa, IIIb, and IIIc definitions. Until such time ICAO removes these definitions from its annexes, the FAA will be required to file a Difference with ICAO.
FAA Order 1050.1E identifies FAA actions that are categorically excluded from preparation of an environmental assessment or environmental impact statement under the National Environmental Policy Act in the absence of extraordinary circumstances. The FAA has determined this rulemaking action qualifies for the categorical exclusion identified in paragraph 312f and involves no extraordinary circumstances.
The FAA has analyzed this final rule under the principles and criteria of Executive Order 13132, Federalism. The agency determined that this action will not have a substantial direct effect on the States, or the relationship between the Federal Government and the States, or on the distribution of power and responsibilities among the various levels of government, and, therefore, does not have Federalism implications.
The FAA analyzed this final rule under Executive Order 13211, Actions Concerning Regulations that Significantly Affect Energy Supply, Distribution, or Use (May 18, 2001). The agency has determined that it is not a “significant energy action” under the executive order and it is not likely to have a significant adverse effect on the supply, distribution, or use of energy.
The FAA invites interested persons to participate in this rulemaking by submitting written comments, data, or views. The agency also invites comments relating to the economic, environmental, energy, or federalism impacts that might result from adopting the rulemaking action in this document. The most helpful comments reference a specific portion of the rulemaking action, explain the reason for any recommended change, and include supporting data. To ensure the docket does not contain duplicate comments, commenters should send only one copy of written comments, or if comments are filed electronically, commenters should submit only one time.
The FAA will file in the docket all comments it receives, as well as a report summarizing each substantive public contact with FAA personnel concerning this rulemaking. Before acting on this rulemaking action, the FAA will consider all comments it receives on or before the closing date for comments. The FAA will consider comments filed after the comment period has closed if it is possible to do so without incurring expense or delay. The agency may change this rulemaking action in light of the comments it receives.
An electronic copy of rulemaking documents may be obtained from the Internet by—
1. Searching the Federal eRulemaking Portal (
2. Visiting the FAA's Regulations and Policies Web page at
3. Accessing the Government Printing Office's Web page at
Copies may also be obtained by sending a request to the Federal Aviation Administration, Office of Rulemaking, ARM-1, 800 Independence Avenue SW., Washington, DC 20591, or by calling (202) 267-9680. Commenters must identify the docket or amendment number of this rulemaking.
All documents the FAA considered in developing this rulemaking action, including economic analyses and technical reports, may be accessed from the Internet through the Federal eRulemaking Portal referenced in item (1) above.
Air transportation.
In consideration of the foregoing, the Federal Aviation Administration amends chapter I of title 14, Code of Federal Regulations as follows:
49 U.S.C. 106(g), 40113, 44701.
Federal Aviation Administration (FAA), DOT.
Final rule; request for comments.
We are adopting a new airworthiness directive (AD) for certain airplanes originally manufactured by Lockheed for the military as P2V airplanes. This emergency AD was sent previously to all known U.S. owners and operators of these airplanes. This AD requires cleaning of the forward lower spar cap between wing stations 40 and 84.5 (right and left), and doing a detailed inspection for cracks, working fasteners, and other anomalies, including surface damage in the form of a nick, gouge, or corrosion; and repairing if necessary. This AD was prompted by a report of a significant crack in the principle wing structure. We are issuing this AD to detect and
This AD is effective March 2, 2012 to all persons except those persons to whom it was made immediately effective by Emergency AD 2012-03-51, issued on February 6, 2012, which contained the requirements of this amendment.
We must receive comments on this AD by April 2, 2012.
You may send comments, using the procedures found in 14 CFR 11.43 and 11.45, by any of the following methods:
•
•
•
•
You may examine the AD docket on the Internet at
Roger Caldwell, Aerospace Engineer, Denver Aircraft Certification Office, FAA, 26805 East 68th Avenue, Denver, CO 80249; phone: 303-342-1086; fax: 303-342-1088; e-mail:
On February 6, 2012, we issued Emergency AD 2012-03-51, which requires cleaning of the forward lower spar cap between wing stations 40 and 84.5 (right and left), and doing a detailed inspection for cracks, working fasteners, and other anomalies, including surface damage in the form of a nick, gouge, or corrosion; and repairing if necessary. That AD also requires sending inspection results (both positive and negative) to the FAA. This AD was prompted by a report of a significant crack in the principle wing structure on a Neptune Aviation Service, Inc. Model SP-2H (P2V-7) airplane. A crack approximately 24 inches long was found in the left side wing front spar and lower skin just outboard of the fuselage side of wing station 40. The crack propagated through the wing front spar web, lower chord, and wing lower skin through stringer No. 22 and aft to stringer No. 21. The cause of the cracking is unknown at this time. This condition, if not detected and corrected, could result in significant loss of structural integrity of the wing.
We are issuing this AD because we evaluated all the relevant information and determined the unsafe condition described previously is likely to exist or develop in other products of the same type design.
This AD requires cleaning of the forward lower spar cap between wing stations 40 and 84.5 (right and left), and doing a detailed inspection for cracks, working fasteners, and other anomalies, including surface damage in the form of a nick, gouge, or corrosion; and repairing if necessary. This AD also requires sending inspection results (both positive and negative) to the FAA.
We consider this AD interim action. If final action is later identified, we might consider further rulemaking then.
An unsafe condition exists that requires the immediate adoption of this AD. The FAA has found that the risk to the flying public justifies waiving notice and comment prior to adoption of this rule because of a report of a significant crack in the principle wing structure on a Neptune Aviation Service, Inc. Model SP-2H (P2V-7) airplane. This condition, if not detected and corrected, could result in significant loss of structural integrity of the wing. Therefore, we find that notice and opportunity for prior public comment are impracticable and that good cause exists for making this amendment effective in less than 30 days.
This AD is a final rule that involves requirements affecting flight safety and was not preceded by notice and an opportunity for public comment. However, we invite you to send any written data, views, or arguments about this AD. Send your comments to an address listed under the
We will post all comments we receive, without change, to
We estimate that this AD affects 38 airplanes of U.S. registry.
We estimate the following costs to comply with this AD:
No definitive data are available for repair costs at this time.
Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. Subtitle VII: Aviation Programs describes in more detail the scope of the Agency's authority.
We are issuing this rulemaking under the authority described in Subtitle VII, Part A, Subpart III, Section 44701: “General requirements.” Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.
This AD will not have federalism implications under Executive Order 13132. This AD will not have a substantial direct effect on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government.
(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),
(3) Will not affect intrastate aviation in Alaska, and
(4) Will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
Air transportation, Aircraft, Aviation safety, Incorporation by reference, Safety.
Accordingly, under the authority delegated to me by the Administrator, the FAA amends 14 CFR part 39 as follows:
49 U.S.C. 106(g), 40113, 44701.
This AD is effective March 2, 2012 to all persons except those persons to whom it was made immediately effective by Emergency AD 2012-03-51, issued on February 6, 2012, which contained the requirements of this amendment.
None.
This AD applies to all of the airplanes identified in paragraphs (c)(1), (c)(2), (c)(3), (c)(4), (c)(5), (c)(6), and (c)(7) of this AD, certificated in any category:
(1) Aero Union Corporation Model SP-2H (P2V-7) airplanes;
(2) Central Air Service, Inc. Model SP-2H (P2V-7) airplanes;
(3) Evergreen Air Center Model SP-2H (P2V-7) airplanes;
(4) Hawkins and Powers Aviation, Inc. Model HP-P2V-7 airplanes;
(5) Minden Air Corp Model SP-2H (P2V-7) airplanes;
(6) Neptune Aviation Service, Inc. Model SP-2H (P2V-7) airplanes; and
(7) USDA Forest Service (type certificate previously held by U.S. Department of Agriculture) Model P2V-5F (SP-2E) airplanes.
Joint Aircraft System Component (JASC)/Air Transport Association (ATA) of America Code 57, Wings.
This AD was prompted by a report of a significant crack in the principle wing structure on a Neptune Aviation Service, Inc. Model SP-2H (P2V-7) airplane. We are issuing this AD to detect and correct cracks, working fasteners, and other anomalies in the principle wing structure, which could cause significant loss of structural integrity of the wing.
Comply with this AD within the compliance times specified.
Within one day after the effective date of this AD: Do the actions specified in paragraphs (g)(1), (g)(2), and (g)(3) of this AD.
(1) Gain access to the wing spar box between wing stations 40 and 84.5 (right and left sides of the airplane) through an access panel that allows for inspecting the forward lower spar cap assembly and remove or reposition any internal fuel bladder assembly that impedes access.
(2) Clean the exposed surface of the forward lower spar cap between wing stations 40 and 84.5 (right and left), and do a detailed inspection for cracks, working fasteners, and other anomalies, including surface damage in the form of a nick, gouge, or corrosion, of the forward lower spar cap between wing stations 40 and 84.5 (right and left).
(3) If any crack, working fastener, or other anomaly is found during any inspection required by paragraph (g)(2) of this AD, before further flight, repair in accordance with a method approved by the Manager, Denver Aircraft Certification Office (ACO), FAA. For a repair method to be approved by the Manager, Denver ACO, as required by this paragraph, the Manager's approval letter must specifically refer to this AD.
For the purposes of this AD, a detailed inspection is: “An intensive examination of a specific item, installation, or assembly to detect damage, failure, or irregularity. Available lighting is normally supplemented with a direct source of good lighting at an intensity deemed appropriate. Inspection aids such as mirror, magnifying lenses, etc., may be necessary. Surface cleaning and elaborate procedures may be required.
Within 10 days after doing the inspection required by paragraph (g) of this AD: Submit a report of the findings (both positive and negative) of the inspections required by paragraph (g) of this AD to the Denver ACO, FAA, Attention: Roger Caldwell, 26805 East 68th Avenue, Denver, CO 80249; phone: 303-342-1086; fax: 303-342-1088; e-mail:
A federal agency may not conduct or sponsor, and a person is not required to respond to, nor shall a person be subject to a penalty for failure to comply with a collection of information subject to the requirements of the Paperwork Reduction Act unless that collection of information displays a current valid OMB Control Number. The OMB Control Number for this information collection is 2120-0056. Public reporting for this collection of information is estimated to be approximately 5 minutes per response, including the time for reviewing instructions, completing and reviewing the collection of information. All responses to this collection of information are mandatory. Comments concerning the accuracy of this burden and suggestions for reducing the burden should be directed to the FAA at: 800 Independence Ave. SW., Washington, DC 20591, Attn: Information Collection Clearance Officer, AES-200.
Special flight permits, as described in Section 21.197 and Section 21.199 of the Federal Aviation Regulations (14 CFR 21.197 and 21.199), are not allowed unless approved in accordance with the procedures specified in paragraph (l) of this AD.
(1) The Manager, Denver ACO, FAA, has the authority to approve AMOCs for this AD, if requested using the procedures found in 14 CFR 39.19. In accordance with 14 CFR 39.19,
(2) Before using any approved AMOC, notify your appropriate principal inspector, or lacking a principal inspector, the manager of the local flight standards district office/certificate holding district office.
For further information about this AD, contact: Roger Caldwell, Aerospace Engineer, Denver Aircraft Certification Office, FAA, 26805 East 68th Avenue, Denver, CO 80249; phone: 303-342-1086; fax: 303-342-1088; e-mail:
None.
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 use of the navigable airspace and to promote safe flight operations under instrument flight rules at the affected airports.
This rule is effective February 16, 2012. 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 February 16, 2012.
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.
Richard A. Dunham III, 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 (Mail Address: P.O. Box 25082, Oklahoma City, OK 73125), Telephone: (405) 954-4164.
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
Air Traffic Control, Airports, Incorporation by reference, and Navigation (air).
Accordingly, pursuant to the authority delegated to me, Title 14, Code of Federal Regulations, Part 97 (14 CFR part 97) is amended by establishing, amending, suspending, or revoking Standard Instrument Approach Procedures and/or Takeoff Minimums and/or Obstacle Departure Procedures effective at 0902 UTC on the dates specified, as follows:
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 use of the navigable airspace and to promote safe flight operations under instrument flight rules at the affected airports.
This rule is effective February 16, 2012. 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 February 16, 2012.
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.
Richard A. Dunham III, 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 (Mail Address: P.O. Box 25082 Oklahoma City, OK 73125), telephone: (405) 954-4164.
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 a 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 requires 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).
Accordingly, pursuant to the authority delegated to me, Title 14, Code of Federal regulations, Part 97, 14 CFR part 97, is amended by amending Standard Instrument Approach Procedures, effective at 0901 UTC on the dates specified, as follows:
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:
Office of the Assistant Secretary of Housing—Federal Housing Commissioner, HUD.
Final rule.
On August 30, 2011, HUD published a proposed rule to suspend FHA's mortgage insurance program for military impacted areas under section 238(c) of the National Housing Act. This single-family mortgage insurance program, established by regulation in 1977, has been significantly underutilized for the past several years. Additionally, these mortgage loans are insured under comparable terms and conditions as loans insured under HUD's primary single-family mortgage insurance program under section 203(b) of the National Housing Act. Accordingly, those borrowers who would be served under section 238(c) of the National Housing Act are served equally well under the section 203(b) mortgage insurance program. The suspension of this mortgage insurance program is consistent with the President's budget requests for Fiscal Years (FYs) 2011 and 2012. In this final rule, HUD is adopting the proposed rule without change.
Karin Hill, Director, Office of Single Family Program Development, Office of Housing, Department of Housing and Urban Development, 451 7th Street SW., Room 9278, Washington, DC 20410-8000; telephone number 202-708-4308 (this is not a toll-free number). Persons with hearing or speech impairments may access this number via TTY by calling the Federal Relay Service at 1-800-877-8339.
On August 30, 2011, HUD published a proposed rule in the
HUD's current regulation implementing section 238(c) is codified at 24 CFR 203.43e. The regulation, promulgated in 1977, closely tracks the language of section 238(c) of the Act. Although established to ensure the availability of affordable housing in military impacted areas, the program has been minimally utilized by eligible borrowers. Section 238(c) mortgage insurance has been available in only six counties throughout the country, three in Georgia and three in New York. From January 1, 2005, to June 30, 2010, FHA insured 4,542 single-family home loans in these six counties, and only 2,309 were endorsed under section 238(c) of the Act. The 2,309 loans endorsed since 2005 represent only .05 percent of all FHA-insured loans endorsed during that span.
The President's budget requests for FYs 2011 and 2012 acknowledged the underutilization of the section 238(c) program and advised that HUD would take action to halt the availability of the program in light of the significant underutilization. The FY 2011 budget request found at
The Budget assumes that HUD will administratively suspend the Section 238(c) program in 2011. The Section 238(c) program provides single family mortgage insurance similar to MMI for a small number of families in areas affected by military installations. The elimination of Section 238(c) will not negatively impact the availability of FHA insured financing in the six counties currently covered under this program. (See HUD Appendix to the Budget at page 620 at
This final rule follows publication of the August 30, 2011, proposed rule. The proposed rule provided for a 60-day public comment period, which closed on October 31, 2011. HUD did not receive any public comments, and HUD is adopting as final the proposed August 30, 2011, rule without change.
Consistent with the President's budget request and Executive Order (EO) 13563, entitled “Improving Regulation and Regulatory Review,” signed by the President on January 18, 2011, and published on January 21, 2011, at 76 FR 3821, this final rule suspends the section 238(c) program and removes § 203.43e from HUD's codified regulations. HUD's removal of the regulations at § 203.43e is not inconsistent with suspension of the section 238(c) mortgage insurance program. If HUD subsequently determines that there is a demand for this program and that military families would be better served by this program, HUD can reactivate it on the basis of the statutory language and does not need a regulation to make insurance available under this program. If such a situation occurs, HUD would notify the public through
The Regulatory Flexibility Act (RFA) (5 U.S.C. 601
The final rule would not modify or add any new regulatory burdens on FHA-approved mortgage lenders. Rather, the final rule would remove § 203.43e from HUD's regulations, in conformity to HUD's (and the Administration's) decision to no longer exercise its authority to insure mortgages under section 238(c) of the Act. As more fully discussed above in the preamble to this rule, the mortgage insurance authority provided by section 238(c) of the Act has been minimally sought by eligible borrowers and consequently minimally utilized by lenders and other small entities participating in the FHA programs. Further, as noted above, section 238(c) mortgage insurance operated in a manner comparable to FHA's mortgage insurance program under section 203(b) of the Act, HUD's primary single-family mortgage insurance program.
Accordingly, for the above reasons, the undersigned certifies that this rule will not have a significant economic impact on a substantial number of small entities.
Executive Order 13132 (entitled “Federalism”) prohibits an agency from publishing any rule that has federalism implications if the rule either imposes substantial direct compliance costs on state and local governments and is not required by statute, or the rule preempts state law, unless the agency meets the consultation and funding requirements of section 6 of the Executive Order. This rule will not have federalism implications and would not impose substantial direct compliance costs on state and local governments or preempt state law within the meaning of the Executive Order.
Title II of the Unfunded Mandates Reform Act of 1995 (2 U.S.C.1531-1538) (UMRA) establishes requirements for federal agencies to assess the effects of their regulatory actions on state, local, and tribal governments, and on the private sector. This rule does not impose any federal mandates on any state, local, or tribal governments, or on the private sector, within the meaning of UMRA.
This final rule does not direct, provide for assistance or loan and mortgage insurance for, or otherwise govern or regulate, real property acquisition, disposition, leasing, rehabilitation, alteration, demolition, or new construction, or establish, revise, or provide for standards for construction or construction materials, manufactured housing, or occupancy. Accordingly, under 24 CFR 50.19(c)(1), this rule is categorically excluded from environmental review under the National Environmental Policy Act of 1969 (42 U.S.C. 4321).
The Catalogue of Federal Domestic Assistance Number for the principal FHA single-family mortgage insurance program is 14.117.
Hawaiian Natives, Home improvement, Indians—lands, Loan programs—housing and community development, Mortgage insurance, Reporting and recordkeeping requirements, Solar energy.
Accordingly, for the reasons discussed in the preamble, 24 CFR part 203 is amended as follows:
12 U.S.C. 1709, 1710, 1715b, 1715z-16, and 1715u; 42 U.S.C. 3535(d).
National Indian Gaming Commission, Interior.
Proposed rule; correction.
This document corrects the preamble and regulatory text of the proposed rule published in the
Maria Getoff, (202) 632-7003.
This document makes six technical corrections in the proposed rule to clarify that the definition of “summary proceeding” in proposed § 580.1 applies only to ordinance and management contract appeals and that the definition of “limited participant” applies only to appeals of disapprovals of gaming ordinances. Section 581.4 is corrected to reference all appeal actions listed in part 584. This notice corrects a typographical error in § 585.3(a) by replacing “§ 585.7 with “§ 585.6”, and clarifies that service of the record will be accomplished after a notice of appeal in proposed § 585.6. Finally, this correction removes limited participant from § 585.7(b) so that the proposed rule is consistent with part 585 and the definition of limited participant. This notice makes technical corrections to the preamble so that the preamble is consistent with the proposed rule.
In the preamble to proposed rule FR Doc. 2012-1767, beginning on page 4720 in the issue of January 31, 2012, make the following corrections in the
1. On page 4723 in the 1st column, second full paragraph remove “a notice of appeal and brief” and add in its place “an appeal brief”.
2. On page 4724 in the 1st column remove the first full paragraph.
3. On page 4724 in the 1st column, fifth full paragraph, remove “a notice of appeal and appeal brief” and add in its place “an appeal brief”.
In proposed rule FR Doc. 2012-1767, beginning on page 4720 in the issue of January 31, 2012, make the following corrections to the amendatory text:
1. On page 4725 in the 1st column, in § 580.1:
a. In the definition of “limited participant” remove the word “either” between the words “in” and “an” and remove “or an appeal on written submissions under 585.5”; and
b. Revise the definition of “summary proceeding”.
The revision reads as follows:
2. On page 4726, in the 2nd column, in § 581.4, add “the Commission's proposal to remove a certificate of self-regulation,” after the word, “contracts,”.
3. On page 4730, in the 2nd column, in § 585.3(a), remove “§ 585.7” and add in its place “§ 585.6”.
5. On page 4731, in the 1st column, in § 585.6, remove the following text, “an appeal brief” and add in its place, “a notice of appeal”.
6. On page 4731, in the 1st column, in § 585.7(b), remove “, and any limited participant”.
Centers for Medicare & Medicaid Services (CMS), HHS.
Proposed rule.
This proposed rule would require providers and suppliers receiving funds under the Medicare program to report and return overpayments by the later of the date which is 60 days after the date on which the overpayment was identified; or any corresponding cost report is due, if applicable.
To be assured consideration, comments must be received at one of the addresses provided below, no later than 5 p.m. on April 16, 2012.
In commenting, please refer to file code CMS-6037-P. Because of staff and resource limitations, we cannot accept comments by facsimile (FAX) transmission.
You may submit comments in one of four ways (please choose only one of the ways listed):
1.
2.
Please allow sufficient time for mailed comments to be received before the close of the comment period.
3.
4.
a. For delivery in Washington, DC—
(Because access to the interior of the Hubert H. Humphrey Building is not readily available to persons without Federal government identification, commenters are encouraged to leave their comments in the CMS drop slots located in the main lobby of the building. A stamp-in clock is available for persons wishing to retain a proof of filing by stamping in and retaining an extra copy of the comments being filed.)
b. For delivery in Baltimore, MD—
If you intend to deliver your comments to the Baltimore address, please call telephone number (410) 786-1066 in advance to schedule your arrival with one of our staff members.
Comments mailed to the addresses indicated as appropriate for hand or courier delivery may be delayed and received after the comment period.
For information on viewing public comments, see the beginning of the
Tiana Korley, (410) 786-9702.
Comments received timely will also be available for public inspection as they are received, generally beginning approximately 3 weeks after publication of a document, at the headquarters of the Centers for Medicare & Medicaid Services, 7500 Security Boulevard, Baltimore, Maryland 21244, Monday through Friday of each week from 8:30 a.m. to 4 p.m. To schedule an appointment to view public comments, phone 1-800-743-3951.
The Medicare program (title XVIII of the Social Security Act (the Act)) is the primary payer of health care for approximately 47 million enrolled beneficiaries. Providers and suppliers furnishing Medicare items and services must comply with the Medicare requirements set forth in the Act and in our regulations. The requirements are meant to ensure compliance with applicable statutes, promote the furnishing of high quality care, and to protect the Medicare Trust Funds against fraud and improper payments. As Medicare spending has grown, we have increased our efforts to reduce fraud, waste, and abuse in the Medicare program.
As part of these efforts we have twice proposed—but did not finalize—rules that would have amended our regulations related to Medicare overpayments. (See the March 25, 1998 (63 FR 14506) and January 25, 2002 (67 FR 3662) proposed rules.)
On March 23, 2010, the Patient Protection and Affordable Care Act (Pub. L. 111-148) was enacted. The Health Care Education Reconciliation Act of 2010 (Pub. L. 111-152) then amended certain provisions of Public Law 111-148. These public laws are collectively known as the Affordable Care Act. The Affordable Care Act makes a number of changes to the Medicare program that enhance our efforts to recover overpayments and combat fraud, waste and abuse in the Medicare program.
Section 6402(a) of the Affordable Care Act established a new section 1128J(d) of the Act entitled “Reporting and Returning of Overpayments.” Section 1128J(d)(1) of the Act requires a person who has received an overpayment to report and return the overpayment to the Secretary, the State, an intermediary, a carrier, or a contractor, as appropriate, at the correct address, and to notify the Secretary, State, intermediary, carrier or contractor to whom the overpayment was returned in writing of the reason for the overpayment. Section 1128J(d)(2) of the Act requires that an overpayment be reported and returned by the later of— (1) the date which is 60 days after the date on which the overpayment was identified; or (2) the date any corresponding cost report is due, if applicable. Section 1128J(d)(3) of the Act specifies that any overpayment retained by a person after the deadline for reporting and returning an overpayment is an obligation (as defined in 31 U.S.C. 3729(b)(3)) for purposes of 31 U.S.C. 3729.
Section 1128J(d)(4)(A) defines “knowing” and “knowingly” as those terms are defined in 31 U.S.C. 3729(b); the terms “knowing” and “knowingly” “mean that a person with respect to information—(i) has actual knowledge of the information; (ii) acts in deliberate ignorance of the truth or falsity of the information; or (iii) acts in reckless disregard of the truth or falsity of the information.” There need not be “proof of specific intent to defraud.” Section 1128J(d)(4)(B) of the Act defines the term “overpayment” as any funds that a person receives or retains under title XVIII or XIX to which the person, after applicable reconciliation, is not entitled under such title. Finally, section 1128J(d)(4)(C) of the Act defines the term “person” as a provider of services, supplier, Medicaid managed care organization (MCO) (as defined in section 1903(m)(1)(A) of the Act), Medicare Advantage organization (MAO) (as defined in section 1859(a)(1) of the Act) or PDP sponsor (PDP) (as defined in section 1860D-41(a)(13) of the Act) but the definition does not include a beneficiary.
To implement section 6402(a) of the Affordable Care Act, we propose establishing a new subpart D in Part 401 of our regulations. In this section, we outline the content of the proposed provisions of this new subpart D.
In proposed § 401.301, we state that subpart D sets forth the policies and procedures for reporting and returning overpayments to the Medicare program for providers and suppliers of services under Parts A and B of title XVIII. At this time, we are proposing to implement the requirements set forth in section 1128J(d) of the Act only as they relate to Medicare Part A and Part B providers and suppliers. Other stakeholders, including, without limitation, MAOs, PDPs, and Medicaid MCOs will be addressed at a later date.
Notwithstanding the foregoing, we remind all stakeholders that even without a final regulation they are subject to the statutory requirements
For purposes of this subpart only, we propose the following definitions:
Section 1128J(d) of the Act provides that an overpayment means “* * * any funds that a person receives or retains under title XVIII * * * to which the person, after applicable reconciliation, is not entitled under such title.” In § 401.303, we propose to include this same definition in our proposed rule. Examples of overpayments under this proposed definition could include all of the following:
• Medicare payments for noncovered services.
• Medicare payments in excess of the allowable amount for an identified covered service.
• Errors and nonreimbursable expenditures in cost reports.
• Duplicate payments.
• Receipt of Medicare payment when another payor had the primary responsibility for payment.
In certain circumstances, Medicare makes estimated payments for services with the knowledge that a reconciliation of those payments to actual costs will be done when the actual costs or related information becomes available, usually at a later date. Interim payments made to a provider throughout the cost year are reconciled with covered and reimbursable costs at the time the cost report is due. The statutory and proposed regulatory definition of the term overpayment acknowledges this practice and provides that an overpayment does not exist until after an applicable reconciliation takes place. When a provider files a cost report, the provider is attesting to the accuracy of the information contained on the cost report and must maintain the appropriate documentation supporting the costs that are claimed on the cost report. We rely upon the information that providers submit through the cost report and we believe that providers must accurately report any overpayments at the time they submit any cost reports to CMS—whether it is an initial submission of a cost report or an amended one.
We propose that the term “Medicare contractor” means a fiscal intermediary, carrier, durable medical equipment Medicare administrative contractor (DME MAC), or Part A/Part B Medicare administrative contractor. We believe that this proposed definition captures the different contractors that would be involved in receiving reports of overpayments as well as handling the return of overpayments, consistent with the statutory requirement.
We propose that a person means a provider (as defined in § 400.202) or supplier (as defined in § 400.202). This definition does not include a beneficiary. Our proposal is consistent with the definition of a “person” in section 1128J(d) of the Act.
Section 1128J of the Act provides that if a person has received an overpayment, the person shall “(i) report and return the overpayment to the Secretary * * * an intermediary, a carrier, or a contractor, as appropriate, at the correct address; and (ii) notify the Secretary * * * intermediary, carrier, or contractor to whom the overpayment was returned in writing of the reason for the overpayment.”
We propose to implement these requirements by using the existing voluntary refund process, which will be renamed the “self-reported overpayment refund process.” This process is described in Publication 100-06, Chapter 4 of the Medicare Financial Management Manual. Under the existing voluntary refund process, providers and suppliers report overpayments using a form that each Medicare contractor makes available on its Web site. The form requires that providers and suppliers provide information to allow CMS to identify the affected claims, such as the health insurance claim number (HICN); the provider's or supplier's name, number and tax identification number; and the date of service. The voluntary refund process also requires providers and suppliers to summarize why the refund is being made including the following information: (1) How the error was discovered; (2) a description of the corrective action plan implemented to ensure the error does not occur again; (3) the reason for the refund; (4) whether the provider or supplier has a corporate integrity agreement (CIA) with the OIG or is under the OIG Self-Disclosure Protocol; (5) the timeframe and the total amount of refund for the period during which the problem existed that caused the refund; (6) Medicare claim control number, as appropriate; (7) Medicare National Provider Identification (NPI) number; (8) a refund in the amount of the overpayment; and (9) if a statistical sample was used to determine the overpayment amount, description of the statistically valid methodology used to determine the overpayment. We are proposing that providers and suppliers would be required to use the self-reported overpayment refund process set forth by the applicable Medicare contractor to report and return overpayments.
Some clarification may be helpful in defining potential reasons for an overpayment since such information must be reported under section 1128J(d) of the Act. While we cannot provide an exhaustive list of all potential reasons for the overpayment as required to be reported at § 401.305(d), we can provide examples. Examples of what a person may report as the reason for the overpayment include the following: (1) Incorrect service date; (2) duplicate payment; (3) incorrect CPT code; (4) insufficient documentation; and (5) lack of medical necessity. We note that many of the forms currently available from our contractors provide a “check the box” format that allows providers and suppliers to easily identify the reason for the overpayment. For overpayments that are not listed on the form that is available from the Medicare contractor, there is an associated “other” box that allows providers and suppliers to clarify the reason for the overpayment.
We make these proposals because we believe that the information requested under the existing voluntary refund process, such as the date of service and the HICN, is necessary to allow CMS to appropriately match claims information with the information that is reported by the provider or supplier and to understand the nature of the overpayment. Furthermore, we recognize that the reporting forms may differ among the different Medicare contractors and plan to develop a uniform reporting form that will enable all overpayments to be reported and returned in a consistent manner across all Medicare contractors. Until such uniform reporting form is made available, providers and suppliers should utilize the existing form available from the Web site of the applicable Medicare contractor as discussed earlier in this proposed rule.
Section 1128J of the Act provides that the terms `knowing' and `knowingly' have the meaning given those terms in the False Claims Act (31 U.S.C. 3729(b)(3)). The statutory text, however, does not use this phrase other than in the definitions. In § 401.305 (a)(2), we propose that a person has identified an overpayment if the person has actual knowledge of the existence of the overpayment or acts in reckless disregard or deliberate ignorance of the overpayment. We believe Congress' use of the term “knowing” in the ACA was intended to apply to determining when a provider or supplier has identified an overpayment. We believe defining “identification” in this way gives providers and suppliers an incentive to exercise reasonable diligence to determine whether an overpayment exists. Without such a definition, some providers and suppliers might avoid performing activities to determine whether an overpayment exists, such as self-audits, compliance checks, and other additional research.
Section 1128J of the Act provides that an overpayment must be reported and returned by the later of—(i) the date which is 60 days after the date on which the overpayment was identified; or (ii) the date any corresponding cost report is due, if applicable. Proposed § 401.305(b) contains an identical requirement. If an overpayment is claims related, the provider or supplier would be required to report and return the overpayment within 60 days of identification. However, for those providers that submit cost reports, if the overpayment is such that it would generally be reconciled on the cost report by the provider, the provider would be permitted to report and return the overpayment either 60 days from the identification of the overpayment or on the date the cost report is due, whichever is later. For example, issues involving upcoding must be reported and returned within 60 days of identification because the upcoded claims for payment are not submitted to Medicare in the form of cost reports. However, for an overpayment that would generally be reconciled on the cost report, such as overpayments related to graduate medical education payments, the provider must report and return the overpayment either 60 days after it has been identified or on the date the cost report is due, whichever is later. We believe that the qualifying language “if applicable” supports the proposed approach of only permitting providers to rely upon the cost report deadline when relevant to the determination of whether an actual overpayment exists. We make this clarification to avoid situations in which providers improperly delay reporting and returning a claims-related, identified overpayment until the date a cost report is due. We do not believe that Congress intended to create a loophole that would allow providers to delay reporting and returning an identified overpayment until a cost report is due if the overpayment would not ordinarily be reconciled on the cost report.
The proposed 60-day requirement to report and return overpayments would run from the date on which the person had identified the overpayment. As previously discussed, an overpayment has been identified at the time that a person acts with actual knowledge of, in deliberate ignorance of, or with reckless disregard to the overpayment's existence. In some cases, a provider or supplier may receive information concerning a potential overpayment that creates an obligation to make a reasonable inquiry to determine whether an overpayment exists. If the reasonable inquiry reveals an overpayment, the provider then has 60 days to report and return the overpayment. On the other hand, failure to make a reasonable inquiry, including failure to conduct such inquiry with all deliberate speed after obtaining the information, could result in the provider knowingly retaining an overpayment because it acted in reckless disregard or deliberate ignorance of whether it received such an overpayment. For example, a provider that receives an anonymous compliance hotline telephone complaint about a potential overpayment has incurred an obligation to timely investigate that matter. If the provider diligently conducts the investigation, and reports and returns any resulting overpayments within the 60-day reporting and repayment period, then the provider would have satisfied its obligations under the proposed rule. If, however, the provider fails to make any reasonable inquiry into the complaint, the provider may be found to have acted in reckless disregard or deliberate ignorance of any overpayment.
In order to assist providers and suppliers with understanding when an overpayment has been identified, we provide the following examples:
• A provider of services or supplier reviews billing or payment records and learns that it incorrectly coded certain services, resulting in increased reimbursement.
• A provider of services or supplier learns that a patient death occurred prior to the service date on a claim that has been submitted for payment.
• A provider of services or supplier learns that services were provided by an unlicensed or excluded individual on its behalf.
• A provider of services or supplier performs an internal audit and discovers that overpayments exist.
• A provider of services or supplier is informed by a government agency of an audit that discovered a potential overpayment, and the provider or supplier fails to make a reasonable inquiry. (When a government agency informs a provider or supplier of a potential overpayment, the provider or supplier has an obligation to accept the finding or make a reasonable inquiry. If the provider's or supplier's inquiry verifies the audit results, then it has identified an overpayment and, assuming there is no applicable cost report, has 60 days to report and return the overpayment. As noted previously, failure to make a reasonable inquiry, including failure to conduct such inquiry with all deliberate speed after obtaining the information, could result in the provider or supplier knowingly retaining an overpayment because it acted in reckless disregard or deliberate ignorance of whether it received such an overpayment).
• A provider of services or supplier experiences a significant increase in Medicare revenue and there is no apparent reason—such as a new partner added to a group practice or a new focus on a particular area of medicine—for the increase. Nevertheless, the provider or supplier fails to make a reasonable inquiry into whether an overpayment exists. (When there is reason to suspect an overpayment, but a provider or supplier fails to make a reasonable inquiry into whether an overpayment exists, it may be found to have acted in reckless disregard or deliberate ignorance of any overpayment.)
We emphasize that these examples are not an exhaustive list of situations where a person has identified an overpayment.
We recognize that there are also intersections between the obligation to report and return overpayments under section 6402(a) of the Affordable Care Act and the existing procedures for providers and suppliers to self-disclose actual or potential violations of the physician self-referral statute to CMS through the Medicare Self-Referral Disclosure Protocol (SRDP). Providers and suppliers self-disclose violations under the SRDP with the intention of resolving overpayment liability
We note that there are also intersections between the obligation to report and return an overpayment under section 6402(a) of the Affordable Care Act and the existing procedures for reporting self-discovered evidence of potential fraud to the OIG through the OIG Self-Disclosure Protocol (OIG SDP). The OIG SDP is available on the OIG Web site at
Providers and suppliers should ensure that they are using the most appropriate process to report and return overpayments. In the October 30, 1998
We believe the distinctions drawn previously are relevant because the process of reporting and returning overpayments pursuant to section 1128J of the Act cannot resolve any potential False Claims Act or OIG administrative liability associated with the overpayment (even though returning an overpayment may, among other benefits, limit any FCA or administrative liability arising from the retention of an overpayment). Providers and suppliers should be aware that the contractors will scrutinize overpayments received through this process and may make referrals to OIG whenever the contractors believe circumstances warrant such a referral.
We are aware that providers and suppliers may be concerned about scenarios in which they have identified an overpayment but because of the magnitude of the overpayment, need additional time to make repayment. Providers and suppliers may not delay the identification date in these situations to meet the deadline prescribed for reporting and returning the overpayment. Instead, if a provider or supplier needs additional time due to financial constraints, the provider or supplier must use the existing Extended Repayment Schedule (ERS)
Finally, we note the following with regard to overpayments that arise due to a violation of the anti-kickback statute (section 1128B(b)(1) and (2) of the Act). Compliance with the anti-kickback statute is a condition of payment. Claims that include items and services resulting from a violation of this law are not payable and constitute false or fraudulent claims for purposes of the False Claims Act. We recognize that, in many instances, a provider or supplier is not a party to, and is unaware of the existence of, an arrangement between third parties that causes the provider or supplier to submit claims that are the subject of a kickback. For example, a hospital may be unaware that a device manufacturer has paid a kickback to a physician on the hospital's medical staff to induce the physician to implant the manufacturer's device in procedures performed at the hospital. Moreover, even if a provider or supplier becomes aware of a potential third party payment arrangement, it would generally not be able to evaluate whether the payment was an illegal kickback or whether one or both parties had the requisite intent to violate the anti-kickback statute.
For this reason, we believe that providers who are not a party to a kickback arrangement are unlikely in most instances to have “identified” the overpayment that has resulted from the kickback arrangement and would therefore have no duty to report it or, as discussed later in this section, to repay it. To the extent that a provider or supplier who is not a party to a kickback arrangement has sufficient knowledge of the arrangement to have identified the resulting overpayment, the provider or supplier must report the overpayment to CMS in accordance with section 1128J(d) of the Act and corresponding
As previously noted, the statutory and our proposed regulatory definition of an overpayment acknowledges that, in some instances, we make interim payments to a provider through the cost year and that the provider reconciles these payments with covered and reimbursable costs at the time the cost report is due. In § 401.305(c), we propose that “applicable reconciliation” will occur with the provider's submission of a cost report. We believe that this would include an initial cost report submission or an amended cost report. We expect providers to accurately report and return overpayments at these points in time, because we rely upon the information that providers include on cost reports.
We propose to recognize two exceptions to the general rule that the applicable reconciliation occurs with the provider's submission of a cost report. The first exception is related to Supplemental Security Income (SSI) ratios used in the calculation of disproportionate share hospital (DSH) payment adjustment. We publish these ratios annually on our Web site and providers are expected to use the appropriate ratio when submitting the cost report for that cost year, unless the published ratios are not available at the time the cost report is due. In instances where the provider later receives more recent information regarding its SSI ratio, we propose that the provider would not be required to amend the cost report or calculate the change in reimbursement and return the potential overpayment until the final reconciliation of the provider's cost report occurs. The second exception is related to the outlier reconciliation. We perform an outlier reconciliation at the time the cost report is settled if certain thresholds are exceeded. Prior to this reconciliation the actual amount of any overpayment is not known. In instances where the provider is aware it has exceeded the established thresholds and an outlier reconciliation will be performed, we propose that the provider would not be required to estimate the change in reimbursement and return the estimated overpayment until the final settlement of that cost report.
Section 1128J(d) of the Act provides that any overpayment retained by a person after the deadline for reporting and returning the overpayment is an obligation for purposes of 31 U.S.C. 3729. Any person who “knowingly conceals or knowingly and improperly avoids or decreases an obligation to pay or transmit money or property to the Government” may be found liable under the False Claims Act. (See 31 U.S.C. 3729 et seq.) Proposed § 401.305(f) contains a similar statement. Additionally, any person who “knows of an overpayment [as defined in section 1128J(d)(4) of the Act] and does not report and return the overpayment in accordance with such section” may be found liable under the Civil Monetary Penalties Law (section 1128A(a)(10) of the Act) and accordingly could be excluded from participation in Federal health care programs (section 1128A of the Act).
In § 401.305(g), we are proposing that overpayments must be reported and returned only if a person identifies the overpayment within 10 years of the date the overpayment was received. We selected 10 years because this is the outer limit of the False Claims Act statute of limitations. We believe that the proposed 10-year lookback period is appropriate for several reasons. First, we believe that providers and suppliers should have certainty after a reasonable period that they can close their books and not have ongoing liability associated with an overpayment. We also believe that the length of the lookback period is long enough to sufficiently further our interest in ensuring that overpayments are timely returned to the Medicare Trust Funds.
We propose to amend the reopening rules at § 405.980(b) to provide that overpayments reported in accordance with § 401.305 may be reopened for a period of 10 years. We make this proposal in order to ensure that our reopening regulations are consistent with the lookback period that we are proposing. We seek comment on the proposed 10-year lookback period. In addition, we seek comment on our proposal to amend the reopening rules to provide for a 10-year reopening period.
Under the Paperwork Reduction Act of 1995, we are required to provide 60-day notice in the
• The need for the information collection and its usefulness in carrying out the proper functions of our agency.
• The accuracy of our estimate of the information collection burden.
• The quality, utility, and clarity of the information to be collected.
• Recommendations to minimize the information collection burden on the affected public, including automated collection techniques.
We are soliciting public comment on each of these issues for the following sections of this document that contain information collection requirements (ICRs):
Proposed § 401.305 states that a provider or supplier must report and return an overpayment to the Secretary, the State, an intermediary, a carrier or a contractor to the correct address by the later of 60 days after the overpayment was identified or the date the corresponding cost report is due and notify the Secretary, the State, an intermediary, a carrier or a contractor in writing of the reason for the overpayment. The burden associated with this requirement would be the time and effort necessary to report and return the overpayment in the manner described at § 401.305.
For purposes of this section only, we estimate that approximately 125,000 providers and suppliers (or roughly 8.5 percent of the total number of Medicare providers and suppliers) would report and return overpayments in a typical year under our proposed provisions. In addition, we project that each of these providers and suppliers would, on average, separately report and return approximately 3 to 5 overpayments. We also estimate that it would take a provider or supplier approximately 2.5
If you comment on these information collection and recordkeeping requirements, please do either of the following:
1. Submit your comments electronically as specified in the
2. Submit your comments to the Office of Information and Regulatory Affairs, Office of Management and Budget, Attention: CMS Desk Officer, [CMS-6037-P], Fax: (202) 395-5806; or Email:
Because of the large number of public comments we normally receive on
This proposed rule is necessary to implement section 6402(a) of the Affordable Care Act, which established a new section 1128J(d) of the Act entitled “Reporting and Returning of Overpayments.” Section 1128J(d)(1) of the Act requires a person who has received an overpayment to report and return the overpayment to the Secretary, the State, an intermediary, a carrier, or a contractor, as appropriate, at the correct address, and to notify the Secretary, State, intermediary, carrier or contractor to whom the overpayment was returned in writing of the reason for the overpayment. Section 1128J(d)(2) of the Act requires that an overpayment must be reported and returned by the later of—(1) the date which is 60 days after the date on which the overpayment was identified; or (2) the date any corresponding cost report is due, if applicable. Section 1128J(d)(3) of the Act specifies that any overpayment retained by a person after the deadline for reporting and returning an overpayment is an obligation (as defined in 31 U.S.C. 3729(b)(3)) for purposes of 31 U.S.C. 3729. As a result, this proposed rule clarifies to providers and suppliers their legal obligations regarding the reporting and returning of overpayments.
We have examined the impact of this proposed rule as required by Executive Order 12866 on Regulatory Planning and Review (September 1993), Executive Order 13563 on Improving Regulation and Regulatory Review (January 18, 2011), the Regulatory Flexibility Act (RFA) (September 19, 1980, Pub. L. 96-354), section 1102(b) of the Act, section 202 of the Unfunded Mandates Reform Act (UMRA) of 1995 (Pub. L. 104-4), Executive Order 13132 on Federalism (August 4, 1999), and the Congressional Review Act (5 U.S.C. 804(2)).
Executive Orders 12866 and 13563 direct agencies to assess all costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects; distributive impacts and equity). Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility. A regulation impact analysis (RIA) must be prepared for major rules with economically significant effects ($100 million or more in any one year).
As discussed earlier in the preamble, even without a final regulation, all stakeholders are subject to the statutory requirements found in section 1128J(d) of the Act and could face potential False Claims Act liability, Civil Monetary Penalties Law liability, and exclusion from Federal health care programs for failure to report and return an overpayment. This proposed rule would impose a new deadline on the return of any overpayment that has been identified. We believe that this change would spur providers to be more diligent in reporting and returning overpayments. That will likely increase the overpayments that we collect, but we do not have a basis for estimating the magnitude of that change, and note the substantial uncertainty surrounding the magnitude of new collections. The burden costs for reporting and returning of overpayments, as discussed in section III. of this proposed rule, are estimated annually between $34.78 million to $57.97 million. As a result, this
The RFA requires agencies to analyze options for regulatory relief for small businesses, if a rule has a significant impact on a substantial number of small entities. For purposes of the RFA, small entities include small businesses, nonprofit organizations, and small governmental jurisdictions. Most hospitals and most other health care providers and suppliers are small entities, either by being nonprofit organizations or by meeting the Small Business Administration (SBA) definition of a small business and having revenues of less than $7 million to $34.5 million in any 1 year. (For details, see the Small Business Administration's Table of Size Standards at
Section 1102(b) of the Act requires us to prepare a regulatory impact analysis if a rule may have a significant impact on the operations of a substantial number of small rural hospitals. This analysis must conform to the provisions of section 603 of the RFA. For purposed of section 1102(b) of the Act, we define a small rural hospital as a hospital located outside of the Metropolitan Statistical Area and has fewer than 100 beds. The cost of the required reporting should be minimal for small rural hospitals because standard business practices dictate keeping accurate records concerning monies due and/or payable. We are not preparing an analysis for section 1102(b) of the Act because the Secretary has determined that this proposed rule will not have a significant impact on the operations of a substantial number of small rural hospitals.
Section 202 of the Unfunded Mandates Reform Act of 1995 requires that agencies assess anticipated costs and benefits before issuing any rule whose mandates require spending in any 1 year by State, local, or tribal governments, in the aggregate, or by the private sector, of $136 million. This proposed rule would have no effect on the annual expenditures of any State, local or tribal government, or the private sector.
Executive Order 13132 establishes certain requirements that an agency must meet when it promulgates a proposed rule (and subsequent final rule) that imposes substantial direct requirement cost on State and local governments, preempts State law, or otherwise has Federalism implications. Since this proposed rule does not impose any costs on State or local governments, the requirements of Executive Order 13132 are not applicable.
In light of the statutory mandate in section 6402(a) of the Affordable Care Act, we did not consider any alternatives to the implementation of this provision. We did, however, contemplate several operational mechanisms to alleviate the burden on the provider and supplier communities.
First, we considered and elected to utilize the existing voluntary refund process. This would allow providers and suppliers to use a reporting mechanism with which they are already familiar.
Second, we contemplated the appropriate length of time in which overpayments must be reported and returned. A time period of less than 10 years was considered, as this would ease the burden on providers and suppliers. However, and as explained earlier, we selected 10 years because this is the outer limit of the False Claims Act statute of limitations. More importantly, we believe that the need to protect the Medicare Trust Fund was of primary importance. It is not possible for us to calculate the costs associated with a 10-year period versus, for instance, a 5-year period. We do, though, solicit comments on this issue, similar to our earlier solicitation of comments on the propriety of a 10-year period.
Third, as with the overpayment reporting period, we contemplated a reopening timeframe of less than 10 years. Yet we selected a 10-year timeframe in order to ensure that our reopening regulations are consistent with the 10-year lookback period. The costs of a shorter lookback period cannot be estimated, though we welcome comments on this issue.
We solicit comment on the analysis provided in this section.
We do not anticipate any impact on beneficiary access to care as a result of this proposed rule. As mentioned, the only burden associated with our proposed provisions involves the ICR aspects of reporting and returning overpayments. We do not believe that this burden—which, in any event, would only affect a small percentage of providers and suppliers—would cause a particular provider or supplier to reduce the services it furnishes to beneficiaries.
Claims, Freedom of information, Health facilities, Medicare, Privacy.
Administrative practice and procedure, Health facilities, Health professions, Kidney diseases, Medical devices, Medicare, Reporting and recordkeeping requirements, Rural areas, X-rays.
For the reasons set forth in the preamble, the Centers for Medicare & Medicaid Services proposes to amend Chapter IV as set forth below:
1. The authority citation for part 401 continues to read as follows:
Secs. 1102 and 1871 of the Social Security Act (42 U.S.C. 1302 and 1395hh).
2. Part 401 is amended by adding subpart D to read as follows:
This subpart sets forth the policies and procedures for reporting and returning overpayments to the Medicare program for providers and suppliers of services under Parts A and B of title XVIII of the Act as required by section 1128J of the Act.
For purposes of this subpart—
(a)
(2) A person has identified an overpayment if the person has actual knowledge of the existence of the overpayment or acts in reckless disregard or deliberate ignorance of the existence of the overpayment.
(b)
(i) The date which is 60 days after the date on which the overpayment was identified.
(ii) The date any corresponding cost report is due, if applicable.
(2) The deadline for returning overpayments will be suspended when either of the following occurs:
(i) OIG acknowledges receipt of a submission to the OIG Self-Disclosure Protocol until such time as a settlement agreement is entered, the person withdraws from the OIG Self-Disclosure Protocol, or the person is removed from the OIG Self-Disclosure Protocol.
(ii) CMS acknowledges receipt of a submission to the Self-Referral Disclosure Protocol until such time as a settlement agreement is entered, the person withdraws from the Self-Referral Disclosure Protocol, or the person is removed from the Self-Referral Disclosure Protocol.
(c)
(2) In instances when the provider—
(i) Receives more recent CMS information on the SSI ratio, the provider is not required to return any overpayment resulting from the updated information until the final reconciliation of the provider's cost report occurs; or
(ii) Knows that an outlier reconciliation will be performed, the provider is not required to estimate the change in reimbursement and return the estimated overpayment until the final reconciliation of that cost report.
(d)
(1) Person's name.
(2) Person's tax identification number.
(3) How the error was discovered.
(4) The reason for the overpayment.
(5) The health insurance claim number, as appropriate.
(6) Date of service.
(7) Medicare claim control number, as appropriate.
(8) Medicare National Provider Identification (NPI) number.
(9) Description of the corrective action plan to ensure the error does not occur again.
(10) Whether the person has a corporate integrity agreement with the OIG or is under the OIG Self-Disclosure Protocol.
(11) The timeframe and the total amount of refund for the period during which the problem existed that caused the refund.
(12) If a statistical sample was used to determine the overpayment amount, a description of the statistically valid methodology used to determine the overpayment.
(13) A refund in the amount of the overpayment. A person may request an extended repayment schedule as that term is defined in § 401.603.
(e)
(2) A person satisfies the reporting obligations of this section by making a disclosure under the OIG's Self-Disclosure Protocol resulting in a settlement agreement using the process described in the OIG Self-Disclosure Protocol.
(f)
(g)
3. In § 401.607(c)(2)(i), the definition of “Hardship” is amended by removing the phrase “outstanding overpayments (principal and interest)” and adding in its place the phrase “outstanding overpayments (principal and interest and including overpayments reported in accordance with §§ 401.301 through 401.305.)”
4. The authority for part 405 continues to read as follows:
Secs. 1102, 1862, and 1871 of the Social Security Act as amended (42 U.S.C.1302, 1395y, and 1395hh).
5. Section 405.980 is amended by adding paragraph (b)(6) to read as follows:
(b) * * *
(6) Within 10 years from the date of initial determination or redetermination if the overpayment is reported in accordance with § 401.305.
Federal Communications Commission.
Proposed rule.
This Fourth FNPRM seeks comment on whether it would be in the public interest to extend the viewability rule and the HD carriage exemption, both of which are currently scheduled to sunset on June 12, 2012. First, we seek comment on whether to extend, in its current form, the “viewability” rule, which implements the statutory requirement that all cable subscribers, including those with analog equipment, be able to view must carry television signals. Second, given the apparent widespread reliance of small cable
Submit comments on or before March 12, 2012. Submit replies on or before March 22, 2012.
Lyle Elder,
The proceeding this Fourth FNPRM initiates shall be treated as a “permit-but-disclose” proceeding in accordance with the Commission's
Filings can be sent by hand or messenger delivery, by commercial overnight courier, or by first-class or overnight U.S. Postal Service mail. All filings must be addressed to the Commission's Secretary, Office of the Secretary, Federal Communications Commission.
All hand-delivered or messenger-delivered paper filings for the Commission's Secretary must be delivered to FCC Headquarters at 445 12th St. SW., Room TW-A325, Washington, DC 20554. The filing hours are 8 a.m. to 7 p.m. All hand deliveries must be held together with rubber bands or fasteners. Any envelopes and boxes must be disposed of
Commercial overnight mail (other than U.S. Postal Service Express Mail and Priority Mail) must be sent to 9300 East Hampton Drive, Capitol Heights, MD 20743.
U.S. Postal Service first-class, Express, and Priority mail must be addressed to 445 12th Street SW., Washington, DC 20554.
1. In 2007, the Commission adopted certain rules to protect consumers as the transition to digital television (DTV) approached.
2. Also in 2007, the Commission adopted a related rule regarding the prohibition on material degradation of broadcast signals when carried by cable systems. One aspect of this rule is the requirement that any signal broadcast in high definition (“HD”) also be carried by cable operators in HD. In response to concerns from commenters about cost and technical capacity, the Commission granted a three-year exemption from this HD carriage rule to the operators of certain small cable systems. As with the viewability rule, the Commission held that the small cable HD exemption would sunset in three years absent action by the Commission to revise or extend it. Thus, this exemption will also expire on June 12, 2012 unless the Commission takes action to extend it.
3. We initiate this Fourth Further Notice of Proposed Rulemaking (Fourth FNPRM) in the DTV cable carriage docket to determine whether it would be in the public interest to extend this rule and exemption. For the reasons described below, we seek comment on whether to extend the “viewability” rule for three more years to ensure that all cable subscribers, including those with analog equipment, continue to have access to must carry television signals. Given the apparent widespread reliance of small cable operators on the HD exemption, we propose to extend it for an additional three years, but ask whether this should be the final extension. We note that both rule and exemption would have expired on February 17, 2012 if the DTV transition had not been delayed by Congress. The Commission is therefore concurrently issuing a Declaratory Order clarifying that both the viewability rule and the HD Carriage Exemption will sunset on June 12, 2012, absent Commission action to extend them.
4. Pursuant to Section 614(b)(4)(B) of the Communications Act of 1934, as amended (the “Act”),
5. In the
6. Since passage of the 1992 Cable Act, the Commission has consistently found that “mere transmission of the must-carry signal is not sufficient to meet the requirements” of the statute.
We believe that the 1992 Act is clear in its requirement that all local commercial television stations carried in fulfillment of the must-carry requirements must be provided to every cable subscriber and must be viewable on all television sets that are connected to the cable system by a cable operator for which the cable operator provides a connection. The Act does not give the Commission authority to exempt any class of subscribers from this requirement.
7. As the Commission also made clear in 2007, viewability of broadcast signals is not only mandated by statute, but is also of vital importance to the broadcast stations that rely on the Commission's “must carry” rules and to all consumers of television programming. The Commission noted that,
Furthermore, the Commission found that, without action, “analog cable subscribers and households that rely solely on over-the-air broadcast television may well face ‘a reduction in the number of media voices’ and the loss of `the widest possible dissemination of information from diverse and antagonistic sources.'”
8. In order to ensure that digital signals would be actually viewable by all subscribers, the Commission adopted a two-part rule and allowed systems to choose how they would comply. Section 76.56(d)(3) of the Commission's rules provides:
(3) The viewability and availability requirements of this section require that, after the broadcast television transition from analog to digital service for full power television stations cable operators must either:
(i) Carry the signals of commercial and non-commercial must-carry stations in analog format to all analog cable subscribers, or
(ii) For all-digital systems, carry those signals in digital format, provided that all subscribers, including those with analog television sets, that are connected to a cable system by a cable operator or for which the cable operator provides a connection have the necessary equipment to view the broadcast content.
This rule ensures that all subscribers are able to view must-carry programming, while still providing flexibility to operators who have been, and continue to be, transitioning to an all-digital system on their own schedules.
9. We seek comment on whether we should extend the viewability rule or permit it to sunset.
10. The sunset of the viewability rule would potentially impact millions of subscribers, and the broadcasters who would be unable to reach them.
11. As discussed in the
12. Furthermore, the Commission affirmed in the
13. We note that some cable operators, such as RCN and BendBroadband, transmit only digital signals and have eliminated analog service in all of their systems.
14. We seek comment on whether to extend the existing viewability rule. To the extent the Commission decides to retain the rule, we seek comment on whether it should be retained for another three years or a different period of time. Is three years too long or is a sunset at some later date more advisable? The Commission considered possible alternative rules in the
15. Unlike the alternatives proposed, the rule the Commission adopted in 2007 ensures viewability by all subscribers, while simultaneously giving cable operators the flexibility to choose the best option for complying with their viewability obligations.
16. Finally, we seek comment on any other proposals that would achieve the results necessary to assure the viewability of must-carry signals through an approach different than that of our existing rule. To the extent any parties find the current rule burdensome, we seek comment on proposals that will satisfy the statute in a less burdensome manner. Is any rule necessary to effectuate the statutory intent? If so, any proposals for an alternative rule to ensure the actual viewability of must-carry signals should include specific proposed wording, as well as an analysis of how the proposal is consistent with the statute.
17. The Act also requires that cable operators carry broadcast signals “without material degradation.”
18. Based on the comments received in response to the
19. The exemption was not intended to be permanent, however. The Commission instead provided it for a three-year window, in order to give small systems “a clear opportunity to come into compliance with the rules by spreading their effort and costs over an extended period.”
20. We tentatively conclude that it is in the public interest to extend the small-system HD exemption for another three years because the number of systems relying on the exemption indicates that three years did not provide sufficient time for some small systems to come into compliance in a cost-effective way.
21. As noted above, the central purpose of the exemption was to provide small systems with additional time to upgrade and, where necessary, expand their systems to come into full compliance with the material degradation provisions of the carriage rules by carrying HD versions of all HD broadcast signals without making relatively large expenditures over a short period of time.
22. Comments at the time of the initial grant of this exemption indicated that it was necessary to protect the economic health of some small systems, and indeed that some systems might become too expensive to continue operation without the exemption.
23. Subsequent to the Commission's adoption of the
24. The
25. As required by the Regulatory Flexibility Act of 1980, as amended (“RFA”)
26. This
27. The authority for the action proposed in this rulemaking is contained in Sections 4, 303, 614, and 615 of the Communications Act of 1934, as amended, 47 U.S.C. 154, 303, 534, and 535.
28. The RFA directs the Commission to provide a description of and, where feasible, an estimate of the number of small entities that will be affected by the proposed rules if adopted.
29.
30. In addition, an element of the definition of “small business” is that the entity not be dominant in its field of operation. We are unable at this time to define or quantify the criteria that would establish whether a specific television station is dominant in its field of operation. Accordingly, the estimate of small businesses to which rules may apply do not exclude any television station from the definition of a small business on this basis and are therefore over-inclusive to that extent. Also, as noted, an additional element of the definition of “small business” is that the entity must be independently owned and operated. We note that it is difficult at times to assess these criteria in the context of media entities and our estimates of small businesses to which they apply may be over-inclusive to this extent.
31.
32.
33.
34.
35. The
36. 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 (among others): (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.
37. The requirements proposed in the
38. None.
39.
40.
41.
Administrative practice and procedure, Cable television, Equal employment opportunity, Political candidates, Reporting and recordkeeping requirements.
For the reasons discussed in the preamble, the Federal Communications Commission proposes to amend 47 CFR part 76 as follows:
1. The authority citation for part 76 continues to read as follows:
47 U.S.C. 151, 152, 153, 154, 301, 302, 302a, 303, 303a, 307, 308, 309, 312, 315, 317, 325, 339, 340, 341, 503, 521, 522, 531, 532, 534, 535, 536, 537, 543, 544, 544a, 545, 548, 549, 552, 554, 556, 558, 560, 561, 571, 572, 573.
2. Section 76.56 is amended by revising paragraph (d)(5) to read as follows:
(d) * * *
(5) The requirements set forth in paragraph (d)(3) of this section shall cease to be effective June 12, 2015, unless the Commission extends the requirements prior to that date.
The following pages will not appear in the Code of Federal Regulations.
1. The FCC collects data from cable operators annually on the “Annual Report of Cable Systems” also called “Form 325.” Through this form, the FCC collects basic operational information from cable television systems nationwide, including data about their architecture, capacity and number of subscribers. Each year the FCC designates a sample of cable systems having fewer than 20,000 subscribers and all systems having 20,000 or more subscribers to file Form 325. Staff performed an analysis of the Form 325 data from the 2010 filing year for use in the viewability proceeding.
2. Filers of Form 325 report information on the channels carried, including for broadcast channels whether the channel is carried pursuant to a must-carry designation or a retransmission consent agreement. Staff analyzed the 2010 filings and found that approximately 780 of 2000 full-service and low-power stations elected or defaulted to must carry.
3. To make this approximation, staff first extracted from the Form 325 database all records where a cable operator marked a channel as either retransmission-consent or must-carry. A single broadcast station often has multiple entries on the Form 325 if the operator carried multiple versions to comply with the viewability requirements or if the operator chose to carry multicast streams of a single station. For example, WXXX-TV was reported 92 times by 25 cable systems with 7 different spellings.
4. Next, the staff reduced the number of entries per cable system to one by considering that if at any one of those entries was marked as must-carry, then that station was must-carry on that cable system. The dataset for WXXX was then reduced to one report for each of the 25 cable systems. If any one of the entries for a cable system was marked as must-carry, the report for that cable system was must-carry.
5. Due to either different elections on different cable systems or accidental misreporting by cable operators, many stations had a mixture of must-carry and retransmission-consent reports.
6. The staff aggregated the reports, and if operators reported a station as must-carry as or more often as operators reported that station as retransmission-consent, the staff considered that station to prefer must-carry. In this case, the majority of cable systems reports retransmission consent, so WXXX was assigned a single preference:
7. The process was repeated for each of the approximately 2000 broadcast stations listed in the 325 reports. In the event of an equal number of systems reporting must-carry and retransmission consent, the station was considered to have chosen must-carry.
8. Staff analyzed the “number of digital channels activated” and “number of analog channels activated” data fields in the Form 325 reports from filing year 2010. A hybrid system has at least one activated analog channel and at least one activated digital channel. As the Form 325 is collected by a sample of cable systems, staff performed the below analysis to determine that 56.8 million of the 62 million cable subscribers are on hybrid systems.
9. Of the 565 systems that reported more than 20,000 subscribers, 542 were hybrid systems, with those systems serving 46.6 million subscribers. No scaling factor was necessary as reports must be filed by all systems with more than 20,000 subscribers.
10. Of the 249 systems that reported between 5,000 and 20,000 subscribers, 233 were hybrid systems serving 2.7 million subscribers. A representative sample of systems with between 5,000 and 20,000 is asked to file reports each year. Based on previous years' Form 325 reports and other research, staff estimated that there are 451 such systems in total. When the data was extrapolated, staff estimated that 422 of the 451 systems are hybrid. Thus, the 2.7 million subscribers were scaled by a multiple of (422/233), yielding an estimated total of 4.9 million subscribers.
11. Of the 154 systems that reported fewer than 5000 subscribers, 91 were hybrid systems serving 184 thousand subscribers. A representative sample of systems with fewer than 5000 subscribers is asked to file reports each year. Based on previous years' Form 325 reports and other research, staff estimated that there are 4450 such systems in total. When the data was extrapolated, staff estimated that 2630 of the 4450 systems are hybrid. When scaled by a multiple of (2630/91), staff estimated that there are a total of 5.3 million subscribers served by these systems.
12. Staff summed the total number of subscribers served by hybrid systems and came up with a result of 56.8 million such subscribers (46.6 million + 4.9 million + 5.3 million).
Staff used a similar process as described above to estimate the total number of cable subscribers in the U.S. as approximately 62 million. This total is close to other publicly available estimates of cable subscribers.
1. Open session, Tuesday, February 28, 2012,
2. Closed session, Tuesday, February 28, 2012,
Due to security requirements and limited seating, all individuals wishing to attend the open session of the meeting must notify Sarah Conway at (202) 233-8811 or
Food and Nutrition Service, USDA.
Notice.
In accordance with the Paperwork Reduction Act of 1995, this notice invites the public and other public agencies to comment on this proposed information collection. This is a revision to a previous data collection to understand better the shopping patterns of SNAP participants at farmers' markets. The purpose of this collection is for the Food and Nutrition Service to understand how private organizations operate Supplemental Nutrition Assistance Program (SNAP) financial incentive programs for clients purchasing fruits and vegetables at farmers' markets. Information collected will be used to examine how these organizations design, operate, and evaluate incentive programs to encourage SNAP clients to shop for fruits and vegetables at farmers' markets. It will also assist in assessing how much these programs influence the purchase of fruits and vegetables at farmers' markets using SNAP benefits.
Written comments must be received on or before April 16, 2012.
Comments are invited on: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden on the proposed collection of information, including the validity of the methodology and assumptions that were used; (c) ways to enhance the quality, utility, and clarity of the information collected; and (d) ways to minimize the burden of the collection of information on those who are to respond, including the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology.
All written comments will be open for public inspection at the Office of Research and Analysis, Food and Nutrition Service during regular business hours (8:30 a.m. to 5 p.m. Monday through Friday) at 3101 Park Center Drive, Room 1014, Alexandria, Virginia 22302.
All responses to this notice will be summarized and included in the request for Office of Management and Budget approval. All comments will be a matter of public record.
Requests for additional information or copies of this information collection should be directed to Steven Carlson at 703-305-2017.
This study is not intended to be nationally representative. Organizations to be included in this study will be chosen from a list of private organizations that is developed based on responses received from farmers' market managers responding to the FNS study, Nutrition Assistance in Farmers' Markets: Understanding Current Operations (76 FR 79646, 12/22/11). To assist in the selection process, the list will tentatively categorize the organizations (Business-for and not-for-profit) into three groups:
(1) Type I: fairly large organizations that provide grant money to other organizations that administer incentive program for SNAP clients;
(2) Type II: smaller than the Type I organizations, Type II organizations distribute the SNAP financial incentives to farmers' markets and administer the incentive program for SNAP clients in the markets that they support; and
(3) Type III: local organizations that provide money for incentive program for SNAP clients.
Further stratification of the frame may be made based on whether the organizations also provide non-financial support. Non-financial support might include providing information and technical assistance for implementing or managing incentive program for SNAP clients or providing staff to work at the farmers' markets and assist with the management of the programs onsite.
There are two main data collection activities for this study. They include:
• Conducting a telephone interview with each of one to three key staff at selected organizations that provide and/or administer farmers' market SNAP incentives. The interview is designed to gather qualitative data to better understand the:
○ Relationship of the organizations to the farmers' markets that obtain incentive funds for SNAP clients;
○ Primary mission of the organizations and their history with SNAP;
○ Source of the financial support for the organizations' incentive program for SNAP clients, and whether other types of support are offered;
○ Number of markets a specific organization supported in 2012;
○ Selection process and requirements for farmers' markets to be awarded incentive dollars for distribution to SNAP clients;
○ Factors that make it difficult to implement and manage incentive programs; and
○ Characteristics of successful incentive programs.
The telephone interview will also capture information on whether the organizations maintain and/or collect information on the performance of their incentive program. This self-evaluation data may include information regarding the number of incentives redeemed by markets with an incentive program, vendor satisfaction with the program, and/or data used for assessing the impact of these programs on farmers' market sales and SNAP participation at farmers' markets.
• Collecting and evaluating self-evaluation data of participating organizations. Organizations identified during the telephone interviews as maintaining data on their incentive program for SNAP clients will be asked to share this data for the purpose of this research study. Self-evaluation data shared by organizations may include for example, the number of other organizations or farmers' markets that they awarded or are managing financial incentive programs for, the volume of SNAP incentive redemptions, dollar amount of unredeemed incentives, and other information. These data will help identify differences across incentive programs with respect to performance in 2012. In combination, the self-evaluation data, organizational and incentive program characteristics obtained through interviews, and ALERT data, will inform how such incentive programs for SNAP clients may work best in the context of individual markets.
Food and Nutrition Service.
Forest Service, USDA.
Notice of intent to prepare an environmental impact statement.
The USDA, Forest Service, Los Padres National Forest, gives notice of intent to conduct analysis and prepare an Environmental Impact Statement (EIS) for the removal of the noxious weed Tamarisk across the Los Padres National forest: This notice announces the beginning of scoping, describes the proposed action, decisions to be made, and estimates the dates for filing the draft and final EIS. This notice also provides information concerning public participation, and the names and addresses of the Agency officials who can provide information.
Comments concerning the scope of the analysis will be received for 45 days from publication in the
Send written comments to Los Padres National Forest, 6755 Hollister Avenue, Suite 150, Goleta, CA 93117, attention: Lloyd Simpson, Forest Botanist. Comments may also be sent via e-mail to:
Comments received in response to this solicitation, including names and addresses of those who comment, will be part of the public record for this proposed action.
Questions about the proposed action may be directed to Project Team Leader, Lloyd Simpson, Los Padres National Forest, Ojai Ranger District, 1190 E. Ojai Ave., Ojai, CA 93023; or by telephone: (805) 646-4348 ext. 316. 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 Time, Monday through Friday.
There is a need to eradicate the noxious weed tamarisk from Piru Creek, Lockwood Creek, Cuyama River, Santa Ynez River, Sisquoc River, and Arroyo Seco River in order to restore and maintain habitat for riparian dependent species such as the federally listed arroyo toad, California red-legged frog, and steelhead trout. The purpose of this project is to eradicate tamarisk in a timely manner and with an approach that is pest-specific, cost effective, and safe for the human and aquatic environments.
The project area is on the Los Padres National Forest in portions of the Piru Creek, Lockwood Creek, Cuyama River, Santa Ynez River, Sisquoc River, and Arroyo Seco River watersheds. The analysis area covers 4,247 acres and 368 miles of perennial and intermittent streams. Infestations of tamarisk occurring in these streams and their tributaries within the analysis area are targeted for removal.
For fish and wildlife, direction is provided to maintain fisheries habitat for viable populations of native fish species and to prevent the destruction or adverse modification of habitat essential to threatened, endangered, or sensitive species. The Forest Plan states that “management activities or practices may occur in riparian areas as long as habitat and species diversity of the area is maintained in a healthy state” and
The Los Padres National Forest (LPNF) proposes to control the invasive species tamarisk in portions of the Piru Creek, Lockwood Creek, Cuyama River, Santa Ynez River, Sisquoc River, and Arroyo Seco River watersheds. This action will result in the improvement of riparian ecosystems that have been impacted by the invasion of tamarisk.
Tamarisk has replaced the native riparian plant community of willows, cottonwoods and other desirable native riparian species. Its water-consuming ability has reduced the surface water available to wildlife. The best management strategy is to enact control measures now before the tamarisk infestations become any larger.
Successful invasive species control programs are implemented at the landscape level, particularly within watersheds for species that colonize stream courses. Partnerships are especially important for accomplishing weed control. Volunteers have worked for many years on the Los Padres to remove and control tamarisk. They will continue to be part of this effort.
Tamarisk infestations have various impacts on a number of federally listed threatened (FT) and endangered (F-E) species, as well as some Region 5 Forest Service Sensitive (R5-S) species. Federally listed endangered Least Bell's vireo and Southwestern Willow Flycatcher have been known to nest in large groves of habitat dominated by tamarisk, but this is not likely in the Los Padres NF given the scattered nature of the present tamarisk populations. However, it is well documented that tamarisk removal will restore natural habitat for these birds as well as arroyo toad (F-E), California red-legged frog (F-T), southwestern pond turtle (R5-S), two-striped garter snake (R5-S) and steelhead trout (both F-E and F-T) stocks.
This project is designed to eradicate current infestations of Tamarisk (Tamarix ramosissima, T chinensis, T gallica, T parviflora) and to prevent its further spread on National Forest System land. Tamarisk is a nonnative invasive tree-shrub that can grow in dense patches, out-compete native vegetation, change soil chemistry by depositing salts in deep ground water on the soil surface, and remove large amounts of water from streams and riparian areas via evapo-transpiration through its foliage. This project covers portions of the Piru Creek, Lockwood Creek, Cuyama River, Santa Ynez River, Sisquoc River, and Arroyo Seco River watersheds.
The current tamarisk infestation covers 368 miles or 4,247 acres of riparian habitat on NFS lands. The goal is to implement control measures now before tamarisk becomes a larger problem in riparian ecosystems.
The methods of tamarisk eradication have several constraints in this project: (1) Many treatment areas are very steep, making access and logistics difficult. There is no motorized access to most of the project area, much of it is in Congressionally designated Wilderness. All supplies and equipment must either be packed or flown in. Pile-burning cut tamarisk stems is not feasible due to the logistics of getting crews and suppression resources down into the canyons to do it. (2) There are few suitable areas to relocate tamarisk stems for disposal via burn piles. (3) There is habitat known for Least Bell's Vireo and Southwestern Willow Flycatcher, two federally endangered birds in the Piru creek watershed. The habitat area contains scattered tamarisk within the riparian vegetation.
The proposed action is a combination of tamarisk treatment methods designed to be as light on the land as possible and at the same time cost and labor efficient. The methods used will be a combination of hand treatments, herbicide applications, and biological control. Tamarisk seedlings will be removed by hand by pulling and placing them where they cannot reestablish. Herbicides are essential to meet the project objectives. Tamarisk will re-sprout if simply cut down and/or burned. Herbicide treatments are the most effective and the most efficient control method currently available. Herbicide use will be consistent with the Forest Service Pesticide Use Policy, will be in compliance with state and federal regulations, will follow Region 5 Best Management Practices for Vegetation Manipulation, the Region 5 Supplement for Pesticide-Use Management and Coordination, and the Forest Plan guidance including the Supplement to Soil and Water Conservation Practices FSH 2509.22-2005-1. A bio-control insect bred to assist in the treatment and control of tamarisk infestations is currently available. While tamarisk distribution across NFS land may be too spread out to maintain effective populations of a control insect, use of the insect may be appropriate in areas where there is higher tamarisk density.
Herbicide treatments will be restricted to ground-based/hand applications only; NO AERIAL SPRAYING is being proposed.
Seedlings and young plants will be hand-pulled where possible and removed from the riparian area and placed in the sun minimizing soil contact with the roots. Experience with hand pulling has shown that only plants 1 foot tall or less can be successfully removed. We will begin removing the younger plants on the boundaries of infestations and do as much as we can each year.
Large tamarisk within 10 horizontal feet of standing or running water will be treated with imazapyr (Habitat or similar formulation). Treatment type will depend on size of the individual tamarisk plant and the access available to do the treatment. Cut plant material will be removed from the waterway but left in small piles as wildlife habitat.
For plants beyond the 10 horizontal feet of standing or running water, another herbicide, triclopyr (Garlon 4 or similar formulation) may be used. Triclopyr is not labeled for use around water and would only be used on upland plants. Treatments would be similar to imazapyr and based on plant size. Cut material will be disposed of in the same way as the cut riparian tamarisk described earlier.
• To avoid trampling of arroyo toads and California red-legged frogs, a qualified biologist would conduct a training session for all project personnel prior to conducting the proposed action in habitat for arroyo toads and California red-legged frogs. At a minimum, the training would include a description of the arroyo toad and its habitat, the general provisions of the Endangered Species Act; the necessity for adhering to the provisions of the Act; the penalties associated with violating the provisions of the Act; the general measures that are being implemented to conserve the listed species as they relate to the project; and the access routes to and from project site boundaries within which the treatments may be accomplished.
• In arroyo toad and California red-legged frog habitat, all routes to treatment sites would be identified by a qualified biologist and used repeatedly by workers to minimize trampling of arroyo toads and vegetation.
• Applicators would avoid walking or stepping in water, to the maximum extent possible. They would also avoid spilling herbicide on footwear and clothing to prevent inadvertent contamination if contact with water occurs.
• All access routes and treatment sites within arroyo toad and California red-legged frog habitat would be thoroughly searched for the presence of arroyo toads and California red-legged frog by a qualified biologist, prior to the onset of project activities at each site. This should occur within two weeks of work commencement.
• Arroyo toads and California red-legged frog found within the treatment sites shall be carefully moved outside the immediate work area and released by a qualified biologist permitted by USFWS to handle these species. Animals found within access routes may be moved to appropriate habitat if their avoidance is not practicable. If project activities cease for more than three days within any one treatment site, access routes and treatment areas would be searched again for arroyo toads and California red-legged frog prior to the start of the day's work. Information that includes the date, time of capture, specific location of capture, approximate size, age and health of the individual would be recorded.
• Treatments will be conducted during low stream flow or no stream flow periods of the year to avoid potential impacts to steelhead trout or their spawning redds during the late fall to early winter months.
• If workers encounter aquatic wildlife species other than arroyo toads and California red-legged frog during project implementation they will allow the animal(s) to flee to safe areas out of the work sites or physically move the animals to safe locations.
A full range of alternatives will be considered including action and no-action. Alternatives responding to issues generated during the scoping process and interdisciplinary team project development will also be developed and considered. All alternatives will comply with the Los Padres National Forest Land Management Plan.
Peggy Hernandez, Forest Supervisor, Los Padres National Forest, Goleta California, is the responsible official for the EIS and its Record of Decision. As the Responsible Official, the Forest Supervisor will document the decision and reason for the decision in the Record of Decision. The decision will be subject to Forest Service Appeals Regulations (36 CFR part 215).
1. Whether the proposed action will proceed as proposed, with modifications, or not at all.
2. What associated mitigation measures and monitoring requirements will be required.
1. Hand removal is not controlling the current infestations of Tamarisk and herbicides are needed.
2. Use of herbicides and the need to protect water quality and public safety.
3. Presence of listed threatened and endangered species, their habitat, and/or mapped critical habitat.
This notice of intent initiates the scoping process, which guides the development of the environmental impact statement.
The Forest Supervisor is seeking public and agency comment on the proposed action to identify issues that arise from the proposed action. The issues may lead to other alternatives, or additional mitigation measure and monitoring requirements. In addition to this notice, public scoping letters will be mailed to interested parties.
It is important that reviewers provide their comments at such times and in such a way they are useful to the Agency's preparation of the environmental impact statement. The submission of timely and specific comments can affect a reviewer's ability to participate in subsequent administrative appeal of judicial review.
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
Copies of the above information collection proposal can be obtained by calling or writing Jennifer Jessup, Departmental Paperwork Clearance Officer, (202) 482-0336, 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
The Regulations and Procedures Technical Advisory Committee (RPTAC) will meet March 6, 2012, 9 a.m., Room 3884, in the Herbert C. Hoover Building, 14th Street between Constitution and Pennsylvania Avenues NW., Washington, DC. The Committee advises the Office of the Assistant Secretary for Export Administration on implementation of the Export Administration Regulations (EAR) and provides for continuing review to update the EAR as needed.
1. Opening remarks by the Chairman.
2. Opening remarks by Bureau of Industry and Security.
3. Export Enforcement update.
4. Regulations update.
5. Working group reports.
6. Automated Export System (AES) update.
7. Presentation of papers or comments by the Public.
8. Discussion of matters determined to be exempt from the provisions relating to public meetings found in 5 U.S.C. app. 2 §§ 10(a)(1) and 10(a)(3).
The open session will be accessible via teleconference to 20 participants on a first come, first serve basis. To join the conference, submit inquiries to Ms. Yvette Springer at
A limited number of seats will be available for the public session. Reservations are not accepted. To the extent that time permits, members of the public may present oral statements to the Committee. The public may submit written statements at any time before or after the meeting. However, to facilitate the distribution of public presentation materials to the Committee members, the Committee suggests that presenters forward the public presentation materials prior to the meeting to Ms. Springer via email.
The Assistant Secretary for Administration, with the concurrence of the delegate of the General Counsel, formally determined on January 11, 2012, pursuant to Section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. app. 2 § (10)(d)), that the portion of the meeting dealing with pre-decisional changes to the Commerce Control List and U.S. export control policies shall be exempt from the provisions relating to public meetings found in 5 U.S.C. app. 2 §§ 10(a)(1) and 10(a)(3). The remaining portions of the meeting will be open to the public.
For more information, call Yvette Springer at (202) 482-2813.
Import Administration, International Trade Administration, Department of Commerce.
As a result of the determination by the Department of Commerce (“the Department”) and the International Trade Commission (“ITC”) that revocation of the antidumping duty order on furfuryl alcohol from the People's Republic of China (“PRC”) would be likely to lead to continuation or recurrence of dumping and of material injury to an industry in the United States within a reasonably foreseeable time, the Department is publishing notice of the continuation of the antidumping duty order.
Jennifer Moats, AD/CVD Operations, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone: (202) 482-5047.
On September 1, 2011, the Department initiated a sunset review of the antidumping duty order on furfuryl alcohol from the PRC pursuant to section 751(c) of the Tariff Act of 1930, as amended (“the Act”).
The Department conducted an expedited sunset review of this order. As a result of its review, the Department found that revocation of the antidumping duty order would be likely to lead to continuation or recurrence of dumping and notified the ITC of the magnitude of the margins likely to prevail were the order to be revoked.
On February 6, 2012, the ITC published its determination pursuant to section 751(c) of the Act that revocation of the antidumping duty order on furfuryl alcohol from the PRC would be likely to lead to continuation or recurrence of material injury to an industry in the United States within a reasonably foreseeable time.
The merchandise covered by the order is furfuryl alcohol (C
The product subject to the order is classifiable under subheading 2932.13.00 of the Harmonized Tariff Schedule of the United States (“HTSUS”). Although the HTSUS subheading is provided for convenience and customs purposes, our written description of the scope of this proceeding is dispositive.
As a result of the determinations by the Department and the ITC that revocation of the antidumping duty order would be likely to lead to continuation or recurrence of dumping and material injury to an industry in the United States, pursuant to section 751(d)(2) of the Act, the Department hereby orders the continuation of the antidumping duty order on furfuryl alcohol from the PRC.
U.S. Customs and Border Protection will continue to collect antidumping duty cash deposits at the rates in effect at the time of entry for all imports of subject merchandise.
The effective date of continuation of this order will be the date of publication in the
This five-year (sunset) review and this notice are in accordance with sections 751(c) and 777(i)(1) of the Act and 19 CFR 351.218(f)(4).
Import Administration, International Trade Administration, Department of Commerce.
Effective Date: February 16, 2012.
The Department of Commerce (the Department) preliminarily determines that large power transformers from the Republic of Korea (Korea) are being, or are likely to be, sold in the United States at less than fair value, as provided in section 733(b) of the Tariff Act of 1930, as amended (the Act). The estimated dumping margins are listed in the “Suspension of Liquidation” section of this notice. Interested parties are invited to comment on this preliminary determination. Pursuant to requests from interested parties, we are postponing for 60 days the final determination and extending provisional measures from a four-month period to not more than six months. Accordingly, we will make our final determination not later than 135 days after publication of the preliminary determination.
David Cordell or Brian Davis, AD/CVD Operations, Office 7, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone: (202) 482-0408 or (202) 482-7924, respectively.
On August 10, 2011, the Department initiated the antidumping duty investigation on large power transformers from Korea.
On August 10, 2011, the Department notified all interested parties of its intent to select mandatory respondents for this investigation based on U.S. import data obtained from U.S. Customs and Border Protection (CBP) and set aside a period of time for parties to comment on the potential respondent selection. Parties were invited to submit comments within five calendar days from the date of that memorandum.
On August 29, 2011, and August 30, 2011, Department officials visited Canonsburg, Pennsylvania to meet with officials of Pennsylvania Transformer Technology Inc., a petitioner in this proceeding, and their legal counsel, and also toured their facility.
On September 2, 2011, the United States International Trade Commission (USITC) published its affirmative preliminary determination that there is a reasonable indication that an industry in the United States is materially injured or threatened with material injury, by reason of imports from Korea of large power transformers.
On September 16, 2011, we selected Hyundai Heavy Industries Co., Ltd. (Hyundai) and Hyosung Corporation (Hyosung) as the mandatory respondents in this investigation and issued the Department's antidumping duty questionnaire to both respondents on September 28, 2011.
Hyundai and Hyosung submitted responses to section A of the Department's antidumping duty questionnaire on November 2, 2011 and on November 16, 2011, both respondents submitted their responses to sections B (
On November 23, 2011, petitioners made a timely request pursuant to section 733(c)(1)(A) of the Act and 19 CFR 351.205(e) for a 50-day postponement of the preliminary determination and on December 6, 2011, the Department postponed the preliminary determination of this investigation until February 9, 2011.
On November 30, 2011, the Department received an allegation from petitioners that home market sales made by Hyosung were made at prices below the cost of production and on December 9, 2011, the Department initiated a sales-below-cost of production investigation with respect to Hyosung.
On November 21, 2011, the Department issued a supplemental questionnaire concerning Hyosung's section A-C responses. On December 12, and 19, 2011, Hyosung submitted its response to this supplemental questionnaire. On December 14, 2011, the Department issued a supplemental questionnaire regarding Hyosung's section D response.
On December 29, 2011, the Department issued a second supplemental questionnaire covering Hyosung's section A-C and supplemental responses. On January 6, 2012, we received the supplemental cost (
On November 21, 2011, the Department issued a supplemental questionnaire concerning Hyundai's section A-C responses. On December 12, 2011, Hyundai responded to this questionnaire. Also on December 12, 2011, Hyundai filed its response to the constructed value sections of the section D questionnaire.
On December 23, 2011, the Department issued a supplemental questionnaire to Hyundai covering Hyundai's section B-D responses. Hyundai responded to this supplemental questionnaire on January 13, and 18, 2012. On January 9, 2012, the Department issued a third sales supplemental questionnaire as well as a second supplemental cost questionnaire to which Hyundai responded on January 23, 2012.
On December 30, 2011, the Department received an allegation from petitioners that home market sales made by Hyundai were made at prices below the cost of production and on February 9, 2012, the Department decided not to initiate a sales-below-cost of production investigation.
With regard to cost estimates provided by respondents thus far, the Department will accept updated information for actual costs through and including December 31, 2011, where available. Further, with regard to estimates in the sales database, the Department will accept the corresponding actual sales information only through December 31, 2011. The Department does not expect to request updated information on sales or cost estimates for dates subsequent to December 31, 2011.
The period of investigation (POI) is July 1, 2010, to June 30, 2011. This period corresponds to the four most recent fiscal quarters prior to the month of the filing of the petition.
The scope of this investigation covers large liquid dielectric power transformers (LPTs) having a top power handling capacity greater than or equal to 60,000 kilovolt amperes (60 megavolt amperes), whether assembled or unassembled, complete or incomplete.
Incomplete LPTs are subassemblies consisting of the active part and any other parts attached to, imported with or invoiced with the active parts of LPTs. The “active part” of the transformer consists of one or more of the following when attached to or otherwise assembled with one another: The steel core or shell, the windings, electrical insulation between the windings, the mechanical frame for an LPT.
The product definition encompasses all such LPTs regardless of name designation, including but not limited to step-up transformers, step-down transformers, autotransformers, interconnection transformers, voltage regulator transformers, rectifier transformers, and power rectifier transformers.
The LPTs subject to this investigation are currently classifiable under subheadings 8504.23.0040,
In accordance with the preamble to the Department's regulations,
On August 23, 2011, we received comments from Hyundai and Hyosung concerning the scope of this investigation. In their submissions, both Hyundai and Hyosung request that the scope language be modified expressly to exclude spare parts when imported individually, or when imported with a complete LPT (whether assembled or unassembled) or with a subassembly, because they are not integral to the start-up or operation of an LPT.
On September 2, 2011, petitioners filed rebuttal comments regarding the scope comments by Hyundai and Hyosung. In their rebuttal comments, petitioners state that Hyundai and Hyosung failed to demonstrate the necessity for any exclusionary language and that the scope language published in the Department's
We preliminarily find that the language of the scope of the order is clear and does not require amendment.
We have considered the comments that were submitted by the interested parties concerning product-comparison criteria. In accordance with section 771(16) of the Act, all products produced by the respondents covered by the description in the “Scope of Investigation” section, above, and sold in Korea during the period of investigation are considered to be foreign like product for purposes of determining appropriate product comparisons to U.S. sales. We have relied on the following 18 criteria to match U.S. sales of subject merchandise to comparison-market sales of the foreign like product: (1) Number of phases; (2) maximum MVA rating; (3) transformer technology; (4) high line voltage; (5) high voltage winding basic insulation level; (6) number of windings in transformer; (7) type of tap changer and percentage regulation; (8) low line voltage; (9) impedance at maximum MVA rating; (10) type of core steel; (11) type of transformer; (12) low voltage winding basic insulation level; (13) load loss at maximum MVA rating; (14) no-load loss; (15) cooling class designation; (16) overload requirement; (17) decibel rating; and (18) frequency. We compared U.S. sales to sales of the next most similar foreign like product on the basis of the characteristics listed above, which were made in the ordinary course of trade. Where we were unable to find a home market match of such or similar merchandise, in accordance with section 773(a)(4) of the Act, we based NV on CV. Where appropriate, we made adjustments to CV in accordance with section 773(a)(8) of the Act.
19 CFR 351.401(i) states that, in identifying the date of sale of the merchandise under consideration or foreign like product, the Secretary normally will use the date of invoice, as recorded in the exporter or producer's records kept in the ordinary course of business. Additionally, the Secretary may use a date other than the date of invoice if the Secretary is satisfied that a different date better reflects the date on which the exporter or producer establishes the material terms of sale.
In this case, Hyosung argued that the date of sale should be the purchase order date.
Since that time, petitioners have raised concerns about the reported date of sale, arguing that we should “rely on the
For the purposes of this preliminary determination, we are using the purchase order date as the date of sale because record evidence currently demonstrates that this date best reflects the date upon which the material terms of sale were established. However, we are excluding from our analysis those sales which are known to be based on long term contracts executed prior to the POI because it is unclear whether the material terms of these sales were set during the POI. We will further examine whether there is other information that denotes a more appropriate date of sale as it is unclear from the record whether the material terms of these sales were set prior to the POI. We intend to issue one final supplemental questionnaire to each respondent regarding the date of sale issue.
To determine whether respondents' sales of large power transformers from Korea to the United States were made at LTFV, we compared the constructed export price (CEP) to normal value (NV) or constructed value, as appropriate and as described in the “Constructed Export Price” and “Normal Value” sections of this notice. In accordance with section 777A(d)(1)(A)(i) of the Act, we compared POI weighted-average CEPs to POI weighted-average NVs or constructed values, as appropriate.
For the price to the United States, we used CEP, in accordance with section 772(b) of the Act. We calculated CEP for those sales where a person in the United States, affiliated with the foreign exporter or acting for the account of the exporter, made the sale to the first unaffiliated purchaser in the United States of the subject merchandise.
In accordance with section 772(b) of the Act, we calculated CEP where the record established that sales made by Hyundai and Hyosung were made in the United States after the date of importation by or for the account of the producer or exporter, or by a seller affiliated with the producer or exporter, to a purchaser not affiliated with the producer or exporter.
In accordance with section 772(c)(2)(A) of the Act, and where appropriate, we made deductions from the starting price for certain billing adjustments, early payment discounts, quantity discounts, and certain other discounts, including rebates. We also made further deductions to price for certain movement expenses where appropriate, for foreign inland freight, inland insurance, foreign brokerage, U.S. inland freight, certain other transportation expenses, U.S. customs duties and U.S. brokerage and handling expenses, pursuant to section 772(c)(2)(A) of the Act.
Pursuant to section 772(d)(1) of the Act, we made additional adjustments to CEP for commissions, credit expenses, bank charges, direct selling expenses associated with costs incurred in the United States, and other indirect selling expenses in the United States associated with economic activity in the United States. Pursuant to section 772(d)(3) of the Act, we made an adjustment for CEP profit. For a detailed discussion of these adjustments,
In accordance with section 772(c)(2)(A) of the Act, and where appropriate, we made deductions from the starting price for certain movement expenses, foreign inland freight, foreign brokerage, foreign inland insurance, U.S. inland freight, international freight, marine insurance, and U.S. brokerage and handling expenses, pursuant to section 772(c)(2)(A) of the Act. Pursuant to section 772(d)(1) of the Act, we made additional adjustments to CEP for commissions, credit expenses, warranty expenses, inventory carrying costs incurred in Korea, direct selling expenses associated with costs incurred in the United States (
To determine whether there is a sufficient volume of sales in the home market to serve as a viable basis for calculating NV (
Pursuant to its regulations, the Department may use prices from sales made to affiliated parties if the price is comparable to the price at which the exporter or producer sold the foreign like product to a non-affiliate.
In accordance with section 773(a)(1)(B) of the Act, to the extent practicable, we determine NV based on sales in the comparison market at the same level of trade (LOT) as the export price or CEP.
To determine whether NV sales are at a different LOT than CEP sales, we examine stages in the marketing process and selling functions along the chain of distribution between the producer and the unaffiliated customer.
In this investigation, we obtained information from Hyundai and Hyosung regarding the marketing stages involved by both parties making their reported home market and U.S. market sales, including a description of the selling activities performed by the respondents and/or their affiliates for each channel of distribution.
For a detailed description of our LOT methodology and a summary of the company-specific LOT findings for this preliminary determination,
Based on the Department's analysis of the Petitioners' allegation, we initiated a sales-below-cost investigation to determine whether Hyosung had sales that were made at prices below their COP pursuant to section 773(b) of the Act.
We calculated the COP based on the sum of the cost of materials and fabrication for the foreign like product, plus amounts for selling, general, and administrative (SG&A) expenses and packing, in accordance with section 773(b)(3) of the Act. We relied on the COP data submitted by respondents except where noted below. Based on the review of record evidence, respondents did not appear to experience significant changes in the cost of manufacturing during the period of investigation. Therefore, we followed our normal methodology of calculating an annual weighted-average cost.
We reclassified certain selling, G&A and other non-operating income and expense items that appeared not to be properly classified by Hyosung and revised Hyosung's calculation of the G&A expense ratio. For additional details,
We excluded unconsolidated foreign exchange gains and losses from Hyundai's G&A expenses and included the corresponding consolidated gains and losses in the calculation of the financial expense ratio according to our normal practice. We disallowed the offset to Hyundai's G&A expense for certain miscellaneous income items. For additional details,
With respect to Hyosung, on a product-specific basis, pursuant to section 773(a)(1)(B)(i) of the Act, we compared the adjusted weighted-average COP to the home market sales prices of the foreign like product, in order to determine whether the sale prices were below the COP. For purposes of this comparison, we used COP exclusive of selling and packing expenses. The prices were net of billing adjustments, movement charges, discounts, direct and indirect selling expenses and packing expenses, where appropriate.
Section 773(b)(1) provides that where sales made at less than the COP “have been made within an extended period of time in substantial quantities” and “were not at prices which permit recovery of all costs within a reasonable period of time” the Department may disregard such sales when calculating
Therefore, for Hyosung, we disregarded below-cost sales of a given product of 20 percent or more and used the remaining sales as the basis for determining NV, in accordance with section 773(b)(1) of the Act.
We calculated NV for Hyundai and Hyosung based on the reported packed, ex-factory or delivered prices to comparison market customers. We made deductions from the starting price, where appropriate, for billing adjustments, early payment and certain other discounts, other revenues received, inland freight and insurance, and warehousing expenses, pursuant to section 773(a)(6)(B)(ii) of the Act.
Pursuant to section 773(a)(6)(C)(iii) of the Act and 19 CFR 351.410(b), we made, where appropriate, circumstance-of-sale adjustments (
When comparing U.S. sales with comparison market sales of similar, but not identical, merchandise, we also made adjustments for physical differences in the merchandise in accordance with section 773(a)(6)(C)(ii) of the Act and 19 CFR 351.411. We based this adjustment on the difference in the variable cost of manufacturing for the foreign-like product and subject merchandise.
Where we were unable to find a home market match of such or similar merchandise, in accordance with section 773(a)(4) of the Act, we based NV on CV. Where appropriate, we made adjustments to CV in accordance with section 773(a)(8) of the Act.
In accordance with section 773(e) of the Act, we calculated CV based on the sum of Hyundai's and Hyosung's respective material and fabrication costs, SG&A expenses, profit, and U.S. packing costs. We calculated the COP component of CV as described above in the “Cost of Production Analysis” section of this notice. In accordance with section 773(e)(2)(A) of the Act, we based SG&A expenses and profit on the amounts incurred and realized by the respondents in connection with the production and sale of the foreign like product in the ordinary course of trade, for consumption in the foreign country.
We made currency conversions into U.S. dollars in accordance with section 773A(a) of the Act and 19 CFR 351.415(a) based on the exchange rates in effect on the dates of the U.S. sales as certified by the Federal Reserve Bank.
As provided in section 782(i)(1) of the Act, we intend to verify the information relied upon in making our final determination for Hyundai and Hyosung.
The weighted-average dumping margins are as follows:
In accordance with section 733(d)(2) of the Act, we will direct CBP to suspend liquidation of all entries of large power transformers from Korea that are entered, or withdrawn from warehouse, for consumption on or after the date of publication of this notice in the
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 or
The Department will disclose to parties the calculations performed in connection with this preliminary determination within five days of the date of publication of this notice.
Section 735(a)(2) of the Act provides that a final determination may be postponed until not later than 135 days after the date of the publication of the preliminary determination if, in the event of an affirmative preliminary determination, a request for such postponement is made by exporters, who account for a significant proportion of exports of the subject merchandise, or in the event of a negative preliminary determination, a request for such postponement is made by the petitioner. The Department's regulations, at 19 CFR 351.210(e)(2), require that requests by
On December 22, 2011, and January 5, 2012, Hyosung and Hyundai, respectively, requested that in the event of an affirmative preliminary determination in this investigation, the Department postpone its final determination by 60 days (135 days after publication of the preliminary determination) and extend the application of the provisional measures prescribed under section 733(d) of the Act and 19 CFR 351.210(e)(2), from a four-month period to a six-month period. In accordance with section 735(a)(2)(A) of the Act and 19 CFR 351.210(b)(2)(ii), because (1) our preliminary determination is affirmative; (2) the requesting producers/exporters account for a significant proportion of exports of the subject merchandise; and (3) no compelling reasons for denial exist, we are granting this request and are postponing the final determination until no later than 135 days after the publication of this notice in the
In accordance with section 733(f) of the Act, we have notified the USITC of the Department's preliminary affirmative determination. If the Department's final determination is affirmative, the USITC will determine before the later of 120 days after the date of this preliminary determination or 45 days after our final determination whether imports of large power transformers from Korea are materially injuring, or threatening material injury to, the U.S. industry.
Interested parties are invited to comment on the preliminary determination. Interested parties may submit case briefs to the Department no later than seven days after the date of the issuance of the last verification report in this proceeding.
In accordance with section 774(1) of the Act, the Department will hold a public hearing, if timely requested, to afford interested parties an opportunity to comment on arguments raised in case or rebuttal briefs, provided that such a hearing is requested by an interested party.
This determination is issued and published pursuant to sections 733(f) and 777(i)(1) of the Act.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of nominations.
NOAA is soliciting nominations for two individuals to serve as United States Commissioners to the International Pacific Halibut Commission (IPHC). This action is necessary to ensure that the interests of the United States and all of its stakeholders in the Pacific halibut fishery are adequately represented. The intended effect of this action is to improve transparency and stakeholder participation in the nomination process.
Nominations must be received by March 19, 2012.
Nominations for U.S. Commissioners to the IPHC should be made in writing to Mr. Patrick E. Moran, Office of International Affairs, National Marine Fisheries Service, at 1315 East-West Highway, Silver Spring, MD 20910. Nominations can also be sent via fax (301-713-2313) or email (
Mr. Patrick E. Moran, (301) 427-8370.
The IPHC is a bilateral regional fishery management organization established pursuant to the Convention between Canada and the United States for the Preservation of the Halibut Fishery of the North Pacific Ocean and Bering Sea (Convention). The Convention was signed at Ottawa, Ontario, on March 2, 1953, and was amended by a Protocol Amending the Convention signed at Washington, DC, on March 29, 1979. The Convention's central objective is to develop the stocks of Pacific halibut in waters off the west coasts of Canada and the United States to levels that will permit the optimum yield from the Pacific halibut fishery
Section 773a of the Northern Pacific Halibut Act of 1982 (16 U.S.C. 773a) requires that the United States be represented on the IPHC by three U.S. Commissioners. U.S. Commissioners are appointed for a term not to exceed 2 years, but are eligible for reappointment. Of the Commissioners:
(1) One must be an official of the National Oceanic and Atmospheric Administration; and
(2) two must be knowledgeable or experienced concerning the Northern Pacific halibut fishery; of these, one must be a resident of Alaska and the other shall be a nonresident of Alaska. Of the three commissioners described in paragraphs (1) and (2), one must also be a voting member of the North Pacific Fishery Management Council.
(3) Commissioners who are not Federal employees are not considered to be Federal employees except for the purposes of injury compensation or tort claims liability as provided in section 8101
In their official IPHC duties, Commissioners represent the interests of the United States and all of its stakeholders in the Pacific halibut fishery. These duties require a modest amount of travel (typically two or three trips per year lasting less than a week), and travel expenses are paid by the U.S. Department of State. Commissioners receive no compensation for their services.
The U.S. Department of Commerce is currently accepting nominations for two U.S. Commissioners for the IPHC who are not officials of the National Oceanic and Atmospheric Administration (NOAA). Successful nominees will be considered for appointment by the President and (pending Presidential action) interim designation by the Department of State.
Nomination packages should provide details of an individual's knowledge and experience in the Pacific halibut fishery. Examples of such knowledge and/or experience could include (but are not limited to) such activities as: Participation in commercial, tribal, Community Development Quota (CDQ) and/or sport and charterboat halibut fishing operations; participation in halibut processing operations; and participation in Pacific halibut management activities.
Nomination packages should document an individual's qualifications and state of residence. Self-nominations are acceptable, and current and former IPHC Commissioners are eligible for reappointment. Résumés, curriculum vitae, and/or letters of recommendation are useful but not required. Nomination packages will be evaluated on a case-by-case basis by officials in the Department of Commerce who are familiar with the duties and responsibilities of IPHC Commissioners; evaluations will consider the aggregate of an individual's prior experience and knowledge of the Pacific halibut fishery, residency requirements, and any letters of recommendation provided. Nominees will be notified of their status (including rejection or approval) and any need for further information once the nomination process is complete.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of public meetings.
The South Atlantic Fishery Management Council will hold meetings of its: Law Enforcement Advisory Panel; Ad Hoc Data Collection Committee; Law Enforcement Committee; Spiny Lobster Committee; Ecosystem-Based Management Committee; King and Spanish Mackerel Committee; Shrimp Committee; Information and Education Committee; Executive Finance Committee; Southeast Data, Assessment and Review (SEDAR) Committee; Golden Crab Committee; Catch Shares Committee; Snapper Grouper Committee; and a meeting of the Full Council. The Council will take action as necessary.
The Council will hold an informal public question and answer session regarding agenda items and a public comment session. See
The Council meeting will be held March 5-9, 2012. See
The meeting will be held at the Savannah Hilton DeSoto, 15 East Liberty Street, Savannah, GA 31401; telephone: (1-877) 280-0751 or (912) 232-9000; fax: (912) 232-6018. Copies of documents are available from Kim Iverson, Public Information Officer, South Atlantic Fishery Management Council, 4055 Faber Place Drive, Suite 201, North Charleston, SC 29405.
Kim Iverson, Public Information Officer; telephone: (843) 571-4366 or toll free at (866) SAFMC-10; fax: (843) 769-4520; email:
The Law Enforcement Advisory Panel (AP) will receive an update on recent amendments and review and develop comments on the following amendments: Snapper Grouper Amendment 18B (golden tilefish); Snapper Grouper Regulatory Amendment 12 (framework action to adjust the golden tilefish Annual Catch Limit (ACL), Optimum Yield (OY) and Annual Catch Target (ACT) in the fishery); Comprehensive Ecosystem-Based Amendment 3; Snapper Grouper Amendment 20B (wreckfish Individual Transferable Quota (ITQ) program modifications); Spiny Lobster Amendment 11 (weather-related fishery closures and a revised Minimum Stock Size Threshold (MSST) for pink shrimp); and Golden Crab Amendment 6 (catch share program for the commercial fishery). The AP will also begin the process for the 2011 Law Enforcement Officer of the Year award.
Concurrent Session.
The Ad Hoc Data Collection Committee will discuss the joint South Atlantic/Gulf Council dealer permits and review commercial and for-hire vessel reporting requirements in the South Atlantic.
The Law Enforcement Committee will receive a report from the Law Enforcement AP and discuss other issues as appropriate.
The Spiny Lobster Committee will receive an overview of Spiny Lobster Amendment 11, which includes measures to help protect threatened/endangered species. These measures include area closures for the commercial trap fishery to protect corals and gear marking requirements for trap lines. The Committee will also review public hearing comments and Supplemental Draft Environmental Impact Statement (SDEIS) comments and modify Amendment 11 as appropriate. The Committee will provide recommendations to Council.
The Ecosystem-Based Management Committee will receive updates on: The status of catches versus quota for octocorals; the status of Comprehensive Ecosystem-Based Amendment 2; the Florida Keys National Marine Sanctuary Strategic Plan; and public scoping comments for Comprehensive Ecosystem-Based Amendment 3 (CE-BA3). The Committee will develop recommendations for CE-BA3, give an update on ecosystem activities, and provide direction to staff.
The King and Spanish Mackerel Committee will receive updates on the status of catches versus quotas for species under quota management and the status of Mackerel Amendment 18, which establishes ACLs and Accountability Measures (AMs) for mackerel and cobia. The Committee will also receive a presentation on king mackerel tournament sales of fish and will select items to include in the joint South Atlantic and Gulf Mackerel Amendments 20 and 21. The Committee will provide guidance to staff and recommendations to Council.
The Shrimp Committee will review scoping comments for Shrimp Amendment 9, which would expedite the closure process during severe cold events in order to protect overwintering shrimp populations and would revise the MSST proxy for pink shrimp. The Committee will take action as appropriate and provide guidance to staff.
The Information and Education Committee will review the recommendations from the Snapper Grouper AP relating to outreach and will receive presentations on the use of social media tools. Additionally, the Committee will receive a review of the recent public hearing and scoping meetings and discuss options for future meetings. The Committee will provide recommendations as appropriate.
The Executive Finance Committee will: Receive a report on the Council Year (CY) 2012 Council expenditures; review and approve the draft CY2012 Council activities schedule and budget; and review the President's 2013 budget proposal.
The SEDAR Committee will receive an overview of SEDAR activities and review SEDAR assessment priorities. The Committee will also receive a presentation on the Marine Recreational Information Program (MRIP) Electronic Logbook Pilot Study, a report on recent MRIP workshops and a report on revised MRIP catch estimates. The Committee will discuss and develop recommendations for the next SEDAR Steering Committee meeting.
The Golden Crab Committee will review: The status of commercial catches versus quotas (amount landed to date); public hearing comments on Golden Crab Amendment 6; Golden Crab AP recommendations; and staff modifications to the amendment. The Committee will provide direction to staff and recommendations to the Council for approving the amendment for Secretarial review and approval.
There will be an informal public question and answer session with the NMFS Regional Administrator and the Council Chairman on March 7, 2012, beginning at 5:30 p.m.
The Catch Shares Committee will receive a presentation on a voluntary catch share program and take action as appropriate.
The Snapper Grouper Committee will receive updates on the status of catches versus quotas for species under quota management and address any necessary actions as the result of these reports. The Committee will receive a report on Oculina research activities and updates on the status of amendments under review, including: Regulatory Amendment 11, which proposes elimination of the current 240′ restriction on the harvest of some deepwater species within the snapper grouper management unit; the Comprehensive Annual Catch Limit (ACL) Amendment, which establishes ACL and AM for species that are not currently undergoing overfishing; Amendment 24 establishing a rebuilding plan for red grouper; Amendment 18A addressing black sea bass management and data collection; and Amendment 20A pertaining to the wreckfish ITQ program.
The Committee will also review Amendment 18B that includes measures to limit participation in the commercial golden tilefish fishery. The Committee will receive a summary of comments from recent public hearings, choose preferred alternatives for actions, modify the amendment as appropriate and provide recommendations to the Council. Additionally, the Committee will receive an overview of Regulatory Amendment 12 regarding a framework action to adjust the golden tilefish ACL, OY and ACT based on the most recent stock assessment. The Committee will choose preferred alternatives and modify the amendment as appropriate. The Committee will discuss limiting the number of black sea bass commercial trips, receive an overview of Amendment 20B addressing modifications to the wreckfish ITQ program, discuss relevant actions in CE-BA3, receive a presentation on National Marine Protected Areas (MPA), and provide recommendations as appropriate.
A public comment session will be held on March 8, 2012, beginning at 5:30 p.m., on Snapper Grouper Amendment 18B, Snapper Grouper Regulatory Amendment 11, Snapper Grouper Regulatory Amendment 12 (framework action adjusting the golden tilefish ACL), Golden Crab Amendment 6, and Spiny Lobster Amendment 11, followed by comment on any other item on the agenda.
From 8:30 a.m. until 8:45 a.m., the Council will call the meeting to order, adopt the agenda, and approve the December 2011 meeting minutes.
From 8:45 a.m. until 9 a.m., the Council will receive a report from the Ad Hoc Data Collection Committee, consider recommendations and take action as appropriate.
From 9 a.m. until 9:15 a.m., the Council will receive a report from the Law Enforcement Committee, consider recommendations and take action as appropriate.
From 9:15 a.m. until 9:30 a.m., the Council will receive a report from the Spiny Lobster Committee, approve Spiny Lobster Amendment 11 for formal Secretarial review and approval, consider recommendations and take action as appropriate.
From 9:30 a.m. until 9:45 a.m., the Council will receive a report from the Ecosystem-Based Management Committee, consider recommendations and take action as appropriate.
From 9:45 a.m. until 10 a.m., the Council will receive a report from the King and Spanish Mackerel Committee, approve Mackerel Amendments 20 and 21 for public scoping, consider other recommendations and take action as appropriate.
From 10 a.m. until 10:15 a.m., the Council will receive a report from the Shrimp Committee, consider recommendations and take action as appropriate.
From 10:15 a.m. until 10:30 a.m., the Council will receive a report from the Information and Education Committee, consider recommendations and take action as appropriate.
From 10:30 a.m. until 10:45 a.m., the Council will receive a report from the Executive Finance Committee, approve the CY2012 activities schedule and budget, consider recommendations and take action as appropriate.
From 10:45 a.m. until 11 a.m., the Council will receive a report from the SEDAR Committee, consider recommendations and take action as appropriate.
From 11 a.m. until 11:15 a.m., the Council will receive a report from the Golden Crab Committee, approve Golden Crab Amendment 6 for formal Secretarial review and approval, consider other recommendations and take action as appropriate.
From 11:15 a.m. until 11:30 a.m., the Council will receive a report from the Catch Shares Committee, consider recommendations and take action as appropriate.
From 11:30 a.m. until 12 noon, the Council will receive a report from the Snapper Grouper Committee, approve Snapper Grouper Amendment 18B and Regulatory Amendment 12 for formal Secretarial review and approval, consider other recommendations and take action as appropriate.
From 12 noon until 1:30 p.m., the Council will receive status reports from the NOAA Fisheries Southeast Regional Office, NOAA Fisheries Southeast Science Center, review and develop recommendations on Experimental Fishing Permits as necessary, review agency and liaison reports, and discuss other business, including upcoming meetings.
Documents regarding these issues are available from the Council office (see
Although non-emergency issues not contained in this agenda may come before this Council for discussion, those issues may not be the subjects of formal final Council action during these meetings. Council action will be restricted to those issues specifically listed in this notice and any issues arising after publication of this notice that require emergency action under section 305(c) of the Magnuson-Stevens Act, provided the public has been notified of the Council's intent to take final action to address the emergency.
Except for advertised (scheduled) public hearings and public comment, the times and sequence specified on this agenda is subject to change.
These meetings are physically accessible to people with disabilities. Requests for sign language interpretation or other auxiliary aids should be directed to the Council office (see
The United States Patent and Trademark Office (USPTO) 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. 35).
Once submitted, the request will be publicly available in electronic format through the Information Collection Review page at
Paper copies can be obtained by:
•
•
Written comments and recommendations for the proposed information collection should be sent on or before March 19, 2012 to Nicholas A. Fraser, OMB Desk Officer, via email to
Under Secretary of Defense for Personnel and Readiness, Department of Defense (DoD).
Notice of meeting.
Pursuant to Public Law 92-463, notice is hereby given of a forthcoming meeting of the National Security Education Board. The purpose of the meeting is to review and make recommendations to the Secretary of Defense concerning requirements established by the David L. Boren National Security Education Act, Title VII of Public Law 102-183, as amended.
March 15, 2012, from 9 a.m.-2 p.m.
Defense Language and National Security Education Office, 1101 Wilson Boulevard, Suite 1210, Arlington, VA 22209.
Ms. Alison Patz, Program Analyst, Defense Language and National Security Education Office (DLNSEO), 1101 Wilson Boulevard, Suite 1210, Rosslyn, Virginia 22209-2248; (703) 696-1991. Electronic mail address:
The National Security Education Board Members meeting is open to the public. The public is afforded the opportunity to submit written statements associated with DLNSEO.
Notice.
The Defense Acquisition Regulations System has submitted to OMB for clearance, the following proposal for collection of information under the provisions of the Paperwork Reduction Act (44 U.S.C. chapter 35).
• Determine whether to provide precious metals as Government-furnished material;
• Determine an entity's eligibility for award of a contract due to ownership or control by the government of a terrorist country;
• Determine an entity's eligibility for award of a contract under a national security program due to ownership or control by a foreign government;
• Determine whether there is a compelling reason for a contractor to enter into a subcontract in excess of $30,000 with a firm, or subsidiary of a firm, that is identified in the List of Parties Excluded from Federal Procurement and Nonprocurement as being ineligible for award of Defense subcontracts because it is owned or controlled by the government of a terrorist country;
• Evaluate claims of indemnification for losses or damages occurring under a research and development contract; and
• Keep track of radio frequencies on electronic equipment under research and development contracts so that the user does not override or interfere with the use of that frequency by another user.
Written comments and recommendations on the proposed information collection should be sent to Ms. Seehra at the Office of Management and Budget, Desk Officer for DoD, Room 10236, New Executive Office Building, Washington, DC 20503.
You may also submit comments, identified by docket number and title, by the following method:
•
Written requests for copies of the information collection proposal should be sent to Ms. Toppings at WHS/ESD/Information Management Division, 4800 Mark Center Drive, 2nd Floor, East Tower, Suite 02G09, Alexandria, VA 22350-3100.
Office of Vocational and Adult Education, Department of Education.
Notice.
For 36-month projects funded in fiscal year (FY) 2009 under the Native Hawaiian Career and Technical Education Program (NHCTEP), CFDA Number: 84.259A, the Secretary proposes to waive the regulation that restricts project period extensions involving the obligation of additional Federal funds. The Secretary also proposes to extend the project period of these grants for an additional 12 months. This would enable the eight current NHCTEP grantees to seek FY 2012 continuation awards for project periods through FY 2013. Further, the waiver and extension, as proposed, would mean that we would not announce new awards in FY 2012.
We must receive your comments on or before March 19, 2012.
Submit all comments on this notice to Linda Mayo, U.S. Department of Education, 400 Maryland Avenue SW., Room 11075, Potomac Center Plaza, Washington, DC 20202-7241.
If you prefer to send your comments by email, use the following address:
Linda Mayo by telephone at (202) 245-7792 or by email at:
If you use a telecommunications device for the deaf (TDD), call the Federal Relay Service (FRS), toll free, at 1-800-877-8339.
We invite you to submit comments regarding this notice. We are particularly interested in receiving comments on the potential impact that this proposed project period waiver and extension might have on NHCTEP and on potential applicants that would be eligible to apply for grant awards under any new NHCTEP notice inviting applications, should there be one.
Eligible applicants are:
(1) Community-based organizations primarily serving and representing Native Hawaiians. For purposes of NHCTEP, a community-based organization means a public or private organization that provides career and technical education, or related services, to individuals in the Native Hawaiian community.
(2) Consortia of community-based organizations primarily serving and representing Native Hawaiians (34 CFR 75.127).
During and after the comment period, you may inspect all public comments about this proposed waiver and extension in room 11075, Potomac Center Plaza, 550 12th Street SW., Washington, DC, between the hours of 8:30 a.m. and 4 p.m., Washington, DC time, Monday through Friday of each week, except Federal holidays.
NHCTEP supports grants to community-based organizations primarily serving and representing Native Hawaiians to plan, conduct, and administer career and technical education programs, as authorized by section 116(h) of the Carl D. Perkins Career and Technical Education Act of 2006 (Perkins Act or Act) (20 U.S.C. 2326(h)). The eight current NHCTEP grantees were selected based on the March 24, 2009, notice inviting applications published in the
In FY 2009, the Department funded NHCTEP projects that are scheduled to end in FY 2012. For those projects, the Secretary proposes to waive the requirement of 34 CFR 75.261(c)(2) of the Education Department General Administrative Regulations (EDGAR), which generally prohibits project period extensions involving the obligation of additional Federal funds. The Secretary also proposes to extend the current NHCTEP project period for 12 months. This would allow the eight current NHCTEP grantees to seek continuation awards in FY 2012 for project periods through FY 2013.
The Secretary makes these proposals because section 9 of the Perkins Act, which includes authorization for NHCTEP at section 116(h), authorizes appropriations for NHCTEP through FY 2012 (20 U.S.C. 2307). With the potential for changes in the authorizing legislation for NHCTEP beyond 2012, we do not believe it would be advisable to hold a new NHCTEP competition in FY 2012 for projects that may then operate for just one year. We are generally reluctant to announce a competition under which eligible entities would be expected to proceed through the application preparation and submission process while lacking critical information about the future of the program, and we do not think that it would be in the public interest to do so in this case.
Rather than holding a new competition in FY 2012, we believe that it would be in the public interest and preferable for NHCTEP for us to review requests for FY 2012 continuation awards from the eight current grantees selected based on the March 24, 2009, notice and to extend currently funded projects, for one more year, through FY 2013.
The extension of the project period and waiver of 34 CFR 75.261(c)(2) we are proposing would mean that: (1) Current grantees would be authorized to request and receive NHCTEP continuation awards in FY 2012 for project periods through FY 2013, (2) we would not announce a new competition or make new awards in FY 2012, (3) the March 24, 2009, notice would continue to govern current projects during the extension year, and (4) the eight currently-approved applications selected based on the March 24, 2009, notice would govern continuation activities.
The March 24, 2009, notice: (1) Established a project period of up to 36 months and reiterated that funding for multi-year awards would be dependent on a grantee meeting the requirements of 34 CFR 75.253 (continuation of a multi-year project after the first budget period); (2) explained the requirements of the program; (3) described the evaluation and reporting requirements; and (4) established the Government Performance and Results Act (GPRA) indicators for NHCTEP.
With this proposed extension of the project period and waiver of 34 CFR 75.261(c)(2), we propose to extend the project period of the eight current NHCTEP grantees that received grants under the FY 2009 competition for one additional year through FY 2013 with FY 2012 funds Congress has appropriated under the current statutory authority. If the waiver of 34 CFR 75.261(c)(2) that we propose in this notice is announced by us in a final notice, the requirements applicable to continuation awards for current NHCTEP grantees and the requirements in section 75.253 of EDGAR would apply to any continuation awards sought by current NHCTEP grantees.
If we announce this proposed waiver and extension as final, we will make decisions regarding annual continuation awards based on grantee program narratives, budgets and budget
The Secretary certifies that the proposed waiver and extension and the activities required to support additional year of funding would not have a significant economic impact on a substantial number of small entities. The small entities that would be affected by this proposed waiver and extension are the eight currently-funded NHCTEP grantees.
The Secretary certifies that the proposed waiver and extension would not have a significant economic impact on these NHCTEP entities because the proposed waiver and extension impose minimal compliance costs to extend projects already in existence, and the activities required to support the additional year of funding would not impose additional regulatory burdens or require unnecessary Federal supervision.
This notice of proposed waiver and extension does not contain any information collection requirements.
The NHCTEP is not subject to Executive Order 12372 and the regulations in 34 CFR part 79.
You may also access documents of the Department published in the
20 U.S.C. 2326(h).
Office of Vocational and Adult Education, Department of Education.
Notice.
For 60-month projects funded in fiscal year (FY) 2007 under the Native American Career and Technical Education Program (NACTEP), the Secretary proposes to waive the regulations that generally restrict project periods to 60 months and that restrict project period extensions involving the obligation of additional Federal funds. The Secretary also proposes to extend the current NACTEP project periods through FY 2013. These proposed waivers and extension of the project period would enable the 30 current NACTEP grantees to request and continue to receive Federal funding beyond the 60-month limitation contained in the Department's regulations. Further, the waivers and extension, as proposed, would mean that we would not announce new awards in FY 2012.
We must receive your comments on or before March 19, 2012.
Submit all comments on this notice to Gwen Washington, U.S. Department of Education, 400 Maryland Avenue SW., room 11076, Potomac Center Plaza, Washington, DC 20202-7241; or Linda Mayo, U.S. Department of Education, 400 Maryland Avenue SW., Room 11075, Potomac Center Plaza, Washington, DC 20202-7241.
If you prefer to send your comments by email, use one of the following addresses:
Gwen Washington, by telephone: (202) 245-7790, or by email:
If you use a telecommunications device for the deaf (TDD), call the Federal Relay Service (FRS), toll free, at 1-800-877-8339.
Eligible applicants for NACTEP are:
(a) Federally-recognized Indian tribes.
(b) Tribal organizations.
(c) Alaska Native entities.
(d) Bureau-funded schools,
(e) Consortia of one or more eligible tribes, tribal organizations, Alaska Native entities, or eligible Bureau-funded schools.
During and after the comment period, you may inspect all public comments about these proposed waivers and extension in room 11076 or room 11075, Potomac Center Plaza, 550 12th Street SW., Washington, DC, between the hours of 8:30 a.m. and 4 p.m., Washington, DC time, Monday through Friday of each week, except Federal holidays.
Current NACTEP grantees, selected based on the March 23, 2007, NACTEP notice inviting applications published in the
The Secretary makes these proposals because section 9 of the Perkins Act authorizes appropriations for activities under section 116 of the Act through FY 2012 (20 U.S.C. 2307). With the potential for changes in the authorizing legislation for NACTEP beyond 2012, we do not believe it would be advisable to hold a new competition for multi-year awards under NACTEP in FY 2012 for projects that may then operate for just one year. We are generally reluctant to announce a competition under which eligible entities would be expected to proceed through the application process while lacking critical information about the future of the program, and we do not think that it would be in the public interest to do so in this case.
Rather than holding a new competition in FY 2012, we believe that it would be in the public interest and preferable for NACTEP for us to review requests for FY 2012 continuation awards from the 30 current grantees selected based on the March 23, 2007, notice and to extend currently funded projects, for one more year, through FY 2013. In lieu of announcing a new competition for this program in 2012, the Secretary proposes to waive the requirement in 34 CFR 75.250, which limits project periods to 60 months, and in 34 CFR 75.261(c)(2), which restricts project period extensions involving the obligation of additional Federal funds.
With these proposed waivers and extension of the project period, currently-funded NACTEP grantees selected based on the March 23, 2007, notice inviting applications could be continued through the FY 2013 budget and project period and we would not announce a new NACTEP competition in 2012.
If these proposed waivers and extension of the project period are announced by us in a final notice, the requirements applicable to continuation awards for current NACTEP grantees selected based on the March 23, 2007, notice inviting applications and the requirements in 34 CFR 75.253 would apply to any continuation awards sought by current NACTEP grantees. If we announce these waivers and extension as final, we will base our decisions regarding continuation awards on the program narratives, budgets, budget narratives, and program performance reports submitted by current grantees, and the requirements in 34 CFR 75.253. Any activities to be carried out during the year of the continuation award would have to be consistent with, or be a logical extension of, the scope, goals, and objectives of each grantee's application as approved in the 2007 NACTEP competition. If we publish these proposed waivers and extension as final, we would award continuation grants based on information provided to us by each grantee, indicating that it is making substantial progress performing its NACTEP grant activities.
The proposed extension of the project period and waivers of 34 CFR 75.250 and 75.261(c)(2) would not exempt the current NACTEP grantees from the appropriation account-closing provisions of 31 U.S.C. 1552(a), nor would they extend the availability of funds previously awarded to current NACTEP grantees. As a result of 31 U.S.C. 1552(a), appropriations available for a limited period may be used for payment of valid obligations for only five years after the expiration of their period of availability for Federal obligation. After that time, the unexpended balance of those funds is canceled and returned to the U.S. Treasury Department and is unavailable for restoration for any purpose (31 U.S.C. 1552(b)).
The Secretary certifies that the proposed waivers and extension would not have a significant economic impact on a substantial number of small entities.
The small entities that would be affected by these proposed waivers and extension are the 30 grantees selected based on the March 23, 2007, notice currently receiving Federal funds.
The Secretary certifies that the proposed waivers and extension would not have a significant economic impact on these entities because the proposed waivers and extension impose minimal compliance costs to extend projects already in existence, and the activities required to support the additional year of funding would not impose additional regulatory burdens or require unnecessary Federal supervision.
This notice of proposed waivers and extension does not contain any information collection requirements.
The NACTEP is not subject to Executive Order 12372 and the regulations in 34 CFR part 79.
You may also access documents of the Department published in the
20 U.S.C. 2326(a) through (g).
Office of Vocational and Adult Education, Department of Education.
Notice.
For 60-month projects funded in fiscal year (FY) 2007 under the Tribally Controlled Postsecondary Career and Technical Institutions Program (TCPCTIP), the Secretary proposes to waive the regulations that generally limit project periods to 60 months and that restrict project period extensions involving the obligation of additional Federal funds. The Secretary also proposes to extend the project period for current TCPCTIP grantees through FY 2013, or longer, if Congress continues to appropriate funds under the existing program authority. The proposed waivers and extension would enable the two current TCPCTIP grantees to request and continue to receive Federal funding beyond the 60-month limitation contained in the Department's regulations, so long as the grantees are meeting the TCPCTIP requirements. Further, the waivers and extension, as proposed, would mean that we would not announce a new competition in FY 2012 or make new awards in that year, or in future years, if Congress continues to appropriate funds under the existing program authority.
We must receive your comments on or before March 19, 2012.
Submit all comments on this notice to Gwen Washington, U.S. Department of Education, 400 Maryland Avenue SW., room 11076, Potomac Center Plaza, Washington, DC 20202-7241.
If you prefer to send your comments by email, use the following address:
Gwen Washington. Telephone: (202) 245-7792, or by email:
If you use a telecommunications device for the deaf (TDD), call the Federal Relay Service (FRS), toll free, at 1-800-877-8339.
Eligible applicants for TCPCTIP are tribally controlled postsecondary career and technical institutions that do not receive Federal support under the Tribally Controlled College or University Assistance Act of 1978 (25 U.S.C. 1801
During and after the comment period, you may inspect all public comments about these proposed waivers and extension for TCPCTIP in room 11076, Potomac Center Plaza, 550 12th Street, SW., Washington, DC, between the hours of 8:30 a.m. and 4 p.m., Washington, DC time, Monday through Friday of each week, except Federal holidays.
Current TCPCTIP grantees, selected based on the May 15, 2007, TCPCTIP notice inviting applications published in the
The project period for the two TCPCTIP grantees is scheduled to end in FY 2012. For these projects, the Secretary proposes to waive the requirements of 34 CFR 75.250 and 34 CFR 75.261(c)(2), which limit project periods to 60 months and restrict project period extensions that involve the obligation of additional Federal funds. The Secretary also proposes to extend the project period for the two current TCPCTIP grantees through FY 2013, or longer, if Congress continues to appropriate funds under the existing program authority. The proposed waivers and extension would enable the two current TCPCTIP grantees to request and continue to receive Federal funds beyond the 60-month limitation set by 34 CFR 75.250.
The Secretary makes these proposals because section 117(i) of the Perkins Act authorizes appropriations for activities under section 117 of the Act, through FY 2012 (20 U.S.C. 2327(i)). With the potential for changes in the authorizing legislation for the TCPCTIP beyond 2012, we do not believe it would be advisable to hold a new TCPCTIP competition in FY 2012 for projects that may then operate for just one year. We are generally reluctant to announce a competition under which eligible entities would be expected to proceed through the application process while lacking critical information about the future of the program, and we do not think that it would be in the public interest to do so in this case.
Rather than holding a new competition in FY 2012, we believe that it is in the public interest and preferable for TCPCTIP for us to review requests for continuation awards from the two grantees based on the May 15, 2007, notice and extend the currently funded projects through FY 2013, or longer, if Congress continues to appropriate funds for TCPCTIP under the existing program authority. In lieu of announcing new competitions for TCPCTIP in FY 2012, the Secretary proposes to waive the requirement in 34 CFR 75.250, which limits project periods to 60 months, and in 34 CFR 75.261(c)(2), which restricts project period extensions involving the obligation of additional Federal funds.
With these proposed waivers and extension, current TCPCTIP grantees selected based on the May 15, 2007, notice inviting applications could be continued at least through the FY 2013 budget and project periods, or longer, if Congress continues to appropriate funds for TCPCTIP under the existing program authority.
If these proposed waivers and extension are announced by us in a final notice, the requirements applicable to continuation awards for current TCPCTIP grantees selected based on the May 15, 2007, notice inviting applications and the requirements in 34 CFR 75.253 would apply to any continuation awards sought by current TCPCTIP grantees. If we announce these proposed waivers and extension as final, we will base our decisions regarding annual continuation awards on the program narratives, budgets, budget narratives, and program performance reports, submitted by current grantees, and the requirements in 34 CFR 75.253. Any activities to be carried out during the year or years of continuation awards would have to be
The proposed extension of the project period and waivers of 34 CFR 75.250 and 75.261(c)(2) would not exempt the current TCPCTIP grantees from the appropriation account-closing provisions of 31 U.S.C. 1552(a), nor would they extend the availability of funds previously awarded to current TCPCTIP grantees. As a result of 31 U.S.C. 1552(a), appropriations available for a limited period may be used for payment of valid obligations for only five years after the expiration of their period of availability for Federal obligation. After that time, the unexpended balance of those funds is canceled and returned to the U.S. Treasury Department and is unavailable for restoration for any purpose (31 U.S.C. 1552(b)).
The Secretary certifies that the proposed waivers and extension would not have a significant economic impact on a substantial number of small entities.
The small entities that would be affected by these proposed waivers and extension are the two grantees selected based on the May 15, 2007, notice currently receiving Federal funds.
The Secretary certifies that the proposed waivers and extension would not have a significant economic impact on these entities because the proposed waivers and extension impose minimal compliance costs to extend projects already in existence, and the activities required to support the additional year or years of funding would not impose additional regulatory burdens or require unnecessary Federal supervision.
This notice of proposed waivers and extension does not contain any information collection requirements.
The TCPCTIP is not subject to Executive Order 12372 and the regulations in 34 CFR part 79.
You may also access documents of the Department published in the
20 U.S.C. 2327.
Department of Energy, Office of Science.
Notice of open meeting.
This notice announces a meeting of the DOE/NSF Nuclear Science Advisory Committee (NSAC). The Federal Advisory Committee Act (Pub. L. 92-463, 86 Stat. 770) requires that public notice of these meetings be announced in the
Friday, March 9, 2012, 9 a.m.-5 p.m.
Marriott Bethesda North Hotel & Conference Center, 5701 Marinelli Road, North Bethesda, Maryland 20852, (301) 822-9200.
Brenda L. May, U.S. Department of Energy; SC-26/Germantown Building, 1000 Independence Avenue SW., Washington, DC 20585-1290; Telephone: (301) 903-0536
Department of Energy, DoE.
Notice of open meeting.
This notice announces a meeting of the Environmental Management Site-Specific Advisory Board (EM SSAB), Oak Ridge Reservation. The Federal Advisory Committee Act (Pub. L. 92-463, 86 Stat.
Wednesday, March 14, 2012, 6 p.m.
Office of Scientific and Technical Information, 1 Science.gov Way, Oak Ridge, Tennessee 37830.
Melyssa P. Noe, Federal Coordinator, Department of Energy Oak Ridge Operations Office, P.O. Box 2001, EM-90, Oak Ridge, TN 37831. Phone (865) 241-3315; Fax (865) 576-0956 or email:
Federal Energy Regulatory Commission.
Comment request.
In compliance with the requirements of the Paperwork Reduction Act of 1995, 44 U.S.C. 3507(a)(1)(D), the Federal Energy Regulatory Commission (Commission or FERC) is submitting the information collection FERC-550, Oil Pipeline Rates: Tariff Filings, to the Office of Management and Budget (OMB) for review of the information collection requirements. Any interested person may file comments directly with OMB and should address a copy of those comments to the Commission as explained below. The Commission issued a Notice in the
Comments on the collection of information are due by March 19, 2012.
Comments filed with OMB, identified by the OMB Control No. 1902-0089, should be sent via email to the Office of Information and Regulatory Affairs:
A copy of the comments should also be sent to the Federal Energy Regulatory Commission, identified by the Docket No. IC12-2-000, by either of the following methods:
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Ellen Brown may be reached by email at
18 CFR Parts 341-348 specifies the filing requirements for proposed oil pipeline rates. The data that oil pipelines file is the basis for Commission analyses of the rates they plan to charge to transport crude oil and petroleum products. The Commission uses its analyses: (1) To determine if the proposed charges result in just and reasonable rates for the oil pipeline's transportation services and (2) to help the Commission decide whether it should suspend, accept or reject the proposed rates.
The total estimated annual cost burden to respondents is $385,499.24 [5,632 hours ÷ 2,080
Take notice that the following hydroelectric application has been filed with the Commission and is available for public inspection.
This application is not ready for environmental analysis at this time.
The existing project works consists of the following:
The London/Marmet Project consists of two developments. The existing London Development utilizes the head created by the Army Corps of Engineers' (Corps) 26-foot-high London Dam located at river mile (RM) 82.8 on the Kanawha River and consists of: (1) A forebay area protected by a log boom; (2) screened intake structures; (3) a concrete powerhouse containing three turbine-generator units with a total installed capacity of 14.4 megawatts (MW); (4) a tailrace 420 feet long; (5) a substation containing two, three-phase transformers and two auxiliary transformers; (6) two, 0.38-mile-long, 46-kilovolt (kV) transmission lines; and (7) other appurtenances. The development generates about 84,048 megawatt-hours (MWh) annually.
The existing Marmet Development utilizes the head created by the Corps' 34-foot-high Marmet Dam located at RM 67.7 on the Kanawha River and consists of: (1) A forebay area protected by a log boom; (2) screened intake structures; (3) a concrete powerhouse containing three turbine-generator units with a total installed capacity of 14.4 MW; (4) a tailrace 450 feet long; (5) a substation containing two, three-phase transformers and two auxiliary transformers; (6) two, 0.78-mile-long, 46-kV transmission lines; and (7) other appurtenances. The development generates about 82,302 MWh annually.
The London/Marmet Project has a total installed capacity of 28.8 MW and generates about 166,350 MWh annually.
The existing Winfield Project utilizes the head created by the Corps' 38-foot-high Winfield Dam located at RM 31.1 on the Kanawha River and consists of: (1) A forebay area protected by a 410-foot-long log boom; (2) screened intake structures; (3) a concrete powerhouse containing three turbine-generator units with a total installed capacity of 14.76 MW; (4) a tailrace 410 feet long; (5) a substation containing a generator step-up bank of three transformers and three auxiliary transformers; (6) a 3.7-mile-long, 69-kV transmission line; and (7) other appurtenances. The project generates about 114,090 MWh annually.
The above hydroelectric facilities' operation is synchronized with the operation of the Corps' locks at each dam. The developments at each of the two projects operate within allowable pool elevation limits as established by the Corps. The London pool elevation is allowed to fluctuate between 611.0 feet and 614.0 feet National Geodetic Vertical Datum 1929 (NGVD). The Marmet pool elevation is allowed to fluctuate between 589.7 feet and 590.0 feet NGVD. The Winfield pool elevation is allowed to fluctuate between 565.8 feet and 566.0 feet NGVD. All three pools can be drawn down at a maximum rate of 0.5 feet per hour. When stream flow exceeds the maximum turbine discharge, the responsibility for control of the pool elevations passes to the Corps' personnel and the projects operate in run-of-release mode.
Appalachian is proposing to modify the maximum pool elevation limit at the London Development from 614.0 feet to 613.7 feet NGVD.
You may also register online at
The application will be processed according to the following preliminary Hydro Licensing Schedule. Revisions to the schedule may be made as appropriate.
Final amendments to the application must be filed with the Commission no later than 30 days from the issuance date of the Notice of Ready for Environmental Analysis.
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j. Lock+ Hydro Friends Fund XLII, LLC filed its request to use the Traditional Licensing Process on December 23, 2011. Lock+ Hydro Friends Fund XLII, LLC provided public notice of its request on December 22, 2011. In a letter dated January 30, 2012, the Director of the Division of Hydropower Licensing approved Lock+ Hydro Friends Fund XLII, LLC's request to use the Traditional Licensing Process.
k. With this notice, we are initiating informal consultation with: (a) The U.S. Fish and Wildlife Service under section 7 of the Endangered Species Act and the joint agency regulations thereunder at 50 CFR, Part 402; and (b) the Pennsylvania State Historic Preservation Officer, as required by section 106, National Historic Preservation Act, and the implementing regulations of the Advisory Council on Historic Preservation at 36 CFR 800.2.
l. With this notice, we are designating Lock+ Hydro Friends Fund XLII, LLC as the Commission's non-federal representative for carrying out informal consultation, pursuant to section 7 of the Endangered Species Act, and section 106 of the National Historic Preservation Act.
m. Lock+ Hydro Friends Fund XLII, LLC filed a Pre-Application Document (PAD; including a proposed process plan and schedule) with the Commission, pursuant to 18 CFR 5.6 of the Commission's regulations.
n. A copy of the PAD is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's Web site (
o. Register online at
Take notice that the Commission received the following electric rate filings:
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00 pm Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
Take notice that the Commission has received the following Natural Gas Pipeline Rate and Refund Report filings:
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and § 385.214) on or before 5 pm Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, and service can be found at:
Take notice that the Commission received the following electric corporate filings:
Take notice that the Commission received the following exempt wholesale generator filings:
Take notice that the Commission received the following electric rate filings:
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5 pm Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
Take notice that the Commission has received the following Natural Gas Pipeline Rate and Refund Report filings:
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5 pm Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
Any person desiring to protest in any of the above proceedings must file in accordance with Rule 211 of the Commission's Regulations (18 CFR 385.211) on or before 5 pm Eastern time on the specified comment date.
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, and service can be found at:
Take notice that on February 8, 2012, pursuant to sections 206 and 306 of the Federal Power Act, 16 U.S.C. 824e and 825e (2006), and Rule 206 of the Commission's Rules of Practice and Procedure, 18 CFR 385.206 (2011), Pioneer Transmission, LLC (Pioneer) filed a formal complaint against Northern Indiana Public Service Company (NIPSCO) and Midwest Independent Transmission System Operator, Inc. (MISO) alleging that (1) NIPSCO does not have ownership and investment rights to any of the 765kV investment associated with the segment of the Pioneer project that MISO recently included in its 2011 regional transmission expansion plan, and (2) Pioneer should be allowed to become a party to the MISO Transmission Owners Agreement immediately and begin recovering costs (CWIP) in accordance with FERC's order approving transmission rate incentives for Pioneer.
Pioneer certifies that copies of the complaint were served on the contacts for NIPSCO and MISO as listed on the Commission's list of Corporate Officials.
Any person desiring to intervene or to protest this filing must file in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 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. The Respondent's answer and all interventions, or protests must be filed on or before the comment date. The Respondent's answer, motions to intervene, and protests must be served on the Complainants.
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 during the month of January 2012, the status of the above-captioned entities as Exempt Wholesale Generators or Foreign Utility Companies became effective by operation of the Commission's regulations. 18 CFR 366.7(a).
Take notice that on February 8, 2012, the New Jersey Board of Public Utilities filed a Confidentiality Certification as required by section 18.17.4 of the Amended and Restated Operating Agreement of PJM Interconnection, L.L.C. and the Federal Energy Regulatory Commission's Order,
Any person desiring to intervene or to protest this filing must file in accordance with Rules 211 and 214 of
The Commission encourages electronic submission of protests and interventions in lieu of paper using the “eFiling” link at
This filing is accessible online at
This is a supplemental notice in the above-referenced proceeding of Physical Systems Integration, LLC's application for market-based rate authority, with an accompanying rate tariff, noting that such application includes a request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability.
Any person desiring to intervene or to protest should file with the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214). Anyone filing a motion to intervene or protest must serve a copy of that document on the Applicant.
Notice is hereby given that the deadline for filing protests with regard to the applicant's request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability, is February 29, 2012.
The Commission encourages electronic submission of protests and interventions in lieu of paper, using the FERC Online links at
Persons unable to file electronically should submit an original and 14 copies of the intervention or protest to the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426.
The filings in the above-referenced proceeding are accessible in the Commission's eLibrary system by clicking on the appropriate link in the above list. They are also available for review in the Commission's Public Reference Room in Washington, DC. There is an eSubscription link on the Web site that enables subscribers to receive email notification when a document is added to a subscribed docket(s). For assistance with any FERC Online service, please email
This is a supplemental notice in the above-referenced proceeding of Lilabell Energy LLC's application for market-based rate authority, with an accompanying rate tariff, noting that such application includes a request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability.
Any person desiring to intervene or to protest should file with the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214). Anyone filing a motion to intervene or protest must serve a copy of that document on the Applicant.
Notice is hereby given that the deadline for filing protests with regard to the applicant's request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability, is February 29, 2012.
The Commission encourages electronic submission of protests and interventions in lieu of paper, using the FERC Online links at
Persons unable to file electronically should submit an original and 14 copies of the intervention or protest to the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426.
The filings in the above-referenced proceeding are accessible in the Commission's eLibrary system by clicking on the appropriate link in the above list. They are also available for review in the Commission's Public Reference Room in Washington, DC. There is an eSubscription link on the web site that enables subscribers to receive email notification when a document is added to a subscribed docket(s). For assistance with any FERC Online service, please email
This is a supplemental notice in the above-referenced proceeding of AP Gas & Electric (NJ), LLC's application for market-based rate authority, with an accompanying rate tariff, noting that such application includes a request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability.
Any person desiring to intervene or to protest should file with the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214). Anyone filing a motion to intervene or protest must serve a copy of that document on the Applicant.
Notice is hereby given that the deadline for filing protests with regard to the applicant's request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability, is February 29, 2012.
The Commission encourages electronic submission of protests and interventions in lieu of paper, using the FERC Online links at
Persons unable to file electronically should submit an original and 14 copies of the intervention or protest to the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426.
The filings in the above-referenced proceeding are accessible in the Commission's eLibrary system by clicking on the appropriate link in the above list. They are also available for review in the Commission's Public Reference Room in Washington, DC. There is an eSubscription link on the Web site that enables subscribers to receive email notification when a document is added to a subscribed docket(s). For assistance with any FERC Online service, please email
This is a supplemental notice in the above-referenced proceeding of AP Gas & Electric (OH), LLC's application for market-based rate authority, with an accompanying rate tariff, noting that such application includes a request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability.
Any person desiring to intervene or to protest should file with the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214). Anyone filing a motion to intervene or protest must serve a copy of that document on the Applicant.
Notice is hereby given that the deadline for filing protests with regard to the applicant's request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability, is February 29, 2012.
The Commission encourages electronic submission of protests and interventions in lieu of paper, using the FERC Online links at http://www.ferc.gov. To facilitate electronic service, persons with Internet access who will eFile a document and/or be listed as a contact for an intervenor must create and validate an eRegistration account using the eRegistration link. Select the eFiling link to log on and submit the intervention or protests.
Persons unable to file electronically should submit an original and 14 copies of the intervention or protest to the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426.
The filings in the above-referenced proceeding are accessible in the Commission's eLibrary system by clicking on the appropriate link in the above list. They are also available for review in the Commission's Public Reference Room in Washington, DC. There is an eSubscription link on the web site that enables subscribers to receive email notification when a document is added to a subscribed docket(s). For assistance with any FERC Online service, please email
This is a supplemental notice in the above-referenced proceeding of AP Gas & Electric (NY), LLC's application for market-based rate authority, with an accompanying rate tariff, noting that such application includes a request for blanket authorization, under 18 CFR Part 34, of future issuances of securities and assumptions of liability.
Any person desiring to intervene or to protest should file with the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214). Anyone filing a motion to intervene or protest must serve a copy of that document on the Applicant.
Notice is hereby given that the deadline for filing protests with regard to the applicant's request for blanket authorization, under 18 CFR Part 34, of
The Commission encourages electronic submission of protests and interventions in lieu of paper, using the FERC Online links at
Persons unable to file electronically should submit an original and 14 copies of the intervention or protest to the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426.
The filings in the above-referenced proceeding are accessible in the Commission's eLibrary system by clicking on the appropriate link in the above list. They are also available for review in the Commission's Public Reference Room in Washington, DC. There is an eSubscription link on the web site that enables subscribers to receive email notification when a document is added to a subscribed docket(s). For assistance with any FERC Online service, please email
This is a supplemental notice in the above-referenced proceeding of AP Gas & Electric (IL), LLC's application for market-based rate authority, with an accompanying rate tariff, noting that such application includes a request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability.
Any person desiring to intervene or to protest should file with the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214). Anyone filing a motion to intervene or protest must serve a copy of that document on the Applicant.
Notice is hereby given that the deadline for filing protests with regard to the applicant's request for blanket authorization, under 18 CFR Part 34, of future issuances of securities and assumptions of liability, is February 29, 2012.
The Commission encourages electronic submission of protests and interventions in lieu of paper, using the FERC Online links at
Persons unable to file electronically should submit an original and 14 copies of the intervention or protest to the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426.
The filings in the above-referenced proceeding are accessible in the Commission's eLibrary system by clicking on the appropriate link in the above list. They are also available for review in the Commission's Public Reference Room in Washington, DC. There is an eSubscription link on the web site that enables subscribers to receive email notification when a document is added to a subscribed docket(s). For assistance with any FERC Online service, please email
This is a supplemental notice in the above-referenced proceeding of AP Gas & Electric (MD), LLC's application for market-based rate authority, with an accompanying rate tariff, noting that such application includes a request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability.
Any person desiring to intervene or to protest should file with the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214). Anyone filing a motion to intervene or protest must serve a copy of that document on the Applicant.
Notice is hereby given that the deadline for filing protests with regard to the applicant's request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability, is February 29, 2012.
The Commission encourages electronic submission of protests and interventions in lieu of paper, using the FERC Online links at
Persons unable to file electronically should submit an original and 14 copies of the intervention or protest to the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426.
The filings in the above-referenced proceeding are accessible in the Commission's eLibrary system by clicking on the appropriate link in the above list. They are also available for review in the Commission's Public Reference Room in Washington, DC. There is an eSubscription link on the Web site that enables subscribers to receive email notification when a document is added to a subscribed docket(s). For assistance with any FERC
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d. All local, state, and federal agencies, Indian tribes, and other interested parties are invited to participate by phone. Please call Dianne Rodman by February 16, 2012, to RSVP and to receive specific instructions on how to participate.
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e. All local, state, and federal agencies, Indian tribes, and other interested parties are invited to participate either in person or by phone. Please call Tom Dean at (202) 502-6041 by Wednesday, March 14, 2012, to receive specific instructions on how to participate.
f. FERC conferences are accessible under section 508 of the Rehabilitation Act of 1973. For accessibility accommodations please send an email to
g. A summary of the teleconference will be placed in the public record for the project.
On March 25, 2011, Reliable Storage 1 LLC filed an application, pursuant to section 4(f) of the Federal Power Act, proposing to study the feasibility of hydropower near the town of Monterey, in Putnam County, Tennessee. The sole purpose of a preliminary permit, if issued, is to grant the permit holder priority to file a license application during the permit term. A preliminary permit does not authorize the permit holder to perform any land-disturbing activities or otherwise enter upon lands or waters owned by others without the owners' express permission.
The proposed pumped storage project would consist of the following: (1) A 70-foot-high, 7,500-foot-long earth embankment dam; (2) an upper reservoir with a surface area of 100 acres and an 7,100 acre-foot storage capacity; (3) a 120-foot-high, 920-foot-long earth embankment dam creating; (4) a lower reservoir with a surface area of 220 acres and an 7,300 acre-foot storage capacity; (5) one 30-foot-diameter, 3,200-foot-long penstock; (6) a bifurcation to three penstocks each 16-foot-diameter, and 100-foot-long; (7) an underground powerhouse/pumping station containing three pump/generating units with a total generating capacity of 600 megawatts; (8) a 30-foot-diameter, 700-foot-long tailrace tunnel; (9) a 24-foot-diameter, 2,000-foot-long access tunnel; (10) a substation; (11) a 1.4-mile-long, 500 kV transmission line to an existing distribution line; and (12) a 6,300-foot-long access road. The proposed project would have an average annual generation of 1,500,000 megawatt-hours (MWh), which would be sold to a local utility.
Deadline for filing comments, motions to intervene, competing applications (without notices of intent), or notices of intent to file competing applications: 60 days from the issuance of this notice. Competing applications and notices of intent must meet the requirements of 18 CFR 4.36. Comments, motions to intervene, notices of intent, and competing applications may be filed electronically via the Internet. See 18 CFR 385.2001(a)(1)(iii) and the instructions on the Commission's Web site
More information about this project, including a copy of the application, can be viewed or printed on the “eLibrary” link of the Commission's Web site at
The Commission has received two preliminary permit applications deemed filed on May 3, 2011, at 8:30 a.m.,
On February 22, 2012, at 9 a.m. (Eastern Time), the Secretary of the Commission, or her designee, will conduct a random drawing to determine the filing priority of the applicants identified in this notice. The Commission will select among competing permit applications as provided in section 4.37 of its regulations.
The drawing is open to the public and will be held in Room 2C, the Commission Meeting Room, located at 888 First St. NE., Washington, DC 20426. A subsequent notice will be issued by the Secretary announcing the results of the drawing.
The Commission has received two preliminary permit applications deemed filed on May 3, 2011, at 8:30 a.m.,
On February 22, 2012, at 9 a.m. (Eastern Time), the Secretary of the Commission, or her designee, will conduct a random drawing to determine the filing priority of the applicants identified in this notice. The Commission will select among competing permit applications as provided in section 4.37 of its regulations.
The drawing is open to the public and will be held in room 2C, the Commission Meeting Room, located at 888 First Street NE., Washington, DC 20426. A subsequent notice will be issued by the Secretary announcing the results of the drawing.
The Commission has received two preliminary permit applications deemed filed on May 3, 2011, at 8:30 a.m.,
On February 22, 2012, at 9 a.m. (Eastern Time), the Secretary of the Commission, or her designee, will conduct a random drawing to determine the filing priority of the applicants identified in this notice. The Commission will select among competing permit applications as provided in section 4.37 of its regulations.
The drawing is open to the public and will be held in room 2C, the Commission Meeting Room, located at 888 First St. NE., Washington, DC 20426. A subsequent notice will be issued by the Secretary announcing the results of the drawing.
The Commission has received three preliminary permit applications deemed filed on April 1, 2011, at 8:30 a.m.,
On February 22, 2012, at 9 a.m. (Eastern Time), the Secretary of the
The drawing is open to the public and will be held in room 2C, the Commission Meeting Room, located at 888 First St. NE., Washington, DC 20426. A subsequent notice will be issued by the Secretary announcing the results of the drawing.
The Commission has received two preliminary permit applications deemed filed on August 6, 2010, at 8:30 a.m.,
On February 22, 2012, at 9 a.m. (Eastern Time), the Secretary of the Commission, or her designee, will conduct a random drawing to determine the filing priority of the applicants identified in this notice. The Commission will select among competing permit applications as provided in section 4.37 of its regulations.
The drawing is open to the public and will be held in room 2C, the Commission Meeting Room, located at 888 First Street NE., Washington, DC 20426. A subsequent notice will be issued by the Secretary announcing the results of the drawing.
The Commission has received two preliminary permit applications deemed filed on May 3, 2011, at 8:30 a.m.,
On February 22, 2012, at 9 a.m. (Eastern Time), the Secretary of the Commission, or her designee, will conduct a random drawing to determine the filing priority of the applicants identified in this notice. The Commission will select among competing permit applications as provided in section 4.37 of its regulations.
The drawing is open to the public and will be held in room 2C, the Commission Meeting Room, located at 888 First St. NE., Washington, DC 20426. A subsequent notice will be issued by the Secretary announcing the results of the drawing.
The Commission has received two preliminary permit applications deemed filed on May 3, 2011, at 8:30 a.m.,
On February 22, 2012, at 9 a.m. (Eastern Time), the Secretary of the Commission, or her designee, will conduct a random drawing to determine the filing priority of the applicants identified in this notice. The Commission will select among competing permit applications as provided in section 4.37 of its regulations.
The drawing is open to the public and will be held in room 2C, the Commission Meeting Room, located at 888 First St. NE., Washington, DC 20426. A subsequent notice will be issued by the Secretary announcing the results of the drawing.
The Commission has received two preliminary permit applications deemed
On February 22, 2012, at 9 a.m. (Eastern Time), the Secretary of the Commission, or her designee, will conduct a random drawing to determine the filing priority of the applicants identified in this notice. The Commission will select among competing permit applications as provided in section 4.37 of its regulations.
The drawing is open to the public and will be held in room 2C, the Commission Meeting Room, located at 888 First St. NE., Washington, DC 20426. A subsequent notice will be issued by the Secretary announcing the results of the drawing.
The Commission has received two preliminary permit applications deemed filed on May 3, 2011, at 8:30 a.m.,
On February 22, 2012, at 9 a.m. (Eastern Time), the Secretary of the Commission, or her designee, will conduct a random drawing to determine the filing priority of the applicants identified in this notice. The Commission will select among competing permit applications as provided in section 4.37 of its regulations.
The drawing is open to the public and will be held in room 2C, the Commission Meeting Room, located at 888 First St. NE., Washington, DC 20426. A subsequent notice will be issued by the Secretary announcing the results of the drawing.
The Commission has received two preliminary permit applications deemed filed on May 3, 2011, at 8:30 a.m.,
On February 22, 2012, at 9 a.m. (Eastern Time), the Secretary of the Commission, or her designee, will conduct a random drawing to determine the filing priority of the applicants identified in this notice. The Commission will select among competing permit applications as provided in section 4.37 of its regulations.
The drawing is open to the public and will be held in room 2C, the Commission Meeting Room, located at 888 First St. NE., Washington, DC 20426. A subsequent notice will be issued by the Secretary announcing the results of the drawing.
The Commission has received two preliminary permit applications deemed filed on May 3, 2011, at 8:30 a.m.,
On February 22, 2012, at 9 a.m. (Eastern Time), the Secretary of the Commission, or her designee, will conduct a random drawing to determine the filing priority of the applicants identified in this notice. The Commission will select among competing permit applications as provided in section 4.37 of its regulations.
The drawing is open to the public and will be held in room 2C, the Commission Meeting Room, located at 888 First St. NE., Washington, DC 20426. A subsequent notice will be issued by the Secretary announcing the results of the drawing.
Take notice that on January 31, 2012, Southwest Gas Storage Company (Southwest), P.O. Box 4967, Houston, Texas 77210, filed a prior notice application pursuant to sections 157.205, 157.208, 157.213, and 157.216 of the Federal Energy Regulatory Commission's regulations under the Natural Gas Act (NGA), and Southwest's blanket certificate issued in Docket No. CP99-230-000, to construct, replace, and abandon facilities at Southwest's Howell storage field in Livingston County, Michigan. Specifically, Southwest proposes to (1) drill dual horizontal wellbore extensions in two injection/withdrawal wells; (2) convert three injection/withdrawal wells to observation wells; (3) replace pipe associated with four storage laterals; and (4) abandon in place three storage laterals, all as more fully set forth in the application, which is open to the public for inspection. The filing may also be viewed on the web at
Any questions regarding this application should be directed to Stephen Veatch, Senior Director of Certificates and Tariffs, Southwest Gas Storage Company, 501 Westheimer Road, Houston, Texas 77056 or telephone (713) 989-2024 or fax (713) 989-1158 or by email
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.
Persons who wish to comment only on the environmental review of this project should submit an original and two copies of their comments to the Secretary of the Commission. Environmental commentors will be placed on the Commission's environmental mailing list, will receive copies of the environmental documents, and will be notified of meetings associated with the Commission's environmental review process. Environmental commentors will not be required to serve copies of filed documents on all other parties. However, the non-party commentors will not receive copies of all documents filed by other parties or issued by the Commission (except for the mailing of environmental documents issued by the Commission) and will not have the right to seek court review of the Commission's final order.
The Commission strongly encourages electronic filings of comments, protests, and interventions via the Internet in lieu of paper. See 18 CFR 385.2001(a)(1)(iii) and the instructions on the Commission's web site (
Environmental Protection Agency.
Notice.
In compliance with the Paperwork Reduction Act (PRA) (44 U.S.C. 3501
Comments must be submitted on or before April 16, 2012.
Submit your comments, identified by Docket ID No. EPA-HQ-OAR-2003-0034, by one of the following methods:
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Sally Rand, Climate Change Division, Office of Atmospheric Programs, 6207J, Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone number: 202-343-9739; fax number: 202-343-2202; email address:
EPA has established a public docket for this ICR under Docket ID No. EPA-HQ-OAR-2003-0034, which is available for online viewing at
Use
Pursuant to section 3506(c)(2)(A) of the PRA, EPA specifically solicits comments and information to enable it to:
(i) Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the Agency, including whether the information will have practical utility;
(ii) evaluate the accuracy of the Agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
(iii) enhance the quality, utility, and clarity of the information to be collected; and
(iv) minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated electronic, mechanical, or other technological collection techniques or other forms of information technology, e.g., permitting electronic submission of responses. In particular, EPA is requesting comments from very small businesses (those that employ less than 25) on examples of specific additional efforts that EPA could make to reduce the paperwork burden for very small businesses affected by this collection.
You may find the following suggestions helpful for preparing your comments:
1. Explain your views as clearly as possible and provide specific examples.
2. Describe any assumptions that you used.
3. Provide copies of any technical information and/or data you used that support your views.
4. If you estimate potential burden or costs, explain how you arrived at the estimate that you provide.
5. Offer alternative ways to improve the collection activity.
6. Make sure to submit your comments by the deadline identified under
7. To ensure proper receipt by EPA, be sure to identify the docket ID number assigned to this action in the subject line on the first page of your response. You may also provide the name, date, and
The ICR provides a detailed explanation of the Agency's estimate, which is only briefly summarized here:
There is a decrease of 60 hours in the total estimated respondent burden compared with that identified in the ICR currently approved by OMB. This decrease reflects that effective in 2010, all producers of primary aluminum are subject to mandatory reporting under EPA's Greenhouse Gas Reporting Program (GGRP). Emissions data collection and reporting efforts are no longer components of the voluntary activities covered by this information collection request. Consequently, the overall burden has decreased from 90 hours to 30 hours with the corresponding decrease in the previously estimated reporting burden.
EPA will consider the comments received and amend the ICR as appropriate. The final ICR package will then be submitted to OMB for review and approval pursuant to 5 CFR 1320.12. At that time, EPA will issue another
Environmental Protection Agency.
Notice.
In compliance with the Paperwork Reduction Act (PRA) (44 U.S.C. 3501
Comments must be submitted on or before April 16, 2012.
Submit your comments, identified by Docket ID No. EPA-HQ-SFUND-2005-0008 by one of the following methods:
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•
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Sicy Jacob, Office of Emergency Management, Mail Code 5104A, Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone number: (202) 564-8019; fax number: (202) 564-2620; email address:
EPA has established a public docket for this ICR under Docket ID No. EPA-HQ-SFUND-2005-0008, which is available for online viewing at
Use
Pursuant to section 3506(c)(2)(A) of the PRA, EPA specifically solicits comments and information to enable it 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, 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, e.g., permitting electronic submission of responses. In particular, EPA is requesting comments from very small businesses (those that employ less than 25) on examples of specific additional efforts that EPA could make to reduce the paperwork burden for very small businesses affected by this collection.
You may find the following suggestions helpful for preparing your comments:
1. Explain your views as clearly as possible and provide specific examples.
2. Describe any assumptions that you used.
3. Provide copies of any technical information and/or data you used that support your views.
4. If you estimate potential burden or costs, explain how you arrived at the estimate that you provide.
5. Offer alternative ways to improve the collection activity.
6. Make sure to submit your comments by the deadline identified under DATES.
7. To ensure proper receipt by EPA, be sure to identify the docket ID number assigned to this action in the subject line on the first page of your response. You may also provide the name, date, and
On November 3, 2008 (73 FR 64452), EPA has revised some of the requirements in 40 CFR part 355, specifically, the requirements related to emergency planning notification. EPA is now requiring facilities to notify their LEPC within 30 days of any changes occurring at the facility that may be relevant to emergency planning. This revision should not impose any additional burden on facilities subject to emergency planning. Prior to the November 3, 2008 final rule, facilities were required to provide any changes to the LEPC promptly. This final rule now requires facilities to provide any changes within 30 days. Other revisions finalized on November 3, 2008 do not impose any burden on facilities subject to Section 302 and 304 requirements.
The average burden for emergency planning activities is 21 hours per plan for LEPCs, and 16 hours per plan for SERCs. Each SERC and LEPC is also estimated to incur an annual record keeping burden of 10 hours. The total annual burden to LEPCs and SERCs is 106,856 hours at a cost of $4.2 million.
Burden means the total time, effort, or financial resources expended by persons to generate, maintain, retain, or disclose or provide information to or for a Federal agency. This includes the time needed to review instructions; develop, acquire, install, and utilize technology and systems for the purposes of collecting, validating, and verifying information, processing and maintaining information, and disclosing and providing information; adjust the existing ways to comply with any previously applicable instructions and requirements which have subsequently changed; train personnel to be able to respond to a collection of information; search data sources; complete and review the collection of information;
The ICR provides a detailed explanation of the Agency's estimate, which is only briefly summarized here:
EPA will consider the comments received and amend the ICR as appropriate. The final ICR package will then be submitted to OMB for review and approval pursuant to 5 CFR 1320.12. At that time, EPA will issue another
Environmental Protection Agency.
Notice.
In compliance with the Paperwork Reduction Act (PRA) (44 U.S.C. 3501
Comments must be submitted on or before April 16, 2012.
Submit your comments, identified by Docket ID No. EPA-HQ-2003-0052, by one of the following methods:
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•
•
•
•
Sicy Jacob, Office of Emergency Management, Mail code 5104A, Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone number: (202) 564-8019; fax number: (202) 564-2625; email address:
EPA has established a public docket for this ICR under Docket ID No. EPA-HQ-OAR-2003-0052 which is available for online viewing at
Use
Pursuant to section 3506(c)(2)(A) of the PRA, EPA specifically solicits comments and information to enable it to:
(i) Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the Agency, including whether the information will have practical utility;
(ii) Evaluate the accuracy of the Agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
(iii) Enhance the quality, utility, and clarity of the information to be collected; and
(iv) Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated electronic, mechanical, or other technological collection techniques or other forms of information technology, e.g., permitting electronic submission of responses. In particular, EPA is requesting comments from very small businesses (those that employ less than 25) on examples of specific additional efforts that EPA
You may find the following suggestions helpful for preparing your comments:
1. Explain your views as clearly as possible and provide specific examples.
2. Describe any assumptions that you used.
3. Provide copies of any technical information and/or data you used that support your views.
4. If you estimate potential burden or costs, explain how you arrived at the estimate that you provide.
5. Offer alternative ways to improve the collection activity.
6. Make sure to submit your comments by the deadline identified under
7. To ensure proper receipt by EPA, be sure to identify the docket ID number assigned to this action in the subject line on the first page of your response. You may also provide the name, date, and
Docket ID No. EPA-HQ-OAR-2003-0052.
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.
The EPA would like to solicit comments to:
(i) Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the Agency, including whether the information will have practical utility;
(ii) Evaluate the accuracy of the Agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
(iii) Enhance the quality, utility, and clarity of the information to be collected; and
(iv) Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated electronic, mechanical, or other technological collection techniques or other forms of information technology, e.g., permitting electronic submission of responses.
Burden means the total time, effort, or financial resources expended by persons to generate, maintain, retain, or disclose or provide information to or for a Federal agency. This includes the time needed to review instructions; develop, acquire, install, and utilize technology and systems for the purposes of collecting, validating, and verifying information, processing and maintaining information, and disclosing and providing information; adjust the existing ways to comply with any previously applicable instructions and
The ICR provides a detailed explanation of the Agency's estimate, which is only briefly summarized here:
EPA will consider the comments received and amend the ICR as appropriate. The final ICR package will then be submitted to OMB for review and approval pursuant to 5 CFR 1320.12. At that time, EPA will issue another
Environmental Protection Agency (EPA).
Notice of Decision.
EPA has granted the California Air Resources Board (CARB) its request for a waiver of preemption and authorization to adopt and enforce California's Truck Idling Requirements. CARB's Truck Idling Requirements apply to new California-certified 2008 and subsequent model year heavy-duty diesel engines in heavy-duty diesel vehicles with a gross vehicle weight rating over 14,000 pounds, and to in-use diesel-fueled commercial vehicles with gross vehicle weight ratings over 10,000 pounds that are equipped with sleeper berths.
Petitions for review must be filed by April 16, 2012.
EPA has established a docket for this action under Docket ID EPA-HQ-OAR-2010-0317. All documents relied upon in making this decision, including those submitted to EPA by CARB, and public comments, are contained in the public docket. Publicly available docket materials are available either electronically through
EPA's Office of Transportation and Air Quality (“OTAQ”) maintains a Web page that contains general information on its review of California waiver requests. Included on that page are links to prior waiver
Kristien G. Knapp, Attorney-Advisor, Compliance and Innovative Strategies Division, Office of Transportation and Air Quality, U.S. Environmental Protection Agency, 1200 Pennsylvania Avenue (6405J), NW., Washington, DC 20460. Telephone: (202) 343-9949. Fax: (202) 343-2800. Email:
By letter dated May 9, 2008, CARB informed EPA that it had adopted its Truck Idling Requirements, and requested that EPA confirm that certain provisions of the requirements are not preempted by sections 209(a) of the Clean Air Act (Act); certain provisions are conditions precedent pursuant to section 209(a) of the Act;
CARB's Truck Idling Requirements consist of three elements: (1) “New engine requirements” that require new California-certified 2008 and subsequent model year on-road diesel engines in vehicles with a gross vehicle weight rating (GVWR) greater than 14,000 pounds (
Section 209(a) of the Clean Air Act preempts states and local governments from setting emission standards for new motor vehicles and engines; it provides:
No State or any political subdivision thereof shall adopt or attempt to enforce any standard relating to the control of emissions from new motor vehicles or new motor vehicle engines subject to this part. No state shall require certification, inspection or any other approval relating to the control of emissions from any new motor vehicle or new motor vehicle engine as condition precedent to the initial retail sale, titling (if any), or registration of such motor vehicle, motor vehicle engine, or equipment.
The second sentence of section 209(a) of the Act prevents states from requiring, “certification, inspection or any other approval relating to the control of emissions from any new motor vehicle or new motor vehicle engine as condition precedent to the initial retail sale, titling (if any), or registration of such motor vehicle, motor vehicle engine, or equipment.” However, once EPA has granted California a waiver of section 209(a)'s preemption for emission standards and/or accompanying enforcement procedures, California may then require other such conditions precedent.
In contrast to section 209(a)'s preemption of state adoption of standards controlling emissions from new motor vehicles and motor vehicle engines, section 209(d) of the Act explicitly preserves states' ability to regulate vehicles and engines in use. Section 209(d) provides that despite section 209(a)'s preemption, “Nothing in this part shall preclude or deny to any State or political subdivision thereof the right otherwise to control, regulate, or restrict the use, operation, or movement of registered or licensed motor vehicles.”
Section 209(e)(1) of the Act permanently preempts any State, or political subdivision thereof, from adopting or attempting to enforce any standard or other requirement relating to the control of emissions for certain new nonroad engines or vehicles. Section 209(e)(2) of the Act requires the Administrator to grant California authorization to enforce its own
(a) The Administrator will grant the authorization if California determines that its standards will be, in the aggregate, at least as protective of public health and welfare as otherwise applicable federal standards.
(b) The authorization will not be granted if the Administrator finds that any of the following are true:
(1) California's determination is arbitrary and capricious.
(2) California does not need such standards to meet compelling and extraordinary conditions.
(3) The California standards and accompanying enforcement procedures are not consistent with section 209 of the Act.
(c) In considering any request from California to authorize the state to adopt or enforce standards or other requirements relating to the control of emissions from new nonroad spark-ignition engines smaller than 50 horsepower, the Administrator will give appropriate consideration to safety factors (including the potential increased risk of burn or fire) associated with compliance with the California standard.
In order to be consistent with section 209(a), California's nonroad standards and enforcement procedures must not apply to new motor vehicles or new motor vehicle engines. To be consistent with section 209(e)(1), California's nonroad standards and enforcement procedures must not attempt to regulate engine categories that are permanently preempted from state regulation. To determine consistency with section 209(b)(1)(C), EPA typically reviews nonroad authorization requests under the same “consistency” criteria that are applied to motor vehicle waiver requests. Pursuant to section 209(b)(1)(C), the Administrator shall not grant California a motor vehicle waiver if she finds that California “standards and accompanying enforcement procedures are not consistent with section 202(a)” of the Act. Previous decisions granting waivers and authorizations have noted that state standards and enforcement procedures are inconsistent with section 202(a) if: (1) There is inadequate lead time to permit the development of the necessary technology giving appropriate consideration to the cost of compliance within that time, or (2) the federal and state testing procedures impose inconsistent certification requirements.
If California amends regulations that were previously granted a waiver of preemption, EPA can confirm that the amended regulations are within the scope of the previously granted waiver. Such within-the-scope amendments are permissible without a full waiver review if three conditions are met. First, the amended regulations must not undermine California's determination that its standards, in the aggregate, are as protective of public health and welfare as applicable federal standards. Second, the amended regulations must not affect consistency with section 202(a) of the Act. Third, the amended regulations must not raise any “new issues” affecting EPA's prior waivers.
In
The court upheld the Administrator's position that, to deny a waiver, there must be `clear and compelling evidence' to show that proposed procedures undermine the protectiveness of California's standards.
With respect to the consistency finding, the court did not articulate a standard of proof applicable to all proceedings, but found that the opponents of the waiver were unable to meet their burden of proof even if the standard were a mere preponderance of the evidence. Although
Opponents of the waiver bear the burden of showing that the criteria for a denial of California's waiver request have been met. As found in
Upon review of CARB's request, EPA invited public comment on the entire request, including but not limited to the following issues.
First, we asked whether we should consider CARB's new engine requirements as non-preempted operational controls, or as conditions precedent. In the alternative, should we determine that CARB's new engine requirements must be treated as standards relating to the control of emissions or accompanying enforcement procedures, we asked whether they be subject to and meet the criteria for EPA to confirm that they are within-the-scope of EPA's waiver for new heavy-duty diesel engines for 2007 and subsequent model years. To the extent the new engine requirements should be treated as standards relating to the control of emissions or accompanying enforcement procedures and require a full waiver from EPA, we asked whether the requirements meet the full waiver criteria.
Second, we asked whether CARB's sleeper truck requirements properly should be considered an operational control and thus not preempted by section 209 of the Act. To the extent that CARB's sleeper truck requirements should be treated as standards relating to the control of emissions from new motor vehicles or engines or accompanying enforcement procedures and require a full waiver from EPA, we sought comment on whether the requirements meet the criteria for a full waiver.
Third, with respect to CARB's alternative technology requirements, EPA sought comment on the following specific questions: (1) Does CARB's requirement that an APS using an internal combustion engine be certified to meet either California off-road or federal nonroad emission standards and test procedures meet the requirements for finding that it is within-the-scope of the authorization EPA issued for new nonroad engine standards, thus not requiring a full authorization?;
As called out by those specific questions, EPA sought threshold input on whether to treat various elements of CARB's Truck Idling Requirements as conditions precedent, within the scope of previous waivers and authorizations, not preempted by section 209, or in need of a full waiver or authorization. We also sought substantive comment on whether the various elements of CARB's Truck Idling Requirements meet the applicable criteria for confirmation as conditions precedent, within the scope, non-preemption, and full waiver or authorization.
In response to EPA's July 27, 2010
ATA's comments specifically oppose California's “alternative technology requirements,” which establish in-use performance standards for HDDV operators who use alternative technologies (e.g., auxiliary power units) to supply power for truck cab or sleeper berth climate control and/or other on-board accessories that otherwise would have been generated by the continuous idling of the truck's main engine. ATA comments that those requirements are not consistent with sections 202(a) and 209(e) of the Clean Air Act.
OOIDA's comments address issues it believes have been overlooked by EPA, including “CARB's delay in requesting EPA review of Truck Idling Requirements without waiting for an EPA determination; CARB's premature implementation and enforcement of those Requirements without waiting for an EPA determination; and CARB's failure to consider the potential adverse impact of these requirements on the health and welfare of the affected truck drivers.” OOIDA also suggested that the Truck Idling Requirements may be preempted by federal law other than the Clean Air Act. OOIDA also requested an additional forty-five days—until November 15, 2010—to fully evaluate a recent decision by the United States Court of Appeals for the Ninth Circuit,
CARB submitted additional information in the form of supplemental comments to update its request in light of EPA's authorization of California's new nonroad compression-ignition regulations, and information regarding technological feasibility. CARB also responded to EPA's request for comments, and the comments EPA received from ATA and OOIDA. CARB's supplemental comments assert that ATA and OOIDA have failed to meet their burden of proof for a denial. CARB further requests that EPA grant California its requested waiver and authorizations to adopt and enforce its Truck Idling Requirements.
California's Truck Idling Requirements feature four general sets of requirements: Those applicable to
The new engine requirements imposed by California's Truck Idling Requirements establish two compliance options for new California certified 2008 and subsequent model year heavy-duty diesel engines installed in trucks with a gross vehicle weight rating greater than 14,000 pounds. The first compliance option requires engine manufacturers to install a system that automatically shuts down the engine after five minutes of continuous idle operation. The second compliance option is an optional NO
CARB presents, first, that the new engine requirements are akin to operational controls on in-use vehicles and, accordingly, they are not preempted by Clean Air Act section 209(b). Alternatively, CARB argues that the new engine requirements are “other conditions precedent” to initial sale, titling, or registration that fall within the scope of the waiver of preemption EPA issued for California's 2007 and subsequent model year heavy-duty diesel engine standards. Last, CARB argues that should EPA determine that the new engine requirements constitute standards relating to the control of emissions from new motor vehicle engines, such requirements fall within the scope of previous waivers of preemption. Thus, EPA must first determine what type of control the California new engine requirements impose before proceeding with an analysis of whether California meets the necessary Clean Air Act requirements under section 209.
To address these issues, EPA asked the first set of questions in the July 27, 2010
EPA received no comments in response to the issues EPA raised for comment with respect to California's new engine requirements.
Despite CARB's contentions, EPA has determined that California's new engine requirements are standards relating to the control of emissions that require a full waiver of preemption from EPA. CARB believes that the United States Supreme Court's interpretation of “standard relating to the control of emissions from new motor vehicles or new motor vehicle engines” in
CARB alternatively requested that EPA evaluate California's new engine requirements by application of EPA's within-the-scope criteria. However, the new engine requirements impose an additional design requirement upon engine manufacturers, which is a “new issue” and cautions against application of the within-the-scope criteria. CARB believes its requirement that manufacturers include an engine shutdown system does not present a “new issue” because it “will only require manufacturers to perform minor reprogramming of the software incorporated in existing engine or vehicle computers, and will not require any modifications to hardware.”
Section 209(b)(1)(A) of the Clean Air Act requires EPA to deny a waiver if the Administrator finds that California was arbitrary and capricious in its determination that its State standards will be, in the aggregate, at least as protective of public health and welfare as applicable federal standards. When evaluating California's protectiveness determination, EPA compares the stringency of the California and federal standards at issue in a given waiver request. That comparison is undertaken within the broader context of the previously waived California program, which relies upon protectiveness determinations that EPA previously found were not arbitrary and capricious.
When California adopted its Truck Idling Requirements, the CARB Board made its protectiveness finding in its Resolution 05-55.
No commenter expressed an opinion or presented any evidence suggesting that CARB was arbitrary and capricious in making its above-noted protectiveness findings. Therefore, based on the record, EPA cannot find that California was arbitrary and capricious in its findings that California's new engine requirements are, in the aggregate, at least as protective of public health and welfare as applicable federal standards.
Under section 209(b)(1)(B) of the Act, EPA cannot grant a waiver if California “does not need such State standards to meet compelling and extraordinary conditions.” To evaluate this criterion, EPA considers whether California needs a separate motor vehicle emissions program to meet compelling and extraordinary conditions.
Over the past forty years, CARB has repeatedly demonstrated the need for its motor vehicle emissions program to address compelling and extraordinary conditions in California.
Under section 209(b)(1)(C) of the Act, EPA must deny a California waiver request if the Agency finds that California standards and accompanying enforcement procedures are not consistent with section 202(a) of the Act. The scope of EPA's review under this criterion is narrow. EPA has stated on many occasions that the determination is limited to whether those opposed to the waiver have met their burden of establishing that California's standards are technologically infeasible, or that California's test procedures impose requirements inconsistent with federal test procedures. Previous waivers of federal preemption have stated that California's standards are not consistent with section 202(a) if there is inadequate lead time to permit the development of technology necessary to meet those requirements, giving appropriate consideration to the cost of compliance within that time. California's accompanying enforcement procedures would be inconsistent with section 202(a) if the federal and California test procedures conflict,
California presents that its new engine requirements are currently technologically feasible, with appropriate consideration given to cost, and do not impose inconsistent certification requirements.
No commenter expressed any disagreement with these statements from CARB, and no commenter presented any evidence opposing CARB's assertions regarding technological feasibility, lead-time, and cost of compliance. Therefore, EPA is unable to find that California's new engine requirements are not technologically feasible within the
After a review of the information submitted by CARB and other parties to this proceeding, EPA finds that those opposing California's request have not met the burden of demonstrating that a waiver for California's new engine requirements should be denied based on any of the three statutory criteria of section 209(b)(1). For this reason, EPA finds that California's new engine requirements should receive a full waiver of preemption.
California's Truck Idling Requirements impose a new requirement on the operators of sleeper berth equipped heavy-duty diesel vehicles. Sleeper truck operators will now be required to manually shut off engines after five minutes of continuous idling. To address CARB's sleeper truck requirements, EPA asked the second set of questions in the July 27, 2010
California asserts that the sleeper truck requirements are an in-use operational control of motor vehicles and do not require a waiver of preemption. Since the sleeper truck requirements only apply to in-use motor vehicles, and Clean Air Act section 209(a) preemption only applies to new motor vehicles and engines, CARB asserts that section 209(a) preemption does not apply to these requirements. Additionally, CARB points towards section 209(d) of the Act, which states: “Nothing in this part shall preclude or deny to any State or political subdivision thereof the right otherwise to control, regulate, or restrict the use, operation, or movement of registered vehicles.” Read together, sections 209(a) and 209(d) make clear that operational controls, such as idling limits directed towards the operator of the vehicle, are not preempted and do not need a waiver of preemption pursuant to section 209(b). EPA agrees with this analysis and does not believe that in-use controls, such as idling limits, are preempted by section 209(a). Therefore, California's sleeper truck requirements do not require a waiver of preemption under section 209(b) of the Act.
OOIDA comments that the sleeper truck idling requirements will have an adverse effect on the health and welfare of drivers. This comment is inapplicable to EPA's analysis here, because as stated above, EPA has found that the sleeper truck requirements are not preempted under section 209(a). Therefore, EPA has no authority to evaluate California's sleeper truck requirements. To the extent this comment suggests that California's protectiveness determination for its alternative technology requirements was arbitrary and capricious, we have addressed that issue below.
CARB anticipated that truck operators would likely utilize alternative technologies to power truck cabins, sleeper berths, and/or other on-board accessories that previously would have been powered by the truck's main engine. Such alternative technologies include internal combustion engine powered alternative power sources (“APSs”) and fuel-fired heaters. To account for the increased particulate matter (PM) emissions that would be generated by inclusion of these alternative technologies on heavy-duty diesel vehicles, CARB developed alternative technology requirements. CARB's general alternative technology requirement is that internal combustion engines used in APSs must be certified to the California or federal nonroad emission standards and test procedures applicable to the fuel type and horsepower category of the engines. CARB also imposes specific requirements for diesel-fueled APSs, dependent upon model year. For 2007 and later model year heavy-duty diesel trucks, a diesel-fueled APS must comply with California or federal nonroad emission standards and one of three additional requirements: (1) Route their exhaust into the truck's exhaust system so that the APS's PM emissions are controlled by the truck's PM trap; or (2) be equipped with a level 3 verified PM control strategy (
With respect to CARB's alternative technology requirements, in the July 27, 2010
With respect to the threshold question EPA asked as to which waiver analysis to apply to CARB's APS requirements, EPA received no comments. CARB asserts that because its APS requirements are linked to preexisting federal or California standards and certification requirements, the new APS requirements are within the scope of the prior authorizations for these engines. However, EPA does not believe that a within-the-scope analysis is appropriate in this circumstance. In the past, EPA has reviewed amendments to previously waived or authorized California standards for a determination of whether those amendments were within the scope of the previously waived or authorized standards. Here though, the APS requirements as imposed by California's Truck Idling Requirements are not amendments, but new regulations. Even though the APS
Section 209(e)(2)(i) of the Act instructs that EPA cannot grant an authorization if the agency finds that CARB was arbitrary and capricious in its determination that its standards are, in the aggregate, at least as protective of public health and welfare as applicable federal standards. CARB's Board made a protectiveness determination in Resolution 05-55, finding that California's Truck Idling Requirements will not cause the California emission standards, in the aggregate, to be less protective of public health and welfare than applicable federal standards.
EPA received one comment challenging California's protectiveness determination with respect to the APS requirements. OOIDA comments that “in determining whether CARB's sleeper truck and alternative power source requirements should be approved, under any analysis, EPA should take care to fully consider and balance against the benefits to be gained by reducing emissions from idling sleeper trucks, the very real adverse impact such a requirement would have on the health and welfare of the operators of those trucks and negative effects on highway safety from truck operators not being properly rested.”
Therefore, based on the record before us, EPA finds that opponents of the authorization have not shown that California was arbitrary and capricious in its determination that its standards are, in the aggregate, at least as protective of public health and welfare as applicable federal standards.
Section 209(e)(2)(ii) of the Act instructs that EPA cannot grant an authorization if the agency finds that California “does not need such California standards to meet compelling and extraordinary conditions * * *.” This criterion restricts EPA's inquiry to whether California needs its own mobile source pollution program to meet compelling and extraordinary conditions, and not whether any given standards are necessary to meet such
Section 209(e)(2)(iii) of the Act instructs that EPA cannot grant an authorization if California's standards and enforcement procedures are not consistent with section 209. As described above, EPA has historically evaluated this criterion for consistency with sections 209(a), 209(e)(1), and 209(b)(1)(C).
To be consistent with section 209(a) of the Clean Air Act, California's APS requirements must not apply to new motor vehicles or engines. California's APS requirements apply to nonroad engines, not new on-highway motor vehicles or engines. CARB presents that although the APS are used on on-highway heavy-duty diesel vehicles and engines, they are auxiliary engines and are not used to propel motor vehicles or engines. CARB further states that because APS are regulated as nonroad engines, they fall within the regulatory definition of nonroad engine, and are, thus, consistent with section 209(a). No commenter presented otherwise; therefore, EPA cannot deny California's request on the basis that California's APS requirements are not consistent with section 209(a).
To be consistent with section 209(e)(1) of the Clean Air Act, California's APS requirements must not affect new farming or construction vehicles or engines that are below 175 horsepower, or new locomotives or their engines. CARB presents that APS engines are not used in locomotives and are not primarily used in farm and construction equipment vehicles. No commenter presented otherwise; therefore, EPA cannot deny California's request on the basis that California's APS requirements are not consistent with section 209(e)(1).
The requirement that California's standards be consistent with section 209(b)(1)(C) of the Clean Air Act effectively requires consistency with section 202(a) of the Act. California standards are inconsistent with section 202(a) of the Act if there is inadequate lead-time to permit the development of technology necessary to meet those requirements, giving appropriate consideration to the cost of compliance within that time. California's accompanying enforcement procedures would also be inconsistent with section 202(a) if the federal and California test procedures were not consistent. The scope of EPA's review of whether California's action is consistent with section 202(a) is narrow. The determination is limited to whether those opposed to the authorization or waiver have met their burden of establishing that California's standards are technologically infeasible, or that California's test procedures impose requirements inconsistent with the federal test procedure.
Congress has stated that the consistency requirement of section 202(a) relates to technological feasibility.
With respect to the general APS requirements, CARB presents that the technological feasibility is readily apparent. CARB believes this because the general APS requirement is that the APS complies with the California or federal nonroad emission standards and test procedures applicable for its fuel type and power category. Therefore, EPA has already determined the technological feasibility for these standards, either in its own federal rulemaking or by authorizing the underlying California standards in a previous authorization.
With respect to the specific APS requirements for diesel APSs, CARB presents that each option is technologically feasible in the specified lead-time. Broadly, CARB asserts that “numerous technologies currently exist that can be used to comply with these requirements, including routing the exhaust from an APS into the exhaust system of the main engine, battery electric APSs, thermal energy storage systems, and on-shore electrical power infrastructures at truck stops.”
In its comments, OOIDA expresses concerns related to the cost of APSs on truck drivers. OOIDA believes that faced with the added expense of an APS, truck drivers will decide not to invest in APSs and “instead subject themselves to unhealthy and unsafe cab temperatures and conditions when hauling cargo in [California].”
EPA did not receive any other comments suggesting that CARB's standards and test procedures are technologically infeasible. Consequently, based on the record, EPA cannot deny California's authorization based on technological infeasibility.
California's standards and accompanying enforcement procedures would also be inconsistent with section 202(a) if the California test procedures were to impose certification requirements inconsistent with the federal certification requirements. Such inconsistency means that manufacturers would be unable to meet both the California and federal testing requirements using the same test vehicle or engine.
CARB presents that none of the APS requirements pose any inconsistency as between California and federal test procedures. First, CARB asserts that its general APS requirements do not modify the test procedures specified for certifying a California or federal nonroad engine.
EPA received no comments suggesting that CARB's APS requirements pose a test procedure consistency problem. Therefore, based on the record, EPA cannot find that CARB's testing procedures are inconsistent with section 202(a). Consequently, EPA cannot deny CARB's request based on this criterion.
In its comments, ATA asserts that because California's APS requirements (those specific to diesel APSs on 2007 and subsequent model year heavy-duty diesel vehicles) apply to new diesel engines, they circumvent the consistency criteria of the Clean Air Act. ATA does not reference any of the sections of the Act which EPA has historically evaluated (
ATA also contends that EPA cannot grant a new authorization for California's APS requirements (again, those specific to diesel APSs on 2007 and subsequent model year heavy-duty diesel vehicles) because “CARB has not complied with the lead time and stability requirements of section 202(a)(3)(C)” of the Clean Air Act. This comment also does not comport with the section 209 criteria. California must take lead-time into account, and EPA must consider lead-time when evaluating California's regulations pursuant to section 209(e)'s consistency requirements. However, the lead-time inquiry EPA undertakes relates to technological feasibility. Specifically, consistency with section 202(a) requires the Administrator to first determine whether adequate technology already exists; or if it does not, whether there is adequate time to develop and apply the technology before the standards go into effect.
After a review of the information submitted by CARB and other parties to this proceeding, EPA finds that those opposing California's request have not met the burden of demonstrating that a waiver for California's APS requirements should be denied based on any of the three statutory criteria of section 209(e)(2). For this reason, EPA finds that California's APS requirements should be authorized.
California's Truck Idling Requirements also impose emission requirements on fuel-fired heaters. Fuel-fired heaters provide heat to truck cabs or sleeper berths and/or preheat engine blocks during cold weather. Fuel-fired heaters on 2007 and later model year trucks operating in California may now only operate fuel-fired heaters that comply with California's second generation of low emission vehicle (LEV II) regulations.
With respect to CARB's fuel-fired heater requirements, in the July 27, 2010
CARB presents that its fuel-fired heater requirements are not preempted and, accordingly, do not require an authorization.
Engine manufacturers, original equipment manufacturers (OEMs), and internal combustion APSs manufacturers, as applicable, are required to produce and affix permanent labels to the hood of the truck. These labels are intended to assist CARB enforcement staff in clearly and easily identifying diesel trucks that comply with the California Truck Idling Requirements. As stated above, EPA is today issuing a waiver of preemption for the new engine requirements and an authorization for the APS requirements. California's engine and optional NO
OOIDA's comments present two other issues that generally challenge California's Truck Idling Requirements. First, OOIDA asserts that CARB should be prohibited from enforcing its Truck Idling Requirements until EPA approves them. Second, OOIDA asserts that federal laws other than the Clean Air Act may preempt California's Truck Idling Requirements. As EPA has stated on numerous occasions, sections 209(b) and 209(e) of the Clean Air Act limit our authority to deny California requests for waivers and authorizations to the three criteria listed therein. As a result, EPA has consistently refrained from denying California's requests for waivers and authorizations based on any other criteria.
The Administrator has delegated the authority to grant California section 209(b) waivers of preemption and section 209(e) authorizations to the Assistant Administrator for Air and Radiation. After evaluating CARB's Truck Idling Requirements, CARB's submissions, and the public comments from ATA and OOIDA, EPA is taking the following actions. First, EPA is granting a waiver of preemption to California for its new engine requirements. Second, EPA is granting
My decision will affect not only persons in California, but also manufacturers outside the State who must comply with California's requirements in order to produce vehicles for sale in California. For this reason, I determine and find that this is a final action of national applicability for purposes of section 307(b)(1) of the Act. Pursuant to section 307(b)(1) of the Act, judicial review of this final action may be sought only in the United States Court of Appeals for the District of Columbia Circuit. Petitions for review must be filed by April 16, 2012. Judicial review of this final action may not be obtained in subsequent enforcement proceedings, pursuant to section 307(b)(2) of the Act.
As with past authorization and waiver decisions, this action is not a rule as defined by Executive Order 12866. Therefore, it is exempt from review by the Office of Management and Budget as required for rules and regulations by Executive Order 12866.
In addition, this action is not a rule as defined in the Regulatory Flexibility Act, 5 U.S.C. 601(2). Therefore, EPA has not prepared a supporting regulatory flexibility analysis addressing the impact of this action on small business entities.
Further, the Congressional Review Act, 5 U.S.C. 801,
The notificants listed below have applied under the Change in Bank Control Act (12 U.S.C. 1817(j)) and § 225.41 of the Board's Regulation Y (12 CFR 225.41) to acquire shares of a bank or bank holding company. The factors that are considered in acting on the notices are set forth in paragraph 7 of the Act (12 U.S.C. 1817(j)(7)).
The notices are available for immediate inspection at the Federal Reserve Bank indicated. The notices also will be available for inspection at the offices of the Board of Governors. Interested persons may express their views in writing to the Reserve Bank indicated for that notice or to the offices of the Board of Governors. Comments must be received not later than March 1, 2012.
A. Federal Reserve Bank of Cleveland (Nadine Wallman, Vice President) 1455 East Sixth Street, Cleveland, Ohio 44101-2566:
The companies listed in this notice have applied to the Board for approval, pursuant to the Bank Holding Company Act of 1956 (12 U.S.C. 1841
The applications listed below, as well as other related filings required by the Board, are available for immediate inspection at the Federal Reserve Bank indicated. The application also will be available for inspection at the offices of the Board of Governors. Interested persons may express their views in writing on the standards enumerated in the BHC Act (12 U.S.C. 1842(c)). If the proposal also involves the acquisition of a nonbanking company, the review also includes whether the acquisition of the nonbanking company complies with the standards in section 4 of the BHC Act (12 U.S.C. 1843). Unless otherwise noted, nonbanking activities will be conducted throughout the United States.
Unless otherwise noted, comments regarding each of these applications must be received at the Reserve Bank indicated or the offices of the Board of Governors not later than March 12, 2012.
A. Federal Reserve Bank of Kansas City (Dennis Denney, Assistant Vice President) 1 Memorial Drive, Kansas City, Missouri 64198-0001:
1.
National Institute for Occupational Safety and Health (NIOSH), Centers for Disease Control and Prevention, Department of Health and Human Services (HHS).
Notice.
HHS gives notice of a decision to designate a class of employees from the Savannah River Site in Aiken, South Carolina, as an addition to the Special Exposure Cohort (SEC) under the Energy Employees Occupational Illness Compensation Program Act of 2000. On February 2, 2012, the Secretary of HHS designated the following class of employees as an addition to the SEC:
All employees of the Department of Energy, its predecessor agencies, and their contractors and subcontractors who worked at the Savannah River Site from January 1, 1953, through September 30, 1972, for a number of work days aggregating at least 250 work days, occurring either solely under this employment or in combination with work days within the parameters established for one or more other classes of employees included in the Special Exposure Cohort.
Stuart L. Hinnefeld, Director, Division of Compensation Analysis and Support, NIOSH, 4676 Columbia Parkway, MS C-46, Cincinnati, OH 45226, Telephone 1-877-222-7570. Information requests
National Institute for Occupational Safety and Health (NIOSH), Centers for Disease Control and Prevention, Department of Health and Human Services (HHS).
Notice.
HHS gives notice of a decision to designate a class of employees from the Linde Ceramics Plant in Tonawanda, New York, as an addition to the Special Exposure Cohort (SEC) under the Energy Employees Occupational Illness Compensation Program Act of 2000. On February 2, 2012, the Secretary of HHS designated the following class of employees as an addition to the SEC:
All Atomic Weapons Employees who worked in any area at the Linde Ceramics Plant in Tonawanda, New York, from November 1, 1947, through December 31, 1953, for a number of work days aggregating at least 250 work days, occurring either solely under this employment or in combination with work days within the parameters established for one or more other classes of employees included in the SEC.
Stuart L. Hinnefeld, Director, Division of Compensation Analysis and Support, NIOSH, 4676 Columbia Parkway, MS C-46, Cincinnati, OH 45226, Telephone 1-877-222-7570. Information requests can also be submitted by email to
National Institute for Occupational Safety and Health (NIOSH), Centers for Disease Control and Prevention, Department of Health and Human Services (HHS).
Notice.
HHS gives notice of a determination concerning a petition to add a class of employees from the Hooker Electrochemical Company in Niagara Falls, New York, to the Special Exposure Cohort (SEC) under the Energy Employees Occupational Illness Compensation Program Act of 2000 (EEOICPA), 42 U.S.C. 7384q. On February 2, 2012, the Secretary of HHS determined that the following class of employees does not meet the statutory criteria for addition to the SEC as authorized under EEOICPA:
All employees who worked in any location at the Hooker Electrochemical Corporation during the operational period from January 1, 1943, through December 31, 1948, and during the residual period from January 1, 1949, to December 31, 1976.
Stuart L. Hinnefeld, Director, Division of Compensation Analysis and Support, National Institute for Occupational Safety and Health (NIOSH), 4676 Columbia Parkway, MS C-46, Cincinnati, OH 45226, Telephone 1-877-222-7570. Information requests can also be submitted by email to
Department of Health and Human Services, Office of the Secretary, Office of the Assistant Secretary for Health, Office for Human Research Protections.
Notice.
42 U.S.C. 217a, Section 222 of the Public Health Service Act, as amended. The Committee is governed by the provisions of Public Law 92-463, as amended (5 U.S.C. Appendix 2), which sets forth standards for the formation and use of advisory committees.
The Office for Human Research Protections (OHRP), a program office in the Office of the Assistant Secretary for Health, Department of Health and Human Services (HHS), previously published a notice (76 FR 243, 19 Dec 2011, pp. 78660-78661) seeking nominations of qualified candidates to be considered for appointment as members of the Secretary's Advisory Committee on Human Research Protections (SACHRP). OHRP would like to announce a four week extension of the SACHRP nomination period. As a result of this extension, the nomination period will now end at the close of business on March 16, 2012.
Nominations for membership on the Committee must be received no later than March 16, 2012.
Nominations should be mailed or delivered to Dr. Jerry Menikoff, Director, Office for Human Research Protections, Department of Health and Human Services, 1101 Wootton Parkway, Suite 200, Rockville, MD 20852. Nominations will not be accepted by email or by facsimile.
Julia Gorey, Executive Director, SACHRP, Office for Human Research Protections, 1101 Wootton Parkway, Suite 200, Rockville, MD 20852, telephone: 240-453-8141. A copy of the Committee charter and list of the current members can be obtained by contacting Ms. Gorey, accessing the SACHRP Web site at
The Committee provides advice on matters pertaining to the continuance and improvement of functions within the authority of HHS directed toward protections for human subjects in research. Specifically, the Committee provides advice relating to the responsible conduct of research involving human subjects with particular emphasis on special populations such as neonates and children, prisoners, the decisionally impaired, pregnant women, embryos and fetuses; individuals and populations in international studies, investigator conflicts of interest and research involving individually identifiable samples, data or information.
In addition, the Committee is responsible for reviewing selected ongoing work and planned activities of
The individuals selected for appointment to the Committee can be invited to serve a term of up to four years. Committee members receive a stipend and reimbursement for per diem and any travel expenses incurred for attending Committee meetings or conducting other business in the interest of the Committee. Interested applicants may self-nominate.
Nominations should be typewritten. The following information should be included in the package of material submitted for each individual being nominated for consideration: (1) A letter of nomination that clearly states the name and affiliation of the nominee, the basis for the nomination (i.e., specific attributes which qualify the nominee for service in this capacity), and a statement that the nominee is willing to serve as a member of the Committee; (2) the nominator's name, address, daytime telephone number, and the home or work address, telephone number, and email address of the individual being nominated; and (3) a current copy of the nominee's curriculum vitae. Federal employees should not be nominated for consideration of appointment to this Committee.
The Department makes every effort to ensure that the membership of HHS Federal advisory committees is fairly balanced in terms of points of view represented and the committee's function. Every effort is made to ensure that individuals from a broad representation of geographic areas, women and men, ethnic and minority groups, and the disabled are given consideration for membership on HHS Federal advisory committees. Appointment to this Committee shall be made without discrimination on the basis of age, race, ethnicity, gender, sexual orientation, disability, and cultural, religious, or socioeconomic status.
Individuals who are selected to be considered for appointment will be required to provide detailed information regarding their financial holdings, consultancies, and research grants or contracts. Disclosure of this information is necessary in order to determine if the selected candidate is involved in any activity that may pose a potential conflict with the official duties to be performed as a member of SACHRP.
Agency for Healthcare Research and Quality (AHRQ), HHS.
Notice of public meeting.
The Patient Safety and Quality Improvement Act of 2005, 42 U.S.C. 299b-21 to b-26, (Patient Safety Act) provides for the formation of Patient Safety Organizations (PSOs), which collect, aggregate, and analyze confidential information regarding the quality and safety of health care delivery. The Patient Safety Act (at 42 U.S.C. 299b-23) authorizes the collection of this information in a standardized manner, as explained in the related Patient Safety and Quality Improvement Final Rule, 42 CFR part 3 (Patient Safety Rule), published in the
The purpose of this notice is to announce a meeting to discuss the Common Formats technical specifications. This meeting is designed as an interactive forum where PSOs and software developers can provide input on these technical specifications. AHRQ especially requests input from those entities which have used AHRQ's technical specifications and implemented, or plan to implement, the formats electronically.
The meeting will be held from 10 a.m. to 3:30 p.m. on April 12, 2012.
The meeting will be held at the Hyatt Regency Bethesda, 7400 Wisconsin Avenue, Bethesda, MD 20814.
Susan Grinder, Center for Quality Improvement and Patient Safety, AHRQ, 540 Gaither Road, Rockville, MD 20850; Telephone (toll free): (866) 403-3697; Telephone (local): (301) 427-1111; TTY (toll free): (866) 438-7231; TTY (local): (301) 427-1130; Email:
If sign language interpretation or other reasonable accommodation for a disability is needed, please contact the Food and Drug Administration (FDA) Office of Equal Employment Opportunity and Disability Management at (301) 827-4840, no later than March 28, 2012.
The Patient Safety Act and Patient Safety Rule establish a framework by which doctors, hospitals, skilled nursing facilities, and other health care providers may voluntarily report information regarding patient safety events and quality of care. Information that is assembled and developed by providers for reporting to PSOs and the information received and analyzed by PSOs—called “patient safety work product”—is privileged and confidential. Patient safety work product is used to identify events, patterns of care, and unsafe conditions that increase risks and hazards to patients. Definitions and other details about PSOs and patient safety work product are included in the Patient Safety Rule.
The Patient Safety Act and Patient Safety Rule require PSOs, to the extent practical and appropriate, to collect patient safety work product from providers in a standardized manner in order to permit valid comparisons of similar cases among similar providers. The collection of patient safety work product allows the aggregation of sufficient data to identify and address underlying causal factors of patient safety problems. Both the Patient Safety Act and Patient Safety Rule, including any relevant guidance, can be accessed electronically at:
In collaboration with the interagency Federal Patient Safety Workgroup (PSWG), the National Quality Forum (NQF) and the public, AHRQ has developed Common Formats for two settings of care—acute care hospitals and skilled nursing facilities—in order to facilitate standardized data collection. The term “Common Formats” refers to the common definitions and reporting formats that allow health care providers to collect and submit standardized information regarding patient safety events. AHRQ's Common Formats include:
• Event descriptions (descriptions of patient safety events and unsafe conditions to be reported),
• Specifications for patient safety aggregate reports and individual event summaries,
• Delineation of data elements to be collected for different types of events to populate the reports,
• A user's guide and quick guide, and
• Technical specifications for electronic data collection and reporting.
AHRQ convenes the PSWG to assist AHRQ with developing and maintaining the Common Formats. The PSWG includes major health agencies within the Department of Health and Human Services (HHS)—the Centers for Disease Control and Prevention, Centers for Medicare & Medicaid Services, Food and Drug Administration, Health Resources and Services Administration, Indian Health Service, National Institutes of Health, National Library of Medicine, Office of the National Coordinator for Health Information Technology, Office of Public Health and Science, and Substance Abuse and Mental Health Services Administration—as well as the Department of Defense and Department of Veterans Affairs.
When developing Common Formats, AHRQ first reviews existing patient safety event reporting systems from a variety of health care organizations. In collaboration with the PSWG and Federal subject matter experts, AHRQ drafts and releases beta versions of the Common Formats for public review and comment.
Through a contract with AHRQ, NQF solicits feedback on the beta (and subsequent) versions of the Common Formats from private sector organizations and individuals. The NQF, a nonprofit organization that focuses on health care quality, then convenes an expert panel to review the comments received and provide feedback to AHRQ. Based upon the expert panel's feedback, AHRQ, in conjunction with the PSWG, further revises the Common Formats.
The technical specifications promote standardization of collected patient safety event information by specifying rules for data collection and submission, as well as by providing guidance for how and when to create data elements, their valid values, conditional and go-to logic, and reports. These specifications will ensure that data collected by PSOs and other entities have comparable clinical meaning.
The technical specifications also provide direction to software developers, so that the Common Formats can be implemented electronically, and to PSOs, so that the Common Formats can be submitted electronically to the PSO Privacy Protection Center (PSO PPC) for data de-identification and transmission to the Network of Patient Safety Databases (NPSD).
Most recently, AHRQ and the PSWG released the beta version of the Venous Thromboembolism (VTE) format for reporting of VTE-related patient safety events as announced in the
The Software Developer's meeting will focus on discussion of an anticipated Spring release—Hospital Common Formats 1.2—and the technical specifications, which provide direction to software developers that plan to implement the Common Formats electronically. The technical specifications are a critical component that allow for the aggregation of patient safety event data.
The technical specifications consist of the following:
• Data dictionary—defines data elements and their attributes (data element name, answer values, field length, guide for use, etc.) included in Common Formats;
• Clinical document architecture (CDA) implementation guide—provides instructions for developing a file to transmit the Common Formats Patient Safety data from the PSO to the PSO PPC using the Common Formats;
• Validation rules and errors document—specifies and defines the validation rules that will be applied to the Common Formats data elements submitted to the PSO PPC;
• Common Formats flow charts—diagrams the valid paths to complete generic and event specific formats (a complete event report);
• Local specifications—provides specifications for processing, linking and reporting on events and details specifications for reports; and
• Metadata registry—includes descriptive facts about information contained in the data dictionary to illustrate how such data corresponds with similar data elements used by other Federal agencies and standards development organizations [e.g., HL—7, International Standards Organization (ISO)].
On Thursday, April 12, 2012, the meeting will convene at 10 a.m. with an overview of the Common Formats, including the Hospital Common Formats Version 1.2 technical specifications, and next steps for upcoming Common Formats releases. AHRQ staff and contractors will review database functionality, which is available through the PSO PPC, for PSOs to generate aggregate reports with technical specifications. Finally, the meeting will review data submission both by PSOs and by vendors on behalf of a PSO. Throughout the meeting there will be interactive discussion to allow meeting participants not only to provide input, but also to respond to the input provided by others. A more specific proposed agenda will be posted before the meeting at
AHRQ requests that interested persons register with the PSO PPC on the Internet at
Prior to the meeting, AHRQ invites review of the technical specifications for Common Formats. The formats can be
A summary of the meeting will be provided upon request. If you are unable to participate in the meeting and would like a copy of the summary, please send an email to supportpsoppc.ORG and it will be sent as soon as it is available after the meeting.
In accordance with section 10(a)(2) of the Federal Advisory Committee Act (Pub. L. 92-463), and pursuant to the requirements of 42 CFR 83.15(a), the Centers for Disease Control and Prevention (CDC), announces the following meeting of the aforementioned committee:
Public Comment Times and Dates (All times are Pacific Time): 5 p.m.-6:30 p.m.,* February 28, 2012.
* Please note that the public comment periods may end before the times indicated, following the last call for comments. Members of the public who wish to provide public comments should plan to attend public comment sessions at the start times listed.
In December 2000, the President delegated responsibility for funding, staffing, and operating the Advisory Board to HHS, which subsequently delegated this authority to the CDC. NIOSH implements this responsibility for CDC. The charter was issued on August 3, 2001, renewed at appropriate intervals, and will expire on August 3, 2013.
The agenda is subject to change as priorities dictate.
In the event an individual cannot attend, written comments may be submitted in accordance with the redaction policy provided below. Any written comments received will be provided at the meeting and should be submitted to the contact person below well in advance of the meeting.
The Director, Management Analysis and Services Office, has been delegated the authority to sign
Centers for Medicare & Medicaid Services (CMS), Department of Health and Human Services (HHS).
Notice.
This notice announces six new membership appointments to the Advisory Panel on Hospital Outpatient Payment (HOP, the Panel). The six appointments to the 19 member Panel will each serve a 4-year period. Five of the new members will have terms that begin on February 1, 2012 and continuing through January 31, 2016. The sixth member's term will begin on August 1, 2012 and continuing through July 31, 2016. The purpose of the Panel is to advise the Secretary of the Department of Health and Human Services and the Administrator of the Centers for Medicare & Medicaid Services concerning the clinical integrity of the Ambulatory Payment Classification groups and their weights. The Panel also addresses and makes recommendations regarding supervision of outpatient services. The advice provided by the Panel will be considered as we prepare the annual updates for the hospital outpatient prospective payment system.
For additional information on the Panel meeting dates, agenda topics, copy of the charter, as well as updates to the Panel's activities, search our Internet Web site:
For other information regarding the Panel, contact Paula Smith, the Designated Federal Officer at CMS, Center for Medicare, Hospital and Ambulatory Policy Group, Division of Outpatient Care, 7500 Security Boulevard, Mail Stop C4-05-13, Baltimore, MD 21244-1850, phone (410) 786-4709. Information can also be obtained by contacting the CMS Advisory Committees' Information Line at 1-877-449-5659 (toll free) and (410) 786-9379 (local).
The Secretary of the Department of Health and Human Services (the Secretary) is required by section 1833(t)(9)(A) of the Social Security Act (the Act) (42 U.S.C. 1395l(t)(9)(A)) and section 222 of the Public Health Service Act (PHS Act) (42 U.S.C. 217a) to consult with an expert outside advisory panel on the clinical integrity of the Ambulatory Payment Classification groups and weights. The Advisory Panel on Hospital Outpatient Payment (HOP, the Panel) is governed by the provisions of the Federal Advisory Committee Act (FACA) (Pub. L. 92-463, as amended (5 U.S.C. Appendix 2), which sets forth standards for the formation and use of advisory panels. The Panel Charter provides that the Panel shall meet up to 3 times annually. We consider the technical advice provided by the Panel as we prepare the proposed and final rules to update the outpatient prospective payment system for the next calendar year.
The Panel shall consist of a chair and up to 19 members who are full-time employees of hospitals, hospital systems, or other Medicare providers. The Secretary or a designee selects the Panel membership based upon either self-nominations or nominations submitted by Medicare providers and other interested organizations. New appointments are made in a manner that ensures a balanced membership under the FACA guidelines.
The Panel presently consists of the following members and a Chair: (The asterisk [*] indicates a Panel member whose term expires on July 31, 2012).
• Edith Hambrick, M.D., J.D., Chair, CMS Medical Officer.
• Ruth L. Bush, M.D., M.P.H.
• Kari S. Cornicelli, C.P.A., FHFMA.
• Dawn L. Francis, M.D., M.H.S.
• Kathleen Graham, R.N., M.S.H.A.*
• David A. Halsey, M.D.
• Brian D. Kavanagh, M.D., MPH.
• Judith T. Kelly, R.H.I.T., R.H.I.A., C.C.S.
• Scott Manaker, M.D., Ph.D.
• John Marshall, CRA, RCC, CIRCC, RT(R), FAHRA.
• Jacqueline Phillips.
• Randall A. Oyer, M.D.
• Daniel J. Pothen, M.S., RHIA, CHPS.
• Gregory Przybylski, M.D.
• Marianna V. Spanaki-Varela, MD, Ph.D., M.B.A.
We published a notice in the
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The new member of the Panel with a term beginning on August 1, 2012, and continuing through July 31, 2016 is:
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This document does not impose information collection and recordkeeping requirements. Consequently, it need not be reviewed by the Office of Management and Budget under the authority of the Paperwork Reduction Act of 1995 (44 U.S.C. 35).
Section 1833(t)(9)(A) of the Act (42 U.S.C. 1395l(t)(9)(A)). The Panel is governed by the provisions of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2).
Food and Drug Administration, HHS.
Notice of public workshop.
The Food and Drug Administration (FDA) is announcing a public workshop entitled “Design and Methodology for Postmarket Surveillance Studies under Section 522 of the Federal Food, Drug and Cosmetic Act”. The purpose of the public workshop is to provide a forum for discussion among FDA, industry, governmental agencies, academia, clinicians and various stakeholders with experience in epidemiology, statistics, and biomedical research to advance the design and methodologies for medical device surveillance studies in the “postmarket” setting, i.e., after FDA premarket approval or clearance of the device and marketing of the device has begun.
The meeting will be held on March 7, 2012, from 8 a.m. to 5:30 p.m.
The meeting will be held at the FDA White Oak Campus, 10903 New Hampshire Ave., Bldg. 31, Rm 1503 (the Great Room), Silver Spring, MD 20993. For parking and security information, please visit the following Web site:
Samantha Jacobs, Center for Devices and Radiological Health, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 66, Rm. 4201C, Silver Spring, MD 20993, 301-796-6897, email:
If you need special accommodations due to a disability, please contact Susan Monahan at
The purpose of the proposed workshop is to facilitate discussion among the FDA, industry, governmental agencies, academia, clinicians, and key stakeholders with experience in epidemiology, statistics, and biomedical research in the scientific community to advance the design and methodologies for medical device surveillance studies in the postmarket setting.
This workshop is open to all interested parties. The target audience is professionals in the scientific community interested in advancing the infrastructure and methodology for postmarket surveillance studies.
We intend to discuss a large number of issues at the workshop, including, but not limited to the following:
• Regulations for postmarket surveillance studies,
• Challenges and opportunities for collaborative efforts,
• Innovative methodologies and scientific infrastructure to promote innovation,
• Role of networks, registries and observational studies,
Background information on the public workshop, registration information, the agenda, information about lodging, and other relevant information will be posted, as it becomes available, on the Internet at
In compliance with the requirement for opportunity for public comment on proposed data collection projects (section 3506(c)(2)(A) of Title 44, United States Code, as amended by the Paperwork Reduction Act of 1995, Pub. L. 104-13), the Health Resources and Services Administration (HRSA) publishes periodic summaries of proposed projects being developed for submission to the Office of Management and Budget (OMB) under the Paperwork Reduction Act of 1995. To request more information on the proposed project or to obtain a copy of the data collection plans and draft instruments, email
Comments are invited on: (a) The proposed collection of information for the proper performance of the functions of the Agency; (b) the accuracy of the Agency's estimate of the burden of the proposed collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; and (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology.
On March 23, 2010, the President signed into law the Patient Protection and Affordable Care Act of 2010 (Pub. L. 111-148), historic and transformative legislation designed to make quality, affordable health care available to all Americans, reduce costs, improve health care quality, enhance disease prevention, and strengthen the health care workforce. Through a provision authorizing the creation of the Maternal, Infant, and Early Childhood Home Visiting (MIECHV) Program, the Act responds to the diverse needs of children and families in communities at risk and provides an unprecedented opportunity for collaboration and partnership at the Federal, State and community levels to improve health and development outcomes for at-risk children through evidence-based home visiting programs. The MIECHV Program is designed: (1) To strengthen and improve the programs and activities carried out under Title V; (2) to improve coordination of services for at-risk communities; and (3) to identify and provide comprehensive services to improve outcomes for families who reside in at-risk communities.
The Social Security Act, Title V, Section 511 (42 U.S.C. 711), as amended by the Patient Protection and Affordable Care Act of 2010, requires that MIECHV grantees collect data to measure improvements for eligible families in six specified areas (referred to as “benchmark areas”) that encompass the major goals for the program. The Supplemental Information Request for the Submission of the Updated State Plan for a State Home Visiting Program (SIR), published on February 8, 2011, further listed a variety of constructs under each benchmark area for which grantees were to select and submit relevant performance measures. Per Section 511(d)(1)(B)(i) of the legislation, no later than 30 days after the end of the third year of the program, grantees are required to demonstrate improvement in at least four of the six benchmark areas. The SIR and subsequent MIECHV guidance documents for both competitive and formula grants also require that grantees report annually on the constructs under each benchmark area, as well as on demographic, service utilization, budgetary and other administrative data related to program implementation.
The proposed data collection and reporting forms were developed by an internal MIECHV workgroup in consultation with Home Visiting Model Developers and selected grantees. The data collected from the proposed forms will be used to track the grantees' progress in demonstrating improvement under each benchmark area and to provide an overall picture of the population being served. The proposed data collection forms are as follows:
Form 1—Demographic and Service Utilization Data for Enrollees and Children: This form will request data to determine the unduplicated number of participants and of participant groups by primary insurance coverage. This form will also request data on the demographic characteristics of program participants. For example, data will be
Form 2—State Performance Measures Template: Grantees have already selected relevant performance measures for the legislatively identified benchmark areas. This form provides a template for grantees to report aggregate data on their State-selected performance measures.
While there will be variation in the data collection and reporting burden to the grantees based on the number of families served and state data system capacity, the estimated average annual burden is as follows:
Email comments to
The Department of Homeland Security, U.S. Citizenship and Immigration Services (USCIS) will be submitting the following information collection request for review and clearance in accordance with the Paperwork Reduction Act of 1995. The information collection notice, OMB Control Number 1615-0049, is published in the
During this 60-day period USCIS will be evaluating whether to revise the Form N-25. Should USCIS decide to revise this form it will advise the public when it publishes the 30-day notice in the
Written comments and suggestions regarding items contained in this notice and especially with regard to the estimated public burden and associated response time should be directed to the Department of Homeland Security (DHS), USCIS, Chief, Regulatory Products Division, Clearance Office, 20 Massachusetts Avenue NW., Washington, DC 20529. Comments may also be submitted to DHS via facsimile to 202-272-0997, or via email at
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information should address one or more of the following four points:
(1) Evaluate whether the 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 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)
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If you have additional comments, suggestions, or need a copy of the information collection instrument, please visit:
We may also be contacted at: USCIS, Regulatory Management Division, 20 Massachusetts Avenue NW., Washington, DC 20529, telephone number 202-272-8377.
60-Day Notice of Information Collection Under Review: Form I-361, Affidavit of Financial Support and Intent To Petition for Legal Custody for Public Law 97-359 Amerasian.
The Department of Homeland Security, U.S. Citizenship and Immigration Services (USCIS), will be submitting the following information collection request for review and clearance in accordance with the Paperwork Reduction Act of 1995. The information collection notice is published in the
During this 60-day period, USCIS will be evaluating whether to revise the Form I-361. Should USCIS decide to revise Form I-361 we will advise the public when we publish the 30-day notice in the
Written comments and suggestions regarding items contained in this notice and especially with regard to the estimated public burden and associated response time should be directed to the Department of Homeland Security (DHS), USCIS, Chief, Regulatory Products Division, Office of the Executive Secretariat, Clearance Office, 20 Massachusetts Avenue NW., Washington, DC 20529-2020. Comments may also be submitted to DHS via facsimile to 202-272-0997, or via email at
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information should address one or more of the following four points:
(1) Evaluate whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
(2) Evaluate the accuracy of the agencies estimate of the burden of the 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, e.g., permitting electronic submission of responses.
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(2)
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If you have additional comments, suggestions, or need a copy of the information collection instrument, please visit the USCIS Web site at:
We may also be contacted at: USCIS, Regulatory Products Division, Office of the Executive Secretariat, 20 Massachusetts Avenue NW., Washington, DC 20529-2020, Telephone number 202-272-8377.
60-Day Notice of Information Collection Under Review: Forms G-1041 and G-1041A, Genealogy Index Search Request and Genealogy Records Request.
The Department of Homeland Security, U.S. Citizenship and Immigration Services (USCIS) will be submitting the following information collection request for review and clearance in accordance with the Paperwork Reduction Act of 1995. The information collection notice is published in the
During this 60 day period, USCIS will be evaluating whether to revise forms G-1041 and G-1041A. Should USCIS decide to revise forms G-1041 and G-1041A, we will advise the public when we publish the 30-day notice in the
Written comments and suggestions regarding items contained in this notice and especially with regard to the estimated public burden and associated response time should be directed to the Department of Homeland Security (DHS), USCIS, Chief, Regulatory Products Division, 20 Massachusetts Avenue NW., Washington, DC 20529-2020. Comments may also be submitted to DHS via facsimile to 202-272-8352, or via email at
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information should address one or more of the following four points:
(1) Evaluate whether the 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
(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, e.g., permitting electronic submission of responses.
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Form G-1041A—1,683 responses (electronically submitted) at 1 hour (60 minutes) per response and 823 responses (submitted by mail) at 1.08 hours (68 minutes).
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If you have additional comments, suggestions, or need a copy of the information collection instrument, please visit:
We may also be contacted at: USCIS, Regulatory Products Division, 20 Massachusetts Avenue NW., Washington, DC 20529-2020, telephone number 202-272-8377.
Fish and Wildlife Service, Interior.
Notice.
This notice advises the public that the U.S. Fish and Wildlife Service (Service) has established the Dakota Grassland Conservation Area, the 554th unit of the National Wildlife Refuge System. The Service established the Dakota Grassland Conservation Area on September 21, 2011, with the purchase of a 318.18-acre grassland easement in Walworth County, South Dakota.
A map depicting the approved Refuge boundary and other information regarding the Refuge is available on the Internet at
Nick Kaczor, Planning Team Leader, Division of Refuge Planning, USFWS, P.O. Box 25486, DFC, Denver, CO 80225.
The Service established the Dakota Grassland Conservation Area in the eastern parts of North Dakota and South Dakota, which cover all counties north and east of the Missouri River except those in the existing Dakota Tallgrass Prairie Wildlife Management Area. The Service will continue to conserve wetland and grassland resources in the conservation area, primarily through the purchase of perpetual easements from willing sellers. These wetland and grassland easements will connect and expand existing lands under conservation protection.
The area's strong and vibrant rural lifestyle, of which agriculture is the dominant land use, is one of the key components to ensuring habitat integrity and wildlife resource protection. Based on anticipated levels of landowner participation, objectives for the conservation area are to protect 240,000 acres of wetland and 1.7 million acres of critical grassland habitat. The conservation area is a landscape-scale effort to conserve populations of priority species in a highly diverse and endangered ecosystem over an area of approximately 29.6 million acres. Therefore, it is important to incorporate the elements of strategic habitat conservation (SHC) to ensure effective conservation. SHC entails strategic biological planning and conservation design, integrated conservation delivery, monitoring, and research at ecoregional scales.
This conservation area allows the Service to purchase critical wetland and grassland easements, using the acquisition authority of the Fish and Wildlife Act of 1956 (16 U.S.C. 742a-j). In response to comments received during the public review of the draft environmental assessment (EA) and land protection plan (LPP), the Service included the authority of the Migratory Bird Conservation Act of 1929 (16 U.S.C. 715-715d, 715e, 715f-r). The Federal money used to acquire conservation easements is from the Land and Water Conservation Fund Act of 1965, as amended (16 U.S.C. 460l-4 through 11; funds received under this act are derived primarily from oil and gas leases on the Outer Continental Shelf, motorboat fuel taxes, and the sale of surplus Federal property), and the sale of Federal Duck Stamps [Migratory Bird Hunting and Conservation Stamp Act (16 U.S.C. 718-718j, 48 Stat. 452)]. Additional funding to acquire lands, water, or interests for fish and wildlife conservation purposes could be identified by Congress or donated by nonprofit organizations. The purchase of easements from willing sellers will be subject to available money.
The Service has involved the public, agencies, partners, and legislators throughout the planning process for the easement program. At the beginning of the planning process, the Service initiated public involvement for the proposal to protect habitats primarily through acquisition of wetland and grassland conservation easements for management as part of the Refuge System. The Service spent time discussing the proposed project with landowners; conservation organizations; Federal, State and county governments; tribes and other interested groups and individuals. The Service held three open-house meetings on December 14, 15, and 16, 2010, at Minot, North Dakota; Jamestown, North Dakota; and Huron, South Dakota; respectively. These open houses were announced in local media.
In compliance with the National Environmental Policy Act of 1969 (42 U.S.C. 4321), the Service prepared an environmental assessment (EA) that evaluated two alternatives and their potential impacts on the project area. The Service released the draft environmental assessment (EA) and LPP on June 20, 2011, for a 30-day public review period. The draft documents were made available to Federal elected officials and agencies, State elected officials and agencies, 32 Native American tribes with aboriginal or tribal interests, local media, and other members of the public that were identified during the scoping process.
In addition, two public meetings were held, in Bismarck, North Dakota, and in Miller, South Dakota, on June 28 and 29, 2011, respectively. These meetings were announced in advance in local media. Approximately 50 landowners, citizens, and elected representatives attended the meetings. The Service received 10 letters from agencies, organizations, and other entities, and 347 general public comments. After all comments were received, they were reviewed, added to the administrative record, and incorporated into the environmental assessment (EA) if substantial.
Based on the documentation contained in the environmental assessment (EA), a Finding of No Significant Impact was signed on September 1, 2011, for the establishment of the Dakota Grassland Conservation Area.
National Indian Gaming Commission, Interior.
Notice.
The National Indian Gaming Commission (“NIGC” or “Commission”), in accordance with the Paperwork Reduction Act, is seeking reinstatement of the approval for collection of information for the following activities: (1) Compliance and enforcement under the Indian Gaming Regulatory Act (“IGRA” or “the Act”); (2) approval of Class II background investigation and tribal licenses; (3) management contract regulations; (4) National Environmental Policy Act procedures; (5) annual fees payable by Indian gaming operations; (6) issuance of certificates of self regulation to tribes for Class II gaming; (7) minimum internal control standards; and (8) facility license review. These information collections have expired.
Submit comments on or before April 16, 2012.
Comments can be mailed, faxed, or emailed to the attention of Michael Hoenig, National Indian Gaming Commission, 1441 L Street NW., Washington, DC 20005. Comments may be faxed to (202) 632-7066 (not a toll-free number). Comments may be sent electronically to
Michael Hoenig at (202) 632-7003; fax (202) 632-7066 (not toll-free numbers).
You are invited to comment on the following items:
(a) Whether the collections of information are 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 the burdens (including the hours and cost) of the proposed collections of information, including the validity of the methodologies and assumptions used;
(c) Ways to enhance the quality, utility, and clarity of the information to be collected;
(d) Ways to minimize the burdens of the collections of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other collection techniques or forms of information technology.
Comments submitted in response to this notice will be summarized and become a matter of public record.
In accordance with this provision, NIGC regulations, 25 CFR 522.2, require tribes to submit to the NIGC: (1) A copy of the gaming ordinance to be approved, including a copy of the authorizing resolution by which it was enacted by the tribal government and a request for approval of the ordinance or resolution; (2) a description of procedures the tribe will employ in conducting background
Under NIGC regulations, 25 CFR 522.3, tribes must submit any amendment to the ordinance or resolution for approval by the NIGC Chair. In this instance, the tribe must provide a copy of the authorizing resolution. The NIGC will use the information collected to approve or disapprove the ordinance or amendment.
Section 2710 of the Act requires tribes to conduct background investigations on key employees and primary management officials involved in class II and class III gaming. NIGC regulations, 25 CFR 522.4(b)(4), require a tribe's ordinance to provide that the tribe will perform background investigations and issue licenses for key employees and primary management officials according to requirements that are at least as stringent as those in NIGC regulations, 25 CFR parts 556 and 558. 25 CFR parts 556 and 558 require tribes to perform each investigation using information such as name, address, previous employment records, previous relationships with either Indian tribes or the gaming industry, licensing relating to those relationships, any convictions, and any other information a tribe feels is relevant to the employment of the individuals being investigated. 25 CFR 556.4. Tribes are then required to submit to the NIGC a copy of the completed employment applications and investigative reports and licensing eligibility determinations on key employees or primary management officials before issuing gaming licenses to those persons. 25 CFR 556.5. The NIGC uses this information to review the eligibility and suitability determinations tribes make and advises them if it disagrees with any particular determination.
Under NIGC regulations, 25 CFR part 533, the Chair requires the submission of the contract to contain the following: original signatures; any collateral agreements to the contract; a tribal ordinance or resolution authorizing the submission and supporting documentation; a three-year business plan which sets forth the parties' goals, objectives, budgets, financial plans, related matters, income statements, sources and use of funds statements for the previous three years; and, for any contract exceeding five years or which includes a management fee of more than 30 percent, justification that the capital investment required and income projections for the gaming operation require the longer duration or the additional fee.
Under NIGC regulations, 25 CFR part 535, the Chair may approve a modification to a management contract or an assignment of that management contract based on information similar to that required under part 533. Part 535 also specifies that the Chair may void a previous management contract approval and allows the parties the opportunity to submit information relevant to that determination.
25 CFR part 537 specifies the requirements for submission of background information in amplification of the statutory requirement for obtaining information on persons and entities having a direct financial interest in or management responsibility for a management contract. Finally, 25 CFR part 539 permits appeals to the Commission from a decision of the Chair to disapprove a management contract and allows the Indian tribe and the management company an opportunity to provide information relevant to that appeal. The NIGC will use the information collected to either approve or disapprove the contract or, in the case of an appeal, to grant or deny the appeal.
Those tribes who have been issued a certificate of self-regulation are required to submit annually a report to the NIGC. Such report shall set forth information to establish that the tribe has continuously met the eligibility requirements of 25 CFR 518.2 and the approval requirements of 25 CFR 518.4 and shall include a report with supporting documentation which explains how tribal gaming revenues were used in accordance with the requirements of IGRA, 25 U.S.C. 2710(b)(2)(B).
NIGC regulations, part 559 requires that a tribe submit a notice to the NIGC that it is considering issuing a facility license, including applicable Indian lands information, at least 120 days before a new class II and/or class III gaming facility is opened. The amount of Indian lands information depends, in part, on whether the Bureau of Indian Affairs maintains the necessary records. The Indian lands information will continue to be utilized by the NIGC to ensure that its records are complete for internal purposes, such as assessing the NIGC's jurisdiction to regulate the gaming on the parcel, as well as responding to inquiries from government agencies and Congress as to the statuses of lands where Indian gaming is proposed or occurring.
Part 559 also requires that tribes submit copies of each newly issued or renewed facility license to the NIGC within 30 days of issuance, as well as notices of facility closures. This information will enable the NIGC to maintain accurate, up-to-date records of the Indian gaming facilities that are operating on Indian lands in the United States at any given point in time. Currently, facility licenses must be renewed every three years. With each new facility license, the Tribe must submit an attestation that it has identified and enforces environment and public health and safety laws and that the tribe is in compliance with those laws. Part 559 also requires tribes to submit a document listing all environmental and public safety laws, resolutions, codes, policies and standards applicable to its gaming facility. If the submitted laws, resolutions, etc. do not change, the tribe need only certify that fact when submitting a renewed facility license. Finally, the NIGC Chair has the discretion to request environmental and public health and safety documentation on occasions when there is an identified, substantial concern. Through these submissions, the NIGC can ensure that the tribes have determined that the construction, maintenance, and operation of their gaming facilities are conducted in a manner that adequately protects the environment and the public health and safety.
This information collection serves two purposes: (i) to receive up-to-date information from tribes regarding the number of licensed Indian gaming facilities and the Indian lands status of the site of each gaming facility; and (ii) to obtain certifications from the tribes that the construction, maintenance, and operation of the gaming facilities are conducted in a manner that adequately protects the environment and the public health and safety.
Bureau of Reclamation, Interior.
Notice and request for comments.
The Bureau of Reclamation intends to seek an extension of the information collection for the Lower Colorado River Well Inventory (1006-0014). The current OMB approval expires on May 31, 2012.
Submit comments on this notice by April 16, 2012.
Send all written comments concerning this notice to Paul Matuska, Water Accounting and Verification Group Manager, LC-4200, Bureau of Reclamation, Lower Colorado Regional Office, P.O. Box 61470, Boulder City, NV 89006-1470; or by email to
Paul Matuska, Water Accounting and Verification Group Manager, Bureau of Reclamation, Lower Colorado Regional Office, 702-293-8164.
In accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.), this notice announces that the Bureau of Reclamation is requesting approval for the collection of data from well and river-pump owners and operators along the lower Colorado River in Arizona, California, and Nevada.
Comments are invited on:
(a) Whether the proposed collection of information is necessary for the proper performance of our functions, including whether the information will have practical use;
(b) The accuracy of our burden estimate for the proposed collection of information;
(c) Ways to enhance the quality, usefulness, and clarity of the information to be collected; and
(d) Ways to minimize the burden of the collection of information on respondents, including the use of automated collection techniques or other forms of information technology.
We will summarize all comments received regarding this notice. We will publish that summary in the
Before including your address, telephone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment—including your personal identifying information—may be made publicly available at any time. While you can ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.
Bureau of Reclamation, Interior.
Notice of public meeting.
The Glen Canyon Dam Adaptive Management Work Group (AMWG) makes recommendations to the Secretary of the Interior concerning Glen Canyon Dam operations and other management actions to protect resources downstream of Glen Canyon Dam, consistent with the Grand Canyon Protection Act. The AMWG meets two to three times a year.
The meeting will be held on Wednesday, February 22, 2012, from 9:30 a.m. to approximately 5:30 p.m., and Thursday, February 23, 2012, from 8 a.m. to approximately 3 p.m.
The meeting will be held at the Fiesta Resort Conference Center, 2100 S. Priest Drive, Tempe, Arizona.
Glen Knowles, Bureau of Reclamation, telephone (801) 524-3781; facsimile (801) 524-3858; email at
The Glen Canyon Dam Adaptive Management Program (AMP) was implemented as a result of the Record of Decision on the Operation of Glen Canyon Dam Final Environmental Impact Statement to comply with consultation requirements of the Grand Canyon Protection Act (Pub. L. 102-575) of 1992. The AMP includes a Federal advisory committee, the AMWG, a technical work group (TWG), a Grand Canyon Monitoring and Research Center, and independent review panels. The TWG is a subcommittee of the AMWG and provides technical advice and recommendations to the AMWG.
To view a copy of the agenda and documents related to the above meeting, please visit Reclamation's Web site at
Before including your name, address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment—including your personal identifying information—may be made publicly available at any time. While you can ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.
Notice is hereby given that, on January 26, 2012, 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 PXI Systems Alliance, Inc. intends to file additional written notifications disclosing all changes in membership.
On November 22, 2000, PXI Systems Alliance, Inc. 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 November 22, 2011. A notice was published in the
Notice is hereby given that, on January 27, 2012, pursuant to Section 6(a) of the National Cooperative Research and Production Act of 1993, 15 U.S.C. 4301
Also, Q-Lambda, Lund, Sweden; Exlar Corporation, Chanhassen, MN; Spang Power Electronics, Mentor, OH; and ASCO Pneumatic Controls, Florham Park, NJ, 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 November 1, 2011. A notice was published in the
Notice is hereby given that, on January 27, 2012, 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 Pistoia Alliance, Inc. intends to file additional written notifications disclosing all changes in membership.
On May 28, 2009, Pistoia Alliance, Inc. 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 November 3, 2011. A notice was published in the
Notice is hereby given that, on January 26, 2012, 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 Interchangeable Virtual Instruments Foundation, Inc. intends to file additional written notifications disclosing all changes in membership.
On May 29, 2001, Interchangeable Virtual Instruments Foundation, Inc. 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 November 22, 2011. A notice was published in the
The Foreign Claims Settlement Commission, pursuant to its regulations (45 CFR part 503.25) and the Government in the Sunshine Act (5 U.S.C. 552b), hereby gives notice in regard to the scheduling of open meetings as follows:
All meetings are held at the Foreign Claims Settlement Commission, 600 E Street NW., Washington, DC. Requests for information, or advance notices of intention to observe an open meeting, may be directed to: Judith H. Lock, Executive Officer, Foreign Claims Settlement Commission, 600 E Street NW., Suite 6002, Washington, DC 20579. Telephone: (202) 616-6975.
The Bureau of International Labor Affairs, United States Department of Labor.
Notice: Request for information and invitation to comment.
This notice is a request for information and/or comment on reports issued by the Bureau of International Labor Affairs (ILAB) October 3, 2011, regarding child labor and forced labor in foreign countries. Relevant information will be used by the Department of Labor (DOL) in preparation of its ongoing reporting under Congressional mandates and Presidential directive. In addition, ILAB may use relevant information to conduct assessments of each country's individual progress towards eliminating the worst forms of child labor during the current reporting period compared to previous years.
Submitters of information are requested to provide their submission to the Office of Child Labor, Forced Labor and Human Trafficking (OCFT) at the email or physical address below by 5 p.m. March 9, 2012.
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The portal includes instructions for submitting comments. Parties submitting responses electronically are encouraged not to submit paper copies.
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Tina McCarter (see contact information above).
I. Section 105(b)(1) of the Trafficking Victims Protection Reauthorization Act of 2005 (“TVPRA of 2005”), Public Law 109-164 (2006), directed the Secretary of Labor, acting through ILAB, to “develop and make available to the public a list of goods from countries that the Bureau of International Labor Affairs has reason to believe are produced by forced labor or child labor in violation of international standards” (TVPRA List).
Pursuant to this mandate, in December 2007 DOL published in the
ILAB released its first TVPRA List on September 30, 2009, an update on December 10, 2010 and another update on October 3, 2011. This List is updated periodically as additional countries and territories are researched and new information for countries and territories already reviewed is evaluated. For a copy of the 2011 TVPRA report, Frequently Asked Questions, and other materials relating to the TVPRA List, see ILAB's TVPRA Web page at:
II. Executive Order No. 13126 (E.O. 13126) declared that it was “the policy of the United States Government * * * that the executive agencies shall take appropriate actions to enforce the laws prohibiting the manufacture or importation of goods, wares, articles, and merchandise mined, produced, or manufactured wholly or in part by forced or indentured child labor.” Pursuant to E.O. 13126, and following public notice and comment, the Department of Labor published in the January 18, 2001,
Pursuant to Sections D through G of the Procedural Guidelines, the EO List may be updated through consideration of submissions by individuals or through OCFT's own initiative.
DOL has officially revised the EO List twice, on July 20, 2010 and May 31, 2011, each time after public notice and comment as well as consultation with DOS and DHS. In addition, DOL published an initial determination on October 4, 2011 proposing another revision to the EO List and requesting public comment (76 FR 61384).
The current EO List, Procedural Guidelines, and related information can be accessed on the Internet at
III. The Trade and Development Act of 2000 (TDA), Public Law 106-200 (2002), established a new eligibility criterion for receipt of trade benefits under the Generalized System of Preferences (GSP), Caribbean Basin Trade and Partnership Act (CBTPA), and Africa Growth and Opportunity Act (AGOA). The TDA amends the GSP reporting requirements of Section 504 of the Trade Act of 1974, 19 U.S.C. 2464, to require that the President's annual report on the status of internationally recognized worker rights include “findings by the Secretary of Labor with respect to the beneficiary country's implementation of its international commitments to eliminate the worst forms of child labor.” Title II of the TDA and the TDA Conference Report, Joint Explanatory Statement of the Committee of Conference, 106th Cong.2d.Sess. (2000), indicate that the same criterion applies for the receipt of benefits under CBTPA and AGOA, respectively.
In addition, the Andean Trade Preference Act, as amended and expanded by the Andean Trade Promotion and Drug Eradication Act, Public Law 107-210, Title XXXI (2002), includes as a criterion for receiving benefits “[w]hether the country has implemented its commitments to eliminate the worst forms of child labor as defined in section 507(6) of the Trade Act of 1974.” DOL fulfills these reporting mandates through annual publication of the U.S. Department of Labor's Findings on the Worst Forms of Child Labor with respect to countries eligible for the aforementioned programs. The 2010 report and additional background information are available on the Internet at
This notice is a general solicitation of comments from the public.
Mine Safety and Health Administration, Labor.
Notice.
Section 101(c) of the Federal Mine Safety and Health Act of 1977 and 30 CFR Part 44 govern the application, processing, and disposition of petitions for modification. This notice is a summary of petitions for modification submitted to the Mine Safety and Health Administration (MSHA) by the parties listed below to modify the application of existing mandatory safety standards codified in Title 30 of the Code of Federal Regulations.
All comments on the petitions must be received by the Office of Standards, Regulations, and Variances on or before March 19, 2012.
You may submit your comments, identified by “docket number” on the subject line, by any of the following methods:
1.
2.
3.
4.
MSHA will consider only comments postmarked by the U.S. Postal Service or proof of delivery from another delivery service such as UPS or Federal Express on or before the deadline for comments.
Barbara Barron, Office of Standards, Regulations, and Variances at 202-693-9447 (Voice),
Section 101(c) of the Federal Mine Safety and Health Act of 1977 (Mine Act) allows the mine operator or representative of miners to file a petition to modify the application of any mandatory safety standard to a coal or other mine if the Secretary of Labor determines that:
(1) An alternative method of achieving the result of such standard exists which will at all times guarantee no less than the same measure of protection afforded the miners of such mine by such standard; or
(2) That the application of such standard to such mine will result in a diminution of safety to the miners in such mine.
In addition, the regulations at 30 CFR 44.10 and 44.11 establish the requirements and procedures for filing petitions for modification.
(1) Equivalent permissible equipment does not exist.
(2) Equivalent non-electronic surveying equipment is obsolete technology and new replacement equipment does not exist; replacement parts and reconditioned equipment are becoming increasingly unavailable.
(3) The continued use of obsolete and worn or reconditioned equipment that may be inaccurate will result in a diminution of safety in that surveys will become increasingly inaccurate which could result in:
(a) The development of entries that are not straight and true.
(b) Pillar sizes that may become compromised.
(c) The location of mine workings that may be inaccurate, creating reduced barrier pillar sizes when approaching old workings and outcrops.
(4) In the alternative to compliance with the existing standard, the petitioner proposes the following:
(a) Non-permissible surveying equipment will be used only when equivalent permissible equipment does not exist.
(b) All non-permissible surveying equipment will be limited to:
(i) Topcon Electronic Total Station Model GTS-233W 7.2 volts d.c.
(ii) Topcon Electronic Total Station Model GTS-235W 7.2 volts d.c.
(iii) Topcon Electronic Total Station Model GTS-211D 7.2 volts d.c.
(iv) Nikon Total Station Nivo Series Model Nivo 2.C 3.8 volts d.c.
(v) Nikon DTM-302 Series Model DTM-352 7.2 volts d.c.
(vi) Spectra Precision Nomad Data Collector 5.0 volts d.c.
(vii) Equivalent equipment with equal or lower voltages.
(c) All non-permissible surveying equipment used in or inby the last open crosscut or in a return airway will be examined by a qualified person, as defined in 30 CFR 75.153, at least weekly to ensure that the equipment is being maintained in a safe operating condition. The results of the inspection will be recorded and the record will be retained for one year and made available for review by MSHA upon request.
(d) All non-permissible surveying equipment to be used in or inby the last open crosscut or in a return airway will be examined in fresh air outby the last open crosscut prior to being used to ensure that the equipment is being maintained in a safe operating condition. The examination will include:
(i) Checking the instrument for any physical damage and the integrity of the case.
(ii) Powering-up and shutting-down the instrument to ensure proper operation.
(iii) Checking the battery compartment cover to ensure that it is securely fastened.
(e) A qualified person, as defined in 30 CFR 75.151, will continuously monitor for methane immediately before and during the use of non-permissible surveying equipment in or inby the last open crosscut or in a return airway.
(f) Non-permissible surveying equipment will not be used if methane is detected at or above 1.0 percent. When 1.0 percent or more methane is detected while the non-permissible surveying equipment is being used, the equipment will be deenergized immediately and withdrawn outby the last open crosscut or out of a return airway.
(g) All hand-held methane detectors will be MSHA-approved and maintained in permissible and proper operating condition as defined in 30 CFR 75.320.
(h) Non-permissible surveying equipment will not be used when coal production is occurring in the entry being surveyed unless it is necessary for the surveying.
(i) Batteries contained in the non-permissible surveying equipment will be changed out or charged in intake air outby the last open crosscut.
(j) Personnel who use the non-permissible surveying equipment will be trained to recognize the hazards and limitations associated with its use.
(k) The non-permissible surveying equipment will not be put into service until MSHA has initially inspected the equipment and determined that it is in compliance with all of the terms and conditions in this petition.
(l) Within 60 days after this petition becomes final, the petitioner will submit proposed revisions for its approved 30 CFR part 48 training plan to the District Manager. The revisions will specify initial and refresher training regarding the terms and conditions in this petition.
The petitioner asserts that the proposed alternative method will at all times guarantee no less than the same measure of protection as that afforded by the existing standard.
(1) Application of the existing standard would result in a diminution of safety to the miners.
(2) Underground mining, by its nature, size, complexity, and relative closeness to other abandoned mines, gas/oil wells, and other features,
(3) The use of currently available non-electronic equipment is less accurate and less dependable than the available electronic equipment and requires more exposure of surveyors to hazardous mining environments. As an alternative to compliance with the existing standard, the petitioner proposes the following:
(a) To examine all non-permissible electronic surveying equipment prior to use in or inby the last open crosscut to ensure that the equipment is being maintained in a safe operating condition, and have a qualified person, as defined in 30 CFR 75.153, examine the equipment at intervals not to exceed 7 days. The examination results will be recorded in the weekly examination of electrical equipment book. The examinations will include:
(i) Checks of the instrument for any physical damage and the integrity of the case.
(ii) Removal of the battery and an inspection for corrosion and damage.
(iii) Inspection of the contact points to ensure a secure connection to the battery.
(iv) Reinsertion of the battery and a power-up and shut-down of the instrument to ensure proper connections.
(v) Checks of the battery compartment cover to ensure that it is securely fastened.
(b) A qualified person, as defined in 30 CFR 75.151, will continuously monitor for methane immediately before and during the use of non-permissible surveying equipment in or inby the last open crosscut or in the return.
(c) Non-permissible surveying equipment will not be used if methane is detected in concentrations at or above 1.0 percent. When 1.0 percent or more of methane is detected while the non-permissible surveying equipment is being used, the equipment will be deenergized immediately and the non-permissible electronic equipment will be withdrawn out of the return.
(d) Non-permissible surveying equipment will not be used in areas where float coal dust is in suspension.
(e) Batteries contained in the surveying equipment will be changed out or charged in fresh air and not in the return.
(f) Qualified personnel who use the surveying equipment will be properly trained to recognize the hazards and limitations associated with the use of non-permissible surveying equipment.
(g) The non-permissible surveying equipment will not be put into service until MSHA has initially inspected the equipment and determined that it is in compliance with the terms and conditions in this petition.
(h) Within 60 days after the Proposed Decision and Order becomes final, the petitioner will submit proposed revisions for its approved 30 CFR Part 48 training plan to the District Manager. These proposed revisions will specify initial and refresher training regarding the terms and conditions stated in the Proposed Decision and Order.
The petitioner further states that the nature of work at times will require that surveying services that would be covered by this petition be provided on short notice and, therefore, does not want the petitions to apply to specific companies or mines. The petitioner states that the list of companies and mines in this petition is not all-inclusive.
The petitioner asserts that the proposed alternative method will at all times guarantee no less than the same measure of protection afforded by the existing standard.
(1) Application of the existing standard would result in a diminution of safety to the miners.
(2) Underground mining, by its nature, size, complexity, and relative closeness to other abandoned mines, gas/oil wells, and other features, requires that accurate and precise measurements be completed in a prompt and efficient manner.
(3) The use of currently available non-electronic equipment is less accurate and less dependable than the available electronic equipment and requires more exposure of surveyors to hazardous mining environments. As an alternative to compliance with the existing standard, the petitioner proposes the following:
(a) To examine all non-permissible electronic surveying equipment prior to use in or inby the last open crosscut to ensure that the equipment is being maintained in a safe operating condition, and have a qualified person, as defined in 30 CFR 75.153, examine the equipment at intervals not to exceed 7 days. The examination results will be recorded in the weekly examination of electrical equipment book. The examinations will include:
(i) Checks of the instrument for any physical damage and the integrity of the case.
(ii) Removal of the battery and an inspection for corrosion and damage.
(iii) Inspection of the contact points to ensure a secure connection to the battery.
(iv) Reinsertion of the battery and a power-up and shut-down of the instrument to ensure proper connections.
(v) Checks of the battery compartment cover to ensure that it is securely fastened.
(b) A qualified person, as defined in 30 CFR 75.151, will continuously monitor for methane immediately before and during the use of non-permissible surveying equipment in or inby the last open crosscut or in the return.
(c) Non-permissible surveying equipment will not be used if methane is detected in concentrations at or above 1.0 percent. When 1.0 percent or more of methane is detected while the non-permissible surveying equipment is being used, the equipment will be deenergized immediately and the non-permissible electronic equipment will be withdrawn out of the return.
(d) Non-permissible surveying equipment will not be used in areas where float coal dust is in suspension.
(e) Batteries contained in the surveying equipment will be changed out or charged in fresh air and not in the return.
(f) Qualified personnel who use the surveying equipment will be properly trained to recognize the hazards and limitations associated with the use of non-permissible surveying equipment.
(g) The non-permissible surveying equipment will not be put into service until MSHA has initially inspected the equipment and determined that it is in compliance with the terms and conditions in this petition.
(h) Within 60 days after the Proposed Decision and Order becomes final, the petitioner will submit proposed revisions for its approved 30 CFR Part 48 training plan to the District Manager. These proposed revisions will specify initial and refresher training regarding the terms and conditions stated in the Proposed Decision and Order.
The petitioner further states that the nature of work at times will require that surveying services that would be covered by this petition be provided on short notice and, therefore, does not want the petitions to apply to specific companies or mines. The petitioner states that the list of companies and mines in this petition is not all-inclusive.
The petitioner asserts that the proposed alternative method will at all times guarantee no less than the same measure of protection afforded by the existing standard.
(1) Application of the existing standard would result in a diminution of safety to the miners.
(2) Underground mining, by its nature, size, complexity, and relative closeness to other abandoned mines, gas/oil wells, and other features, requires that accurate and precise measurements be completed in a prompt and efficient manner.
(3) The use of currently available non-electronic equipment is less accurate and less dependable than the available electronic equipment and requires more exposure of surveyors to hazardous mining environments. As an alternative to compliance with the existing standard, the petitioner proposes the following:
(a) To examine all non-permissible electronic surveying equipment prior to use in or inby the last open crosscut to ensure the equipment is being maintained in a safe operating condition, and have a qualified person, as defined in 30 CFR 75.153, examine the equipment at intervals not to exceed 7 days. The examination results will be recorded in the weekly examination of electrical equipment book. The examinations will include:
(i) Checks of the instrument for any physical damage and the integrity of the case.
(ii) Removal of the battery and an inspection for corrosion and damage.
(iii) Inspection of the contact points to ensure a secure connection to the battery.
(iv) Reinsertion of the battery and a power-up and shut-down of the instrument to ensure proper connections.
(v) Checks of the battery compartment cover to ensure that it is securely fastened.
(b) A qualified person, as defined in 30 CFR 75.151, will continuously monitor for methane immediately before and during the use of non-permissible surveying equipment in or inby the last open crosscut or in the return.
(c) Non-permissible surveying equipment will not be used if methane is detected in concentrations at or above 1.0 percent. When 1.0 percent or more of methane is detected while the non-permissible surveying equipment is being used, the equipment will be deenergized immediately and the non-permissible electronic equipment will be withdrawn out of the return.
(d) Non-permissible surveying equipment will not be used in areas where float coal dust is in suspension.
(e) Batteries contained in the surveying equipment will be changed out or charged in fresh air and not in the return.
(f) Qualified personnel who use the surveying equipment will be properly trained to recognize the hazards and limitations associated with the use of non-permissible surveying equipment.
(g) The non-permissible surveying equipment will not be put into service until MSHA has initially inspected the equipment and determined that it is in compliance with the terms and conditions in this petition.
(h) Within 60 days after the Proposed Decision and Order becomes final, the petitioner will submit proposed revisions for its approved 30 CFR Part 48 training plan to the District Manager. These proposed revisions will specify initial and refresher training regarding
The petitioner further states that the nature of work at times will require that surveying services that would be covered by this petition be provided on short notice and, therefore, does not want the petitions to apply to specific companies or mines. The petitioner states that the list of companies and mines in this petition is not all-inclusive.
The petitioner asserts that the proposed alternative method will at all times guarantee no less than the same measure of protection afforded by the existing standard.
(1) The Tennant Sweeper is operated only on paved flat roads within the surface mine property.
(2) The sweeper primarily operates with use of a hydraulic system. When the foot is taken off the accelerator the sweeper stops.
(3) The back brakes are currently inoperable and the unit is so old that the parts are hard to obtain to fix the system.
(4) The sweeper has a functional front braking system capable of stopping and holding the vehicle with a full load on the steepest incline it travels.
(5) The sweeper is operated only on day shift, only travels on dry roads and dusty days when the roads are not wet or slippery, and is put up for the winter.
(6) The sweeper is not capable of traveling over 5 miles per hour. It is generally run between 3 and 5 miles per hour within the plant. The standard on brakes requires at least 10 miles per hour to test the brakes, and the sweeper cannot go that fast.
(7) The sweeper has a fully functional parking brake system capable of holding the machine with a full load on the steepest incline it travels.
(8) The unit is not being supported by Tennant, the manufacturer.
(9) Any spare parts that can be obtained will no longer be produced once they are used up.
(10) What is available to fix the unit has been ordered, and the unit is needed to comply with environmental regulations.
As an alternative, the petitioner proposes to rely on the hydraulic system, the front brake system, and the parking brake to stop and hold the equipment with its typical load on the maximum grade it travels.
The petitioner asserts that the proposed alternative method will at all times guarantee the miners no less than the same measure of protection as provided by the existing standard.
National Science Foundation.
Submission for OMB Review; Comment Request.
The National Science Foundation (NSF) has submitted the following information collection requirement to OMB for review and clearance under the Paperwork Reduction Act of 1995, Public Law 104-13. This is the second notice for public comment; the first was published in the
Suzanne H. Plimpton at (703) 292-7556 or send email to
NSF 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.
ERCs conduct world-class research with an engineered systems perspective that integrates materials, devices, processes, components, control algorithms and/or other enabling elements to perform a well-defined function. These systems provide a unique academic research and education experience that involves integrative complexity and
ERCs enable and foster excellent education, integrate research and education, speed knowledge/technology transfer through partnerships between academe and industry, and prepare a more competitive future workforce. ERCs capitalize on diversity through participation in center activities and demonstrate leadership in the involvement of groups underrepresented in science and engineering.
Centers will be required to submit annual reports on progress and plans, which will be used as a basis for performance review and determining the level of continued funding. To support this review and the management of a Center, ERCs will also be required to submit management and performance indicators annually to NSF via a data collection Web site that is managed by a technical assistance contractor. These indicators are both quantitative and descriptive and may include, for example, the characteristics of center personnel and students; sources of cash and in-kind support; expenditures by operational component; characteristics of industrial and/or other sector participation; research activities; education activities; knowledge transfer activities; patents, licenses; publications; degrees granted to students involved in Center activities; descriptions of significant advances and other outcomes of the ERC effort. Such reporting requirements will be included in the cooperative agreement which is binding between the academic institution and the NSF.
Each Center's annual report will address the following categories of activities: (1) Vision and impact, (2) strategic plan, (3) research program, (4) innovation ecosystem and industrial collaboration, (5) education, (6) infrastructure (leadership, management, facilities, diversity) and (7) budget issues.
For each of the categories the report will describe overall objectives for the year, progress toward center goals, problems the Center has encountered in making progress towards goals and how they were overcome, plans for the future and anticipated research and other barriers to overcome in the following year, and specific outputs and outcomes.
U.S. Nuclear Regulatory Commission.
Notice of public meeting.
The U.S. Nuclear Regulatory Commission (NRC), Office of Nuclear Regulatory Research (RES), in cooperation with the Electric Power Research Institute (EPRI), will hold a joint workshop on the Treatment of Probabilistic Risk Assessment (PRA) Uncertainties. Since 2002, RES and EPRI, under a Memorandum of Understanding (MOU) on Cooperative Nuclear Safety Research, have been developing state-of-the-art methods for conduct of PRA.
The purpose of the workshop is to bring together experts to gain a better understanding of the sources of uncertainty, how they manifest in the PRA, and their potential significance to the PRA model and results. More specifically, the workshop will address uncertainties associated with risk assessments for internal fires, seismic events, low power and shutdown (LPSD) conditions, and for the Level 2 portion of PRAs.
Wednesday, February 29, 2012 (8:30 a.m.-5 p.m.);
Thursday, March 1, 2012 (8:30 a.m.—12:30 p.m.)
The Legacy Hotel & Meeting Centre; 1775 Rockville Pike; Rockville, Maryland 20852.
Because of limited available space, attendees are asked to pre-register (there is not a registration fee) as soon as possible. There will be the ability to call-in to the workshop. Please contact Matt Dennis, Sandia National Laboratories, at 505-284-0781, email:
Mary T. Drouin, Sr. Program Manager, Performance and Reliability Branch, Division of Risk Analysis, Office of Nuclear Regulatory Research, United States Nuclear Regulatory Commission, Tel: 301-251-7574, Email:
This meeting is a Category 3 meeting.*
* Meetings between the NRC technical staff and external stakeholders are open for interested members of the public, petitioners, interveners, or other parties to attend as observers pursuant to Commission policy statement, “Enhancing Public Participation in NRC Meetings,” (67 FR 36920; May 28, 2002).
The NRC provides reasonable accommodation to individuals with disabilities where appropriate. If you need a reasonable accommodation to participate in this workshop, or need the workshop notice or agenda in another format (e.g., Braille, large print), please notify the NRC is meeting contact. Determinations on requests for reasonable accommodation will be made on a case-by-case basis.
For the Nuclear Regulatory Commission.
In the Matter of USEC INC. (American Centrifuge Lead Cascade Facility and American Centrifuge Plant); Order EA-12-
USEC Inc., (USEC) is the holder of materials licenses SNM-7003 and SNM-2011 for the American Centrifuge Lead Cascade Facility (Lead Cascade) and American Centrifuge Plant (ACP), respectively, which authorize the licensee to: (1) Possess and use source and special nuclear material at the Lead Cascade at the former Portsmouth Gaseous Diffusion Plant site in Piketon, Ohio, in accordance with materials license number SNM-7003; and (2) construct and operate a gas centrifuge uranium enrichment facility (the ACP) at the former Portsmouth Gaseous Diffusion Plant site in Piketon, Ohio, in accordance with materials license number SNM-2011.
The U.S. Nuclear Regulatory Commission's (NRC) Order EA-11-013, dated February 10, 2011, approved the direct transfer of the licenses of the above facilities from USEC to the limited liability company American Centrifuge Operating, LLC (ACO), pursuant to Sections 161(b), 161(i), 161(o) and 184 of the Atomic Energy Act, as amended; 42 United States Code (U.S.C.) 2201(b), 2201(i), and 2234; and Title 10 of the
By letter dated January 6, 2012, and supplemented by letter dated January 27, 2012, USEC submitted a request to extend the date by which the license transfers must be completed from February 9, 2012, to February 8, 2013. USEC stated that Condition 3 of Order EA-11-013 will be satisfied following completion of actions with the DOE, without any linkage to the loan guarantee. In its January 27, 2012, letter, USEC stated that due to uncertainty, it appears that the date for completion of activities associated with the sub-lease will extend beyond May 18, 2012. Accordingly, USEC stated that it will not be able to fully implement the conditions in Order EA-11-013 by February 9, 2012, and is requesting a second extension to Order EA-11-013.
USEC states that there have been no changes in the information and technical and financial qualifications presented in its September 10, 2010, request to transfer the licenses (Agencywide Documents Access and Management System (ADAMS) Accession No. ML102660371). The NRC staff notes that its basis for approving the transfers of USEC's licenses for the Lead Cascade and the ACP from USEC to ACO is documented in its safety evaluation report (SER, ADAMS Accession No. ML103630748) supporting the February 10, 2011, Order.
The NRC staff reviewed the information provided by USEC in its September 10, 2010, transfer of licenses request, the information provided in its July 22, 2011, first extension request (ADAMS Accession No. ML11210B497), and supplemental electronic communication dated August 1, 2011 (ADAMS Accession No. ML11213A282), and the information provided in its January 6, 2012, second extension request, and supplemental letter dated January 27, 2012. Based on this review of the information provided by USEC, the NRC staff concludes that the basis for originally approving the transfers of USEC's licenses for the Lead Cascade and the ACP from USEC to ACO remains valid. The NRC staff evaluated the January 6, 2012, submittal and the January 27, 2012, supplemental letter and determined that USEC has shown good cause to extend the implementation period of Order EA-11-013 a second time and, therefore, the implementation date for Order EA-11-013 should be extended to February 8, 2013, the date by which the transfer of licenses must be completed.
Accordingly, pursuant to Sections 161b, 161i, 161o, and 184 of the Atomic Energy Act of 1954, as amended, 42 U.S.C. 2201(b), 2201(i), and 2234; and 10 CFR 30.34(b), 10 CFR 40.46, “Inalienability of Licenses,” and 10 CFR 70.36, “Inalienability of Licenses,”
This Order is effective upon issuance. The Order of February 10, 2011, as modified by the August 8, 2011, Order and this Order, remains in full force and effect.
For further details with respect to this Order, see the submittal dated January 6, 2012 (ADAMS Accession No. ML11210B497), the supplemental letter dated January 27, 2012 (ADAMS Accession No. ML12032A279), and the SER documenting NRC's staff evaluation of USEC's submittal dated February 8, 2012 (ADAMS Accession No. ML12027A034), which may be examined—and/or copied for a fee—at the NRC's Public Document Room, located at One White Flint North, 11555 Rockville Pike (First Floor), Rockville, MD 20852; and accessible online in the NRC Library at
For the U.S. Nuclear Regulatory Commission.
On December 14, 2011, the Chicago Board Options Exchange, Incorporated (“Exchange”) filed with the Securities and Exchange Commission (“Commission”), pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The proposed rule change was published for comment in the
After careful review, the Commission finds that the proposed rule change is consistent with the requirements of the Act and the rules and regulations thereunder applicable to a national securities exchange
It is therefore ordered, pursuant to Section 19(b)(2) of the Act,
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (the “Act”)
CBOE proposes to amend its Fees Schedule to establish fees for transactions in options on the CBOE Emerging Market ETF Volatility Index (“VXEEM”), the CBOE Brazil ETF Volatility Index (“VXEWZ”) and the CBOE Crude Oil ETF Volatility Index (“OVX”). The text of the proposed rule change is available on the Exchange's Web site (
In its filing with the Commission, the self-regulatory organization included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of those statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant parts of such statements.
The Exchange received approval to list and trade options on the CBOE Emerging Market ETF Volatility Index (“VXEEM”), the CBOE Brazil ETF Volatility Index (“VXEWZ”) and the CBOE Crude Oil ETF Volatility Index (“OVX”) (collectively herein, “volatility indexes”), which are up-to-the-minute market estimates of the expected volatility of their corresponding exchange-traded funds (“ETF”)
The purpose of this rule change is to clarify that the existing transaction fees for “Volatility Indexes” shall apply for transactions in VXEEM options, VXEWZ options and OVX options except that the existing Surcharge Fee (currently $.10 per contract for Volatility Index options) will not apply to VXEEM options, VXEWZ options and OVX options.
For reference, the existing Volatility Index transactions fees that will apply
• $0.40 per contract for customer transactions;
• $0.40 per contract for voluntary professional transactions;
• $0.40 per contract for professional transactions
• $0.20 per contract for CBOE Market-Maker/DPM transactions;
• $0.25 per contract for Clearing Trading Permit Holder proprietary transactions;
• $0.40 per contract for broker-dealer transactions;
• $0.10 per contract CFLEX Surcharge Fee;
$0.03 per contract floor brokerage fee;
• $0.015 per contract floor brokerage fee for crossed orders;
• $0.03 per contract par official fee;
• $0.015 per contract for par official fee for crossed orders.
The Exchange believes the proposed rule change is consistent with Section 6(b) of the Act,
The Exchange is excluding VXEEM, VXEWZ and OVX options from the Index License/Surcharge Fee of $0.10 per contract because that fee is assessed to help the Exchange recoup license fees that the Exchange pays to different index licensors in order to list options on the respective indexes. The Exchange does not pay fees to index licensors to list VXEEM, VXEWZ and OVX options. The Exchange is assessing a Product Research & Development/Surcharge fee to all non-public customer transactions (
The Exchange believes that the fees are reasonable because they are comparable to fees that the Exchange currently assesses for another similar volatility index option,
The Exchange believes that the fees are equitable and do not unfairly discriminate because they provide comparable pricing among similar categories of market participants. The Exchange believes that a fee of $0.20 per contract for CBOE Market-Maker/DPM transactions is equitable since those market participants provide a valuable market service by adding liquidity to the Exchange and since they are subject to liquidity provider obligations. This standard rate is not subject to the Liquidity Provider Sliding Scale as set forth in Footnote 10 to the Fees Schedule. The Exchange also believes that a fee of $0.25 per contract for Clearing Trading Permit Holders is equitable since they contribute capital to facilitate customer orders, which in turn provides a deeper pool of liquidity that benefits all market participants.
CBOE does not believe that the proposed rule change will impose any burden on competition not necessary or appropriate in furtherance of the purposes of the Act.
No written comments were solicited or received with respect to the proposed rule change.
The proposed rule change is designated by the Exchange as establishing or changing a due, fee, or other charge, thereby qualifying for effectiveness on filing pursuant to Section 19(b)(3)(A) of the Act
At any time within 60 days of the filing of the proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act.
Interested persons are invited to submit written data, views and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Elizabeth M. Murphy, Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The Exchange proposes to amend the NYSE Arca Equities Fee Schedule (“Fee Schedule”) to increase the indication of interest (“IOI”) Tier 1 credit and the Tracking Order Tier 1 credit for ETP Holders and Market Makers. The text of the proposed rule change is available at the Exchange, the Commission's Public Reference Room, and
In its filing with the Commission, the self-regulatory organization included statements concerning the purpose of, and basis for, the proposed rule change and discussed any comments it received on the proposed rule change. The text of those statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant parts of such statements.
The Exchange proposes to amend the Fee Schedule to increase the IOI Tier 1 credit
Currently, an IOI Tier 1 credit is offered to each ETP Holder and Market Maker that send IOIs to the Exchange resulting in executions with an average daily share volume (“ADV”) per month greater than or equal to 10 million shares in Tape A, B, and C securities. The credit is $0.0012 per share for each share up to and including 15 million shares and $0.0015 per share for each share in excess of 15 million shares.
The Exchange proposes to amend the IOI Tier 1 credit so that each ETP Holder and Market Maker will receive a credit of $0.0015 per share for all shares if its IOIs result in executions on the Exchange with an ADV per month greater than 15 million shares. The Exchange will continue to provide a $0.0012 credit per share for IOIs sent to the Exchange resulting in executions with an ADV per month up to and including 15 million shares (assuming the 10 million share threshold is met).
For example, under the current Fee Schedule, if an ETP Holder sends IOIs to the Exchange resulting in executions with an ADV per month of 17 million shares, the ETP Holder receives a $0.0012 per share credit for the first 15 million shares and a $0.0015 per share credit for the 2 million shares in excess of the 15 million shares. Under the proposed Fee Schedule, the ETP Holder will receive a $0.0015 per share credit for all 17 million shares.
Currently, the Tracking Order Tier 1 credit is offered to each ETP Holder and Market Maker that sends Tracking Orders to the Exchange resulting in executions with an ADV per month greater than or equal to 5 million shares in Tape A, B, and C securities.
The Exchange proposes to amend the Tracking Order Tier 1 credit so that each ETP Holder and Market Maker will receive a credit of $0.0015 per share for all shares if its Tracking Orders result in executions on the Exchange with an ADV per month greater than 15 million shares. The Exchange will continue to credit ETP Holders $0.0012 per share for Tracking Orders that result in executions up to and including 15 million shares (assuming the 5 million share threshold is met).
For example, under the current Fee Schedule, if an ETP Holder sends Tracking Orders to the Exchange resulting in executions with an ADV per month of 17 million shares, the ETP Holder receives a $0.0012 per share credit for the first 15 million shares and a $0.0015 per share credit for the remaining 2 million shares. Under the proposed Fee Schedule, the ETP Holder will receive a $0.0015 per share credit for all 17 million shares.
The Exchange believes that the proposed rule change is consistent with Section 6(b) of the Securities Exchange Act of 1934 (the “Act”),
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act.
No written comments were solicited or received with respect to the proposed rule change.
The foregoing rule change is effective upon filing pursuant to Section 19(b)(3)(A)
At any time within 60 days of the filing of such proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Elizabeth M. Murphy, Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The Exchange proposes to amend the NYSE Arca Equities Fee Schedule (“Fee Schedule”) to increase the Investor Tier 1 credit for ETP Holders and Market Makers. The text of the proposed rule change is available at the Exchange, the Commission's Public Reference Room, and
In its filing with the Commission, the self-regulatory organization included statements concerning the purpose of, and basis for, the proposed rule change and discussed any comments it received on the proposed rule change. The text of those statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant parts of such statements.
The Exchange proposes to amend the Fee Schedule to increase the Investor
Currently, the Investor Tier 1 allows customers to earn a credit of $0.0032 per share for executed orders that provide liquidity to the Book for Tape A, Tape B and Tape C securities when they meet all of the following criteria on a monthly basis:
• Maintain a ratio of cancelled orders to total orders of less than 30%. In calculating this ratio, the Exchange will exclude Immediate-or-Cancel orders, which are liquidity removing in nature.
• Maintain a ratio of executed liquidity adding volume to total volume of greater than 80%.
• Firms must add liquidity that represents 0.45% or more of the total US average daily consolidated share volume (“ADV”) per month (volume on days when the market closes early is excluded from the calculation of ADV).
For example, if US ADV is 8.5 billion shares in a given month, the minimum adding ADV requirement for Investor Tier 1 would be 38.25 million adding shares a day.
The Exchange proposes to amend the Investor Tier 1 credit so that each ETP Holder and Market Maker will receive a credit of $0.0033 per share for orders that provide liquidity to the Book when they meet the above criteria on a monthly basis.
The Exchange believes that the proposed rule change is consistent with Section 6(b) of the Securities Exchange Act of 1934 (the “Act”),
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act.
No written comments were solicited or received with respect to the proposed rule change.
The foregoing rule change is effective upon filing pursuant to Section 19(b)(3)(A)
At any time within 60 days of the filing of such proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Elizabeth M. Murphy, Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (the “Act”),
The Exchange is filing with the Commission a proposal to amend Rule 11.23 entitled “Auctions” to allow orders designated to participate in the opening auction on the Exchange (“Opening Auction”) to participate in an auction in the initial public offering (“IPO”) for a security on the Exchange (“IPO Auction”).
The text of the proposed rule change is available at the Exchange's Web site at
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in Sections A, B, and C below, of the most significant parts of such statements.
The Exchange recently proposed and received approval of rules governing auctions conducted on the Exchange for securities listed on the Exchange (“Exchange Auctions”).
Specifically, the Exchange proposes to amend several portions of Rule 11.23 to allow MOO, LOO, and LLOO orders to participate in IPO Auctions. Under the proposal, MOO orders would behave like market orders participating in an IPO Auction currently behave. LOO and LLOO orders would behave like limit orders participating in an IPO Auction currently behave. In order to effect the change, the Exchange proposes to amend the definition of Eligible Auction Orders for IPO Auctions to include those orders designated to exclusively participate in the Opening Auction. The Exchange also proposes modifications to the definitions of MOO, LOO, and LLOO orders and to make clear that these Opening Auction orders that are not executed as part of the IPO Auction would be cancelled immediately following the IPO Auction, exactly as currently occurs in the Opening Auction.
The Exchange believes that its proposal is consistent with the requirements of the Act and the rules and regulations thereunder that are applicable to a national securities exchange, and, in particular, with the requirements of Section 6(b) of the Act.
The Exchange does not believe that the proposed rule change imposes any burden on competition.
The Exchange has neither solicited nor received written comments on the proposed rule change.
Because the foregoing proposed rule change does not: (i) Significantly affect the protection of investors or the public interest; (ii) impose any significant burden on competition; and (iii) become operative for 30 days from the date on which it was filed, or such shorter time as the Commission may designate, it has become effective pursuant to Section 19(b)(3)(A) of the Act
A proposed rule change filed under 19b-4(f)(6) normally may not become operative prior to 30 days after the date of filing.
At any time within 60 days of the filing of the proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is 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.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act” or “Exchange Act”)
The Exchange proposes to list and trade the following under NYSE Arca Equities Rule 8.600 (“Managed Fund Shares”): PIMCO Global Advantage Inflation-Linked Bond Strategy Fund. The text of the proposed rule change is available at the Exchange, the Commission's Public Reference Room, and
In its filing with the Commission, the self-regulatory organization included statements concerning the purpose of, and basis for, the proposed rule change and discussed any comments it received on the proposed rule change. The text of those statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant parts of such statements.
The Exchange proposes to list and trade the following Managed Fund Shares
The investment manager to the Fund is Pacific Investment Management Company LLC (“PIMCO” or “Adviser”). PIMCO Investments LLC serves as the distributor for the Fund (“Distributor”). State Street Bank & Trust Co. serves as the custodian and transfer agent for the Fund (“Custodian” or “Transfer Agent”).
Commentary .06 to Rule 8.600 provides that, if the investment adviser to the investment company issuing Managed Fund Shares is affiliated with a broker-dealer, such investment adviser shall erect a “fire wall” between the investment adviser and the broker-dealer with respect to access to information concerning the composition and/or changes to such investment company portfolio.
According to the Registration Statement, the Fund seeks total return which exceeds that of its benchmark indexes, consistent with prudent investment management. The Fund's primary benchmark index is the Barclays Capital Universal Government Inflation-Linked Bond Index. The Fund's secondary benchmark index is the PIMCO Global Advantage Inflation-Linked Bond Index.
The Fund seeks to achieve its investment objective by investing under normal circumstances
According to the Registration Statement, inflation-linked bonds are government-issued fixed income securities that are structured to provide protection against inflation. The value of the bond's principal or the interest income paid on the bond is adjusted to track changes in an official inflation measure. The effective duration of the Fund's portfolio normally varies within two years (plus or minus) of the effective duration of the PIMCO Global Advantage Inflation-Linked Bond Index which, as of September 30, 2011, as converted, was 4.53 years. Duration is a measure used to determine the sensitivity of a security's price to changes in interest rates. The longer a security's duration, the more sensitive it will be to changes in interest rates. Effective duration takes into account that, for certain bonds, expected cash flows will fluctuate as interest rates change and will be defined in nominal yield terms, which is market convention for most bond investors and managers. Because market convention for bonds is to use nominal yields to measure duration, duration for inflation-linked
The Fund will invest under normal circumstances at least 80% of its assets in inflation-linked bonds issued by U.S. or foreign governments (or any political subdivision, agency, authority or instrumentality of such government).
The Fund primarily will invest in debt securities rated Baa or higher by Moody's Investors Service, Inc., or equivalently rated by Standard & Poor's Ratings Services or Fitch, Inc., or, if unrated, determined by PIMCO to be of comparable quality.
The Fund's portfolio holdings will be disclosed on the Trust's Web site (
As disclosed in the Trust's Registration Statement, if PIMCO believes that economic or market conditions are unfavorable to investors, PIMCO may temporarily invest up to 100% of the Fund's assets in certain defensive strategies, including holding a substantial portion of the Fund's assets in cash, cash equivalents or other highly rated short-term securities, including securities issued or guaranteed by the U.S. government, its agencies or instrumentalities and affiliated money market and/or short-term bond funds.
The Fund may invest in, to the extent permitted by Section 12(d)(1) of the 1940 Act and rules thereunder, other affiliated and unaffiliated funds, such as open-end or closed-end management investment companies, including other exchange traded funds.
The Fund may enter into foreign currency transactions (such as currency forwards).
The Fund may hold in the aggregate up to 15% of its net assets in: (1) Illiquid securities,
With respect to its equity securities investments, the Fund will invest only in U.S.-registered equity securities and non-U.S.-registered equity securities that trade in markets that are members of the Intermarket Surveillance Group (“ISG”) or are parties to a comprehensive surveillance sharing agreement with the Exchange.
The Fund is subject to the following investment limitations:
The Fund may not concentrate its investments in a particular industry, as that term is used in the 1940 Act,
The Fund will be non-diversified,
The Fund intends to qualify annually and elect to be treated as a regulated investment company under Subchapter M of the Internal Revenue Code.
Consistent with the Exemptive Order, the Fund will not invest in options contracts, futures contracts or swap agreements.
The Fund's investments will be consistent with the Fund's investment objective and will not be used to enhance leverage. That is, while the Fund will be permitted to borrow as permitted under the 1940 Act, the Fund's investments will not be used to seek performance that is the multiple or inverse multiple (
The Shares will conform to the initial and continued listing criteria under NYSE Arca Equities Rule 8.600. The Exchange represents that, for initial and/or continued listing, the Fund will be in compliance with Rule 10A-3 under the Exchange Act,
According to the Registration Statement, Shares of the Fund that trade in the secondary market will be “created” at NAV
Except when aggregated in Creation Units, Shares will not be redeemable by the Fund. The prices at which creations and redemptions occur will be based on the next calculation of NAV after an order is received. Requirements as to the timing and form of orders are described in the Authorized Participant agreement. PIMCO will make available on each business day via the National Securities Clearing Corporation (“NSCC”) or other method of public dissemination, prior to the opening of business (subject to amendments) on the Exchange (currently 9:30 a.m. E.T.), the identity and the required amount of each Deposit Security and the amount of the Cash Component (or Cash Deposit) to be included in the current Fund Deposit
Additional information regarding the Trust and the Shares, including investment strategies, risks, creation and redemption procedures, fees, portfolio holdings, disclosure policies, distributions and taxes is included in the Registration Statement. All terms relating to the Fund that are referred to but not defined in this proposed rule change are defined in the Registration Statement.
The Trust's Web site (
On a daily basis, the Adviser will disclose for each portfolio security or other financial instrument of the Fund the following information: Ticker symbol (if applicable), name of security or financial instrument, number of shares or dollar value of financial instruments held in the portfolio, and percentage weighting of the security or financial instrument in the portfolio. The Web site information will be publicly available at no charge. In addition, price information for the debt
In addition, a basket composition file, which will include the security names and share quantities, if applicable, required to be delivered in exchange for Fund Shares, together with estimates and actual cash components, will be publicly disseminated daily prior to the opening of the NYSE via the NSCC. The basket represents one Creation Unit of the Fund. The NAV of the Fund will normally be determined as of the close of the regular trading session on the NYSE (ordinarily 4 p.m. E.T.) on each business day. Authorized Participants may refer to the basket composition file for information regarding Fixed Income Instruments, inflation-linked bonds and any other instrument that may comprise the Fund's basket on a given day.
Investors can also obtain the Trust's Statement of Additional Information (“SAI”), the Fund's Shareholder Reports, and its Form N-CSR and Form N-SAR, filed twice a year. The Trust's SAI and Shareholder Reports are available free upon request from the Trust, and those documents and the Form N-CSR and Form N-SAR may be viewed on-screen or downloaded from the Commission's Web site at
With respect to trading halts, the Exchange may consider all relevant factors in exercising its discretion to halt or suspend trading in the Shares of the Fund.
The Exchange deems the Shares to be equity securities, thus rendering trading in the Shares subject to the Exchange's existing rules governing the trading of equity securities. Shares will trade on the NYSE Arca Marketplace from 4 a.m. to 8 p.m. E.T. in accordance with NYSE Arca Equities Rule 7.34 (Opening, Core, and Late Trading Sessions). The Exchange has appropriate rules to facilitate transactions in the Shares during all trading sessions. As provided in NYSE Arca Equities Rule 7.6, Commentary .03, the minimum price variation (“MPV”) for quoting and entry of orders in equity securities traded on the NYSE Arca Marketplace is $0.01, with the exception of securities that are priced less than $1.00 for which the MPV for order entry is $0.0001.
The Exchange intends to utilize its existing surveillance procedures applicable to derivative products (which include Managed Fund Shares) to monitor trading in the Shares. The Exchange represents that these procedures are adequate to properly monitor Exchange trading of the Shares in all trading sessions and to deter and detect violations of Exchange rules and applicable federal securities laws.
The Exchange's current trading surveillance focuses on detecting securities trading outside their normal patterns. When such situations are detected, surveillance analysis follows and investigations are opened, where appropriate, to review the behavior of all relevant parties for all relevant trading violations.
The Exchange may obtain information via the ISG from other exchanges that are members of ISG or with which the Exchange has in place a comprehensive surveillance sharing agreement.
In addition, the Exchange also has a general policy prohibiting the distribution of material, non-public information by its employees.
Prior to the commencement of trading, the Exchange will inform its Equity Trading Permit (“ETP”) Holders in an Information Bulletin (“Bulletin”) of the special characteristics and risks associated with trading the Shares. Specifically, the Bulletin will discuss the following: (1) The procedures for purchases and redemptions of Shares in Creation Unit aggregations (and that Shares are not individually redeemable); (2) NYSE Arca Equities Rule 9.2(a), which imposes a duty of due diligence on its ETP Holders to learn the essential facts relating to every customer prior to trading the Shares; (3) the risks involved in trading the Shares during the Opening and Late Trading Sessions when an updated Portfolio Indicative Value will not be calculated or publicly disseminated; (4) how information regarding the Portfolio Indicative Value is disseminated; (5) the requirement that ETP Holders deliver a prospectus to investors purchasing newly issued Shares prior to or concurrently with the confirmation of a transaction; and (6) trading information.
In addition, the Bulletin will reference that the Fund is subject to various fees and expenses described in the Registration Statement. The Bulletin will discuss any exemptive, no-action, and interpretive relief granted by the Commission from any rules under the Exchange Act. The Bulletin will also disclose that the NAV for the Shares will be calculated after 4:00 p.m. E.T. each trading day.
The basis under the Exchange Act for this proposed rule change is the requirement under Section 6(b)(5)
The Exchange believes that the proposed rule change is designed to prevent fraudulent and manipulative acts and practices in that the Shares will be listed and traded on the Exchange pursuant to the initial and continued listing criteria in NYSE Arca Equities Rule 8.600. The Exchange has in place surveillance procedures that are adequate to properly monitor trading in the Shares in all trading sessions and to deter and detect violations of Exchange rules and applicable federal securities laws. The Exchange may obtain information via ISG from other exchanges that are members of ISG or with which the Exchange has entered into a comprehensive surveillance sharing agreement. According to the Registration Statement, the Fund will invest under normal circumstances at least 80% of its assets in inflation-linked bonds issued by U.S. or foreign governments, screened for minimum liquidity levels. The Fund primarily will invest in debt securities rated Baa or higher by Moody's Investors Service, Inc., or equivalently rated by Standard & Poor's Ratings Services or Fitch, Inc., or, if unrated, determined by PIMCO to be of comparable quality. The Adviser is affiliated with a broker-dealer and has implemented a “fire wall” with respect to such broker-dealer regarding access to information concerning the composition and/or changes to the Fund's portfolio. In addition, the Fund will implement and maintain, or be subject to, procedures designed to prevent the use and dissemination of material non-public information regarding the Fund's portfolio holdings. Consistent with the Exemptive Order, the Fund will not invest in options contracts, futures contracts or swap agreements. The Fund's investments will be consistent with the Fund's investment objective and will not be used to enhance leverage. That is, while the Fund will be permitted to borrow as permitted under the 1940 Act, the Fund's investments will not be used to seek performance that is the multiple or inverse multiple (
The proposed rule change is designed to promote just and equitable principles of trade and to protect investors and the public interest in that the Exchange will obtain a representation from the issuer of the Shares that the NAV per Share will be calculated daily and that the NAV and the Disclosed Portfolio will be made available to all market participants at the same time. In addition, a large amount of information is publicly available regarding the Fund and the Shares, thereby promoting market transparency. The Fund's portfolio holdings will be disclosed on the Trust's Web site daily after the close of trading on the Exchange and prior to the opening of trading on the Exchange the following day. Moreover, the Portfolio Indicative Value will be widely disseminated by one or more major market data vendors at least every 15 seconds during the Exchange's Core Trading Session. On each business day, before commencement of trading in Shares in the Core Trading Session on the Exchange, the Fund will disclose on the Trust's Web site the Disclosed Portfolio that will form the basis for the Fund's calculation of NAV at the end of the business day. Information regarding market price and trading volume of the Shares will be continually available on a real-time basis throughout the day on brokers' computer screens and other electronic services, and quotation and last sale information will be available via the CTA high-speed line. The Trust's Web site will include a form of the prospectus for the Fund and additional data relating to NAV and other applicable quantitative information. Moreover, prior to the commencement of trading, the Exchange will inform its ETP Holders in an Information Bulletin of the special characteristics and risks associated with trading the Shares. Trading in Shares of the Fund will be halted if the circuit breaker parameters in NYSE Arca Equities Rule 7.12 have been reached or because of market conditions or for reasons that, in the view of the Exchange, make trading in the Shares inadvisable, and trading in the Shares will be subject to NYSE Arca Equities Rule 8.600(d)(2)(D), which sets forth circumstances under which Shares of the Fund may be halted. In addition, as noted above, investors will have ready access to information regarding the Fund's holdings, the Portfolio Indicative Value, the Disclosed Portfolio, and quotation and last sale information for the Shares.
The proposed rule change is designed to perfect the mechanism of a free and open market and, in general, to protect investors and the public interest in that it will facilitate the listing and trading of an additional type of actively-managed exchange-traded product that will enhance competition among market participants, to the benefit of investors and the marketplace. As noted above, the Exchange has in place surveillance procedures relating to trading in the Shares and may obtain information via ISG from other exchanges that are members of ISG or with which the Exchange has entered into a comprehensive surveillance sharing agreement. In addition, as noted above, investors will have ready access to information regarding the Fund's holdings, the Portfolio Indicative Value, the Disclosed Portfolio, and quotation and last sale information for the Shares.
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.
Within 45 days of the date of publication of this notice in the
(A) By order approve or disapprove such proposed rule change, or
(B) Institute proceedings to determine whether the proposed rule change should be disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Elizabeth M. Murphy, Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
On December 15, 2011, NYSE Amex LLC (“NYSE Amex” or “Exchange”) filed with the Securities and Exchange Commission (“Commission”), pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
Certain securities listed on Nasdaq may be traded on NYSE Amex pursuant to a grant of unlisted trading privileges as part of a pilot program on the Exchange (“UTP Pilot Program”).
Currently, under NYSE Amex Equities Rule 509(a)(1), DMM units who are registered in securities subject to the UTP Pilot Program must maintain continuous two-sided quotes at the National Best Bid or Offer (“NBBO”) with reasonable size for each such security for at least 10% of the time during the regular business hours of the Exchange for each calendar month.
The Exchange also proposes to delete from NYSE Amex Equities Rule 504(b)(1)(A) the text that references NYSE Amex Equities Rule 103B(II), which provides for security allocation eligibility. The Exchange represented that this reference is not necessary within Rule 504(b)(1)(A), and that, despite the proposed deletion, DMM units would remain subject to NYSE Amex Equities Rule 103B(II) with respect to security allocation eligibility.
After careful review, the Commission finds that the proposed rule change is consistent with the requirements of the Act and the rules and regulations thereunder that are applicable to a national securities exchange, and, in particular, with the requirements of Section 6(b) of the Act.
The Exchange proposes to reduce DMM units' quoting obligations applicable to “more active” securities traded in the UTP Pilot Program to quoting at the NBBO for 5% of the trading day. The Commission notes that this percentage would reflect the quoting requirement currently applicable to DMM units quoting non-UTP Pilot Program securities,
The Commission also finds that the proposed deletion in NYSE Amex Equities Rule 504(b)(1)(A) to the reference to NYSE Amex Equities Rule 103B(II) is consistent with the Act. The Exchange represented that this reference is not necessary within Rule 504(b)(1)(A), and that, despite the proposed deletion, DMM units would remain subject to NYSE Amex Equities Rule 103B(II) with respect to security allocation eligibility.
For the foregoing reasons, the Commission finds that the proposal to amend the UTP Pilot Program is consistent with the requirements of the Act.
It is therefore ordered, pursuant to Section 19(b)(2) of the Act,
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The Exchange proposes to amend the NYSE Arca Options Fee Schedule (“Fee Schedule”) to increase the Post Liquidity credits on Customer posted electronic executions and to delete references to Royalty Fees for foreign currency options, which the Exchange no longer trades. The text of the proposed rule change is available at the Exchange, the Commission's Public Reference Room, and
In its filing with the Commission, the self-regulatory organization included statements concerning the purpose of, and basis for, the proposed rule change and discussed any comments it received on the proposed rule change. The text of those statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant parts of such statements.
The Exchange proposes to amend the Fee Schedule to increase the Post Liquidity credits on Customer posted electronic executions and to delete references to Royalty Fees for foreign currency options, which the Exchange no longer trades. The Exchange proposes to make the rule change operative on February 1, 2012.
Electronic transactions in Penny Pilot issues
The Exchange proposes to amend the volume thresholds for the Post Liquidity credits by lowering the initial volume threshold to qualify for the first level of higher Post Liquidity credits, generally raising the amount of the Post Liquidity
The current Fee Schedule sets forth Royalty Fees for certain foreign currency options. Because the Exchange no longer trades foreign currency options, it proposes to delete references to such Royalty Fees.
The Exchange believes that the proposed rule change is consistent with Section 6(b) of the Securities Exchange Act of 1934 (the “Act”)
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act.
No written comments were solicited or received with respect to the proposed rule change.
The foregoing rule change is effective upon filing pursuant to Section 19(b)(3)(A)
At any time within 60 days of the filing of such proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Elizabeth M. Murphy, Secretary,
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”),
The NASDAQ Stock Market LLC proposes to amend NASDAQ Rule 3020 to reflect recent changes to a corresponding rule of the Financial Industry Regulatory Authority (“FINRA”).
The text of the proposed rule change is available on the Exchange's Web site at
In its filing with the Commission, the Exchange included statements concerning the purpose of, and basis for, the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
Many of NASDAQ's rules are based on rules of FINRA (formerly the National Association of Securities Dealers (“NASD”)). Beginning in 2008, FINRA embarked on an extended process of moving rules formerly designated as “NASD Rules” into a consolidated FINRA rulebook. In most cases, FINRA has renumbered these rules, and in some cases has substantively amended them. Accordingly, NASDAQ also has initiated a process of modifying its rulebook to ensure that NASDAQ rules corresponding to FINRA/NASD rules continue to mirror them as closely as practicable.
This proposed rule change concerns NASDAQ Rule 3020 entitled “Fidelity Bonds,” which follows and incorporates by reference former NASD Rule 3020.
NASD Rule 3020(a) generally provides that each member required to join the Securities Investor Protection Corporation (“SIPC”) that has employees and that is not a member in good standing of one of the enumerated national securities exchanges must maintain fidelity bond coverage. FINRA Rule 4360 requires each member that is required to join SIPC to maintain blanket fidelity bond coverage with specified amounts of coverage based on the member's net capital requirement, with certain exceptions. NASD Rule 3020(a)(1) requires members to maintain a blanket fidelity bond in a form substantially similar to the standard form of Brokers Blanket Bond promulgated by the Surety Association of America. New FINRA Rule 4360 requires members to maintain fidelity bond coverage that provides for per loss coverage without an aggregate limit of liability. Also, pursuant to FINRA Rule 4360, a member's fidelity bond must provide against loss and have Insuring Agreements covering at least the following: Fidelity, on premises, in transit, forgery and alteration, securities and counterfeit currency. The rule change modified the descriptive headings for these Insuring Agreements, in part, from NASD Rule 3020(a)(1) and NYSE Rule 319(d) to align them with the headings in the current bond forms available to broker-dealers. FINRA Rule 4360 also eliminates the specific coverage provisions in NASD Rule
Further, FINRA Rule 4360 requires that a member's fidelity bond include a cancellation rider providing that the insurer will use its best efforts to promptly notify FINRA in the event the bond is cancelled, terminated or “substantially modified.” Also, the rule change adopted the definition of “substantially modified” in NYSE Rule 319 and would incorporate NYSE Rule 319.12's standard that a firm must immediately advise FINRA in writing if its fidelity bond is cancelled, terminated or substantially modified.
FINRA Rule 4360 requires each member to maintain, at a minimum, fidelity bond coverage for any person associated with the member, except directors or trustees of a member who are not performing acts within the scope of the usual duties of an officer or employee. As further detailed below, the rule change eliminated the exemption in NASD Rule 3020 for sole stockholders and sole proprietors. The rule change also increased the minimum required fidelity bond coverage for members, while continuing to base the coverage on a member's net capital requirement. To that end, FINRA Rule 4360 required a member with a net capital requirement that is less than $250,000 to maintain minimum coverage of the greater of 120 percent of the firm's required net capital under Exchange Act Rule 15c3-1 or $100,000. The increase to $100,000 modifies the present minimum requirement of $25,000.
Under the new FINRA Rule 4360, members with a net capital requirement of at least $250,000 must use a table in the rule to determine their minimum fidelity bond coverage requirement. The table is a modified version of the tables in NASD Rule 3020(a)(3) and NYSE Rule 319(e)(i). The identical NASD and NYSE requirements for members that have a minimum net capital requirement that exceeds $1 million are retained in the new Rule; however, the rule adopts the higher requirements in NYSE Rule 319(e)(i) for a member with a net capital requirement of at least $250,000, but less than $1 million. Under the new rule, the entire amount of a member's minimum required coverage must be available for covered losses and may not be eroded by the costs an insurer may incur if it chooses to defend a claim. Specifically, any defense costs for covered losses must be in addition to a member's minimum coverage requirements. A member may include defense costs as part of its fidelity bond coverage, but only to the extent that it does not reduce a member's minimum required coverage under the rule.
Under prior NASD Rule 3020(b), a deductible provision may be included in a member's bond of up to $5,000 or 10% of the member's minimum insurance requirement, whichever is greater. If a member desires to maintain coverage in excess of the minimum insurance requirement, then a deductible provision may be included in the bond of up to $5,000 or 10% of the amount of blanket coverage provided in the bond purchased, whichever is greater. The excess of any such deductible amount over the maximum permissible deductible amount based on the member's minimum required coverage must be deducted from the member's net worth in the calculation of the member's net capital for purposes of Exchange Act Rule 15c3-1. Where the member is a subsidiary of another member, the excess may be deducted from the parent's rather than the subsidiary's net worth, but only if the parent guarantees the subsidiary's net capital in writing.
Consistent with NASD Rule 3020(c) and NYSE Rule 319.10, FINRA Rule 4360 requires a member (including a firm that signs a multi-year insurance policy), annually as of the yearly anniversary date of the issuance of the fidelity bond, to review the adequacy of its fidelity bond coverage and make any required adjustments to its coverage, as set forth in the rule. Under FINRA Rule 4360(d), a member's highest net capital requirement during the preceding 12-month period, based on the applicable method of computing net capital (dollar minimum, aggregate indebtedness or alternative standard), is used as the basis for determining the member's minimum required fidelity bond coverage for the succeeding 12-month period. The “preceding 12-month period” includes the 12-month period that ends 60 days before the yearly anniversary date of a member's fidelity bond. This would give a firm time to determine its required fidelity bond coverage by the anniversary date of the bond.
Further, FINRA Rule 4360 allows a member that has only been in business for one year and elected the aggregate indebtedness ratio for calculating its net capital requirement to use, solely for the purpose of determining the adequacy of its fidelity bond coverage for its second year, the 15 to 1 ratio of aggregate indebtedness to net capital in lieu of the 8 to 1 ratio (required for broker-dealers
Based in part on NASD Rule 3020(a), FINRA Rule 4360 exempts from the fidelity bond requirements members in good standing with a national securities exchange that maintain a fidelity bond subject to the requirements of such exchange that are equal to or greater than the requirements set forth in Rule 4360. Additionally, consistent with NYSE Rule Interpretation 319/01, FINRA Rule 4360 continues to exempt from the fidelity bond requirements any firm that acts solely as a Designated Market Maker (“DMM”),
The Exchange believes that its proposal is consistent with Section 6(b) of the Act
The Exchange does not believe that the proposed rule change will impose any burden on competition not necessary or appropriate in furtherance of the purposes of the Act.
No written comments were either solicited or received.
Because the foregoing proposed rule change does not: (i) Significantly affect the protection of investors or the public interest; (ii) impose any significant burden on competition; and (iii) become operative for 30 days after the date of the filing, or such shorter time as the Commission may designate, it has become effective pursuant to 19(b)(3)(A) of the Act
The Exchange has requested that the Commission waive the 30-day operative delay. The Commission believes that waiver of the operative delay is consistent with the protection of investors and the public interest because the proposed rule change presents no novel issues, and NASDAQ members are currently subject to FINRA Rule 4360. Therefore, the Commission designates the proposal operative upon filing.
At any time within 60 days of the filing of the proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Elizabeth M. Murphy, Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for Web site viewing and printing in the Commission's Public Reference Room, 100 F Street NE., Washington, DC 20549, on official business days between the hours of 10
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”),
The Exchange proposes to amend an existing rebate relating to Qualified Contingent Cross (“QCC”) orders that are entered and executed through the Exchange systems. The text of the proposed rule change is available at the Exchange, the Commission's Public Reference Room, and
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 proposal is to increase a rebate for Floor Brokers who enter QCC orders that subsequently execute.
The rebate is credited to the executing Floor Broker. The Exchange notes that the terms of a QCC order are negotiated and agreed to prior to being brought to an exchange for possible execution. In bringing a QCC order to the Exchange for execution, permit holders have two primary means of doing so. They can configure their systems to deliver the QCC order to the Exchange matching engines for validation and execution. Alternatively they can utilize the services of another ATP Holder acting as a Floor Broker. In turn, the Floor Broker who is in receipt of such an order can enter the order through an Exchange-provided system
The Exchange believes that the proposed rule change is consistent with the provisions of Section 6(b)
The Exchange believes the proposed increase from $.03 per contract to $.07 per contract rebate for Floor Brokers who enter QCC orders that execute is reasonable because it will allow Floor Brokers the opportunity to compete for QCC orders that would otherwise be
The Exchange believes the proposal to increase the rebate from $.03 per contract to a $.07 per contract is equitable and not unfairly discriminatory because it would uniformly apply to all QCC orders entered by a Floor Broker for validation by the system and potential execution, excepting Customer-to-Customer QCC trades. The exclusion of Customer-to-Customer QCC trades from the Floor Broker rebate will remain.
For the reasons noted above, the Exchange believes that the proposed fees are fair, equitable and not unfairly discriminatory.
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act.
No written comments were solicited or received with respect to the proposed rule change.
The foregoing rule change is effective upon filing pursuant to Section 19(b)(3)(A)
At any time within 60 days of the filing of such proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Elizabeth M. Murphy, Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Notice of request for public comment and submission to OMB of proposed collection of information.
The Department of State has submitted the following information collection request to the Office of Management and Budget (OMB) for approval in accordance with the Paperwork Reduction Act of 1995.
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Submit comments to the Office of Management and Budget (OMB) for up to 30 days from February 16, 2012.
Direct comments to the Department of State Desk Officer in the Office of Information and Regulatory Affairs at the Office of Management and Budget (OMB). You may submit comments by the following methods:
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You may obtain copies of the proposed information collection and supporting documents from Passport Services, Passport Forms Management and Officer, U.S. Department of State, Office of Program Management and Operational Support, 2201 C Street NW., Washington, DC 20520, who may be reached on 202-663-2457 or at
We are soliciting public comments to permit the Department to:
• Evaluate whether the proposed information collection is necessary to properly perform our functions.
• Evaluate the accuracy of our estimate of the burden of the proposed collection, including the validity of the methodology and assumptions used.
• Enhance the quality, utility, and clarity of the information to be collected.
• Minimize the reporting burden on those who are to respond.
This Statement of Non-Receipt is used by the U.S. Department of State to collect information for the purpose of issuing a replacement passport to customers who have not received the passport for which they originally applied.
Passport applicants who do not receive their passports are required to complete a Statement of Non-Receipt of a Passport, Form DS-86. Passport applicants can either download the form from the Internet or pick one up from an Acceptance Facility/Passport Agency. The form must be completed, signed, and then submitted to the Acceptance Facility/Passport Agency for passport re-issuance.
Notice of request for public comment and submission to OMB of proposed collection of information.
The Department of State has submitted the following information collection request to the Office of Management and Budget (OMB) for approval in accordance with the Paperwork Reduction Act of 1995.
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Submit comments to the Office of Management and Budget (OMB) for up to 30 days from February 16, 2012.
Direct comments to the Department of State Desk Officer in the Office of Information and Regulatory Affairs at the Office of Management and Budget (OMB). You may submit comments by the following methods:
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You may obtain copies of the proposed information collection and supporting documents from Passport Services, Passport Forms Management and Officer, U.S. Department of State, Office of Program Management and Operational Support, 2201 C Street NW., Washington, DC 20520, who may be reached on 202-663-2457 or at
We are soliciting public comments to permit the Department to:
• Evaluate whether the proposed information collection is necessary to properly perform our functions.
• Evaluate the accuracy of our estimate of the burden of the proposed collection, including the validity of the methodology and assumptions used.
• Enhance the quality, utility, and clarity of the information to be collected.
• Minimize the reporting burden on those who are to respond,
The Affidavit of Identifying Witness is submitted in conjunction with an application for a U.S. passport. It is used by Passport Services to collect information for the purpose of establishing the identity of the applicant. This application is completed by the identifying witness when the applicant is unable to establish his or her identity to the satisfaction of a person authorized to accept passport applications.
The Affidavit of Identifying Witness is submitted in conjunction with an application for a U.S. passport. Due to legislative mandates Form DS-0071 is only available at acceptance facilities and passport agencies. This form must be completed and signed in the presence of an authorized Passport Agent, Acceptance Agent, or Consular Officer.
Pursuant to section 110 of Trafficking Victims Protection Act of 2000 (Division A, Pub. L. 106-386), as amended (the “Act”), and the Presidential memorandum of delegation signed on February 3, 2012, I hereby determine, consistent with sections 110(d)(4) and 110(f) of the Act, that provision to the Government of Burma of all programs, projects, or activities of assistance described in sections 110(d)(1)(B) of the Act would promote the purposes of the Act or is otherwise in the national interest of the United States.
This determination shall be published in the
The following Applications for Certificates of Public Convenience and Necessity and Foreign Air Carrier Permits were filed under Subpart B (formerly Subpart Q) of the Department of Transportation's Procedural Regulations (See 14 CFR 301.201 et seq.). The due date for Answers, Conforming Applications, or Motions to Modify Scope are set forth below for each application. Following the Answer period DOT may process the application by expedited procedures. Such procedures may consist of the adoption of a show-cause order, a tentative order, or in appropriate cases a final order without further proceedings.
In accordance with Part 235 of Title 49 of the Code of Federal Regulations (CFR) and 49 U.S.C. 20502(a), this document provides the public notice that by a document dated January 18, 2012, the Union Pacific Railroad (UP) has petitioned the Federal Railroad Administration (FRA) seeking approval for the discontinuance or modification of a signal system. FRA assigned the petition Docket Number FRA-2012-0012.
UP seeks approval of the proposed discontinuance of the automatic block signal (ABS) system between Control Point (CP) Troost and Neff Yard on UP's KC Metro Subdivision, at approximately Milepost 281. UP's plans call for the discontinuance of ABS Signals Numbers 2805L, 2805R, 2806L, and 2806R, on Track 112 and Main 2; as well as a switch circuit controller on a hand-operated switch on Track 112.
The reason given is that the ABS system is not needed for efficient and safe operation of trains in this area.
A copy of the petition, as well as any written communications concerning the petition, is available for review online at
Interested parties are invited to participate in these proceedings by submitting written views, data, or comments. FRA does not anticipate scheduling a public hearing in connection with these proceedings since the facts do not appear to warrant a hearing. If any interested party desires an opportunity for oral comment, they should notify FRA, in writing, before the end of the comment period and specify the basis for their request.
All communications concerning these proceedings should identify the appropriate docket number and may be submitted by any of the following methods:
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Communications received by April 2, 2012 will be considered by FRA before final action is taken. Comments received after that date will be considered as far as practicable.
Anyone is able to search the electronic form of any written communications and comments received into any of our dockets by the name of the individual submitting the comment (or signing the comment, if submitted on behalf of an association, business, labor union, etc.). You may review DOT's complete Privacy Act Statement in the
In accordance with Part 211 of Title 49 of the Code of Federal Regulations (CFR), this document provides the public notice that by a document dated December 19, 2011, Durango & Silverton Narrow Gauge Railroad (DSNG) has petitioned the Federal Railroad Administration (FRA) for a waiver of compliance from certain provisions of the Federal railroad safety regulations contained at 49 CFR Part 230, Steam Locomotive Inspection and Maintenance Standards. FRA assigned the petition Docket Number FRA-2012-0002.
DSNG is a tourist railroad that operates between Durango and Silverton, CO. The railroad maintains six narrow gauge (36-inch) steam locomotives; four 1925 Baldwin 2-8-2 locomotives and two 1923 Alco 2-8-2 locomotives. All of these locomotives have received previous 1,472 service-day inspections (SDI) in accordance with 49 CFR 230.17 and will soon receive their second 1,472 SDI due to an accumulation of service days rather than an expiration of the 15 years permitted by 49 CFR 230.17.
Locomotive No. 480, a 1925 Baldwin 2-8-2, has accumulated 1,307 days of service. This locomotive is currently removed from service due to a crack found on the knuckle of the rear flue sheet necessitating repair or replacement. Replacement was chosen due to the age of the existing flue sheet and the added safety of replacement versus repairing the crack in place. Replacement requires that all of the boiler flues will have to be removed to affect the repair. The flues will be removed 165 service days earlier than required for the 1,472 SDI. While the flues are removed, DSNG will clean and inspect the boiler interior as required by 49 CFR 230.31 and 230.32(b)(2), and the applicable portions of 49 CFR 230.32(a).
DSNG requests relief from 49 CFR 230.31(a) with respect to timeframe, and 49 CFR 230.32(b)(3) with respect to boiler exterior. DSNG desires to perform the interior portion of the 1,472 SDI; return the locomotive back into service for the remainder of the 2012 operating season; and complete the exterior portion of the 1,472 SDI at or before the expiration of its present 1,472 service-day cycle. DSNG states that granting of relief will allow extensive monetary savings, as removing and replacing the flues twice within 12 months would be burdensome and costly with a negligible effect on safety. The request is for permission to perform the interior boiler inspection earlier than required. The use of service time for the next 1,472 SDI will start with the first firing of the boiler after returning to service, not at the completion of the exterior inspection.
A copy of the petition, as well as any written communications concerning the petition, is available for review online at
Interested parties are invited to participate in these proceedings by submitting written views, data, or comments. FRA does not anticipate scheduling a public hearing in connection with these proceedings since the facts do not appear to warrant a hearing. If any interested party desires an opportunity for oral comment, they should notify FRA, in writing, before the end of the comment period and specify the basis for their request.
All communications concerning these proceedings should identify the appropriate docket number and may be submitted by any of the following methods:
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Communications received by April 2, 2012 will be considered by FRA before final action is taken. Comments received after that date will be considered as far as practicable.
Anyone is able to search the electronic form of any written communications and comments received into any of our dockets by the name of the individual submitting the comment (or signing the comment, if submitted on behalf of an association, business, labor union, etc.). You may review DOT's complete Privacy Act Statement in the
National Highway Traffic Safety Administration (NHTSA), U.S. Department of Transportation (DOT).
Meeting Notice—National Emergency Medical Services Advisory Council.
The NHTSA announces a meeting of NEMSAC to be held in the Metropolitan Washington, DC area. This notice announces the date, time, and location of the meeting, which will be open to the public. This meeting will include a special roundtable event, hosted by the NEMSAC, regarding the EMS Education Agenda for the Future. The purpose of NEMSAC is to provide a nationally recognized council of emergency medical services (EMS) representatives and consumers to provide advice and recommendations regarding EMS to DOT's National Highway Traffic Safety Administration.
The NEMSAC meeting will take place over two and a half days and be held on Wednesday March 28, 2012, from 9 a.m. to 5 p.m. EST, Thursday March 29, 2012, from 1 p.m. to 5 p.m. EST, and on Friday March 30, 2012, from 8 a.m. to 12 p.m. EST. NEMSAC committees will meet from 8 a.m. to 12 p.m. on March 29, 2012. Public comment periods will be scheduled throughout the day of March 28, 2012, as well as from 3:30 p.m. to 4:30 p.m. EST on March 29, 2012.
The meeting will be held on the 8th floor of the FHI 360 Conference Center at 1825 Connecticut Avenue NW., Washington, DC 20009.
Drew Dawson, Director, U.S. Department of Transportation, Office of Emergency Medical Services, 1200 New Jersey Avenue SE., NTI-140, Washington, DC 20590, telephone number (202) 366-9966; email
Notice of this meeting is given under the Federal Advisory Committee Act, Public Law 92-463, as amended (5 U.S.C. App.). NEMSAC will meet on March 28-30, 2012, at the FHI 360 Conference Center at 1825 Connecticut Avenue NW., Washington, DC 20009. This meeting will include a special roundtable event, hosted by the NEMSAC, regarding the EMS Education Agenda for the Future. The purpose of the March 28, 2012, roundtable is to provide NEMSAC with stakeholder input about the EMS Education Agenda for the Future: A Systems Approach including a briefing on the Agenda's history and lessons learned from its implementation throughout the United States. This stakeholder input will help NEMSAC in making recommendations to the Department of Transportation and the Federal Interagency Committee on EMS regarding: The Agenda's future and a process for revising/updating the Agenda as deemed necessary and appropriate.
The tentative agenda includes the following:
Public comment periods will be scheduled throughout the day of March 28, 2012, as well as from 3:30 p.m. to 4:30 p.m. EST on March 29, 2012. Written comments or requests to make oral presentations must be received by March 21, 2012, by emailing
Minutes of the NEMSAC Meeting will be available to the public online through
Pipeline and Hazardous Materials Safety Administration (PHMSA), DOT.
Notice of actions on Special Permit Applications.
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 of the actions on special permits applications in (November to January 2012). The mode of transportation involved are identified by a number in the “Nature of Application” portion of the table below as follows: 1—Motor vehicle, 2—Rail freight, 3—Cargo vessel, 4—Cargo aircraft only, 5—Passenger-carrying aircraft. Application numbers prefixed by the letters EE represent applications for Emergency Special Permits. It should be noted that some of the sections cited were those in effect at the time certain special permits were issued.
The Department of the Treasury will submit the following information collection request to the Office of Management and Budget (OMB) for review and clearance in accordance with the Paperwork Reduction Act of 1995, Public Law 104-13, on or after the date of publication of this notice.
Comments should be received on or before March 19, 2012 to be assured of consideration.
Send comments regarding the burden estimate, or any other aspect of the information collection, including suggestions for reducing the burden, to (1) Office of Information and Regulatory Affairs, Office of Management and Budget, Attention: Desk Officer for Treasury, New Executive Office Building, Room 10235, Washington, DC 20503, or email at
Copies of the submission(s) may be obtained by calling (202) 927-5331, email at
The Department of Veterans Affairs (VA) gives notice under Public Law 92-463 (Federal Advisory Committee Act) that the National Research Advisory Council will hold a meeting on Wednesday, February 22, 2012, in Conference Room 23, at 131 M Street NE., Washington, DC. The meeting will convene at 9 a.m. and end at 3:30 p.m. The meeting is open to the public.
The purpose of the Council is to provide external advice and review for VA's research mission. The agenda will include a review of the VA research portfolio and a summary of current budget allocations. The Council will also provide feedback on the direction/focus of VA's research initiatives.
No time will be allocated at this meeting for receiving oral presentations from the public. Interested members of the public may submit written statements for the Council's review to Margaret Hannon, Designated Federal Officer, Office of Research and Development (10P9), Department of Veterans Affairs, 810 Vermont Avenue NW., Washington, DC 20420, or by email at
By direction of the Secretary.
Environmental Protection Agency (EPA).
Final rule.
On May 3, 2011, under authority of Clean Air Act (CAA) sections 111 and 112, the EPA proposed both national emission standards for hazardous air pollutants (NESHAP) from coal- and oil-fired electric utility steam generating units (EGUs) and standards of performance for fossil-fuel-fired electric utility, industrial-commercial-institutional, and small industrial-commercial-institutional steam generating units (76 FR 24976). After consideration of public comments, the EPA is finalizing these rules in this action.
Pursuant to CAA section 111, the EPA is revising standards of performance in response to a voluntary remand of a final rule. Specifically, we are amending new source performance standards (NSPS) after analysis of the public comments we received. We are also finalizing several minor amendments, technical clarifications, and corrections to existing NSPS provisions for fossil fuel-fired EGUs and large and small industrial-commercial-institutional steam generating units.
Pursuant to CAA section 112, the EPA is establishing NESHAP that will require coal- and oil-fired EGUs to meet hazardous air pollutant (HAP) standards reflecting the application of the maximum achievable control technology. This rule protects air quality and promotes public health by reducing emissions of the HAP listed in CAA section 112(b)(1).
This final rule is effective on April 16, 2012. The incorporation by reference of certain publications listed in this rule is approved by the Director of the Federal Register as of April 16, 2012.
The EPA established two dockets for this action: Docket ID. No. EPA-HQ-OAR-2011-0044 (NSPS action) or Docket ID No. EPA-HQ-OAR-2009-0234 (NESHAP action). All documents in the dockets are listed on the
For the NESHAP action: Mr. William Maxwell, Energy Strategies Group, Sector Policies and Programs Division, (D243-01), Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711; Telephone number: (919) 541-5430; Fax number (919) 541-5450; Email address:
The information presented in this preamble is organized as follows:
The regulated categories and entities potentially affected by the final standards are shown in Table 1 of this preamble.
This table is not intended to be exhaustive, but rather is meant to provide a guide for readers regarding entities likely to be affected by this action. To determine whether you, as owner or operator of a facility, company, business, organization, etc., will be regulated by this action, you should examine the applicability criteria in 40 CFR 60.40, 60.40Da, or 60.40c or in 40 CFR 63.9981. If you have any questions regarding the applicability of this action to a particular entity, consult either the air permitting authority for the entity or your EPA regional representative as listed in 40 CFR 60.4 or 40 CFR 63.13 (General Provisions).
In addition to being available in the dockets, an electronic copy of this action will also be available on the Worldwide Web (WWW) through the Technology Transfer Network (TTN). Following signature by the Administrator, a copy of the action will be posted on the TTN's policy and guidance page for newly proposed or promulgated rules at the following address:
Under CAA section 307(b)(1), judicial review of this final rule is available only by filing a petition for review in the U.S. Court of Appeals for the District of Columbia Circuit by April 16, 2012. Under CAA section 307(d)(7)(B), only an objection to this final rule that was raised with reasonable specificity during the period for public comment (including any public hearing) can be raised during judicial review. This section also provides a mechanism for the EPA to convene a proceeding for reconsideration, “[i]f the person raising an objection can demonstrate to the Administrator that it was impracticable to raise such objection within [the period for public comment] or if the grounds for such objection arose after the period for public comment (but within the time specified for judicial review) and if such objection is of central relevance to the outcome of the rule[.]” Any person seeking to make such a demonstration to us should submit a Petition for Reconsideration to the Office of the Administrator, Environmental Protection Agency, Room 3000, Ariel Rios Building, 1200 Pennsylvania Ave. NW., Washington, DC 20004, with a copy to the person listed in the preceding
Consistent with Executive Order (EO) 13563, “Improving Regulation and Regulatory Review,” we have estimated the costs and benefits of the final rule. This rule will reduce emissions of HAP, including mercury (Hg), from the electric power industry. Installing the technology necessary to reduce emissions directly regulated by this rule will also reduce the emissions of directly emitted PM
The EPA estimates that this final rule will yield annual monetized benefits (in 2007$) of between $37 to $90 billion using a 3 percent discount rate and $33 to $81 billion using a 7 percent discount rate. The great majority of the estimates are attributable to co-benefits from reductions in PM
The benefits of this rule outweigh costs by between 3 to 1 or 9 to 1 depending on the benefit estimate and discount rate used. The co-benefits are substantially attributable to the 4,200 to 11,000 fewer PM
For more information on how EPA is addressing EO 13563, see the EO discussion in the Statutory and Executive Order Reviews section of this preamble.
On May 3, 2011, the EPA proposed this rule to address emissions of toxic air pollutants from coal and oil-fired electric generating units as required by the CAA. The proposal explained at length the statutory history and requirements leading to this rule, the factual and legal basis for the rule and its specific provisions, and the costs and benefits to the public health and environment from the proposed requirements.
The EPA received over 900,000 comments from members of the public on the proposed rule, substantially more than for any other prior regulatory proposal. The comments express concerns about the presence of Hg in the environment and the effect it has on human health, concerns about the costs of the rule, how challenging it may be for some sources to comply and questions about the impact it may have on this country's electricity supply and economy. Many comments provided additional information and data that have enriched the factual record and enabled EPA to finalize a rule that fulfills the mandate of the CAA while providing flexibility and compliance options to affected sources—options that make the rule less costly and compliance more readily manageable.
This rule establishes uniform emissions-control standards that sources can meet with proven and available technologies and operational processes in a timeframe that is achievable. They will put this industry, now the single largest source of Hg emissions in the United States (U.S.) with emissions of 29 tons per year, on a path to reducing those emissions by approximately 90 percent. Emissions of other toxic metals, such as arsenic (As) and nickel (Ni), dioxins and furans, acid gases (including hydrochloric acid (HCl) and SO
This preamble explains EPA's appropriate and necessary finding, the elements of the final rule, key changes the EPA is making in response to comments submitted on the proposed rule, and our responses to many of the comments we received. A full response to comments is provided in the response to comments document available in the docket for this rulemaking.
Congress established a specific structure for determining whether to regulate EGUs under CAA section 112.
Section 112(n)(1)(A) of the CAA requires the EPA to conduct a study to evaluate the remaining public health hazards that are reasonably anticipated to occur as a result of EGUs' HAP emissions after imposition of CAA requirements. The EPA must report the results of that study to Congress, and regulate EGUs “if the Administrator finds such regulation is appropriate and necessary,” after considering the results of that study. Thus, CAA section 112(n)(1)(A) governs how the Administrator decides whether to list EGUs for regulation under CAA section 112.
As directed, the EPA conducted the study to evaluate the remaining public health hazards and reported the results to Congress (Utility Study Report to Congress (Utility Study)).
Once the EPA lists a source category pursuant to CAA section 112(c), the EPA must then establish technology-based emission standards under CAA section 112(d). For major sources, the EPA must establish emission standards that “require the maximum degree of reduction in emissions of the hazardous air pollutants subject to this section” that the EPA determines are achievable taking into account certain statutory factors.
The EPA also must consider more stringent “beyond-the-floor” control options. When considering beyond-the-floor options, the EPA must consider the maximum degree of reduction in HAP emissions and take into account costs, energy, and non-air quality health and environmental impacts when doing so.
Alternatively, the EPA may set a health-based standard for HAP that have an established health threshold, and the standard must provide “an ample margin of safety.”
For area sources, the EPA may issue standards or requirements that provide for the use of generally available control technologies or management practices (GACT standards) in lieu of promulgating MACT or health-based standards.
As noted above, CAA section 112(n) requires completion of various reports concerning EGUs. For the first report, the Utility Study, Congress required the EPA to evaluate the hazards to public health reasonably anticipated to occur as the result of HAP emissions from EGUs after imposition of the requirements of the CAA.
In addition, Congress, in conference report language associated with the EPA's fiscal year 1999 appropriations, directed the EPA to fund the National Academy of Sciences (NAS) to perform an independent evaluation of the available data related to the health impacts of methylmercury (MeHg) (NAS Study or MeHg Study). H.R. Conf. Rep. No 105-769, at 281-282 (1998). Specifically, Congress required NAS to advise the EPA as to the appropriate reference dose (RfD) for MeHg. 65 FR 79826. The RfD is the amount of a chemical which, when ingested daily over a lifetime, is anticipated to be without adverse health effects to humans, including sensitive subpopulations. In the same conference report, Congress indicated that the EPA should not make the appropriate and necessary regulatory determination for Hg emissions until the EPA had reviewed the results of the NAS Study.
As directed by Congress through different vehicles, the NAS Study and the NIEHS Study evaluated the same issues. The NIEHS completed the NIEHS Study in 1995,
The EPA conducted the studies required by CAA section 112(n)(1) concerning utility HAP emissions, the Utility Study and the Mercury Study,
On December 20, 2000, the EPA issued a finding pursuant to CAA section 112(n)(1)(A) that it was appropriate and necessary to regulate coal- and oil-fired EGUs under CAA section 112 and added such units to the list of source categories subject to regulation under CAA section 112(d). In making that finding, the EPA considered the Utility Study, the Mercury Study, the NAS Study, and certain additional information, including information about Hg emissions from coal-fired EGUs that the EPA obtained pursuant to an information collection request (ICR) under the authority of CAA section 114. 65 FR 79826-27.
Shortly after issuance of the December 2000 finding, an industry group challenged that finding in the Court of Appeals for the D.C. Circuit (D.C. Circuit).
Pursuant to a settlement agreement, the deadline for issuing emission standards was March 15, 2005. However, instead of issuing emission standards pursuant to CAA section 112(d), on March 29, 2005, the EPA issued the Section 112(n) Revision Rule (2005 Action). That action delisted EGUs after finding that it was neither appropriate nor necessary to regulate such units under CAA section 112. In addition, on May 18, 2005, the EPA issued the Clean Air Mercury Rule (CAMR). 70 FR 28606. That rule established standards of performance for emissions of Hg from new and existing coal-fired EGUs pursuant to CAA section 111.
Environmental groups, states, and tribes challenged the 2005 Action and CAMR. Among other things, the environmental and state petitioners argued that the EPA could not remove EGUs from the CAA section 112(c) source category list without following the requirements of CAA section 112(c)(9).
On February 8, 2008, the D.C. Circuit vacated both the 2005 Action and CAMR. The D.C. Circuit held that the EPA failed to comply with the requirements of CAA section 112(c)(9) for delisting source categories. Specifically, the D.C. Circuit held that CAA section 112(c)(9) applies to the removal of “any source category” from the CAA section 112(c) list, including EGUs. The D.C. Circuit found that, by enacting CAA section 112(c)(9), Congress limited the EPA's discretion to reverse itself and remove source categories from the CAA section 112(c) list. The D.C. Circuit found that the EPA's contrary position would “nullify § 112(c)(9) altogether.”
On December 18, 2008, several environmental and public health organizations filed a complaint in the U.S. District Court for the District of Columbia.
The EPA promulgated revised NSPS for SO
The EPA has previously developed other non-EGU combustion-related NESHAP under CAA section 112(d). The EPA promulgated final NESHAP for major source industrial, commercial and institutional boilers and process heaters (IB) and area source industrial, commercial and institutional boilers on March 21, 2011 (40 CFR part 63, subpart DDDDD, 76 FR 15608; and subpart JJJJJJ, 76 FR 15249, respectively), and promulgated standards for stationary combustion turbines (CT) on March 5, 2004 (40 CFR part 63 subpart YYYY; 69 FR 10512). In addition to these three NESHAP, on March 21, 2011, the EPA also promulgated final CAA section 129 standards for commercial and institutional solid waste incineration (CISWI) units, including energy recovery units (40 CFR part 60, subparts CCCC (NSPS) and DDDD (emission guidelines); 76 FR 15704); and a definition of non-hazardous secondary materials that are solid waste (Non-hazardous Solid Waste Definition Rule (40 CFR part 241, subpart B; 76 FR 15456)). Electric generating units and IB
The two IB (Boiler) NESHAP, the CT NESHAP, and this final rule will regulate HAP emissions from sources that combust fossil fuels for electrical power, process operations, or heating. The differences among these rules are due to the size of the units (megawatt (MW), megawatt-electric (MWe), or British thermal unit per hour (Btu/hr)), the boiler/furnace technology, and/or the portion of their electrical output (if any) for sale to any utility power distribution systems.
Pursuant to the CAA, an EGU is “any fossil fuel fired combustion unit of more than 25 megawatts that serves a generator that produces electricity for sale. A unit that cogenerates steam and electricity and supplies more than one-third of its potential electric output capacity and more than 25 megawatts electrical output to any utility power distribution system for sale shall be considered an electric utility steam generating unit.” CAA section 112(a)(8). We consider all of the MW ratings quoted in the final rule to be the original rated nameplate capacity of the unit. We consider cogeneration to be the simultaneous production of power (electricity) and another form of useful thermal energy (usually steam or hot water) from a single fuel-consuming process.
We consider any combustion unit, regardless of size, that produces steam to serve a generator that produces electricity exclusively for industrial, commercial, or institutional purposes (
Because of the combustion technology of simple-cycle and combined-cycle stationary CTs (with the exception of integrated gasification combined cycle (IGCC) units that burn gasified coal or petroleum coke synthesis gas/syngas), we do not consider these CTs to be EGUs for purposes of this final rule.
The December 2000 listing discussed above did not list natural gas-fired EGUs. Thus, this final rule does not regulate a unit that otherwise meets the CAA section 112(a)(8) definition of an EGU but that combusts natural gas exclusively or natural gas in combination with another fossil fuel where the natural gas constitutes 90.0 percent or more of the average annual heat input during any 3 consecutive calendar years or 85.0 percent or more of the annual heat input in one calendar year. We consider such units to be natural gas-fired EGUs notwithstanding the combustion of some coal or oil (or derivative thereof) and such units are not subject to this final rule.
The CAA does not define the terms “fossil fuel-fired” and “fossil fuel.” In this rule, we are finalizing definitions for both terms for purposes of this rule. The definition of “fossil fuel-fired” will help determine the applicability of the final rule to combustion units that sell electricity to the utility power distribution system. The definition of “fossil fuel-fired” establishes the amount of fossil fuel combustion necessary to make a unit “fossil fuel-fired” and hence potentially subject to this final rule. These definitions will help determine applicability of the final rule to units that primarily fire non-fossil fuels (
In addition, the EPA is finalizing in the definition of “fossil fuel-fired” that, among other things, an EGU must fire coal or oil for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year after the applicable compliance date in order to be considered a fossil fuel-fired EGU subject to this final rule. The EPA has based these threshold percentage values on the definition of “oil-fired” in the Acid Rain Program (ARP) found at 40 CFR 72.2. Though the EPA does not have annual heat input data for, for example, biomass co-fired EGUs because their use is not yet commonplace, we believe this definition accounts for the use of fossil fuels for flame stabilization use without inappropriately subjecting such units to this final rule.
Units that do not meet the EGU definition will in most cases be considered IB units subject to one of the two Boiler NESHAP. Thus, for example, a biomass-fired EGU, regardless of size, that utilizes fossil fuels for startup and flame stabilization purposes only (
A cogeneration facility that sells electricity to any utility power distribution system equal to more than one-third of its potential electric output capacity and more than 25 MW will be considered an EGU if the facility is fossil fuel-fired as that term is defined in the final rule.
We recognize that different CAA section 112 rules may impact a particular unit at different times. For example, the Boiler NESHAP may cover some cogeneration units. Such a unit may decide to increase or decrease the proportion of production output it supplies to the electric utility grid, thus causing the unit to meet the EGU cogeneration criteria (
Another rule intersection may occur where one or more coal- or oil-fired EGU(s) share an air pollution control device (APCD) and/or an exhaust stack with one or more similarly-fueled IB unit(s). To demonstrate compliance with two different rules, either the emissions would need to be apportioned to the appropriate source or the more stringent emission limit would need to be met. Data needed to apportion emissions are not currently required by this final rule or the final boiler NESHAP and are not otherwise available. Therefore, the EPA is finalizing the requirement to comply with the more stringent emission limit.
Clean Air Act section 129 regulates units that combust “non-hazardous secondary materials,” as that term is defined by the Administrator under the Resource Conservation and Recovery Act (RCRA), that are “solid wastes.” On March 21, 2011, the EPA promulgated the final Non-Hazardous Solid Waste Definition Rule (76 FR 15456). Any EGU that combusts any solid waste as defined in that final rule is a solid waste
In the Non-Hazardous Solid Waste Definition Rule, the EPA determined that coal refuse from current mining operations is not considered to be a “solid waste” if it is not discarded. Coal refuse that is in legacy coal refuse piles is considered a “solid waste” because it has been discarded. However, if discarded coal refuse is processed in the same manner as currently mined coal refuse, the coal refuse would not be considered a solid waste but instead would be considered a product fossil fuel. Therefore, the combustion of such material by a combustion unit would not subject that unit to regulation under CAA section 129. Instead, the unit would be subject to this final rule if it meets the definition of EGU. In the proposed rule, we assumed that all units that combust coal refuse and otherwise meet the definition of a coal-fired EGU are in fact combusting newly mined coal refuse or coal refuse from legacy piles that has been processed such that it is not a solid waste. We did not receive any information since proposal that would cause us to revise this determination in the final rule.
Further, CAA section 129(g)(1)(B) exempts from regulation
“* * * qualifying small power production facilities, as defined in section 796(17)(C) of Title 16, or qualifying cogeneration facilities, as defined in section 796(18)(B) of Title 16, which burn homogeneous waste * * * for the production of electric energy or in the case of qualifying cogeneration facilities which burn homogeneous waste for the production of electric energy and steam or forms of useful energy (such as heat) which are used for industrial, commercial, heating or cooling purposes * * *”
This final rule protects air quality and promotes public health by reducing emissions of some of the HAP listed in CAA section 112(b)(1). Utilities are by far the largest anthropogenic source of Hg in the U.S. In addition, EGUs are the largest source of HCl, hydrogen fluoride (HF), and selenium (Se) emissions, and a major source of metallic HAP emissions including As, chromium (Cr), Ni, and others. The discrepancy is even greater now that almost all other major source categories have been required to control Hg and other HAP under CAA section 112. In 2005, U.S. EGUs emitted 50 percent of total domestic anthropogenic Hg emissions, 62 percent of total As emissions, 39 percent of total cadmium (Cd) emissions, 22 percent of total Cr emissions, 82 percent of total HCl emissions, 62 percent of total HF emissions, 28 percent of total Ni emissions, and 83 percent of total Se emissions.
In December 2000, the EPA issued a finding pursuant to CAA section 112(n)(1)(A) that it was appropriate and necessary to regulate coal- and oil-fired EGUs under CAA section 112 and added such units to the list of source categories subject to regulation under section 112(d). The EPA found that it was appropriate to regulate HAP emissions from coal- and oil-fired EGUs because, among other reasons, Hg is a hazard to public health, and U.S. EGUs are the largest domestic source of Hg emissions. The EPA also found it appropriate to regulate HAP emissions from EGUs because it had identified certain control options that would effectively reduce HAP emissions from U.S. EGUs. The EPA found that it was necessary to regulate HAP emissions from U.S. EGUs under section 112 because the implementation of other requirements under the CAA will not adequately address the serious public health and environmental hazards arising from HAP emissions from U.S. EGUs and that CAA section 112 is intended to address HAP emissions.
Because several years had passed since the 2000 finding, the EPA performed additional technical analyses for the proposed rule, even though those analyses were not required. These analyses included a national-scale Hg risk assessment focused on populations with high levels of self-caught fish consumption, and a set of 16 case studies of inhalation cancer risks for non-Hg HAP. The analyses confirm that it remains appropriate and necessary to regulate U.S. EGUs under section 112.
In the preamble to the proposed rule, the EPA reported the results of those additional technical analyses. Those analyses confirmed the 2000 finding that it is appropriate to regulate U.S. EGUs under section 112 by demonstrating that (1) Hg continues to pose a hazard to public health because up to 28 percent of watersheds were estimated to have Hg deposition attributable to U.S. EGUs that contributes to potential exposures above the reference dose for methylmercury (MeHg RfD), a level above which there is increased risk of neurological effects in children, (2) non-Hg HAP emissions pose a hazard to public health because case studies at 16 facilities demonstrated that lifetime cancer risks at 4 of the facilities exceed 1 in 1 million, and (3) U.S. EGUs remain the largest domestic source of Hg emissions and several HAP (
In the preamble to the proposed rule, the EPA also found that it is appropriate to regulate U.S. EGUs because (1) Hg emissions pose a hazard to the environment and wildlife, adversely impacting species of fish-eating birds and mammals, (2) acid gas HAP pose a hazard to the environment because they contribute to aquatic acidification, and (3) effective controls are available to reduce Hg and non-Hg HAP emissions from U.S. EGUs.
The additional analyses reported in the preamble to the proposed rule also confirmed that it remains necessary to regulate U.S. EGU under CAA section 112. These analyses demonstrated that (1) Hg emissions from U.S. EGUs remaining in 2016 are reasonably anticipated to pose a hazard to public health after imposition of other CAA
Since issuance of the proposed rule, the EPA has conducted peer reviews of the national-scale Hg risk assessment (Hg Risk TSD) and the approach for estimating chromium and nickel inhalation cancer risk in the case studies.
As described in the revised Hg Risk TSD, after addressing comments from the peer review, the revised results show that up to 29 percent of modeled watersheds are estimated to have Hg deposition attributable to U.S. EGUs that contributes to potential exposures above the MeHg RfD, an increase of one percentage point from the results reported in the proposed rule. We conclude that Hg emissions from EGUs pose a hazard to public health based on the total of 29 percent of modeled watersheds at risk. Our analyses show that of the 29 percent of watersheds with population at-risk, in 10 percent of those watersheds U.S. EGU deposition alone without considering deposition from other sources would lead to potential exposures that exceed the MeHg RfD, and in 24 percent of those watersheds, total potential exposures to MeHg exceed the RfD and U.S. EGUs contribute at least 5 percent to Hg deposition.
The peer review of the approach to estimate Ni and Cr cancer risk in the case studies also supported EPA's assessment. The EPA enhanced this analysis in response to the peer review and public comments. The results of those revised analyses show that 6 of 16 modeled facilities have lifetime cancer risks greater than 1 in a million, thus confirming that non-Hg HAP emissions from U.S. EGUs remain a hazard to public health. Given Congress' determination that categories of sources that emit HAP resulting in a lifetime cancer risk greater than 1 in a million should not be removed from the CAA section 112(c) source category list and should continue to be regulated under CAA section 112, the EPA concludes that risk above that level represents a hazard to public health.
Based on our consideration of the peer reviews, public comments, and our updated analyses, we confirm the findings that Hg and non-Hg HAP emissions from U.S. EGUs pose hazards to public health and that it remains appropriate to regulate U.S. EGUs under CAA section 112. We also conclude that it remains appropriate to regulate U.S. EGUs under CAA section 112 because of the magnitude of Hg and non-Hg emissions, environmental effects of Hg and certain non-Hg emissions, and the availability of controls to reduce HAP emissions from EGUs.
In addition, we conclude that the hazards to public health from Hg and non-Hg emissions from U.S. EGUs are reasonably anticipated to remain after imposition of the requirements of the CAA. The same is true for hazards to the environment. Thus, we confirm that it is necessary to regulate U.S. EGUs under CAA section 112.
In the preamble to the proposed rule, the EPA stated that “in making the finding that it remains appropriate and necessary to regulate EGUs to address public health and environmental hazards associated with emissions of Hg and Non-Hg HAP from EGUs, the EPA determined that the Hg Risk TSD supporting EPA's 2011 review of U.S. EGU health impacts should be peer-reviewed.”
The EPA's response to the peer review the Hg Risk TSD is fully documented in the revised
Peer review is consistent with EPA's open and transparent process to ensure that the Agency's scientific assessments and rulemakings are based on the best science available. This regulatory action was supported by the Hg Risk TSD, which is a highly influential scientific assessment. Therefore, the EPA conducted a peer review in accordance with OMB's
The EPA commissioned the peer review through EPA's SAB, which provides independent advice and peer review to EPA's Administrator on the scientific and technical aspects of environmental issues. The SAB convened a 22-member peer review committee. The SAB process for selecting the panel began with two
The EPA asked the SAB to comment on the Hg Risk TSD, including the overall design and approach and the use of specific models and key assumptions. The EPA also asked the SAB to comment on the extent to which specific facets of the assessment were well characterized in the Hg Risk TSD. The specific charge questions are listed below:
Question 1. Please comment on the scientific credibility of the overall design of the mercury risk assessment as an approach to characterize human health exposure and risk associated with U.S. EGU mercury emissions (with a focus on those more highly exposed).
Question 2. Are there any additional critical health endpoint(s) besides IQ loss, which could be quantitatively estimated with a reasonable degree of confidence to supplement the mercury risk assessment (
Question 3. Please comment on the benchmark used for identifying a potentially significant public health impact in the context of interpreting the IQ loss risk metric (i.e., an IQ loss of 1 to 2 points or more representing a potential public health hazard). Is there any scientifically credible alternate decrement in IQ that should be considered as a benchmark to guide interpretation of the IQ risk estimates (
Question 4: Please comment on the spatial scale used in defining watersheds that formed the basis for risk estimates generated for the analysis (i.e., use of 12-digit hydrologic unit code classification). To what extent do [Hydrologic Unit Code] HUC12 watersheds capture the appropriate level of spatial resolution in the relationship between changes in mercury deposition and changes in MeHg fish tissue levels? (see section 1.3 and Appendix A of the Mercury Risk TSD for additional detail on specifying the spatial scale of watersheds used in the analysis).
Question 5: Please comment on the extent to which the fish tissue data used as the basis for the risk assessment are appropriate and sufficient given the goals of the analysis. Please comment on the extent to which focusing on data from the period after 1999 increases confidence that the fish tissue data used are more likely to reflect more contemporaneous patterns of Hg deposition and less likely to reflect earlier patterns of Hg deposition. Are there any additional sources of fish tissue MeHg data that would be appropriate for inclusion in the risk assessment?
Question 6: Given the stated goal of estimating potential risks to highly exposed populations, please comment on the use of the 75th percentile fish tissue MeHg value (reflecting targeting of larger but not the largest fish for subsistence consumption) as the basis for estimating risk at each watershed. Are there scientifically credible alternatives to use of the 75th percentile in representing potential population exposures at the watershed level?
Question 7: Please comment on the extent to which characterization of consumption rates and the potential location for fishing activity for high-end self-caught fish consuming populations modeled in the analysis are supported by the available study data cited in the Mercury Risk TSD. In addition, please comment on the extent to which consumption rates documented in Section 1.3 and in Appendix C of the Mercury Risk TSD provide appropriate representation of high-end fish consumption by the subsistence population scenarios used in modeling exposures and risk. Are there additional data on consumption behavior in subsistence populations active at inland freshwater water bodies within the continental U.S.?
Question 8: Please comment on the approach used in the risk assessment of
Question 9: Please comment on the draft risk assessment's characterization of the limitations and uncertainty associated with application of the Mercury Maps approach (including the assumption of proportionality between changes in mercury deposition over watersheds and associated changes in fish tissue MeHg levels) in the risk assessment. Please comment on how the output of CMAQ [Community Multiscale Air Quality] modeling has been integrated into the analysis to estimate changes in fish tissue MeHg levels and in the exposures and risks associated with the EGU-related fish tissue MeHg fraction (
Question 10: Please comment on the EPA's approach of excluding watersheds with significant non-air loadings of mercury as a method to reduce uncertainty associated with application of the Mercury Maps approach. Are there additional criteria that should be considered in including or excluding watersheds?
Question 11: Please comment on the specification of the concentration-response function used in modeling IQ loss. Please comment on whether EPA, as part of uncertainty characterization, should consider alternative concentration-response functions in addition to the model used in the risk assessment. Please comment on the extent to which available data and methods support a quantitative treatment of the potential masking effect of fish nutrients (
Question 12: Please comment on the degree to which key sources of uncertainty and variability associated with the risk assessment have been identified and the degree to which they are sufficiently characterized.
Question 13: Please comment on the draft Mercury Risk TSD's discussion of analytical results for each component of the analysis. For each of the components below, please comment on the extent to which EPA's observations are supported by the analytical results presented and whether there is a sufficient characterization of uncertainty, variability, and data limitations, taking into account the models and data used: Mercury deposition from U.S. EGUs, fish tissue MeHg concentrations, patterns of Hg deposition with HG fish tissue data, percentile risk estimates, and number and frequency of watersheds with populations potentially at risk due to U.S. EGU mercury emissions.
Question 14: Please comment on the degree to which the final summary of key observations in Section 2.8 is supported by the analytical results presented. In addition, please comment on the degree to which the level of confidence and precision in the overall analysis is sufficient to support use of the risk characterization framework described on page 18.
The SAB was generally supportive of EPA's approach.
The SAB report contained many recommendations for improving the Hg Risk TSD, which the SAB organized into three general themes: (1) Improve the clarity of the Hg Risk TSD regarding methods and presentation of results, (2) expand the discussion of sources of variability and uncertainty, and (3) de-emphasize IQ loss as an endpoint. In the following subsection, we provide EPA's response to these recommendations.
In response to the peer review, the EPA has substantially revised the Hg Risk TSD. The revised Hg Risk TSD addresses all of the recommendations from the SAB and includes a detailed list of the specific revisions made to the Hg Risk TSD. Revisions in response to the main recommendations are summarized below. Italicized statements are the SAB's recommendations, which are followed by EPA's response.
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Based on the recommendations we received from the SAB, we revised the quantitative analysis of risk to subsistence fishing populations with high levels of fish consumption. Our revision to the quantitative risk results reflects three key recommendations from the SAB, including (1) addition of 824 watersheds based on additional fish tissue Hg sample data we obtained from states and the National Listing of Fish Advisories, (2) application of a 0.95 adjustment factor to the reported fish tissue Hg concentrations to account for the fraction that is MeHg, and (3) inclusion of all watersheds with fish samples that meet the filtering criteria
Based on these revisions, our estimates of the number and percent of modeled watersheds with populations potentially at-risk from exposure to EGU-attributable MeHg changed from those presented in the preamble to the proposed rule.
The additional sensitivity analyses conducted in response to the SAB peer review showed that the estimates of the percent of modeled watersheds with populations potentially at-risk are robust to alternative assumptions about both the watersheds included in the analysis and the selection of the 50th percentile or 75th percentile fish tissue Hg level. Sensitivity analyses excluding entire states with the potential for historical loadings of Hg from non-air sources
As explained in the preamble to the proposed rule, the EPA submitted for peer review its characterization of the chemical speciation for the emissions of Cr and Ni used in the non-Hg HAP inhalation risk case studies. The remaining aspects of the non-Hg HAP case study risk assessments used methods that were previously peer reviewed. Specifically, the methodologies used to conduct the non-Hg case studies are consistent with those used to conduct inhalation risk assessments under EPA's Risk and Technology Review (RTR) program. Because the RTR assessments are considered to be highly influential science assessments, the methodologies used to conduct them were subject to a peer review by the SAB in 2009. The SAB issued its peer review report in May 2010.
The EPA's case studies identified Cr and Ni emissions as the key drivers of the estimated inhalation cancer risks for EGUs. Because these results hinged on specific scientific interpretations of data used to characterize EGU emissions of Cr and Ni, the EPA conducted a letter peer review of its analysis and interpretation of those data relative to the quantification of inhalation risks associated with Cr and Ni emissions from U.S. EGUs. The following sections describe the peer review process, enumerate the peer review charge questions presented to the peer review panel, summarize the key recommendations from the peer review, and summarize our responses to those recommendations.
The EPA asked three independent, external peer reviewers representing government, academic and the private sector to review of the methods for developing inhalation cancer risk estimates associated with emissions of Cr and Ni compounds from coal- and oil-fired EGUs in support of the appropriate and necessary finding. The approaches and rationale for the technical and scientific considerations used to derive inhalation cancer risks were summarized in the draft document entitled, “Methods to Develop Inhalation Cancer Risk Estimates for Chromium and Nickel Compounds.” The peer reviewers received several charge questions (three questions on Cr and two questions on Ni, which are provided below) on the technical and scientific relevance of the approaches used to develop the inhalation unit risk estimates. The EPA also provided information on Cr speciation profiles for different industrial sources, as well as information on the Ni speciation of PM from oil-fired EGUs.
Below, we present the charge questions posed to the peer reviewers to help guide their review and development of recommendations to EPA on key issues relevant to the characterization of risks from EGU emissions containing either Cr or Ni compounds.
The EPA asked three questions regarding Cr and Cr compounds:
Question 1: Do EPA's judgments related to speciated Cr emissions adequately take into account the available Cr speciation data?
Question 2: Has EPA selected the species of Cr (
Question 3: Are the assumptions used in past analysis scientifically defensible, and are there alternatives that EPA should consider for future analysis?
The EPA asked two questions regarding Ni and Ni compounds:
Question 1: Do EPA's judgments related to speciated Ni emissions adequately take into account available speciation data, including recent industry spectrometry studies?
Question 2: Based on the speciation information available and on what we know about the health effects of Ni and Ni compounds, and taking into account the existing Unit Risk Estimates (URE) values (
Regarding Cr and Cr compounds, all three reviewers considered Cr(VI) as the species likely to be driving cancer risks based on solid evidence from the health effects database for Cr and Cr compounds. All three authors also considered EPA's use of the average of the range of the available speciation data (
Regarding Ni and Ni compounds, the reviewers agreed with the views of the international scientific bodies, which consider Ni compounds carcinogenic as a group. One reviewer recommended that the EPA review several additional Ni speciation data that suggests that sulfidic Ni compounds (which the reviewer considered as the most potent carcinogens within the group of all Ni compounds) are present at low levels in emissions from EGUs. In addition, this reviewer pointed out that there is a recently proposed model that may explain the differences in carcinogenic potential across Ni compounds.
We summarize EPA's basic responses to the peer review comments below, first for Cr-related issues, and second for Ni-related issues, which are reflected in the revised document.
In agreement with the peer reviewers and based on the health effects information available for Cr, the EPA assigns high confidence in the assumption that Cr(VI) is the carcinogenic species driving the risk of Cr-emitting facilities. In agreement with the reviews, the EPA considers derivation of default speciation profiles based on the mass of Cr(VI) a reasonable approach. As suggested by one of the reviewers, the EPA reviewed two potentially relevant studies, one of which showed coal combustion emissions containing as much as 43 percent Cr(VI),
In agreement with the peer reviewers, the EPA also recognizes that the confidence in the default speciation profiles is low because the profiles are based on a limited data set with a wide range of percentages of Cr(VI) across the different samples.
Based on the views of the major scientific bodies mentioned above and the peer reviewers that commented on EPA's approaches to risk characterization of Ni compounds, the EPA considers all Ni compounds to be carcinogenic as a group and the EPA does not consider Ni speciation or Ni solubility to be strong determinants of Ni carcinogenicity. These scientific bodies also recognize that based on the data available, the precise Ni compound(s) responsible for the carcinogenic effects in humans is not always clear, and that there may be differences in the potential toxicity and carcinogenic potential across Ni compounds. Nevertheless, studies in humans indicate that various mixtures of Ni compounds (including Ni sulfate, sulfides and oxides, alone or in combination) encountered in the Ni refining industries may cause cancer in humans, and there is no reason to expect anything different from this for mixtures of Ni compounds from other emission sources. One of the reviewers suggested we consider views by some authors that believe that water soluble Ni, such as Ni sulfate, should not be considered a human carcinogen. This view is based primarily on a negative Ni sulfate 2-year rodent bioassay by the National Toxicology Program (NTP) (which is different from the positive 2-year NTP bioassay for Ni subsulfide).
Regarding the second charge question on Ni compounds, two reviewers suggested using the URE derived by the TCEQ
Although this report focused primarily on cancer risks associated with emissions containing Ni compounds, it is important to note that comparative quantitative analyses of non-cancer toxicity of Ni compounds indicate that Ni sulfate is as toxic or more toxic than Ni subsulfide or Ni oxide which does not support the notion that the solubility of Ni compounds is a strong determinant of its toxicity.
Based on the results of the peer review and public comments on the non-Hg case study chronic inhalation risk assessment, we made several changes to the emissions estimates, dispersion modeling, and risk characterization for the modeled case study facilities. Key changes include (1) changes in emissions, (2) changes in stack parameters for some facilities based on new data received during the
Based on estimated actual emissions, the highest estimated individual lifetime cancer risk from any of the 16 case study facilities was 20 in a million, driven by Ni emissions from the one case study facility with oil-fired EGUs. Of the facilities with coal-fired EGUs, five facilities had maximum individual cancer risks greater than one in a million
Since these case studies do not cover all facilities in the category, and since our assessment does not include the potential for impacts from different EGU facilities to overlap one another (
Based on the fact that six U.S. EGUs were estimated to meet or exceed the CAA section 112(c)(9) criterion of one in a million, EGUs cannot be removed from the list of source categories to be regulated under CAA section 112.
First, the commenter makes much of the fact that the EPA did not go through CAA section 307(d) notice and comment rulemaking when making the appropriate and necessary finding and listing decision in 2000. However, the commenter's complaint is without foundation. The CAA does not require CAA section 307(d) rulemaking for listing decisions. In fact, CAA section 112(e)(4) specifically provides that listing decisions may only be challenged “when the Administrator issues emission standards for such * * * [listed] category.” Second, the commenter challenged the listing decision in the U.S. Court of Appeals for the District of Columbia Circuit (Court) and, on July 26, 2001, the Court granted EPA's motion to dismiss that action based on the plain language of CAA section 112(e)(4). Moreover, in addition to the 2000 notice, the EPA clearly articulated its basis for listing EGUs in this proposed rule, which is consistent with CAA section 307(d), and the commenter was provided an ample opportunity to comment. Finally, the commenter asserts that the rulemaking docket for this action is incomplete because the Agency did not include two earlier dockets—Docket ID. No. A-92-55 and Docket ID. No. EPA-HQ-OAR-2002-0056—for the Section 112(n) Revision Rule, 70 FR 15994 (March 29, 2005), and the reconsideration of the Section 112(n) Revision Rule, 71 FR 33388 (June 9, 2006), respectively. The commenter is incorrect because EPA incorporated by reference the two dockets at issue.
The commenter seems confused about the basis for the Agency's appropriate and necessary finding because it maintains that the EPA made the appropriate and necessary finding based on the health co-benefits attributable to PM reductions that will be achieved as a result of the Agency's regulation of HAP emissions from EGUs. Nowhere in the May 2011 proposal does EPA state that it based the appropriate and necessary finding on hazards to public health attributable to PM emissions. The commenter's allegation lacks foundation. The appropriate and necessary finding unmistakably focuses on the hazards to public health and hazards to the environment associated with HAP emissions from EGUs.
As for EGUs, according to the commenter, the EPA found that the combustion of fossil fuels produces extremely small emissions of a broad variety of substances that are present in trace amounts in fuels and that are removed from the gas stream by control equipment installed to satisfy other CAA requirements. The commenter stated that the EPA, in past reviews, found that these HAP emissions did not pose hazards to public health.
According to the commenter, in the late 1980s, the EPA was concerned that its prior risk assessments of individual HAP emissions from fossil-fuel-fired power plants may not reflect the total risks posed by all HAP emitted by those sources. The commenter states that the EPA modeled the risks posed by all HAP emitted by power plants (very much like the analyses the Agency would conduct for the Utility Study ten years later). The commenter asserts that the modeling again failed to identify threats to public health that warranted regulation under an “ample margin of safety” test.
We acknowledge that Congress treated radionuclide emissions from EGUs differently. For radionuclides from EGUs (and certain other sources), Congress included CAA section 112(q)(3), which authorizes but does not require the Agency to maintain the regulations of radionuclides in effect prior to the 1990 amendments. The fact that Congress made an exception for radionuclides and no other HAP from EGUs further demonstrates that the HAP-related actions EPA took with regard to EGUs prior to the 1990 amendments to the CAA are not germane.
As for the commenter's statements about Hg emissions from EGUs, we find their conclusions wholly inconsistent with CAA section 112(n)(1). That provision is titled “Electric utility steam generating units,” and it directs EPA to conduct two Hg-specific studies.
Finally, the commenter stated that the EPA conducted a risk assessment of all HAP from EGUs prior to the 1990 amendments and that the Agency did not identify any HAP that failed the “ample margin of safety” test. The commenter did not cite the study or provide any information to support the statements so we are unable to respond to the alleged study directly; however, the risk assessments conducted in support of the appropriate and necessary finding, as well as the 2000 finding, demonstrate that HAP emissions from EGUs pose hazards to public health and the environment.
The detailed interpretation set forth in the preamble to the proposed rule is consistent with the 2000 finding, but EPA does not assert that the interpretation is in any way necessary to support the factual conclusions reached in the 2000 finding. Instead, we noted in the preamble to the proposed rule that our interpretation is consistent with the 2000 finding because in 2005 we interpreted the statute in a manner that was not consistent with the 2000 finding. The commenter has provided no legal support for its position that the Agency erred in interpreting the statute in a manner that is consistent with a prior factual finding.
According to the commenters the sponsor of the House bill that became section 112(n)(1)(A) provides an explanation that contradicts the EPA's approach to regulating EGUs:
Pursuant to section 112(n), the Administrator may regulate fossil fuel fired electric utility steam generating units only if the studies described in section 112(n) clearly establish that emissions of any pollutant, or aggregate of pollutants, from such units cause a significant risk of serious adverse effects on the public health. Thus, * * * he may regulate only those units that he determines—after taking into account compliance with all provisions of the act and any other Federal, State, or local regulation and voluntary emission reductions—have been demonstrated to cause a significant threat of serious adverse effects on the public health.
The commenters stated that the EPA position is premised on the assumption that “regulation under section 112” necessarily means “regulation under 112(d)” and falsely premised on the assumption that source categories listed by operation of section 112(n)(1)(A) cannot be regulated differently. The commenters conclude that the language of section 112(n)(1)(a) reflects Congress' intent that “regulation of HAP from EGUs was not intended to operate under section 112(d) but was instead intended to be tailored to the findings of the utility study mandated by section 112(n)(1)(A).”
The commenter has not cited any other legislative history to support
Senator Durenberger discussed the negotiations with the Administration and the industry push to avoid regulation, including industry arguments for not regulating Hg from U.S. EGUs:
The utility industry continued to adamantly oppose [regulation under section 112]. First, they argued that mercury isn't much of an environmental problem. But as the evidence mounted over the summer and it became clear that mercury is a substantial threat to the health of our lakes, rivers and estuaries and that power plants are among the principal culprits, they changed their tactic. Now they are arguing that mercury is a global problem so severe that just cleaning up U.S. power plants won't make enough of a difference to be worth it. They've gone from `we're not a problem' to `you can't regulate us until you address the whole global problem.' Recasting an issue that way is not new around here. So, it is not a surprise. But it does suggest the direction in which this debate will be heading in the next few years.
Senator Durenberger also explained why the House version was adopted:
Given that a resolution of the difficult issues in the conference were necessary to conclude work on this bill, the Senate proposed to recede to the House provision which was taken from the original administration bill. It provides for a 3-year study of utility emissions followed by regulation to the extent that the Administrator finds them necessary.
Senator Durenberger's statements indicate that it is unlikely that he would agree with Oxley's interpretation of CAA section 112(n)(1), a provision that provides the Agency with considerable discretion, and nothing indicates that others in the Senate (or for that matter anyone else in the House) would agree with that interpretation. Given the Supreme Court's views on the use of such limited legislative history, the EPA reasonably declined to consider (or even discuss) the legislative history in the preamble to the proposed rule and we believe it would be improper to ascribe Representative Oxley's statements to the entire Congress.
Moreover, Representative Oxley's statement directly conflicts with the statutory text. Representative Oxley stated that “[the Administrator may regulate only those units that he determines—
The legislative history the commenters rely on is not controlling. The Agency believes that it has reasonably interpreted section 112(n)(1)(A), for all the reasons described herein and in the proposal. The commenters also cite Representative Oxley's statements as support for alternative interpretations of CAA section 112(n)(1). We believe that any arguments that rely on such limited legislative history are without merit.
According to the commenter, it is not enough that the EPA has purported to “explain” why it has abandoned the interpretation of CAA section 112(n)(1) adopted in 2005. The commenter states that under the first step of
Furthermore, we properly considered the scope of our discretion in interpreting the statute as explained in detail in the preamble to the proposed rule. We believe the interpretation set forth in the preamble to the proposed rule is consistent with the Act and, therefore, the Agency should be afforded deference pursuant to
The commenter stated that this remarkably forthright statement establishes that the underlying basis for EPA's proposal to regulate EGUs under CAA section 112 is not to address any “hazards to public health” that might be attributed to the emission by EGUs of HAP listed under CAA section 112(b). Rather, according to commenter, the EPA is utilizing the regulation of EGUs under CAA section 112 as a means to an entirely different end: To force the imposition of controls that will also have the result of reducing non-HAP emissions (primarily PM) or force the shutdown of those units for which the cost of such controls would be prohibitive. At the same time, according to commenter, the EPA tacitly acknowledges that it cannot hope to make out a case that the regulation of EGU HAP emissions is “appropriate and necessary” within the meaning of CAA section 112(n)(1). The commenter asserts that the only HAP whose health-related benefits EPA quantifies is Hg. Elsewhere, the commenter stated that the EPA contends there are “additional health and environmental effects” attributable to HAP other than Hg, but admits that it has “not quantified” those risks due supposedly to “insufficient information.”
One commenter stated that the EPA is directed by CAA section 112(n)(1)(A) to study the “hazards to public health anticipated to occur as a result of emissions” by EGUs of “pollutants listed under subsection (b) of this section”—
Furthermore, the Agency's interpretation does not violate Chevron Step 1. The terms “appropriate” and “necessary” are ambiguous. The statements of a lone legislator do not transform those ambiguous words into a Chevron Step 1 situation.
Moreover, the commenter's assertion that Congress unambiguously defined the factors to consider in making the appropriate determination is without merit. We fully explain in the preamble to the proposed rule the basis for the Agency's interpretation, and we are not revising that interpretation based on the comments received.
Finally, the EPA notes that the sentence concerning regulation under CAA section 112(d) that the commenter quotes from the preamble states, in full: “Congress did not exempt EGUs from the other requirements of section 112 and,
Commenters assert that the EPA misreads CAA section 112(n)(1)(B) and (C) to inject environmental effects in the CAA section 112(n)(1)(A) determination. According to one commenter the plain language of CAA section 112(n)(1) establishes that regulation of EGUs is to be predicated solely on “hazards to public health” attributable to HAP emissions. The legislative history providing that the EPA “may regulate [EGUs] only if the studies described in section 112(n) clearly establish that emissions of any pollutant * * * from such units cause a significant risk of serious adverse risk to the public health” confirms that plain language.
The commenter makes a related assertion that the EPA acts contrary to congressional intent by assuming authority to assess the “`hazard to public health or the environment [from] HAP emissions from EGUs alone' or the `result of HAP emissions from EGUs in conjunction with HAP emissions from other sources'” (citing 76 FR at 24,988/1). According to the commenter, the only evident basis for the Agency's interpretation that, in making its “appropriate and necessary” finding, the EPA can (and should) take into account HAP emissions from sources other than EGUs, is that the Mercury Study authorized by CAA 112(n)(1)(B) references “mercury emissions from * * * municipal waste combustion units, and other sources, including area sources,” in addition to EGUs. The commenter asserts, however, that subparagraph (n)(1)(A) identifies the Utility Study as the sole study to inform EPA's “appropriate and necessary” finding. The commenter states that if Congress had intended that the EPA take into account information developed through the Mercury Study, Congress “would not have specified that the EPA was to predicate its `appropriate and necessary' finding on the `results of the study required by this subparagraph' (n)(1)(A).”
Commenter also cites to a number of other section 112 provisions that expressly address environmental effects and the commenter states the only conclusion to draw from the inclusion in those provisions and the absence of such language in section 112(n)(1)(A) is that Congress intended public health to be the only basis for the appropriate and necessary finding.
The commenter appears to maintain that the EPA must interpret the scope of the appropriate and necessary finding solely in the context of the CAA section 112(n)(1)(A) Utility Study, such that only hazards to public health and only EGU HAP emissions may be considered. The commenter incorrectly conflates the requirements for the Utility Study with the requirement to regulate EGUs under CAA section 112 if EPA determines it is appropriate and necessary to do so. The commenter concedes that the Agency may consider information other than that contained in the Utility Study, but only to the extent it relates specifically to hazards to public health directly attributable to HAP emissions from EGUs. We agree that we may consider additional information other than that contained in the Utility Study, as we stated in the preamble to the proposed rule, because courts do not interpret phrases like “after considering the results of” in a manner that precludes the consideration of other information.
The commenter also argues that the statute clearly prohibits the Agency from considering adverse environmental effects or the cumulative effects of HAP emissions from EGUs and other sources based on its claim that the statute is clear when one
The commenter stated that Congress specifically told EPA when it wanted EPA to consider adverse environmental effects in CAA section 112 and cites to several provisions of the Act that require consideration of adverse environmental effects. The commenter ignores CAA section 112(n)(1)(B), which directs the Agency to consider adverse environmental effect. In any event, even were we to view section 112(n)(1)(A) in isolation, as the commenter suggests, we still maintain that we can consider adverse environmental effects under 112(n)(1)(A). Nothing in section 112(n)(1)(A) precludes consideration of environmental effects. Congress required the Agency to assess whether it is appropriate and necessary to regulate EGUs under section 112. We believe that adverse environmental effects can be considered in the appropriate analysis. Congress specifically directed the Agency to consider adverse environmental effects when delisting source categories pursuant to section 112(c)(9), and thus we believe it is reasonable to consider such effects when determining whether it is appropriate to regulate such units under section 112, especially given that Congress did not limit our appropriate and necessary inquiry to the Utility Study. See CAA section 112(c)(9)(B)(ii).
Moreover, the other provisions of CAA section 112 that specifically discuss environmental effects have purposes that are distinguishable from CAA section 112(n)(1), and we do not believe one can reasonably draw the conclusion that the commenter does when comparing those provisions to CAA section 112(n)(1)(A). The lack of a requirement to consider environmental effects in CAA section 112(n)(1)(A) does not equate to a prohibition on the consideration of environmental effects as the commenter concludes. The EPA maintains that it reasonably concluded that we should protect against identified or potential adverse environmental effects absent clear direction to the contrary.
Concerning the consideration of the cumulative effect of HAP emissions from EGUs and other sources, we provided a reasonable interpretation of the statute and noted that our interpretation, unlike commenters, does not “ignore the manner in which public health and the environment are affected by air pollution. An individual that suffers adverse health effects as the result of the combined HAP emissions from EGUs and other sources is harmed, irrespective of whether HAP emissions from EGUs alone would cause the harm.”
The commenter does not explain its issues with our interpretation of how regulation under section 112 works—
The commenter also ignores the language of section 112(n)(1)(A). As explained in the proposed rule, the use of the terms section, subsection, and subparagraph in section 112(n)(1)(A) demonstrates that Congress was consciously distinguishing the various provisions of section 112 in directing EPA's action under section 112(n)(1)(A). Congress directed the Agency to regulate utilities “under this section,” not “under this subparagraph,” and accordingly EGUs should be regulated under section 112 in the same manner as other categories for which the statute requires regulation. Furthermore, the D.C. Circuit Court found that section 112(n)(1) “governs how the Administrator decides whether to list EGUs” and that once listed, EGUs are subject to the requirements of section 112.
The commenter provided no alternative theory for regulating EGUs under CAA section 112, other than to state that the EPA could regulate under CAA section 112(n)(1). However, even assuming for the sake of argument, that we could issue standards pursuant to CAA section 112(n)(1), we would decline to do because there is nothing in section 112(n)(1)(A) that provides any guidance as to how such standards should be developed. Any mechanism we devised, absent explicit statutory support, would likely receive less deference than a CAA section 112(d) standard issued in the same manner in which the Agency issues standards for other listed source categories. We would also decline to establish standards under section 112(n)(1) because Congress did provide a mechanism under CAA sections 112(d) and (f) for establishing emission standards for HAP emissions from stationary sources and it is reasonable to use that mechanism to regulate HAP emissions from EGUs.
Commenters characterize as “unintelligible” the EPA's position that it is “reasonable to conclude that costs may not be considered in determining whether to regulate EGUs” when “hazards to public health and the environmental are at issue (citing 76 FR at 24989). “Two commenters stated that a natural reading of the term “appropriate” would include the consideration of costs. According to the commenters, something may be found to be “appropriate” where it is “specially suitable,” “fit,” or “proper.”
One commenter asserts that on the face of CAA section 112(n)(1)(A), it is clear that the EPA is expected to consider costs. According to the commenter, that Congress intended that the EPA investigate and consider “alternative control strategies” for emissions as part of the section 112 (n)(1) Utility Study when making the “appropriate and necessary” determination refutes the notion that the Agency can, and indeed must, disregard the cost of regulation in making that determination, because the cost of a given emission “control strategy” is a central factor in any evaluation of “alternative” controls.
Further, according to commenters, it is well-settled that CAA regulatory provisions should be read with a presumption in favor of considering costs (citing
Commenters also assert that the EPA falsely represents that it “did not consider costs when making the “appropriate” determination in the EPA's December 2000 notice (76 FR at 24,989/2).
The commenters next argue that the Agency is compelled by the statute to consider costs based on a dictionary definition of “appropriate” and the CAA section 112(n)(1)(A) direction to consider alternative control strategies for regulating HAP emissions in the Utility Study.
Concerning the definition of “appropriate”, commenters stated:
Not only is it “reasonable” for EPA to consider costs in determining whether it is “appropriate” to regulate EGU HAP emissions, a natural reading of the term indicates that excluding the consideration of costs would be entirely unreasonable. Something may be found to be “appropriate” where it is “specially suitable,” “fit,” or “proper.”
The EPA believes the definition of “appropriate” that the commenters provide wholly support its interpretation and nothing about the definition compels a consideration of costs. It is appropriate to regulate EGUs under CAA section 112 because EPA has determined that HAP emissions from EGUs pose hazards to public health and the environment, and section 112 is “specially suitable” for regulating HAP emissions, and Congress specifically designated CAA section 112 as the “proper” authority for regulating HAP emissions from stationary sources, including EGUs. Section 112 of the CAA is “suitable [and] proper in the circumstances” because EPA has identified a hazard to public health and the environment from HAP emissions from EGUs and Congress directed the Agency to regulate HAP emissions from EGUs under that provision if we make such a finding. Cost does not have to be read into the definition of “appropriate” as commenter suggests. In addition, as stated elsewhere in response to comments, the Agency does not consider costs in any listing or delisting determinations, and the EPA maintains that it is reasonable to assess whether to list EGUs (
The commenters' argument that costs must be considered based on the CAA section 112(n)(1)(A) requirement to “develop and describe alternative control strategies” in the Utility Study is equally flawed. The argument is flawed because Congress did not direct the Agency to consider in the Utility Study the costs of the controls when evaluating the alternative control strategies. In addition, the EPA did not consider the costs of the alternative controls in the Utility Study, as implied by the commenter. Thus, even viewing section 112(n)(1)(A) in isolation, there is nothing in that section that compels EPA to consider costs. For the reasons described herein, we do not believe that it is appropriate to consider costs in determining whether to regulate EGUs under section 112.
Additionally, one commenter attempts to refute EPA's statement in the preamble to the proposed rule that the EPA did not consider costs in the 2000 finding by pointing to the only two mentions of cost in that notice. However, the EPA did not say that costs were not mentioned in the 2000 finding and a review of the regulatory finding will show that costs were not considered in the regulatory finding. 65 FR 79830 (December 20, 2000) (“Section III. What is EPA's Regulatory Finding?”).
On the facts, the EPA explained in the preamble to the proposed rule its interpretation of the phrase “after imposition of the requirements of [the Act]” as it related to the conduct of the Utility Study.
Although not required, the Agency in the preamble to the proposed rule conducted further analyses in support of the 2000 finding. In doing so, we considered a number of requirements that far exceed what Congress contemplated when enacting CAA section 112(n)(1)(A)), and our analyses still show that it remains necessary to regulate coal- and oil-fired EGUs under section 112. 76 FR 24991.
We maintain that we have reasonably interpreted the requirement to consider the hazards to public health and the environment reasonably anticipated to occur after imposition of the requirements of the Act as explained in the preamble to the proposed rule.
Moreover, Representative Oxley's statement cited by the commenter is not consistent with the express terms of CAA section 112(n)(1)(A) on this issue. Representative Oxley stated that the EPA was to take “into account compliance with all the provisions of the act and any other Federal, State, or local regulation and voluntary emission reductions,” but CAA section 112(n)(1)(A) directs the Agency to consider “imposition of the requirements of this chapter,” which means the CAA. The Agency reasonably focused on the requirements of the Clean Air Act, which are federally enforceable, and declined to include potential future reductions that may be attributable to voluntary emission reduction programs or state and local regulations that have no basis in the Clean Air Act and are not federally enforceable. In addition to the statutory direction not to consider such requirements, the EPA believes it is reasonable not to include potential reductions attributable to such requirements because the Agency cannot assure that such requirements and the attendant HAP reductions will remain absent regulation under section 112. Finally, the commenter implies that EPA's position is that the Agency will only consider requirements of the Act that directly regulate HAP emissions. The EPA never stated or suggested that interpretation and a fair reading of the proposed rule will demonstrate that EPA considered requirements that achieve co-benefit HAP emission reductions, for example the Transport Rule (known as CSAPR).
The commenter further asserts that the EPA erred when it concluded that it may “ `determine it is necessary to regulate under section 112' when the Agency is `uncertain whether imposition of the requirements of the CAA will address the identified hazards'” (citing 76 FR at 24,991/3). According to the commenter, the EPA “cannot take refuge in its own `uncertainty' to support a finding that it is `necessary' to regulate EGUs under section 112, and the Act precludes the EPA from “`err[ing] on the side of regulation'” in face of uncertainty (
As an initial matter, this comment is only addressing one aspect of the Agency's interpretation of the term necessary. As EPA stated at proposal:
If we determine that the imposition of the requirements of the CAA will not address the identified hazards, EPA must find it necessary to regulate EGUs under section 112. Section 112 is the authority Congress provided to address hazards to public health and the environment posed by HAP emissions and section 112(n)(1)(A) requires the Agency to regulate under section 112 if we find regulation is “appropriate and necessary.” If we conclude that HAP emissions from EGUs pose a hazard today, such that it is appropriate, and we further conclude based on our scientific and technical expertise that the identified hazards will not be resolved through imposition of the requirements of the CAA, we believe there is no justification in the statute to conclude that it is not necessary to regulate EGUs under section 112.
The EPA has determined that the imposition of the requirements of the CAA will not address the hazards to public health or hazards to the environment that EPA has identified; therefore, it is necessary to regulate EGUs under CAA section 112.
The EPA further interpreted the statute to allow the Agency to find that it is necessary to regulate EGUs under other circumstances, and it is with one of our additional interpretations that commenter takes issue. Specifically, the commenter argues that EPA's interpretation authorizes the Agency to find it necessary to regulate EGUs when we are uncertain it is necessary, but that misconstrues our interpretation and the record. At proposal, the EPA stated:
In addition, we may determine it is necessary to regulate under section 112 even if we are uncertain whether the imposition of the requirements of the CAA will address the identified hazards. Congress left it to EPA to determine whether regulation of EGUs under section 112 is necessary. We believe it is reasonable to err on the side of regulation of such highly toxic pollutants in the face of uncertainty. Further, if we are unsure whether the other requirements of the CAA will address an identified hazard, it is reasonable to exercise our discretion in a manner that assures adequate protection of public health and the environment. Moreover, we must be particularly mindful of CAA regulations we include in our modeled estimates of future emissions if they are not
The CAA requires EPA to exercise its discretion in determining whether regulation under section 112 is necessary, and the D.C. Circuit has stated that “there are many situations in which the use of the word `necessary,' in context, means something that is done, regardless of whether it is indispensible, to achieve a particular end.”
The commenter stated that EPA concedes that the Agency has not “clearly established” that regulation of HAP emissions under CAA section 112 is “indispensible.” The EPA has conceded nothing but, more importantly, the supposed standard that the commenter presents for evaluating whether it is necessary to regulate HAP emissions from EGUs is not required by the statute. Even the limited legislative history on which the commenter incorrectly relies does not espouse such a standard. The commenter specifically takes issue with EPA's statement that the Agency may find it is necessary to regulate EGUs under CAA section 112 if we are “uncertain whether imposition of the other requirements of the CAA will sufficiently address the identified hazards.” 76 FR at 24990. The commenter has again misinterpreted the Agency's position by stating that “EPA construes CAA section 112(n)(1)(A) as permitting it to find that it is “necessary” to regulate EGUs even where the Agency does not actually know whether it is “necessary” to regulate EGUs.” Instead, the EPA maintains that it may be necessary to regulate EGUs under CAA section 112 if we identify a hazard to public health or the environment that is appropriate to regulate today and our projections into the future do not clearly establish that the imposition of the requirements of the CAA will address the identified hazard in the future. Making a prediction about future emission reductions from a source category is difficult for statutory provisions that do not mandate direct control of the given source category or pollutants of concern. We maintain that erring on the side of caution is appropriate when the protection of public health and the environment from HAP emissions is not assured based on our modeling of future emissions.
Furthermore, as we stated in the preamble to the proposed rule, we believe it would be reasonable to find it appropriate
The commenter stated that, in support of this reading of the CAA, the EPA invokes the decision of the U.S. Court of Appeals for the D.C. Circuit in
The commenter asserts that EPA misinterprets the “under this section” language of CAA section 112(n)(1); overstates the significance of the
One commenter stated that if Congress had intended that EPA regulate EGU HAP emissions only through a MACT standard, Congress could have—and presumably would have—directed the Agency to regulate EGU emissions “under CAA section 112(d).” Thus, the commenter maintained that EPA's authority to regulate EGU HAP emissions is not derived from any particular subsection of CAA section 112. Rather, the commenter stated that EPA is authorized to regulate “under this section”—
The statute directs the Agency to regulate EGUs under section 112 if the Agency finds such regulation is appropriate and necessary. Once the appropriate and necessary finding is made, EGUs are subject to section 112 in the same manner as other sources of HAP emissions. Section 112(n)(1)(A) provision provides, in part, that: `[t]he Administrator shall perform a study of the hazards to public health reasonably anticipated to occur as a result of emissions by electric utility steam generating units of pollutants listed under subsection (b) of this section after imposition of the requirements of this chapter. * * * The Administrator shall regulate electric utility steam generating units
In the first sentence, Congress described the study and directed the Agency to evaluate the hazards to public health posed by HAP emissions listed
We maintain that our interpretation of the statute gives meaning to all the words, and the commenter's interpretation does not give any particular meaning to the requirement to “regulate under this section [112]”. The commenter is correct that Congress could have in CAA section 112(n)(1)(A) directed EPA to regulate HAP from EGUs under CAA section 112(d) after making the appropriate and necessary finding, but the commenter presumes too much when it stated that Congress would have directed the Agency to regulate HAP emissions from EGUs in such a manner if that is what Congress wanted, simply by including the phrase “regulate under this paragraph” or “regulate under this subparagraph” instead of directing the Agency to “regulate under this section''. It did not do so.
As we explained in the section II.A. of the proposed rule, CAA section 112 establishes a mechanism to list and regulate stationary sources of HAP emissions. 76 FR 24980-81. Regulation under CAA section 112 generally requires listing under CAA section 112(c), regulation under CAA section 112(d), and, for sources subjected to MACT standards, residual risk regulations under CAA section 112(f) (as necessary to protect human health and the environment with an ample margin of safety). A determination that EGUs should be listed once the prerequisite appropriate and necessary finding is made is wholly consistent with the language of section 112(n)(1)(A), and listed sources must be regulated under CAA section 112(d).
As noted above, Congress used the terms section, subsection, and subparagraph in section 112(n)(1)(A). The use of these three terms demonstrates that Congress was consciously distinguishing between the various provisions of section 112. Congress directed the Agency to regulate utilities “under this section,” and accordingly EGUs should be regulated in the same manner as other categories for which the statute requires regulation.
Furthermore, the flaws in the commenter's interpretation are highlighted by other CAA section 112 provisions wherein Congress provided specific direction as to the manner of regulation. For example, CAA section 112(m)(6) requires the Administrator to determine “whether the other provisions of
In addition, CAA section 112(n)(3) provides that when the Agency is “promulgating any standard under this section [112] applicable to publicly owned treatment works, the Administrator may provide for control measures that include pretreatment of discharges causing emissions of hazardous air pollutants and process or product substitutions or limitations that may be effective in reducing such emissions.” Finally, CAA section 112(n)(5) directs the Agency to assess hydrogen sulfide emissions from oil and gas extraction and “develop and implement a control strategy for emissions of hydrogen sulfide to protect human health and the environment * * *
The commenters appear to interpret the word “alternative control strategies” to mean something other than the traditional control technologies and control measures that are used to control HAP emissions from EGUs. We do not believe that is a reasonable interpretation of the statute, and the Agency did not interpret the statute in that manner when it conducted the Utility Study. In Chapter 13 of the Utility Study, the EPA considered a range of control measures that would reduce the different types of HAP emitted from EGUs.
Given the manner in which the Agency conducted the Utility Study, the EPA interpreted the statutory direction as a requirement to set forth the potential alternative control options available to EGUs to comply with CAA section 112 standards in the event the Agency determined regulation under section 112 was appropriate and necessary. The EPA's development and discussion in the Utility Study of alternative control strategies for complying with the standards would help prepare EGUs to comply with the standards if promulgated. Thus, the EPA interpreted the direction to address control strategies in the Utility Study as a request to identify the controls available to EGUs for addressing HAP emissions, and such information would, of course, be relevant if EPA determined that such emissions warranted regulation under section 112.
Furthermore, the EPA establishes CAA section 112(d) standards for stationary sources and it is the responsibility of the sources to comply with the standards using any mechanism available, including pre-combustion and post-combustion measures. Also, the establishment of a MACT standard under CAA section 112(d)(2) and (3) is a two-step process. In the first step, the Agency establishes a floor based on the performance of the best controlled unit or units.
The commenter also takes issue with EPA's statement in the proposed rule that “use of the terms section, subsection, and subparagraph” “demonstrates that Congress was consciously distinguishing the various provisions of section 112 in directing the conduct of the study and the manner in which the Agency must regulate EGUs,” if EPA determines that it is appropriate and necessary to regulate EGUs. See 76 FR at 24,993/2.
One commenter does not agree with the EPA's finding that the word “subsection” in the first sentence of CAA section 112(n)(1)(A) demonstrates that Congress was consciously distinguishing between the various provisions of CAA section 112 in directing the conduct of the study and the manner in which the Agency must regulate EGUs,” were the EPA to “find[ ] it appropriate and necessary to do so.”
The commenter also asserts that the EPA mistakenly relies on section 112(c)(6) when the EPA states that “ `where Congress wished to exempt EGUs from specific requirements of section 112, it said so explicitly. Congress did not exempt EGUs from the other requirements of section 112,' ” and thus the Agency is “ `required to establish emission standards for EGUs consistent with the requirements set forth in section 112(d)' ” (citing 76 FR at 24,993 (internal quotation omitted)).
According to the commenter, nothing in section 112(c)(6) indicates how (or even whether) EGU HAP emissions should be regulated under section 112; paragraph (c)(6) serves only to reiterate that the regulation of such emissions is to occur (if at all) as is provided by section 112(n)(1). The commenter also asserts that the EPA mistakenly relies on
The commenter's argument that the EPA erred because we did not explain why section CAA section 307(d)(1)(C) contemplates regulations under CAA section 112(n) is without merit. It is correct that the Agency believes EGUs should be regulated in the same manner as other sources if the appropriate and necessary finding is made because of the structure of CAA section 112. Nothing in CAA section 112(n)(1) requires or implies that the Agency should or must establish standards for EGUs under that provision. Furthermore, unlike CAA sections 112(n)(3) and 112(n)(5) that commenter cites, CAA section 112(n)(1)(A) does not provide any guidance concerning the manner in which EPA is authorized or required to regulate sources under CAA section 112.
Even if we agreed that regulation under CAA section 112(n)(1) was a viable option for EGUs, we would still have listed and regulated EGUs like other sources because CAA section 112(d) provides a statutory framework for regulating HAP emissions from sources and CAA section 112(n)(1) does not. We believe that even if CAA section 112(n)(1) were available to regulate EGUs, there would be sufficient uncertainty about the legal vulnerability of such an approach to caution against employing it. This legal uncertainty would be particularly troubling in light of the fact that we have identified hazards to public health and the environment from HAP emissions from EGUs that warrant regulation, and these regulations are long overdue.
The commenter also takes issue with our statement in the preamble to the proposed rule that the use of the words “section”, “subsection”, and “subparagraph” in CAA section 112(n)(1)(A) “demonstrates that Congress was consciously distinguishing the various provisions of section 112 in directing the conduct of the study and the manner in which the Agency must regulate EGUs.”
The commenter also stated that the EPA relied on CAA section 112(c)(6) to support a conclusion that EGUs must be regulated under CAA section 112(d). The commenter takes the EPA's statements out of context. The statement in whole read:
Furthermore, the D.C. Circuit Court has already held that section 112(n)(1) “governs how the Administrator decides whether to list EGUs” and that once listed, EGUs are subject to the requirements of CAA section 112.
As can be seen from this passage, the Court cited section 112(c)(6) as an example of Congress' intent regarding regulating EGUs under CAA section 112. The commenter cited the last clause of the last sentence of the paragraph quoted above without including the prefatory clause “once listed,” and, without that clause, the statement is not fairly characterized. The point the EPA was making in that paragraph is that EGUs are a listed source category and listed sources must be regulated under CAA section 112(d) unless the EPA delists the source category.
According to the commenter, the EPA must consider both whether the regulation of EGUs is “appropriate and necessary” under section 112(n)(1) and address anew whether the Agency is authorized by section 112 to list EGUs under section 112(c) at all. The commenter asserts that on the face of the proposal, the EPA has not revisited the question whether the “listing” of EGUs under section 112(c) is consistent with congressional intent.
As stated in the preamble to the proposed rule, CAA section 112(n)(1)(A)
The EPA did not rely on the
The commenter also argues that Congress intended that EGUs be treated differently from all other “major sources” to which the “delisting” provisions of CAA section 112(c)(9), and the standard-setting provisions of CAA section 112(d) necessarily and automatically apply. Therefore, according to the commenter, the EPA's proposal to utilize the criteria of CAA section 112(c)(9) to inform its findings under CAA section 112(n)(1)(A) treats EGUs exactly the same as all other major source categories, is contrary to congressional intent, and thus unlawful. The commenter goes on to state that in exercising its discretion to define “hazards to public health” as the phrase is used in CAA section 112(n)(1)(A), the EPA would be better served to consider the “residual health risk” provisions of CAA section 112(f)(2). Those provisions provide a better analogy to the establishment of standards for EGUs under CAA section 112 than do the “de-listing” criteria of CAA section 112(c)(9).
The commenter believes the category-specific criteria of paragraph (c)(9) are a poor fit for an evaluation of “hazards to public health” that should reasonably include such factors as the affected population, the characteristics of exposure, the nature of the health effects, and the uncertainties associated with the data. The commenter states that, while CAA section 112(n)(1)(A) does not expressly include any requirement that EGU emissions be regulated with an “ample margin of safety,” that standard is more appropriate than the “one-in-a-million” cancer risk standard of CAA section 112(c)(9)(B)(i) that EPA proposes to employ.
The commenter also suggests that the “ample margin of safety standard” of CAA section 112(f)(2) is a better fit than the one-in-a-million standard set forth in CAA section 112(c)(9)(B)(1) for evaluating hazards to public health. The commenter asserts that an evaluation of “hazards to public health” should include such factors as the affected population, the characteristics of exposure, the nature of the health effects, and the uncertainties associated with the data. However, the EPA did not rely solely on the delisting provisions for evaluating hazards to public health as commenter suggests. In fact, the EPA considered all of the factors the commenter suggests in making our finding.
The commenters who generally supported the 2000 finding also commented on specific aspects of the finding. Several commenters asserted that while the evidence on Hg alone supports the finding, the potential harm from non-Hg HAP further supported the 2000 finding. Several commenters noted that new science continues to support the 2000 finding. Several commenters also stated that the “appropriate” finding was further supported because numerous control options were available at the time of the finding that would reduce HAP emissions. One commenter concurred with EPA that regulating natural gas-fired EGUs was not appropriate and necessary because the impacts due to HAP emissions from such units are negligible based on the results of the Utility Study.
Several commenters addressed the 2005 reversal of the 2000 finding. Several commenters specifically supported the vacatur of the 2005 action. Other commenters asserted that the 2005 action was proper, and that EPA reverted back to the 2000 finding in the proposed rule without adequate explanation or support. Several commenters cited the 2005 action as invalidating the 2000 finding, specifically noting that EPA concluded that “no hazards to public health” remained after accounting for emission reductions under CAIR. These commenters assert that EPA's current position is illegal because EPA took the exact opposite position on the interpretation of the term “necessary” in its 2005 reversal, and, thus, deserves no judicial deference. One commenter stated that in 2005 EPA recognized the potential for excessive regulation created by CAA section 112 and determined that the 2000 finding lacked foundation.
Several commenters generally disagreed with the 2000 finding, with two commenters stating that EPA did not have a rational justification for it and another claiming that it was fraught with misinformation and overestimating assumptions. One commenter claimed that EPA did not explain the terms “appropriate” and “necessary” in the 2000 finding and that the emission control analysis was inadequate. Two commenters stated that the 2000 finding was based on data that was more than 10 years old, which causes serious concern regarding the validity of the findings because technology, the regulatory environment, and the economic climate have evolved. Furthermore, because the Utility Report underestimated emissions controls that EGUs would install by 2010 and additional controls that would be later required by the CSAPR, the basis for EPA's 2000 finding has changed. Several commenters stated that a “plausible link” between anthropogenic Hg and MeHg in fish is not an adequate reason for the 2000 finding. Several commenters claim that EPA only identified health concerns for Hg (and potentially Ni) but not other HAP from coal-fired EGUs in the 2000 finding, and, thus, cannot regulate HAP other than Hg because the 2000 finding authorizes only the regulation of Hg. One commenter questioned the Hg emissions underlying the 2000 finding, specifically the fraction of total deposition attributable to U.S. EGUS and the fact that EPA projected an increase in U.S. EGU emissions from 1990 to 2010 though emissions actually declined.
Several commenters raised procedural issues related to the 2000 finding. Several commenters stated that the 2000 finding failed to provide public notice and comment. According to the commenters, the CAA requires that any decision made under CAA section 112(n) must go through public notice and comment. The commenters further stated that the failure to provide public notice and comment means that this MACT is outside EPA's statutory authority. One commenter stated that because the 2000 finding was never “fully ventilated” in front of the D.C. Circuit, the EPA's authority to regulate EGUs under CAA section 112(d) is directly at issue. The commenters claim that specific issues did not undergo
The EPA agrees that reviewing courts defer to the reasoned scientific and technical decisions of an Agency charged with implementing complex statutory provisions such as those at issue in this case. As EPA stated in the preamble to the proposed rule, the EPA maintains that the 2000 finding was reasonable and based on well-supported evidence available at the time, including the Utility Study, the Mercury Study,
The EPA agrees with the commenters that Congress did not exempt EGUs from section 112(d) HAP emission limits while simultaneously limiting emissions at other sources with less HAP emissions. Congress simply provided EPA with a separate path for listing EGUs by requiring that the Agency evaluate HAP emissions from EGUs and determine whether regulation under CAA section 112 was appropriate and necessary. Since 1990, the EPA has promulgated regulations requiring the use of available control technology and other practices to reduce HAP emissions for more than 170 source categories. U.S. EGUs are the most significant source of HAP in the country that remains unaddressed by Congress's air toxics program. The EPA listed EGUs in 2000 because the considerable amount of available data supported the conclusion that regulation of EGUs under CAA section 112 was appropriate and necessary. That finding was valid at the time, and EPA reasonably added EGUs to the CAA section 112(c) list of sources that must be regulated under CAA section 112.
The EPA acknowledges that we did not expressly define the terms appropriate and necessary in the 2000 finding, but the finding is instructive in that it shows that EPA considered whether HAP emissions from EGUs posed a hazard to public health and the environment and whether there were control strategies available to reduce HAP emissions from EGUs when determining whether it was appropriate to regulated EGUs.
The EPA disagrees with commenters that suggest it was not “rational” to determine that it was appropriate to regulate HAP emissions from EGUs due to the cancer risks identified in the Utility Study or the potential concerns associated with other HAP emissions from EGUs. Nothing in CAA section 112(n)(1)(A) suggests that EPA must determine that every HAP emitted by EGUs poses a hazard to public health or the environment before EPA can find it appropriate to regulate EGUs under CAA section 112. In fact, the EPA maintains that it must find it appropriate and necessary to regulate EGUs under CAA section 112 if it determines that any one HAP emitted from EGUs poses a hazard to public health or the environment that will not be addressed through imposition of the requirements of the Act. The EPA disputes the commenters' conclusion that the 2000 finding was limited to Hg and Ni emissions, but, even if it were, the EPA reasonably concluded that EGUs should be listed pursuant to CAA section 112(c) based on the Hg and Ni finding. As stated in the 2000 finding, cancer risks from some non-Hg metal HAP (including As, Cr, Ni, and Cd) were not low enough to be to eliminate as potential concern.
The EPA disagrees that there is any concern regarding the validity of the 2000 finding or that the emissions information provided in the 2000 finding makes the finding “questionable” as stated by some of the commenters. The EPA maintains that the 2000 finding was sound and fully supported by the record available at the time, including the future year emissions projections. Therefore, the listing of EGUs is valid based on that finding alone. Even though Hg emissions have decreased since the 2000 finding instead of increasing as projected, the new technical analyses confirm that Hg emissions from EGUs continue to pose hazards to public
The EPA agrees with the commenters who assert that the 2005 action was in error and disagrees with the commenters that the 2005 action invalidated the 2000 finding. As fully described in the preamble to the proposal, the EPA erred in the 2005 action by concluding that the 2000 finding lacked foundation. The 2005 action improperly conflated the “appropriate” and “necessary” analyses by addressing the “after imposition of the requirements of the Act” in the appropriate finding as well as the necessary finding. The EPA also indicated that it was not reasonable to interpret the necessary prong of the finding as a requirement to scour the CAA for alternative authorities to regulate HAP emissions from stationary sources, including EGUs, when Congress provided section 112 for that purpose. The EPA asserts that the 2000 finding was sound and fully supported by the record available at the time for all the reasons stated in this final rule and the proposed rule. The 2005 action interpreted the statute in a manner inconsistent with the 2000 finding and attempted to delist EGUs without complying with the mandates of CAA section 112(c)(9)(B).
The EPA disagrees with the commenters who raise concerns about the validity of the 2000 finding because the data on which that finding was based were more than 10 years old. The EPA made the finding at that time based on the scientific and technical information available, and the finding is wholly supported by that information. In addition, even though not required to do so, the EPA has since conducted new technical analyses utilizing the best information available in 2010 as several years have passed since the 2000 finding. These new analyses confirm that HAP emissions from EGUs continue to pose a hazard to public health and the environment, even after taking into account emission reductions that have occurred since 2000 from promulgated rules, settlements, and consent decrees.
Contrary to the commenter's assertion, the EPA did not violate CAA section 307(d) by not providing a notice and comment opportunity before making the December 2000 appropriate and necessary finding. One commenter challenged EPA's 2000 finding and listing on the same grounds, and the D.C. Circuit dismissed the case because CAA section 112(e)(4) clearly states that listing decisions cannot be challenged until the Agency issues final emission standards for the listed source category.
The EPA also disagrees with the commenters' characterization of the
Other commenters disagreed that the new analyses confirm that it remains appropriate and necessary to regulate U.S. EGUs. One commenter claims that EPA tried to use the new technical analyses to provide retroactive justification for the 2000 finding, which only found “plausible links” of health effects and “potential concerns” of health effects of certain metal emissions, dioxins and acid based aerosols. The commenter also asserted that none of these new analyses demonstrate that EGU regulation under section 112 is necessary and appropriate.
One commenter agreed that EPA may supplement its finding with new information, analyses and arguments to reaffirm the 2000 finding up until EPA issues final emissions standards. The commenter noted that the CAA does not freeze the finding. However, another commenter argued that EPA does not have the authority to rely on new technical analyses because the CAA requires EPA to make the finding on the basis of the Utility Study alone. According to that commenter, the EPA unreasonably stretched the language of CAA section 112 by considering new technical analyses.
Citing a report from Dr. Willie Soon that was submitted to the SAB, one commenter stated that the new technical analyses supporting the proposed rule do not conform to the Information Quality Act, which requires that information relied on by EPA be accurate, reliable, unbiased, and presented in a complete and unbiased manner.
Although these new analyses were not required, the EPA agrees with the commenters that stated that EPA is authorized to conduct additional analyses to confirm the 2000 finding. The EPA disagrees with the commenter's assertion that the Agency is not authorized to consider new information and at the same time unable to use the information available in 2000 because, according to the commenter, that information is “stale.” Under this theory, the Agency could not ever make an appropriate and necessary finding prospectively, thereby excusing the Agency from its obligations to protect public health and the environment because it did not diligently act in undertaking its statutory responsibility to establish CAA section 112(d) standards within two years of listing EGUs.
The EPA disagrees with the commenter's implication that EPA conducted the new analyses because of alleged flaws in the 2000 finding. As explained in detail in the preamble to the proposed rule, the 2000 finding was wholly valid and reasonable based on the information available to the Agency at that time, including the Utility Study. Further, the EPA maintains that had it complied with the statutory mandate to issue CAA section 112(d) standards within two years of listing EGUs, the EPA would likely have declined to conduct new analyses. The EPA conducted new analyses because over 10 years had passed since the 2000 finding, and EPA wanted to evaluate HAP emissions from U.S. EGUs based on the most accurate information available, though the Agency was not required to reevaluate the 2000 finding. In conducting the new analyses, the EPA used this updated information to further support the finding.
The EPA strongly disagrees with the commenter that stated that EPA failed to conform to the Information Quality Act. The EPA used peer reviewed information and quality-assured data in all aspects of the technical analyses used to support the appropriate and necessary finding supporting this regulation. In addition, the EPA submitted the Hg Risk TSD to the SAB for peer review, which “supports the overall design of and approach to the risk assessment and finds that it should provide an objective, reasonable, and credible determination of the potential for a public health hazard from mercury emitted from U.S. EGUs.”
The EPA acknowledges that the current Hg emissions estimate would not be the same as the 2016 Hg emissions estimate given that compliance with CSAPR is anticipated to have some Hg co-benefits. For this reason, the EPA reflected emission reductions anticipated from CSAPR in the Hg deposition modeling for 2016 in the Hg Risk TSD. In the final rule, the EPA revised the estimate of Hg emissions remaining from U.S. EGUs in 2016, which includes additional emission reductions anticipated from the final CSAPR. The revised estimate shows that U.S. EGUs would emit 27 tons of Hg in 2016. Although EPA does not use the current Hg emissions estimates in any of the risk calculations, the EPA estimates that current Hg emissions are 29 tons. Conclusions about the trend between current emissions and emissions in 2016 are limited by the fact that different methods were used to compute the two estimates, as fully explained in the revised Emissions Overview memo in the docket.
The EPA disagrees with the commenter's assertion that incorrect Hg emission factors result in incorrect 2016 emissions. The 2016 projected Hg emissions are not based on emissions factors. The 2016 Hg emissions are computed by the IPM based on forecasts of demand, fuel type, Hg content of the fuel, and the emissions reductions resulting from each unit's configurations. The speciation factors referenced by the commenter provide a basis for the speciation of total projected Hg emissions into particulate, divalent gaseous, and elemental species, and do not impact the total amount of Hg emissions.
The EPA agrees with commenters who noted that EGU sources are the predominant source of U.S. anthropogenic Hg emissions, and in particular the oxidized and particulate forms of Hg that are of primary concern for Hg deposition.
Several commenters noted that Hg emissions from U.S. EGUs are small when compared to global Hg emissions totals and natural sources within the U.S. These commenters used a variety of information to support alternative conclusions about the necessity to control U.S. EGU emissions to reduce Hg risk: global Hg emissions inventories, global and regional photochemical modeling research, and observation-based assessments. A commenter stated that EPA has not acknowledged the dramatic decline in Hg emissions from U.S. EGUs since the late 1990s (approximately 50 percent) to the current level or consider the relative magnitude of Hg emissions from U.S. EGUs compared to other sources, natural (such as fires) and human-caused.
The EPA also disagrees with the commenters' assertion that EPA has not acknowledged the decline in Hg emissions for the U.S. EGUs since the late 1990s. The EPA analyzed historical, current, and future projected Hg emissions from the power generation sector, as cited in the preamble to the proposed rule. The EPA also disagrees with the commenters' assertions that EPA failed to consider the relative magnitude of Hg emissions from U.S. EGUs compared to other sources. As noted in the Hg Risk TSD, the EPA modeled Hg emissions from U.S. and non-U.S. anthropogenic and natural sources to estimate Hg deposition across the country. The EPA also determined the contribution of Hg emissions from U.S. EGUs to total Hg deposition in the U.S. by running modeling simulations for 2005 and 2016 with Hg emissions from U.S. EGUs set to zero. Based on the Hg Risk TSD, Hg emissions from U.S. EGUs pose a hazard to public health based on the total of 29 percent of modeled watersheds potentially at-risk. Our analyses show that of the 29 percent of watersheds with population at-risk, in 10 percent of those watersheds U.S. EGU deposition alone leads to potential exposures that exceed the MeHg RfD, and in 24 percent of those watersheds, total potential exposures to MeHg exceed the RfD and U.S. EGUs contribute at least 5 percent to Hg deposition.
The commenters suggest that Hg emissions from U.S. EGUs represent a limited portion of the total Hg emitted worldwide, including anthropogenic and natural sources. While EPA acknowledges that Hg emissions from U.S. EGUs are a small fraction of the total Hg emitted globally, it views the environmental significance of Hg emissions from U.S. EGUs and other domestic sources as a more germane consideration. Mercury is emitted from EGUs in three forms. Each form of Hg has specific physical and chemical properties that determine how far it travels in the atmosphere before depositing to the landscape. Although gaseous oxidized Hg and particle-bound Hg are generally local/regional Hg deposition concerns, all forms of Hg may deposit to local or regional watersheds. U.S. coal-fired power plants account for over half of the U.S. controllable emissions of the quickly depositing forms of Hg. Although emissions from international Hg sources contribute to Hg deposition in the U.S., the peer reviewed scientific literature shows that Hg emissions from U.S. EGUs in the U.S. significantly enhance Hg deposition and the response of ecosystems in the U.S.
Another commenter suggested that current research shows that models of Hg atmospheric fate and transport overestimate the local and regional impacts of some anthropogenic sources, such as U.S. EGUs. Thus, according to the commenter, calculated contributions to Hg deposition and fish tissue MeHg levels from these sources represent upper bounds of actual contributions,
The EPA asserts that the numbers suggested by the commenter are inaccurate, as it is not appropriate to adjust EPA's deposition estimates based on previous Hg modeling done with older Hg chemistry, in-plume reactions that have not been explicitly identified, and erroneous adjustments to Hg boundary inflow. Recent research has shown that ambient Hg concentrations have been decreasing in the northern hemisphere since 2000.
The EPA also disagrees with the commenter's interpretation of the applicability of wildfire Hg emissions to
The EPA disagrees with the assertion that EPA failed to consider the relative magnitude of Hg emissions from U.S. EGUs compared to other sources and disagrees with the interpretation of EGU deposition presented in the ENVIRON report. As noted in the Hg Risk TSD, the EPA modeled Hg emissions from U.S. and non-U.S. anthropogenic and natural sources to estimate Hg deposition across the country. The EPA also determined the contribution of Hg emissions from U.S. EGUs to total Hg deposition in the U.S. by running modeling simulations for 2005 and 2016 with Hg emissions from U.S. EGUs set to zero. Hg emissions from U.S. EGUs pose a hazard to public health based on the total of 29 percent of modeled watersheds potentially at-risk. Our analyses show that of the 29 percent of watersheds with population at-risk, in 10 percent of those watersheds U.S. EGU deposition alone leads to potential exposures that exceed the MeHg RfD, and in 24 percent of those watersheds, total potential exposures to MeHg exceed the RfD and U.S. EGUs contribute at least 5 percent to Hg deposition. The ENVIRON report provides no risk analysis of EGU contribution.
The EPA disagrees that research
Recent studies in central Wisconsin and central California suggest the opposite may happen; elemental Hg may be oxidized to Hg(II) in plumes.
The EPA agrees with the commenter that the CMAQ modeling with 12 km grid resolution may provide a lower bound estimate on EGU contribution as higher impacts using finer grid resolution are possible. The commenter's assertion that EGU impacts are likely higher further supports the final conclusions of the exposure modeling assessment. The EPA notes that the application of a photochemical model at a 12 km grid resolution for the entire continental U.S. is more robust in terms of grid resolution and scale that anything published in literature and represents the most advanced modeling platform used for a national Hg deposition assessment.
The EPA disagrees that it did not conduct an assessment comparing CMAQ total Hg wet deposition estimates to MDN data. The Air Quality Modeling TSD clearly shows a comparison of CMAQ estimated total Hg wet deposition with MDN data for the entire length of the modeling period. The CMAQ wet deposition of Hg has been and will continue to be extensively evaluated against MDN sites.
The EPA disagrees that the model performance presented in the air quality TSD is insufficient. The EPA asserts that the model performance evaluation is generally similar to the level of model performance presented in literature. One commenter presented the results of several Hg modeling studies as providing information that the commenter believes to be relevant for this assessment in terms of model performance metric estimation and the level of model performance evaluation shown for assessments modeling Hg near point sources. For example, one cited study titled “Modeling Mercury in Power Plant Plumes” models near-source Hg chemistry from U.S. EGUs, but provides absolutely no information about model performance evaluation.
Another commenter identified two studies as supposedly having Hg modeling results that are applicable to EPA's analysis.
One commenter agreed with the Agency's assessment of the potential for deposition “hotspots” that shows that Hg deposition near EGUs can be three times as large as the regional average. The commenter stated that this excess Hg deposition would substantially increase the health and environmental risks associated with emissions at these sites. The same commenter also stated that EPA applied a conservative methodology to quantify near-source Hg deposition. The commenter stated that maximum excess local Hg deposition may be significantly underestimated by averaging high deposition sites downwind of an EGU in the direction of prevailing winds with lower excess deposition at locations close to but frequently upwind of the facility. The same commenter suggests that had EPA used CMAQ and individual 12x12 km
One commenter stated that the Hubbard Brook Research Foundation issued a report in 2007 that identified five Hg hotspots, one of which was in the Adirondack Park, along with four suspected hotspots.
One commenter stated that there is there is no evidence of Hg hotspots due to local deposition associated with coal-fired power plants. According to the commenter, the EPA's use of a 50 km radius to calculate hotspots is flawed. The commenter stated that modeling studies show that deposition of Hg emitted from power plants is not confined to a 50-km radius around the plants and that most emissions from power plants travel beyond 50 km.
Several commenters stated that the EPA does not adequately define hotspots in this proposed rule. Those same commenters cited a previous EPA definition of hotspots as “a waterbody that is a source of consumable fish with MeHg tissue concentrations, attributable solely to utilities, greater than EPA's MeHg water quality criterion of 0.3 mg/kg” (milligrams per kilogram).
One commenter stated that Hg concentrations are not always highest at sites closest to a major source. The commenter referred to a study
One commenter provided information from a non-peer reviewed report with wet Hg deposition measurements downwind from the coal-fired power plant Crist in Pensacola, FL. The commenter stated that using the same data from these same wet deposition sites, one study
Another commenter stated that Plant Crist installed a wet scrubber and has operated that scrubber continuously since December 2009. The commenter stated that the scrubber reduces total Hg emissions by about 70 percent and reduces emissions of reactive gaseous Hg by about 85 percent. The commenter cited a non-peer reviewed conference presentation
Two commenters stated that a study by the Department of Energy (DOE) that collected and analyzed soil and vegetation samples for Hg near three U.S. coal-fired power plants—one in North Dakota, one in Illinois, and one in Texas—found no strong evidence of “hotspots” around these three plants.
Two commenters stated that analysis of long-term trends in Hg emissions from coal-fired EGUs and wet deposition in Florida concluded that statistical analysis does not show evidence of a significant relationship between temporal trends in Hg emissions from coal-fired EGUs in Florida and Hg concentrations in precipitation during 1998 to 2010.
Two commenters stated that the Hg Risk TSD presents no information, summary statistics, and/or actual calculations showing how excess deposition within 50 km of an EGU source is obtained. The commenters stated that by assessing only Hg deposition attributable to EGUs, the EPA fails to provide a context for all other sources of Hg deposition. The commenters stated that the Agency does not explain why deposition from the top 10 percent of EGU Hg emitters does not decline, despite substantial reductions in modeled Hg emissions from those sources between 2005 and 2016.
Two commenters stated that the CMAQ model has limitations when used to predict local deposition and tends to overestimate local deposition. The commenters stated that modeling studies using either a plume model or an Eulerian model predict that 91 to 96 percent of the Hg emitted by an EGU travels beyond 50 km.
The EPA agrees that there is no generally agreed-upon definition of “hotspot.” As discussed in the preamble and TSD, for the purposes of the appropriate and necessary finding, the EPA determined that information on the potential for excess deposition of Hg in areas surrounding power plants would be useful in informing the finding. The EPA disagrees with some commenters who misinterpreted the intent of the Hg deposition hotspot analysis. Specifically, the analysis is not of “Hg hotspots”, which are often defined as high Hg concentration in fish, but rather of Hg deposition hotspots, defined as excess local Hg deposition around U.S. EGUs, as clarified in the new Local Deposition TSD. Because EPA did not identify “Hg hotspots” of high Hg concentrations in fish, the EPA's MeHg water quality criterion of 0.3 mg/kg is irrelevant to EPA's analysis of excess local Hg deposition for this rule.
The EPA disagrees that the analysis assumes that deposition of Hg is confined to a 50-km radius around power plants. The purpose of the EPA's analysis was to evaluate whether there existed “excess deposition of Hg in nearby locations within 50 km of EGUs that might result in Hg deposition `hotspots'.” As explained further in the new TSD, the EPA calculated the average EGU-attributable deposition (based on CMAQ modeling of Hg deposition) in the area 500 km around each plant and the average EGU-attributable deposition in the area 50 km around each plant. The difference between those two values is the excess local deposition around the plant. The EPA does not suggest Hg emissions from power plants stop at 50 km from the source. Some portion of EGU emissions deposit before 50 km, and some portion travels beyond 50 km. In addition, Hg disperses as it transports, so the average EGU contribution can be lower in areas beyond 50km relative to areas within 50km even though Hg emissions from EGUs are depositing into U.S. watersheds.
The EPA disagrees with some commenters' interpretation of the analysis as being focused on local deposition from all sources. In fact, the focus was on excess local deposition, rather than all local deposition. The EPA has clarified the purpose of the excess local deposition analysis in the new TSD. The EPA agrees that all EGUs add to local deposition, however, not all EGUs have local deposition that greatly exceeds regional deposition, which is the relevant question. The EPA disagrees that the DOE study referenced by the commenters attempted to assess the same analytical question as EPA's analysis. The DOE study focused on comparisons of total deposition near and far from power plants. The EPA's analysis did not focus on total Hg deposition, because as EPA acknowledges throughout its analysis, global sources of Hg deposition account for a large percentage of total Hg deposition. In addition, including global sources of Hg deposition would obscure the comparison of local and regional U.S. EGU-attributable Hg deposition. Because of regional deposition from both domestic and global sources of Hg, total Hg deposition at any location is unlikely to be highly correlated with local sources. The EPA's analysis focused on U.S. EGU-attributable Hg deposition and demonstrates that for some plants (especially those with high Hg emissions), there is local deposition of Hg that exceeds the average regional deposition around the plant.
The EPA's analysis shows heterogeneity in the amount of excess local deposition around plants. The new Local Deposition TSD shows that some plants can have local deposition that is less than the regional average deposition, suggesting that most of the Hg from those plants is transported regionally or that other EGUs in the vicinity of those plants dominate the deposition of Hg near the plants. This does not detract from the overall finding that around some power plants with high levels of Hg emissions excess local deposition is on average three times the regional EGU-attributable deposition around those plants.
The EPA disagrees that the Hg Risk TSD did not provide sufficient information regarding the excess local deposition calculation. Nonetheless, the EPA has further clarified the methodology in the new Local Deposition TSD, including further descriptions of the method used to calculate the local and regional deposition around power plants along with maps and tables of results.
The EPA disagrees with the commenters that stated that the discussion of local deposition in the Hg Risk TSD did not demonstrate that Hg deposition from the top 10 percent of EGU Hg emitters declines. Table 1 of the new Local Deposition TSD clearly shows that mean local deposition (within 50km of a plant) for the top 10 percent of emitters declines from 4.89 micrograms per cubic meter (µg/m
The EPA disagrees that the information
The EPA disagrees with the commenter regarding the interpretation of the literature related to the spatial extent of deposition of Hg emitted by U.S. EGUs. The EPA also disagrees that the peer-reviewed CMAQ model has limitations for this application or overestimates local deposition. The commenter does not provide any credible support for the assertion that grid-based models typically overestimate local deposition surrounding EGUs. The EPA maintains that the CMAQ photochemical model represents the best science currently available in simulating atmospheric
The study
Several commenters stated that the Mercury Maps model has many deficiencies. Those commenters stated that Mercury Maps is a static model unable to account for the dynamics of ecosystems that affect Hg bioaccumulation in fish, cannot consider non-air Hg inputs to watersheds, and assumes reductions in airborne Hg lead to proportional reductions in fish MeHg concentrations. Another commenter claimed that data that demonstrate a steady-state linear reduction in fish tissue MeHg in response to a reduction in atmospheric Hg deposition within watersheds do not exist and provided several references that they claimed show non-linear responses to changes in Hg deposition.
The same commenter disagreed with EPA's interpretation of Figure 2-17 in the March TSD and stated that a U.S. Geological Survey national waterway study
Several commenters provided comments related to the assumption that fish tissue Hg levels used in the analysis represent a steady-state. One commenter stated that given the demonstrated lag time in response to deposition change, it is logical to conclude that a lag time needs to be incorporated in Mercury Maps to adjust the estimation of how much fish tissue MeHg levels decrease in response to decreases in Hg deposition attributable to U.S. EGUs. According to the same commenter, the METAALICUS study shows that there is a lag time (and a non-proportional response) after 3-4 years. The same commenter noted that there are numerous factors that influence lag time including (1) watershed characteristics,
One commenter believes EPA incorrectly implied that its EGU risk estimates using Mercury Maps are underestimated because they do not account for legacy EGU-attributable deposition, which EPA assumes to be higher.
One commenter stated that while EPA properly screened out watersheds with significant current non-air sources of Hg, the EPA did not adequately screen out watersheds with significant Hg contributions from non-air sources, specifically watersheds with historic Hg or gold mining or other industrial Hg discharges. The same commenter stated that EPA's study was not geographically balanced and was dominated by rivers in the coastal region of the southeast that has numerous wetlands, which are favorable locations for methylation and have conditions that are not typical of much of the rest of the U.S.
The SAB agrees with the Mercury Maps approach used in the analysis and has cited additional work that supports a linear relationship between mercury loading and accumulation in aquatic biota. These studies suggest that mercury deposited directly to aquatic ecosystems can become quickly available to biota and accumulated in fish, and reductions in atmospheric mercury deposition should lead to decreases in methylmercury concentrations in biota. The SAB notes other modeling tools are available to link deposition to fish concentrations, but does not consider them to be superior for this analysis or recommend their use. The integration of Community Multiscale Air Quality Modeling System (CMAQ) deposition modeling to produce estimates of changes in fish tissue concentrations is considered to be sound. Although the SAB is generally satisfied with the presentation of uncertainties and limitations associated with the application of the Mercury Maps approach in qualitative terms, it recommends that the document include quantitative estimates of uncertainty available in the existing literature.
The SAB peer review committee specifically addressed the MCM suggested by the commenter and had the following response:
The SAB agrees with the application of Mercury Maps in this assessment. There are other modeling tools capable of making a national scale assessment, such as the Regional Mercury Cycling Model (R-MCM). However, the R-MCM is more data intensive and the results produced by the two model approaches should be equivalent.
The R-MCM, a steady-state version of the time-dependent Dynamic Mercury Cycling Model, has been publicly available to and used by the EPA (Region 4, Athens, Environmental Research Laboratory) for a number of years. R-MCM requires more detail on water chemistry, methylation potential, etc., and yields more information as well. Substantial data support the Mercury Maps and the R-MCM steady-state results, so that the results of the sensitivity analysis and the outcomes from using the alternative models would be equivalent between the two modeling approaches. Though running an alternative model framework may provide additional reassurance that the Mercury Maps “base case” approach is a valid one, it is unlikely that substantial additional insight would be gained with the alternative model framework.
In addition, the SAB stated, “Since the Mercury Maps approach was developed, several recent publications have supported the finding of a linear relationship between mercury loading and accumulation in aquatic biota.
Based on the responses of the SAB peer review committee, the EPA's use of the linear proportionality assumption, supported by the Mercury Maps analysis, is well-supported.
The EPA also disagrees with commenters' interpretation of Figure 2-17. As stated in the Hg Risk TSD, while this figure is useful to demonstrate the lack of correlation across watersheds between total deposition of Hg and MeHg concentrations in fish tissue, it is not indicative of the likely correlation between changes in Hg deposition at a given watershed and changes in MeHg concentrations in fish tissue from that watershed. The SAB agreed with this interpretation, noting the importance of Figure 2-17 demonstrating that “spatial variability of deposition rates is only one major driver of spatial variability of fish methylmercury and that variability of ecosystem factors that control methylation potential (especially wetlands, aqueous organic carbon, pH, and sulfate) also play a key role.”
In response to recommendations from the SAB, the EPA expanded the discussion of uncertainties associated with the linearity assumption, including uncertainties related to the potential for sampled fish tissue Hg level to reflect previous Hg deposition and the potential for non-air sources of Hg to contribute to sampled fish tissue Hg levels. Each of these sources of uncertainty may result in potential bias in the estimate of exposure associated with current deposition. The EPA took steps to minimize the potential for these biases by (1) only using fish tissue Hg samples from after 1999, and (2) screening out watersheds that either contained active gold mines or had other substantial non-U.S. EGU anthropogenic emissions of Hg. The SAB commented that EPA's approach to minimizing the potential for these biases to affect the results of the risk analysis appears to be sound and that additional criteria that could be applied are unlikely to substantially change the results. As a result, the EPA disagrees with the commenter that EPA's screening process is inadequate. In addition, we conducted several sensitivity analyses to gauge the impact of excluding watersheds with the potential for non-EGU Hg emissions, and found that the results were robust to these exclusions.
In response to specific comments regarding the use of the Mercury Maps model, the EPA clarifies that the Hg Risk TSD did not directly use the Mercury Maps model. Instead, the EPA applied an assumption of linear proportionality between changes in Hg deposition and changes in MeHg concentrations in fish that is supported by the Mercury Maps modeling. By assuming steady-state conditions in apportioning fish tissue Hg levels and risk, the EPA does not attempt to project lag times. Recent research cited by the SAB
One commenter stated that it is unclear what literature the Agency says “generally supports the plausibility of high-end subsistence-like fishing * * * to some extent across the watersheds” and stated that if other studies exist, the EPA should provide the values for comparison.
One commenter stated that EPA combined two parameters with differing scales to establish the geographic unit used in the Hg Risk TSD risk assessment. The HUC watersheds are based on average about 35 square miles in size, while U.S. census tracts used to identify watersheds relevant for subpopulations of interest—cover a few tenths to hundreds of square miles. Several commenters stated that it is unclear how the analysis handled differences in geographic resolution between watersheds and census tracts were.
One commenter stated that the procedure for assigning census tracts could bias exposure outcomes. For example, the commenter stated that a single influential census tract in a watershed could drive risk, even if the watershed had only a minimal number of fish samples. The commenter stated that this possibility is a concern in urban areas, which account for the majority of census tracts, because these census tracts are more likely to be included in a risk analysis because they have more than 25 people living in poverty. The commenter stated that these census tracts may drive the extremes of the distribution without regard to the actual number of high-level, self-caught fish consumers within their boundaries. The commenter stated that they could not assess the potential bias and noted that EPA did not test the bias by sensitivity analyses.
Several commenters stated that EPA was not clear whether the poverty criteria were applied in all scenarios or just for the high-end female fish consumer scenario. One commenter stated that EPA should apply the minimum 25 source population criteria only to populations of women of childbearing age. One commenter stated that EPA's assumption would result in any densely populated urban census tract with a single fish tissue sample being assigned to a modeled watershed with populations potentially at-risk, regardless of the actual degree of recreational or subsistence fishing taking place there.
The EPA notes that there is some confusion in the comments related to the size of the watersheds modeled. Several commenters stated that HUC watersheds are 35 km on a side. The commenters appear to be referring to HUC8 classifications. The HUCs are defined for varying spatial resolutions. The geographic unit used as the basis for generating risk estimates is HUC12, which are watersheds about 10 km on a side, which is comparable with the size of the 12 km
The EPA only used the U.S. Census tracts to determine whether there are populations in the vicinity of a given watershed, which could increase the potential for a category of subsistence fishers to be active at that watershed. In the revised Hg Risk TSD, the EPA modified the female subsistence scenario to apply equally to all watersheds with fish tissue Hg data based on the likelihood that these populations have the potential to fish at most watersheds. As described in the revised Hg Risk TSD, the EPA made this change in response to SAB's concerns regarding the potential exclusion of watersheds with fewer than 25 individuals and regarding coverage for high-end recreational fish consumption.
The EPA continues to model risk for white and black subsistence fishers active in the southeast and for Hispanics assessed nationally. In this case, the EPA links poverty with subsistence fishing, as EPA only modeled locations with poor source populations. However, in modeling these three populations, the
While EPA agrees with the comment that it is likely that exposure to total MeHg through commercial fish consumption represents a more significant risk for the general population than consumption of freshwater fish obtained through self-caught fishing activity, exposure to total MeHg through self-caught fish consumption is the most significant risk for subsistence fishing populations and high-end recreational fishers. For the subset of these populations that focus their fishing activity in freshwater streams and lakes, it is also the case that they will experience a higher fraction of MeHg exposure attributable to U.S. EGU Hg emissions. As a result, the EPA focused the risk assessment on subsistence fishers active at inland freshwater watersheds because they are likely to experience the highest levels of individual risk as a result of exposure to U.S. EGU-attributable Hg.
Regarding the alternative studies identified by the commenters, the EPA disagrees that these studies considered collectively contradict the cooking loss factor in the analysis. Specifically, the first study
The EPA agrees that application of the cooking loss adjustment factor is appropriate if the fish consumption rates are for
Several commenters stated that EPA based its fish consumption rates used in the risk analysis on a limited number of studies and that those studies are poorly documented.
Another commenter stated that EPA should summarize available supporting studies by basic study content, characteristics, design, size, demographics, dietary recall period, and fish intake rates by demographic variables. According to the commenter, this summary would support the scientific validity of the assessment and better illustrate the potential variability and uncertainty involved in extrapolating data from small populations to the national-scale. The commenter also noted that the three studies actually used to provide subsistence population estimates, which were extrapolated to the national-scale, included a limited number of individuals living in diverse and localized areas.
One commenter stated that the assumption with the greatest impact on risk is the fish consumption rate. That same commenter stated that using 99th percentile ingestion rate dramatically increases HQ and IQ loss compared to the 50th percentile ingestion rate. The commenter stated that when an estimate of the 95th percentile ingestion rate of the 15 to 44 year old female population is considered, the HQ is a tenth of the value computed with the 99th percentile high-end female fisher.
One commenter stated that EPA provides broad summary statistics of its fish tissue data in Table 5-2 of the Regulatory Impact Analysis (RIA), but the summary does not allow an assessment of the representativeness and robustness of the underlying data for the risk assessment, especially at the tails of the distribution. The commenter stated that the table does not include a median statistic and does not provide any information on the number of lakes and river segments in each watershed. According to the commenter, an analysis of EPA's database by the SAB indicated that 60 percent of the watersheds with fish Hg data from rivers have risks calculated based upon a sample size of one or two fish. The commenter stated that it is not reasonable to base a significant policy and regulation decision on watersheds where exposure is based on a single fish sample in a single water body within it.
Several commenters criticized EPA's use of the 75th percentile fish tissue MeHg level in a watershed. One commenter stated that EPA provided no rationale for its decision to choose the highest of the 75th percentile for fish Hg levels among rivers and lakes within the HUC. Several commenters stated that subsistence fishers are less likely to target larger fish relative to recreational fishers. Several commenters suggested that EPA include a sensitivity analysis using the mean or median fish MeHg level in a watershed. One commenter also stated that EPA arbitrarily inflated the risk estimates by assuming consumption of only fish greater than 7 inches and choosing the largest of the 75th percentile of fish Hg levels from these larger fish (
One commenter stated that EPA should quantify adverse effects from the ingestion of MeHg in seafood in addition to ingestion of MeHg from self-caught freshwater fish. According to the commenter, recent studies demonstrate that were EPA to take into account consumption of seafood, MeHg consumption in the U.S. is of even greater concern.
The EPA agrees that the fish consumption rate is an important factor in calculating risk from exposure to MeHg in fish. The EPA acknowledges that the distribution of fish consumption rates is positively skewed, which means that at higher percentiles (
The EPA disagrees with the comment that high consumption rates are poorly documented. Evidence of these high fish consuming populations can be found in surveys
The EPA agrees that the Hg Risk TSD would be improved by clarifying that the literature review focused on identifying studies that characterize subsistence fish consumption for groups active at freshwater locations within the U.S., and EPA has revised the Hg Risk TSD accordingly. In the Hg Risk TSD, the EPA summarized important study attributes for the source studies used to obtain fish consumption rates. This information was provided in Table C-1 in an appendix. To improve clarity, the EPA moved the summary table to the main body in the revised Hg Risk TSD. In identifying these studies, the EPA focused on surveys for subsistence fishers that were applicable at the broader regional or national level. In the Hg Risk TSD, the EPA acknowledged the smaller sample sizes for some of the subsistence fisher groups, and in several cases the EPA did not use the 99th percentile consumption rates because the sample sizes were too low to support this level of resolution. This decision did not affect EPA's finding of a hazard to public health, which is based on the results for the female subsistence fishing population, which has an estimate of the 99th percentile consumption rate that is supported by an adequate sample size.
The EPA disagrees with the comment that it did not provide a rationale for choosing the 75th percentile fish tissue concentration across lakes and rivers in a watershed. However, the EPA modified the methodology based on evaluation of the number of samples within each watershed (responding to a recommendation from the SAB). In the revised methodology, the EPA computes the 75th percentile value at each sampling site within a watershed. The EPA then computed the average of the site-specific 75th percentile fish tissue Hg values within a given watershed. This approach does not differentiate between rivers and lakes and reflects an improved treatment of behavior, allowing for fishers to choose among multiple fishing sites within a watershed.
The EPA generally agrees with the comment that some fraction of subsistence fishers likely consume fish without consideration for size (given dietary necessity), however, the EPA considers it reasonable to assume that a subset of subsistence fishers could target larger fish in order to maximize the potential consumption per unit of fishing effort. The EPA uses this subset of subsistence fishers targeting larger fish, which is represented by the 75th percentile fish tissue value, in the risk assessment. In addition, including the female subsistence fishing population in the analysis also provides coverage for high-end recreational anglers who target larger freshwater fish. The SAB commented that: “Using the 75th percentile of fish tissue values as a reflection of consumption of larger, but not the largest, fish among sport and subsistence fishers is a reasonable approach and is consistent with published and unpublished data on predominant types of fish consumed.”
The EPA disagrees with the comment that it is not reasonable to use watersheds where only a single fish sample is available. Although it is generally preferred to have multiple samples, the SAB noted that using a single sample is likely to underestimate the 75th percentile fish MeHg concentration and is, therefore, likely to underestimate the risk estimates for those watersheds. The SAB suggested that EPA conduct additional analyses of the fish tissue MeHg data, which EPA has done and included in the revised Hg Risk TSD. The revised Hg Risk TSD includes information on the number of watersheds modeled in the risk assessment with various fish tissue Hg samples sizes (e.g., 1, 2, 3-5, 6-10 and >10 measurements).
However, many commenters expressed concerns regarding EPA's use of the MeHg RfD as a benchmark for health risk. Several commenters raised concerns claiming that EPA has not incorporated the best available Hg toxicological data into the RfD, which results in a flawed analysis and an overestimate of the impact of Hg emissions on human health.
Several commenters stated that, when deriving the RfD, the EPA relied on the flawed Faroe Islands' children study and ignored the Seychelles Islands study,
One commenter criticized EPA for using a linear dose-response model for the RfD-based HQ metric and the IQ metric. Another commenter stated that the RfD assumes a threshold dose below which an appreciable risk of adverse effects is unlikely, and NAS did not evaluate whether MeHg exposure data were better fit by a linear or non-linear model or by a threshold or non-threshold model.
Several commenters stated that EPA's MeHg RfD is more conservative than “safe” levels determined by other federal agencies and claim that EPA assigned unusually high uncertainty factors. Several commenters stated that EPA's use of the 1999 National Health and Nutrition Examination Survey (NHANES) blood Hg levels show a downward trend since 1999, and the levels have been below the RfD since 2001.
One commenter stated that a study by Texas Department of State Health Services (DSHS, 2004)
Two commenters claim that EPA uses the RfD as if it were an absolute threshold for health risk in the risk assessment even though the RfD methodology is a screening tool for deciding when risks clearly do not exist.
Several commenters recommended adding qualitative discussions to the Hg Risk TSD regarding several aspects of uncertainty, including uncertainty in the RfD, uncertainty in extrapolating a dose-response relationship between MeHg exposure and change in IQ, uncertainty in extrapolating the dose-response relationship from marine fish and marine mammals to freshwater fish, and uncertainty due to potential confounding by PCBs in marine species.
Several commenters raised concerns regarding the relationship between MeHg exposure and IQ loss. Two commenters stated that changes in IQ are not a well-defined health consequence of MeHg exposure. One commenter stated that the SAB had reservations about EPA's use of IQ loss. Two commenters questioned whether IQ impacts would even occur because in Japan and Korea, where the maternal blood Hg levels are higher than in the U.S., there is no evidence of adverse effects. Another commenter cited a study
Several commenters question the relationship between cardiovascular effects and MeHg exposure. Two
Several commenters assert that the risks from eating seafood are low relative to the benefits, that fish advisories can limit the beneficial aspects of fish consumption, and that fish advisories are often unsuccessful in changing behavior.
The EPA disagrees that it did not incorporate the latest Hg data to support the appropriate and necessary finding. It is the policy of EPA to use the most current peer reviewed, publicly available data and methodologies in its risk assessments. However, the EPA noted in the preamble to the proposed rule that “data published since 2001 are generally consistent with those of the earlier studies that were the basis of the RfD, demonstrating persistent effects in the Faroe Island cohort, and in some cases associations of effects with lower MeHg exposure concentrations than in the Faroe Islands. These new studies provide additional confidence that exposures above the RfD are contributing to risk of adverse effects, and that reductions in exposures above the RfD can lead to incremental reductions in risk.” However, the EPA has not completed a comprehensive review of the new literature, and as such, it would be premature to draw conclusions about the overall implications for the RfD.
The EPA agrees that EPA's RfD is not the same as the levels used by other federal agencies. In their advice to the EPA on the appropriate bases for a MeHg RfD, NAS specifically recommended that EPA use neither the study nor the uncertainty factor employed by the Agency for Toxic Substances Disease Registry (ATSDR) in the calculation of the minimal risk level.
The EPA disagrees that the uncertainty factor is “unusually high”. The uncertainty factor used in calculation of EPA's peer-reviewed RfD is small (10 fold); half of this factor is to account for measured variability in human pharmacokinetics, which is based on advice of the NAS
The IRIS makes this statement regarding a threshold for MeHg, “It is also important to note that no evidence of a threshold arose for methylmercury-related neurotoxicity within the range of exposures in the Faroe Islands study. This lack [of a threshold] is indicated by the fact that, of the K power models, K = 1 provided a better fit for the endpoint models than did higher values of K.”
The EPA disagrees that it is using the MeHg RfD as an absolute bright line for health effects in the risk assessment. As stated in the preamble to this proposed rule, the RfD is an estimate of a daily exposure to the human population that is likely to be without an appreciable risk of deleterious effects during a lifetime. The EPA also stated that no RfD defines an exposure level corresponding to zero risk. Because mercury is a cumulative neurotoxin, it is important to distinguish health effects from public health hazard. Within the context of the appropriate and necessary finding, we interpret a public health hazard as risk, rather than certain occurrence of health effects.
The EPA disagrees that exposure levels in the U.S. are lower than those in the Faroe Islands study. Exposure to MeHg in the U.S. has been reported at the same levels as those published in the Faroe Islands.
The EPA disagrees that there is a statistically discernible downward trend in the NHANES data on blood Hg. The EPA is unaware that a formal statistical analysis for temporal trends has been completed for NHANES data on blood Hg levels for the period 1999 to 2008. Mahaffey
The EPA disagrees with the commenter regarding confounding by PCBs and lead. Exposure to MeHg in the Faroe Islands was largely from consumption of pilot whale meat; exposure to PCBs was found in the portion of the population who also consume whale blubber. Numerous analyses have shown neurobehavioral effects of PCBs; however, the effects of MeHg and PCB in the Faroe Islands study are separable.
The EPA disagrees with the commenter's assertion that the connection between MeHg in fish and observed health effects is not understood due to evidence from the cited Texas study.
The EPA is aware of the possibility of both interactions among environmental contaminants and cumulative effects of pollutants that produce the same adverse endpoint. The EPA guidance exists for dealing with such scenarios.
The EPA disagrees with commenters suggesting that the RfD-based HQ is inappropriate. The SAB “agreed that EPA's calculation of a hazard quotient for each watershed included in the assessment is appropriate as the primary means of expressing risk,” and that “because the RfD from which the HQ is calculated is an integrative metric of neurodevelopmental effects of methylmercury, it constitutes a reasonable basis for assessing risk.”
The SAB also recommended that EPA revise the Hg Risk TSD to include additional qualitative discussion about uncertainty in the revised Hg Risk TSD. Specifically, the SAB recommended that EPA revise the Hg Risk TSD “to better explain the methods and choices made in the analysis, and analytical results, and where the uncertainties lie.” The SAB noted several uncertainties related to the RfD. The EPA agrees with this recommendation and included a more complete discussion of these uncertainties in the revised Hg Risk TSD.
The EPA disagrees that the IQ metric threshold is questionable. The SAB concluded that it was reasonable to consider a loss of >1 or >2 IQ points a public health concern. The SAB stated, “The Panel agreed that if IQ loss is retained in the risk assessment despite these reservations, a loss of one or two points would be an appropriate benchmark.”
Although EPA disagrees that the IQ results are too uncertain to rely upon, the EPA acknowledges that IQ is not the most sensitive neurodevelopmental endpoint affected by MeHg exposure, as also noted by the SAB. The SAB recommended that the IQ analyses be retained but be de-emphasized in the documentation underlying the final regulation. The SAB concluded, “The Panel does not consider it appropriate to use IQ loss in the risk assessment and recommended that this aspect of the analysis be de-emphasized, moving it to an appendix where IQ loss is discussed along with other possible endpoints not included in the primary assessment. While the Panel agreed that the concentration-response function for IQ loss used in the risk assessment is appropriate, and no better alternatives are available, IQ loss is not a sensitive response to methylmercury and its use likely underestimates the impact of reducing methylmercury in water bodies.”
The SAB, however, supported the use of the IQ dose-response function calculated by EPA in the Hg Risk TSD. The SAB noted, “The function used came from a paper by Axelrad and Bellinger (2007) that seeks to define a relationship between methylmercury exposure and IQ. A whitepaper by Bellinger (Bellinger, 2005)
The EPA disagrees that the Agency has overstated or failed to review the scientific literature on cardiovascular effects from MeHg exposure. As summarized in the preamble to the proposal, the EPA stated that the NAS study concluded that “Although the data base is not as extensive for cardiovascular effects as it is for other end points (
The EPA acknowledges the research regarding the effectiveness of fish advisories. However, the proposed regulation does not address the subject of fish advisories, consumer advice on fish or efficacy of such advice. The EPA rejects the commenter's speculation regarding whether the estimated IQ impacts for the regulation are real. Adverse effects of
Moreover, many studies show that beneficial effects of fish on both cardiovascular and neurodevelopmental health are decreased by concomitant exposure to MeHg. Several studies describe one or more aspects of exposure to fish nutrients and MeHg.
The EPA recognizes the potential for confounding of the effects of Hg on the developing nervous system by a range of nutrients and discusses this uncertainty in the revised Hg Risk TSD. Regarding selenium, the SAB commented that “one SAB member suggests the use of blood markers of selenium-dependent enzyme function, noting that methylmercury irreversibly inhibits selenium-dependent enzymes that are required to support vital-but-vulnerable metabolic pathways in the brain and endocrine system. Impaired selenoenzyme activities would be observed in the blood before they would be observed in brain, but the effect is also expected to be transitory. The use of these measures is a minority view among the SAB members.”
Several commenters claimed that overly conservative assumptions in the risk analysis render the results flawed and unreliable, including using CMAQ to model deposition, Mercury Maps, fish consumption rate and fish MeHg concentrations, overly stringent RFD, national-scale model, using poverty as a surrogate for subsistence fishing, assuming a subsistence fisher resides in most watersheds with fish tissue data, fishers only eat larger fish with high Hg concentrations, cooking loss adjustment, unrealistically high fish ingestion rates (a large fish meal every day), focused on the extremes of the distributions, cast many assumptions as an underestimate of the effect despite evidence to the contrary, and created inappropriate metrics for risk that show no improvement despite significant Hg emissions reductions in the U.S.
Several commenters cite Tetra Tech's analysis that assessed Hg risk using different consumption rates, cooking factor, mean fish tissue concentrations, and EGU-attributable Hg deposition only, which showed considerably fewer watersheds that exceed an HQ of 1 at 2016 deposition levels.
Several commenters claim that this regulation would not significantly reduce Hg exposure via fish consumption because EGU-attributable deposition is a small fraction of total deposition. One commenter stated that EPA's data shows Hg emissions from U.S. EGUs have little influence on fish Hg concentrations despite a reduction of 41 tons of Hg in the U.S. between 2005 and 2016. One commenter requested that EPA accurately describe the low health risks posed by utility hazardous air pollutant emissions. One commenter stated that EPA did not consider scientific information showing that there is no straightforward connection between Hg emissions from U.S. EGUs to the Hg level in fish, which is dependent upon many environmental factors, such as sunlight and organic matter, pH, water temperature, sulfate, bacteria, and zooplankton present in the ecosystem. One commenter stated that there is not any demonstrable evidence that anyone in the U.S. has suffered adverse health problems as a result of Hg emissions from coal-fired EGUs. One commenter stated that EPA's findings are similar to the 2000 findings where EPA found a plausible link between anthropogenic emissions of Hg from sources in the U.S. and MeHg in fish, and “plausible” is a euphemism for unproven.
Several commenters had recommendations for the Hg risk analysis. One commenter stated that more data from Florida should have been included because Florida is known to have a rich data set on fish Hg concentrations. One commenter stated that EPA should characterize general recreational angler fishers instead of subsistence fishers. One commenter claims that EPA made math errors in the Hg Risk TSD regarding the deposition in watersheds at specific percentiles. One commenter questioned EPA's policy metrics used to characterize Hg risk.
Several commenters stated that the Hg TSD is unclear and lacks detail, as noted by the SAB. One commenter stated that the SAB is critical of EPA's efforts, stating that the SAB found it difficult to evaluate the risk assessment based solely upon Hg Risk TSD and recommended that EPA transparently explain the methods and uncertainties. One commenter stated that because of insufficient review time and the lack of detail in the Hg Risk TSD, they could not assess key questions, such as the nation-wide representativeness of the fish tissue data.
One commenter stated the subset of watersheds considered in the analysis (
One commenter stated EPA's reporting of IQ point loss is erroneous and not relevant to informing policy, and the U.S. EGU contribution to risk is marginal as evidenced by the null values for the 50th percentile watershed.
One commenter notes that U.S. EGU-attributable emissions of Hg have decreased significantly between 2005
The SAB conducted a comprehensive peer review of all of EPA's assumptions in the Hg Risk TSD, and concluded that “the SAB supports the overall design of and approach to the risk assessment and finds that it should provide an objective, reasonable, and credible determination of the potential for a public health hazard from Hg emitted from U.S. EGUs.”
The SAB concurred with EPA's analytical assumptions and overall study design for the Hg Risk TSD, including the RfD-based HQ approach, fish tissue data, 75th percentile size fish, Mercury Maps assumption, and consumption rates. Based on the SAB peer review, the EPA strongly disagrees with commenter statements that the results reported in the Hg Risk TSD are unreliable, overly conservative, extreme, inconsistent with EPA risk guidelines, or severely overstate risk based on the stated objectives of the analysis. The EPA has specifically addressed each of these assumptions in the previous sections of the preamble, and thus, does not repeat those responses here. Based on the review by the SAB, the EPA has accurately described the health risks posed by utility hazardous air pollutant emissions and disagrees with the commenter's statement that EPA has not provided any demonstrable evidence to show that adverse health risks exist. The EPA has applied peer reviewed modeling to estimate the deposition of Hg attributable to U.S. EGUs. The EPA asserts that these metrics demonstrate a clear hazard to public health from Hg emissions from U.S. EGUs.
The EPA thoroughly evaluated the Tetra Tech analysis. The EPA does not agree that the analysis by Tetra Tech uses assumptions that are “more reasonable”, and the SAB agreed that all of EPA's assumptions in the Hg Risk TSD are reasonable and appropriate. The EPA asserts that Tetra Tech's analysis does not fully cover subsistence fishers likely to experience elevated U.S. EGU-related Hg exposure. Specifically, the risk estimate cited in the comment reflects application of a number of behavioral assumptions that provide significantly less coverage for higher risk subsistence fishers. Fish consumption surveys cited in the revised Hg Risk TSD suggest that higher percentile subsistence fishers eat more than twice the level of fish assumed by Tetra Tech. Tetra Tech's analysis also used the median fish tissue levels, but it is reasonable to assume that subsistence fishers would target somewhat larger fish to maximize the volume of edible meat per unit time spent fishing. Tetra Tech's analysis also assumed that cooking fish did not concentrate Hg, but a number of studies discussed in the revised Hg Risk TSD explicitly provide adjustment factors involving a higher unit concentration following preparation. Taken together, Tetra Tech's analysis does not address the stated goal of the risk assessment to assess the nature and magnitude of risk for those individuals likely to experience the greatest risk associated with exposure to U.S. EGU-attributable Hg.
The EPA disagrees with the commenter's assertion that this rule will not affect risks associated with Hg exposure. Hg from U.S. EGUs contributes to the levels of MeHg in fish across the country and consumption of contaminated fish can lead to increased risk of adverse health effects. The EPA has shown in the RIA (Chapter 5) that this rule will reduce Hg levels in fish.
The EPA acknowledges that U.S. EGUs contribute only a small fraction of total Hg deposition in the U.S. However, U.S. EGUs remain the largest emitter of Hg in the U.S., and the revised Hg Risk TSD shows that U.S. EGU-attributable Hg deposition results in up to 29 percent of modeled watersheds with populations potentially at-risk. Our analyses show that of the 29 percent of watersheds with population at-risk, in 10 percent of those watersheds U.S. EGU deposition alone leads to potential exposures that exceed the MeHg RfD, and in 24 percent of those watersheds, total potential exposures to MeHg exceed the RfD and U.S. EGUs contribute at least 5 percent to Hg deposition. Mercury risk is increasing for exposures above the RfD, and as a result, any reductions in Hg exposures in locations where total exposures exceed the RfD can result in reduced risks. While these reductions in risk may be small for most populations and locations, in some watersheds and for some populations, reductions in risk may be greater.
The SAB also directly addressed the question of the nation-wide representativeness of the fish tissue MeHg data in the national Hg risk assessment. The SAB concluded, “Although the SAB considers the number of watersheds included in the assessment adequate, some watersheds
The EPA disagrees with the commenter that there were errors in the Hg Risk TSD. Instead, the commenter has misinterpreted how EPA calculated the percentiles. The percentile (and mean) values presented in Table ES-1 for total and U.S. EGU-attributable Hg deposition are not matched by watershed. In other words, the EPA queried for the percentiles (and mean) provided for total Hg deposition and presented those percentiles and then separately estimated the percentiles for U.S. EGU-attributable Hg. Therefore, the total and U.S. EGU-attributable values for the 99th percentile do not necessarily occur at the same watershed. The EPA has provided additional clarification in the revised Hg Risk TSD.
The EPA agrees with the commenter that MeHg levels in fish depend on a complicated set of environmental factors, and EPA acknowledged this in the revised Hg Risk TSD. Furthermore, the EPA acknowledges that total Hg fish tissue levels are not correlated with levels of total Hg deposition when looking across watersheds because this relationship is highly dependent on the methylation potential at the specific waterbody, which is affected by pH, sulfate deposition, turbidity, etc. However, several recent studies
The EPA does not agree that there is no improvement in fish Hg concentrations between 2005 and 2016, or that there will be no further improvement from decreasing Hg emissions from U.S. EGUs from the baseline in 2016. Although total risk from all Hg exposures will remain elevated in much of the U.S., much of that risk is associated with global, non-U.S. Hg emissions. U.S. EGUs remain the largest source of Hg emissions in the U.S., and reductions in those emissions will result in reduced Hg deposition in many highly impacted watersheds. As shown in the revised Hg Risk TSD, average U.S. EGU-attributable fish tissue Hg concentrations is estimated to decrease by 44 percent between 2005 and 2016. Although we did not remodel risk for the 2005 scenario in the revised Hg Risk TSD, we estimated at proposal that the total percent of modeled watersheds with populations potentially at-risk from Hg emissions from U.S. EGUs exceeding either risk metric (
The EPA disagrees that IQ loss is erroneous or irrelevant to informing policy, but EPA has moved that analysis to an appendix in the revised Hg Risk TSD, per the SAB's recommendation. The EPA disagrees that the IQ effects at the 50th percentile watershed are useful in determining that there is not a hazard to public health because EPA's stated goal of the risk assessment was to focus on populations likely to experience relatively higher exposures to U.S. EGU-attributable Hg.
We also disagree with those commenters that point to the SAB's statements concerning the clarity of the Hg Risk TSD to suggest that the public did not have an ample opportunity to comment on the Hg risk assessment. Although it is correct that the SAB said the Hg Risk TSD was difficult to evaluate until EPA staff explained it at the public meeting in June 2011, we note that the commenters that assert that this issue amounts to a violation of CAA section 307(d) notice requirements made detailed technical comments, including many of the same comments as the SAB. Furthermore, the EPA provided notice of the peer review in the preamble to the proposed rule and a number of
The EPA disagrees with commenters' assertions that the metal content of the coal is a basis for invalidating the test results of high Cr emissions. The identification of sources whose measured emissions do not match the commenters' preconceived idea of emissions behavior is not surprising. There are many possible explanations for these differences. For example, the inconsistency between the test data and the coal analysis could be due to any number of reasons including unrepresentative coal sampling, control device problems, degradation of the refractory, or sampling contamination. The idea that test data should be discarded because it does not match initial expectations is unfounded.
The EPA disagrees with the commenter recommendations for using an equation from AP-42, developed in part by the commenters. Based on analyses of metal emissions measured at the site compared to statistically predicted estimates, the EPA concluded that measured emissions test data better predict actual emissions, and emission factors based on the arithmetic mean are a reasonable method to estimate emissions when test data are not available. The EPA analysis of the ICR data has found that the emissions equation recommended by the commenter is not a good predictor of actual EGU emissions. The EPA also disagrees with commenters' concerns about the assumption that 12 percent of the Cr will be Cr(VI) for every coal-fired unit, which was specifically supported by the peer review on the approach for estimating cancer risks associated with Cr and Ni emissions. The EPA disagrees with the commenter's assertion that any impact of scrubbers will impact the case study analyses. In EPA's revised case study analysis, 6 facilities have risk greater than 1 in a million, and of these, four facilities have Cr as the risk driver (James River, Conesville, TVA Gallatin, and Dominion—Chesapeake Bay). For these facilities, none of the units contributing the bulk of the Cr emissions have scrubbers according to the data provided to EPA by those facilities, so scrubber impacts on Cr speciation is not relevant to EPA's conclusions based on the non-Hg case studies. In any case, the EPA disagrees with the commenter's conclusions about the impacts of scrubbers on Cr speciation and provides evidence that impacts of scrubbers on Cr speciation can have the opposite effect on Cr(VI) fractions, concluding that EPA's 12 percent assumption is somewhat conservative.
The EPA also disagrees that coal rank must be a factor in computing Cr emission factors for use in the case studies. The EPA's analysis has demonstrated that coal rank appears to play no role in non-Hg metals emissions. The EPA's newly revised emissions factor development procedures can isolate and compare subgroups based on control device type or coal rank; the ICR data were subjected to these tests and no statistical significance was found between coal rank groups.
Finally, the EPA agrees with one commenter's recommendations on revised stack parameters for the case studies and has included these revisions in the case study modeling for the final rule.
One commenter stated that EPA's case study assessment might be flawed by the use of “beta” tests versions of the AERMOD meteorological preprocessors (AERMINUTE and AERMET). The commenter obtained from EPA the meteorological data used for EPA's assessment of the Conesville facility and processed these data with EPA's current regulatory versions of these preprocessors, which differ from the beta version. According to the commenter, a comparison of the hourly wind speed and hourly wind direction data produced by the beta preprocessor and by current EPA preprocessors revealed numerous and often substantial disparities.
One commenter stated that EPA's finding that only three coal-fired facilities and one oil-fired facility out of roughly 440 coal-fired facilities and 97 oil-fired facilities in the U.S. indicated risk greater than one-in-a-million supports a finding that it is “appropriate” to regulate those four and not the other 537. Another commenter stated that EPA found only a “few” facilities that have estimated maximum cancer risks in excess of one in a million, and that this does not justify regulating all non-Hg HAP for all sources in this category.
One commenter stated that EPA's discussion in the preamble to the proposed rule misleads the reader into believing that non-Hg HAP emissions from EGUs are associated with serious human health effects. According to the commenter, the EPA's discussion of the effects associated with excessive exposure to an individual HAP would lead the reader to believe that those effects inevitably occur from EGU emissions because EGU emissions have trace amounts of non-Hg HAP.
One commenter stated that with the assumptions in the Utility Study, both in terms of conservative scientific estimates and overestimated amounts of oil burned by these units, the EPA concluded that the risks from oil-fired units would result in only one new cancer case every 5 years. The commenter does not believe that this level of risk warrants regulation under CAA section 112(n)(1)(A).
Several commenters stated that even if the additional studies EPA performed were accurate, they hardly demonstrate that it is necessary and appropriate to regulate coal-fired EGU HAP under CAA section 112 because three sites nationwide show risks greater than one in a million, with the highest at eight in a million.
One commenter stated that the highest cancer risk estimated for coal-fired EGUs is still within the acceptable range used by EPA in other programs and is also far less than the background exposure risks the average person experiences. The background risk of developing cancer in a lifetime is approximately one in three (0.33). According to EPA's own data, the predicted added cancer risk of exposure to HAP from U.S. EGUs would change the background risk from 0.33 to 0.330001. This level of change is so minimal that it could not be observed in any health effects study that might be conducted.
One commenter stated that EPA conducted a health risk assessment on a limited number of facilities and found a “few” facilities that have estimated maximum cancer risks in excess of one in a million. The commenter stated that, based on this limited health risk assessment, the EPA apparently decided that they were justified to regulate all non-Hg HAP for all sources in this category.
Several commenters stated that EPA's assumption implies that a person stays exactly at the center of a census tract for 70 years and that a unit will operate in exactly the same manner for 70 years is unrealistic. The commenters suggest that Tier 3 risk assessment is warranted
One commenter asserts that because the alleged health benefits are derived from total exposure, the EPA should explain how its numerical emission limit units, which would not directly restrict total exposure if heat inputs increase, redress this health concern. In its preamble, the EPA simply notes that its emission limit units are consistent with, and allow for simple comparison to, other regulations.
One commenter questioned whether acid gas emissions limits for oil-fired units are “appropriate” or “necessary” because EPA's new technical analyses do not indicate a health concern from acid gas emissions from oil-fired units. According to the commenter, the EPA identifies Ni as the main HAP of concern from oil-fired units, even though cancer-related inhalation risks were well below the RfCs and EPA states that significant uncertainty remains as to whether those emissions present a health concern.
The EPA disagrees that EPA's case study assessment is flawed by the use of beta versions of AERMINUTE and AERMET. The EPA remodeled the case study facilities using the current versions of AERMINUTE (version 11059), AERMET (version 11059), and AERMOD (version 11103). Although there were differences in the number of calm and missing winds in the current AERMINUTE/AERMET output compared to the beta version, the resulting risks differed by less than two percent, on average. For Conesville, which had the largest difference in calms between the beta and current versions of AERMINUTE/AERMET, the risks differed by three percent. For the final rule, the case study facilities have been modeled with the current available versions of AERMINUTE, AERMET, and AERMOD.
The EPA disagrees with the commenter that having only a few case study facilities exceeding one in a million risk invalidates the “appropriate finding”. The 16 facilities EPA selected as case studies for assessment may not represent the highest-emitting or highest-risk sources. Although case study facility selection criteria included high estimated cancer and non-cancer risks using the 2005 NEI data, high throughput, and minimal emission control, another necessary criterion was the availability of Information Collection Request (ICR) data for the EGUs at those facilities (or for similar EGUs at other facilities). Because the ICR data were collected for the purpose of developing the MACT standards, the ICR was targeted towards better performing sources for non-Hg metal HAP, acid gas HAP, and organic HAP, with a smaller set of random recipients. Therefore, facilities for which ICR data were available may not represent the highest-emitting sources. The EPA's assessment of the case study facilities for the proposed rule concluded that three coal-fired facilities and one oil-fired facility had estimated lifetime cancer risks greater than one in a million. For the final rule, revisions were made to the 16 case studies based on comments received, and the results indicate that 5 coal-fired facilities and 1 oil-fired facility had estimated lifetime cancer risks greater than 1 in a million. The EPA maintains that its finding that more than 30 percent of the case study facilities had a cancer risk greater than one in a million is sufficient to support the appropriate finding.
The EPA disagrees with the commenter's assertion that the health effects associated with exposures to non-Hg HAP from U.S. EGUs are mischaracterized in the preamble to the proposed rule. The discussion of the health effects of non-Hg HAP provided in the preamble includes general information on the potential health effects associated with a broad range of exposure concentrations (from low to high levels) of the various non-Hg HAP (some of which have been determined to be carcinogenic to humans) based on peer reviewed scientific information extracted from priority sources such as IRIS, Cal EPA and ATSDR health effects assessments.
The EPA disagrees with the commenter's characterization of the Utility Study. The Utility Study represented the highest-quality factual record of information available at the time regarding EGU emissions and risks. Further, the EPA's revised risk assessments of 16 case studies, performed with more recent data and refined scientific methods, indicate that there are six U.S. EGU facilities that pose estimated inhalation cancer risks greater than 1 in a million. The EPA maintains that the findings of the case studies are one element that independently supports our determination that it remains appropriate and necessary to regulate EGUs under CAA section 112.
The EPA does not agree with the commenter who suggested that EPA should interpret the results of the non-Hg HAP risk analysis in the context of background cancer risk. As explained in the preamble to the proposed rule, the EPA reasonably looked to the cancer risk threshold established under CAA section 112(c)(9)(B)(1) for delisting a source category as an indicator of the level of cancer risk that was appropriate to regulate under CAA section 112. The commenters comparison of the cancer risk from EGUs as compared with the risk of contracting cancer from unknown sources is not the standard Congress established for evaluating HAP emission risk and the commenter has provided no support for its contention that the Agency should evaluate risk in that manner. The EPA maintains that the analysis was reasonable.
The EPA does not agree with the commenter's implication that EPA must make a facility-specific finding for each HAP for each source and then only regulate individual EGU facilities for the individual HAP that identified as causing an identified hazard to public health or the environment. That approach is not required under CAA section 112(n)(1) or anywhere under CAA section 112, and it would be virtually impossible to undertake such an effort. For these reasons, the EPA does not agree with the commenter and maintains that the appropriate and necessary finding is reasonably supported by the record and consistent with the statute for all the reasons set forth in the preamble to the proposed rule and this final action.
The EPA disagrees that an exposure adjustment is needed to account for conditions changing over 70 years because it runs counter to the long-standing approach that EPA has taken to estimate the maximum individual risk, or MIR. The MIR is defined by EPA's Benzene NESHAP regulation of 1989
The EPA disagrees with the commenter's assertion that the numerical emission limits being promulgated in today's final rule must be justified on their ability to redress the health concerns that were identified as the basis for regulating EGUs. The emission limits in today's rule are technology-based, as prescribed under CAA section 112, and do not need to be justified based on their ability to protect public health. Regarding potential health concerns, the EPA has up to 8 years after the promulgation of the technology-based emission limits for EGUs to determine whether the regulations protect public health with an ample margin of safety. If the regulations do not, the CAA directs EPA to promulgate additional more stringent standards (within the prescribed 8 years) to achieve the appropriate level of public health protection.
Furthermore, the EPA reasonably concluded that it was appropriate and necessary to regulate oil-fired EGUs in 2000, and EPA confirmed that conclusion was proper with the analysis set forth in the preamble to the proposed rule. Certain commenters question the determination based on their views of how the Agency can and should exercise its discretion. The EPA disagrees with these commenters and stands by the determination for the reasons set forth in the preamble to the proposed rule. The EPA also stands by the determination that the maximum cancer risks posed by emissions of oil-fired EGUs are greater than one in a million, due primarily to emissions of Ni compounds. Based on our analysis, we are unable to delist oil-fired EGUs.
1. To continue using the same approach as that developed for use in the 2000 NATA, which consists of using the IRIS URE for nickel subsulfide and assuming that nickel subsulfide constitutes 65 percent of the mass emissions of all Ni compounds.
2. To consider a more health-protective approach, based on the consistent views of the most authoritative scientific bodies (
3. To make the same assumptions as in option 2, but considering alternative UREs derived by the CDHS or TCEQ.
In responding to these peer review questions, two of the reviewers agreed with the views of the most authoritative scientific bodies, which consider Ni compounds carcinogenic as a group. These reviewers, therefore, did not focus on the availability of Ni speciation profile data. The third reviewer recommended that EPA review several manuscripts on Ni speciation profiles showing that sulfidic Ni compounds (which the reviewer considered as the most potent carcinogens) are present at low levels in emissions from EGUs.
Nickel and Ni compounds have been classified as human carcinogens by national and international scientific bodies including the IARC,
Based on the views of the major scientific bodies mentioned above, and those of expert peer reviewers that commented on EPA's approaches to risk characterization of Ni compounds, the EPA considers all Ni compounds to be carcinogenic as a group and does not consider Ni speciation or Ni solubility to be strong determinants of Ni carcinogenicity. With regards to non-cancer effects, comparative quantitative analysis across Ni compounds indicates that Ni sulfate is as toxic or more toxic than Ni subsulfide or Ni oxide.
Regarding the second charge question, two of the reviewers suggested using the URE derived by TCEQ for all Ni compounds as a group, rather than the one derived by IRIS specifically for Ni subsulfide. The third reviewer did not comment on alternative approaches. The EPA decided to continue using 100 percent of the current IRIS URE for Ni subsulfide because IRIS values are at the top of the hierarchy with respect to the dose response information used in EPA's risk characterizations, and because of the concerns about the potential carcinogenicity of all forms of Ni raised by the major national and international scientific bodies. Nevertheless, taking into account that there are potential differences in toxicity and/or carcinogenic potential across the different Ni compounds, and given that there have been two URE values derived for exposure to mixtures of Ni compounds that are 2-3 fold lower than the IRIS URE for Ni subsulfide, the EPA also considers it reasonable to use a value that is 50 percent of the IRIS URE for Ni subsulfide for providing an estimate of the lower end of a plausible range of cancer potency values for different mixtures of Ni compounds.
Several commenters questioned the validity of the chronic inhalation study by EPA because of (1) the use of surrogate speciated Cr emissions data instead of actual emissions data, (2) the assumption that units were run 100 percent of the time which is impossible, (3) dispersion modeling was used that is biased towards over predicting downwind impacts, and (4) estimated ambient concentrations were utilized as substitutes for real exposure concentrations for all people within a census block.
The EPA also disagrees that units were assumed to operate 100 percent of the time. The dispersion modeling performed for the case study facilities used hourly heat input as a temporalization factor for estimating hourly emissions, and in some cases hourly heat inputs (and emissions) were zero or very low. The commenter provided no data or information to support their claim that the dispersion modeling EPA used is biased towards overestimating downwind impacts.
The EPA disagrees with the commenters' assertion that “real exposure concentrations for all people within a census block” must be considered because it runs counter to the long-standing approach that EPA has taken to estimate the maximum individual risk, or MIR. The MIR is defined by EPA's Benzene NESHAP regulation of 1989
Several commenters stated that acid gas concentrations estimated in the case study facility assessment and the Utility Study do not exceed human health thresholds of concern. Two commenters stated that HCl emissions are negligible compared to other primary emissions (such as SO
The EPA's dispersion modeling of the case study facilities was actually performed with a greater degree of refinement than the EPRI analysis, and was consistent with EPA's
In contrast to the approach used in the EPRI analysis, the EPA used:
(1) 5 years of recent meteorological data from the weather station nearest to each facility, rather than one year of meteorological data. This is more representative of long-term (
(2) Temporally-varying emissions based on continuous emissions monitoring data, rather than assuming a constant emission rate for each facility throughout the entire simulation.
(3) Building downwash, where appropriate.
(4) The latest version of AERMOD [version 11103].
The EPA's assessment of the case study facilities for the proposed rule concluded that three coal-fired facilities and one oil-fired facility had estimated lifetime cancer risks greater than one in a million. For the final rule, revisions were made to the case studies based on comments received, and the results indicate that five coal-fired facilities and one oil-fired facility had estimated lifetime cancer risks greater than one in a million.
Regarding peer review, the risk assessment methodology used by EPA for the case studies was consistent with the method that EPA uses for assessments performed for Risk and Technology Review rulemakings, which underwent peer review by the Science Advisory Board in 2009.
In response to peer reviews of both the Hg and non-Hg HAP risk analyses, and taking into account public comments, the EPA conducted revised analyses of the risks associated with emissions of Hg and non-Hg HAP from U.S. EGUs. These revised analyses demonstrated that the risk results reported in the preamble to the proposed rule are robust to revisions in response to the peer reviews and public comments.
Specifically, the revised Hg Risk TSD shows that up to 29 percent of modeled watersheds have populations potentially at-risk from exposure to Hg from U.S. EGUs.
In the preamble to the proposed rule and in the 2000 finding, the EPA explained at length the serious nature of the health effects associated with Hg exposures, and the persistent nature of Hg in the environment. Congress specifically recognized the significant impacts of persistent bioaccumulative pollutants, like Hg, when it enacted section 112(c)(6), which requires the EPA to subject source categories listed pursuant to that section to MACT standards. Congress also required certain studies be conducted under CAA section 112(n) regarding the health effects of Hg. The EPA interprets CAA section 112(n)(1), with regard to Hg, as intended to protect the public, including sensitive populations, against exposures to Hg from EGUs that would exceed the level determined by the EPA to be without appreciable risk,
As we have explained, in calculating the estimates described above, the EPA has used peer-reviewed methods, and focused on populations likely to be at higher risk of exposure to Hg from U.S. EGUs,
Further, we were able to assess potential Hg exposures in only a small subset of generally representative watersheds in the U.S. because our analysis was necessarily premised on those water bodies for which we had fish tissue Hg samples. Specifically, we analyzed 3,141 of the approximately 88,000 watersheds in the United States. This limited set of watersheds excludes several of the watersheds with the highest U.S. EGU attributable deposition, and may also not have included watersheds with the highest sensitivity to Hg deposition,
Considering these points and the information on Hg in the record, the EPA believes that 10 percent of watersheds with populations at risk due to U.S. EGU emissions alone is unacceptable, as is 24 percent of watersheds with populations at risk due to U.S. EGU contributions in conjunction with total deposition from other sources. Taking into account the percentage of watersheds at risk, and the potential for even higher percentages to be at risk using more conservative risk assumptions and a more complete coverage of high U.S. EGU Hg deposition watersheds, the EPA concludes that Hg emissions from U.S. EGUs pose a hazard to public health.
Given these findings, and considering that (1) the revised risk analysis showed the percent of modeled watersheds with populations potentially at-risk increased from 28 to 29 percent, and (2) the revised analysis includes 36 percent more watersheds, which significantly expands the coverage in several states, we conclude that the finding that emissions of Hg from U.S. EGUs pose a hazard to public health is confirmed by the national-scale revised Hg Risk TSD. As a result, we conclude that it remains appropriate to regulate Hg emissions from U.S. EGUs because those Hg emissions pose a hazard to public health.
With regards to the revised non-Hg inhalation case studies, the highest estimated individual lifetime cancer risk for the one case study facility (out of 16) with oil-fired EGUs is estimated to be 20 in a million, driven by Ni emissions. For the facilities with coal-fired EGUs, there were five (out of 16) with maximum individual cancer risks greater than one in a million (the highest was five in a million), four of which were driven by emissions of Cr(VI), and one of which was driven by emissions of Ni. Therefore, a total of six facilities exceed the criterion for EGUs to be regulated under CAA section 112. There were also two facilities with coal-fired EGUs with maximum individual cancer risks at one in a million. In the preamble to the proposed rule, we reported that the maximum individual lifetime cancer risk for the one facility with oil-fired EGUs was estimated to be 10 in a million, and that there were 3 coal-fired EGU facilities with maximum individual cancer risks greater than 1 in a million (the highest was 8 in a million), and 1 coal-fired EGU facility with maximum individual cancer risks equal to 1 in a million. Given that (1) the lifetime cancer risk for the oil-fired EGU facility has increased from 10 to 20 in a million, (2) the number of coal-fired EGU facilities with cancer risks greater than 1 in a million has increased from 3 to 5, and (3) the highest risk coal-fired facility still has cancer risks of 5 in a million, which is above the 1 in a million benchmark, we conclude that the finding that emissions of non-Hg HAP from U.S. EGUs pose a hazard to public health is confirmed by the revised non-Hg risk inhalation case studies.
Moreover, some HAP emissions from U.S. EGUs contribute to adverse ecosystem effects. While we did not do new analyses on these topics, we reiterate that (1) Hg emissions from U.S. EGUs pose a hazard to the environment, contributing to adverse impacts on fish-eating birds and mammals, (2) Hg is a persistent bioaccumulative environmental contaminant, and as a result, failing to control Hg emissions from U.S. EGU sources will result in long-term environmental loadings of Hg, above and beyond those loadings caused by immediate deposition of Hg within the U.S.; controlling Hg emissions from U.S. EGUs helps to reduce the potential for environmental hazard from Hg now and in the future, and (4) it is appropriate to regulate those HAP which are not known to cause cancer but are known to contribute to chronic non-cancer toxicity and environmental degradation, such as the acid gases. In addition, we have identified effective controls available to reduce Hg and non-Hg HAP emissions.
In summary, we confirm the findings that Hg and non-Hg HAP emissions from U.S. EGUs each pose hazards to public health and that it remains appropriate to regulate U.S. EGUs under CAA section 112 for those reasons. We also conclude that it remains appropriate to regulate EGUs under CAA section 112 because of the magnitude of Hg and non-Hg emissions and the environmental effects of Hg and some non-Hg emissions, each of which standing alone, supports the appropriate finding. The availability of controls to reduce HAP emissions from EGUs only further supports the appropriate finding.
Our revised analyses still show that in 2016 after implementation of other provisions of the CAA, HAP emissions from U.S. EGUs are reasonably anticipated to pose hazards to public health; therefore, it is necessary to regulate EGUs under CAA section 112. Moreover, HAP emissions from U.S. EGUs are expected to continue to contribute to adverse ecosystem effects. In addition, based on evaluation of the regulations required by the CAA, including the recent CSAPR, it is necessary to regulate U.S. EGUs under CAA section 112 because the only way to ensure permanent reductions in HAP emissions from U.S. EGUs and the associated risks to public health and the environment is through standards set under CAA section 112. While CSAPR is projected to achieve some Hg reductions due to co-control of Hg provided by controls put in place to achieve required reductions in SO
In summary, we confirm the findings that it is necessary to regulate HAP emissions from U.S. EGUs because (1) the national-scale Hg Risk TSD shows that the hazards to public health posed by Hg emissions from U.S. EGUs will not be addressed through imposition of the CAA, (2) we cannot be certain that the identified cancer risks attributable to U.S. EGUs will be addressed through imposition of the requirements of the CAA, (3) the environmental hazards posed by acidification will not be fully addressed through imposition of the CAA, (4) regulation under CAA section 112 is the only way to ensure that all HAP emissions reductions that have been achieved since 2005 remain permanent, and (5) direct control of Hg emissions affecting U.S. deposition is only possible through regulation of U.S. emissions as we are unable to control global emissions directly. All of these findings independently support a finding that it is necessary to regulate U.S. EGUs under CAA section 112.
Based on these findings, the Agency affirms its finding that it remains appropriate and necessary to regulate
During the comment period on the proposed rule, UARG submitted a petition pursuant to CAA section 112(c)(9), asking the Agency to delete a portion of the EGU source category from the list of source categories to be regulated under CAA section 112. Specifically, UARG asks that EPA delist coal-fired EGUs from the CAA section 112(c) source category list. A copy of UARG's petition has been placed in the docket for today's rulemaking, along with the analysis conducted by EPRI that UARG uses to support its petition (hereinafter referred to as UARG's analysis). In support of its petition, UARG asserts that: (1) No coal-fired EGU or group of coal-fired EGUs will emit HAP in amounts that will cause a lifetime cancer risk greater than one in one million; and (2) no coal-fired EGU or group of coal-fired EGUs will emit non-carcinogenic HAP in amounts that will exceed a level which is adequate to protect public health with an ample margin of safety or cause adverse environmental effects. We disagree with UARG's assertions and for the reasons set forth below are denying UARG's petition to delist coal-fired EGUs from the section 112(c) source category list.
CAA section 112(c)(9)(B) provides that “[t]he Administrator may delete any source category” from the section 112(c) source category list if the Agency determines that: (i) For HAP that may cause cancer in humans, “no source in the category (or group of sources in the case of area sources) emits such hazardous air pollutants in quantities which may cause a lifetime risk of cancer greater than one in one million to the individual in the population who is most exposed to emissions of such pollutants from the source (or group of sources in the case of area sources)”; and (ii) for HAP that may result in human health effects other than cancer or adverse environmental effects, “a determination that emissions from no source in the category or subcategory concerned (or group of sources in the case of area sources) exceed a level which is adequate to protect public health with an ample margin of safety and no adverse environmental effect will result from emissions from any source.”
The EPA has the discretion to delete a source category under CAA section 112(c)(9)(B), but only if EPA concludes that the relevant requirements of CAA section 112(c)(9)(B) have been met. HAP emissions from EGUs present both cancer risks, which implicate the requirements of CAA section 112(c)(9)(B)(i), and non-cancer human health effects or adverse environmental effects, which implicate the requirements of CAA section 112(c)(9)(B)(ii). As such, UARG bears the burden of demonstrating that the requirements of
The EPA is denying UARG's petition to delist EGUs from the CAA section 112(c) source category list. UARG improperly seeks to delist a portion of a CAA section 112(c) listed source category that emits carcinogens, which is contrary to the plain language of CAA section 112(c)(9). Even setting aside this fundamental defect, UARG has failed to meet the requirements of CAA section 112(c)(9)(B).
In December 2000, the EPA listed coal- and oil-fired EGUs as a single source category. UARG asks the Agency to delist a portion of that listed source category: Coal-fired EGUs. UARG's request conflicts, however, with D.C. Circuit precedent, which provides that for categories, like EGUs, that pose cancer risks, the EPA may not delist a portion of a source category.
UARG's request is indistinguishable from the situation before the court in
Even assuming, for the sake of argument, that EPA could delist a portion of a source category that emits carcinogens, which it cannot, UARG has failed to demonstrate that the requirements for delisting in CAA section 112(c)(9)(i) and (ii) have been met. UARG contends that it used EPA's models and approaches, as well as the most recent data. We have carefully reviewed UARG's analyses, however, and found certain flaws that we believe bias their risk results low. Specifically, we identified flaws in emissions estimation. UARG developed estimates for all EGU facilities using data which pre-date the 2010 ICR emissions measurement data that EPA obtained to support this rule. UARG also relied upon an emissions equation developed by EPRI and DOE to develop its metal emissions estimates. With regard to that approach, the EPA analysis of the ICR data has found that the regression approach is not a good predictor of actual EGU emissions. Furthermore, we found fault with their use of the geometric mean and their outlier analysis for computing emission factors. The EPA analysis has found that the geometric mean approach underpredicts actual emissions by an average of more than seventy percent. This had an especially large impact on the arsenic, chromium, and nickel emissions estimates. These and other issues are explained in further detail in the response to comments document. As a result, we believe the resulting risk estimates in UARG's analysis are biased low. In addition, we note that there are dispersion model refinements that are not included in the UARG analyses, but were included in EPA's analysis. For example, for the dispersion modeling of the 16 non-Hg case studies, the EPA considered building downwash and used time-varying emissions, neither of which were used in UARG's analysis. These factors could also bias the UARG risk estimates low.
However, even taking UARG's analysis at face value and accepting, for arguments' sake, their assumptions and emissions estimates, UARG's own data supports denial of the petition because UARG itself identifies a maximum individual cancer risk exceeding 1 in a million, which is the statutory threshold in CAA section 112(c)(9)(B)(i). Specifically, UARG's multi-pathway
UARG dismisses the 4 in a million cancer result, arguing that the refined model plant multipathway risk assessment that it conducted is “overly conservative.” UARG conducted its multi-pathway risk analysis to evaluate the risks associated with ingesting persistent and bioaccumulative HAP which are emitted into the atmosphere and subsequently deposit into the environment and bioaccumulate in animals which are eventually consumed as food. Instead of conducting this multipathway analysis for each EGU facility, UARG instead analyzed multi-pathway risks by evaluating a single model plant. Nothing in the record indicates, however, that UARG's model plant represents the worst-case scenario for cancer human health risks from any EGU. Indeed, although UARG claims in its petition that the site selected for its case study is “likely as close to a worst-case scenario as is possible given the numerous variables associated with ingestion pathway risks” (UARG petition at 12), the supporting documentation for that case study specifically acknowledges that its fictional model plant scenario “is not intended to represent the risk due to emissions from an actual plant or the highest level of risk that could be associated with a coal-fired power plant at any location” (EPRI at 1). The statute requires that no source in the category may cause a lifetime cancer risk greater than one in one million to the most exposed individual, and UARG has failed to make this showing. UARG has neither modeled multi-pathway risks for a worst-case model facility, nor evaluated the multipathway risks associated with each individual EGU facility. Accordingly, UARG has not made the demonstration required by CAA section 112(c)(9)(B)(i). But, even focusing on the multi-pathway risk analysis that UARG did conduct, which admittedly does not represent a worst-case facility, UARG's analysis still shows cancer risks greater than one in a million. Accordingly, UARG's petition must be denied.
Although it is not necessary to reach the requirements of CAA section 112(c)(9)(B)(ii) that address non-cancer human health risks, we note that UARG has also failed to show that “emissions from no source in the category * * * exceed a level which is adequate to protect public health with an ample margin of safety.” Again, even accepting, for argument's sake, the conclusions in UARG's analysis, UARG only evaluated the non-cancer
Finally, UARG failed to meet its burden of showing that “no adverse environmental effect will result from emissions from any source” pursuant to CAA section 112(c)(9)(B)(ii). UARG analyzed environmental effects only in conjunction with its model plant. Because UARG's model plant does not represent the worst-case scenario for environmental effects, UARG's analysis falls short and fails to characterize fully the potential environmental impacts, and UARG's petition must be denied.
For all of these reasons, the EPA denies UARG's petition to delist coal-fired EGUs from the CAA section 112(c) source category list.
The EPA reasonably concluded in December 2000, based on the information available to the Agency at that time, that it was appropriate and necessary to regulate coal- and oil-fired EGUs under CAA section 112 and added such units to the list of source categories subject to regulation under CAA section 112(d). As discussed in section III above, the EPA conducted additional, extensive technical analyses based on recent data that confirm it remains appropriate and necessary to regulate HAP from coal- and oil-fired EGUs, because such EGUs continue to pose hazards to public health. HAP emissions from coal- and oil-fired EGUs also continue to cause adverse environmental effects. UARG advances several arguments, challenging the analyses the Agency completed in support of the proposed rule. We address those arguments in section III above. The Agency's analyses supporting the appropriate and necessary finding confirm that EGUs cannot be delisted pursuant to CAA section 112(c)(9).
Specifically, as explained further in section III above, the EPA analyzed non-Hg inhalation risks from 16 EGU facility case studies, including both coal- and oil-fired EGUs, as part of its technical analyses supporting the appropriate and necessary finding. That analysis demonstrates that there are 6 EGU facilities (of the 16 that we analyzed) with cancer risks exceeding one in one million. These cancer risk levels exceed the delisting criteria set forth in CAA section 112(c)(9)(B)(i), and confirm that EGUs must remain a listed source category. As explained above, some commenters assert that EPA's analysis of non-Hg inhalation risks from EGUs conducted in support of the proposal for this rulemaking overstated emissions from, and risks associated with, EGUs. These commenters argue that the analysis supporting UARG's petition more appropriately assesses EGU risk. The EPA disagrees with these comments and addresses these comments in section III above.
Significantly, the EPA based its analysis of 16 case study EGUs directly on the 2010 emissions test data from EGUs obtained through the ICR. The EPA's 16 case study analysis used emissions data either taken directly from the 2010 emissions test data, or derived using emissions factors based on the 2010 data for similar EGU units. The EPA also included dispersion model refinements in its final case studies, as noted above. Further, the EPA re-analyzed the 16 case studies that we conducted for the proposal and revised those analyses consistent with new non-Hg HAP emissions data and corrected stack parameters provided by commenters (including UARG) during the comment period on the proposed rule. The EPA received revised information concerning emissions tests, stack heights and stack diameters for some of the case study EGU facilities. The EPA incorporated all of these corrections into our analysis and then re-analyzed the risks for the 16 case study facilities. When completed, the EPA determined that the corrections incorporated into the reanalysis had little effect on the overall results. In the final rule, the EPA concludes that the maximum individual inhalation cancer risks for 6 out of the 16 case study EGU facilities are greater than 1 in a million. These cancer risk levels confirm that EGUs do not satisfy the delisting criterion of CAA section 112(c)(9)(B)(i) and thus should remain a listed source category.
The EPA's national-scale Hg Risk TSD supporting the appropriate and necessary finding also confirm that Hg emissions from coal- and oil-fired US EGUs are reasonably anticipated to pose a hazard to public health. As discussed
In order to determine whether EGU Hg emissions pose a hazard to public health, the EPA conducted a national-scale Hg Risk TSD focused on populations with high levels of self-caught freshwater fish consumption. The results of the Hg Risk TSD show that 98 percent of modeled watersheds have total exposures to MeHg that exceed the MeHg RfD, above which there is an increased risk of adverse effects on human health. In these watersheds, any reductions in exposures to Hg will reduce risk, and thus the incremental contribution to Hg exposure from any individual source or group of sources, such as EGUs, may reasonably be anticipated to cause additional risk. The Hg Risk TSD focused on those watersheds that either exceeded the RfD based on U.S. EGU attributable deposition alone, without considering other sources of deposition, or watersheds that exceed the RfD due to total Hg deposition and to which U.S. EGUs contributed at least 5 percent of the Hg deposition. The results of that analysis show that up to 29 percent of the modeled watersheds have populations that are potentially at-risk from exposure to Hg from U.S. EGUs, including up to 10 percent of modeled watersheds where deposition from U.S. EGUs alone leads to potential exposures that exceed the MeHg RfD, and up to 24 percent of modeled watersheds where total potential exposures to MeHg exceed the RfD and U.S. EGUs contribute at least 5 percent to Hg deposition. This approach to assessing national risks from Hg deposition from EGUs was supported by the independent peer review conducted by the Science Advisory Board, as discussed fully in section III.
Finally, as discussed in section III, based on this assessment, the EPA has confirmed that Hg emitted from U.S. EGUs pose a hazard to public health and it is appropriate to regulate U.S. EGUs under CAA section 112. This determination and the confirmatory assessments support our conclusion that UARG's delisting petition must be denied.
UARG attempts to dismiss the results of EPA's national-scale Hg Risk TSD, arguing that EPA cannot consider the risks posed by EGUs in conjunction with any other risks, including those from other source categories. Nothing in CAA section 112(c)(9), however, provides that the Agency cannot consider background or emissions due to other sources. CAA section 112(c)(9)(B)(ii) provides that “no source in the category or subcategory concerned (or group of sources in the case of area sources) exceed a level which is adequate to protect public health with an ample margin of safety and no adverse environmental effect will result from emissions from any source.” This language could be read to provide that the Agency consider only the risks associated with the source category at issue, and ignore how those risks fit with real-world exposures.
Here, the record demonstrates that 98 percent of the watersheds EPA modeled have total exposures to MeHg that exceed the MeHg RfD, above which there is increased risk of adverse effects on human health, especially on the developing nervous systems of children during gestation. EGUs remain one of the largest unregulated sources of Hg emissions, and those emissions continue to contribute to Hg exposures and risk. UARG seeks to ignore the fact that exposures above the RfD exist in almost every watershed we modeled, and instead focuses on the contribution provided solely by EGUs. The EPA did as UARG asked and found that up to 10 percent of modeled watersheds where deposition from U.S. EGUs alone leads to potential exposures that exceed the MeHg RfD. Thus, even focusing on EGU emissions in a vacuum, which we do not believe is appropriate or required under CAA section 112(c)(9), we still found that up to 10 percent of the watersheds exceed the RfD due to EGU emissions even before taking into account the numerous other sources of Hg deposition, and we believe this to be an unacceptable percentage of watersheds above the RfD. Due to the persistent, bioacccumulative nature of Hg, among other factors, we believe it is appropriate to consider the combined impact of Hg emissions from EGUs and other sources of Hg. Thus, we also considered the 24 percent of modeled watersheds where, even though U.S. EGU emissions alone are not enough to cause exposures that exceed the RfD, those emissions contribute at least 5 percent of total exposures to MeHg that exceed the RfD. The combined total of 29 percent of modeled watersheds where U.S. EGUs cause or contribute to MeHg exposures above the RfD is clearly unacceptable and thus the UARG petition to delist must be denied.
Thus, the technical analyses the Agency conducted in support of the appropriate and necessary finding confirm that EGUs should remain a listed source category.
This section summarizes the requirements of the final EGU NESHAP. Section VI below summarizes the significant changes to this final rule following proposal.
This final rule affects coal- and oil-fired EGUs.
An existing affected source under this final rule is the collection of coal- or oil-fired EGUs in a subcategory within a single contiguous area and under common control. A new affected source is each coal- or oil-fired EGU for which construction or reconstruction began after May 3, 2011.
CAA section 112(a)(8) defines an EGU as: a fossil fuel-fired combustion unit of more than 25 megawatts that serves a generator that produces electricity for sale. A unit that cogenerates steam and electricity and supplies more than one-third of its potential electric output capacity and more than 25 megawatts electrical output to any utility power distribution system for sale shall be considered an electric utility steam generating unit.
If an EGU burns coal (either as a primary fuel or as a supplementary fuel) or any combination of coal with another fuel (except for solid waste as noted below) where the coal accounts for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year after the applicable compliance date, the unit is considered to be coal-fired under this final rule.
If a unit is not a coal-fired unit and burns only oil or burns oil in combination with a fuel other than coal (except solid waste as noted below) where the oil accounts for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year after the applicable compliance date, the unit is considered to be oil-fired under this final rule.
As noted below, the EPA is finalizing in this rule a definition to determine whether the combustion unit is “fossil fuel fired” such that it is considered an EGU as defined in CAA section 112(a)(8) and, thus, potentially subject to this final rule. In addition, using the construct of the definition of “oil-fired” from the ARP, we are finalizing in this rule a requirement that the unit fire coal or oil (or natural gas), or any combination thereof, for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year to be considered a “fossil fuel-fired” EGU as defined in CAA section 112(a)(8). However, if a new or existing EGU is not coal- or oil-fired, and the unit burns natural gas exclusively or burns natural gas in combination with another fuel where the natural gas constitutes 10 percent or more of the average annual heat input during any 3 calendar years or 15 percent or more of the annual heat input during any 1 calendar year, the unit is considered to be natural gas-fired EGU and not subject to this final rule. As discussed later, we believe that this definition will address those situations where an EGU co-fires limited amounts of either coal or oil with natural gas or other non-fossil fuels (e.g., biomass).
If an EGU combusts solid waste, standards issued pursuant to CAA section 129 apply to that EGU, rather than this final rule.
For coal-fired EGUs, this final rule regulates HCl as a surrogate for acid gas HAP, with an alternate of SO
We are finalizing the emission limitations presented in Tables 3 and 4 of this preamble. Within the two major subcategories of “coal” and “oil,” emission limitations were developed for new and existing sources for seven subcategories, two for coal-fired EGUs, one for IGCC EGUs burning synthetic gas derived from coal- and/or solid oil-derived fuel, one for solid oil-derived fuel-fired EGUs, and four for liquid oil-fired EGUs, as described in more detail below. The limited-use liquid oil-fired subcategory, discussed elsewhere in this preamble, is not presented in Table 3 because only work practice standards apply to this subcategory.
We are also finalizing alternate equivalent emission standards (for certain subcategories) to the final surrogate standards in three areas: SO
As noted elsewhere in this preamble, we are finalizing a requirement to use filterable PM as a surrogate for the non-mercury metallic HAP and HCl as a surrogate for the acid gas HAP for all subcategories of coal-fired EGUs and for the solid oil derived fuel-fired EGUs. For all liquid oil-fired EGUs, we are finalizing a requirement to use filterable PM as a surrogate for the total metallic HAP, and we are finalizing HCl and HF limits.
In addition, we are finalizing alternative standards for certain HAP for some subcategories. The alternative pollutants and subcategories are as follows: (1) SO
We are finalizing a beyond-the-floor standard for Hg only for all existing coal-fired units designed for low rank virgin coal based on the use of activated carbon injection (ACI) for Hg control, as described elsewhere in this preamble. The EPA has determined that this beyond-the-floor level is achievable after considering the relevant CAA section 112(d)(2) provisions.
As noted elsewhere in this preamble, we are also finalizing a compliance assurance option that would allow you to monitor liquid oil fuel moisture to demonstrate that fuel moisture content is no greater than 1.0 percent. Provided that demonstration is made, you will not have to conduct additional testing and monitoring to demonstrate compliance with the HCl and HF emission limits for units in both liquid oil subcategories (
Pursuant to CAA section 112(h), we are finalizing a work practice standard for organic HAP, including emissions of dioxins and furans, for all subcategories of EGUs. The work practice standard being finalized requires the implementation of periodic burner tune-up procedures described elsewhere in this preamble. We are finalizing work practice standards because the significant majority of data for measured organic HAP emissions from EGUs are below the detection levels of the EPA test methods, even when long duration (around 8 hour) test runs are considered. As such, we consider it impracticable to measure emissions from these units. As discussed at proposal, we believe the inaccuracy of a majority of measurements, coupled with the extended sampling times used, allow a work practice standard under CAA section 112(h) to apply to these HAP.
In addition, as discussed below, we are creating a subcategory for limited use liquid oil-fired electric utility steam generating unit with an annual capacity factor of less than 8 percent of its maximum or nameplate heat input and we are establishing work practice standards applicable to such units pursuant to CAA section 112(h).
We are finalizing that new or existing EGUs are “coal-fired” if they combust coal more than 10 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15 percent of the annual heat input during any one calendar year and meet the final definition of “fossil fuel-fired.” We are finalizing that an EGU is considered to be in the coal-fired “unit designed for coal greater than or equal to 8,300 Btu/lb” subcategory if the EGU: (1) meets the final definitions of “fossil fuel-fired” and “coal-fired electric utility steam generating unit;” and (2) is not a coal-fired EGU in the “unit designed for low rank virgin coal” subcategory.
We are finalizing that the EGU is considered to be in the “unit designed for low rank virgin coal” subcategory if the EGU: (1) meets the final definitions of “fossil fuel-fired” and “coal-fired electric utility steam generating unit;” and (2) is designed to burn and is burning nonagglomerating virgin coal having a calorific value (moist, mineral matter-free basis) of less than 19,305 kJ/kg (8,300 Btu/lb) and that is constructed and operates at or near the mine that produces such coal.
We are finalizing that the EGU is considered to be an IGCC unit if the EGU: (1) Combusts a synthetic gas derived from gasified coal or solid oil-derived fuel (
We are finalizing that the EGU is considered to be in the “Continental liquid oil-fired” subcategory if (1) meets the final definitions of “oil-fired electric utility steam generating unit” and “fossil fuel-fired;” and (2) is located in the continental United States (U.S.).
We are finalizing that the EGU is considered to be “Non-continental liquid oil-fired” subcategory if (1) meets the final definitions of “oil-fired electric utility steam generating unit” and
We are finalizing that the EGU is considered to be “solid oil-derived fuel-fired” if (1) the EGU is not a coal-fired EGU and burns solid oil-derived fuel (
We are finalizing that the EGU is considered to be a “limited-use liquid oil-fired” if (1) the EGU meets the final definitions of “oil-fired electric utility steam generating unit” and “fossil fuel-fired;” and (2) has an annual capacity factor of less than 8 percent of its maximum or nameplate heat input, whichever is greater, averaged over a 24-month block contiguous period commencing.
As discussed below in section VI.E., for startup and shutdown, the requirements have changed since proposal. For periods of startup and shutdown, the EPA is finalizing work practice standards in lieu of numeric emission limits. Numeric emission limits apply for all other periods for all pollutants, except organic HAP. For malfunctions, the EPA is finalizing an affirmative defense for exceedances of the numerical emission limits that are caused by malfunctions.
We are requiring that you, as an owner or operator of a new or existing coal- or oil-fired EGU, must conduct performance tests to demonstrate compliance with all applicable emission limits. For units using certified continuous emissions monitoring systems (CEMS) that directly measure the regulated pollutant under final 40 CFR part 63, subpart UUUUU (
(1) For coal-fired units, IGCC units, and solid oil-derived fuel-fired units, if you elect to comply with the filterable PM emission limit, you must conduct filterable PM emissions testing using EPA Method 5 from Appendix A to part 60 of chapter 40 to determine initial compliance. Alternatively, if you elect to comply with the total non-mercury HAP metals emission limit or the individual non-mercury HAP metals emissions limits, you must conduct HAP metals testing using EPA Method 29 from Appendix A to part 60 of chapter 40. Note for this rule that the filter temperature for each Method 5 or 29 emissions test must be maintained at 160° ± 14 °C (320 ° ± 25 °F), and the material in Method 29 impingers must be analyzed for metals content. Whenever metals testing is performed with Method 29, you must report the front half and back half analytical fractions separately.
(2) For coal-fired, IGCC, and solid oil-derived fuel-fired units, you must use a Hg CEMS or a sorbent trap monitoring system for both initial compliance and continuous compliance using the continuous Hg monitoring provisions of Appendix A to 40 CFR part 63, subpart UUUUU, except where the low emitting EGU (LEE) requirements apply (see below). The initial performance test consists of all valid data recorded with the certified Hg monitoring system in the 30 boiler operating days of data collected with the certified monitoring system by the initial compliance demonstration date specified in § 63.10005.
(3) For coal-fired and solid oil-derived fuel-fired units and new or reconstructed IGCC units that employ FGD technology and elect to meet the alternative SO
(4) For liquid oil-fired units, you must conduct initial performance testing as follows. If you elect to meet the filterable PM limit instead of the non-mercury metals limit (total or individual), then use Method 5 with the filter material maintained at 160° ± 14°C (320° ± 25°F). Alternatively, you may use a PM CEMS as discussed elsewhere in this preamble. If you elect to meet either the total or individual HAP metals limit, you will use Method 29 for all non-mercury HAP metals. For Hg, conduct emissions testing using EPA Method 29 or 30B from Appendix A to part 60 of chapter 40, or ASTM Method D6784-02 (Reapproved 2008). For acid gases, conduct HCl and HF testing using EPA Method 26A, 320, or 26; or you may elect to comply by using an HCl CEMS and/or an HF CEMS; or under certain conditions you may choose to demonstrate compliance by measuring fuel moisture to demonstrate that moisture content is no greater than 1.0 percent. You must measure daily if fuel is delivered continuously or per shipment if fuel is delivered on a batch basis, or you may use a fuel moisture content certification provided by your fuel supplier. If you use a CEMS, then use the 30 boiler operating days of data collected with the certified monitoring system by the initial compliance demonstration date specified in § 63.10005 to determine initial compliance.
(5) For the required performance stack tests, if you are demonstrating compliance with a heat-input based standard, you must conduct concurrent O
(6) For an existing unit that you believe will qualify as LEE for Hg, you must conduct an initial Method 30B test over 30 days and follow the calculation procedures in the final rule to document a potential to emit less than 10 percent of the applicable Hg emissions limit or less than 29 pounds of Hg per year. If your unit qualifies as a LEE for Hg, you must conduct subsequent performance tests on an annual basis to demonstrate that the unit continues to qualify. For all other pollutants, you must conduct the initial compliance test, and then all other required tests over a 3-year period, and in all such tests, your emission results must be less than 50 percent of the applicable emission limit. If you qualify as a LEE on that basis, you must conduct subsequent performance tests every 3 years to demonstrate that the unit continues to qualify.
(7) You may use results from tests conducted no earlier than 12 months before the compliance date of this rule as the initial performance test for an applicable pollutant, provided that:
a. You certify and keep records demonstrating that no significant changes have occurred,
b. Tests were conducted using methods allowed in this rule in accordance with § 63.10007 and Table 5,
c. You have records of all parameters needed to convert results to units of the standard for the entire period, and
d. For a CEMS-based performance test, you have all the required data for the entire 30-boiler operating day rolling average period.
Under the final rule, you may elect to comply continuously with an operating limit, established during the initial performance test, to demonstrate continuous compliance with the filterable PM, total non-mercury HAP metals, or individual non-mercury HAP metals limit. You will use a PM CPMS to monitor compliance with the operating limit. The PM CPMS operating principle must be based on in-stack or extractive light scatter, light scintillation, beta attenuation, or mass accumulation detection of the exhaust gas or representative exhaust gas sample. The reportable measurement output from the PM CPMS may be expressed as milliamps, stack concentration, or other raw data signal. Meeting the operating limit serves as your demonstration of continuous compliance with the filterable PM, total non-mercury HAP metals, or individual non-mercury HAP metals limit. As mentioned earlier, if you use this method to demonstrate continuous compliance, you must install a PM CPMS and establish the operating limit during the initial compliance test for filterable PM, total non-mercury HAP metals, or individual non-mercury HAP metals. As noted below, when you use this operating limit, you can reduce stack testing frequency to demonstrate ongoing compliance. You may also opt to install and operate a PM CEMS certified in accordance with Performance Specification 11 and Procedure 2 of 40 CFR part 60, Appendices B and F, respectively. If you elect to use this option, then the requirements for quarterly testing with Method 5, or annual testing and use of a PM CPMS, are no longer applicable.
For dioxins and furans and non-dioxin/furan organic HAP, you must submit documentation that you have conducted a combustion process tune-up, a thorough equipment inspection, and an optimization to minimize generation of CO and NO
This same work practice standard also applies in place of any emission limits for Hg, non-mercury metals HAP, acid gas HAP, dioxins and furans, and non-dioxin/furan organic HAP from a limited-use, liquid oil-fired EGU (
To demonstrate continuous compliance with the emission limitations, the final rule includes the following requirements:
(1)
For each unit using HCl, HF, SO
For HCl and HF CEMS, the EPA is adding monitoring provisions as Appendix B to 40 CFR part 63, subpart UUUUU. Appendix A references performance specification (PS) 15 of Appendix B to 40 CFR part 60 for Fourier Transform Infrared (FTIR) CEMS for procedures to certify and conduct ongoing quality assurance on these FTIR CEMS. In addition, we expect to publish a PS specific to HCl CEMS in the near future (prior to the compliance date of this rule). In the meantime, you may petition the Administrator under the procedure given in 40 CFR 63.7(f) for an alternative approach to compliance monitoring or testing for HCl or any other regulated pollutant.
When using a sorbent trap monitoring system, you may use each pair of sorbent traps to collect Hg samples for no more than 15 boiler operating days. Under the general duty to monitor at all times, you must replace traps in a timely manner to ensure that Hg emissions are sampled continuously.
For Hg monitoring, the EPA is adding Hg monitoring provisions as Appendix A to 40 CFR part 63, subpart UUUUU, and requiring use of these provisions to document continuous compliance with the rule for coal-fired, IGCC, and solid oil derived-fired units that cannot qualify as LEEs. Appendix A consolidates all Hg monitoring provisions.
Today's rule provides two basic Hg continuous monitoring options: Hg CEMS and sorbent trap monitoring systems. Appendix A requires initial certification and periodic quality assurance (QA) testing of the Hg CEMS and sorbent trap monitoring systems. The certification tests required for the Hg CEMS are a 7-day calibration error test; a linearity check, using NIST-traceable elemental Hg standards; a 3-level system integrity check (similar to a linearity check), using NIST-traceable oxidized Hg standards; a cycle time test; and a relative accuracy test audit (RATA). Table A-1 of Appendix A summarizes the performance specifications for the required certification tests. For ongoing QA of the Hg CEMS, Appendix A requires daily calibrations, weekly single-point system integrity checks, quarterly linearity checks (or 3-level system integrity checks), and annual RATAs. Table A-2 in Appendix A summarizes these ongoing QA test requirements and the applicable performance criteria for Hg CEMS, which are consistent with those published in support of CAMR and are, thus, familiar to the industry.
For sorbent trap monitoring systems, a RATA is required for initial certification, and annual RATAs are required for ongoing QA. The performance specification for these RATAs is the same as for the RATAs of the Hg CEMS. Bias adjustment of the measured Hg concentration data is not required. For day-to-day operation of the sorbent trap system, Appendix A requires you to follow the procedures and QA/QC criteria in PS 12B in Appendix B to 40 CFR part 60. PS 12B is nearly identical to the Appendix K to 40 CFR part 75, published in support of CAMR and with which the industry is familiar. The 40 CFR part 75 concepts of:
a. Determining the due dates for certain QA tests on the basis of “QA operating quarters” and
b. Grace periods for certain QA tests apply to both Hg CEMS and sorbent trap monitoring systems. Mercury concentrations measured by Hg CEMS or sorbent trap systems are used together with hourly flow rate, diluent gas, moisture, and electrical load data, to express the Hg emissions in units of the rule, on an hourly basis (
For HCl and HF CEMS, the EPA is adding monitoring provisions as Appendix B to 40 CFR part 63, Subpart UUUUU. Appendix A references performance specification (PS) 15 of Appendix B to 40 CFR part 60 for Fourier Transform Infrared (FTIR) CEMS for procedures to certify and conduct ongoing quality assurance on these FTIR CEMS. In addition, we expect to promulgate a generic PS specific to HCl CEMS prior to the compliance date of this rule. In the meantime, you may petition the Administrator under the procedure given in 40 CFR 63.7(f) for an alternative approach to compliance monitoring or testing for HCl or any other regulated pollutant.
(2)
a. If you use a PM CPMS and associated operating limit, you may conduct the applicable Method 5 or Method 29 test once annually rather than quarterly, in which case you must re-establish the operating limit during each performance test. A PM CPMS does not need to meet the requirements for a PM CEMS under PS 11. The final rule includes basic quality checks that the PM CPMS must meet and a requirement for you to develop and follow a site-specific monitoring plan to be approved by the delegated authority. You must demonstrate compliance with the operating limit by using all valid hourly data collected during each successive 30-boiler operating day period rolled daily. The 30-boiler operating day rolling average is calculated by all of the valid hourly average PM CPMS output values collected for the 30 boiler operating days (excluding hours of startup and shutdown;
b. If you combust liquid fuels and if your fuel moisture content is no greater than 1.0 percent, you may demonstrate ongoing compliance with HCl and HF emissions limits by:
i. Measuring fuel moisture content of each shipment of fuel if your fuel arrives on a batch basis;
ii. Measuring fuel moisture content daily if your fuel arrives on a continuous basis; or
iii. Obtaining and maintaining a fuel moisture certification from your fuel supplier.
Should the moisture in your liquid fuel be more than 1.0 percent, you must
i. Conduct HCl and HF emissions testing quarterly and establish site-specific monitoring to demonstrate continued acid gas control performance between periodic tests, or
ii. Use an HCl CEMS and/or HF CEMS.
c. If your existing unit qualifies as an LEE for Hg, you must conduct another 30-day Method 30B performance test on your unit once per year to reestablish that the unit continues to qualify as a LEE for Hg. If the results of the LEE test show that the unit exceeds 10 percent of the emissions limit or exceeds the potential to emit 29 pounds of Hg per year, you will lose LEE status for the unit. You can regain LEE status for that unit if every required performance test for a 3-year period shows that emissions from the unit did not exceed the LEE limit. If LEE status is lost for a solid fuel unit, you must commence quarterly performance testing until you install,
d. If a liquid oil-fired EGU has an annual capacity factor on oil of less than 8 percent of its maximum or nameplate heat input, whichever is greater, you must demonstrate continuous compliance with the applicable work practice standard by conducting at least once every 36 calendar months (48 calendar months if a neural network is employed) a combustion process tune-up, a thorough equipment inspection, and an optimization to minimize generation of CO and NO
e. The rule allows a grant of LEE status to existing units with test results that show a history of low, non-mercury emissions. As mentioned earlier, LEE status reduces testing frequency for units. After a 3-year period during which every emissions test for a specific pollutant shows emissions no greater than 50 percent of the emissions limit, you may reduce the emissions testing frequency for that specific non-mercury pollutant to once every 36 months. If any subsequent emissions test for that pollutant exhibits emissions greater than 50 percent of the emissions limit, you must revert to the original emissions testing frequency until you re-establish a 3-year period of very low emissions no greater than 50 percent of the standard.
f. For liquid oil-fired units that demonstrate continuous compliance with quarterly performance tests for HCl and HF emission limits rather than through use of HCl and HF CEMS, the final rule requires a site-specific monitoring plan in addition to the quarterly tests. For these pollutants, there is unlikely to be any existing underlying monitoring (such as compliance assurance monitoring) that serves as an additional tool to ensure the source's operations remain consistent with operating conditions during a recent successful performance test. The requirement for a site-specific monitoring plan fills this gap and ensures that in between tests, the source continues to operate in a manner designed to maintain HCl and HF emissions in compliance with the emission limits under this rule. The appropriate parameters to monitor will depend on the compliance strategy employed by a specific source, and thus EPA is enabling the monitoring approach to be established on a case-by-case basis. Given the relatively small number of these units and the other compliance options available, we anticipate that this approach will apply to a small set of units. The monitoring plan will identify the parameters monitored, the monitoring methods, the QA/QC elements that apply, and the data reduction elements (including appropriate averaging periods, as applicable). See 40 CFR 63.10000(c)(2)(ii).
(3)
All new and existing sources in all subcategories must comply with certain requirements of the General Provisions (40 CFR part 63, subpart A), which are identified in Table 9 of this final rule. The General Provisions include specific requirements for notifications, recordkeeping, and reporting. You must submit a notification of compliance status report for each unit, according to the schedule required by 40 CFR 63.9(h) of the General Provisions, including a certification of compliance.
Except for units that use CEMS for continuous compliance, under this rule you must provide semiannual compliance reports, as required by 40 CFR 63.10(e)(3) of subpart A, that indicate whether a deviation from any of the requirements in the rule occurred and whether or not any process changes occurred and compliance certifications were reevaluated. As discussed below, we are finalizing a requirement to use the 40 CFR part 75-based Emissions Collection and Monitoring Plan System (ECMPS) for reporting emissions and related data for units using CEMS for most pollutants. Also, as discussed below, for the PM CPMS, PM CEMS, and performance test results, we require you to use EPA's WebFIRE
This rule requires you to keep certain records to demonstrate compliance with each emission limit and work practice standard. The General Provisions to 40 CFR part 63 specify these recordkeeping requirements (see Table 9 to this subpart). Among other specific records, you must keep the following:
(1) All reports and notifications submitted to comply with this rule.
(2) Continuous monitoring data as required in this rule.
(3) Each instance in which you did not meet an emission limit, work practice requirement, operating limit, or other compliance obligation (
(4) Daily hours of operation by each unit.
(5) As part of the general duty to keep all monitoring data, fuel moisture content of liquid fuel, if you elect to demonstrate compliance using that information.
(6) A copy of the results of all performance tests, monitor certifications, performance evaluations, or other compliance demonstrations conducted to demonstrate initial or continuous compliance with this rule.
(7) A copy of your site-specific performance evaluation test plans developed for this rule as specified in 40 CFR 63.8(e), if applicable.
(8) A copy of your acid gas control system parameter monitoring plan under 40 CFR 63.10000(c)(2)(ii).
You also must submit the following additional notifications:
(1) Notifications required by the General Provisions.
(2) Initial Notification no later than 120 calendar days after you become subject to this subpart.
(3) Notification of Intent to conduct performance tests and/or compliance demonstration at least 60 calendar days before the performance test and/or compliance demonstration is scheduled.
(4) Notification of Compliance Status 60 calendar days following completion of the performance test and/or compliance demonstration.
Electronic reporting is becoming a common element of modern life (as evidenced by electronic banking and income tax filing), and the EPA is beginning to require electronic submittal of environmental data. Electronic reporting is already common in environmental data collection and many media offices at EPA are reducing reporting burden for the regulated community by embracing electronic reporting systems as an alternative to paper-based reporting.
One of the major benefits of reporting electronically is standardization, to the extent possible, of the data reporting formats that provides more certainty to users of what data are required in specific reports. For example, electronic reporting software allows for more efficient data submittal and the software's validation mechanism helps industry users submit fewer incomplete reports. This alone saves industry report processing resources and reduces transaction times. Standardization also allows for development of efficient methods to compile and store much of the documentation required to be reported by this rule.
We are requiring that you submit certain reports electronically. In addition to supporting regulation development, control strategy development, and other air pollution control activities, having an electronic database populated with these reports will save industry, state, local, tribal agencies, the public, and the EPA significant time, money, and effort while also improving the transparency and quality of emission inventories and, as a result, air quality regulations.
The reports to be submitted electronically include all performance test reports, notification of compliance status reports, compliance, and continuous monitoring data summaries specified in 40 CFR 63.10031 of this rule. Performance tests are required to be conducted as described in 40 CFR 63.7 of the General Provisions. The data that must be submitted as the performance test report are also described in 40 CFR 63.7. These data must be submitted (except in limited cases) to EPA's WebFIRE database by using the electronic reporting tool (ERT) and the Compliance and Emissions Data Reporting Interface (CEDRI) that is accessed through EPA's Central Data Exchange (CDX), as described below. The data requirements for the notification of compliance status and compliance reports are described in detail in the regulatory text (40 CFR 63.10031) of this rule, but they essentially mirror the requirements in 40 CFR 63.6 of the General Provisions. These reports will also be submitted to WebFIRE using an electronic form found in CEDRI and through the CDX as described below. As required in 40 CFR 63.10031(f)(2) of the final rule, the continuous monitoring summaries are required to be submitted quarterly. The quarterly reports must include all of the calculated 30-boiler operating day rolling average values derived from the PM CPMS. These reports will also be submitted to WebFIRE using an electronic form found in CEDRI and through the CDX, as described below. This same approach will apply if a source elects to use a PM CEMS or receives approval to use a HAP metals CEMS as an alternative monitoring method.
The availability of electronic reporting for sources subject to the Subpart UUUUU will provide efficiency, improved services, better accessibility of information, and more transparency and accountability. Additionally, submittal of these required reports electronically provides significant benefits for regulatory agencies, industry, and the public. The compliance data electronic reporting system (CEDRI and CDX) is being developed such that once a facility's initial data entry into the system is established and a report is generated, subsequent data submittal will only consist of electronic updates to existing information in the system. Such a system will effectively reduce the burden associated with submittal of data and reports by reducing the time, costs, and effort required to submit and update hard copies of documentation. State, local, and tribal air pollution control agencies will also benefit from having access to the more streamlined and accurate electronic data submitted to the EPA. Electronic reporting will allow for an electronic review process rather than a manual data assessment, making review and evaluation of the source-provided data and calculations easier and more efficient. Electronic reporting will also benefit the public by generating a more transparent review process and increasing the ease and efficiency of data accessibility. Furthermore, electronic reporting will reduce the burden on the regulated community by reducing the effort involved in data collection and reporting activities. In the future, we anticipate there will be fewer and less substantial data collection requests in conjunction with prospective required residual risk assessments or technology reviews. Electronic reporting will substantially reduce this burden, because the EPA will already have these data available and consolidated in an electronic database named WebFIRE. We anticipate that using electronic reporting for the required reports will result in an overall reduction in reporting costs; for a discussion of the economic and cost impacts of electronic reporting, see section XII.D. of this preamble.
Another benefit of electronic data submittal is that these data will greatly improve the overall quality of existing and new emissions factors by supplementing the pool of emissions test data for establishing emissions factors and by ensuring that the factors are more representative of current industry operational procedures. A common complaint heard from industry and regulators is that emission factors are outdated or not representative of a particular source category. With timely receipt and incorporation of data from most performance tests, the EPA will be able to ensure that emission factors, when updated, represent the most current range of operational practices.
Data entry of these electronic reports will be through the CEDRI that is accessed through EPA's CDX (
Once you have accessed CEDRI, you will select the applicable subpart for the report that you are submitting. You will then select the report being submitted, enter the data into the form, and click on the submit button. In some cases, such as with submittal of a notification of compliance status report, you will select the report icon, enter basic facility information, and then upload the report in a specified file format.
In addition, we believe that there will be value in allowing other reporting forms to be developed and used in cases where the other reporting forms can provide an alternate electronic file consistent with EPA's form output format. This approach has been used successfully to provide alternatives for other electronic forms (
In cases where performance test data are to be submitted to the EPA, you must enter the performance test data
Submitting performance test data electronically to the EPA will apply only to those performance tests conducted using test methods that will be supported by the ERT. The ERT contains a specific electronic data entry form for most of the commonly used EPA reference methods. A listing of the pollutants and test methods supported by the ERT is available at the ERT Web site listed above.
The EPA has determined that harmonization of the monitoring and reporting requirements of this final rule with 40 CFR part 75 is appropriate, where the affected industry already has a well-defined system for continuous monitoring and reporting of emissions under that part. Therefore, the Agency is finalizing monitoring and reporting requirements for most CEMS that are consistent with 40 CFR part 75. You must report CEMS data (other than PM CEMS data or data from alternative monitoring subject to site-specific approval such as a HAP metals CEMS) to the EPA electronically, on a quarterly basis, using the ECMPS.
The ECMPS process divides electronic data into three categories, the first of which is monitoring plan data. You must maintain the electronic monitoring plan separately and can update it at any time if necessary. The monitoring plan documents the characteristics of the affected units (
The second type of data collected through ECMPS is certification and QA test data. These data include data from linearity checks, RATAs, cycle time tests, 7-day calibration error tests, and a number of other QA tests that are required to validate the emissions data. You may submit the results of these tests to the EPA as soon as you obtain the results, with one notable exception. Daily calibration error tests are not treated as individual QA tests, due to the large number of records generated each quarter. Rather, these tests must be included in the quarterly electronic reports, along with the hourly emissions data. The ECMPS system is set up to receive and process certification and QA data from SO
To accommodate the certification and QA tests for Hg CEMS, other CEMS, and sorbent trap monitoring systems, the structure and functionality of ECMPS needs relatively few changes, because most of the tests are the same as those required for other gas monitors. For reporting Hg, HCl, SO
The third type of data collected through ECMPS is the hourly emissions data, which, as previously noted, is reported on a quarterly schedule. You must submit reports within 30 days after the end of each calendar quarter. The emissions data format requires hourly reporting of all measured and calculated emissions values, in a standardized electronic format. You must report direct measurements made with CEMS, such as gas concentrations, in a Monitor Hourly Value (MHV) record. A typical MHV record for gas concentration includes data fields for:
(1) The parameter monitored (
(2) The unadjusted and bias-adjusted hourly concentration values (note that if bias adjustment is not required, only the unadjusted hourly value is reported);
(3) The source of the data,
(4) The percent monitor availability (PMA), which is updated hour-by-hour. This generic record structure could easily accommodate hourly average measurements from CEMS used under this rule.
The ECMPS reporting structure is quite flexible, which makes it useful for assessing compliance with various emission limits. The Derived Hourly Value (DHV) record allows calculations of a wide variety of quantities from the reported hourly emissions data. For instance, if an emission limit is expressed in units of lb/MMBtu, the DHV record can be used to report hourly pollutant concentration values in these units of measure, since the lb/MMBtu values can be derived from the hourly pollutant and diluent gas (CO
One change in this rule from standard 40 CFR part 75 emissions data reporting is elimination of the requirement to provide substitute data calculations within ECMPS. The ARP and other emissions trading programs that report emissions data to the EPA using 40 CFR part 75 require provision of a complete data record. Emissions data are required to be reported for every unit operating hour. When CEMS are out of service, substitute data must be reported to fill in the gaps. However, for the purposes of compliance with a NESHAP, reporting substitute data during monitor outages is not necessary, as quantification of total mass emissions is not the focus of the rule. Hours when a monitoring system is out of service would be counted as hours of monitor down-time and may be a deviation from the monitoring requirements of this rule unless the rule provides an exception, as it does for routine quality control and maintenance activities.
In contrast to the CEMS-related data that would be submitted through ECMPS, you must submit reports of performance tests and PM CPMS data to EPA's WebFIRE database by using CEDRI that is accessed through EPA's
Other notifications and reports not currently accepted by the electronic reporting system will be submitted in hardcopy form at this time.
The previous section described the requirements that EPA is finalizing in this rule. This section will discuss in greater detail the key changes EPA is making from the proposed. These changes result from EPA's review of the additional data and information provided to us and our consideration of the many substantive and thoughtful comments submitted on the proposal. While our approach and methodology to establishing the standards remain the same, the changes make the final rule more flexible and cost-effective, reduce reliability concerns and improve clarity, while fully preserving, or improving, the public health and environmental protection required by the CAA.
Since proposal, the EPA has made certain changes to the applicability provisions of the final rule to provide clarity. These changes do not change the universe of sources subject to the rule.
The EPA is revising a number of the proposed definitions and adding a definition for “natural gas-fired electric utility steam generating unit” in the final rule to provide clarity to the regulated community concerning the standards applicable to coal- and oil-fired EGUs.
In the proposed rule, the EPA defined “[e]lectric utility steam generating unit” consistent with the CAA section 112(a)(8) definition:
A fossil fuel-fired combustion unit of more than 25 megawatts electric (MWe) that serves a generator that produces electricity for sale. A fossil fuel-fired unit that cogenerates steam and electricity and supplies more than one-third of its potential electric output capacity and more than 25 MWe output to any utility power distribution system for sale is considered an electric utility steam generating unit.
We also indicated how we would determine whether units were coal-fired or oil-fired fired EGUs: “If an EGU burns coal (either as a primary fuel or as a supplementary fuel), or any combination of coal with another fuel (except solid waste as noted below), the unit is considered to be coal fired under this proposed rule. If a unit is not a coal-fired unit and burns only oil, or oil in combination with another fuel other than coal (except as noted below), the unit is considered to be oil fired under this proposed rule.” 76 FR 25020.
We proposed a definition for the term “fossil fuel-fired” because that term was not defined in the statute and we wanted to clarify the level of fossil fuel combustion necessary to satisfy the CAA section 112(a)(8) definition of EGU. The definition focused on coal and oil combustion because the EPA was only regulating coal- and oil-fired EGUs in this final rule. The proposed definition contained two primary elements: (1) the unit must be capable of combusting sufficient amounts of coal or oil to generate the equivalent of 25 megawatts electrical output; and (2) the unit must have fired coal or oil for more than 10.0 percent of the average annual heat input during the previous 3 calendar years or for more than 15.0 percent of the annual heat input during any one of those calendar years. 76 FR 25025. We further stated that for a unit to be “capable of combusting” coal or oil the unit must have a permit that authorized the combustion of coal or oil and also have the appropriate fuel handling facilities on-site.
As explained in the proposed rule, natural gas-fired EGUs were not included in the December 2000 listing so such units that otherwise met the CAA section 112(a)(8) definition of EGU because of natural gas combustion are not subject to the final rule. In the proposed rule, we stated that an EGU that “combusts natural gas exclusively or natural gas in combination with another fuel where the natural gas constitutes 90 percent or more of the average annual heat input during the previous 3 calendar years or 85.0 percent or more of the annual heat input during any one of those calendar years” was not subject to the rule.
We further explained that the percentages included in the definition of “fossil fuel-fired” would prevent units that primarily combusted fuels other than fossil fuels from being subjected to the final rule:
Units that do not meet the definition of fossil-fuel fired would, in most cases, be considered IB units subject to one of the Boiler NESHAP. Thus, for example, a biomass-fired EGU, regardless of size, that utilizes fossil fuels for startup and flame stabilization purposes only (
Thus, in the proposed rule, we intended to create thresholds to determine when a unit is fossil fuel-fired and for which fossil fuel the unit is fossil fuel-fired. We intended to include a unit combusting more than the defined amount of coal in one of the coal-fired EGU subcategories. If a unit is not coal-fired and it is combusting more than the defined amount of oil, we intended to include the unit in one of the oil-fired EGU subcategories. We also intended to make clear that EGUs that are neither coal-fired nor oil-fired but combust more than the defined amount of natural gas are natural gas-fired EGUs not subject to the final standards. However, the definitions, as proposed, were not sufficiently descriptive.
For example, we included a definition for “coal-fired electric utility steam generating unit” that did not include the requirement that the unit must combust coal for at least 10 percent of the heat input over 3 years or 15 percent of the heat input in any one year. Instead, in the proposed rule we indicated that a unit was coal-fired if it burned coal in any amount. We did not intend to
In addition, we proposed to define “[u]nit designed to burn solid oil fuel subcategory” to include any EGU that burned a solid fuel derived from oil for more than 10.0 percent of the average annual heat input during the previous 3 calendar years or for more than 15.0 percent of the annual heat input during any one of those calendar years, either alone or in combination with other fuels. We also included the 10 percent/15 percent thresholds in the definition for the liquid oil subcategory, but, as stated above, we did not include the thresholds in the definition of “coal-fired” EGU. Therefore, there would be some confusion for a source that blended coal with solid oil derived fuel (
For these reasons, we are revising the definitions for “coal-fired electric utility steam generating unit,” “integrated gasification combined cycle electric utility steam generating unit,” and “oil-fired electric utility steam generating unit,” and we are adding a definition of “natural-gas fired electric utility steam generating unit” as set out in 40 CFR 63.10042.
In addition to these changes, we are revising the definition of “fossil fuel-fired” based on comments. We are revising the definition to remove the heat input equivalent of 25 MW because commenters noted that the equivalency used (taken from 40 CFR part 60, subpart Da) could not be applied consistently because of differing boiler efficiencies. Commenters noted that owners/operators were familiar with the use of the “MW” term for the boilers and boilers include nameplate capacities that are readily identifiable.
We are also including a revision to the definition so that the fossil fuel combustion thresholds of 10 percent over 3 consecutive years and 15 percent in one year are evaluated after the applicable compliance date of the final rule on a rolling basis. Commenters correctly noted that some existing coal- and oil-fired EGUs will convert their units to alternative fuels (
The new definition is set out in 40 CFR 63.10042.
For clarity, we are also removing the definition of “[u]nit designed to burn liquid oil fuel subcategory,” revising the definition of “[u]nit designed to burn solid oil fuel subcategory,” adding definitions for the continental and non-continental liquid oil-fired EGU subcategories, and adding a definition of a limited-use liquid oil-fired EGU as set out in 40 CFR 63.10042.
In the proposed rule, we stated that we believed EGUs may at times not meet the definition of an EGU subject to this subpart. For example, we explained that there may be some cogeneration units that are determined to be covered under the Boiler NESHAP. Such unit(s) may make a decision to increase the proportion of production output being supplied to the electric utility grid, thus causing the unit(s) to meet the EGU cogeneration criteria (
Several commenters asked the Agency to include provisions in the final rule that would address situations like the ones described in the preamble to the proposed rule. Because applicability to the final rule is based in part on the statutory definition of an EGU is CAA section 112(a)(8), similar to the situation with units combusting solid waste under CAA section 129(g)(1) (
In addition, we are finalizing a provision whereby you may opt to remain subject to the provisions of this final rule, unless you combust solid waste, in which case you are a solid waste incineration unit subject to standards under CAA section 129 (
The changes to the definitions described above provide clarity to sources, permitting agencies, and the public about the applicability of the rule and help ensure that sources are appropriately covered by the regulation.
In this final rule, the EPA is adding subcategories for limited-use oil-fired units and non-continental oil-fired units and revising the definitions for the coal-fired EGU subcategories.
The proposed rule subcategorized EGUs burning coal into two subcategories: EGUs designed for coal ≥8,300 Btu/lb and EGUs designed for virgin coal <8,300 Btu/lb (low rank virgin coal). We received a number of comments indicating that the definition of the low rank virgin coal subcategory was technically deficient.
Under CAA section 112(d)(1), the Administrator has the discretion to “* * * distinguish among classes, types, and sizes of sources within a category or subcategory in establishing * * *” standards. The EPA maintains that, normally, any basis for subcategorization (
When developing the proposed rule, we examined the EGUs in the top performing 12 percent of sources for Hg emissions. We determined that:
There were no EGUs designed to burn a nonagglomerating virgin coal having a calorific value (moist, mineral matter-free basis) of 19,305 kJ/kg (8,300 Btu/lb) or less in an EGU with a height-to-depth ratio of 3.82 or greater among the top performing 12 percent of sources for Hg emissions, indicating a difference in the emissions for this HAP from these types of units. The boiler of a coal-fired EGU designed to burn coal with that heat value is bigger than a boiler designed to burn coals with higher heat values to account for the larger volume of coal that must be combusted to generate the desired level of electricity. Because the emissions of Hg are different between these two subcategories, we are proposing to establish different Hg emission limits for the two coal-fired subcategories. For all other HAP from these two subcategories of coal-fired units, the data did not show any difference in the level of the HAP emissions and, therefore, we have determined that it is not reasonable to establish separate emissions limits for the other HAP. 76 FR 25036-67.
Based on this determination, we proposed to establish two subcategories with separate Hg limits. Comments on the proposed rule indicate that we correctly identified the EGUs that should be included in each subcategory, but the comments also demonstrated that we made certain incorrect conclusions that require us to revise the definitions of our coal-fired EGU subcategories. The revised definitions ensure that the EGUs we identified at proposal as having different Hg emissions remain in one subcategory.
As stated above, we believed at proposal that the boiler size was the cause of the different Hg emissions characteristics that led us to propose subcategorization, but many commenters indicated that it was not the boiler size but the fact that the EGUs burned a nonagglomerating virgin coal having a calorific value (moist, mineral matter-free basis) of less than 19,305 kJ/kg (8,300 Btu/lb) (low rank virgin coal) that causes the disparity in Hg emissions. Several commenters indicated that their EGUs were designed to burn and burned low rank virgin coal but the units did not meet the height-to-depth ratio that EPA proposed. For example, the height-to-depth ratio of certain EGUs in this subcategory is in fact 3.5, not 3.82. Further, there are other EGUs in this subcategory that are circulating fluidized bed (CFB) combustion units which do not meet the height-to-depth ratio parameters in the proposed rule, nor are they anything like the pulverized coal (PC) EGUs we initially identified as having the 3.82 height-to-depth ratio.
In addition to the comments concerning EGUs firing this coal, we received comments from at least two commenters indicating that the EPA should clarify in which subcategory a unit belongs when it does not burn low rank virgin coal but is designed to combust low rank virgin coal and has a height-to-depth ratio of greater than 3.82. Commenters also indicated that CFB units that are burning coal-refuse
Based on the comments received, we reevaluated the subcategory definitions because we were concerned that the definitions we proposed would improperly categorize a number of the EGUs in both subcategories. We concluded that we should not maintain the proposed definition for “[u]nits designed for coal <8,300 Btu/lb” and exclude the CFB units and PC EGUs with a height-to-depth ratio less than 3.82 that combusted low rank virgin coal.
We were equally concerned that the subcategory definitions not be revised in a manner that would move EGUs that we believed the data show could comply with a more stringent standard into a subcategory with a less stringent standard because, aside from the type of EGUs we identified, all other classes, types, and sizes of EGUs were represented among the top performing 12 percent for Hg in the ≥8,300 Btu/lb subcategory. We were particularly concerned about the CFB units because other CFB units are well represented among the best performing EGUs for Hg in the ≥8,300 Btu/lb subcategory, but the CFB units burning low rank virgin coal are not achieving the same levels of Hg emissions control. Including the best performing CFB units from the other subcategory in the low rank virgin coal subcategory would likely lead to a Hg standard as stringent as the standard for
After fully considering the available information, including the comments received, we have concluded that it is appropriate to continue to base the subcategory definitions, at least in part, on whether the EGUs were designed to burn and, in fact, did burn low rank-virgin coal, but that it is not appropriate to continue to use the height-to-depth ratio criteria because that approach would potentially exclude EGUs we identified as having different Hg emission characteristics and include EGUs that did not have different emissions characteristics. We recognize that some commenters have taken the position that it is unlawful to subcategorize based on factors such as fuel type but nothing in the statute prohibits such an approach and the case law supports this approach to the extent courts have considered subcategorization based on such factors.
We considered basing the subcategory solely on an EGU being designed to burn and burning low rank virgin coal. We decided not to do so because we were concerned that such a definition would allow sources to potentially meet the definition by combusting very small amounts of low rank virgin coal. For example, an EGU on the east coast (or any other region) that was not designed to burn and did not routinely burn low rank virgin coal could import one truck full of low rank virgin coal and burn a very small quantity of it periodically to meet the subcategory definition. To avoid creating this potential loophole, we considered other characteristics that would distinguish EGUs combusting low rank virgin coal.
We determined that these EGUs are universally constructed “at or near” a mine containing low rank virgin coal because it is not cost-effective to transport large quantities of such fuel long distances. Furthermore, we believe that this subcategory of EGUs are almost always built at a mine and limited transportation of the coal is only required as the mine face moves over the course of time. Many such EGUs construct dedicated rail lines, private roads, or conveyor systems to transport the coal to the EGU as the mine face moves. We obtained information from data acquired to develop the CSAPR indicating that the longest distance any EGU firing low rank virgin coal transports that coal is 40 miles. We believe that this distance is near the outer limits for the transport of such coal, but, even for those EGUs, the EGUs were constructed closer to a now idle mine or closer to the working face of a mine that has now expanded away from the EGU site. For these reasons, we are including a requirement that the unit be constructed and operated at or near a mine containing the low rank virgin coal it burns.
We are revising the coal-fired EGU subcategory definitions as set out in 40 CFR 63.10042.
We believe the revised subcategory definitions are reasonable for all the reasons set forth above. The revised definitions maintain the EGUs we identified as having different Hg emissions characteristics in one subcategory and the definitions prevent other EGUs that are not firing low rank virgin coal from being required to comply only with the less stringent Hg emission standard.
As discussed in response to comments, we do not believe that additional subcategorization of other coal-fired EGUs is reasonable or appropriate. All other coal-fired EGUs that are not designed to burn and are burning low rank virgin coal are represented among the best performing sources for Hg, such that no argument exists to support that the Hg emissions from those EGUs are different. In any case, even if emissions are somewhat different as some commenters suggest, we would decline to exercise our discretion because the data demonstrate that the best performing EGUs designed to burn and burning all other ranks of coal are able to achieve the MACT level of control using currently available controls and other HAP emission reduction mechanisms (
A second issue related to subcategorization concerns non-continental liquid oil-fired EGUs. At proposal, the EPA did not have sufficient emissions data from non-continental liquid oil-fired EGUs upon which to base a subcategory and took comment on the issue. The data have since been provided in response to the ICR and we received comments suggesting that a non-continental subcategory is appropriate based on the location of such units, the limited availability of alternative fuel sources, and the fact that the emissions characteristics of such units are distinct from continental liquid oil-fired EGUs. The EPA has evaluated the data and comments and we agree that a subcategory is warranted based for the reasons suggested by the commenters. Therefore, the Agency is finalizing the liquid oil-fired EGU subcategories of “continental” and “non-continental.”
Lastly, the EPA did not have sufficient information on limited-use liquid oil-fired EGUs upon which to base a subcategory at proposal because some sources required to test under the ICR did not submit the data until after proposal. We took comment on whether a limited-use subcategory was warranted. Commenters indicated that their units were a different class and type of units because many of them were only called to service to address reliability issues associated with, for example, natural gas curtailments. The commenters further indicated that their units are different because of the generally infrequent use and the sporadic, and at times frequent, start-up and shutdown periods (
The proposed rule included numerical emission limits for PM, Hg, HCl, HF, SO
In addition to adjustments to the emission limits themselves, we are finalizing several other changes to the emission standards that will simplify and improve compliance for sources without compromising the toxics reductions achieved. One key change, as discussed elsewhere in this notice, is that we have changed the surrogate for non-mercury metallic HAP from total particulate matter (PM) to filterable PM for coal-fired and solid oil-derived EGUs. This change is based on information provided in comments and our own conclusion that measurement of filterable PM provided assurance of equivalent HAP emissions control. Most of the non-mercury metal HAP, for which PM is a surrogate, are filterable PM and the one that is not (Se) is well controlled by the limit on acid gases. Using filterable PM as the surrogate will allow us to use continuous PM monitoring systems, which measure filterable (but not total) PM, thereby providing a more continuous measure of compliance.
For liquid oil-fired EGUs, based on comments received and corrections made to the data submitted, we have added a filterable PM limit in the final rule as an alternative equivalent standard for the total metal-HAP limit in the proposed rule. In addition, as discussed elsewhere in this notice, we have added measurement of the moisture content of the oil (with a 1 percent limit) as an alternate compliance assurance measure for liquid oil-fired EGUs for determining compliance with the HCl and HF limits. Direct measurement of HCl and HF remains a compliance demonstration method in the final rule. Finally, as discussed in section VI.D of this notice, the final work practice standard consisting of burner tune-ups, much like those required for organic HAP control, for those limited-use liquid oil-fired EGUs whose annual capacity factor is less than 8 percent.
As noted earlier in section V.D., the final rule includes a work practice standard for organic HAP, including dioxins and furans, applicable to all EGUs. As noted in section V.D. above, the majority of emissions of these pollutants are below the detection levels of EPA test methods and, therefore, are impractical to measure. The work practice standard, described below, is a practical approach to ensuring that equipment is maintained and run so as to minimize emissions of dioxins and furans, and we expect it to be more effective than establishing a numeric standard that cannot reliably be measured or monitored. The work practice also applies to the limited-use liquid oil-fired subcategory included in the final rule.
The work practice involves maintaining and inspecting the burners and associated combustion controls (as applicable), tuning the specific burner type to optimize combustion, obtaining and recording CO and NO
Under the final rule, the tune-up must be conducted at each planned major outage and in no event less frequently than every 36 calendar months, with an exception that if the unit employs a neural-network system for combustion optimization during hours of normal unit operation, the required frequency is a minimum of once every 4 years (48 calendar months). Initial compliance with the work practice standard of maintaining burners must occur within 180 days of the compliance date of the rule. The initial compliance demonstration for the work practice standard of conducting a tune-up may occur prior to the compliance date of the rule, but must occur no later than 42 months (36 months plus 180 days) from the compliance date of the rule or, in the case of units employing neural network combustion controls, 54 months (48 months plus 180 days). If the tune-up occurs prior to the compliance date of the rule, you must maintain adequate records to show that the tune-up met the requirements of this standard.
We have made a number of specific changes to address what to do for repairs that may require longer term corrective actions, additional methods for evaluating combustion effectiveness, and clarification on procedures for recording CO and NO
We proposed numerical emission standards that would apply at all times, including during periods of startup, shutdown, and malfunction. Although at proposal we stated that we were not setting a different standard for startup and shutdown, we did propose different standards for startup and shutdown by our inclusion of the default values described below, which applied only during startup and shutdown. Specifically, we stated:
To appropriately determine emissions during startup and shutdown and account for those emissions in assessing compliance with the proposed emission standards, we propose use of a default diluent value of 10.0 percent O
We proposed application of the respective emission limits during periods of startup and shutdown and use of default values to calculate the emission limits. The standards that apply at all times other than startup and shutdown are production-based limits, which is why we proposed the default values. The default values were meant to account for the fact that during startup and shutdown events, production (in this case the generation of electricity) is by definition nonexistent. Thus, in effect, we proposed a separate standard to apply during startup and shutdown.
We received a variety of comments on the proposed standards that would apply during startup and shutdown. Many commenters pointed to the lack of data in the record concerning emissions that occur during periods of startup and shutdown. They further asserted that emissions during these periods can be highly variable in light of the sequence of events that occurs during the startup and shutdown of an EGU. Although a number of commenters supported the use of the diluent factor approach, including the default 5 percent of rated capacity, during startup/shutdown periods, other commenters questioned the feasibility of collecting additional data during such periods and had concerns regarding the reliability of measurements obtained from EGUs during such periods.
In response to the Agency's ICR to the utility industry, seven owners or operators indicated that they provided startup and shutdown data for their EGUs. These data were submitted in response to the requirement in the ICR to provide all available data from the 5 years prior to the date the ICR was issued. Of these data, there were almost no HAP data for startup and shutdown periods and almost all of the data failed to meet our data quality requirements.
Several commenters had an expansive view of what constitutes startup and shutdown. We disagree with these commenters that asserted that periods of “load swings” should be considered “startup” or “shutdown,” as they are generally routine, normal operations with production (
Commenters sought more clarity regarding the meaning of these terms as applied to EGUs, so we are revising the definitions in the final rule as set out in 40 CFR 63.10042.
These interpretations are tailored for EGUs and are consistent with the definitions of “startup” and “shutdown” contained in the 40 CFR part 63, subpart A General Provisions. We believe these revised definitions address the comments and are rational based on the fact that EGUs function to provide electricity primarily for sale to the grid but also at times for use on-site; therefore, EGUs should be considered to be operating normally at all times electricity is generated. We further believe these revised definitions address what some commenters describe as “warm” and “hot” startups as long as the EGU is shutdown (
As for the work practices, in this final rule, the EPA is requiring sources to operate using either natural gas or distillate oil for ignition during startup. The EPA also is requiring sources to vent emissions to the main stack(s) and operate all control devices necessary to meet the normal operating standards under this final rule (with the exception of dry scrubbers and SCRs) when coal, solid oil-derived fuel, or residual oil is fired in the boiler during startup or shutdown. It is the responsibility of the operators of EGUs to start their dry scrubber and SCR systems appropriately to comply with relevant standards applicable during normal operation.
The EPA carefully considered fuels and potential operational constraints of air pollution control devices (APCDs) when designing its work practices for periods of startup and shutdown. The EPA notes that there is no technical barrier to burning natural gas or distillate oil for longer portions of startup or shutdown periods, if needed, at a boiler, and the HAP emission reduction benefits warrant additional utilization of such fuels until the temperature and stack emissions pressure is sufficient to engage the APCDs. The EPA is aware that SCR systems with ammonia injection need to be operated within a prescribed and relatively narrow temperature window to provide NO
Some commenters have asserted that firing of fuel oil during periods of startup and shutdown constrains operation of PM controls (ESPs and baghouses) because under cooler conditions, acids and tars can condense on surfaces in these controls. The commenters assert that such condensation can cause detrimental impacts on hardware and operation of these controls, and could cause safety concerns. The EPA understands that concerns with acidic and tarry deposits are related to firing of heavy (residual) oil and not distillate oil. Accordingly, with residual fuel oil firing, site-specific flue gas temperature and oxygen (O
The EPA is not aware of any operational constraints applicable to operation of wet scrubbers during startup that could cause detrimental impacts on wet scrubber hardware and safety concerns and none of the commenters have commented on this aspect of wet scrubber operation.
Finally, the EPA notes that dry sorbent injection (DSI) can be applied across a very broad temperature range and will be engaged when residual oil or coal is fired in a boiler to comply with HCl requirements. Again, no comments have been received on this aspect of DSI operation.
This final rule requires work practice standards for emissions during startup and shutdown, and the rule requires sources to measure and report their emissions at all times, including periods of startup and shutdown, when continuous monitoring is used to demonstrate compliance. Data collected under this final rule will provide the EPA with information to more fully analyze this issue and address it during the 8-year review established under CAA section 112.
We now address malfunctions. In contrast to the exclusion of startup and shutdown period emissions from 30-boiler operating day rolling average emissions, the final rule requires inclusion of emissions during periods of source or APCD malfunction. We have concluded that when combined with the availability of an affirmative defense as described below, this is an appropriate and practical approach.
As mentioned earlier, periods of startup, normal operations, and shutdown are all predictable and routine aspects of a source's operations. However, by contrast, malfunction is defined as a “sudden, infrequent, and not reasonably preventable failure of air pollution control and monitoring equipment, process equipment or a process to operate in a normal or usual manner * * *” (40 CFR 63.2). The EPA has determined that CAA section 112 does not require that emissions that occur during periods of malfunction be factored into development of CAA section 112 standards. Under CAA section 112, emissions standards for new sources must be no less stringent than the level “achieved” by the best controlled similar source and for existing sources generally must be no less stringent than the average emission limitation “achieved” by the best performing 12 percent of sources in the category. There is nothing in CAA section 112 that directs the Agency to consider malfunctions in determining the level “achieved” by the best performing or best controlled sources when setting emission standards. Moreover, while the EPA accounts for variability in setting emissions standards consistent with the CAA section 112 case law, nothing in that case law requires the Agency to consider malfunctions as part of that analysis. Clean Air Act section 112 uses the concept of “best controlled” and “best performing” unit in defining the level of stringency that CAA section 112 performance standards must meet. Applying the concept of “best controlled” or “best performing” to a unit that is malfunctioning presents significant difficulties, as malfunctions are sudden and unexpected events.
Further, accounting for malfunctions would be difficult, if not impossible, given the myriad different types of malfunctions that can occur across all sources in the category and given the difficulties associated with predicting or accounting for the frequency, degree, and duration of various malfunctions that might occur. As such, the performance of units that are malfunctioning is not “reasonably” foreseeable.
In the event that a source fails to comply with the applicable CAA section 112(d) standards as a result of a malfunction event, the EPA would determine an appropriate response based on, among other things, the good faith efforts of the source to minimize emissions during malfunction periods, including preventative and corrective actions, as well as root cause analyses
Finally, the EPA recognizes that even equipment that is properly designed and maintained can sometimes fail and that such failure can sometimes cause an exceedance of the relevant emission standard. (
The EPA is including an affirmative defense in the final rule as we have in other recent MACT rules so as to balance the tension, inherent in many types of air regulation, to ensure adequate compliance while simultaneously recognizing that despite the most diligent of efforts, emission limits may be exceeded under circumstances beyond the control of the source. The EPA must establish emission standards that “limit the quantity, rate, or concentration of emissions of air pollutants on a continuous basis.” 42 U.S.C. 7602(k) (defining “emission limitation and emission standard”).
We have carefully evaluated the wide-ranging comments on testing, continuous monitoring, and other provisions regarding initial compliance demonstrations, and we have made adjustments intended to help streamline implementation while still ensuring adequate demonstration of compliance with the emission limits and other standards established under this final rule. The significant changes include:
Apart from an alternative that allows you to analyze fuel moisture for liquid oil-fired EGUs rather than measuring HCl and HF, the final rule does not include any of the fuel analysis requirements that were in the proposed rule, either as part of initial compliance demonstrations or ongoing compliance demonstrations. In reviewing the results of the fuel analyses and the expected range of results that would be received from laboratories conducting the proposed analyses, we determined that too many results would be returned as “below detection level” and, thus, provide little information to assist with rule implementation and compliance oversight. Given the costs and efforts involved, we determined that the proposed fuel analysis requirements would not be an effective compliance monitoring tool for this final rule.
We have clarified that where options for emission limits apply (such as filterable PM versus non-mercury HAP metals, or SO
We have significantly modified the proposed requirements to qualify as a LEE unit for a pollutant other than Hg based on an initial performance test. Under the proposed rule, the operating limit monitoring provided additional assurance of compliance for a source qualified for non-mercury LEE status based on an initial compliance demonstration. Under the final rule, to qualify for LEE status for pollutants other than Hg, a unit must meet the LEE criteria for a series of performance tests over a 3-year period to demonstrate that the unit continues to perform well below the standard for which the source has obtained LEE status.
The most significant changes to the testing and monitoring requirements involve the procedures for demonstrating continuous compliance. The proposed rule contained different options involving CEMS, periodic stack tests, fuel analysis, and various PM and control device operating limits. The final rule greatly simplifies the requirements and provides two basic approaches for most situations: use of continuous monitoring (either CEMS or PM continuous parametric monitoring system, CPMS) or periodic quarterly testing. The final rule does not contain the proposed fuel analysis requirements. For periodic testing, the proposed rule required testing every month or every 2 months. For those EGU owners or operators who choose to use emissions testing to demonstrate compliance, the final rule requires quarterly filterable PM or non-mercury metals HAP, whether individual or total metals, testing for coal- and liquid oil-fired units. The rule requires quarterly HCl testing for coal-fired units and quarterly HCl and HF testing, along with site-specific monitoring for liquid oil-fired units to ensure compliance with the HCl and HF standards. The final rule also has a separate compliance demonstration for those liquid oil-fired EGUs that have an annual capacity factor of less than 8 percent (emission limits do not apply, just the tune-up work practice standard). For those EGU owners or operators who choose to use emissions testing to demonstrate compliance, the final rule requires quarterly filterable PM or non-mercury metals HAP, whether individual or total metals, testing for coal- and liquid oil- fired units; quarterly HCl testing for coal-fired units and quarterly HCl and HF testing, along with site-specific parameter monitoring for liquid oil-fired units to ensure compliance with the HCl and HF standards.
The continuous monitoring options remain generally intact from the proposed rule, with relatively minor clarifications concerning calculation of 30-boiler operating day averages and QA requirements.
The final rule eliminates all operating limits for PM except for the use of a PM CPMS. For the PM CPMS, the final rule clarifies procedures for setting this operating limit and how it is distinct from the PM emission limit. The PM CPMS will not be correlated as a PM CEMS under PS 11 and will produce data in terms of a signal you define. That signal could be milliamps, stack concentration, or other output signal instead of PM emissions in units of the standard. The operating limit will be set using the highest hourly average obtained from the PM CPMS during the performance test. Compliance with the limit is based on a 30-boiler operating day rolling average basis. However, the final rule also does provide for the use of a PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use this approach. The EPA believes that some sources may be interested in adopting this direct approach, and so has included that option in the final rule. If this approach is selected, the PM CEMS is used as the direct method of compliance and no additional testing is required other than tests that are required as part of the QA requirements in PS 11 and Procedure 2. To use this option, the source must elect to meet the filterable PM standard, and not one of the HAP metals standards.
Apart from the operating limit for site-specific monitoring associated with liquid oil-fired EGUs, we removed the other operating limits for control devices based on a review of the comments, after considering other programs in place to ensure proper operations of controls at EGUs. Those other programs include compliance assurance monitoring under part 64, part 70, and New Source Review permit conditions, and other SIP and NSPS requirements for operating and maintaining equipment in accordance with good air pollution control practices. Those requirements, in combination with the CEMS, PM CPMS, and frequent periodic testing provisions under the final rule, will enhance the monitoring of continuous compliance with the requirements of this rule.
Because the EPA is concerned that there will be little or no monitoring in these underlying applicable requirements for acid gases at liquid oil-fired EGUs, the final rule requires a site-specific monitoring plan for those units in this subcategory that demonstrate compliance with the HCl and HF standards through quarterly performance tests. With the exception for limited-use liquid oil-fired EGUs and other monitoring options available (such as fuel moisture monitoring or HCl/HF CEMS), the EPA believes this provision will apply to few units. The owner or operator will submit the site-specific plan to identify appropriate parameters that ensure that the operations of the unit critical to meeting the HCl/HF emission limits remain consistent with conditions during performance testing. This will be approved similarly to an alternative monitoring request. The plan should include the parameters, monitoring approach, QA/QC elements, and data reduction (including averaging period) elements. Like the PM CPMS operating limit, the operating limit for acid gas control devices on liquid oil-fired EGUs will be set using the highest hourly average obtained during the HCl and HF performance tests. Compliance with the limit is based on a 30-boiler operating day rolling average basis.
Finally, we have changed the continuous compliance requirements for the performance tune-up work practice standard since the proposal. Our intent was that this work practice standard could be performed in conjunction with routine maintenance operations at a facility and be a logical extension of routine best practices for boiler inspection and optimization. Based on the comments received, we have reduced the required frequency for this inspection to every 3 years and provided incentives for neural network combustion management and optimization practices by providing a longer interval of 4 years between inspections when such systems are in use at a given EGU.
We are finalizing that owners and operators of existing affected sources may demonstrate compliance by emissions averaging for existing EGUs that are located at the same facility that are within a single subcategory and that rely on emissions testing as the compliance demonstration method. In response to our request for comments on the suitability of emissions averaging and need for a discount factor, we received a range of suggestions, including requests for clarification regarding eligibility, points for and against the need for a discount factor, and suggestions to ease implementation.
As we noted at proposal, part of the EPA's general policy of encouraging the use of flexible compliance approaches where they can be properly monitored and enforced is to include emissions averaging. Emissions averaging can provide sources the flexibility to comply in the least costly manner while still maintaining a regulation that is workable and enforceable. Emissions averaging would not be applicable to new affected sources and could only be used between EGUs in the same subcategory at a particular facility. Also, owners or operators of existing sources subject to the EGU NSPS (40 CFR part 60, subparts D and Da) would be required to continue to meet the PM emission standard of that NSPS regardless of whether or not they are using emissions averaging (
Emissions averaging allows owners and operators of a facility that includes existing EGUs within a subcategory to demonstrate that the source complies with the proposed emission limits by averaging the emissions from an individual affected EGU that is emitting above the proposed emission limits with other affected EGUs at the same facility that are emitting below the proposed emission limits and that are within the same subcategory. Although some commenters note that the MACT limits are low, based on the data available to the Agency, we believe that dozens of existing EGUs are achieving all of the limits and, thus, emissions averaging is a possible approach.
The final rule includes an emissions averaging compliance alternative because emissions averaging
In the final rule, the EPA is providing that sources may average emissions from existing EGUs at the same facility and within the same subcategory. Further, for Hg emissions only from existing EGUs within the same subcategory, such EGUs in an emissions averaging plan may use an alternate compliance approach consisting of a 90-boiler operating day rolling average emission limit of 1.0 lb/TBtu or 1.1E-2 lb/GWh.
In the memo entitled “The Impact of Emission Averaging Time on the Stringency of an Emission Standard” in the docket, we have illustrated why a longer-term average results in a lower limit. In essence, longer-term averages allow particularly high (or low) measurements to be averaged with many more measurements closer to the mean. This results in the highest averages from a longer-term averaging period (
We have illustrated this concept by taking Hg CEMS data and calculating rolling 30-day averages and rolling 90-day averages. The 30-day averages have greater variability and, thus, higher peaks and valleys. The 90-day average has less variability; therefore, the same unit is able to meet a tighter 90-day limit.
The EPA is providing this alternate 90-day rolling average compliance approach for Hg only. A 90-day rolling average is appropriate for Hg, and only for Hg, because the health and environmental impacts associated with Hg are related to environmental loading rather than shorter term inhalation or other acute exposure, as is the case with HCl and PM. We believe that this alternative compliance approach will provide at least the same level of environmental protection while allowing companies greater flexibility to use emissions averaging. For example, such an approach would allow for the averaging of an infrequently operated unit that is operating slightly above the standard with a more frequently operated unit that is operating below the standard in the instances when the more frequently operated unit is in a multi-day or multi-week maintenance outage.
The EPA has concluded that it is permissible to establish within a NESHAP a unified compliance regimen that permits averaging within the same facility across individual existing EGUs subject to the same standards under certain conditions. As mentioned earlier, individual EGUs within an emissions averaging group would be allowed to have emissions greater than, less than, or equivalent with the emissions limit for their subcategory, provided that the average emissions comprised from individual EGU emissions do not exceed the emissions limit for their subcategory. Averaging across affected units is permitted only if it can be demonstrated that the total quantity of any particular HAP that may be emitted by that portion of a contiguous major source that is subject to the same standards in the NESHAP will not be greater under the averaging mechanism than it could be if each individual affected EGU in the subcategory complied separately with the applicable standard. Under this test, the practical outcome of averaging is equivalent to compliance with the MACT floor limits by each discrete EGU, and the statutory requirement that the MACT standard reflect the maximum achievable emissions reductions is, therefore, fully effectuated.
As noted in the proposal preamble, in past rulemakings, the EPA has generally imposed certain limits on the scope and nature of emissions averaging programs. These limits include: (1) No averaging between different types of pollutants; (2) No averaging between sources that are not part of the same affected source; (3) No averaging between individual sources within a single major source if the individual sources are not subject to the same NESHAP; and (4) No averaging between existing sources and new sources.
The final rule fully satisfies each of these criteria. First, emissions averaging would only be permitted between individual existing sources at a single stationary source (
The final rule excludes new affected sources from the emissions averaging provision. The EPA does not believe the statute authorizes emissions averaging for new affected sources. One reason we allow emissions averaging is to give existing sources flexibility to achieve compliance at diverse points with varying degrees of add-on control already in place in the most cost-effective and technically reasonable fashion.
With the monitoring and compliance provisions that are being finalized, there is additional assurance that the environmental benefit will be realized. Further, the emissions averaging provision would not apply to individual EGUs if the EGU shares a common stack with units in other subcategories, because in that circumstance it is not possible to distinguish the emissions from each individual unit.
The rule allows EGUs that rely on CEMS for compliance demonstrations to be able to participate in emissions averaging and the emissions limits are not subject to a discount. The EPA believes that the data certainty provided by units that use CEMS would be ideal for emissions averaging and the flexibility and cost-effectiveness it offers. Given the homogeneity of fuels within the rules subcategories, along with other emissions averaging criteria, the Agency believes use of a discount factor to be unwarranted for this rule.
The emissions averaging provisions in this final rule are based in part on the emissions averaging provisions in the Hazardous Organic NESHAP (HON). The legal basis and rationale for the HON emissions averaging provisions were provided in the preamble to the final HON.
Compared to the proposed rule, the reduced continuous compliance requirements in the final rule—primarily reduced testing frequencies and removal of fuel analyses and control device or fuel operating parameter monitoring—considerably reduces the overall burden associated with recordkeeping and reporting. Based on evaluation of the comments received, we have established a provision in the final rule for submission of most CEMS data (including monitoring plan, emissions data, and QA data) through ECMPS, so that the affected industry uses a common reporting tool for submitting CEMS data.
For data other than most CEMS data, the final rule requires electronic reporting of certain data, including performance test reports, PM CPMS data, PM CEMS data, and, if approved as part of an alternative monitoring request, HAP metals CEMS data. Other reports, such as notifications, must be submitted in hard copy format or in accordance with the procedures established by state and local agencies that receive delegation for implementing this rule. In the proposed rule, we took comment on these approaches and stated our anticipation of adopting these approaches. In the final rule, we have extended the ECMPS reporting to most CEMS data to promote harmonization for CEMS data from the industry, while leaving reporting of non-CEMS data in a separate reporting system.
In this final action, we are making a number of technical corrections and clarifications to 40 CFR part 63, subpart UUUUU. These changes clarify procedures for implementing the emission limitations for affected sources. We are also clarifying several definitions to help affected sources determine applicability of this rule. We have modified some proposed regulatory language based on public comments. In addition, in response to comments received (including the May 2010 notice from the Utility Air Regulatory Group (UARG) of calculation errors in the proposed Hg MACT floor limits), we have checked all calculations and made corrections where necessary.
In several places throughout the subpart, including the associated tables, we have corrected the cross-references to other sections and paragraphs of the subpart.
Clean Air Act section 112(d)(3) is not explicit as to whether the MACT floor is to be based on the performance of an entire source or on the performance achieved in controlling particular HAP. Congress specified in CAA section 112(d)(3) the minimum level of emission reduction that could satisfy the requirement to adopt MACT. For new sources, this floor level is to be “the emission control that is achieved in practice by the best controlled similar source.” For existing sources, the floor level is to be “the average emission limitation achieved by the best performing 12 percent of the existing sources” for categories and subcategories with 30 or more sources, or “the average emission limitation achieved by the best performing 5 sources” for categories and subcategories with fewer than 30 sources. Commenters point to the statute's reference to the best performing “sources,” and claim that Congress would have specifically referred to the best performing sources “for each pollutant” if it intended for the EPA to establish MACT floors separately for each HAP.
The EPA disagrees. The language of the Act does not address whether floor levels can be established HAP-by-HAP or by any other means. The reference to “sources” does not lead to the assumption the commenters make that the best performing sources can only be the best-performing sources for the entire suite of regulated HAP. Instead, the language can be reasonably interpreted as referring to the source as a whole or to performance as to a particular HAP. Similarly, the reference in the new source MACT floor provision to “emission control achieved by the best controlled similar source” can mean emission control as to a particular HAP or emission control achieved by a source as a whole.
Commenters also stressed that CAA section 112(d) requires that floors be based on actual performance from real facilities. The EPA agrees that this language refers to sources' actual operation, but again the language says nothing about whether it is referring to performance as to individual HAP or to single facility's performance for all HAP. Industry commenters also said that Congress could have mandated a HAP-by-HAP result by using the phrase “for each HAP” at appropriate points in CAA section 112(d). The fact that Congress did not do so does not compel any inference that Congress was
Commenters also point to the EPA's subcategorization authority, and claim that because Congress authorized the EPA to distinguish among classes, types, and sizes of units, the EPA cannot distinguish units by individual pollutant, as they allege the EPA did in the proposed rule. However, that statutory language addresses the EPA's authority to subcategorize sources within a source category prior to setting standards, which the EPA has done for certain EGUs. The EPA is not distinguishing within each subcategory based on HAP emitted. Rather, it is establishing emissions standards based on the emissions limits achieved by units in each subcategory. Therefore, the EPA's subcategorization authority is irrelevant to the question of how the EPA establishes MACT floor standards once it has made the decision to distinguish among sources and create subcategories.
The EPA's long-standing interpretation of the Act is that the existing and new source MACT floors are to be established on a HAP-by-HAP basis. One reason for this interpretation is that a whole plant approach could yield least common denominator floors—that is, floors reflecting limited or no control, rather than performance which is the average of what best performers have achieved.
For example, if the best performing 12 percent of facilities for HAP metals were also the worst performing units for acid gas HAP and the best performers for acid gas HAP were the worst performers for HAP metals, the floor for acid gases or metals would end up not reflecting best performance. In such a situation, the EPA would have to make a value judgment as to which pollutant reductions were most critical to decide which sources are best controlled.
Commenters suggested that a multi-pollutant approach could be implemented by weighting pollutants according to relative toxicity and calculating weighted emissions totals to use as a basis for identifying and ranking best performers. This suggested approach would require the EPA to essentially prioritize the regulated HAP based on relative risk to human health of each pollutant, where risk is a criterion that has no place in the establishment of MACT floors, which are required by statute to be based on technology.
The central purpose of the amended air toxics provisions was to apply strict technology-based emission controls on HAP.
The EPA notes, however, that if optimized performance for different HAP is not technologically possible due to mutually inconsistent control technologies (for example, if metals performance decreased as organics reduction is optimized), then this would have to be taken into account by the EPA in establishing a floor (or floors). The Senate Report indicates that if certain types of otherwise needed controls are mutually exclusive, the EPA is to optimize the part of the standard providing the most environmental protection. S. Rep. No. 228, 101st Cong. 1st sess. 168 (although, as noted, the bill accompanying this Report contained no floor provisions). It should be emphasized, however, that the D.C. Circuit has stated that “the fact that no plant has been shown to be able to meet all of the limitations does not demonstrate that all the limitations are not achievable.”
All available data for EGUs indicate that there is no technical problem achieving the floor levels contained in this final rule for each HAP simultaneously, using the MACT floor technology. Data demonstrating a technical conflict in meeting all of the limits have not been provided, and, as stated above, based on the available data, there are approximately 64 EGUs that meet all of the final existing source emission limits and at least one EGU that meets all of the final new source emission limits.
Some commenters stated it is necessary to keep the data as reported because changing values would lead to an upward bias. Additional commenters agreed with this basic premise, but suggested that replacing non-detect data with a value of half the MDL is appropriate while still minimizing the bias. They noted that treating measurements below the MDL as occurring at the MDL is statistically incorrect and violates the statute's “shall not be less stringent than” requirement for MACT floors. One commenter also provided a reference for a statistical method based on a log-normal distribution of the data which estimated the “maximum likelihood” of data values; this result is slightly higher than half the MDL.
Some commenters stated that it is necessary to substitute the MDL value when performing the MACT floor calculations. With MDL defined as the lowest concentration that can be distinguished from the blank at a defined level of statistical significance, this is an appropriate value. If MDL values are not reported, one commenter suggested an approach for estimating an MDL equivalent value, but recognized that the background laboratory and test report files may not be available to the EPA in order to derive these estimates.
Most commenters representing industry and industry trade groups argued that either LOQ or PQL values should replace non-detects. The LOQ is defined as the smallest concentration of the analyte which can be measured. These commenters contended that the LOQ leads to a quantifiable amount of the substance with an acceptable level of uncertainty. A few commenters provided calculations showing some of the proposed MACT floors were below the LOQ. Additionally, some of these commenters stated that using LOQ or PQL values also incorporates additional sources of random and inherent sampling error throughout the testing process, which is necessary. These errors occur during sample collection, sample recovery, and sample analysis;
Commenters stated that where the proposed MACT floor is below the LOQ or PQL then that source category has a technological measurement limitation. A few commenters suggested RL values should be used when developing the floor limits. They stated that the RL is the lowest level at which the entire analytical system gives reliable signals and includes an acceptable calibration point. They added that use of an acceptable calibration point is critical in showing that numbers are real versus multiplying the MDL by various factors.
Several commenters stated that all non-detect values should be excluded from MACT floor calculations. They believed that excluding all non-detect values would eliminate any potential errors or accuracy issues related to testing for compliance. Due to inconsistencies of the MDL value reported for non-detect data, one commenter suggested treating all such values as zero. This would provide a consistent approach for setting the floor as well as determining compliance.
Several commenters provided input on the EPA's proposed method of three times the MDL as an option for setting limits. A few commenters in support noted that this approach provided a reasonable method to account for data variability as it took into account more than just analytical instrument precision. Many other commenters argued that this method results in limits which are too low, namely that it is still lower than the LOQ value which they are in favor of as a substitute for any reported non-detect data. Other commenters disagreed with this method and claimed that it would lead to results which introduce a high bias in the floor setting process. A few contended that multiplying by 3 would introduce a 300 percent error into the floor, resulting in a floor that is less stringent than required by the Act. Others suggested that the MDL values are antiquated and already too high and thus it is not appropriate to multiply them by three. Also, a few commenters suggested multiplying the MDL by three would not reflect the actual lower emissions achieved by any source and as such is unlawful under CAA section 112(d).
The EPA's guidance to respondents for reporting pollutant emissions used to support the data collection specified the criteria for determining test-specific method detection levels. Those criteria ensure that there is only about a 1 percent probability of an error in deciding that the pollutant measured at the method detection level is present when in fact it was absent. (Reference: ReMAP: PHASE 1, Precision of Manual Stack Emission Measurements; American Society of Mechanical Engineers, Research Committee on Industrial and Municipal Waste, February 2001.) Such a probability is also called a false positive or the alpha, Type I, error. This means specifically that for a normally distributed set of measurement data, 99 out of 100 single measurements will fall within ±2.54 × standard deviation of the true concentration. The anticipated range for the average of repeated measurements comes progressively closer to the true concentration. More precisely, the anticipated range varies inversely with the square root of the number of measurements. Thus, for a known standard deviation (SD) of anticipated single measurements, the anticipated range for 99 out of 100 future triplicate measurements will fall within ±2.54 SD/√3 of the true concentration. This relationship translates to an expected measurement imprecision for an emissions value occurring at or near the method detection level of about 40 to 50 percent.
By assuming a similar distribution of measurements across a range of values and increasing the mean value to a representative higher value (
Analytical laboratories often report a value above the method detection limit that represents the laboratory's perceived confidence in the quality of the value. This independently adjusted value is expressed differently by various laboratories and is called LOQ, PQL, or RL. In many cases, the LOQ, PQL, or RL is simply a multiplication of the method detection limit. Commonly used multipliers range from 3 to 10. Because these values reflect individual laboratories' perceived confidence, and, therefore, could be viewed as arbitrary, we decline to adopt the LOQ, PQL, or RL because such approaches in our view would inappropriately inflate the MACT floor standards. Our alternative to those inconsistent approaches is discussed below.
Consistent with findings expressed in reports of emissions measurement imprecision and the practices of analytical laboratories, we believe that using a measurement value of 3 times a representative method detection limit established in a manner that assures 99 percent confidence of a measurement above zero will produce a representative method reporting limit suitable for establishing regulatory floor values.
On the other hand, we also agree with commenters that an emissions limit set from a small subset of data or data from a single source may be significantly different than the actual method detection levels achieved by the best performing units in practice. This fact, combined with the low levels of emissions measured from many of the best performing units, led the EPA since proposal to review and revise the procedure intended to account for the contribution of measurement imprecision to data variability in establishing effective emissions limits. In response to the comments about the
The revised procedure for determining an RDL starts with identifying all of the available reported pollutant-specific method detection levels for the best performing units regardless of any subcategory (
The second step in the process is to calculate 3xRDL to compare with the calculated floor or emissions limit. This step is similar to what we have used for other NESHAP including the Portland Cement rule. As outlined above, we use the multiplication factor of 3 to reduce the imprecision of the analytical method until the imprecision in the field sampling reflects the relative method precision as estimated by the ASME ReMAP study. That study indicates that such relative imprecision remains a constant 10 to 20 percent over the range of the method. For assessing the calculated floor results relative to measurement method capabilities, if 3xRDL were less than the calculated floor or emissions limit (
We determined the RDL for each pollutant using data from tests of all the best performers for all of the final regulatory subcategories (
Commenters also stated that the EPA failed to address cumulative effects of using multiple pollution control devices in determining MACT levels applicable to PM levels. In proposing total PM as a surrogate, commenters believe that the EPA failed to consider or address the antagonistic effects that adding multiple pollution control devices can have on an EGU's HAP emissions. Commenters indicated that EGUs would not be able to comply with the proposed new source HCl limit without adding a scrubber or some type of sorbent injection to control HCl emissions. Adding these HCl control technologies will increase the total PM emissions of these units. According to commenters, because a fabric filter-alone configuration (the basis for the new source PM limit) would not meet all MACT limits, these units may not be the best-performing units.
The EPA also believes that the EGUs serving as the basis for the new source Hg and HCl limits in the final rule are representative of what a new coal-fired EGU would look like to meet all of the requisite regulations applicable to EGUs (
Some commenters add that the proposed new source MACT standards do not represent rates that have been achieved in practice and are orders of magnitude lower than any of the CAA section 112(g) case-by-case MACT limits established for the most advanced units in the U.S. coal fleet by multiple state agencies.
Other commenters stated that the synergistic impact of multiple controls has not been taken into account in the proposed rules. Commenters argue that circumstances exist with respect to the control of acid gases, which will require scrubbers or other SO
The commenters state that, for existing sources as with the new source standard-setting approach, a pollutant-by-pollutant approach does not consider what the top performing 12 percent achieve in practice for all pollutants and does not consider the antagonistic effects of the concurrent use of various control technologies. For example, one commenter states that 47 of the 131 sources used to calculate the existing source total PM limit only had PM control but no acid gas or Hg controls that could emit additional PM. According to the commenter, the CAA is clear that standards must be based on actual sources and not the product of a pollutant-by-pollutant determination resulting in a set of composite standards that do not necessarily reflect the overall performance of any actual source. To address these issues, the commenter recommends that the EPA use an approach that more accurately reflects what actual best performing sources achieve.
We disagree with commenters that suggest the proposed new source standards are invalid because they are more stringent than CAA section 112(g) case-by-case MACT limits established by state agencies. As commenters note, states, not the EPA, established the CAA section 112(g) standards, and they did so based on the information available to them. The EPA likewise must establish CAA section 112(d) standards based on the available data. We have considered the available data and information, including the 2010 ICR data, and complied with the requirements of CAA section 112(d) in establishing the standards in this final rule. That the final standards are more stringent than CAA section 112(g) standards issued by certain state agencies has no bearing on the legitimacy of the standards at issue here.
The EPA agrees with commenters that the SO
The final standard is not based on the source used to establish the proposed limit. As stated above, industry commenters provided data corrections and new data and the EPA considered that new and revised data in establishing the final standards. We re-ranked all the coal-fired EGUs based on the new data. The new ranking of coal-fired EGUs resulted in a change of the source we used to establish the new source PM surrogate standard for non-mercury metal HAP. The basis for the new source limit in the final rule is a unit that has a full suite of controls similar to what would be required for any new coal-fired EGUs (
The EPA also disagrees that the final new source standards are so stringent that there are not adequate test methods available to determine compliance with the standards. The EPA has taken into account the ability of the various test methods to accurately measure emissions at the levels being demonstrated by the best performing EGUs in establishing the final limits. This has been done through use of the 3XRDL (discussed elsewhere in this preamble and the Response to Comments document) and through adjustments to the sampling time requirements for certain of the HAP.
According to commenters, the EPA cannot determine what amount of the overall performance of a combined stack data point is the specific result of the combination. Commenters assert that the EPA also argues that applying the emissions equally to multiple units exhausting through a single stack “accurately represents the emissions of those units on average.” Commenters believe that is simply not correct and there is no plausible factual basis for that statement, believing that there is no unit that “achieved” those emissions. Rather, the data represent the combined weighted average of two units, without knowing how either unit actually performed. One commenter also stated that in several instances when a facility operated tandem or multiple EGUs but only submitted a single stack measurement, the EPA used the single stack measurement to represent Hg emissions from the facility's other stacks.
The EPA has reviewed the data based on comments received and does not believe that there are any inconsistencies in the data set used for the final rule. In the MACT floor analysis, the EPA only used data from stacks that were tested or for which test data were provided. These stack measurements were not used to represent emissions from other, non-tested, stacks in the MACT analysis.
Comments were also received that some state programs contain Hg emission limits that are more stringent than the EPA's proposed emission limits. The programs of Connecticut, Massachusetts, New Hampshire, New Jersey, and New York were noted. Commenters provided information on these states' Hg emission limits, which often are in the form of either a lb/TBtu format or a percent reduction. Commenters noted that EGUs in these states were in compliance with the state regulations and, therefore, the EPA's emission limits should be more stringent.
The EPA believes that an emission rate format allows for, and promotes, the use of pre-combustion HAP removal processes because such practices will
The 2010 ICR data confirm that plant inputs likely play a role in emissions to the atmosphere. These data indicate that some EGUs are achieving lower Hg emissions to the atmosphere at a lower Hg percent reduction (
With regard to the comments relating to some state programs being more stringent than the EPA's proposed limits, the EPA would note that many of the programs identified by one commenter have an “either/or” format for their Hg standards. That is, an EGU can either meet an emission limit (
The EPA believes that its beyond-the-floor analysis is appropriate, including the costs analyzed. The EPA's cost analysis is meant to serve as an average for all sources in the subcategory recognizing that some EGU's costs will be more and some less; EGUs whose costs are higher are not exempted from the regulation. Further, five EGUs in the subcategory are meeting the final beyond-the-floor limit based on available data (
Two commenters provided permit information, based on IGCC units currently under construction, for PM and Hg emissions. One commenter requested that the proposed new MACT floor limit for PM be modified to address the two scenarios for duct burners at IGCC plants, syngas-fired and natural-gas-fired. The commenter requested the 0.050 lb/MWh limit be increased to at least 0.068 lb/MWh
The commenter also noted that there is not sufficient test data to precisely predict the Hg emissions performance of even the best-controlled IGCC units, other than that IGCC Hg emissions are expected to be much less than those for EGUs that directly burn coal. In its permit application, the commenter proposed to establish a new standard for Hg removal in IGCC units by treating the syngas in catalytic reactors. The catalytic reactor system is expected to achieve greater than 95 percent Hg removal using either sulfur-impregnated activated carbon or alumina catalyst. In the absence of actual stack test data, the commenter has had to estimate expected emissions based on engineering estimates of how much Hg may arrive in the syngas routed to the catalytic reactors. Based on these engineering estimates and 95 percent Hg removal in the catalytic reactors, the commenter believes that the resulting Hg emission limit for a state-or-the-art IGCC unit would be 0.003 lb/GWh, which is much less than the Hg emissions for EGUs that directly burn coal.
The commenter notes that IGCC units are still in their infancy. Funding for them will be very difficult or unavailable if there is a regulatory limit below the level that can be supported by vendor guarantees. Given the important role that IGCC units may have in meeting global energy and climate stability goals, the commenter believes it would be a mistake to erect barriers to the implementation of this technology. The commenter stated that the EPA can reevaluate the appropriate levels for future IGCC units after demonstration units which incorporate effective controls have been built and tested.
Many commenters stated that the EPA should have proposed more subcategories, while others believed that too many subcategories were proposed. Many different issues were raised by commenters, and some of the key issues that were considered in the final rule (some of which led to changes in the final rule) include: the technical deficiencies in the definition for the low-Btu coal subcategory; additional subcategorization of the coal-fired EGU population; the need for subcategorization of distillate vs. residual oil-fired EGUS; the need for a limited-use subcategory for EGUs that operate for only a small percentage of hours during a year; and the need for a non-continental liquid oil subcategory for island units that have limited fuel options and other unique circumstances. The comments and the EPA responses are provided below.
In general, the EPA has reviewed the data provided and continues to believe that the coal-fired EGU subcategories proposed are the only ones supported by the data, though we have revised the basis for EGUs designed to burn low rank virgin coal as discussed above. The EPA may not subcategorize by air pollution control technology type as requested by a few commenters. Further, the EPA has reviewed the other suggested coal-fired subcategories and finds no basis for further subcategorization (
Commenters also stated that without further subcategorization the economic impacts on individual Midwestern states will be particularly acute as huge segments of the U.S. coal reserve will be disenfranchised by this rule. According to the commenters, the EPA did not even attempt to legitimately analyze this issue and, thus, in their opinion the Agency's proffered rationale for
Other commenters are opposed to any further subcategorization based on coal rank. Because many sources blend several ranks of coal on a regular basis, commenters believe that establishing coal rank subcategories would create numerous opportunities for sources to game the regulations and substantially increase emissions. Commenters stated that there is no need for such an approach since modern pollution controls can accommodate a wide range of coals. These commenters believe that EGUs firing different ranks of coal are not fundamentally different in size, class, or type in a way that impacts emissions or that limits the availability of controls. The commenters believe that emissions of fuel-dependent HAP can be controlled by either changing the fuel prior to combustion or by removing the HAP from the flue gas after combustion. Commenters state that ACI systems, DSI controls, and PM controls are available for installation at units firing sub-bituminous coal and are equally available for units firing bituminous, anthracite, or lignite coal. These commenters also believe that as long as a control option is commercially available, the cost for a particular EGU is irrelevant to the EPA's development of emission standards based on MACT. Commenters stated that subcategories based on coal rank would make a meaningful consideration of fuel switching impossible, contrary to the judicial mandate to consider substitution of materials in setting the floor and the statutory mandate to consider substitution of materials in the beyond-the-floor analysis.
One commenter stated that although they previously supported the subcategorization of coal-fired units on the basis of coal rank, they no longer object to grouping units that burn bituminous and subbituminous coals in a single category because the prior basis for subcategorization no longer exists. The commenter indicated that at the time of CAMR, it was widely recognized that although coal-fired units combusting bituminous coal, with its higher concentration of chlorine and, therefore, ionic Hg, could effectively limit Hg emissions by utilizing existing control technologies such as scrubbers, units burning subbituminous coal could not do so with the same controls because of the coal's higher levels of elemental Hg. The commenter stated that activated carbon was only a fledgling and unproven technology at the time; today, however, activated carbon has been proven, and units burning bituminous and subbituminous coal can achieve the same levels of emissions for Hg and other HAP. Consequently, the commenter believes the prior basis for subcategorization no longer exists and the commenter, therefore, agrees that coal-fired EGUs burning bituminous and subbituminous coals ought to be grouped in a single category.
When all of the factors noted by commenters have been reviewed, with the exception of Hg for certain units, as discussed above, the EPA does not believe that the HAP emissions to the atmosphere are sufficiently different from coal-fired EGUs to warrant further subcategorization. There are EGUs firing bituminous, subbituminous, and coal refuse among the top performing units for Hg and EGUs firing bituminous, subbituminous, lignite, and coal refuse are all among the top performers for the acid gas HAP and non-mercury metallic HAP indicating that the MACT floor limits established based on these units are achievable by units burning all ranks of coal.
As noted by commenters, ACI, not fully developed in 2004, is now able to effect Hg control levels on subbituminous coals such that similar emissions to the atmosphere may be achieved as those achieved by higher-chlorine bituminous coals when FGD systems are used or by coal refuse EGU with less controls. Thus, in looking at the total system, similar emissions to the atmosphere are achieved by all of these coal ranks. The EPA has addressed elsewhere in this document its rationale for not subcategorizing by coal chlorine content. The EPA does not believe that any fundamental discrimination between coal ranks will occur as a result of the final rule, though clearly some sources will be required to install greater controls to comply with the final standard. We maintain that such result is consistent with the intent of CAA section 112 standards, which are not intended to have an outcome whereby all sources can comply with final standards without any action.
The EPA agrees, in theory, that EGUs are designed around a basic set of coal characteristics. However, the 1999 ICR demonstrated that numerous EGUs have conducted trial burns and gained sufficient experience such that co-firing blends of various coal ranks is now common practice. In fact, the EPA believes that such blends may be modified daily, depending on the characteristics of the coal being burned and on the level of generation needed. The extent of blending, and the ability to switch the blends on short notice, does not lend itself (or, in fact, argue for) additional subcategorization.
The EPA disagrees with any assertion that the EPA ignored possible subcategorization approaches or that it has insufficient data upon which to base or evaluate various subcategories. The EPA fully examined the record, which demonstrates that coal-fired EGUs, with the exception of certain units for Hg, have similar HAP emissions profiles and that similar control approaches are available to such EGUs. Although commenters suggested additional subcategories were warranted, they failed to provide sufficient data to support their proposed alternative subcategories. As noted elsewhere, the EPA does not disagree with commenters that there are some differences in EGUs. However, the EPA does disagree with commenters that those differences result in differences in emissions to the atmosphere such that additional subcategorization is justified.
Failing to demonstrate that coal-fired EGUs are different based on emissions, the commenters turn to economic arguments, asserting that failing to subcategorize will impose an economic hardship on certain sources. Congress precluded consideration of costs in setting MACT floors, and it is not appropriate to premise subcategorization on costs either. See S. Rep No. 101-228 at 166-67 (5 Legislative History at 8506-07) (rejecting the implication that separate categories could be based on “assertions of extraordinary economic effects”);
The final limits are based on EGUs currently operating with available controls. As noted above, the record shows that the various types of EGUs are represented in the floors, with the exception of certain units for Hg, which
In addition, the EPA believes it has fulfilled the CAA section 112(c)(l) directive that “[t]o the extent practicable, the categories and subcategories listed under this subsection shall be consistent * * *” with those of CAA section 111, notwithstanding commenters assertion to the contrary. The decision on whether to directly align CAA sections 112 and 111 subcategories is discretionary and EPA has reasonably exercised its discretion in declining to create additional subcategories for coal-fired EGUs based on the record, with the exception of certain sources for Hg.
Finally, the EPA disagrees with the commenters that suggest that EPA lacks the legal authority to consider material inputs when considering subcategories. We agree, however, that material inputs must be considered when establishing MACT standards for the subcategories that are established. We also believe a meaningful consideration of fuel switching can occur even if sources are subcategorized based on fuel inputs because EPA considers fuels switching in evaluating potential beyond-the-floor alternatives.
In addition, as noted above, the SO
The commenters noted that an examination of the 40 “best performing” units for Hg emissions in the proposed MACT floor spreadsheet showed that 14 of those units are FBC units. The commenters maintained that had FBC units performed as well as conventional PC boilers, 2 units would have been expected to be in the top 40. The commenters allege that the far higher percentage of FBCs in the top 40 leads to the conclusion that these units are different from conventional PCs with regard to Hg emissions and, as a result, should have been placed in their own subcategory. Further, commenters noted that the largest FBC has a nameplate capacity of about 300 MW while the largest conventional boilers have nameplate capacities of around 1,300 MW.
The commenters stated that FBCs combust relatively large coal particles in a bed of sorbent or inert material at a lower degree of combustion efficiency.
One commenter stated that the EPA properly declined to subcategorize units based on design type where there is no indication that any physical distinctions among unit designs have a meaningful and substantial impact on HAP emissions. The commenter indicated that it would be inappropriate to subcategorize FBCs because there is no evidence to support a determination that FBC design is responsible for a unit falling in or out of the top 12 percent for a particular HAP.
Commenters assert that FBC units are disproportionately represented among the best performers, with the inference being that they were selected to test in the 2010 ICR because of their boiler design. However, FBC EGUs were not specifically selected as best performers for Hg, as EPA did not select any EGUs based on a determination that they were best performers for Hg (as noted elsewhere, we had no basis for selecting EGUs as being best performers for Hg), and to the extent CFB units were selected in the 2010 ICR, they were selected because we determined they were best performers for non-mercury metallic HAP, acid gas HAP, or organic HAP or because they were randomly selected among the non-best performers for those three HAP groupings. Thus, the CFBs were selected for testing under the 2010 ICR based not on their boiler design but, rather, based on the age and on their PM and FGD control systems (as noted in the Supporting Statement for the 2010 ICR). As many FBC EGUs, including CFB EGUs, are relatively new, they were included in the non-mercury metallic HAP group selected for testing (because their PM controls were among the 175 newest), the acid gas HAP group selected for testing (because FBC was considered to be an FGD system and the units were among the 175 newest), and organic HAP testing (because they were among the newest and, thus, determined to be among the most efficient).
The effect on Hg emissions is not what commenters suggest because, although, as noted by commenters, FBC units may be found among the better performers (among the top 10 EGUs) on the Hg MACT floor spreadsheet, they are also found in the range of 221 to 226 EGUs (of 393 data points). The fact that FBC units have “vastly dissimilar ash properties” that may contain higher levels of lime or unburned carbon in the fly ash than conventional PC EGUs does not indicate that the overall system behaves any differently with regard to emissions to the atmosphere (the key metric) than a conventional PC EGU with add-on controls. The asserted higher levels of unburned carbon result in a range of effectiveness of Hg control that is similar to that of ACI found on PC EGUs; such ACI control may be found on EGUs that are among the better performers as well as on EGUs as low as 369 on the list of data points. Thus, the EPA disagrees that FBC units are disproportionately represented in the Hg floor and that their inclusion is somehow inappropriate or leads to skewing of the analysis.
All types of coal-fired EGUs other than those we subcategorized are represented in the MACT floors for Hg and all types of EGUs are represented in the floors for the non-mercury HAP. Fluidized bed combustion EGUs are not an exception and such EGUs are found across the range of top performing EGUs for all of the HAP categories: Acid gas, non-mercury metallic, and Hg. In addition, any assertion that non-FBC EGUs are unable to meet the final standards because FBC EGUs are included in the same subcategory (or vice versa) is plainly refuted by the fact that EGUs of all types are currently meeting one or more of the final standards. Thus, the EPA finds no basis for subcategorizing FBC EGUs.
Further, as noted below, the EPA does not believe there is a basis for subcategorizing small EGUs, either FBC or PC. In addition, the data have been re-evaluated based on comments received and an FBC unit is not the basis for the new source Hg MACT floor.
One commenter stated that in general, the nature of many public power facilities differs from the general population of coal-fired power plants. Public power units tend to be smaller in size, and are often space-constrained by growth in the community surrounding the generating unit since its initial construction. These limitations restrict the ability of these EGUs to achieve the same performance levels of larger,
One commenter stated that the EPA properly recognized that subcategories based on unit size would be inappropriate because the proposed emission limits are in terms of lb/MMBtu or lb/TBtu and noting that an EGU's total nameplate capacity is wholly unrelated to its ability to achieve the proposed limits. Another commenter opposed any proposal to subcategorize units below 100 MW. The proposed rule does not apply to units less than or equal to 25 MW, and this commenter believed that this is a sufficient threshold for applicability.
One commenter stated that the EPA could establish subcategories for the purpose of temporarily exempting, for example, a subcategory of utilities that meet the definition of small entity for purposes of the proposed rule. The temporary exemption would sunset on a date certain (e.g., 3 years from the effective date of the rule) at which point the sources in the subcategory would become subject to the rule, and a compliance timetable would start to run. The commenter believed that this time-staged promulgation and compliance proposal would greatly increase the chance that the control measures could be added in an orderly and efficient manner with minimal disruption to power markets and grid reliability.
The EPA examined the effect if EGUs less than 125 MW were subcategorized for Hg. The resultant MACT floor for these EGUs would be 1.0 lb/TBtu on a 30-boiler operating day rolling average, a level more stringent than that developed for the >8,300 Btu subcategory as a whole. We do not believe that this is what commenters envisioned when suggesting such a subcategory but we believe it confirms our analysis of the data that indicates, as noted, these units are controlled in the same manner as other, larger EGUs, such that additional subcategorization is not necessary or reasonable. Further, based on the number of EGUs less than 125 MW in the HCl and PM MACT floor pools, we believe that a similar analysis for HCl and PM would lead to similar or more stringent standards than without the additional subcategory. Thus, units of all sizes are capable of achieving the proposed limits and the EPA is not finalizing a subcategory based on unit size in the final rule.
The CAA authorizes EPA to subcategorize based on “classes, types, and sizes of sources.” The EPA does not believe that this provision permits subcategorizing sources based solely on their status as small entities for several reasons. As a threshold matter, commenters provided no information to suggest that EGUs at small entities are different from EGUs owned by other entities. Instead, the commenters' justification for such a subcategory was that the costs to comply with the standards make it more difficult for small entities; thus, the basis is essentially a cost basis and we do not think that is consistent with the statute. Moreover, the legislative history of CAA section 112(d) supports EPA's interpretation that subcategories cannot be based on the cost of compliance.
In addition, the EGUs owned by small entities use the same type of fuel as other units, have the same type of combustor designs, and can use the same types of controls, and so there is no difference in the HAP emissions from such units. So, even if we believed a subcategory based on small entities was consistent with the statute, we would decline to include such a subcategory.
Therefore, given the language of CAA section 112(d), the legislative history, and the available information, EPA is not creating a separate subcategory for EGUs owned by small entities.
In addition, the D.C. Circuit has clearly stated that the EPA does not have the statutory authority under CAA section 112 to extend compliance dates past the 3-year maximum compliance time authorized in CAA section 112(i)(3)(A) except consistent with CAA sections 112(i)(3)(B) and 112(i)(4).
The EPA is constrained by the definition of “new source” such that any source that “commenced” construction after the May 3, 2011, proposal date is considered a new source under the statute and the source must comply with the new source standards even if the source received a final and legally effective CAA section 112(g) permit before proposal. It is unclear from the comments whether the sources identified in the comments have commenced construction as defined in the regulations; however, the identified sources are existing sources, not new sources, under the final rule if construction was commenced prior to the proposal date.
Under the final rule, new sources must comply with the standards on the date of promulgation or at startup, whichever is earlier, and existing sources have 3 years to come into compliance with the final standards. Pursuant to the EPA's regulations at 40 CFR 63.44(b)(1), however, we may provide in a final CAA section 112(d) standard a specific compliance date for those sources that obtained a final and legally effective CAA section 112(g) case-by-case MACT standard and submitted the information required by 40 CFR 63.43 to the Agency before the close of the comment period. The EPA does not believe it has received such information during the comment period and we are not establishing a separate specific compliance period for sources that obtained final and legally effective CAA section 112(g) standards prior to promulgation of the final rule. In the absence of EPA action on this issue, state Title V permitting authorities are required to “establish a compliance date in the [title V] permit that assures that the owner or operator shall comply with the promulgated standard [ ] as expeditiously as practicable, but not longer than 8 years after such standard is promulgated * * *” 40 CFR 63.44(b)(2). Sources with final and legally effective section 112(g) standards should work with their permitting authorities to determine the appropriate compliance date consistent with the EPA regulations.
However, the EPA is sensitive to the commenters' concerns and particularly recognizes the significance of Navajo Generating Station to the Central Arizona Project and the water delivery to tribes. As a result, EPA has been consulting with affected Indian tribes and working closely with other federal agencies, including the Department of the Interior, on these issues and intends to work with tribal and other authorities to ensure a smooth transition and address specific issues as they arise.
Some commenters alleged that by combining distillate and residual oil into a single MACT category, the resultant MACT standards cannot be satisfied by a boiler firing residual oil without substantial add-on controls. The commenters asserted that creation of separate subcategories for liquid oil-fired units that distinguish between residual and distilled oil would render the standards more achievable for distinct subcategories of EGUs and reduce the number of potential plant closures while still advancing the goal of reducing overall emissions. These commenters contend that MACT floors should not be used to eliminate whole classes of existing EGUs through mathematical floor calculations based on data from uncontrolled units and combining boiler subcategories that are not capable of accommodating a different fuel.
One commenter stated that the EPA should not subcategorize liquid oil-fired EGUs based upon different grades of liquid oil. Although different grades of liquid oil may vary in their heat contents or viscosities, the commenter maintained that there is no indication in the rulemaking record that any physical
In addition, the EPA does not agree that distillate oil-fired EGUs were not listed in the 2000 Finding. We believe it is inappropriate to exclude distillate oil-fired EGUs from regulation under the final rule because the Agency did not make a distinction when listing the oil-fired units.
The EPA also disagrees with commenters that by providing the distillate vs. residual oil subcategories as requested, the resultant standards would be more achievable. Were the EPA to subcategorize distillate oil from residual oil, the users of distillate oil would have no means of compliance other than obtaining “compliance” oil from their distributor (which was not indicated as an option by any commenter) or converting to natural gas and being removed from the subcategory. With no further subcategorization, oil-fired EGUs have the option of installing an ESP or converting to distillate oil for compliance. Commenters did not contend that it was impossible to convert to distillate oil, only that it would require plant modifications. Installing controls would also require plant modifications so sources will be able to evaluate the options and determine the most cost-effective option to comply with the final rule. CAA section 112 is intended to be a technology-forcing statute, and, because both distillate oil- and residual oil-fired EGUs were among the best performing sources in the floor and both types are meeting the final standards, we cannot reasonably conclude that the HAP emissions characteristics of these similar types of units are distinct. Therefore, the EPA is not establishing separate subcategories for distillate and residual oil-fired units in the final rule.
Other commenters noted that requiring installation of emission controls on oil-fired units that operate at a 10 percent oil-fired capacity factor or less is nonsensical and will result in little environmental benefit. Commenters contend that low-capacity factor units emit significantly less HAP than even well-controlled oil-fired units with much higher capacity factors. In addition, commenters allege that stack-testing at such units would be equally impractical and, in addition, would likely require the unit to operate on oil (and emit HAP just for the test) when it would otherwise be off-line or operating on natural gas.
At proposal, we solicited comment on establishing a limited-use subcategory for liquid oil-fired EGUs:
EPA is also considering a limited-use subcategory to account for liquid oil-fired units that only operate a limited amount of time per year on oil and are inoperative the remainder of the year. Such units could have specific emission limitations, reduced monitoring requirements (limited operation may preclude the ability to conduct stack testing), or be held to the same emission limitations (which could be met through fuel sampling) as other liquid oil-fired units. EPA solicits comment on all of these proposed subcategorization approaches.
As stated above, the EPA did not have sufficient information on limited-use liquid oil-fired EGUs upon which to base a subcategory at proposal. Some sources required to test under the ICR did not submit the data until after proposal. Commenters indicated that their units are different because many of them are only called to service to address reliability issues associated with, for example, natural gas curtailments. The commenters further indicated that their units are different because of the generally infrequent use and the sporadic, and at times frequent, start-up and shutdown periods (
Based on comments received and our own analysis, we are finalizing a subcategory for limited-use liquid oil-
Although some commenters indicated a prevalence of natural gas/oil co-fired EGUs, the EPA also understands that there are other liquid oil-fired EGUs that do not co-fire natural gas but that could be subject to mandatory operation during periods of natural gas curtailment in their operating area if sufficient non-natural gas capacity is not available. Based on a review of units that report oil use to EPA, in 2010 there were 228 liquid oil-fired EGUs with a capacity factor of less than 5 percent and an additional 10 units with a capacity factor of between 5 percent and 10 percent. Only 2 of these units have capacity factors between 5 percent and 8 percent. This subcategory applies only to oil-fired EGUs that operate on oil alone and act as peaking units, as they generally address reliability issues. We are establishing the capacity factor threshold of 8 percent averaged over each 24-month block period after the compliance date.
Commenters that requested a subcategory for these units noted the dichotomy of establishing a NESHAP to reduce emissions of HAP to the environment while at the same time requiring an EGU to run for the sole purpose of conducting emissions testing and thereby emitting those same HAP. Because the operation of these units is infrequent and unpredictable, performing testing to demonstrate that emission limits are being met requires the sources to be scheduled to be operated merely for the purpose of performing testing. We realize that similar situations occurred in the gathering of emissions data through the 2010 ICR. However, unlike the case of one-time testing on a limited number of these units, such testing would be mandatory on a yearly basis for all of the EGUs upon the effective date of the final rule. Because requiring testing under this rule would in many cases require operators of these EGUs to schedule operation of these EGUs at times they would not otherwise run, it would result in both extra cost related to the testing as well as extra emissions; therefore, the Agency believes that it is technically and economically impracticable to monitor emissions for these EGUs, and that they should be subject to work practice standards that would not require emissions monitoring.
The annual average capacity factor would be calculated on a 24-month block period, commencing with the compliance date of the final rule. For example, assuming a March 1, 2015, compliance date, the first 24-month block would commence on March 1, 2015, and end on February 28, 2017, with the next 24-month block averaging period commencing on March 1, 2017. We believe the 24-month averaging period is reasonable to account for the fact that units needed to address reliability issues (e.g., natural gas curtailment periods) will be called to service sporadically. A 24-month averaging period provides flexibility to ensure that these units can run if there are large periods when natural gas is unavailable. As explained above, the data shows that most of these units operate for less than 8 percent of the time, and in fact it is usually less than 5 percent. Therefore, when considering whether these units would be able to perform stack testing, in many cases this will be for units that in fact operate significantly less than 8 percent of the time. In these cases, the EPA does not want to require the units to operate more just for the purpose of running a stack test resulting in additional pollution and cost. With projections for rising oil prices relative to natural gas prices, we expect this trend to continue. Liquid oil-fired EGUs subject to this subcategory would be required to conduct the same initial and periodic tune-up as all other affected units, but would have no other emission limit or work practice requirements.
Although the EPA believes that the ability to burn oil up to 8 percent of the time should address concerns about units that may need to operate using oil during gas curtailments. The EPA recognizes that if there were a period where gas use was more severely limited, such units might need the flexibility to operate for more than 8 percent in one year and less in the next, which is why we are providing the 2-year period; however based on the data we do not think EGUs in this subcategory will exceed even the 5 percent capacity factor that the data indicate is the average level for these sources.
Two commenters believe that the separate non-continental subcategory should be expanded to include continental areas that are not interconnected with other utilities and have limited compliance options due to remote locations (
The EPA agrees that the unique considerations faced by non-continental refineries, including a limited ability to obtain alternative fuels that lead to different emissions characteristics, warrant a separate subcategory for these EGUs. The EPA believes that units in this subcategory will comply through the use of cleaner oils or, for PM, through the installation of an ESP. The EPA finds no merit in the comment that Alaska should be included in this non-continental subcategory because utilities in Alaska are not faced with the same access issues affecting island-based facilities.
Although the objective of the emission limits we are establishing is to reduce the risks associated with HAP emissions, the limits are based in part upon the demonstrated capabilities of control technologies which are installed on existing sources. Except for Hg, the best PM controls provide the best controls of metal emissions. Emissions measurements of either filterable particulate, total particulate, individual metals, or total metals provide comparable indications that the best level of control is achieved. We can find no significant difference in the emissions that would be achieved by using any one of these emissions measurements.
We re-assessed the relationships between individual metal emissions, filterable PM emissions, total PM emissions, and total PM
The EPA is not aware of any FGD systems installed on oil-fired EGUs. Thus, it is only the quality of the oil, and the level of HAP constituents contained therein, that can be relied upon for ensuring compliance.
In the proposal preamble, we stated:
We believe that chlorine may not be a compound generally expected to be present in oil. The ICR data that we have received suggests that in at least some oil, it is in fact present. EPA requests comment on whether chlorine would be expected to be a contaminant in oil and if not, why it is appearing in the ICR data. To the extent it would not be expected, we are taking comment on the appropriateness of an HCl limit.
Commenters refer to certain studies that provide a plausible reason for the chloride/fluoride contamination of fuel oils. We found this reason persuasive and accordingly are providing alternative compliance approaches in the final rule to demonstrate compliance with the acid gas HAP standards. Specifically, sources can demonstrate compliance through either specific HCl or HF measurements or by demonstrating that the moisture content in the fuel oil remains at a level no more than 1.0 percent.
Several commenters in opposition to area source standards stated that the EPA properly established emissions limitations based upon the performance of all EGUs, rather than distinguishing between major sources and area sources. The commenters believe that Congress did not intend the EPA to distinguish between “major source” EGUs and “area source” EGUs in determining whether and how to regulate EGUs under CAA section 112. These commenters indicated that differentiating major source and area source EGUs for purposes of setting emissions standards is inappropriate in light of the 2000 Finding regarding the threat posed by the absence of regulation of HAP emissions from EGUs. The 2000 Finding was based upon studies whose conclusions regarding the impacts from EGU emissions did not depend upon any relevant distinction between major source and area source EGUs. The commenters note that segregating “major source” and “area source” EGUs
Many commenters in support of an area source designation for EGUs stated that the EPA has promulgated area source limits for many source categories of HAP emissions, including most recently industrial boilers and note that GACT controls have been used successfully in many other EPA MACT rules, including rules for iron & steel foundries, electric arc steelmaking, coatings operations, clay ceramics manufacturing, glass manufacturing, and secondary nonferrous metals manufacturing, in order to reduce costs and regulatory burdens. The commenters state that Congress has given the EPA the ability to subcategorize area sources because of their low HAP emissions and low potential impact on human health and that, contrary to the plain language of CAA section 112 and its legislative history, the EPA made no attempt in the proposed rule to distinguish between major sources and area sources for purposes of listing or setting standards. The commenters indicated that where Congress was concerned about the health impacts of specific pollutants from specific sources, it knew how to specify that MACT limits be promulgated (
The CAA section 112(a)(8) definition of EGU does not distinguish between major and area sources, and we maintain that EGUs are a single source category that contains both major and area sources. The EPA proposed to regulate five subcategories of EGUs without distinguishing between major and area sources for purposes of establishing the standards for the different subcategories. Our approach is wholly consistent with the statutory definition of EGU and reasonable.
Nevertheless, the Agency did examine whether to set separate standards for area source EGUs, because we do not believe that the statute prohibits the Agency from exercising its discretion to establish GACT standards for area sources pursuant to CAA section 112(d)(5) if we determine such standards are appropriate. The EPA is not required, however, to establish GACT standards for area sources, and we believe it may even be unreasonable to do so under the circumstances we identified in the proposed rule as supported by the record of this final rule.
At proposal, we determined that it was not appropriate to establish separate standards for major and area source EGUs, and even if we had exercised our discretion to set separate standards, we would have likely declined to exercise our discretion to set GACT standards for area source EGUs given our appropriate and necessary finding and the fact that a potentially large number of area source EGUs are in fact large well controlled units.
Some commenters note that there could be as many as 12 percent of the total population that could be classified as area sources. We are not sure of the commenters' point in regard to this statement. As to commenters' statements that many of the area sources are municipal utilities, our information shows that many rather large EGUs (
Commenters did not provide an evaluation of the health and environmental impacts of the area sources and simply presume that the risks from such sources are lower, even though many of the same commenters noted that these smaller EGUs are often located in densely populated areas where populations are more likely to have adverse health effects from the HAP emissions. Furthermore, other commenters, including some industry commenters, noted that the vast majority of these potential area sources meet the criteria due to the installation of emission controls installed to meet other requirements. According to these commenters, these synthetic area sources would likely be able to meet the limits of this rulemaking and imposition of this rule would not appear to result in the installation of additional controls in a number of cases. We do not know if this assertion is correct but we determined approximately 69 coal-fired EGUs will be able to meet the existing source MACT standards with their current control configuration (out of 252 EGUs that reported data for Hg, PM, and HCl in the 2010 ICR).
Commenters also note that the Agency has exercised its discretion in other NESHAP rulemakings to establish area source limits. Although true, the fact that the EPA has established area source limits in some source categories is irrelevant to similar decisions for different source categories. Commenters have not shown that the circumstances applicable to those other source categories are similar to the circumstances identified for major and area source EGUs (
The EPA considered the totality of the circumstances when determining whether to set separate area and major source standards for EGUs and also considered whether it would be reasonable to establish GACT standards for areas sources. We reasonably considered whether emissions characteristics of major and area sources are different when determining whether to establish GACT standards, notwithstanding commenters' assertion that such consideration is not correct. That we also consider emission characteristics in subcategorization decisions is of no consequence for area source decisions. Given that the statutory definition of EGUs contains both major and area sources, it was reasonable to evaluate whether there were sufficient differences between area and major sources when deciding whether to exercise our discretion to set separate area and major source standards.
In addition, we find commenter's point concerning CAA section 112(c)(6) odd because EGUs emit several of the CAA section 112(c)(6) HAP (
Commenters indicate that many EGUs owned by small entities are potential area sources. However, commenters fail to note that there are also EGUs owned by small entities that are not potential area sources, and, thus, would not accrue any “lessened regulatory burden” benefit from a decision by the EPA to establish area source standards.
Some commenters state that the EPA's mere assertion that there would be no difference between GACT and MACT to justify an area source finding does not provide sufficient documentation for the decision. But EPA did not say there would be no difference between MACT and GACT. Instead, it stated that it would be difficult to make a distinction given the similarities between the EGUs and major and area source facilities. Specifically, as noted by other commenters, and observable by a review of the MACT Floor Analysis spreadsheets, potential area sources range in size from units near the CAA section 112(a)(8) defined lower size limit to units of hundreds of megawatts. Further, these larger area source units are, for the most part, controlled with the full suite of emission control technologies available (
In addition, the data that were available in the docket for the proposed rule show that there is little difference between major and area source EGUs individually, and that generally the driver for whether a utility facility is a major or area source depends on the number of EGUs located at a facility (almost exclusively one or two EGUs located at area sources), not on any inherent difference between the EGUs themselves.
In addition, the data show that a number of area sources for which we have data are high emitters of Hg and non-Hg metal HAP.
We fully evaluated the nature of EGUs, and we do not see a basis on which to distinguish these sources for purposes of setting standards. Thus, we maintain that we reasonably exercised the discretion afforded the Agency under the statute and declined to set separate standards for area source EGUs.
Other commenters stated that on August 6, 2010, the EPA adopted a NESHAP for Portland Cement plants that specifically rejected adoption of risk-based exemptions or HBEL for HCl and manganese (Mn). These commenters argue there are no differences sufficient to warrant a reversal of that decision in the EGU MACT standard. The commenters raised concerns that health risk information cited by the EPA for HCl, HF, and hydrogen cyanide (HCN) does not establish “an ample margin of safety” and, therefore, no health threshold should be established. The commenters believe risk-based exemptions at levels less stringent than the MACT floor are prone to lawsuits that could potentially further delay implementation of the EGU MACT.
Some commenters disagreed with using a hazard quotient (HQ) approach to establish a risk-based standard because the HQ would not account for potential toxicological interactions. The commenter noted that an HQ approach incorrectly assumes the different acid gases affect health through the same health endpoint, rather than assuming that the gases interact in an additive fashion. This commenter suggested that a hazard index approach, as described in the EPA's “Guideline for the Health Risk Assessment of Chemical Mixtures,” would be more appropriate.
Some commenters dispute that emissions from other EGUs or source categories should be considered when developing an HBEL and they argued that Congress expected the EPA to consider the effect of co-located facilities during the CAA section 112(f) residual risk program instead of under CAA section 112(d). Commenters added that there is no prior EPA precedent for considering co-located facilities from a different source category during the same CAA section 112 rulemaking.
Several commenters disputed the EPA's consideration of non-HAP collateral emissions reductions in setting MACT standards. They contended that the EPA's sole support for its “collateral benefits” theory is legislative history—the Senate Report that accompanied Senate Bill 1630 in 1989 and noted that the D.C. Circuit rejected this use of this theory since the Senate Report referred to an earlier version of the statute that was ultimately not enacted. Instead commenters suggested that other components of the CAA, such as the National Ambient Air Quality Standards (NAAQS), are more appropriate avenues for mitigating emissions of criteria pollutants.
Several other commenters suggested it is impossible to assess an established health threshold for HCl such that a CAA section 112(d)(4) standard could be set without evaluating the collateral benefits of a MACT standard. And, as described in the recently finalized cement kiln MACT rule, setting technology-based standards for HCl will result in significant reductions in the emissions of other pollutants, including SO
Several commenters indicated that the current economic climate requires the EPA to balance economic and environmental interests and indicated that HBEL would help target investments into solving true health threats where limits are no more or less stringent than needed to protect public health. Many commenters provided estimates of compliance cost savings if an HBEL is included in this final rule. Some commenters stressed the importance of an HBEL for small entities affected by the regulations. Several other commenters suggested that the EPA should estimate the costs and environmental effects of the HBEL option compared to a conventional MACT standard in order to make an informed decision on the adoption of HBEL.
The EPA notes that the Agency's authority under CAA section 112(d)(4) is discretionary. That provision states that the EPA “may” consider establishing health thresholds when setting emissions standards under CAA section 112(d). By the use of the term “may,” Congress clearly intended to allow the EPA to decide not to consider a health threshold even for pollutants which have an established threshold. As explained in the preamble to the proposed rule, it is appropriate for the EPA to consider relevant factors when deciding whether to exercise its discretion under CAA section 112(d)(4), and, notwithstanding commenters' assertions to the contrary, the considerations we include in our analysis are reasonable. The EPA has considered the public comments received and is not adopting an emissions standard under CAA section 112(d)(4) for the reasons set forth in the proposed rule and explained below. We note that this action is consistent with EPA's recent decisions not to develop standards under CAA section 112(d)(4) for the Industrial, Commercial and Institutional Boilers and Process Heaters and the Portland Cement source categories.
As explained in the preamble to the proposed rule, the EPA continues to believe that the potential cumulative public health and environmental effects of all acid gas HAP emissions, not just HCl emissions, from EGUs and other acid gas sources located near EGUs supports the Agency's decision not to exercise its discretion under CAA section 112(d)(4). Additional data for all acid gas emissions were not provided during the comment period, and the data already in hand regarding these emissions are not sufficient to support the development of emissions standards for EGUs under CAA section 112(d) that take into account the health threshold for acid gas HAP, particularly given that the Act requires the EPA's consideration of health thresholds under CAA section 112(d)(4) to protect public health with an ample margin of safety. We note here that EPA agrees with the commenter who pointed out that a better way to evaluate the potential health impact interactions of all acid gases would be to use the approach in EPA's “Guideline for the Health Risk Assessment of Chemical Mixtures” rather than a simple evaluation of individual HQ values for each acid gas, but we further note that use of such an approach requires a substantially greater knowledge of acid gas emissions than is currently available. We further note that, even if cost were a relevant factor in setting standards under CAA section 112(d)(4), since the data are not available that would allow us to develop an acid gas HBEL appropriate to protect public health with an ample margin of safety, we cannot determine whether such standards would have any cost savings associated with them or not. In addition, the concerns expressed by the EPA in the proposal regarding the potential environmental impacts and the cumulative impacts of acid gases on public health were not assuaged by the
The EPA also received comments recommending not only that the EPA establish emissions standards for acid gases pursuant to CAA section 112(d)(4), but that it do so by excluding specific facilities from complying with emissions limits if the facility demonstrates that its emissions do not pose a health risk. The EPA does not believe that a plain reading of the statute supports the establishment of such an approach. Although CAA section 112(d)(4) authorizes the EPA to consider the level of the health threshold for pollutants which have an established threshold, that threshold may be considered “when establishing emissions standards under [CAA section 112(d)].” Therefore, the EPA must still establish emissions standards under CAA section 112(d) even if it chooses to exercise its discretion to consider an established health threshold. A source-by-source standard is not mandated as some commenters seem to imply, and we are unsure how we could reasonably implement such an approach even if we determined such an approach was legally available. For these reasons alone, we concluded it was not appropriate to exercise our discretion to establish section 112(d)(4) standards for acid gas HAP emissions.
In addition, as explained in the preamble to the proposed rule, the EPA also considered the co-benefits of setting a conventional MACT standard for HCl. The EPA considered the comments received on this issue and continues to believe that the estimated co-benefits are significant and provide an additional basis for the Administrator to conclude that it is not appropriate to exercise her discretion under CAA section 112(d)(4). The EPA disagrees with the commenters who stated that it is not appropriate to consider non-HAP benefits in deciding whether to invoke CAA section 112(d)(4). Although MACT standards may directly regulate only HAP and not criteria pollutants, Congress did recognize, in the legislative history to CAA section 112(d)(4), that MACT standards would have the collateral benefit of controlling criteria pollutants as well and viewed this as an important benefit of the air toxics program.
Multiple commenters offered suggestions on methods for allowing more time for compliance, including EPA's authority under CAA section 112(n)(1)(A); state authority under CAA section 112(i)(3); Presidential authority under CAA section 112(i)(4); categorical extensions for publicly-owned or governmental facilities according to EO 13132, 13563, and UMRA of 1995; state-designed programs under the delegation provisions of CAA section 112; various Consent Decrees; Administrative Orders of Consent (AOCs); temporary waiver mechanisms; and adoption of MACT compliance schedules through minor permit modifications of a source's Title V federal operating permits. Absent such considerations for additional compliance time, many commenters suggested that the reliability of the nation's electric grid would be jeopardized as utility companies were forced to retire EGUs because they could not install the needed controls in the requisite time.
Compliance times requested by commenters ranged from 1 additional year (4 years total) to 6 additional years (9 years total). Multiple commenters requested that a utility be required to demonstrate good faith progress toward compliance to get any extension. Some commenters suggested that the EPA require utilities to submit a notice concerning which EGUs will be retrofitted or retired within 1 year of the effective date; that the compliance date align with the Power Year used by RTOs; and that the EPA clarify that retirement and any clean replacement power that complies with the NESHAP rule, including off-site combined heat and power and waste heat recovery, can be deemed “controls” under the CAA.
Commenters noted the specific situations related to small entities and their inability to compete with the larger, investor-owned utilities for financing and engineering and technical labor as well as the different process they need to follow for capital improvements. Multiple commenters asked that the EPA consider other simultaneous rulemakings (
Some commenters pointed to existing state programs (
Other commenters requested that no additional time be granted for compliance. These commenters reference a number of reports (
A number of commenters expressed concern that the time frame for compliance with a regulation under CAA section 112(d) was too short for this industry and would result in compromising the reliability of electricity supply. Commenters asserted that reliability would be compromised in several ways: (1) EGUs might have to temporarily close if the owner or operator is unable to install controls on the unit within the 3-year time frame or 3 years plus one; (2) the timing of outages to install controls will cause short term closures that could threaten grid stability; (3) owner/operators may shut down EGUs rather than invest in retrofits to keep them running and that these closures may cause a loss of critical generation; and (4) the construction of replacement generation or implementation of other measures to address reliability concerns due to plant retirements could take longer than 3 years, and that units slated for closure may be necessary beyond the 3-year compliance period but will be unable to run because they have not installed the necessary controls.
As is explained earlier in this preamble, the 3-year compliance window is based on the date that is 60 days after publication of this rule in the
The EPA has considered the concerns raised by commenters and has concluded that given the flexibilities further detailed in this section, the requirements of the final rule for existing sources can be met by most sources without adversely impacting electric reliability. In particular, EPA believes that the flexibility of permitting authorities to allow a fourth year for compliance should be available in a broad range of situations (as discussed below), and that this flexibility addresses many of the concerns that have been raised. Furthermore as indicated below, in the event that an isolated, localized concern were to emerge that could not be addressed solely through the 1-year extension under CAA section 112(i)(3), the CAA provides flexibilities to bring sources into compliance while maintaining reliability.
The EPA considered the impact that potential retirements in response to this rule will have on resource adequacy in order to gauge the rule's impact on reliability. In considering these impacts, the EPA considered both the analysis it has conducted as well as analyses conducted by a number of other groups. The EPA's analysis shows that the expected retirements of coal-fueled units as a result of this final rule (4.7 GW) are fewer than was estimated at proposal and much fewer than some have predicted.
The EPA's assessment looked at the capacity reserve margins in each of 32 subregions in the continental U.S. Demand forecasts used were based on EIA projected demand growth. The analysis shows that with the addition of very little new capacity, average reserve margins are significantly higher than required. The NERC assumes a default reserve margin of 15 percent while the average capacity margin seen after implementation of the policy is nearly 25 percent. Although such an analysis does not address the potential for more localized reliability concerns associated with transmission constraints or the provision of location-specific ancillary services (such as voltage support and black start service), the number of retirements projected suggests that the magnitude of any local reliability concerns should be manageable with existing tools and processes.
Several outside analyses have reached conclusions consistent with EPA's analysis. The DOE, in December 2011, published a report that looked at resource adequacy in the bulk power system when faced with a stress test which was a regulatory scenario far more stringent than EPA's regulations.
In June 2011, the Bipartisan Policy Center issued a report analyzing potential collective impacts of EPA's pending power sector rules and concluding that “scenarios in which electric system reliability is broadly affected are unlikely to occur.”
In August 2011, PJM Interconnection—the Regional Transmission Operator (RTO) responsible for planning and reliable operation of the bulk power system serving all or portions of 13 states in the Mid-Atlantic and Midwestern regions—issued a report analyzing the impacts of the CSAPR and the proposed MATS rule.
The EPA has reviewed industry and NERC studies suggesting, contrary to the EPA's and these other groups' analyses, that EPA rules affecting the power sector (including this final rule, the CSAPR, EPA's proposed rule addressing power plant cooling water intake systems under section 316(b) of the Clean Water Act (CWA), and EPA's proposed rule addressing coal combustion residuals under the Resource Conservation and Recovery Act) will result in substantial power plant retirements. Some of these studies predict that such levels of retirements will have adverse effects on electric reliability in some regions of the country. Although the specifics of these analyses differ, in general they share a number of serious flaws in common that call their conclusions into question.
First, most of these studies make assumptions about the requirements of the EPA rules that are inconsistent with, and dramatically more expensive than, the EPA's actual proposals or final rules. For example, a large proportion of the retirements projected by several of these studies is attributable to their inaccurate assumption that EPA's cooling water intake rule under CWA section 316(b) would require all or virtually all existing power plants to install cooling towers. In one study, the reliability effects reported are based on inaccurate assumptions that all existing EGUs with a capacity utilization factor of less than 35 percent would close, and that all in-scope electric generators would be required to install cooling towers within 5 years, whereas the not-selected options with closed cycle cooling in EPA's proposal envisioned that permit authorities could exercise discretion to allow facilities 10 to 15 years' time to comply. In most cases, these analyses were performed before the CWA section 316(b) rule or the MATS rule were even proposed; even analyses subsequent to the CWA section 316(b) proposal continue to inaccurately portray EPA's proposed approach.
Second, in reporting the number of retirements, many analyses fail to differentiate between plant retirements attributable to the EPA rules and retirements of older, smaller, and less efficient plants that are already scheduled for retirement because owners have made business decisions, based in significant part on market conditions, not to continue operating them.
Third, most of these analyses fail to account for the broad range of responses available to address electric reliability concerns associated with power plant retirements, including upgrades to the transmission system, construction of new generation, and implementation of demand-side measures. These measures are discussed at greater length below.
As a preliminary matter, none of these situations, either alone or in combination, will necessarily lead to an electric reliability problem. There is excess generating capacity in the U.S. today and in most cases an EGU that closes, either temporarily until it comes into compliance or permanently, will not cause a reliability problem. As explained above, our modeling of the impact of this final rule at the regional level projects retirements of less than one percent of nationwide generating capacity and confirms that there will continue to be adequate capacity in all 32 subregions of the country as sources comply with the rule.
Outside analyses have identified many of the same flaws in studies
Although we do not expect to see any regional reliability problems, we acknowledge that there could be localized reliability issues in some areas—due to transmission constraints or location-specific ancillary services provided by retiring generation—if utilities and other entities with responsibility for maintaining electric reliability do not take actions to mitigate such issues in a timely fashion. There are many potential actions that could be taken to address this problem and multiple safeguards to assure a reliable electricity supply.
First, utilities can help to assure reliability through proactive steps in coordination with relevant planning and regulatory authorities. As we said in the proposal, early planning is key. The industry has adequate resources to install the necessary controls and develop the new capacity that may be required within the compliance time provided for in the final rule.
Second, companies that intend to retire EGUs should formally notify their RTO (or comparable planning authority in the case of non-RTO regions), state regulatory agencies, and regional reliability entities as soon as possible of their compliance plans, particularly with regard to any planned unit retirements. As we said before, in most places a closing plant will not be a cause for concern for reliability. The same is true of any outages required for retrofitting of units with controls. To the extent there is concern, however, early notification will provide an opportunity for transmission planners, market participants, and state authorities to develop solutions to avoid a reliability problem. In RTOs with forward capacity markets, owner/operators that do not bid generating capacity that they plan to shut down will provide an advance signal to market participants to take action to assure adequate future capacity. In all regions, early and public notification will allow market participants, planning coordinators and state authorities, as appropriate and in a timely fashion, to bring new generation on line, put demand side resources in place, and/or complete any transmission upgrades needed to circumvent a potential issue. Most RTOs only require 45 to 120 days notification of closure. In combined comments to EPA, 5 RTOs suggested that such notification should be made no later than 12 months after this regulation is final in order to allow a smooth transitioning to action to avoid a reliability problem. The EPA strongly encourages sources to provide notice to the RTOs as early as possible and believes that responsible owner/operators should and will do the early planning for compliance and provide early notification of their compliance plans, especially where such plans include retiring one or more units.
On the supply side, there are a range of options including the development of more centralized power resources (either base-load or peaking) and/or the development of cogeneration or distributed generation. Even with the current large reserve margins, there are companies ready to implement supply-side projects quickly. For instance, in the PJM region, there are over 11,600 MW of capacity that have completed feasibility and impact studies; the units representing this capacity could be on-line by the third quarter of 2014.
Demand side options include energy efficiency as well as demand response programs. These types of resources can also be developed very quickly. In 2006, PJM had less than 2,000 MWs of capacity in demand side resources. Within 4 years this capacity nearly quadrupled to almost 8,000 MW of capacity.
With regard to transmission, recent experience also shows that, in many cases, transmission upgrades to address reliability issues from plant closures can be implemented in less than 3 years. For instance, when Exelon notified PJM of its intention to retire four units,
The CAA allows CAA Title V permitting authorities the discretion to grant extensions to the compliance time of up to one year if needed for installation of controls.
We believe that the permitting authorities have the discretion to use this extension authority to address a range of situations in which installation schedules may take more than 3 years including: staggering installations for reliability reasons or other site-specific challenges that may arise related to source-specific construction, permitting, or labor, procurement or resource challenges. Staggered installation allows companies to schedule outages at multiple units so that reliable power can be provided during these outage periods. It can also be helpful for particularly complex retrofits (
As we indicated at proposal, this source category is unique due to the large, complex and interconnected nature of electrical generation, transmission and distribution, and the critical role of the electric grid in the functioning of all aspects of the economy. The grid functions as an interconnected system that supplies electricity to end users on a continuous basis. Safe, reliable operation of the grid requires coordination among actions taken at individual units, including timing of outages for the installation of controls, derating, or deactivation. It was for this reason that we specifically addressed in the proposed rule reasonable interpretations of the phrase “installation of controls” in CAA section 112(i)(3)(B). We determined that it was important to provide Title V permit authorities with information that might be useful if they were asked to authorize a fourth year for specific EGUs.
The EPA took comment on whether the construction of on-site replacement power could be considered the “installation of controls” such that a fourth year would be available while the replacement unit is being completed for a unit that is retiring (
Commenters were generally supportive of the proposed approach described above, but a number of commenters suggested several additional situations that should be considered as the “installation of controls” such that it would be appropriate for permitting authorities to grant a 1-year extension beyond the 3-year compliance time-frame. In particular, commenters suggested that the 1-year extension should be available for a unit if a company's compliance choice was to retire that unit but doing so within the 3-year time-frame caused reliability problems for any of the following reasons: (1) Generation from the retiring unit is needed to maintain reliability while other units install emission controls; (2) new off-site generation was being built to replace the retiring unit, but the new generation was not scheduled to be operational within the 3-year time-frame and any gap between the time the existing unit retires and the new unit comes on line would cause reliability problems; and (3) transmission upgrades were needed in order to maintain electric reliability after the unit retired but could not be completed within 3 years.
While the ultimate discretion to provide a 1-year extension lies with the permitting authority, EPA believes that all three of these cases may provide reasonable justification for granting the 1-year extension if the permitting authority determines, for example, based on information from the RTO or other planning authority or other entities with relevant expertise, that continued operation of a particular unit slated for retirement for some or all of the additional year is necessary to avoid a serious risk to electric reliability.
In a case where pollution controls are being installed, or onsite replacement power is being constructed to allow for retirement of older, under-controlled generation, a determination that an extra year is necessary for compliance should be relatively straightforward. In order to install controls, companies will have to go through a number of steps fairly early in the process including obtaining necessary building and environmental permits and hiring contractors to perform the construction of the emission controls or replacement power. This should provide sufficient information for a permitting authority to determine that emission controls are being installed or that replacement power is being constructed. Because companies will need to develop this information early in the process and because a determination can easily be made as to whether the schedule will exceed 3 years, the EPA believes that Title V permitting authorities should be able to quickly make determinations as to when extensions are appropriate.
In the three cases related to retirement of a unit without construction of onsite replacement power, additional information is needed. The Title V permitting authority should request that the affected company or companies provide information, including, for example, from the RTO or other planning authority for the relevant region, the state electric regulatory agency, NERC or its regional entities, and/or FERC or the DOE, demonstrating that retirement of a particular unit within the 3-year compliance period would result in a serious risk to electric reliability.
The first two situations involving a retiring unit—where one or more related existing units are upgrading pollution controls or a new unit is being constructed off-site—are similar to the situation we discussed in the proposed rule wherein a retiring unit at a facility runs an additional year while a replacement unit on the same site is constructed. In each of these situations, the retiring unit would be allowed to run so a unit compliant with the rule (either a retrofitted existing unit or a new unit) can come on line. We believe that these situations may, in the appropriate circumstances, constitute ones in which a 1-year extension for the retiring unit is “necessary for the installation of controls.” In these two situations, however, we believe that it would be appropriate for the Title V permitting authority to consider reliability concerns as a necessary factor before granting the additional year because continuing operation of the retiring unit is only “necessary” to the extent it is required for reliability. In each of these situations, the permitting authority should determine that the retiring unit is necessary to maintain
The third hypothetical situation identified above is one in which transmission upgrades are necessary to address a reliability issue resulting from the retirement of a unit in order to comply with this rule, where the upgrade cannot be completed by the 3-year compliance date. In terms of the functionality of the electric grid, this situation has some similarity to those discussed above. Here, it is the completion of the transmission upgrades, rather than bringing another compliant (retrofitted or new) unit on line, that would allow the retiring unit to come into compliance (by retiring) without threatening reliability. The general objective and result is similar: Reductions of the existing unit's HAP emissions (through retirement) while maintaining electric reliability. If such situations develop and the reliability problem has been properly demonstrated, permitting authorities should consider whether an extension under CAA section 112(i)(3)(B) may be provided.
The EPA continues to believe, based on the analysis discussed at the beginning of this section, that most, if not all, units will be able to comply with the requirements of this rule within 3 years. The EPA also believes that making it clear that permitting authorities have the authority to grant a 1-year compliance extension where necessary, in the range of situations described above, addresses many of the other concerns that commenters have raised. The EPA believes that the number of cases in which a unit is reliability critical and in which it is not possible to either install controls on the unit or mitigate the reliability issue through construction of new generation, transmission upgrades, or demand-side measures, within 4 years, is likely to be very small or nonexistent. This view is consistent with statements from commenters explicitly mandated with ensuring grid reliability.
The EPA's authority to provide relief from the requirements of this final rule beyond the fourth year is limited by the statute. If reliability issues do develop, however, the CAA provides mechanisms for sources to come into compliance while maintaining electric reliability. One area where the EPA has some measure of flexibility is with respect to the exercise of its enforcement authorities. The Agency has used such authority in the past to bring sources into compliance with the requirements of the CAA while maintaining electric reliability, although these authorities are not as flexible as suggested by some commenters.
The EPA generally does not speak publicly to the intended scope of its enforcement efforts, particularly well in advance of the date when a violation may occur. In light of the importance of ensuring electric reliability, however, the Office of Enforcement and Compliance Assurance will separately publish a document that articulates our intended approach with respect to sources that operate in noncompliance with this final rule to address a specific and documented reliability concerns.
That document provides a pathway for reliability critical units (as such units are described in the document) to achieve compliance within an additional year. The result is that qualifying reliability critical units may come into compliance within up to 5 years. This pathway is structured to maintain reliability, to ensure CAA compliance and to increase certainty for sources in planning by allowing a unit owner/operator to determine whether it qualifies for a compliance schedule well in advance of the MATS compliance deadline.
The EPA believes that there will be few, if any, situations in which it will be necessary to have recourse to the processes discussed in the document just described, and that there are likely to be fewer, if any, cases in which it is not possible to mitigate a reliability issue within the further year contemplated under that document. However, there is always the possibility that some unit owner/operator will be unable to address its reliability issues within 5 years and there is always the possibility that a unit owner/operator will be unable to timely comply with the MATS for some other reason. Consistent with its longstanding historical practice under the CAA, the EPA will address individual non-compliance circumstances on a case-by-case basis, at the appropriate time, to determine the appropriate response and resolution.
A number of commenters also raised concerns about inconsistencies between the compliance timelines under this final rule and existing state agreements with specific owners/operators to install pollution control equipment and/or retire EGUs. The EPA believes the flexibilities provided in this discussion allow for some discretion to address those cases, but that they may not be fully addressed. The EPA is supportive of such efforts and believes they can have important multi-pollutant health and environmental benefits. To the extent that the flexibilities discussed here do not fully address a particular situation, we encourage states and sources to contact the EPA as early as possible to discuss their individual circumstances.
Other commenters disagree with statements made that DSI is not proven. One commenter stated that DSI is a mature technology. The commenter indicated that DSI is well suited for units that burn fuels with lower or mid-level sulfur contents, and is among the viable options available for a number of sources to achieve the proposed HCl limits. Thus, the commenter believes that DSI represents a real technology control option for many units, and is among the suite of technology options that certain units will be able to employ to meet the proposed HCl limit.
Some commenters were concerned that fly ash currently sold for beneficial uses will become unsalable because it will be contaminated by injected sodium-based DSI sorbents. Two commenters argued that EPA's IPM analysis understates DSI cost by not including the costs of foregone fly ash sales revenue and contaminated fly ash disposal. A few commenters observed that landfilling of sodium-based DSI solid wastes will produce leachate containing sodium and other compounds that are challenging to handle, thus requiring special landfill designs and a high cost for landfill disposal of DSI waste.
The EPA disagrees that its IPM modeling of DSI is overly optimistic and therefore underestimates the costs of MATS compliance. In its IPM modeling, EPA restricts the availability of the DSI option to only those units that use or switch to relatively low sulfur coal: Less than 2 lb SO
Senior technical staff from the EPA have carefully evaluated the key assumptions regarding the cost and operation of emission control technologies. In general, these staff believe that trona should have strong HCl reaction selectivity and, consequently, EPA's assumed trona injection rates may be overstated. The extent to which this assumption may actually overstate DSI control costs can be observed through DSI pilot testing for Solvay Chemicals by the Energy & Environmental Research Center (EERC) at the University of North Dakota.
Given the EERC test data, it is also apparent that most units that have ESPs and are burning low sulfur western coal could meet the HCl limit using DSI without the addition of a FF. If EPA were to re-analyze MATS compliance while allowing DSI use without the need for a downstream FF, it is apparent that there would be a very significant reduction in the overall number of FF retrofits projected, and a corresponding reduction in annualized capital costs. For the MATS proposal, the EPA modeled DSI on the assumption that all chlorine in coal converts to HCl, and that DSI would be the only mechanism by which the unit could prevent HCl from being emitted. Based on public
The EPA models DSI with sorbent injection occurring downstream of an existing electrostatic precipitator (ESP). The existing ESP is assumed to remain in service. The model adds a fabric filter downstream of the DSI injection point to capture the small amount of PM passing through the ESP plus the reacted and unreacted DSI sorbent. Most of the DSI projected by IPM, therefore, includes the costs of a retrofitted FF. This modeled configuration allows fly ash currently captured in ESPs to remain uncontaminated by DSI sorbent and, therefore, remain available for sale and beneficial use. The EPA conservatively models FF costs based on an assumed full-size system with an air-to-cloth ratio of 4.0. The FF costs could be somewhat less in practice if a smaller system (with an air-to-cloth ratio of 6.0) were used for the reduced DSI dust loading. The EPA observes that some of the owners of units with ESPs may chose to convert existing ESPs into FFs,
For all of these reasons, the EPA believes that its representation of DSI in MATS compliance modeling is reasonable, is properly limited to applications that are technically feasible, and reflects a conservative approach to modeling future use of this technology.
The EPA estimates that there will be an increase of 3.1 percent in retail
The Agency found that the readily discernible impact on long-term employment nationally within the most directly affected sectors should be small and the EPA also estimated that about 46,000 job-years
The EPA has also looked at the possibility that changes in the price of electricity may influence the levels and geographic distribution of downstream economic activities, and associated employment. Projecting how potentially higher electricity prices may affect various downstream economic activities in particular regions as a result of this rule is challenging for several reasons: (1) There are significant uncertainties regarding projections of consumer- and location-specific electricity price changes in response to future firm-specific compliance strategies; (2) the availability of competitively-priced alternative energy sources (including energy conservation) and less electricity-intensive substitute goods and services may significantly mitigate potentially adverse economic consequences resulting from projected increases in electricity prices in ways which are not captured effectively in currently available models; and (3) available modeling tools are not configured to capture the effects over time of economically significant effects of cleaner air (
We expect the downstream economic effects of this rule to be small because electricity is only a small factor in the production of most goods and services.
Despite the absence of a satisfactory methodology for quantifying the potential economy-wide effects (including employment) of any potential increases in electricity prices resulting from this rule, the EPA expects the incremental effects of this rule on electricity prices to be small given the projected electricity price increases relative to historical levels and volatility in end-user electricity prices. Based on these projections and contextual information, the Agency believes that the incremental effects on electricity prices and economic activity of this rule are likely to be small relative to other factors influencing electricity prices, overall employment, and other aspects of economic activity.
Several commenters observed that the positive impacts of the rule strongly favor its adoption. These commenters stated that, contrary to the unfounded assertions by critics of EPA and the rule, EPA has conducted a technically sound and conservative benefit-cost analysis showing that the proposed rule's estimated benefits are at least five times as high as its costs. One commenter stated, “With sound, albeit unduly conservative, econometric modeling, EPA has also determined that the Toxics Rule will promote economic growth and create jobs in both the long and short term.” Two commenters cited the EPA impact analyses by Dr. Charles Cicchetti which confirm this finding and state that the analysis underestimates the rule's net benefits and positive impacts on the nation's economy. By considering some benefits not monetized in the EPA analysis, Dr. Cicchetti concludes that the proposed rule will create $52.5 to $139.5 billion in net benefits annually, create 115,200 jobs, generate annual health savings of $4.513 billion, annual increases in GDP of $7.17 billion and $2.689 billion in additional annual tax revenues, and spur innovation and modernization of EGUs. The commenters state that the study findings show no need to delay implementation of the rule or needlessly duplicate economic analyses already completed.
Commenters reported that multiple researchers confirmed that the EPA's estimates of economic stimulus are conservative and that the proposed rule will stimulate job growth. A commenter quotes Dr. Josh Bivens of the Economic Policy Institute, who also found that EPA's conclusions were conservative. Dr. Bivens concluded, “The EPA RIA on the proposed toxics rule makes a compelling case that the rule passes any reasonable cost-benefit analysis with flying colors—the monetized benefits of longer lives, better health, and greater productivity dwarf the projected costs of compliance * * * Whether regulation in general and the toxics rule in particular costs jobs is an empirical question this paper attempts to answer. In particular, this paper examines the possible channels through which the proposed toxics rule could affect employment in the United States and finds that claims that this regulation destroys jobs are flat wrong: “The jobs-impact of the rule will be modest, but it will be positive.” His report details the following major findings:
1. The proposed rule would have a modest positive net impact on overall employment, likely leading to the creation of 28,000 to 158,000 jobs between now and 2015.
2. The employment effect of the [MATS] on the utility industry itself could range from 17,000 jobs lost to 35,000 jobs gained.
3. The proposed rule would create between 81,000 and 101,000 jobs in the pollution abatement and control industry (which includes suppliers such as steelmakers).
4. Between 31,000 and 46,000 jobs would be lost due to higher energy prices leading to reductions in output.
5. Assuming a re-spending multiplier of 0.5, and since the net impact of the above impacts is positive, another 9,000 to 53,000 jobs would be created through re-spending.
The EPA's analysis shows that retail electricity price increases will not fall disproportionately on a specific region. In fact, those regions experiencing the largest change in prices are projected to have retail electricity prices below the national average both in the absence of MATS and after the implementation of MATS. In Chapter 3 of the RIA, the EPA presents retail electricity prices by region in 2015, for both the base case and MATS policy case. The six regions that are projected to have retail electricity prices above the national average price in 2015 in the absence of MATS are projected to have increases that are below the national average increase following the implementation of MATS. Those regions that have projected retail electricity price increases that are above the national average are all projected to have retail electricity prices below the national average in the absence of MATS.
The results of the EPA's employment analysis, found in Chapter 6 of the RIA, indicate that the final MATS has the potential to provide significant short-term employment opportunities, primarily driven by the high demand for new pollution control equipment. While the employment gains related to the new pollution controls are likely to be tempered by some losses due to certain coal retirements, some of these workers who lose their jobs due to plant retirements could find replacement employment operating the new pollution controls at nearby units. Finally, job losses due to reduced coal demand are expected to be offset by job gains due to increased natural gas demand, resulting in a small positive net change in employment due to fuel demand changes.
While shifts in employment are difficult for those directly affected, and the Agency remains concerned about the challenges job shifts can bring to the
1. The power sector has demonstrated ability to install large number of systems in short time period;
2. The majority of coal plans have installed control systems already;
3. Fewer resource and labor-intensive control options being used for compliance; and
4. End users have utilized cost reducing and implementation efficiency strategies for efficient deployment of technologies.
Another commenter states that a wide range of technical and economically feasible practices and technologies are available currently to meet the emission limits and are in use around the country.
This does not, however, mean EPA has failed to incorporate these regulations into this analysis. The inclusion of CSAPR and other regulatory actions (including federal, state, and local actions) in the IPM base case reflects the level of controls that are likely to be in place in response to other requirements apart from MATS. This base case provides meaningful projections of how the power sector will respond to the cumulative regulatory requirements for air emissions, while isolating the incremental impacts of MATS. These results are presented in Chapter 3 of the RIA.
Additionally, the Agency does reflect on the cumulative impacts of our regulations. In March 2011, EPA issued the Second Clean Air Act Prospective Report which assessed the benefits and costs of regulations pursuant to the 1990 Clean Air Act Amendments. The study examines the cumulative impact of these regulations (found at
The direct benefits of the 1990 Clean Air Act Amendments and associated programs are estimated to significantly exceed their direct costs, which means economic welfare and quality of life for Americans were improved by passage of the 1990 Amendments. The wide margin by which benefits are estimated to exceed costs, combined with extensive uncertainty analysis, suggest it is very unlikely this result would be reversed using any reasonable alternative assumptions or methods. The analysis presented in the RIA for the current regulation uses a similar methodology.
The techniques employed by the Agency for generating benefits and costs, and consider the most recent and complete data available to the Agency. The EPA recognizes that the analyses have caveats and limitations, and we discuss our analyses and their caveats and limitations in the RIA for the rule, as well as in the benefits section of the preamble. The Agency has also revised the cost analyses for the final rule to reflect data received in public comments on the proposed rule, and costs are lower than when the rule was proposed.
1. Direct compliance costs to electric generating units (EGUs) owned by federal agencies; and
2. Pass-through compliance costs paid in the form of higher prices for electricity purchased by federal agencies.
For stack test frequency, we modified the final rule to require quarterly testing to demonstrate continuous compliance. In addition, we agree that testing should be required only for the emission limits that your source is complying with, and, thus, the final rule does not require testing of both the pollutant and the surrogate.
The final rule establishes the PM CPMS as an operating limit monitor and not a direct filterable PM emission monitoring requirement that meets PS 11 requirements. Although we recognize the importance of continued control device performance to ensure emissions minimization, we also are aware that other rules that apply to these units including, but not limited to, the Operating Permits rule, the Compliance Assurance Monitoring rule, the ARP rules, and the NSPS already require continuous monitoring in most cases. Those rules will remain in effect so the need to impose additional operating limits monitoring or CEMS on those units is much reduced.
The final rule also provides for the use of a PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use this approach. In that case, the PM CEMS is used as the direct method of compliance and no additional testing is required other than tests that are required as part of satisfying the requirements in Performance Specification 11 in Appendix B to 40 CFR part 60 and Procedure 2 in Appendix F to part 60. The EPA provided this option in response to the comments in order to provide a straightforward direct measure of compliance that some sources may want to implement.
The final rule provides the option for use of either Hg CEMS or sorbent trap monitoring systems. We believe the record clearly shows these to be proven technologies each providing certain advantages. For existing and some of the new unit standards, the level of the NIST-traceable Hg gas standards will be adequate and consistent with existing applications of Hg CEMS. For the lowest limits and other applications where an integrated sampling system offers advantages, affected facilities may opt to use sorbent trap monitoring systems to comply. There are data in the recent draft report entitled “Determining the Variability Of CMMS At Low Hg Levels,”
The final rule provides several options for HCl and/or HF monitoring including:
(1) Using Fourier Transform Infrared (FTIR)-based HCl CEMS and/or HF CEMS complying with Appendix B to the rule which relies on PS 15,
(2) Seeking approval for an alternative HCl monitoring procedure through 40 CFR 63.7(f),
(3) Monitoring compliance continuously with the alternate SO
(4) Quarterly reference method testing.
Including these options in the final rule provides flexibility to adopt CEMS monitoring options as the technology continues to mature and the new, non-technology-specific EPA performance specifications becomes available.
Instead of a minimum data availability threshold that would invalidate data collected for some averaging periods because one did not collect data for at least a specified percent of an averaging time, the final rule requires that a source report as deviations to the rule failure to collect data during required periods if these deviations are not covered by exceptions allowed in the final rule.
On the issue of applying a data substitution procedure to represent actual emissions or pollution control performance, we are not requiring data substitutions under this rule. We believe, however, that defensibility concerns make it incumbent on the source to collect and evaluate other information in accordance with 40 CFR section 63.6(f)(3) during periods of monitoring downtime to assure compliance with the applicable emissions limitations and standards.
We believe that enforcement authorities also can and should determine whether a source is meeting any monitoring system operating
We further believe that the final rule provides sufficient means to ensure CMS performance and ongoing compliance without specifying an arbitrary numerical minimum data availability or data substitution requirement. We believe that specifying failure to collect required or otherwise excepted data as a deviation from the rule will provide the necessary incentive to collect data sufficient to demonstrate compliance with the limits in the final rule.
In addition, the 5-year retention period is the general rule for all recordkeeping for all sources under the part 70 operating permits program. Given that the General Provisions for 40 CFR part 63 and part 70 already establish a 5-year retention period, we believe it is justified in using those precedents for the retention periods under this subpart. If we stayed silent on retention period in this subpart, the General Provisions would provide for the 5-year retention as would the part 70 requirements. Thus, this action does not establish any new retention requirements, but merely confirms that the existing retention requirements apply.
The electronic submission of compliance test reports to us through the Central Data Exchange (CDX) is not solely for the purpose of developing improved emissions factors as some commenters assert. Although populating WebFIRE will allow us to improve emissions factors, we intend to use data stored in WebFIRE as the primary location for compliance test reports for use by regulatory authorities. The electronic submission of compliance test reports is a continuation of our efforts to bring the submission and sharing of environmental data into the modern age. The storage of this compliance data in our WebFIRE provides a convenient location which is already used to store source test data.
As federal and state and local agencies' data systems mature, information provided through the ERT will be used to populate these data systems. We are currently upgrading the AIRS Facility System and expect to replace manually entered information with electronic population from the ERT. We are also working with several state and local agencies to adopt the use of the ERT for delivery of compliance test reports. The ERT is also much improved since the version used during the 2010 ICR process, and there is no expectation that the information to be reported under this final rule will be as extensive as some of the data reported for the 2010 ICR purposes.
We disagree that a separate and independent regulatory action is required to implement electronic reporting for selected regulated sources. Each of these regulatory actions for selected source categories provides ample notice and the opportunity for individuals to provide comment. We also disagree that the system to receive the compliance data must be operational prior to establishing the requirement for regulated sources to submit compliance data electronically. We are on track to have the capability to receive electronic compliance tests through our CDX in sufficient time to receive all utility source test reports required by this final rule.
We do plan a separate and independent regulatory action to implement electronic reporting for regulated entities which are covered by past and future rules. Although we have provided draft procedures for the development of emissions factors, that effort is an ancillary effort to the electronic delivery of compliance test reports. It is our intention to convert to the electronic delivery and storage of all air emissions compliance source test data. With this transition, we believe this valuable information will be more readily available not only for compliance purposes but also for a variety of other uses.
New source performance standards implement CAA section 111(b), and are issued for categories of sources which cause, or contribute significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare. Section 111 of the CAA requires that NSPS reflect the application of the best system of emissions reductions which (taking into consideration the cost of achieving such emissions reductions, any non-air quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated. The level of control prescribed by CAA section 111 historically has been referred to as “Best Demonstrated Technology” or BDT. In order to better reflect that CAA section 111 was amended in 1990 to clarify that “best systems” may or may not be “technology,” the EPA is now using the term “best system of emission reduction” or BSER. As was done previously in analyzing BDT, the EPA uses available information and considers the emission reductions and incremental costs for different systems available at reasonable cost. Then, the EPA determines the appropriate emission limits representative of BSER. Section 111(b)(1)(B) of the CAA requires EPA to periodically review and revise the standards of performance, as necessary, to reflect improvements in methods for reducing emissions.
The current standards for steam generating units are contained in the NSPS for EGUs (40 CFR part 60, subpart Da), industrial-commercial-institutional steam generating units (40 CFR part 60, subpart Db), and small industrial-commercial-institutional steam generating units (40 CFR part 60, subpart Dc).
The NSPS for EGUs (40 CFR part 60, subpart Da) were originally promulgated on June 11, 1979 (44 FR 33580) and apply to units capable of firing more than 73 megawatts (MW) (250 MMBtu/h) heat input of fossil fuel that commenced construction, reconstruction, or modification after September 18, 1978. The NSPS for EGUs also apply to industrial-commercial-institutional cogeneration units that sell more than 25 MW and more than one-third of their potential output capacity to any utility power distribution system. The most recent significant amendments to emission standards under 40 CFR part 60, subpart Da, were promulgated in 2006 (71 FR 9866) resulting in new PM, SO
The NSPS for industrial-commercial-institutional steam generating units (40 CFR part 60, subpart Db) apply to units for which construction, modification, or reconstruction commenced after June 19, 1984, that have a heat input capacity greater than 29 MW (100 MMBtu/h). Those standards were originally promulgated on November 25, 1986 (51 FR 42768) and also have been amended since the original promulgation to reflect changes in BSER for these sources.
The NSPS for small industrial-commercial-institutional steam generating units (40 CFR part 60, subpart Dc) were originally promulgated on September 12, 1990 (55 FR 37674) and apply to units with a maximum heat input capacity greater than or equal to 2.9 MW (10 MMBtu/h) but less than 29 MW (100 MMBtu/h). Those standards apply to units that commenced construction, reconstruction, or modification after June 9, 1989.
The final rule amends the emission standards for SO
The filterable PM emissions standard for new and reconstructed EGUs is 11 nanograms per joule (ng/J) (0.090 pound per megawatt hour (lb/MWh)) gross energy output regardless of the type of fuel burned. The PM emissions standard for modified EGUs is essentially equivalent to the existing requirements of 13 ng/J (0.015 lb/MWh) heat input regardless of the type of fuel burned. Compliance with this emission limit can be determined using testing, monitoring, and other compliance provisions similar to those for PM standards set forth in the existing rule. While not required, PM CEMS may be used as an alternative method to demonstrate continuous compliance and as an alternative to opacity and parameter monitoring requirements.
The SO
The NO
As an alternative to the NO
See the Response to Comments document.
The proposal included a combined (filterable plus condensable) PM standard. The final standard is based only on filterable PM. No standard is being established for condensable PM. The rationale for this is set forth in the Response to Comments (RTC) document for this final rule (the NSPS Final Rule RTC).
The proposal requested comment on whether the final standard should include a stand-alone NO
The proposal included alternate emission standards for commercial demonstration projects. Proposed commercial demonstrations included pressurized fluidized beds, multi-pollutant control technologies, and advanced combustion controls. The final rule includes the commercial demonstration permit exemption for pressurized fluidized beds and multi-pollutant control technologies, but not advanced combustion controls. Advanced combustion controls are applicable to existing facilities and the exemption is not necessary to further the development of the technology.
For startup and shutdown, the requirements for PM have changed since proposal. For periods of startup and shutdown, the EPA is finalizing work practice standards for PM in lieu of numeric emission limits. Emissions incurred during periods of startup and shutdown for PM are not used in demonstrations of compliance with the 30-boiler operating day rolling average period applicable for numeric emission standards.
See the Response to Comments document.
The EPA anticipates significant public health and environmental benefits from the rule as a direct result of the substantial reduction in the emissions of several pollutants, including SO
Additionally, the EPA anticipates significant non-health, non-ecological benefits from this rule. The fine particle and SO
The EPA anticipates significant emission reductions under the final rule from coal-fired EGUs, which are of particular interest due to their share of total power sector emissions. In 2015, annual HCl emissions are projected to be reduced by 88 percent, Hg emissions reduced by 75 percent, and PM
The reductions in this table do not account for reductions in other HAP which will occur as a result of this rule. For instance, the fine particulate reductions presented above only partly reflect reductions in many heavy metal particulates, and the HCl reductions above only partly reflect reductions of all acid gases. This rule will also result in additional HAP reductions from oil-fired EGUs, which are covered by the rule but are not included in the EPA's analysis of emission reductions.
The EPA projects that approximately 4.7 GW of coal-fired generation (less than 2 percent of all coal-fired capacity and 0.5 percent of total generation capacity in 2015) may be uneconomic to maintain and may be removed from operation by 2015. These units are predominantly smaller, less frequently used, and are dispersed throughout the country. If current forecasts of either natural gas prices or electricity demand were revised in the future to be higher, that would create a greater incentive to
The final rule has other important energy market implications. Average nationwide retail electricity prices are projected to increase in the contiguous U.S. by 3.1 percent in 2015. The average delivered coal price is projected to increase by less than 2 percent in 2015 as a result of shifts within and across coal types. The EPA also projects that electric power sector-delivered natural gas prices will increase by between 0.3 and 0.6 percent over the 2015 to 2030 timeframe, on average, and that natural gas use for electricity generation will increase by less than 200 billion cubic feet (BCF) in 2015. These impacts are well within the range of price variability that is regularly experienced in natural gas markets. Finally, the EPA projects coal production for use by the power sector, a large component of total coal production, will decrease by 10 million tons in 2015 from base case levels, which is about 1 percent of total coal produced for the electric power sector in that year.
The power industry's “compliance costs” are represented in this analysis as the change in electric power generation costs between the base case and policy case in which the sector pursues pollution control approaches to meet the MATS emission standards. In simple terms, these costs are the resource costs of direct power industry expenditures to comply with the EPA's requirements.
The EPA projects that the annual incremental compliance cost of MATS is $9.6 billion in 2015 ($2007). The annualized incremental cost is the projected additional cost of complying with the rule in the year analyzed, and includes the amortized cost of capital investment and the ongoing costs of operating additional pollution controls, needed new capacity, shifts between or amongst various fuels, and other actions associated with compliance.
The total incremental compliance cost includes compliance costs modeled in IPM of $9.4 billion, costs modeled outside of IPM for oil-fired EGUs of $56 million, and monitoring, reporting, and recordkeeping costs of $158 million.
For this final rule, EPA analyzed the costs using the IPM. The IPM is a dynamic linear programming model that can be used to examine the economic impacts of air pollution control policies for a variety of HAP and other pollutants throughout the contiguous U.S. for the entire power system.
Documentation for IPM can be found in the docket for this rulemaking or at
The EPA performed a screening analysis for impacts on small entities by comparing compliance costs to sales/revenues (
Although a stand-alone analysis of employment impacts is not included in a standard cost-benefit analysis, the current economic climate has led to heightened concerns about potential job impacts. Executive Order 13563 specifically states that our “regulatory system must protect public health, welfare, safety, and our environment while promoting economic growth, innovation, competitiveness, and
Under conditions of full employment, it is conventional to assume that regulations will merely shift jobs from one sector to another, without having a material effect on employment levels. Potential employment effects are of greater concern in the current economic climate, with high levels of employment, because of the risk that displaced workers may not find alternative jobs. In addition, regulations that result in firms hiring workers, in order to ensure compliance, may have a positive effect on employment.
During sustained periods of excess unemployment, the opportunity cost of labor required by regulated sectors to bring their facilities into compliance with an environmental regulation may be lower than it would be during a period of full employment (particularly if regulated industries employ otherwise idled labor to design, fabricate, or install the pollution control equipment required under this final rule). Consistent with EO 13563, the EPA includes estimates of job impacts associated with the final rule. In the electricity sector, the EPA estimates that the net employment effect will range from −15,000 to +30,000 jobs, with a central estimate of +8,000. The EPA also presents an estimate of short-term employment effects as a result of increased demand for pollution control equipment.
The results of this analysis, found in Chapter 6 of the RIA, indicate that the final rule has the potential to provide increases in short-term employment in the environmental industry, primarily driven by the high demand for new pollution control equipment. Overall, the results suggest that the final rule could support a net of roughly 46,000 job years
There are other employment effects that cannot be estimated quantitatively at this time. The employment gains related to the new pollution controls are likely to be tempered by some losses due to certain coal retirements. On the other hand, some of those workers who lose their jobs due to plant retirements could find alternative employment operating the replacement electricity generating equipment or new pollution controls at nearby units. Finally, job losses due to reduced coal demand may be offset by job gains due to increased natural gas demand, potentially resulting in a positive net change in employment due to fuel demand changes.
The basic approach to estimate these employment impacts involved using IPM projections from the final rule analysis, in particular the amount of existing coal-fired capacity that is projected to be retrofit with pollution control technologies. These data, along with data on labor and resource needs of new pollution controls and labor productivity from engineering studies and secondary sources, are used to estimate employment impacts for the pollution control industry in 2015. For more information, please refer to Chapter 6 and appendix 6B in the RIA.
The EPA relied on Morgenstern,
Higher production costs raise market prices, higher prices reduce consumption, and employment within an industry falls (“demand effect”);
Pollution abatement activities require additional labor services to produce the same level of output (“cost effect”); and
Post-regulation production technologies may be more or less labor intensive (i.e., more/less labor is required per dollar of output) (“factor-shift effect”).
Using plant-level Census information between the years 1979 and 1991,
In the directly affected sector, the EPA estimates that the net employment effect will range from −15,000 to +30,000 jobs, with a central estimate of +8,000. The ranges of job effects for the electricity sector, as calculated using the Morgenstern,
The EPA recognizes there may be other job effects that are not considered in the Morgenstern,
a. Human Health and Environmental Effects Due to Exposure to MeHg. In this section, we provide a qualitative description of human health and environmental effects due to exposure to MeHg. The NAS Study (NRC, 2000) provides a thorough review of the effects of MeHg on human health. Many of the peer-reviewed articles cited in this section are publications originally cited in the NAS Study. In addition, the EPA has conducted literature searches to obtain other related and more recent publications to complement the material summarized by the NAS in 2000.
b. Neurologic Effects of Exposure to MeHg. In its review of the literature, the NAS found neurodevelopmental effects to be the most sensitive and best documented endpoints and concluded that they are appropriate for establishing an RfD (NRC, 2000); in particular NAS supported the use of results from neurobehavioral or neuropsychological tests. The NAS Study (NRC, 2000) noted that studies in animals reported sensory effects as well as effects on brain development and memory functions and support the conclusions based on epidemiology studies. The NAS noted that their recommended neurodevelopmental endpoints for an RfD are associated with the ability of children to learn and to succeed in school. They concluded the following: “The population at highest risk is the children of women who consumed large amounts of fish and seafood during pregnancy. The committee concludes that the risk to that population is likely to be sufficient to result in an increase in the number of children who have to struggle to keep up in school.”
c. Cardiovascular Impacts of Exposure to MeHg. The NAS summarized data on cardiovascular effects available up to 2000. Based on these and other studies, the NAS Study concluded that “Although the data base is not as extensive for cardiovascular effects as it is for other end points (
Additional cardiovascular studies have been published since 2000. The EPA did not develop a quantitative dose-response assessment for cardiovascular effects associated with MeHg exposures, as there is no consensus among scientists on the dose-response functions for these effects. In addition, there is inconsistency among available studies as to the association between MeHg exposure and various cardiovascular system effects. The pharmacokinetics of some of the exposure measures (such as toenail Hg levels) are not well understood. The studies have not yet received the review and scrutiny of the more well-established neurotoxicity data base.
d. Genotoxic Effects of Exposure to MeHg. The Mercury Study noted that MeHg is not a potent mutagen but is capable of causing chromosomal damage in a number of experimental systems. The NAS Study indicated that evidence that human exposure to MeHg causes genetic damage is inconclusive; they note that some earlier studies showing chromosomal damage in lymphocytes may not have controlled sufficiently for potential confounders. One study of adults living in the Tapajós River region in Brazil (Amorim
e. Immunotoxic Effects to Exposure to MeHg. Although exposure to some forms of Hg can result in a decrease in immune activity or an autoimmune response (ATSDR, 1999), evidence for immunotoxic effects of MeHg is limited (NRC, 2000).
f. Other Hg-Related Human Toxicity Data. Based on limited human and animal data, MeHg is classified as a “possible” human carcinogen by the International Agency for Research on Cancer (IARC, 1994) and in IRIS (USEPA, 2002). The existing evidence supporting the possibility of carcinogenic effects in humans from low-dose chronic exposures is tenuous. Multiple human epidemiological studies have found no significant association between Hg exposure and overall cancer incidence, although a few studies have shown an association between Hg exposure and specific types of cancer incidence (
Some evidence of reproductive and renal toxicity in humans from MeHg exposure exists. However, overall, human data regarding reproductive, renal, and hematological toxicity from MeHg are very limited and are based on studies of the two high-dose poisoning episodes in Iraq and Japan or animal data, rather than epidemiological studies of chronic exposures at the levels of interest in this analysis.
g. Ecological Effects of Hg. Deposition of Hg to watersheds can also have an impact on ecosystems and wildlife. Mercury contamination is present in all environmental media, with aquatic systems experiencing the greatest exposures due to bioaccumulation. Bioaccumulation refers to the net uptake of a contaminant from all possible pathways and includes the accumulation that may occur by direct exposure to contaminated media as well as uptake from food.
A review of the literature on effects of Hg on fish
Mercury also affects avian species. In previous reports
Recently, attention has turned to other piscivorous species such as the white ibis and great snowy egret. These wading birds have a very wide diet including crayfish, crabs, snails, insects and frogs. White ibis have been observed to have decreased foraging efficiency
Insectivorous birds have also been shown to suffer adverse effects due to Hg exposure. Songbirds such as Bicknell's thrush, tree swallows, and the great tit have shown reduced reproduction, survival, and changes in singing behavior. Exposed tree swallows produced fewer fledglings,
In mammals, adverse effects have been observed in mink and river otter, both fish eating species. For otter from Maine and Vermont, maximum concentrations of Hg in fur nearly equal or exceed a level associated with mortality and concentration in liver for mink in Massachusetts/Connecticut and the levels in fur from mink in Maine exceed concentrations associated with acute mortality.
h. Methodology for Partial Hg Benefits Estimation. The EPA has conducted a national-scale analysis of the benefits to recreational anglers of avoided IQ loss related to reductions of Hg emissions
Data from the 1994 National Survey on Recreation and the Environment (NSRE) were used to approximate the percentage of freshwater fishing trips (and exposed individuals) matched to different distances from anglers' residential location.
To determine an appropriate daily fish consumption rate for the analysis, the EPA conducted an extensive review of existing literature characterizing self-caught freshwater fish consumption. Based on this review, it was decided that the ingestion rates for recreational freshwater fishers, specified as “recommended” in the EPA's “Environmental Exposure Factors Handbook” (EPA, 1997), represented the most appropriate values to use in this analysis.
Estimating the IQ decrements in children that result from mothers' prenatal ingestion of Hg from fish required two steps. First, based on the estimated average daily maternal ingestion rate, the expected Hg concentration in the hair of exposed pregnant women was estimated. Second, to estimate the expected IQ decrement in offspring, the following dose-response relationship was developed based on the summary findings reported in Axelrad
The valuation approach used to assess monetary losses due to IQ decrements is based on an approach applied in previous EPA analyses (EPA, 2008). The approach expresses the potential loss to an affected individual resulting from IQ decrements in terms of foregone future earnings (net of changes in education costs) for that individual.
The estimate for “Present Value of Lifetime Earnings” is derived using earnings and labor force participation rate data from the Bureau of Labor Statistics 2006 Current Population Survey. Estimates of the average effect of a 1-point increase in IQ on lifetime earnings range from a 1.76 percent increase (Schwartz, 1994) to a 2.379 percent increase (Salkever, 1995). The percentage increases in the two studies reflect both the direct impact of IQ on hourly wages and indirect effects on annual earnings as the result of additional schooling and increased labor force participation. The estimate for years of additional schooling is based on Schwartz (1994), who reports an increase of 0.131 years of schooling per IQ point.
In addition to this positive net effect on earnings, an increase in IQ is also assumed to have a positive effect on the amount of time spent in school and on associated costs. To incorporate (1) uncertainty regarding the size of the percentage change in future earnings and (2) different assumptions regarding the discount rate, the resulting value estimates for the average net loss per IQ point decrement are expressed as a range. Assuming a 3 percent discount rate, value IQ ranges from $8,013 (using the Schwartz estimates) to $11,859 (using the Salkever estimates) in increased earnings per year per 1-point IQ increase. With a 7 percent discount rate assumption, the value IQ estimates range from $893 to $1,958 in increased earnings per year per 1-point IQ increase.
The EPA analyzed the aggregate national IQ and present-value loss estimates for two base case and three emission control scenarios. The highest losses are estimated for the 2005 base case. For the population of prenatally exposed children included in the analysis (almost 240,000), Hg exposures under baseline conditions during the year 2005 are estimated to have resulted in more than 25,500 IQ points lost. Assuming a 3 percent discount rate, the present-year value of these losses ranges from $204.8 million to $292.5 million nationally.
For this rule, the EPA generated estimates of aggregate nationwide benefits associated with reductions in Hg exposures and resulting reductions in IQ losses. Most importantly, the benefits of the 2016 MATS scenario (relative to the 2016 base case) are estimated to range between $4 million and $6 million (assuming a 3 percent discount rate), because of an estimated 511 point reduction in IQ losses. The EPA recognizes that these calculated benefits are a small subset of the benefits of reducing Hg emissions.
Emission controls installed to meet the requirements of this rule will generate co-benefits by reducing criteria pollutants including PM
a. Human Health Co-Benefits. To estimate the human health co-benefits of this rule, the EPA used benefit-per-ton
Table 9 presents the estimates of reduced annual incidence of PM
The reduction in premature fatalities each year accounts for between 93 and 97 percent of the estimated health co-benefits that were monetized.
It is important to note that the magnitude of the PM
Every benefit analysis examining the potential effects of a change in environmental protection requirements is limited to some extent by data gaps, 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, or to assign economic values even to those health and environmental outcomes that can be quantified. The uncertainties in the underlying scientific and economics literature (that may result in overestimation or underestimation of the co-benefits) are discussed in detail in the RIA. Despite these uncertainties, we believe the benefit analysis for this rule provides a reasonable indication of the expected health co-benefits of the rulemaking in future years under a set of reasonable assumptions.
When characterizing uncertainty in the PM-mortality relationship, the 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, the EPA's 2009 Integrated Science Assessment 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 rulemaking, rather than segmenting out impacts predicted to be associated with levels above and below a “bright line” threshold, the EPA includes a “lowest measured level” (LML) analysis that illustrates the increasing uncertainty that characterizes exposure attributed to levels of PM
Based on the modeled interim baseline which is approximately equivalent to the final baseline (
It is important to note that the monetized benefits include many but not all health effects associated with PM
b. Non-Climate Welfare Co-Benefits. Emission controls installed to comply with the requirements specified in this rule will also generate co-benefits by improving visibility. We anticipate that improvements in visibility in Class I areas as well as residential areas where people live, work, and recreate could be substantial. Because full-scale air quality modeling was not performed for this rule, we are unable to quantify these visibility co-benefits for this rule. However, the estimated value of visibility benefits calculated from the modeled interim baseline and policy scenario was $1.1 billion (in 2007$). These visibility benefits are not included in the total co-benefits estimate of the final policy scenario used as a basis for this final rule. The distribution of emission reductions did not change substantially in the visibility regions studied, therefore visibility benefits of the final policy scenario are likely to be of a similar magnitude.
Ecosystem and other welfare effects include reduced acidification and, in the case of NO
c. Climate co-benefits. This rule is expected to reduce CO
The SCC estimates used in this analysis were developed through an interagency process that included the EPA and other executive branch entities, and that concluded in February 2010. We first used these SCC estimates in the benefits analysis for the final joint EPA/DOT Rulemaking to establish Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards; see the rule's preamble for discussion about application of the SCC (75 FR 25324; May 7, 2010). The SCC Technical Support Document (SCC TSD) provides a complete discussion of the methods used to develop these SCC estimates.
The interagency group selected four SCC values for use in regulatory analyses, which we have applied in this analysis: $5.9, $24.3, $39, and $74.4 per metric ton of CO
Applying the global SCC estimates using a 3 percent discount rate, we estimate the value of the climate related benefits of this rule in 2016 is $360 million (2007$), as shown in Table 11. See the RIA for more detail on the methodology used to calculate these benefits and additional estimates of climate benefits using different discount rates and the 95th percentile of the 3 percent discount rate SCC. Important limitations and uncertainties of the SCC approach are also described in the RIA.
Our best estimate for the monetized total health and climate co-benefits of this rule in 2016 at a 3 percent discount rate is between $37 billion and $90 billion or between $33 billion and $81 billion (2007$) at a 7 percent discount rate. These estimates account for the quantified health and climate benefits described in Table 11.
Under EO 12866 (58 FR 51735; October 4, 1993), this action is an “economically significant regulatory action” because it is likely to have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or state, local, or tribal governments or communities. Accordingly, the EPA submitted this action to the OMB for review under Executive Orders 12866 and 13563 and any changes in response to OMB recommendations have been documented in the docket for this action. For more information on the costs and benefits for this rule, please refer to Table 2 of this preamble.
When estimating the human health benefits and compliance costs in Table 2 of this preamble, the EPA applied methods and assumptions consistent with the state-of-the-science for human health impact assessment, economics and air quality analysis. The EPA applied its best professional judgment in performing this analysis and believes that these estimates provide a reasonable indication of the expected benefits and costs to the nation of this rulemaking. The RIA available in the docket describes in detail the empirical basis for the EPA's assumptions and characterizes the various sources of uncertainties affecting the estimates below. In doing what is laid out above in this paragraph, the EPA adheres to EO 13563, “Improving Regulation and Regulatory Review,” (76 FR 3821; January 18, 2011), which is a supplement to EO 12866.
In addition to estimating costs and benefits, EO 13563 focuses on the importance of a “regulatory system [that] * * * promote[s] predictability and reduce[s] uncertainty” and that “identify[ies] and use[s] the best, most innovative, and least burdensome tools for achieving regulatory ends.” In addition, EO 13563 states that “[i]n developing regulatory actions and identifying appropriate approaches, each agency shall attempt to promote such coordination, simplification, and harmonization. Each agency shall also seek to identify, as appropriate, means to achieve regulatory goals that are designed to promote innovation.” We recognize that the utility sector faces a variety of requirements, including ones under CAA section 110(a)(2)(D) dealing with the interstate transport of emissions contributing to ozone and PM air quality problems, with coal combustion wastes, and with the implementation of CWA section 316(b). In developing today's final rule, the EPA recognizes that it needs to approach these rulemakings in ways that allow the industry to make practical investment decisions that minimize costs in complying with all of the final rules, while still achieving the fundamentally important environmental and public health benefits that underlie the rulemakings.
A summary of the monetized costs, benefits, and net benefits for the final rule at discount rates of 3 percent and 7 percent is in Table 2 of this preamble. For more information on the analysis, please refer to the RIA for this rulemaking, which is available in the docket.
The information collection requirements in this rule have been submitted for approval to the OMB under the Paperwork Reduction Act, 44
The information collection requirements are not enforceable until OMB approves them. The information requirements are based on notification, recordkeeping, and reporting requirements in the NESHAP General Provisions (40 CFR part 63, subpart A), which are mandatory for all operators subject to national emission standards. These recordkeeping and reporting requirements are specifically authorized by CAA section 114 (42 U.S.C. 7414). All information submitted to the EPA pursuant to the recordkeeping and reporting requirements for which a claim of confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR part 2, subpart B. This final rule requires maintenance inspections of the control devices but would not require any notifications or reports beyond those required by the General Provisions. The recordkeeping requirements require only the specific information needed to determine compliance.
When a malfunction occurs, sources must report them according to the applicable reporting requirements of 40 CFR part 63, subpart UUUUU. An affirmative defense to civil penalties for exceedances of emission limits that are caused by malfunctions is available to a source if it can demonstrate that certain criteria and requirements are satisfied. The criteria ensure that the affirmative defense is available only where the event that causes an exceedance of the emission limit meets the narrow definition of malfunction in 40 CFR 63.2 (sudden, infrequent, not reasonable preventable, and not caused by poor maintenance and or careless operation) and where the source took necessary actions to minimize emissions. In addition, the source must meet certain notification and reporting requirements. For example, the source must prepare a written root cause analysis and submit a written report to the Administrator documenting that it has met the conditions and requirements for assertion of the affirmative defense.
For this rule, EPA is adding affirmative defense to the estimate of burden in the ICR. To provide the public with an estimate of the relative magnitude of the burden associated with an assertion of the affirmative defense position adopted by a source, the EPA has provided administrative adjustments to this ICR that shows what the notification, recordkeeping, and reporting requirements associated with the assertion of the affirmative defense might entail. The EPA's estimate for the required notification, reports, and records, including the root cause analysis, associated with a single incident totals approximately totals $3,141, and is based on the time and effort required of a source to review relevant data, interview plant employees, and document the events surrounding a malfunction that has caused an exceedance of an emission limit. The estimate also includes time to produce and retain the record and reports for submission to EPA. The EPA provides this illustrative estimate of this burden, because these costs are only incurred if there has been a violation, and a source chooses to take advantage of the affirmative defense.
The EPA provides this illustrative estimate of this burden because these costs are only incurred if there has been a violation and a source chooses to take advantage of the affirmative defense. Given the variety of circumstances under which malfunctions could occur, as well as differences among sources' operation and maintenance practices, we cannot reliably predict the severity and frequency of malfunction-related excess emissions events for a particular source. It is important to note that the EPA has no basis currently for estimating the number of malfunctions that would qualify for an affirmative defense. Current historical records would be an inappropriate basis, as source owners or operators previously operated their facilities in recognition that they were exempt from the requirement to comply with emissions standards during malfunctions. Of the number of excess emissions events reported by source operators, only a small number would be expected to result from a malfunction (based on the definition above), and only a subset of excess emissions caused by malfunctions would result in the source choosing to assert the affirmative defense. Thus, we believe the number of instances in which source operators might be expected to avail themselves of the affirmative defense will be extremely small.
For this reason, we estimate no more than two such occurrences for all sources subject to 40 CFR part 63, subpart UUUUU over the 3-year period covered by this ICR. We expect to gather information on such events in the future, and will revise this estimate as better information becomes available.
The annual monitoring, reporting, and record-keeping burden for this collection (averaged over the first 3 years after the effective date of the standards) is estimated to be $207.6 million. This includes 700,296 labor hours per year at a total labor cost of $49.1 million per year, annualized capital costs of $81.9 million, and annual operating and maintenance costs of $76.5 million. This estimate includes initial and annual performance tests, semiannual excess emission reports, developing a monitoring plan, notifications, and recordkeeping. All burden estimates are in 2007 dollars and represent the most cost effective monitoring approach for affected facilities. Burden is defined at 5 CFR 1320.3(b).
An Agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for our regulations 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 today's rule on small entities, small entity is defined as: (1) A small business that is an electric utility producing 4 billion kilowatt-hours or less as defined by NAICS codes 221122 (fossil fuel-fired electric utility steam generating units) and 921150 (fossil fuel-fired electric utility steam generating units in Indian country); (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.
Pursuant to RFA section 603, the EPA prepared an initial regulatory flexibility analysis (IRFA) for the proposed rule and convened a Small Business Advocacy Review Panel to obtain advice
As required by RFA section 604, we also prepared a final regulatory flexibility analysis (FRFA) for the final rule. The FRFA addresses the issues raised by public comments on the IRFA, which was part of the proposal of this rule. The FRFA is summarized below and in the RIA.
In 2000, the EPA made a finding that it was appropriate and necessary to regulate coal- and oil-fired EGUs under CAA section 112 and listed EGUs pursuant to CAA section 112(c). On March 29, 2005 (70 FR 15994), the EPA published a final rule (2005 Action) that removed EGUs from the list of sources for which regulation under CAA section 112 was required. That rule was published in conjunction with a rule requiring reductions in emissions of Hg from EGUs pursuant to CAA section 111, i.e., CAMR, May 18, 2005, 70 FR 28606). The 2005 Action was vacated on February 8, 2008, by the U.S. Court of Appeals for the District of Columbia Circuit. As a result of that vacatur, CAMR was also vacated and EGUs remain on the list of sources that must be regulated under CAA section 112. This action provides the EPA's final NESHAP and NSPS for EGUs.
The MATS will protect air quality and promote public health by reducing emissions of HAP. In the December 2000 regulatory determination, the EPA made a finding that it was appropriate and necessary to regulate EGUs under CAA section 112. The February 2008 vacatur of the 2005 Action reverted the status of the rule to the December 2000 regulatory determination. Section 112(n)(1)(A) of the CAA and the 2000 determination do not differentiate between EGUs located at major versus area sources of HAP. Thus, the NESHAP for EGUs will regulate units at both major and area sources. Major sources of HAP are those that have the potential to emit at least 10 tons per year (tpy) of any one HAP or at least 25 tpy of any combination of HAP. Area sources are any stationary sources of HAP that are not major sources.
The EPA received a number of comments related to the Regulatory Flexibility Act during the public comment process. A consolidated version of the comments received is reproduced below. These comments can also be found in their entirety in the response to comment document in the docket.
The RFA does not require a covered agency to create or assemble information for SERs or for the government panel members. Although CAA section 609(b)(4) requires that the government Panel members review any material the covered agency has prepared in connection with the RFA, the law does not prescribe the materials to be reviewed. The EPA's policy, as reflected in its RFA guidance, is to provide as much information as possible, given time and resource constraints, to enable an informed Panel discussion. In this rulemaking, because of a court-ordered deadline, the EPA was unable to hold a pre-panel meeting but still provided SERs with the information available at the time, held a standard Panel Outreach meeting to collect verbal advice and recommendations from SERs, and provided the standard 14-day written comment period to SERs. The EPA received substantial input from the SERs, and the Panel report describes recommendations made by the Panel on measures the Administrator should consider that would minimize the economic impact of the proposed rule on small entities. The EPA complied with the RFA. In addition, we met with representatives of small businesses, small rural cooperatives, and small governments a number of times during the regulatory development process to discuss their issues and concerns regarding the proposed MATS rule for EGUs.
The EPA disagrees with the comment that recommendations made by the SERs were not considered or discussed in the proposed rulemaking such as recommendations regarding subcategorization and separate GACT standards for area sources. The preamble to the proposed standards includes a detailed discussion of how the EPA determined which subcategories and sources would be regulated (76 FR 25036-25037; May 3, 2011). In that discussion, the EPA explains the rationale for its proposed subcategories based on five unit design types. In addition, the EPA acknowledges the subcategorization suggestions from the SERs and explains its reasons for not subcategorizing on those bases. The preamble to the proposed standards also includes a discussion of the SERs' suggestion that area source EGUs be distinguished from major-source EGUs and the EPA's reasons for not making that distinction (76 FR 25020-25021; May 3, 2011).
The EPA also disagrees with the suggestion that the Agency pursue an extension of the timeline for final rulemaking such that the SBAR Panel can be reconvened and a new IRFA can be prepared and released for public comment prior to the final rulemaking. The EPA entered into a Consent Decree to resolve litigation alleging that the EPA failed to perform a non-discretionary duty to promulgate CAA section 112(d) standards for EGUs.
A detailed description of the changes made to the rule since proposal, including those made as a result of feedback received during the public comment process can be found in sections VI (NESHAP) and X (NSPS) of this preamble. Changes explained in the identified sections include those related to applicability; subcategorization; work practices; periods of startup, shutdown, and malfunction; initial testing and compliance; continuous compliance; and notification, recordkeeping, and reporting.
For the purposes of assessing the impacts of MATS on small entities, a small entity is defined as:
(1) A small business according to the Small Business Administration size standards by the North American Industry Classification System (NAICS) category of the owning entity. The range of small business size standards for electric utilities is 4 billion kilowatt hours (kWh) of production or less;
(2) A small government jurisdiction that is a government of a city, county, town, district, or special district with a population of less than 50,000; and
(3) A small organization that is any not for profit enterprise that is independently owned and operated and is not dominant in its field.
The EPA examined the potential economic impacts to small entities associated with this rulemaking based on assumptions of how the affected entities will install control technologies in compliance with MATS. This analysis does not examine potential indirect economic impacts associated with this rule, such as employment effects in industries providing fuel and pollution control equipment, or the potential effects of electricity price increases on industries and households.
The EPA used Velocity Suite's Ventyx data as a basis for identifying plant ownership and compiling the list of potentially affected small entities. The Ventyx dataset contains detailed ownership and corporate affiliation information. The analysis focused only on those EGUs affected by the rule, which includes units burning coal, oil, petroleum coke, or coal refuse as the primary fuel, and excludes any combustion turbine units or EGUs burning natural gas. Also, because the rule does not affect combustion units with an equivalent electricity generating capacity up to 25 MW, small entities that do not own at least one combustion unit with a capacity greater than 25 MW were removed from the dataset. For the affected units remaining, boiler and generator capacity, heat input, generation, and emissions data were aggregated by owner and then by parent company. Entities with more than 4 billion kWh of annual electricity generation were removed from the list, as were municipal owned entities with a population greater than 50,000. For cooperatives, investor owned utilities, and subdivisions that generate less than 4 billion kWh of electricity annually but which may be part of a large entity, additional research on power sales, operating revenues, and other business activities was performed to make a final determination regarding size. Finally, small entities for which the IPM does not project generation in 2015 in the base case were omitted from the analysis because they are not projected to be operating and, thus, are not projected to face the costs of compliance with the rule. After omitting entities for the reasons above, the EPA identified a total of 82 potentially affected small entities that are affiliated with 102 EGUs.
The number of potentially affected small entities by ownership type and potential impacts of MATS are presented in Chapter 7 of the RIA and summarized here. The EPA estimated the annualized net compliance cost to small entities to be approximately $106 million in 2015 (2007$).
The EPA assessed the economic and financial impacts of the final rule using the ratio of compliance costs to the value of revenues from electricity generation, and our results focus on those entities for which this measure could be greater than 1 percent or 3 percent. Of the 82 small entities identified, The EPA's analysis shows 40 entities may experience compliance costs greater than 1 percent of base generation revenues in 2015, and 35 may experience compliance costs greater than 3 percent of base revenues. Also, all generating capacity at 3 small entities is projected to be uneconomic to maintain. In this analysis, the cost of withdrawing a unit as uneconomic is estimated as the base case profit that is forgone by not operating under the policy case. Because 35 of the 82 total units, or more than 40 percent, are estimated to incur compliance cost greater than 3 percent of base revenues, the EPA has concluded that it cannot certify that there will be no significant economic impact on a substantial number of small entities (SISNOSE) for this rule. Results for small entities discussed here do not account for the reality that electricity markets are regulated in parts of the country. Entities operating in regulated or cost-of-service markets should be able to recover all of their costs of compliance through rate adjustments.
Note that the estimated costs for small entities are significantly lower than those estimated by the EPA for the MATS proposal (which were $379 million). This is driven by a small group of units (less than 6 percent) which were projected to be uneconomic to operate under the proposal (and hence incurred lost profits due to lost electricity revenues), but are now projected to continue their operations under MATS. In addition, the EPA's modeling indicates one unit that would have operated at a low capacity factor under the base case would find it economical to increase its generation significantly under MATS to meet electricity demand in its region. Excluding this unit, the total cost impacts across all entities would be roughly $175 million. Changes in compliance behavior for this small group of units, in particular the one unit which operates at a higher capacity factor, has a substantial impact on total costs as their increased generation revenues offsets a large portion of the compliance costs.
The most significant components of incremental costs to these entities are changes in electricity revenues, followed by the increased capital and operating costs for retrofits. Capital and operating costs increase across all ownership types, but the direction of changes in electricity revenues varies among ownership types. All ownership types, with the exception of private entities, experience a net gain in electricity revenues under the MATS, unlike projections from the EPA's modeling during the proposal, where only municipals benefitted from higher electricity revenues. The change in electricity revenue takes into account both the profit lost from units that do not operate under the policy case and the difference in revenue for operating units under the policy case. According to the EPA's modeling, an estimated 274 MW of capacity owned by small entities are considered uneconomic to operate under the policy case, resulting in a net loss of $13 million (in 2007$) in profits. On the other hand, many operating units actually increase their electricity revenue due to higher electricity prices under MATS. In addition, as mentioned above, the EPA's modeling indicates one unit finds it economical to increase its capacity factor significantly under the policy case which results in significantly higher revenues offsetting the costs.
Consistent with the requirements of the RFA and SBREFA, the EPA has taken steps to minimize the significant economic impact on small entities. Because this rule does not affect units with a generating capacity of less than 25 MW, small entities that do not own at least one generating unit with a capacity greater than 25 MW are not subject to the rule. According to the EPA's analysis, among the coal- and oil-fired EGUs (
For units affected by the proposed rule, the EPA considered a number of comments received, both during the Small Business Advocacy Review (SBAR) Panel and the public comment period. While none of the alternatives adopted is specifically applied to small entities, the EPA believes these modifications will make compliance less onerous for all regulated units, including those owned by small entities.
a. Work practice standards. The EPA proposed numerical emission standards that would apply at all times, including during periods of startup and shutdown. After reviewing comments and other data regarding the nature of these periods of operation, the EPA is finalizing a work practice standard for periods of startup and shutdown. The EPA is also finalizing work practice standards for organic HAP from all subcategories of EGUs. Descriptions of the work practice requirements for startup and shutdown, as well as organic HAP and limited-use liquid oil-fired EGUs, can be found in section VI.D-E. of the preamble.
b. Continuous compliance and notification, record-keeping, and reporting. The final rule greatly simplifies the continuous compliance requirements and provides two basic approaches for most situations: use of continuous monitoring and periodic testing. The frequency of periodic testing has been decreased from monthly in the proposal to quarterly in the final rule. In addition to simplifying compliance, the EPA believes these changes considerably reduce the overall burden associated with recordkeeping and reporting. These changes to the final rule are described in more detail in Section VI.G-H of this preamble.
c. Subcategorization. The Small Entity Representatives on the SBAR Panel were generally supportive of subcategorization and suggested a number of additional subcategories the EPA should consider when developing the final rule. Although it was not consistent with the statute to adopt the proposed subcategories, the EPA maintained the existing subcategories and split the “liquid oil-fired units” subcategory into three subcategories—continental, non-continental units, and limited-use units.
d. MACT floor calculations. As recommended by the EPA SBAR Panel representative, the EPA established the MACT floors using all the available ICR data that was received to the maximum extent possible consistent with the CAA requirements. The Agency believes this approach reasonably ensures that the emission limits selected as the MACT floors adequately represent the level of emissions actually achieved by the average of the units in the top 12 percent, considering operational variability of those units.
e. Alternatives not adopted. The EPA did not adopt several of the suggestions posed either during the SBAR Panel or public comment period. The EPA did not propose a percent reduction standard as an alternative to the concentration-based MACT floor. The percent reduction format for Hg and other HAP emissions would not have addressed the EPA's consideration of coal preparation practices that remove Hg and other HAP before firing. Also, to account for the coal preparation practices, sources would be required to track the HAP concentrations in coal from the mine to the stack, and not just before and after the control device(s), and such an approach would be difficult to implement and enforce. Furthermore, the EPA does not believe the percent reduction standard is in line with the Court's interpretation of the CAA section 112 requirements. Even if we believed it was appropriate to establish a percent reduction standard, we do not have the data necessary to establish percent reduction standards for HAP, as explained further in the response to comments document.
The EPA determined not to establish GACT standards for area sources for a number of reasons. The data show that similar HAP emissions and control technologies are found on both major and area sources greater than 25 MW, and some large units are synthetic area sources. In fact, because of the significant number of well-controlled EGUs of all sizes, we believe it would be difficult to make a distinction between MACT and GACT. Moreover, the EPA believes the standards for area source EGUs should reflect MACT, rather than GACT, because there is no essential difference between area source and major source EGUs with respect to emissions of HAP.
The EPA determined not to exercise its discretionary authority to establish health-based emission standards for HCl and other HAP acid gases. Given the limitations of the currently available information (
As required by SBREFA section 212, the EPA also is preparing a Small Entity Compliance Guide to help small entities comply with this rule. Small entities will be able to obtain a copy of the Small Entity Compliance guide at the following Web site:
Title II of the UMRA of 1995, Public Law 104-4, establishes requirements for federal agencies to assess the effects of their regulatory actions on state, local, and tribal governments and the private sector. Under UMRA section 202, we generally must prepare a written statement, including a cost-benefit analysis, for proposed and final rules with “Federal mandates” that may result in expenditures to state, local, and tribal governments, in the aggregate, or to the private sector, of $100 million or more in any 1 year. Before promulgating a rule for which a written statement is needed, UMRA section 205 generally requires us to identify and consider a reasonable number of regulatory alternatives and adopt the least costly, most cost-effective or least burdensome alternative that achieves the objectives of the rule. The provisions of UMRA section 205 do not apply when they are inconsistent with applicable law. Moreover, UMRA section 205 allows us 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. Before we establish any regulatory requirements that may significantly or uniquely affect small governments, including tribal governments, we must develop a small government agency plan under UMRA section 203. 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 regulatory proposals with significant federal intergovernmental mandates, and informing, educating, and advising small governments on compliance with the regulatory requirements.
We have determined that 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 1 year. Accordingly, we have prepared a written statement entitled “Unfunded Mandates Reform Act Analysis” under
As discussed elsewhere in this preamble, the statutory authority for this rulemaking is CAA section 112. Title III of the CAA Amendments was enacted to reduce nationwide air toxic emissions. CAA section 112(b) lists the 188 chemicals, compounds, or groups of chemicals deemed by Congress to be HAP. These toxic air pollutants are to be regulated by NESHAP.
CAA section 112(d) directs us to develop NESHAP which require existing and new major sources to control emissions of HAP using MACT-based standards. This NESHAP applies to all coal- and oil-fired EGUs.
In compliance with UMRA section 205(a), we identified and considered a reasonable number of regulatory alternatives. Additional information on the costs and environmental impacts of these regulatory alternatives were presented in the RIA for the rulemaking.
The regulatory alternative upon which this rule is based represents the MACT floor for all regulated pollutants for all but one EGU subcategory for all but one regulated pollutant for that subcategory. These MACT floor-based standards represent the least costly and least burdensome alternative. Beyond-the-floor emission limits for Hg are for existing coal-fired EGUs in the subcategory for low rank virgin coal EGUs.
The RIA prepared for this rule including the Agency's assessment of costs and benefits is in the docket.
It is estimated that HAP would be reduced by thousands of tons in 2015, relative to the base case, including reductions in HCl, HF, metallic HAP (including Hg), and several other organic HAP from EGUs. Studies have determined a relationship between exposure to certain of these HAP and the onset of cancer; however, the Agency is unable to provide a monetized estimate of the HAP benefits at this time. In addition, significant reductions in PM
The UMRA requires that we estimate, where accurate estimation is reasonably feasible, future compliance costs imposed by this rule and any disproportionate budgetary effects. Our estimates of the future compliance costs of this rule are discussed previously in this preamble.
The EPA assessed the economic and financial impacts of the rule on government-owned entities using the ratio of compliance costs to the value of revenues from electricity generation, and our results focus on those entities for which this measure could be greater than 1 percent or 3 percent of base revenues. The EPA projects that 42 government entities will have compliance costs greater than 1 percent of base generation revenue in 2016, and 32 may experience compliance costs greater than 3 percent of base revenues. Overall, 6 units owned by government entities are expected to retire. The most significant components of incremental costs to these entities are the increased capital and operating costs, followed by changes in electricity revenues. For more details on these results and the methodology behind their estimation, see the results included in chapter 7 of the RIA.
The UMRA requires that we estimate the effect of this rule on the national economy. To the extent feasible, we must estimate the effect on productivity, economic growth, full employment, creation of productive jobs, and international competitiveness of the U.S. goods and services, if we determine that accurate estimates are reasonably feasible and that such effect is relevant and material.
The nationwide economic impact of this rule is presented in the RIA in the docket. This analysis provides estimates of the effect of this rule on some of the categories mentioned above.
The results of the economic impact analysis are summarized previously in this preamble. The results show that, relative to baseline, there will be an average 3.1 percent increase in electricity price on average nationwide in 2016, with the range of increases from 1.3 percent to 6.3 percent in regions throughout the U.S., and a less than 1 percent increase in natural gas price nationwide in 2016. The roughly 3 percent incremental price effect of this rule is small relative to the changes observed in the absolute levels of electricity prices over the last 50 years, which have ranged from as much as 23 percent lower (in 1969) to as much as 23 percent higher (in 1982) than prices observed in 2010.
The UMRA requires that we describe the extent of the Agency's prior consultation with affected state, local,
Consistent with UMRA section 205, the EPA has identified and considered a reasonable number of regulatory alternatives. Because the potential existed for a significant impact for substantial number of small entities, the EPA convened a SBAR Panel to obtain advice and recommendation of representatives of the small entities that potentially would be subject to the requirements of the rule. As part of that process, the EPA considered several options, which are discussed previously in this preamble. Those options included establishing emission limits, establishing work practice standards, establishing subcategories, and consideration of monitoring options. The regulatory alternative selected is a combination of the options considered and includes provisions regarding a number of the recommendations resulting from the SBAR Panel process as described below (see the Regulatory Flexibility Act discussion in this section of the preamble for more detail).
Under EO 13132, the EPA may not issue an action that has federalism implications, that imposes substantial direct compliance costs, and that is not required by statute, unless the federal government provides the funds necessary to pay the direct compliance costs incurred by state and local governments, or the EPA consults with state and local officials early in the process of developing the final action.
The EPA has concluded that this action may have federalism implications, because it may impose substantial direct compliance costs on state or local governments, and the federal government will not provide the funds necessary to pay those costs. Accordingly, the EPA provides the following federalism summary impact statement as required by section 6(b) of EO 13132.
Based on estimates in the RIA, provided in the docket, the final rule may have federalism implications because the rule may impose approximately $294 million in annual direct compliance costs on an estimated 96 state or local governments. Specifically, we estimate that there are 80 municipalities, 5 states, and 11 political subdivisions (
The EPA consulted with state and local officials in the process of developing the rule to permit them to have meaningful and timely input into its development. The EPA met with 10 national organizations representing state and local elected officials to provide general background on the rule, answer questions, and solicit input. In the final rule, EPA has provided flexibilities that will lower compliance costs for these entities. The EPA also recognizes that municipalities may need a longer compliance timeframe because of required approval processes.
Subject to EO 13175 (65 FR 67249; November 9, 2000) the EPA may not issue a regulation that has tribal implications, that imposes substantial direct compliance costs, and that is not required by statute, unless the federal government provides the funds necessary to pay the direct compliance costs incurred by tribal governments, or the EPA consults with tribal officials early in the process of developing the proposed regulation and develops a tribal summary impact statement. Executive Order 13175 requires the EPA to develop an accountable process to ensure “meaningful and timely input by Tribal officials in the development of regulatory policies that have Tribal implications.”
The EPA has concluded that this action may have tribal implications. The EPA offered consultation with tribal officials early in the regulation development process to permit them an opportunity to have meaningful and timely input. Consultation letters were sent to 584 tribal leaders and provided information regarding the EPA's development of this rule and offered consultation. At the request of the tribes, three consultation meetings were held: December 7, 2010, with the Upper Sioux Community of Minnesota; December 13, 2010, with Moapa Band of Paiutes, Forest County Potawatomi, Standing Rock Sioux Tribal Council, and Fond du Lac Band of Chippewa; January 5, 2011, with the Forest County Potawatomi, and a representative from the National Tribal Air Association (NTAA). In these meetings, the EPA presented the authority under the CAA used to develop these rules and an overview of the industry and the industrial processes that have the potential for regulation. Tribes expressed concerns about the impact of EGUs in Indian country. Specifically, they were concerned about potential Hg deposition and the impact on the water resources of the tribes, with particular concern about the impact on subsistence
In addition to these consultations, the EPA also conducted outreach on this rule through presentations at the National Tribal Forum in Milwaukee, WI; phone calls with the NTAA; and a webinar for tribes on the proposed rule. The EPA specifically requested tribal data that could support the appropriate and necessary analyses and the RIA for this rule. In addition, the EPA held individual consultations with the Navajo Nation on October 12, 2011; as well as the Gila River Indian Community, Ak-Chin Indian Community, and the Hopi Nation on October 14, 2011. These tribes expressed concerns about the impact of the rule on the Navajo Generating Station (NGS), the impact on the cost of the water allotted to the tribes from the Central Arizona Project (CAP), the impact on tribal revenues from the coal mining operations (
The EPA will continue to work with these and other potentially affected tribes as this final rule is implemented.
This final rule is subject to EO 13045 (62 FR 19885; April 23, 1997) because it is an economically significant regulatory action as defined by EO 12866, and EPA believes that the environmental health or safety risk addressed by this action may have a disproportionate effect on children. Accordingly, we have evaluated the environmental health or safety effects of the standards on children.
Although this final rule is based on technology performance, the standards are designed to protect against hazards to public health with an adequate margin of safety as described in Section III of this preamble. The protection offered by this rule is particularly important for children, especially the developing fetus. As referenced in Chapter 4 of the RIA, “Mercury and Other HAP Benefits Analysis,” children are more vulnerable than adults to many HAP emitted by EGUs due to differential behavior patterns and physiology. These unique susceptibilities were carefully considered in a number of different ways in the analyses associated with this rulemaking, and are summarized in the RIA. We also estimate substantial health improvements for children in the form of 130,000 fewer asthma attacks, 3,100 fewer emergency room visits due to asthma, 6,300 fewer cases of acute bronchitis, and approximately 140,000 fewer cases of upper and lower respiratory illness.
Executive Order 13211 (66 FR 28355; May 22, 2001) requires EPA to prepare and submit a Statement of Energy Effects to the Administrator of the Office of Information and Regulatory Affairs, OMB, for actions identified as “significant energy actions.” This action, which is a significant regulatory action under EO 12866, is likely to have a significant adverse effect on the supply, distribution, or use of energy. We have prepared a Statement of Energy Effects for this action as follows.
We estimate a 3.1 percent price increase for electricity nationwide in 2016 and a less than 2 percent percentage fall in coal-fired power production as a result of this rule. The EPA projects that electric power sector-delivered natural gas prices will increase by about 0.6 percent over the 2015 to 2030 timeframe. For more information on the estimated energy effects, please refer to the economic impact analysis for this final rule. The analysis is available in the RIA, which is in the public docket.
Section 12(d) of the National Technology Transfer and Advancement Act (NTTAA) of 1995 (Pub. L. 104-113; 15 U.S.C. 272 note) directs the EPA to use voluntary consensus standards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (
This rulemaking involves technical standards. The EPA cites the following standards in the final rule: EPA Methods 1, 2, 2A, 2C, 2F, 2G, 3A, 3B, 4, 5, 5D, 17, 19, 23, 26, 26A, 29, 30B of 40 CFR part 60 and Method 320 of 40 CFR part 63. Consistent with the NTTAA, the EPA conducted searches to identify voluntary consensus standards in addition to these EPA methods. No applicable voluntary consensus standards were identified for EPA Methods 2F, 2G, 5D, and 19. The search and review results have been documented and are placed in the docket for the proposed rule.
The three voluntary consensus standards described below were identified as acceptable alternatives to EPA test methods for the purposes of the final rule.
The voluntary consensus standard American National Standards Institute (ANSI)/American Society of Mechanical Engineers (ASME) PTC 19-10-1981, “Flue and Exhaust Gas Analyses [part 10, Instruments and Apparatus]” is cited in the final rule for its manual method for measuring the O
The voluntary consensus standard ASTM D6348-03 (Reapproved 2010), “Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform (FTIR) Spectroscopy” is acceptable as an alternative to Method 320 and is cited in the final rule, but with several conditions: (1) The test plan preparation and implementation in the Annexes to ASTM D6348-03, Sections A1 through A8 are mandatory; and (2) In ASTM D6348-03 Annex A5 (Analyte Spiking Technique), the percent (%) R must be determined for each target analyte (Equation A5.5). In order for the test data to be acceptable for a compound, %R must be 70% ≥ R ≤ 130%. If the %R value does not meet this criterion for a target compound, the test data are not acceptable for that compound and the test must be repeated for that analyte (
The voluntary consensus standard ASTM D6784-02, “Standard Test Method for Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro Method),” is an acceptable alternative to use of EPA Method 29 for Hg only or Method 30B for the purpose of conducting relative accuracy tests of Hg continuous monitoring systems under this final rule. Because of the limitations of this method in terms of total sampling volume, it is not appropriate for use in performance testing under this rule. In addition to the voluntary consensus standards the EPA used in the final rule, the search for emissions measurement procedures identified 16 other voluntary consensus standards. The EPA determined that 14 of these 16 standards identified for measuring emissions of the HAP or other pollutants subject to emission standards in the final rule were impractical alternatives to EPA test methods for the purposes of this final rule. Therefore, the EPA did not adopt these standards for this purpose. The reasons for this determination for the 14 methods are discussed below, and the remaining 2 methods are discussed later in this section.
The voluntary consensus standard ASTM D3154-00, “Standard Method for Average Velocity in a Duct (Pitot Tube Method),” is impractical as an alternative to EPA Methods 1, 2, 3B, and 4 for the purposes of this rulemaking because the standard appears to lack in quality control and quality assurance requirements. Specifically, ASTM D3154-00 does not include the following: (1) proof that openings of standard pitot tube have not plugged during the test; (2) if differential pressure gauges other than inclined manometers (
The voluntary consensus standard ASTM D3464-96 (Reapproved 2001), “Standard Test Method Average Velocity in a Duct Using a Thermal Anemometer,” is impractical as an alternative to EPA Method 2 for the purposes of this rule primarily because applicability specifications are not clearly defined,
The voluntary consensus standard ISO 10780:1994, “Stationary Source Emissions—Measurement of Velocity and Volume Flowrate of Gas Streams in Ducts,” is impractical as an alternative to EPA Method 2 in this rule. The standard recommends the use of an L-shaped pitot, which historically has not been recommended by the EPA. The EPA specifies the S-type design which has large openings that are less likely to plug up with dust.
The voluntary consensus standard, CAN/CSA Z223.2-M86 (1999), “Method for the Continuous Measurement of Oxygen, Carbon Dioxide, Carbon Monoxide, Sulphur Dioxide, and Oxides of Nitrogen in Enclosed Combustion Flue Gas Streams,” is unacceptable as a substitute for EPA Method 3A because it does not include quantitative specifications for measurement system performance, most notably the calibration procedures and instrument performance characteristics. The instrument performance characteristics that are provided are non-mandatory and also do not provide the same level of quality assurance as the EPA methods. For example, the zero and span/calibration drift is only checked weekly, whereas the EPA methods require drift checks after each run.
Two very similar voluntary consensus standards, ASTM D5835-95 (Reapproved 2001), “Standard Practice for Sampling Stationary Source Emissions for Automated Determination of Gas Concentration,” and ISO 10396:1993, “Stationary Source Emissions: Sampling for the Automated Determination of Gas Concentrations,” are impractical alternatives to EPA Method 3A for the purposes of this final rule because they lack in detail and quality assurance/quality control requirements. Specifically, these two standards do not include the following: (1) Sensitivity of the method; (2) acceptable levels of analyzer calibration error; (3) acceptable levels of sampling system bias; (4) zero drift and calibration drift limits, time span, and required testing frequency; (5) a method to test the interference response of the analyzer; (6) procedures to determine the minimum sampling time per run and minimum measurement time; and (7) specifications for data recorders, in terms of resolution (all types) and recording intervals (digital and analog recorders, only).
The voluntary consensus standard ISO 12039:2001, “Stationary Source Emissions—Determination of Carbon Monoxide, Carbon Dioxide, and Oxygen—Automated Methods,” is not acceptable as an alternative to EPA Method 3A. This ISO standard is similar to EPA Method 3A, but is missing some key features. In terms of sampling, the hardware required by ISO 12039:2001 does not include a 3-way calibration valve assembly or equivalent to block the sample gas flow while calibration gases are introduced. In its calibration procedures, ISO 12039:2001 only specifies a two-point calibration while EPA Method 3A specifies a three-point calibration. Also, ISO 12039:2001 does not specify performance criteria for calibration error, calibration drift, or sampling system bias tests as in the EPA method, although checks of these quality control features are required by the ISO standard.
The voluntary consensus standard ASTM D6522-00, “Standard Test Method for the Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating Engines, Combustion Turbines, Boilers and Process Heaters Using Portable Analyzers” is not an acceptable alternative to EPA Method 3A for measuring CO and O
The voluntary consensus standard ASME PTC-38-80 R85 (1985), “Determination of the Concentration of Particulate Matter in Gas Streams,” is not acceptable as an alternative for EPA Method 5 because ASTM PTC-38-80 is not specific about equipment requirements, and instead presents the options available and the pros and cons of each option. The key specific differences between ASME PTC-38-80 and the EPA methods are that the ASME standard: (1) Allows in-stack filter placement as compared to the out-of-stack filter placement in EPA Methods 5 and 17; (2) allows many different types of nozzles, pitots, and filtering equipment; (3) does not specify a filter weighing protocol or a minimum allowable filter weight fluctuation as in the EPA methods; and (4) allows filter paper to be only 99 percent efficient, as compared to the 99.95 percent efficiency required by the EPA methods.
The voluntary consensus standard ASTM D3685/D3685M-98, “Test Methods for Sampling and Determination of Particulate Matter in Stack Gases,” is similar to EPA Methods 5 and 17, but is lacking in the following areas that are needed to produce quality, representative particulate data: (1) Requirement that the filter holder temperature should be between 120°C and 134°C, and not just “above the acid dew-point”; (2) detailed specifications
The voluntary consensus standard ISO 9096:1992, “Determination of Concentration and Mass Flow Rate of Particulate Matter in Gas Carrying Ducts—Manual Gravimetric Method,” is not acceptable as an alternative for EPA Method 5. Although sections of ISO 9096 incorporate EPA Methods 1, 2, and 5 to some degree, this ISO standard is not equivalent to EPA Method 5 for collection of PM. The standard ISO 9096 does not provide applicable technical guidance for performing many of the integral procedures specified in Methods 1, 2, and 5. Major performance and operational details are lacking or nonexistent, and detailed quality assurance/quality control guidance for the sampling operations required to produce quality, representative particulate data (
The voluntary consensus standard CAN/CSA Z223.1-M1977, “Method for the Determination of Particulate Mass Flows in Enclosed Gas Streams,” is not acceptable as an alternative for EPA Method 5. Detailed technical procedures and quality control measures that are required in EPA Methods 1, 2, 3, and 4 are not included in CAN/CSA Z223.1. Second, CAN/CSA Z223.1 does not include the EPA Method 5 filter weighing requirement to repeat weighing every 6 hours until a constant weight is achieved. Third, EPA Method 5 requires the filter weight to be reported to the nearest 0.1 milligram (mg), while CAN/CSA Z223.1 requires reporting only to the nearest 0.5 mg. Also, CAN/CSA Z223.1 allows the use of a standard pitot for velocity measurement when plugging of the tube opening is not expected to be a problem. The EPA Method 5 requires an S-shaped pitot.
The voluntary consensus standard EN 1911-1,2,3 (1998), “Stationary Source Emissions-Manual Method of Determination of HCl-Part 1: Sampling of Gases Ratified European Text-Part 2: Gaseous Compounds Absorption Ratified European Text-Part 3: Adsorption Solutions Analysis and Calculation Ratified European Text,” is impractical as an alternative to EPA Methods 26 and 26A. Part 3 of this standard cannot be considered equivalent to EPA Method 26 or 26A because the sample absorbing solution (water) would be expected to capture both HCl and chlorine gas, if present, without the ability to distinguish between the two. The EPA Methods 26 and 26A use an acidified absorbing solution to first separate HCl and chlorine gas so that they can be selectively absorbed, analyzed, and reported separately. In addition, in EN 1911 the absorption efficiency for chlorine gas would be expected to vary as the pH of the water changed during sampling.
The voluntary consensus standard EN 13211 (1998), is not acceptable as an alternative to the Hg portion of EPA Method 29 primarily because it is not validated for use with impingers, as in the EPA method, although the method describes procedures for the use of impingers. This European standard is validated for the use of fritted bubblers only and requires the use of a side (split) stream arrangement for isokinetic sampling because of the low sampling rate of the bubblers (up to 3 liters per minute, maximum). Also, only two bubblers (or impingers) are required by EN 13211, whereas EPA Method 29 require the use of six impingers. In addition, EN 13211 does not include many of the quality control procedures of EPA Method 29, especially for the use and calibration of temperature sensors and controllers, sampling train assembly and disassembly, and filter weighing.
Two of the 16 voluntary consensus standards identified in this search were not available at the time the review was conducted for the purposes of the final rule because they are under development by a voluntary consensus body: ASME/BSR MFC 13M, “Flow Measurement by Velocity Traverse,” for EPA Method 2 (and possibly 1); and ASME/BSR MFC 12M, “Flow in Closed Conduits Using Multiport Averaging Pitot Primary Flowmeters,” for EPA Method 2.
Finally, in addition to the three voluntary consensus standards identified as acceptable alternatives to EPA methods required in the final rule, the EPA is also specifying four voluntary consensus standards in the rule for use in sampling and analysis of liquid oil samples for moisture content. These standards are: ASTM D95-05 (Reapproved 2010), “Standard Test Method for Water in Petroleum Products and Bituminous Materials by Distillation,” ASTM D4006-11, “Standard Test Method for Water in Crude Oil by Distillation,” ASTM D4177-95 (Reapproved 2010), “Standard Practice for Automatic Sampling of Petroleum and Petroleum Products,” and ASTM D4057-06 (Reapproved 2011), “Standard Practice for Manual Sampling of Petroleum and Petroleum Products.”
Table 5, section 4.1.1.5 of appendix A, and section 3.1.2 of appendix B to subpart UUUUU, 40 CFR part 63, list the EPA testing methods included in the final rule. Under section 63.7(f) and section 63.8(f) of subpart A of the General Provisions, a source may apply to the EPA for permission to use alternative test methods or alternative monitoring requirements in place of any of the EPA testing methods, performance specifications, or procedures specified.
Executive Order 12898 (59 FR 7629; February 16, 1994) establishes federal executive policy on environmental justice (EJ). Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make EJ part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in the U.S.
The EPA has determined that this final rule will not have disproportionately high and adverse human health or environmental effects on minority, low income, and indigenous populations because it increases the level of environmental protection for all affected populations without having any disproportionately
This final rule establishes national emission standards for new and existing EGUs that combust coal and oil. The EPA estimates that there are approximately 1,400 units located at 600 facilities covered by this final rule.
This final rule will reduce emissions of all the listed HAP that come from EGUs. This includes metals (Hg, As, Be, Cd, Cr, Pb, Mn, Ni, and Se), organics (POM, acetaldehyde, acrolein, benzene, dioxins, ethylene dichloride, formaldehyde, and PCB), and acid gases (HCl and HF). At sufficient levels of exposure, these pollutants can cause a range of health effects including cancer; irritation of the lungs, skin, and mucous membranes; effects on the central nervous system such as memory and IQ loss and learning disabilities; damage to the kidneys; and other acute health disorders.
The final rule will also result in substantial reductions of criteria pollutants such as CO, PM, and SO
This final rule is one of a group of regulatory actions that the EPA has taken and will take over the next several years to respond to statutory and judicial mandates that will reduce exposure to HAP and PM
This is an air toxics rule; therefore, it does not permit emissions trading among sources. Instead, this final rule will place a limit on the rates of Hg and other HAP emitted from each affected EGU. As a result, emissions of Hg and other HAP such as HCl will be substantially reduced in the vast majority of states. In some states, however, there may be small increases in Hg and other HAP emissions due to shifts in electricity generation from EGUs with higher emission rates to EGUs with already low emission rates. Hydrogen chloride emissions are projected to increase at a small number of sources but that does not lead to any increased emissions at the state level.
The primary risk analysis to support the finding that this final rule is both appropriate and necessary includes an analysis of the effects of Hg from EGUs on people who rely on freshwater fish they catch as a regular and frequent part of their diet. These groups are characterized as subsistence level fishing populations or fishers. A significant portion of the data in this analysis came from published studies of EJ communities where people frequently consume locally-caught freshwater fish. These communities included: (1) White and black populations (including female and poor strata) surveyed in South Carolina; (2) Hispanic, Vietnamese and Laotian populations surveyed in California; and (3) Great Lakes tribal populations (Chippewa and Ojibwe) active on ceded territories around the Great Lakes. These data were used to help estimate risks to similar populations beyond the areas where the study data were collected. For example, while the Vietnamese and Laotian survey data were collected in California, given the ethnic (heritage) nature of these high fish consumption rates, we assumed that they could also be associated with members of these ethnic groups living elsewhere in the U.S. Therefore, the high-end consumption rates referenced in the California study for these ethnic groups were used to model risk at watersheds elsewhere in the U.S. As a result of this approach, the specific fish consumption patterns of several different EJ groups are fundamental to the EPA's assessment of both the underlying risks that make this final rule appropriate and necessary, and of the analysis of the benefits of reducing exposure to Hg and the other HAP.
The EPA's full analysis of risks from consumption of Hg-contaminated fish is contained in the RIA for this rule. The effects of this final rule on the health risks from Hg and other HAP are presented in the preamble and in the RIA for this rule.
The EPA has conducted several analyses that provide additional insight on the potential effects of this rule on EJ communities. These include: (1) The socio-economic distribution of people living close to affected EGUs who may be exposed to pollution from these sources; and (2) an analysis of the distribution of health effects expected from the reductions in PM
a. Socio-Economic Distribution. As part of the analysis for this final rule, the EPA reviewed the aggregate demographic makeup of the communities near EGUs covered by this final rule. Although this analysis gives some indication of populations that may be exposed to levels of pollution that cause concern, it does not identify the demographic characteristics of the most highly affected individuals or communities. Electric generating units usually have very tall emission stacks; this tends to disperse the pollutants emitted from these stacks fairly far from the source. In addition, several of the pollutants emitted by these sources, such as a common form of Hg and SO
The proximity-to-the-source review is included in the analysis for this final rule because some EGUs emit enough HAP such as Ni or Cr(VI) to cause elevated lifetime cancer risks greater than 1 in a million in nearby communities. In addition, the EPA's analysis indicates that there are localized areas with potential for elevated levels of Hg deposition around most U.S. EGUs.
The analysis of demographic data used proximity-to-the-source as a surrogate for exposure to identify those populations considered to be living near affected sources, such that they have notable exposures to current HAP
In determining the aggregate demographic makeup of the communities near affected sources, the EPA focused on those census blocks within three miles of affected sources and determined the demographic composition (
The data indicate that coal-fired EGUs are located in areas where the minority share of the population living within a three mile buffer is higher than the national average by 12 percentage points or 48 percent. For these same areas, the percent of the population below the poverty line is also higher than the national average by 4 percentage points or 31 percent. These results are presented in more detail in the “Review of Proximity Analysis,” February 2011, a copy of which is available in the docket.
b. PM
We estimate that in 2016 the annual PM-related benefits of the final rule for adults include approximately 4,200 to 11,000 fewer premature mortalities, 2,900 fewer cases of chronic bronchitis, 4,800 fewer non-fatal heart attacks, 2,600 fewer hospitalizations (for respiratory and cardiovascular disease combined), 3.2 million fewer days of restricted activity due to respiratory illness and approximately 540,000 fewer lost work days. As described in EO 13045, Protection of Children from Environmental Health Risks and Safety Risks, we also estimate substantial health improvements for children.
We also examined the PM
In 2005, people living in the highest risk counties and in the poorest counties had a substantially higher risk of PM
Our analysis demonstrates that this final rule will significantly reduce the PM
The EPA estimates that the benefits of the final rule are distributed among races, income levels, and levels of education fairly evenly. However, the analysis does indicate that this final rule in conjunction with the implementation of existing or final rules (
These results are presented in more detail in Section 7.11 of the RIA.
The EPA defines “environmental justice” to include meaningful involvement of all people regardless of race, color, national origin, or income with respect to the development, implementation, and enforcement of environmental laws, regulations, and policies. To promote meaningful involvement, the EPA publicized the rulemaking via newsletters, EJ listserves, and the internet, including the Office of Policy's (OP) Rulemaking Gateway Web site (
There will continue to be opportunities for public notice and comment as the utilities move forward with implementation of this rule. Once the rule is finalized, affected EGUs will need to update their Title V operating permits to reflect their new emission limits, any other new applicable requirements, and the associated monitoring and recordkeeping from this rule. The Title V permitting process provides that when most permits are reopened (for example, to incorporate new applicable requirements) or renewed, there must be opportunity for public review and comments. In addition, after the public review process, the EPA has an opportunity to review the proposed permit and object to its issuance if it does not meet CAA requirements.
In addition to the previously described assessment of EJ impacts, the EPA conducted an analysis of sub-populations with particularly high potential risks of Hg exposure due to high rates of fish consumption. These populations overlap in many cases with traditional EJ populations and would benefit from Hg reductions resulting from this rule. The EPA also conducted an analysis of the distribution of PM
This final rule strictly limits the emissions rate of Hg and other HAP from every affected EGU. The EPA's analysis indicates substantial health benefits, including for minority, low income, and indigenous populations, from reductions in PM
The EPA's analysis also indicates reductions in risks for individuals, including for members of minority populations, who eat fish frequently from U.S. lakes and rivers and who live near affected sources. Based on all the available information, the EPA has determined that this final rule will not have disproportionately high and adverse human health or environmental effects on minority, low income, and indigenous populations. The EPA is providing multiple opportunities for EJ communities to both learn about and comment on this rule and welcomes their participation as implementation of the rule proceeds.
The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the Small Business Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a copy of the rule, to each House of the Congress and to the Comptroller General of the U.S. The EPA will submit a report containing this rule and other required information to the U.S. Senate, the U.S. House of Representatives, and the Comptroller General of the U.S. prior to publication of the rule in the
Environmental protection, Administrative practice and procedure, Air pollution control, Incorporation by reference, Intergovernmental relations, Reporting and recordkeeping requirements.
Environmental protection, Administrative practice and procedure, Air pollution control, Hazardous substances, Incorporation by reference, Intergovernmental relations, Reporting and recordkeeping requirements.
For the reasons stated in the preamble, title 40, chapter I, of the Code of the Federal Regulations is amended as follows:
42 U.S.C. 7401
(a) * * *
(54) ASTM D3699-08, Standard Specification for Kerosine, including Appendix X1, approved September 1, 2008, IBR approved for §§ 60.41b of subpart Db of this part and 60.41c of subpart Dc of this part.
(90) ASTM D6751-11b, Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels, including Appendices X1 through X3, approved July 15, 2011, IBR approved for §§ 60.41b of subpart Db of this part and 60.41c of subpart Dc of this part.
(93) ASTM D7467-10, Standard Specification for Diesel Fuel Oil, Biodiesel Blend (B6 to B20), including Appendices X1 through X3, approved August 1, 2010, IBR approved for §§ 60.41b of subpart Db of this part and 60.41c of subpart Dc of this part.
(a)
(f)
(b) * * *
(1) Emission standards shall either be based on an allowance system or prescribe allowable rates of emissions except when it is clearly impracticable. Such cases will be identified in the guideline documents issued under § 60.22. Where emission standards prescribing equipment specifications are established, the plan shall, to the degree possible, set forth the emission reductions achievable by implementation of such specifications, and may permit compliance by the use of equipment determined by the State to be equivalent to that prescribed.
(e) Any facility subject to either subpart Da or KKKK of this part is not subject to this subpart.
(a) Except as provided under paragraphs (b), (c), (d), and (e) of this section, on and after the date on which the performance test required to be conducted by § 60.8 is completed, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility any gases that:
(d) An owner or operator of an affected facility that combusts only natural gas is exempt from the PM and opacity standards specified in paragraph (a) of this section.
(e) An owner or operator of an affected facility that combusts only gaseous or liquid fossil fuel (excluding residual oil) with potential SO
(a) Each owner or operator of an affected facility subject to the applicable emissions standard shall install, calibrate, maintain, and operate continuous opacity monitoring system (COMS) for measuring opacity and a continuous emissions monitoring system (CEMS) for measuring SO
(b) Certain of the CEMS and COMS requirements under paragraph (a) of this section do not apply to owners or operators under the following conditions:
(1) For a fossil-fuel-fired steam generator that combusts only gaseous or liquid fossil fuel (excluding residual oil)
(2) For a fossil-fuel-fired steam generator that does not use a flue gas desulfurization device, a CEMS for measuring SO
(3) Notwithstanding § 60.13(b), installation of a CEMS for NO
(4) If an owner or operator is not required to and elects not to install any CEMS for either SO
(5) For affected facilities using a PM CEMS, a bag leak detection system to monitor the performance of a fabric filter (baghouse) according to the most current requirements in § 60.48Da of this part, or an ESP predictive model to monitor the performance of the ESP developed in accordance and operated according to the most current requirements in section § 60.48Da of this part a COMS is not required.
(6) A COMS for measuring the opacity of emissions is not required for an affected facility that does not use post-combustion technology (except a wet scrubber) for reducing PM, SO
(7) * * *
(i) * * *
(A) If no visible emissions are observed, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 12 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later;
(B) If visible emissions are observed but the maximum 6-minute average opacity is less than or equal to 5 percent, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 6 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later;
(C) If the maximum 6-minute average opacity is greater than 5 percent but less than or equal to 10 percent, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 3 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later; or
(ii) * * *
(B) If no visible emissions are observed for 10 operating days during which an opacity standard is applicable, observations can be reduced to once every 7 operating days during which an opacity standard is applicable. If any visible emissions are observed, daily observations shall be resumed.
(8) A COMS for measuring the opacity of emissions is not required for an affected facility at which the owner or operator installs, calibrates, operates, and maintains a particulate matter continuous parametric monitoring system (PM CPMS) according to the requirements specified in subpart UUUUU of part 63.
(b) * * *
(1) The IGCC electric utility steam generating unit is capable of combusting more than 73 MW (250 MMBtu/h) heat input of fossil fuel (either alone or in combination with any other fuel) in the combustion turbine engine and associated heat recovery steam generator; and
(e) Applicability of this subpart to an electric utility combined cycle gas turbine other than an IGCC electric utility steam generating unit is as specified in paragraphs (e)(1) through (3) of this section.
(1) Affected facilities (
(2) For heat recovery steam generators use with duct burners subject to this subpart, only emissions resulting from the combustion of fuels in the steam generating unit (
(3) Any affected facility that meets the applicability requirements and is subject to subpart Eb or subpart CCCC of this part is not subject to the emission standards under subpart Da.
(1) For facilities constructed, reconstructed, or modified before May 4, 2011, the gross electrical or mechanical output from the affected facility plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit (
(2) For facilities constructed, reconstructed, or modified after May 3, 2011, the gross electrical or mechanical output from the affected facility minus any electricity used to power the feedwater pumps and any associated gas compressors (air separation unit main compressor, oxygen compressor, and nitrogen compressor) plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit (
(3) For combined heat and power facilities constructed, reconstructed, or modified after May 3, 2011, the gross electrical or mechanical output from the affected facility divided by 0.95 minus any electricity used to power the feedwater pumps and any associated gas compressors (air separation unit main compressor, oxygen compressor, and nitrogen compressor) plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit (
(4) For a IGCC electric utility generating unit that coproduces chemicals constructed, reconstructed, or modified after May 3, 2011, the gross useful work performed is the gross electrical or mechanical output from the unit minus electricity used to power the feedwater pumps and any associated gas compressors (air separation unit main compressor, oxygen compressor, and nitrogen compressor) that are associated with power production plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit (
(a) Except as provided in paragraph (f) of this section, on and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, an owner or operator of an affected facility shall not cause to be discharged into the atmosphere from any affected facility for which construction, reconstruction, or modification commenced before March 1, 2005, any gases that contain PM in excess of 13 ng/J (0.030 lb/MMBtu) heat input.
(b) Except as provided in paragraphs (b)(1) and (b)(2) of this section, on and after the date the initial PM performance test is completed or required to be completed under § 60.8, whichever date comes first, an owner or operator of an affected facility shall not cause to be discharged into the atmosphere any gases which exhibit greater than 20 percent opacity (6-minute average), except for one 6-minute period per hour of not more than 27 percent opacity.
(1) An owner or operator of an affected facility that elects to install, calibrate, maintain, and operate a continuous emissions monitoring system (CEMS) for measuring PM emissions according to the requirements of this subpart is exempt from the opacity standard specified in this paragraph (b) of this section.
(2) An owner or operator of an affected facility that combusts only natural gas is exempt from the opacity standard specified in paragraph (b) of this section.
(c) Except as provided in paragraphs (d) and (f) of this section, on and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification after February 28, 2005, but before May 4, 2011, shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of either:
(1) 18 ng/J (0.14 lb/MWh) gross energy output; or
(2) 6.4 ng/J (0.015 lb/MMBtu) heat input derived from the combustion of solid, liquid, or gaseous fuel.
(d) As an alternative to meeting the requirements of paragraph (c) of this section, the owner or operator of an affected facility for which construction, reconstruction, or modification commenced after February 28, 2005, but before May 4, 2011, may elect to meet the requirements of this paragraph. On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of:
(1) 13 ng/J (0.030 lb/MMBtu) heat input derived from the combustion of solid, liquid, or gaseous fuel, and
(2) For an affected facility that commenced construction or reconstruction, 0.1 percent of the combustion concentration determined according to the procedure in § 60.48Da(o)(5) (99.9 percent reduction) when combusting solid, liquid, or gaseous fuel, or
(3) For an affected facility that commenced modification, 0.2 percent of the combustion concentration determined according to the procedure in § 60.48Da(o)(5) (99.8 percent reduction) when combusting solid, liquid, or gaseous fuel.
(e) Except as provided in paragraph (f) of this section, the owner or operator of an affected facility that commenced construction, reconstruction, or modification commenced after May 3, 2011, shall meet the requirements specified in paragraphs (e)(1) and (2) of this section.
(1) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator shall cause to be discharged into the atmosphere from that affected facility at all times except during periods of startup and shutdown, any gases that contain PM in excess of the applicable emissions limit specified in paragraphs (e)(1)(i) or (ii) of this section.
(i) For an affected facility which commenced construction or reconstruction, any gases that contain PM in excess of either:
(A) 11 ng/J (0.090 lb/MWh) gross energy output; or
(B) 12 ng/J (0.097 lb/MWh) net energy output.
(ii) For an affected facility which commenced modification, any gases that contain PM in excess of 13 ng/J (0.015 lb/MMBtu) heat input.
(2) During periods of startup and shutdown, the owner or operator shall meet the work practice standards specified in Table 3 to subpart UUUUU of part 63.
(f) An owner or operator of an affected facility that meets the conditions in either paragraphs (f)(1) or (2) of this section is exempt from the PM emissions limits in this section.
(1) The affected facility combusts only gaseous or liquid fuels (excluding residual oil) with potential SO
(2) The affected facility is operated under a PM commercial demonstration permit issued by the Administrator according to the provisions of § 60.47Da.
(a) * * *
(1) 520 ng/J (1.20 lb/MMBtu) heat input and 10 percent of the potential combustion concentration (90 percent reduction);
(2) 30 percent of the potential combustion concentration (70 percent
(3) 180 ng/J (1.4 lb/MWh) gross energy output; or
(4) 65 ng/J (0.15 lb/MMBtu) heat input.
(f) The SO
(i) Except as provided in paragraphs (j) and (k) of this section, on and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility for which construction, reconstruction, or modification commenced after February 28, 2005, but before May 4, 2011, shall cause to be discharged into the atmosphere from that affected facility, any gases that contain SO
(1) For an affected facility which commenced construction, any gases that contain SO
(i) 180 ng/J (1.4 lb/MWh) gross energy output; or
(ii) 5 percent of the potential combustion concentration (95 percent reduction).
(2) For an affected facility which commenced reconstruction, any gases that contain SO
(i) 180 ng/J (1.4 lb/MWh) gross energy output;
(ii) 65 ng/J (0.15 lb/MMBtu) heat input; or
(iii) 5 percent of the potential combustion concentration (95 percent reduction).
(3) For an affected facility which commenced modification, any gases that contain SO
(i) 180 ng/J (1.4 lb/MWh) gross energy output;
(ii) 65 ng/J (0.15 lb/MMBtu) heat input; or
(iii) 10 percent of the potential combustion concentration (90 percent reduction).
(k) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility located in a noncontinental area for which construction, reconstruction, or modification commenced after February 28, 2005, but before May 4, 2011, shall cause to be discharged into the atmosphere from that affected facility any gases that contain SO
(1) For an affected facility that burns solid or solid-derived fuel, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain SO
(2) For an affected facility that burns other than solid or solid-derived fuel, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain SO
(l) Except as provided in paragraphs (j) and (m) of this section, on and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility for which construction, reconstruction, or modification commenced after May 3, 2011, shall cause to be discharged into the atmosphere from that affected facility, any gases that contain SO
(1) For an affected facility which commenced construction or reconstruction, any gases that contain SO
(i) 130 ng/J (1.0 lb/MWh) gross energy output; or
(ii) 140 ng/J (1.2 lb/MWh) net energy output; or
(iii) 3 percent of the potential combustion concentration (97 percent reduction).
(2) For an affected facility which commenced modification, any gases that contain SO
(i) 180 ng/J (1.4 lb/MWh) gross energy output; or
(ii) 10 percent of the potential combustion concentration (90 percent reduction).
(m) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility located in a noncontinental area for which construction, reconstruction, or modification commenced after May 3, 2011, shall cause to be discharged into the atmosphere from that affected facility any gases that contain SO
(1) For an affected facility that burns solid or solid-derived fuel, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain SO
(2) For an affected facility that burns other than solid or solid-derived fuel, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain SO
(a) Except as provided in paragraph (h) of this section, on and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility for which construction, reconstruction, or modification commenced before July 10, 1997 any gases that contain NO
(1) The owner or operator shall not cause to be discharged into the atmosphere any gases that contain NO
(2) When two or more fuels are combusted simultaneously in an affected facility, the applicable emissions limit (E
(b) [Reserved]
(c) [Reserved]
(d) Except as provided in paragraph (h) of this section, on and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification after July 9, 1997, but before March 1, 2005, shall cause to be discharged into the atmosphere from that affected facility any gases that contain NO
(1) For an affected facility which commenced construction, any gases that contain NO
(2) For an affected facility which commenced reconstruction, any gases that contain NO
(e) Except as provided in paragraphs (f) and (h) of this section, on and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification after February 28, 2005 but before May 4, 2011, shall cause to be discharged into the atmosphere from that affected facility any gases that contain NO
(1) For an affected facility which commenced construction, any gases that contain NO
(2) For an affected facility which commenced reconstruction, any gases that contain NO
(i) 130 ng/J (1.0 lb/MWh) gross energy output; or
(ii) 47 ng/J (0.11 lb/MMBtu) heat input.
(3) For an affected facility which commenced modification, any gases that contain NO
(i) 180 ng/J (1.4 lb/MWh) gross energy output; or
(ii) 65 ng/J (0.15 lb/MMBtu) heat input.
(f) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, the owner or operator of an IGCC electric utility steam generating unit subject to the provisions of this subpart and for which construction, reconstruction, or modification commenced after February 28, 2005 but before May 4, 2011, shall meet the requirements specified in paragraphs (f)(1) through (3) of this section.
(1) Except as provided for in paragraphs (f)(2) and (3) of this section, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain NO
(2) When burning liquid fuel exclusively or in combination with solid-derived fuel such that the liquid fuel contributes 50 percent or more of the total heat input to the combined cycle combustion turbine, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain NO
(3) In cases when during a 30-boiler operating day rolling average compliance period liquid fuel is burned in such a manner to meet the conditions in paragraph (f)(2) of this section for only a portion of the clock hours in the
(g) Except as provided in paragraphs (h) of this section and § 60.45Da, on and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification after May 3, 2011, shall cause to be discharged into the atmosphere from that affected facility any gases that contain NO
(1) For an affected facility which commenced construction or reconstruction, any gases that contain NO
(i) 88 ng/J (0.70 lb/MWh) gross energy output; or
(ii) 95 ng/J (0.76 lb/MWh) net energy output.
(2) For an affected facility which commenced construction or reconstruction and that burns 75 percent or more coal refuse (by heat input) on a 12-month rolling average basis, any gases that contain NO
(i) 110 ng/J (0.85 lb/MWh) gross energy output; or
(ii) 120 ng/J (0.92 lb/MWh) net energy output.
(3) For an affected facility which commenced modification, any gases that contain NO
(h) The NO
(a) The owner or operator of an affected facility that commenced construction, reconstruction, or modification after May 3, 2011 as alternate to meeting the applicable NO
(b) On and after the date on which the initial performance test is completed or required to be completed under § 60.8 no owner or operator of an affected facility that commenced construction, reconstruction, or modification after May 3, 2011, shall cause to be discharged into the atmosphere from that affected facility any gases that contain NO
(1) For an affected facility which commenced construction or reconstruction, any gases that contain NO
(i) 140 ng/J (1.1 lb/MWh) gross energy output; or
(ii) 150 ng/J (1.2 lb/MWh) net energy output.
(2) For an affected facility which commenced construction or reconstruction and that burns 75 percent or more coal refuse (by heat input) on a 12-month rolling average basis, any gases that contain NO
(i) 160 ng/J (1.3 lb/MWh) gross energy output; or
(ii) 170 ng/J (1.4 lb/MWh) net energy output.
(3) For an affected facility which commenced modification, any gases that contain NO
(c) An owner or operator of an affected facility that uses fluidized bed combustion (atmospheric or pressurized) and who is issued a commercial demonstration permit by the Administrator is not subject to the SO
(f) An owner or operator of an affected facility that uses a pressurized fluidized bed or a multi-pollutant emissions controls system who is issued a commercial demonstration permit by the Administrator is not subject to the total PM emission reduction requirements under § 60.42Da but must, as a minimum, reduce PM emissions to less than 6.4 ng/J (0.015 lb/MMBtu) heat input.
(g) An owner or operator of an affected facility that uses a pressurized fluidized bed or a multi-pollutant emissions controls system who is issued a commercial demonstration permit by the Administrator is not subject to the SO
(h) An owner or operator of an affected facility that uses a pressurized fluidized bed or a multi-pollutant emissions control system or advanced combustion controls who is issued a commercial demonstration permit by the Administrator is not subject to the NO
(i) Commercial demonstration permits may not exceed the following equivalent MW electrical generation capacity for any one technology category listed in the following table.
(a) For affected facilities for which construction, modification, or reconstruction commenced before May 4, 2011, the applicable PM emissions limit and opacity standard under § 60.42Da, SO
(b) After the initial performance test required under § 60.8, compliance with the applicable SO
(c) For the initial performance test required under § 60.8, compliance with the applicable SO
(d) For affected facilities for which construction, modification, or reconstruction commenced before May 4, 2011, compliance with applicable 30-boiler operating day rolling average SO
(e) For affected facilities for which construction, modification, or reconstruction commenced before May 4, 2011, compliance with applicable SO
(f) For affected facilities for which construction, modification, or reconstruction commenced before May 4, 2011, compliance with applicable daily average PM emissions limits is determined by calculating the arithmetic average of all hourly emission rates for PM each boiler operating day, except for data obtained during startup, shutdown, and malfunction. Daily averages are only calculated for boiler operating days that have non-out-of-control data for at least 18 hours of unit operation during which the standard applies. Instead, all of the non-out-of-control hourly emission rates of the operating day(s) not meeting the minimum 18 hours non-out-of-control data daily average requirement are averaged with all of the non-out-of-control hourly emission rates of the next boiler operating day with 18 hours or more of non-out-of-control PM CEMS data to determine compliance. For affected facilities for which construction, modification, or reconstruction commenced after May 3, 2011, compliance with applicable daily average PM emissions limits is determined by dividing the sum of the PM emissions for the 30 successive boiler operating days by the sum of the gross useful output or net energy output, as applicable, for the 30 successive boiler operating days.
(g) For affected facilities for which construction, modification, or reconstruction commenced after May 3, 2011, compliance with applicable 30-boiler operating day rolling average NO
(k) * * *
(1) * * *
(i) The emission rate (E) of NO
(2) * * *
(i) The emission rate (E) of NO
(iv) The owner or operator may, in lieu of installing, operating, and recording data from the continuous flow monitoring system specified in § 60.49Da(l), determine the mass rate (lb/h) of NO
(m) Compliance provisions for sources subject to § 60.43Da(i)(1)(i), (i)(2)(i), (i)(3)(i), (j)(1)(i), (j)(2)(i), (j)(3)(i), (l)(1)(i), (l)(1)(ii), or (l)(2). The owner or operator shall calculate SO
(n) Compliance provisions for sources subject to § 60.42Da(c)(1) or (e)(1)(i). The owner or operator shall calculate PM emissions by multiplying the average hourly PM output concentration (measured according to the provisions of § 60.49Da(t)), by the average hourly flow rate (measured according to the provisions of § 60.49Da(l) or § 60.49Da(m)), and dividing by the average hourly gross energy output (measured according to the provisions
(p) * * *
(5) At a minimum, non-out-of-control CEMS hourly averages shall be obtained for 75 percent of all operating hours on a 30-boiler operating day rolling average basis. Beginning on January 1, 2012, non-out-of-control CEMS hourly averages shall be obtained for 90 percent of all operating hours on a 30-boiler operating day rolling average basis.
(i) At least two data points per hour shall be used to calculate each 1-hour arithmetic average.
(ii) [Reserved]
(7) All non-out-of-control CEMS data shall be used in calculating average emission concentrations even if the minimum CEMS data requirements of paragraph (j)(5) of this section are not met.
(8) When PM emissions data are not obtained because of CEMS breakdowns, repairs, calibration checks, and zero and span adjustments, emissions data shall be obtained by using other monitoring systems as approved by the Administrator or EPA Reference Method 19 of appendix A of this part to provide, as necessary, non-out-of-control emissions data for a minimum of 90 percent (only 75 percent is required prior to January 1, 2012) of all operating hours per 30-boiler operating day rolling average.
(r) Compliance provisions for sources subject to § 60.45Da. To determine compliance with the NO
(1) Calculate NO
(2) Calculate CO emissions by multiplying the average hourly CO output concentration (measured according to the provisions of § 60.49Da(u), by the average hourly flow rate (measured according to the provisions of § 60.49Da(l) or § 60.49Da(m)), and dividing by the average hourly gross energy output (measured according to the provisions of § 60.49Da(k)) or the average hourly net energy output, as applicable.
(3) Calculate NO
(s) Affirmative defense for exceedance of emissions limit during malfunction. In response to an action to enforce the standards set forth in paragraph §§ 60.42Da, 60.43Da, 60.44Da, and 60.45Da, you may assert an affirmative defense to a claim for civil penalties for exceedances of such standards that are caused by malfunction, as defined at 40 CFR 60.2. Appropriate penalties may be assessed, however, if you fail to meet your burden of proving all of the requirements in the affirmative defense as specified in paragraphs (s)(1) and (2) of this section. The affirmative defense shall not be available for claims for injunctive relief.
(1) To establish the affirmative defense in any action to enforce such a limit, you must timely meet the notification requirements in paragraph (s)(2) of this section, and must prove by a preponderance of evidence that:
(i) The excess emissions:
(A) Were caused by a sudden, infrequent, and unavoidable failure of air pollution control and monitoring equipment, process equipment, or a process to operate in a normal or usual manner; and
(B) Could not have been prevented through careful planning, proper design, or better operation and maintenance practices; and
(C) Did not stem from any activity or event that could have been foreseen and avoided, or planned for; and
(D) Were not part of a recurring pattern indicative of inadequate design, operation, or maintenance; and
(ii) Repairs were made as expeditiously as possible when the applicable emissions limits were being exceeded. Off-shift and overtime labor were used, to the extent practicable to make these repairs; and
(iii) The frequency, amount, and duration of the excess emissions (including any bypass) were minimized to the maximum extent practicable during periods of such emissions; and
(iv) If the excess emissions resulted from a bypass of control equipment or a process, then the bypass was unavoidable to prevent loss of life, personal injury, or severe property damage; and
(v) All possible steps were taken to minimize the impact of the excess emissions on ambient air quality, the environment, and human health; and
(vi) All emissions monitoring and control systems were kept in operation if at all possible, consistent with safety and good air pollution control practices; and
(vii) All of the actions in response to the excess emissions were documented by properly signed, contemporaneous operating logs; and
(viii) At all times, the facility was operated in a manner consistent with good practices for minimizing emissions; and
(ix) A written root cause analysis has been prepared, the purpose of which is to determine, correct, and eliminate the primary causes of the malfunction and the excess emissions resulting from the malfunction event at issue. The analysis shall also specify, using best monitoring methods and engineering judgment, the amount of excess emissions that were the result of the malfunction.
(2)
(a) * * *
(1) Except as provided for in paragraphs (a)(2) and (4) of this section, the owner or operator of an affected facility subject to an opacity standard, shall install, calibrate, maintain, and operate a COMS, and record the output of the system, for measuring the opacity of emissions discharged to the atmosphere. If opacity interference due to water droplets exists in the stack (for example, from the use of an FGD system), the opacity is monitored upstream of the interference (at the inlet to the FGD system). If opacity interference is experienced at all locations (both at the inlet and outlet of the SO
(2) As an alternative to the monitoring requirements in paragraph (a)(1) of this section, an owner or operator of an affected facility that meets the conditions in either paragraph (a)(2)(i), (ii), (iii), or (iv) of this section may elect to monitor opacity as specified in paragraph (a)(3) of this section.
(i) The affected facility uses a fabric filter (baghouse) to meet the standards in § 60.42Da and a bag leak detection system is installed and operated according to the requirements in paragraphs § 60.48Da(o)(4)(i) through (v);
(ii) The affected facility burns only gaseous or liquid fuels (excluding residual oil) with potential SO
(iii) The affected facility meets all of the conditions specified in paragraphs (a)(2)(iii)(A) through (C) of this section.
(A) No post-combustion technology (except a wet scrubber) is used for reducing PM, SO
(B) Only natural gas, gaseous fuels, or fuel oils that contain less than or equal to 0.30 weight percent sulfur are burned; and
(C) Emissions of CO discharged to the atmosphere are maintained at levels less than or equal to 1.4 lb/MWh on a boiler operating day average basis as demonstrated by the use of a CEMS measuring CO emissions according to the procedures specified in paragraph (u) of this section; or
(iv) The affected facility uses an ESP and uses an ESP predictive model to monitor the performance of the ESP developed in accordance and operated according to the most current requirements in section § 60.48Da of this part.
(3) The owner or operator of an affected facility that meets the conditions in paragraph (a)(2) of this section may, as an alternative to using a COMS, elect to monitor visible emissions using the applicable procedures specified in paragraphs (a)(3)(i) through (iv) of this section. The opacity performance test requirement in paragraph (a)(3)(i) must be conducted by April 29, 2011, within 45 days after stopping use of an existing COMS, or within 180 days after initial startup of the facility, whichever is later.
(ii) Except as provided in paragraph (a)(3)(iii) or (iv) of this section, the owner or operator shall conduct subsequent Method 9 of appendix A-4 of this part performance tests using the procedures in paragraph (a)(3)(i) of this section according to the applicable schedule in paragraphs (a)(3)(ii)(A) through (a)(3)(ii)(C) of this section, as determined by the most recent Method 9 of appendix A-4 of this part performance test results.
(A) If the maximum 6-minute average opacity is less than or equal to 5 percent, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 12 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later;
(B) If the maximum 6-minute average opacity is greater than 5 percent but less than or equal to 10 percent, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 3 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later; or
(C) If the maximum 6-minute average opacity is greater than 10 percent, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 45 calendar days from the date that the most recent performance test was conducted.
(iii) * * *
(B) If no visible emissions are observed for 10 operating days during which an opacity standard is applicable, observations can be reduced to once every 7 operating days during which an opacity standard is applicable. If any visible emissions are observed, daily observations shall be resumed.
(4) An owner or operator of an affected facility that is subject to an opacity standard under § 60.42a(b) is not required to operate a COMS provided that affected facility meets the conditions in either paragraph (a)(4)(i) or (ii) of this section.
(i) The affected facility combusts only gaseous fuels and/or liquid fuels (excluding residue oil) with a potential SO
(ii) The owner or operator of the affected facility installs, calibrates, operates, and maintains a particulate matter continuous parametric monitoring system (PM CPMS) according to the requirements specified in subpart UUUUU of part 63.
(b) The owner or operator of an affected facility shall install, calibrate, maintain, and operate a CEMS, and record the output of the system, for measuring SO
(2) For a facility that qualifies under the numerical limit provisions of § 60.43Da, SO
(e) The CEMS under paragraphs (b), (c), and (d) of this section are operated and data recorded during all periods of operation of the affected facility including periods of startup, shutdown, and malfunction, except for CEMS breakdowns, repairs, calibration checks, and zero and span adjustments.
(k) The procedures specified in paragraphs (k)(1) through (3) of this section shall be used to determine gross energy output for sources demonstrating compliance with an output-based standard.
(3) For an affected facility generating process steam in combination with electrical generation, the gross energy output is determined according to the definition of “gross energy output” specified in § 60.41Da that is applicable to the affected facility.
(l) The owner or operator of an affected facility demonstrating compliance with an output-based standard shall install, certify, operate, and maintain a continuous flow monitoring system meeting the requirements of Performance Specification 6 of appendix B of this part and the calibration drift (CD) assessment, relative accuracy test audit (RATA), and reporting provisions of procedure 1 of appendix F of this part, and record the output of the system, for measuring the volumetric flow rate of exhaust gases discharged to the atmosphere; or
(t) The owner or operator of an affected facility demonstrating compliance with the output-based emissions limitation under § 60.42Da shall install, certify, operate, and maintain a CEMS for measuring PM emissions according to the requirements of paragraph (v) of this section. An owner or operator of an affected facility demonstrating compliance with the input-based emissions limit in § 60.42Da may install, certify, operate, and maintain a CEMS for measuring PM emissions according to the requirements of paragraph (v) of this section.
(u) * * *
(1) * * *
(iii) At a minimum, non-out-of-control 1-hour CO emissions averages must be obtained for at least 90 percent of the operating hours on a 30-boiler operating day rolling average basis. The 1-hour averages are calculated using the data points required in § 60.13(h)(2).
(v) * * *
(4) As of January 1, 2012, and within 90 days after the date of completing each performance test, as defined in § 60.8, conducted to demonstrate compliance with this subpart, you must submit relative accuracy test audit (
(b) In conducting the performance tests to determine compliance with the PM emissions limits in § 60.42Da, the owner or operator shall meet the requirements specified in paragraphs (b)(1) through (3) of this section.
(1) The owner or operator shall measure filterable PM to determine compliance with the applicable PM emissions limit in § 60.42Da as specified in paragraphs (b)(1)(i) through (ii) of this section.
(i) The dry basis F factor (O
(ii) For the PM concentration, Method 5 of appendix A of this part shall be used for an affected facility that does not use a wet FGD. For an affected facility that uses a wet FGD, Method 5B of appendix A of this part shall be used downstream of the wet FGD.
(A) The sampling time and sample volume for each run shall be at least 120 minutes and 1.70 dscm (60 dscf). The probe and filter holder heating system in the sampling train may be set to provide an average gas temperature of no greater than 160 ± 14 °C (320 ± 25 °F).
(B) For each particulate run, the emission rate correction factor, integrated or grab sampling and analysis procedures of Method 3B of appendix A of this part shall be used to determine the O
(2) In conjunction with a performance test performed according to the requirements in paragraph (b)(1) of this section, the owner or operator of an affected facility for which construction, reconstruction, or modification commenced after May 3, 2011, shall measure condensable PM using Method 202 of appendix M of part 51.
(3) Method 9 of appendix A of this part and the procedures in § 60.11 shall be used to determine opacity.
(a) For SO
(b) * * *
(5) Identification of the times when emissions data have been excluded from the calculation of average emission rates because of startup, shutdown, or malfunction.
(d) In addition to the applicable requirements in § 60.7, the owner or operator of an affected facility subject to the opacity limits in § 60.43c(c) and conducting performance tests using Method 9 of appendix A-4 of this part shall submit excess emission reports for any excess emissions from the affected facility that occur during the reporting period and maintain records according to the requirements specified in paragraph (d)(1) of this section.
(1) For each performance test conducted using Method 9 of appendix
(i) Dates and time intervals of all opacity observation periods;
(ii) Name, affiliation, and copy of current visible emission reading certification for each visible emission observer participating in the performance test; and
(iii) Copies of all visible emission observer opacity field data sheets.
(2) [Reserved]
(k) The owner or operator of an affected facility may submit electronic quarterly reports for SO
(c) Affected facilities that also meet the applicability requirements under subpart J or subpart Ja of this part are subject to the PM and NO
(h) Any affected facility that meets the applicability requirements and is subject to subpart Ea, subpart Eb, subpart AAAA, or subpart CCCC of this part is not subject to this subpart.
(i) Affected facilities (
(l) Affected facilities that also meet the applicability requirements under subpart BB of this part (Standards of Performance for Kraft Pulp Mills) are subject to the SO
(m) Temporary boilers are not subject to this subpart.
24. Section 60.41b is amended by revising the definition of “distillate oil”, and adding the definition of “temporary boiler” in alphabetical order to read as follows:
(1) The equipment is attached to a foundation.
(2) The steam generating unit or a replacement remains at a location for more than 180 consecutive days. Any temporary boiler that replaces a temporary boiler at a location and performs the same or similar function will be included in calculating the consecutive time period.
(3) The equipment is located at a seasonal facility and operates during the full annual operating period of the seasonal facility, remains at the facility for at least 2 years, and operates at that facility for at least 3 months each year.
(4) The equipment is moved from one location to another in an attempt to circumvent the residence time requirements of this definition.
(f) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that combusts coal, oil, wood, or mixtures of these fuels with any other fuels shall cause to be discharged into the atmosphere any gases that exhibit greater than 20 percent opacity (6-minute average), except for one 6-minute period per hour of not more than 27 percent opacity. An owner or operator of an affected facility that elects to install, calibrate, maintain, and operate a continuous emissions monitoring system (CEMS) for measuring PM emissions according to the requirements of this subpart and is subject to a federally enforceable PM limit of 0.030 lb/MMBtu or less is exempt from the opacity standard specified in this paragraph.
(b) Except as provided under paragraphs (k) and (l) of this section, on and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that
(c) Except as provided under paragraph (d) and (l) of this section, on and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that simultaneously combusts coal or oil, natural gas (or any combination of the three), and wood, or any other fuel shall cause to be discharged into the atmosphere any gases that contain NO
(d) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that simultaneously combusts natural gas and/or distillate oil with a potential SO
(e) Except as provided under paragraph (l) of this section, on and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that simultaneously combusts only coal, oil, or natural gas with byproduct/waste shall cause to be discharged into the atmosphere any gases that contain NO
(l) * * *
(1) 86 ng/J (0.20 lb/MMBtu) heat input if the affected facility combusts coal, oil, or natural gas (or any combination of the three), alone or with any other fuels. The affected facility is not subject to this limit if it is subject to and in compliance with a federally enforceable requirement that limits operation of the facility to an annual capacity factor of 10 percent (0.10) or less for coal, oil, and natural gas (or any combination of the three); or
(j) * * *
(14) As of January 1, 2012, and within 90 days after the date of completing each performance test, as defined in § 60.8, conducted to demonstrate compliance with this subpart, you must submit relative accuracy test audit (
(a) Except as provided in paragraph (j) of this section, the owner or operator of an affected facility subject to the opacity standard under § 60.43b shall install, calibrate, maintain, and operate a continuous opacity monitoring systems (COMS) for measuring the opacity of emissions discharged to the atmosphere and record the output of the system. The owner or operator of an affected facility subject to an opacity standard under § 60.43b and meeting the conditions under paragraphs (j)(1), (2), (3), (4), (5), or (6) of this section who elects not to use a COMS shall conduct a performance test using Method 9 of appendix A-4 of this part and the procedures in § 60.11 to demonstrate compliance with the applicable limit in § 60.43b by April 29, 2011, within 45 days of stopping use of an existing COMS, or within 180 days after initial startup of the facility, whichever is later, and shall comply with either paragraphs (a)(1), (a)(2), or (a)(3) of this section. The observation period for Method 9 of appendix A-4 of this part performance tests may be reduced from 3 hours to 60 minutes if all 6-minute averages are less than 10 percent and all individual 15-second observations are less than or equal to 20 percent during the initial 60 minutes of observation.
(1) * * *
(i) If no visible emissions are observed, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 12 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later;
(ii) If visible emissions are observed but the maximum 6-minute average opacity is less than or equal to 5 percent, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 6 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later;
(iii) If the maximum 6-minute average opacity is greater than 5 percent but less than or equal to 10 percent, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 3 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later; or
(2) * * *
(ii) If no visible emissions are observed for 10 operating days during which an opacity standard is applicable, observations can be reduced to once every 7 operating days during which an
(j) The owner or operator of an affected facility that meets the conditions in either paragraph (j)(1), (2), (3), (4), (5), (6), or (7) of this section is not required to install or operate a COMS if:
(5) The affected facility uses a bag leak detection system to monitor the performance of a fabric filter (baghouse) according to the most current requirements in section § 60.48Da of this part; or
(6) The affected facility uses an ESP as the primary PM control device and uses an ESP predictive model to monitor the performance of the ESP developed in accordance and operated according to the most current requirements in section § 60.48Da of this part; or
(7) The affected facility burns only gaseous fuels or fuel oils that contain less than or equal to 0.30 weight percent sulfur and operates according to a written site-specific monitoring plan approved by the permitting authority. This monitoring plan must include procedures and criteria for establishing and monitoring specific parameters for the affected facility indicative of compliance with the opacity standard.
(l) An owner or operator of an affected facility that is subject to an opacity standard under § 60.43b(f) is not required to operate a COMS provided that the unit burns only gaseous fuels and/or liquid fuels (excluding residue oil) with a potential SO
(r) * * *
(1) The owner or operator of an affected facility who elects to demonstrate that the affected facility combusts only very low sulfur oil, natural gas, wood, a mixture of these fuels, or any of these fuels (or a mixture of these fuels) in combination with other fuels that are known to contain an insignificant amount of sulfur in § 60.42b(j) or § 60.42b(k) shall obtain and maintain at the affected facility fuel receipts (such as a current, valid purchase contract, tariff sheet, or transportation contract) from the fuel supplier that certify that the oil meets the definition of distillate oil and gaseous fuel meets the definition of natural gas as defined in § 60.41b and the applicable sulfur limit. For the purposes of this section, the distillate oil need not meet the fuel nitrogen content specification in the definition of distillate oil. Reports shall be submitted to the Administrator certifying that only very low sulfur oil meeting this definition, natural gas, wood, and/or other fuels that are known to contain insignificant amounts of sulfur were combusted in the affected facility during the reporting period; or
(a) Except as provided in paragraphs (d), (e), (f), and (g) of this section, the affected facility to which this subpart applies is each steam generating unit for which construction, modification, or reconstruction is commenced after June 9, 1989 and that has a maximum design heat input capacity of 29 megawatts (MW) (100 million British thermal units per hour (MMBtu/h)) or less, but greater than or equal to 2.9 MW (10 MMBtu/h).
(e) Affected facilities (
(f) Any affected facility that meets the applicability requirements of and is subject to subpart AAAA or subpart CCCC of this part is not subject to this subpart.
(g) Any facility that meets the applicability requirements and is subject to an EPA approved State or Federal section 111(d)/129 plan implementing subpart BBBB of this part is not subject to this subpart.
(h) Affected facilities that also meet the applicability requirements under subpart J or subpart Ja of this part are subject to the PM and NO
(i) Temporary boilers are not subject to this subpart.
(1) The equipment is attached to a foundation.
(2) The steam generating unit or a replacement remains at a location for more than 180 consecutive days. Any temporary boiler that replaces a temporary boiler at a location and performs the same or similar function will be included in calculating the consecutive time period.
(3) The equipment is located at a seasonal facility and operates during the full annual operating period of the seasonal facility, remains at the facility for at least 2 years, and operates at that facility for at least 3 months each year.
(4) The equipment is moved from one location to another in an attempt to circumvent the residence time requirements of this definition.
(c) * * *
(1) Affected facilities that have a heat input capacity of 22 MW (75 MMBtu/h) or less;
(3) Affected facilities located in a noncontinental area; or
(d) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that combusts oil shall cause to be discharged into the atmosphere from that affected facility any gases that contain SO
(e) * * *
(1) * * *
(ii) Has a heat input capacity greater than 22 MW (75 MMBtu/h); and
(h) For affected facilities listed under paragraphs (h)(1), (2), (3), or (4) of this section, compliance with the emission limits or fuel oil sulfur limits under this section may be determined based on a certification from the fuel supplier, as described under § 60.48c(f), as applicable.
(3) Coal-fired affected facilities with heat input capacities between 2.9 and 8.7 MW (10 and 30 MMBtu/h).
(4) Other fuels-fired affected facilities with heat input capacities between 2.9 and 8.7 MW (10 and 30 MMBtu/h).
(a) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification on or before February 28, 2005, that combusts coal or combusts mixtures of coal with other fuels and has a heat input capacity of 8.7 MW (30 MMBtu/h) or greater, shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of the following emission limits:
(b) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification on or before February 28, 2005, that combusts wood or combusts mixtures of wood with other fuels (except coal) and has a heat input capacity of 8.7 MW (30 MMBtu/h) or greater, shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of the following emissions limits:
(c) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that combusts coal, wood, or oil and has a heat input capacity of 8.7 MW (30 MMBtu/h) or greater shall cause to be discharged into the atmosphere from that affected facility any gases that exhibit greater than 20 percent opacity (6-minute average), except for one 6-minute period per hour of not more than 27 percent opacity. Owners and operators of an affected facility that elect to install, calibrate, maintain, and operate a continuous emissions monitoring system (CEMS) for measuring PM emissions according to the requirements of this subpart and are subject to a federally enforceable PM limit of 0.030 lb/MMBtu or less are exempt from the opacity standard specified in this paragraph (c).
(e)(1) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commences construction, reconstruction, or modification after February 28, 2005, and that combusts coal, oil, wood, a mixture of these fuels, or a mixture of these fuels with any other fuels and has a heat input capacity of 8.7 MW (30 MMBtu/h) or greater shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of 13 ng/J (0.030 lb/MMBtu) heat input, except as provided in paragraphs (e)(2), (e)(3), and (e)(4) of this section.
(3) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commences modification after February 28, 2005, and that combusts over 30 percent wood (by heat input) on an annual basis and has a heat input capacity of 8.7 MW (30 MMBtu/h) or greater shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of 43 ng/J (0.10 lb/MMBtu) heat input.
(4) An owner or operator of an affected facility that commences construction, reconstruction, or modification after February 28, 2005, and that combusts only oil that contains no more than 0.50 weight percent sulfur
(c) * * *
(14) As of January 1, 2012, and within 90 days after the date of completing each performance test, as defined in § 60.8, conducted to demonstrate compliance with this subpart, you must submit relative accuracy test audit (
(d) The owner or operator of an affected facility seeking to demonstrate compliance under § 60.43c(e)(4) shall follow the applicable procedures under § 60.48c(f). For residual oil-fired affected facilities, fuel supplier certifications are only allowed for facilities with heat input capacities between 2.9 and 8.7 MW (10 to 30 MMBtu/h).
(a) Except as provided in paragraphs (c), (d), (e), and (f) of this section, the owner or operator of an affected facility combusting coal, oil, or wood that is subject to the opacity standards under § 60.43c shall install, calibrate, maintain, and operate a continuous opacity monitoring system (COMS) for measuring the opacity of the emissions discharged to the atmosphere and record the output of the system. The owner or operator of an affected facility subject to an opacity standard in § 60.43c(c) that is not required to use a COMS due to paragraphs (c), (d), (e), or (f) of this section that elects not to use a COMS shall conduct a performance test using Method 9 of appendix A-4 of this part and the procedures in § 60.11 to demonstrate compliance with the applicable limit in § 60.43c by April 29, 2011, within 45 days of stopping use of an existing COMS, or within 180 days after initial startup of the facility, whichever is later, and shall comply with either paragraphs (a)(1), (a)(2), or (a)(3) of this section. The observation period for Method 9 of appendix A-4 of this part performance tests may be reduced from 3 hours to 60 minutes if all 6-minute averages are less than 10 percent and all individual 15-second observations are less than or equal to 20 percent during the initial 60 minutes of observation.
(1) * * *
(i) If no visible emissions are observed, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 12 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later;
(ii) If visible emissions are observed but the maximum 6-minute average opacity is less than or equal to 5 percent, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 6 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later;
(iii) If the maximum 6-minute average opacity is greater than 5 percent but less than or equal to 10 percent, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 3 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later; or
(2) * * *
(ii) If no visible emissions are observed for 10 operating days during which an opacity standard is applicable, observations can be reduced to once every 7 operating days during which an opacity standard is applicable. If any visible emissions are observed, daily observations shall be resumed.
(f) An owner or operator of an affected facility that is subject to an opacity standard in § 60.43c(c) is not required to operate a COMS provided that the affected facility meets the conditions in either paragraphs (f)(1), (2), or (3) of this section.
(1) The affected facility uses a fabric filter (baghouse) as the primary PM control device and, the owner or operator operates a bag leak detection system to monitor the performance of the fabric filter according to the requirements in section § 60.48Da of this part.
(2) The affected facility uses an ESP as the primary PM control device, and the owner or operator uses an ESP predictive model to monitor the performance of the ESP developed in accordance and operated according to the requirements in section § 60.48Da of this part.
(3) The affected facility burns only gaseous fuels and/or fuel oils that contain no greater than 0.5 weight percent sulfur, and the owner or operator operates the unit according to a written site-specific monitoring plan approved by the permitting authority. This monitoring plan must include procedures and criteria for establishing and monitoring specific parameters for the affected facility indicative of compliance with the opacity standard. For testing performed as part of this site-specific monitoring plan, the permitting authority may require as an alternative to the notification and reporting requirements specified in §§ 60.8 and 60.11 that the owner or operator submit any deviations with the excess emissions report required under § 60.48c(c).
42 U.S.C. 7401,
(b) * * *
(19) ASTM D95-05 (Reapproved 2010), Standard Test Method for Water in Petroleum Products and Bituminous Materials by Distillation, approved May 1, 2010, IBR approved for § 63.10005(i)(4)(i).
(20) ASTM Method D388-05, Standard Classification of Coals by Rank, approved September 15, 2005, IBR approved for § 63.10042.
(22) ASTM Method D396-10, Standard Specification for Fuel Oils, including Appendix X1, approved October 1, 2010, IBR approved for § 63.10042.
(23) ASTM D4006-11, Standard Test Method for Water in Crude Oil by Distillation, including Annex A1 and Appendix X1, approved June 1, 2011, IBR approved for § 63.10005(i)(4)(ii).
(69) ASTM D4057-06 (Reapproved 2011), Standard Practice for Manual Sampling of Petroleum and Petroleum Products, including Annex A1, approved June 1, 2011, IBR approved for § 63.10005(i)(4)(iv).
(70) ASTM D4177-95 (Reapproved 2010), Standard Practice for Automatic Sampling of Petroleum and Petroleum Products, including Annexes A1 through A6 and Appendices X1 and X2, approved May 1, 2010, IBR approved for § 63.10005(i)(4)(iii).
(71) ASTM D6348-03 (Reapproved 2010), Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy, including Annexes A1 through A8, approved October 1, 2010, IBR approved for table 1 to subpart UUUUU of this part, table 2 to subpart UUUUU of this part, table 5 to subpart UUUUU of this part, and appendix B to subpart UUUUU of this part.
(72) ASTM D6784-02 (Reapproved 2008), Standard Test Method for Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro Method), approved April 1, 2008, IBR approved for table 5 to subpart UUUUU of this part, and appendix A to subpart UUUUU of this part.
(i) * * *
(1) ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses [part 10, Instruments and Apparatus],” IBR approved for §§ 63.309(k)(1)(iii), 63.865(b), 63.3166(a)(3), 63.3360(e)(1)(iii), 63.3545(a)(3), 63.3555(a)(3), 63.4166(a)(3), 63.4362(a)(3), 63.4766(a)(3), 63.4965(a)(3), 63.5160(d)(1)(iii), 63.9307(c)(2), 63.9323(a)(3), 63.11148(e)(3)(iii), 63.11155(e)(3), 63.11162(f)(3)(iii) and (f)(4), 63.11163(g)(1)(iii) and (g)(2), 63.11410(j)(1)(iii), 63.11551(a)(2)(i)(C), table 5 to subpart DDDDD of this part, table 1 to subpart ZZZZZ of this part, table 4 to subpart JJJJJJ of this part, and table 5 to subpart UUUUU of this part.
This subpart establishes national emission limitations and work practice standards for hazardous air pollutants (HAP) emitted from coal- and oil-fired electric utility steam generating units (EGUs) as defined in § 63.10042 of this subpart. This subpart also establishes requirements to demonstrate initial and continuous compliance with the emission limitations.
You are subject to this subpart if you own or operate a coal-fired EGU or an oil-fired EGU as defined in § 63.10042 of this subpart.
(a) This subpart applies to each individual or group of two or more new, reconstructed, and existing affected source(s) as described in paragraphs (a)(1) and (2) of this section within a contiguous area and under common control.
(1) The affected source of this subpart is the collection of all existing coal- or oil-fired EGUs, as defined in 63.10042, within a subcategory.
(2) The affected source of this subpart is each new or reconstructed coal- or oil-fired EGU as defined in 63.10042.
(b) An EGU is new if you commence construction of the coal- or oil-fired EGU after May 3, 2011, and you meet the applicability criteria at the time you commence construction.
(c) An EGU is reconstructed if you meet the reconstruction criteria as defined in § 63.2, you commence reconstruction after May 3, 2011, and you meet the applicability criteria at the time you commence reconstruction.
(d) An EGU is existing if it is not new or reconstructed. An existing electric steam generating unit that meets the applicability requirements after the effective date of this final rule due to a change process (
The types of electric steam generating units listed in paragraphs (a) through (d) of this section are not subject to this subpart.
(a) Any unit designated as a stationary combustion turbine, other than an integrated gasification combined cycle (IGCC) unit, covered by 40 CFR part 63, subpart YYYY.
(b) Any electric utility steam generating unit that is not a coal- or oil-fired EGU and combusts natural gas for more than 10.0 percent of the average annual heat input during any 3 calendar years or for more than 15.0 percent of the annual heat input during any calendar year.
(c) Any electric utility steam generating unit that has the capability of combusting more than 25 MW of coal or oil but did not fire coal or oil for more than 10.0 percent of the average annual heat input during any 3 calendar years or for more than 15.0 percent of the annual heat input during any calendar year. Heat input means heat derived from combustion of fuel in an EGU and does not include the heat derived from preheated combustion air, recirculated flue gases or exhaust gases from other sources (such as stationary gas turbines, internal combustion engines, and industrial boilers).
(d) Any electric steam generating unit combusting solid waste is a solid waste incineration unit subject to standards established under sections 129 and 111 of the Clean Air Act.
(a) If you have a new or reconstructed EGU, you must comply with this subpart by April 16, 2012 or upon startup of your EGU, whichever is later, and as further provided for in § 63.10005(g).
(b) If you have an existing EGU, you must comply with this subpart no later than April 16, 2015.
(c) You must meet the notification requirements in § 63.10030 according to the schedule in § 63.10030 and in subpart A of this part. Some of the notifications must be submitted before you are required to comply with the emission limits and work practice standards in this subpart.
(d) An electric steam generating unit that does not meet the definition of an EGU subject to this subpart on April 16, 2012 for new sources or April 16, 2015 for existing sources must comply with the applicable existing source provisions of this subpart on the date such unit meets the definition of an EGU subject to this subpart.
(e) If you own or operate an electric steam generating unit that is exempted from this subpart under § 63.9983(d), if the manner of operating the unit changes such that the combustion of waste is discontinued and the unit becomes a coal-fired or oil-fired EGU (as defined in § 63.10042), you must be in compliance with this subpart on April 16, 2015 or on the effective date of the switch from waste combustion to coal or oil combustion, whichever is later.
(f) You must demonstrate that compliance has been achieved, by conducting the required performance tests and other activities, no later than 180 days after the applicable date in paragraph (a), (b), (c), (d), or (e) of this section.
(a) A new EGU is an EGU that meets any of the criteria specified in paragraph (a)(1) through (a)(2) of this section.
(1) An EGU that commenced construction after May 3, 2011.
(2) An EGU that commenced reconstruction or modification after May 3, 2011.
(b) [Reserved]
(a) Coal-fired EGUs are subcategorized as defined in paragraphs (a)(1) through (a)(2) of this section and as defined in § 63.10042.
(1) EGUs designed for coal with a heating value greater than or equal to 8,300 Btu/lb, and
(2) EGUs designed for low rank virgin coal.
(b) Oil-fired EGUs are subcategorized as noted in paragraphs (b)(1) through (b)(4) of this section and as defined in § 63.10042.
(1) Continental liquid oil-fired EGUs
(2) Non-continental liquid oil-fired EGUs,
(3) Limited-use liquid oil-fired EGUs, and
(4) EGUs designed to burn solid oil-derived fuel.
(c) IGCC units combusting either gasified coal or gasified solid oil-derived fuel. For purposes of compliance, monitoring, recordkeeping, and reporting requirements in this subpart, IGCC units are subject in the same manner as coal-fired units and solid oil-derived fuel-fired units, unless otherwise indicated.
(a) You must meet the requirements in paragraphs (a)(1) and (2) of this section. You must meet these requirements at all times.
(1) You must meet each emission limit and work practice standard in Table 1 through 3 to this subpart that applies to your EGU, for each EGU at your source, except as provided under § 63.10009.
(2) You must meet each operating limit in Table 4 to this subpart that applies to your EGU.
(b) As provided in § 63.6(g), the Administrator may approve use of an alternative to the work practice standards in this section.
(c) You may use the alternate SO
(1) Has a system using wet or dry flue gas desulfurization technology and SO
(2) At all times, you operate the wet or dry flue gas desulfurization technology installed on the unit consistent with § 63.10000(b).
(a) You must be in compliance with the emission limits and operating limits in this subpart. These limits apply to you at all times except during periods of startup and shutdown; however, for coal-fired, liquid oil-fired, or solid oil-derived fuel-fired EGUs, you are required to meet the work practice requirements in Table 3 to this subpart during periods of startup or shutdown.
(b) At all times you must operate and maintain any affected source, including associated air pollution control equipment and monitoring equipment, in a manner consistent with safety and good air pollution control practices for minimizing emissions. Determination of whether such operation and maintenance procedures are being used will be based on information available to the EPA Administrator which may include, but is not limited to, monitoring results, review of operation and maintenance procedures, review of operation and maintenance records, and inspection of the source.
(c)(1) For coal-fired units and solid oil-derived fuel-fired units, initial performance testing is required for all pollutants, to demonstrate compliance with the applicable emission limits.
(i) For a coal-fired or solid oil-derived fuel-fired EGU or IGCC EGU, you may conduct the initial performance testing in accordance with § 63.10005(h), to determine whether the unit qualifies as a low emitting EGU (LEE) for one or more applicable emissions limits, with two exceptions:
(A) You may not pursue the LEE option if your coal-fired, IGCC, or solid oil-derived fuel-fired EGU is equipped with an acid gas scrubber and has a main stack and bypass stack exhaust configuration, and
(B) You may not pursue the LEE option for Hg if your coal-fired, solid oil-fired fuel fired EGU or IGCC EGU is new.
(ii) For a qualifying LEE for Hg emissions limits, you must conduct a 30-day performance test using Method 30B at least once every 12 calendar months to demonstrate continued LEE status.
(iii) For a qualifying LEE of any other applicable emissions limits, you must conduct a performance test at least once every 36 calendar months to demonstrate continued LEE status.
(iv) If your coal-fired or solid oil-derived fuel-fired EGU or IGCC EGU does not qualify as a LEE for total non-mercury HAP metals, individual non-mercury HAP metals, or filterable particulate matter (PM), you must demonstrate compliance through an initial performance test and you must monitor continuous performance through either use of a particulate matter continuous parametric monitoring system (PM CPMS), a PM CEMS, or compliance performance testing repeated quarterly.
(A) If you elect to use PM CPMS, you will establish a site-specific operating limit corresponding to the results of the performance test demonstrating compliance with the pollutant with which you choose to comply: total non-mercury HAP metals, individual non-mercury HAP metals or filterable PM. You will use the PM CPMS to demonstrate continuous compliance with this operating limit. If you elect to use a PM CPMS, you must repeat the performance test annually for the selected pollutant limit and reassess and adjust the site-specific operating limit in accordance with the results of the performance test.
(B) You may also opt to install and operate a particulate matter CEMS certified in accordance with Performance Specification 11 and Procedure 2 of 40 CFR part 60, Appendices B and F, respectively, in accordance with § 63.10010(i).
(v) If your coal-fired or solid oil-derived fuel-fired EGU does not qualify as a LEE for hydrogen chloride (HCl), you may demonstrate initial and continuous compliance through use of an HCl CEMS, installed and operated in accordance with Appendix B to this subpart. As an alternative to HCl CEMS, you may demonstrate initial and continuous compliance by conducting an initial and periodic quarterly performance stack test for HCl. If your EGU uses wet or dry flue gas desulfurization technology (this includes limestone injection into a fluidized bed combustion unit), you may apply a second alternative to HCl CEMS by installing and operating a sulfur dioxide (SO
(vi) If your coal-fired or solid oil-derived fuel-fired EGU does not qualify as a LEE for Hg, you must demonstrate initial and continuous compliance through use of a Hg CEMS or a sorbent trap monitoring system, in accordance with appendix A to this subpart.
(2) For liquid oil-fired EGUs, except limited use liquid oil-fired EGUs, initial performance testing is required for all pollutants, to demonstrate compliance with the applicable emission limits.
(i) For an existing liquid oil-fired unit, you may conduct the performance testing in accordance with § 63.10005(h), to determine whether the unit qualifies as a LEE for one or more pollutants. For a qualifying LEE for Hg emissions limits, you must conduct a 30-day performance test using Method 30B at least once every 12 calendar months to demonstrate continued LEE status. For a qualifying LEE of any other applicable emissions limits, you must conduct a performance test at least once every 36 calendar months to demonstrate continued LEE status.
(ii) If your existing liquid oil-fired unit does not qualify as a LEE for total HAP metals (including mercury), individual metals (including mercury), or filterable PM you must demonstrate compliance through an initial performance test and you must monitor continuous performance through either use of a PM CPMS, a PM CEMS, or performance testing conducted quarterly.
(A) If you elect to use PM CPMS, you will establish a site-specific operating limit corresponding to the results of the performance test demonstrating compliance with the pollutant with which you choose to comply: total HAP metals, individual HAP metals, or filterable PM. You will use the PM CPMS to demonstrate continuous compliance with this operating limit. If you elect to use a PM CPMS, you must repeat the performance test at least annually for the selected pollutant limit and reassess and adjust the site-specific operating limit in accordance with the results of the performance test.
(B) If you elect to use a PM CEMS, you will use the CEMS in accordance with § 63.10010(i) to demonstrate initial and continuous compliance with the filterable PM emission limit.
(iii) If your existing liquid oil-fired unit does not qualify as a LEE for hydrogen chloride (HCl) or for hydrogen fluoride (HF), you may demonstrate initial and continuous compliance through use of an HCl CEMS, an HF CEMS, or an HCl and HF CEMS, installed and operated in accordance with Appendix B to this rule. As an alternative to HCl CEMS, HF CEMS, or HCl and HF CEMS, you may demonstrate initial and continuous compliance by conducting periodic quarterly performance stack tests for HCl and HF. If you elect to demonstrate compliance through quarterly performance testing, then you must also develop a site-specific monitoring plan to ensure that the operations of the unit remain consistent with those during the performance test. As another alternative, you may measure or obtain, and keep
(iv) If your unit qualifies as a limited-use liquid oil-fired as defined in § 63.10042, then you are not subject to the emission limits in Tables 1 and 2, but must comply with the performance tune-up work practice requirements in Table 3.
(d)(1) If you demonstrate compliance with any applicable emissions limit through use of a continuous monitoring system (CMS), where a CMS includes a continuous parameter monitoring system (CPMS) as well as a continuous emissions monitoring system (CEMS), you must develop a site-specific monitoring plan and submit this site-specific monitoring plan, if requested, at least 60 days before your initial performance evaluation (where applicable) of your CMS. This requirement also applies to you if you petition the Administrator for alternative monitoring parameters under § 63.8(f). This requirement to develop and submit a site-specific monitoring plan does not apply to affected sources with existing monitoring plans that apply to CEMS and CPMS prepared under Appendix B to part 60 or part 75 of this chapter, and that meet the requirements of § 63.10010. Using the process described in § 63.8(f)(4), you may request approval of monitoring system quality assurance and quality control procedures alternative to those specified in this paragraph of this section and, if approved, include those in your site-specific monitoring plan. The monitoring plan must address the provisions in paragraphs (d)(2) through (5) of this section.
(2) The site-specific monitoring plan shall include the information specified in paragraphs (d)(5)(i) through (d)(5)(vii) of this section. Alternatively, the requirements of paragraphs (d)(5)(i) through (d)(5)(vii) are considered to be met for a particular CMS or sorbent trap monitoring system if:
(i) The CMS or sorbent trap monitoring system is installed, certified, maintained, operated, and quality-assured either according to part 75 of this chapter, or appendix A or B to this subpart; and
(ii) The recordkeeping and reporting requirements of part 75 of this chapter, or appendix A or B to this subpart, that pertain to the CMS are met.
(3) If requested by the Administrator, you must submit the monitoring plan (or relevant portion of the plan) at least 60 days before the initial performance evaluation of a particular CMS, except where the CMS has already undergone a performance evaluation that meets the requirements of § 63.10010 (
(4) You must operate and maintain the CMS according to the site-specific monitoring plan.
(5) The provisions of the site-specific monitoring plan must address the following items:
(i) Installation of the CEMS or sorbent trap monitoring system sampling probe or other interface at a measurement location relative to each affected process unit such that the measurement is representative of control of the exhaust emissions (
(ii) Performance and equipment specifications for the sample interface, the pollutant concentration or parametric signal analyzer, and the data collection and reduction systems.
(iii) Schedule for conducting initial and periodic performance evaluations.
(iv) Performance evaluation procedures and acceptance criteria (
(v) On-going operation and maintenance procedures, in accordance with the general requirements of §§ 63.8(c)(1)(ii), (c)(3), and (c)(4)(ii).
(vi) Conditions that define a CMS that is out of control consistent with § 63.8(c)(7)(i) and for responding to out of control periods consistent with §§ 63.8(c)(7)(ii) and (c)(8).
(vii) On-going recordkeeping and reporting procedures, in accordance with the general requirements of §§ 63.10(c), (e)(1), and (e)(2)(i), or as specifically required under this subpart.
(e) As part of your demonstration of continuous compliance, you must perform periodic tune-ups of your EGU(s), according to § 63.10021(e).
(f) You are subject to the requirements of this subpart for at least 6 months following the last date you met the definition of an EGU subject to this subpart (
(g) If you no longer meet the definition of an EGU subject to this subpart you must be in compliance with any newly applicable standards on the date you are no longer subject to this subpart. The date you are no longer subject to this subpart is a date selected by you, that must be at least 6 months from the date that you last met the definition of an EGU subject to this subpart or the date you begin combusting solid waste, consistent with § 63.9983(d). Your source must remain in compliance with this subpart until the date you select to cease complying with this subpart or the date you begin combusting solid waste, whichever is earlier.
(h)(1) If you own or operate an EGU that does not meet the definition of an EGU subject to this subpart on April 16, 2015, and you commence or recommence operations that cause you to meet the definition of an EGU subject to this subpart, you are subject to the provisions of this subpart, including, but not limited to, the emission limitations and the monitoring requirements, as of the first day you meet the definition of an EGU subject to this subpart. You must complete all initial compliance demonstrations for this subpart applicable to your EGU within 180 days after you commence or recommence operations that cause you to meet the definition of an EGU subject to this subpart.
(2) You must provide 30 days prior notice of the date you intend to commence or recommence operations that cause you to meet the definition of an EGU subject to this subpart. The notification must identify:
(i) The name of the owner or operator of the EGU, the location of the facility, the unit(s) that will commence or recommence operations that will cause the unit(s) to meet the definition of an EGU subject to this subpart, and the date of the notice;
(ii) The 40 CFR part 60, part 62, or part 63 subpart and subcategory
(iii) The date on which you became subject to the currently applicable emission limits;
(iv) The date upon which you will commence or recommence operations that will cause your unit to meet the definition of an EGU subject to this subpart, consistent with paragraph (f) of this section.
(i)(1) If you own or operate an EGU subject to this subpart, and it has been at least 6 months since you operated in a manner that caused you to meet the definition of an EGU subject to this subpart, you may, consistent with paragraph (g) of this section, select the date on which your EGU will no longer be subject to this subpart. You must be in compliance with any newly applicable section 112 or 129 standards on the date you selected.
(2) You must provide 30 days prior notice of the date your EGU will cease complying with this subpart. The notification must identify:
(i) The name of the owner or operator of the EGU(s), the location of the facility, the EGU(s) that will cease complying with this subpart, and the date of the notice;
(ii) The currently applicable subcategory under this subpart, and any 40 CFR part 60, part 62, or part 63 subpart and subcategory that will be applicable after you cease complying with this subpart;
(iii) The date on which you became subject to this subpart;
(iv) The date upon which you will cease complying with this subpart, consistent with paragraph (g) of this section.
(j) All air pollution control equipment necessary for compliance with any newly applicable emissions limits which apply as a result of the cessation or commencement or recommencement of operations that cause your EGU to meet the definition of an EGU subject to this subpart must be installed and operational as of the date your source ceases to be or becomes subject to this subpart.
(k) All monitoring systems necessary for compliance with any newly applicable monitoring requirements which apply as a result of the cessation or commencement or recommencement of operations that cause your EGU to meet the definition of an EGU subject to this subpart must be installed and operational as of the date your source ceases to be or becomes subject to this subpart. All calibration and drift checks must be performed as of the date your source ceases to be or becomes subject to this subpart. You must also comply with provisions of §§ 63.10010, 63.10020, and 63.10021 of this subpart. Relative accuracy tests must be performed as of the performance test deadline for PM CEMS, if applicable. Relative accuracy testing for other CEMS need not be repeated if that testing was previously performed consistent with CAA section 112 monitoring requirements or monitoring requirements under this subpart.
In response to an action to enforce the standards set forth in § 63.9991 you may assert an affirmative defense to a claim for civil penalties for exceedances of such standards that are caused by malfunction, as defined at 40 CFR 63.2. Appropriate penalties may be assessed, however, if you fail to meet your burden of proving all of the requirements in the affirmative defense. The affirmative defense shall not be available for claims for injunctive relief.
(a) To establish the affirmative defense in any action to enforce such a limit, you must timely meet the notification requirements in paragraph (b) of this section, and must prove by a preponderance of evidence that:
(1) The excess emissions:
(i) Were caused by a sudden, infrequent, and unavoidable failure of air pollution control and monitoring equipment, process equipment, or a process to operate in a normal or usual manner, and
(ii) Could not have been prevented through careful planning, proper design or better operation and maintenance practices; and
(iii) Did not stem from any activity or event that could have been foreseen and avoided, or planned for; and
(iv) Were not part of a recurring pattern indicative of inadequate design, operation, or maintenance; and
(2) Repairs were made as expeditiously as possible when the applicable emission limitations were being exceeded. Off-shift and overtime labor were used, to the extent practicable to make these repairs; and
(3) The frequency, amount and duration of the excess emissions (including any bypass) were minimized to the maximum extent practicable during periods of such emissions; and
(4) If the excess emissions resulted from a bypass of control equipment or a process, then the bypass was unavoidable to prevent loss of life, personal injury, or severe property damage; and
(5) All possible steps were taken to minimize the impact of the excess emissions on ambient air quality, the environment and human health; and
(6) All emissions monitoring and control systems were kept in operation if at all possible, consistent with safety and good air pollution control practices; and
(7) All of the actions in response to the excess emissions were documented by properly signed, contemporaneous operating logs; and
(8) At all times, the affected source was operated in a manner consistent with good practices for minimizing emissions; and
(9) A written root cause analysis has been prepared, the purpose of which is to determine, correct, and eliminate the primary causes of the malfunction and the excess emissions resulting from the malfunction event at issue. The analysis shall also specify, using best monitoring methods and engineering judgment, the amount of excess emissions that were the result of the malfunction.
(b)
(a)
(1) To demonstrate initial compliance with an applicable emissions limit in Table 1 or 2 to this subpart using stack testing, the initial performance test generally consists of three runs at specified process operating conditions using approved methods. If you are required to establish operating limits (see paragraph (d) of this section and Table 4 to this subpart), you must collect all applicable parametric data during the performance test period. Also, if you choose to comply with an electrical output-based emission limit, you must collect hourly electrical load data during the test period.
(2) To demonstrate initial compliance using either a CMS that measures HAP concentrations directly (
(i) The 30-boiler operating day CMS performance test must demonstrate compliance with the applicable Hg, HCl, HF, PM, or SO
(ii) If you choose to comply with an electrical output-based emission limit, you must collect hourly electrical load data during the performance test period.
(b)
(1) For a performance test based on stack test data, the test was conducted no more than 12 calendar months prior to the date on which compliance is required as specified in § 63.9984;
(2) For a performance test based on data from a certified CEMS or sorbent trap monitoring system, the test consists of all valid data CMS data recorded in the 30 boiler operating days immediately preceding that date;
(3) The performance test was conducted in accordance with all applicable requirements in § 63.10007 and Table 5 to this subpart;
(4) A record of all parameters needed to convert pollutant concentrations to units of the emission standard (e.g., stack flow rate, diluent gas concentrations, hourly electrical loads) is available for the entire performance test period; and
(5) For each performance test based on stack test data, you certify, and keep documentation demonstrating, that the EGU configuration, control devices, and fuel(s) have remained consistent with conditions since the prior performance test was conducted.
(c)
(d)
(1) For an affected coal-fired, solid oil-derived fuel-fired, or liquid oil-fired EGU, you may demonstrate initial compliance with the applicable SO
(2) For affected coal-fired or solid oil-derived fuel-fired EGUs that demonstrate compliance with the applicable emission limits for total non-mercury HAP metals, individual non-mercury HAP metals, total HAP metals, individual HAP metals, or filterable PM listed in Table 1 or 2 to this subpart using initial performance testing and continuous monitoring with PM CPMS:
(i) You must demonstrate initial compliance no later than the applicable date specified in § 63.9984(f) for existing EGUs and in paragraph (g) of this section for new EGUs.
(ii) You must demonstrate continuous compliance with the PM CPMS site-specific operating limit that corresponding to the results of the performance test demonstrating compliance with the pollutant with which you choose to comply.
(iii) You must repeat the performance test annually for the selected pollutant emissions limit and reassess and adjust the site-specific operating limit in accordance with the results of the performance test.
(3) For affected EGUs that are either required to or elect to demonstrate initial compliance with the applicable Hg emission limit in Table 1 or 2 of this
(4) For affected liquid oil-fired EGUs that demonstrate compliance with the applicable emission limits for HCl or HF listed in Table 1 or 2 to this subpart using quarterly testing and continuous monitoring with a CMS:
(i) You must demonstrate initial compliance no later than the applicable date specified in § 63.9984 for existing EGUs and in paragraph (g) of this section for new EGUs.
(ii) You must demonstrate continuous compliance with the CMS site-specific operating limit that corresponding to the results of the performance test demonstrating compliance with the HCl or HF emissions limit.
(iii) You must repeat the performance test annually for the HCl or HF emissions limit and reassess and adjust the site-specific operating limit in accordance with the results of the performance test.
(e)
(f) For existing affected sources a tune-up may occur prior to April 16, 2012, so that existing sources without neural networks have up to 42 calendar months (3 years from promulgation plus 180 days) or, in the case of units employing neural network combustion controls, up to 54 calendar months (48 months from promulgation plus 180 days) after the date that is specified for your source in § 63.9984 and according to the applicable provisions in § 63.7(a)(2) as cited in Table 9 to this subpart to demonstrate compliance with this requirement. If a tune-up occurs prior to such date, the source must maintain adequate records to show that the tune-up met the requirements of this standard.
(g) If your new or reconstructed affected source commenced construction or reconstruction between May 3, 2011, and July 2, 2011, you must demonstrate initial compliance with either the proposed emission limits or the promulgated emission limits no later than 180 days after April 16, 2012 or within 180 days after startup of the source, whichever is later, according to § 63.7(a)(2)(ix).
(1) For the new or reconstructed affected source described in this paragraph (g), if you choose to comply with the proposed emission limits when demonstrating initial compliance, you must conduct a second compliance demonstration for the promulgated emission limits within 3 years after April 16, 2012 or within 3 years after startup of the affected source, whichever is later.
(2) If your new or reconstructed affected source commences construction or reconstruction after April 16, 2012, you must demonstrate initial compliance with the promulgated emission limits no later than 180 days after startup of the source.
(h)
(1) An EGU may qualify for low emitting EGU (LEE) status for Hg, HCl, HF, filterable PM, total non-Hg HAP metals, or individual non-Hg HAP metals (or total HAP metals or individual HAP metals, for liquid oil-fired EGUs) if you collect performance test data that meet the requirements of this paragraph (h), and if those data demonstrate:
(i) For all pollutants except Hg, performance test emissions results less than 50 percent of the applicable emissions limits in Table 1 or 2 to this subpart for all required testing for 3 consecutive years; or
(ii) For Hg emissions from an existing EGU, either:
(A) Average emissions less than 10 percent of the applicable Hg emissions limit in Table 2 to this subpart (expressed either in units of lb/TBtu or lb/GWh); or
(B) Potential Hg mass emissions of 29.0 or fewer pounds per year and compliance with the applicable Hg emission limit in Table 2 to this subpart (expressed either in units of lb/TBtu or lb/GWh).
(2) For all pollutants except Hg, you must conduct all required performance tests described in § 63.10007 to demonstrate that a unit qualifies for LEE status.
(i) When conducting emissions testing to demonstrate LEE status, you must increase the minimum sample volume specified in Table 1 or 2 nominally by a factor of two.
(ii) Follow the instructions in § 63.10007(e) and Table 5 to this subpart to convert the test data to the units of the applicable standard.
(3) For Hg, you must conduct a 30-boiler operating day performance test using Method 30B in appendix A-8 to part 60 of this chapter to determine whether a unit qualifies for LEE status. Locate the Method 30B sampling probe tip at a point within the 10 percent centroidal area of the duct at a location that meets Method 1 in appendix A-1 to part 60 of this chapter and conduct at least three nominally equal length test runs over the 30-boiler operating day test period. Collect Hg emissions data continuously over the entire test period (except when changing sorbent traps or performing required reference method QA procedures), under all process operating conditions. You may use a pair of sorbent traps to sample the stack gas for no more than 10 days.
(i) Depending on whether you intend to assess LEE status for Hg in terms of the lb/TBtu or lb/GWh emission limit in Table 2 to this subpart or in terms of the annual Hg mass emissions limit of 29.0 lb/year, you will have to collect some or all of the following data during the 30-boiler operating day test period (see paragraph (h)(3)(iii) of this section):
(A) Diluent gas (CO
(B) Stack gas flow rate data, using either Method 2, 2F, or 2G in appendices A-1 and A-2 to part 60 of this chapter, or a flow rate monitor that has been certified according to part 75 of this chapter.
(C) Stack gas moisture content data, using either Method 4 in appendix A-1 to part 60 of this chapter, or a moisture monitoring system that has been certified according to part 75 of this chapter. Alternatively, an appropriate fuel-specific default moisture value from § 75.11(b) of this chapter may be used in the calculations or you may petition the Administrator under § 75.66 of this chapter for use of a default moisture value for non-coal-fired units.
(D) Hourly electrical load data (megawatts), from facility records.
(ii) If you use CEMS to measure CO
(iii) Calculate the average Hg concentration, in µg/m
(A) To express the test results in units of lb/TBtu, follow the procedures in § 63.10007(e). Use the average Hg concentration and diluent gas values in the calculations.
(B) To express the test results in units of lb/GWh, use Equations A-3 and A-4 in section 6.2.2 of appendix A to this subpart, replacing the hourly values “C
(C) To calculate pounds of Hg per year, use one of the following methods:
(
(
(
(4) For a group of affected units that vent to a common stack, you may either assess LEE status for the units individually by performing a separate emission test of each unit in the duct leading from the unit to the common stack, or you may perform a single emission test in the common stack. If you choose the common stack testing option, the units in the configuration qualify for LEE status if:
(i) The emission rate measured at the common stack is less than 50 percent (10 percent for Hg) of the applicable emission limit in Table 1 or 2 to this subpart; or
(ii) For Hg from an existing EGU, the applicable Hg emission limit in Table 2 to this subpart is met and the potential annual mass emissions, calculated according to paragraph (h)(3)(iii) of this section (with some modifications), are less than or equal to 29.0 pounds times the number of units sharing the common stack. Base your calculations on the combined heat input capacity of all units sharing the stack (i.e., either the combined maximum rated value or, if applicable, a lower combined value restricted by permit conditions or operating hours).
(5) For an affected unit with a multiple stack or duct configuration in which the exhaust stacks or ducts are downstream of all emission control devices, you must perform a separate emission test in each stack or duct. The unit qualifies for LEE status if:
(i) The emission rate, based on all test runs performed at all of the stacks or ducts, is less than 50 percent (10 percent for Hg) of the applicable emission limit in Table 1 or 2 to this subpart; or
(ii) For Hg from an existing EGU, the applicable Hg emission limit in Table 2 to this subpart is met and the potential annual mass emissions, calculated according to paragraph (h)(3)(iii) of this section, are less than or equal to 29.0 pounds. Use the average Hg emission rate from paragraph (h)(5)(i) of this section in your calculations.
(i) Liquid-oil fuel moisture measurement. If your EGU combusts liquid fuels, if your fuel moisture content is no greater than 1.0 percent by weight, and if you would like to demonstrate initial and ongoing compliance with HCl and HF emissions limits, you must meet the requirements of paragraphs (i)(1) through (5) of this section.
(1) Measure fuel moisture content of each shipment of fuel if your fuel arrives on a batch basis; or
(2) Measure fuel moisture content daily if your fuel arrives on a continuous basis; or
(3) Obtain and maintain a fuel moisture certification from your fuel supplier.
(4) Use one of the following methods to determine fuel moisture content:
(i) ASTM D95-05 (Reapproved 2010), “Standard Test Method for Water in Petroleum Products and Bituminous Materials by Distillation,” or
(ii) ASTM D4006-11, “Standard Test Method for Water in Crude Oil by Distillation,” including Annex A1 and Appendix A1, or
(iii) ASTM D4177-95 (Reapproved 2010), “Standard Practice for Automatic Sampling of Petroleum and Petroleum Products,” including Annexes A1 through A6 and Appendices X1 and X2, or
(iv) ASTM D4057-06 (Reapproved 2011), “Standard Practice for Manual Sampling of Petroleum and Petroleum Products,” including Annex A1.
(5) Should the moisture in your liquid fuel be more than 1.0 percent by weight, you must
(i) Conduct HCl and HF emissions testing quarterly (and monitor site-specific operating parameters as provided in § 63.10000(c)(2)(iii) or
(ii) Use an HCl CEMS and/or HF CEMS.
(j) Startup and shutdown for coal-fired or solid oil derived-fired units. You must follow the requirements given in Table 3 to this subpart.
(k) You must submit a Notification of Compliance Status summarizing the results of your initial compliance demonstration, as provided in § 63.10030.
(a) For liquid oil-fired, solid oil-derived fuel- and coal-fired EGUs and IGCC units using PM CPMS to monitor continuous performance with an applicable emission limit as provided for under § 63.10000(c), you must conduct all applicable performance tests according to Table 5 to this subpart and § 63.10007 at least every year.
(b) For affected units meeting the LEE requirements of § 63.10005(h), you must repeat the performance test once every 3 years (once every year for Hg) according to Table 5 and § 63.10007. Should subsequent emissions testing results show the unit does not meet the LEE eligibility requirements, LEE status is lost. If this should occur:
(1) For all pollutant emission limits except for Hg, you must conduct emissions testing quarterly, except as otherwise provided in § 63.10021(d)(1).
(2) For Hg, you must install, certify, maintain, and operate a Hg CEMS or a sorbent trap monitoring system in accordance with appendix A to this subpart, within 6 calendar months of losing LEE eligibility. Until the Hg CEMS or sorbent trap monitoring system is installed, certified, and operating, you must conduct Hg emissions testing quarterly, except as otherwise provided in § 63.10021(d)(1). You must have 3 calendar years of testing and CEMS or
(c) Except where paragraphs (a) or (b) of this section apply, or where you install, certify, and operate a PM CEMS to demonstrate compliance with a filterable PM emission limit, for liquid oil-fired EGUs, you must conduct all applicable periodic emissions tests for filterable PM, or individual or total HAP metals emissions according to Table 5 to this subpart and § 63.10007 at least quarterly, except as otherwise provided in § 63.10021(d)(1).
(d) Except where paragraph (b) of this section applies, for solid oil-derived fuel- and coal-fired EGUs that do not use either an HCl CEMS to monitor compliance with the HCl limit or an SO
(e) Except where paragraph (b) of this section applies, for liquid oil-fired EGUs without HCl CEMS, HF CEMS, or HCl and HF CEMS, you must conduct all applicable emissions tests for HCl, HF, or HCl and HF emissions according to Table 5 to this subpart and § 63.10007 at least quarterly, except as otherwise provided in § 63.10021(d)(1), and conduct site-specific monitoring under a plan as provided for in § 63.10000(c)(2)(iii).
(f) Unless you follow the requirements listed in paragraphs (g) and (h) of this section, performance tests required at least every 3 calendar years must be completed within 35 to 37 calendar months after the previous performance test; performance tests required at least every year must be completed within 11 to 13 calendar months after the previous performance test; and performance tests required at least quarterly must be completed within 80 to 100 calendar days after the previous performance test, except as otherwise provided in § 63.10021(d)(1).
(g) If you elect to demonstrate compliance using emissions averaging under § 63.10009, you must continue to conduct performance stack tests at the appropriate frequency given in section (c) through (f) of this section.
(h) If a performance test on a non-mercury LEE shows emissions in excess of 50 percent of the emission limit and if you choose to reapply for LEE status, you must conduct performance tests at the appropriate frequency given in section (c) through (e) of this section for that pollutant until all performance tests over a consecutive 3-year period show compliance with the LEE criteria.
(i) If you are required to meet an applicable tune-up work practice standard, you must conduct a performance tune-up according to § 63.10021(e).
(1) For EGUs not employing neural network combustion optimization during normal operation, each performance tune-up specified in § 63.10021(e) must be no more than 36 calendar months after the previous performance tune-up.
(2) For EGUs employing neural network combustion optimization systems during normal operation, each performance tune-up specified in § 63.10021(e) must be no more than 48 calendar months after the previous performance tune-up.
(j) You must report the results of performance tests and performance tune-ups within 60 days after the completion of the performance tests and performance tune-ups. The reports for all subsequent performance tests must include all applicable information required in § 63.10031.
(a) Except as otherwise provided in this section, you must conduct all required performance tests according to § 63.7(d), (e), (f), and (h). You must also develop a site-specific test plan according to the requirements in § 63.7(c).
(1) If you use CEMS (Hg, HCl, SO
(2) If you conduct performance testing with test methods in lieu of continuous monitoring, operate the unit at maximum normal operating load conditions during each periodic (
(3) For establishing operating limits with particulate matter continuous parametric monitoring system (PM CPMS) to demonstrate compliance with a PM or non Hg metals emissions limit, operate the unit at maximum normal operating load conditions during the performance test period. Maximum normal operating load will be generally between 90 and 110 percent of design capacity but should be representative of site specific normal operations during each test run.
(b) You must conduct each performance test (including traditional 3-run stack tests, 30-boiler operating day tests based on CEMS data (or sorbent trap monitoring system data), and 30-boiler operating day Hg emission tests for LEE qualification) according to the requirements in Table 5 to this subpart.
(c) If you choose to comply with the filterable PM emission limit and demonstrate continuous performance using a PM CPMS for an applicable emission limit as provided for in § 63.10000(c), you must also establish an operating limit according to § 63.10011(b)(5) and Tables 4 and 6 to this subpart. Should you desire to have operating limits that correspond to loads other than maximum normal operating load, you must conduct testing at those other loads to determine the additional operating limits.
(d) Except for a 30-boiler operating day performance test based on CEMS (or sorbent trap monitoring system) data, where the concept of test runs does not apply, you must conduct a minimum of three separate test runs for each performance test, as specified in § 63.7(e)(3). Each test run must comply with the minimum applicable sampling time or volume specified in Table 1 or 2 to this subpart. Sections 63.10005(d) and (h), respectively, provide special instructions for conducting performance tests based on CEMS or sorbent trap monitoring systems, and for conducting emission tests for LEE qualification.
(e) To use the results of performance testing to determine compliance with the applicable emission limits in Table 1 or 2 to this subpart, proceed as follows:
(1) Except for a 30-boiler operating day performance test based on CEMS (or sorbent trap monitoring system) data, if measurement results for any pollutant are reported as below the method detection level (
(2) If the limits are expressed in lb/MMBtu or lb/TBtu, you must use the F-factor methodology and equations in
(i) Multiply SO
(ii) Multiply HCl ppm by 9.43 × 10
(iii) Multiply HF ppm by 5.18 × 10
(iv) Multiply HAP metals concentrations (mg/dscm) by 6.24 × 10
(v) Multiply Hg concentrations (µg/scm) by 6.24 × 10
(3) To determine compliance with emission limits expressed in lb/MWh or lb/GWh, you must first calculate the pollutant mass emission rate during the performance test, in units of lb/h. For Hg, if a CEMS or sorbent trap monitoring system is used, use Equation A-2 or A-3 in appendix A to this subpart (as applicable). In all other cases, use an equation that has the general form of Equation A-2 or A-3, replacing the value of K with 1.66 × 10
(f) Upon request, you shall make available to the EPA Administrator such records as may be necessary to determine whether the performance tests have been done according to the requirements of this section.
(a)
(i) You have more than one existing EGU in the same subcategory located at one or more contiguous properties, belonging to a single major industrial grouping, which are under common control of the same person (or persons under common control); and
(ii) You use CEMS (or sorbent trap monitoring systems for determining Hg emissions) or quarterly emissions testing for demonstrating compliance.
(2) You may demonstrate compliance by emissions averaging among the existing EGUs in the same subcategory, if your averaged Hg emissions for EGUs in the “unit designed for coal ≥ 8,300 Btu/lb” subcategory are equal to or less than 1.0 lb/TBtu or 1.1E-2 lb/GWh or if your averaged emissions of individual, other pollutants from other subcategories of such EGUs are equal to or less than the applicable emissions limit in Table 2, according to the procedures in this section. Note that except for Hg emissions from EGUs in the “unit designed for coal ≥ 8,300 Btu/lb” subcategory, the averaging time for emissions averaging for pollutants is 30 days (rolling daily) using data from CEMS or a combination of data from CEMS and manual performance testing. The averaging time for emissions averaging for Hg from EGUs in the “unit designed for coal ≥ 8,300 Btu/lb” subcategory is 90 days (rolling daily) using data from CEMS, sorbent trap monitoring, or a combination of monitoring data and data from manual performance testing. For the purposes of this paragraph, 30- (or 90-day) group boiler operating days is defined as a period during which at least one unit in the emissions averaging group has operated 30 (or 90) days. You must calculate the weighted average emissions rate for the group in accordance with the procedures in this paragraph using the data from all units in the group including any that operate fewer than 30 (or 90) days during the preceding 30 (or 90) group boiler days.
(i) You may choose to have your EGU emissions averaging group meet either the heat input basis (MMBtu or TBtu, as appropriate for the pollutant) or gross electrical output basis (MWh or GWh, as appropriate for the pollutant).
(ii) You may not mix bases within your EGU emissions averaging group.
(iii) You may use emissions averaging for affected units in different subcategories if the units vent to the atmosphere through a common stack (see paragraph (m) of this section).
(b)
(1)
(2) Weighted 30-day rolling average emissions rate equations for pollutants other than Hg. Use equation 2a or 2b to calculate the 30-day rolling average emissions daily.
(3) Weighted 90-boiler operating day rolling average emissions rate equations for Hg emissions from EGUs in the “unit designed for coal ≥ 8,300 Btu/lb” subcategory. Use equation 3a or 3b to calculate the 90-day rolling average emissions daily.
(c)
(d) For each existing EGU in the averaging group:
(1) The emissions rate achieved during the initial performance test for the HAP being averaged must not exceed the emissions level that was being achieved 180 days after April 16, 2015, or the date on which emissions testing done to support your emissions averaging plan is complete (if the Administrator does not require submission and approval of your emissions averaging plan), or the date that you begin emissions averaging, whichever is earlier; or
(2) The control technology employed during the initial performance test must not be less than the design efficiency of the emissions control technology employed 180 days after April 16, 2015 or the date that you begin emissions averaging, whichever is earlier.
(e) The weighted-average emissions rate from the existing EGUs participating in the emissions averaging option must be in compliance with the limits in Table 2 to this subpart at all times following the compliance date specified 180 days after April 16, 2015, or the date on which you complete the emissions measurements used to support your emissions averaging plan (if the Administrator does not require submission and approval of your emissions averaging plan), or the date that you begin emissions averaging, whichever is earlier.
(f) Emissions averaging group eligibility demonstration. You must demonstrate the ability for the EGUs included in the emissions averaging group to demonstrate initial compliance according to paragraph (f)(1) or (2) of this section using the maximum normal operating load of each EGU and the results of the initial performance tests. For this demonstration and prior to submitting your emissions averaging plan, if requested, you must conduct required emissions monitoring for 30 days of boiler operation and any required manual performance testing to calculate an initial weighted average emissions rate in accordance with this section. Should the Administrator require approval, you must submit your proposed emissions averaging plan and supporting data at least 120 days before April 16, 2015. If the Administrator requires approval of your plan, you may not begin using emissions averaging until the Administrator approves your plan.
(1) You must use Equation 1a in paragraph (b) of this section to demonstrate that the maximum weighted average emissions rates of filterable PM, HF, SO
(2) If you are not capable of monitoring heat input or gross electrical output, and the EGU generates steam for purposes other than generating electricity, you may use Equation 1b of this section as an alternative to using Equation 1a of this section to demonstrate that the maximum weighted average emissions rates of filterable PM, HF, SO
(g) You must determine the weighted average emissions rate in units of the applicable emissions limit on a 30 day rolling average (90 day rolling average for Hg) basis according to paragraphs (f)(1) through (3) of this section. The first averaging period begins on 30 (or 90 for Hg) days after February 16, 2015 or the date that you begin emissions averaging, whichever is earlier.
(1) You must use Equation 2a or 3a of paragraph (b) of this section to calculate the weighted average emissions rate using the actual heat input or gross electrical output for each existing unit participating in the emissions averaging option.
(2) If you are not capable of monitoring heat input or gross electrical output, you may use Equation 2b or 3b of paragraph (b) of this section as an alternative to using Equation 2a of paragraph (b) of this section to calculate the average weighted emission rate using the actual steam generation from the units participating in the emissions averaging option.
(h)
(i)
(j)
(1) You must include the information contained in paragraphs (j)(1)(i) through (v) of this section in your implementation plan for all the emissions units included in an emissions averaging:
(i) The identification of all existing EGUs in the emissions averaging group, including for each either the applicable HAP emission level or the control technology installed as of 180 days after February 16, 2015, or the date on which you complete the emissions measurements used to support your emissions averaging plan (if the Administrator does not require submission and approval of your emissions averaging plan), or the date that you begin emissions averaging, whichever is earlier; and the date on which you are requesting emissions averaging to commence;
(ii) The process weighting parameter (heat input, gross electrical output, or steam generated) that will be monitored for each averaging group;
(iii) The specific control technology or pollution prevention measure to be used for each emission EGU in the averaging group and the date of its installation or application. If the pollution prevention measure reduces or eliminates
(iv) The means of measurement (
(v) A demonstration that emissions averaging can produce compliance with each of the applicable emission limit(s) in accordance with paragraph (b)(1) of this section.
(2) If the Administrator requests you to submit the plan for review and approval, you must submit a complete implementation plan at least 120 days before April 16, 2015. If the Administrator requests you to submit the plan for review and approval, you must receive approval before initiating emissions averaging.
(i) The Administrator shall use following criteria in reviewing and approving or disapproving the plan:
(A) Whether the content of the plan includes all of the information specified in paragraph (h)(1) of this section; and
(B) Whether the plan presents information sufficient to determine that compliance will be achieved and maintained.
(ii) The Administrator shall not approve an emissions averaging implementation plan containing any of the following provisions:
(A) Any averaging between emissions of different pollutants or between units located at different facilities; or
(B) The inclusion of any emissions unit other than an existing unit in the same subcategory.
(k)
(l) For a group of two or more existing units in the same subcategory and which vent through a common emissions control system to a common stack that does not receive emissions from units in other subcategories or categories, you may treat such averaging group as a single existing unit for purposes of this subpart and comply with the requirements of this subpart as if the group were a single unit.
(m) For all other groups of units subject to paragraph (k) of this section, you may elect to conduct manual performance tests according to procedures specified in § 63.10007 in the common stack. If emissions from affected units included in the emissions averaging and from other units not included in the emissions averaging (
(n) Combination requirements. The common stack of a group of two or more existing EGUs in the same subcategory subject to paragraph (k) of this section may be treated as a single stack for purposes of paragraph (c) of this section and included in an emissions averaging group subject to paragraph (c) of this section.
(a) Flue gases from the affected units under this subpart exhaust to the atmosphere through a variety of different configurations, including but not limited to individual stacks, a common stack configuration or a main stack plus a bypass stack. For the CEMS, PM CPMS, and sorbent trap monitoring systems used to provide data under this subpart, the continuous monitoring system installation requirements for these exhaust configurations are as follows:
(1)
(2)
(i) Install the required CEMS, PM CPMS, and sorbent trap monitoring systems in the duct leading to the common stack from each unit; or
(ii) Install the required CEMS, PM CPMS, and sorbent trap monitoring systems in the common stack.
(3)
(i) When one or more affected units shares a common stack with one or more non-affected units, you shall either:
(A) Install the required CEMS, PM CPMS, and sorbent trap monitoring systems in the ducts leading to the common stack from each affected unit; or
(B) Install the required CEMS, PM CPMS, and sorbent trap monitoring systems described in this section in the common stack and attribute all of the emissions measured at the common stack to the affected unit(s).
(ii) If you choose the common stack monitoring option:
(A) For each hour in which valid data are obtained for all parameters, you must calculate the pollutant emission rate and
(B) You must assign the calculated pollutant emission rate to each unit that shares the common stack.
(4)
(5)
(i) Install required CEMS, PM CPMS, and sorbent trap monitoring systems in each of the multiple stacks;
(ii) Install required CEMS, PM CPMS, and sorbent trap monitoring systems in each of the ducts that feed into the stack;
(iii) Install required CEMS, PM CPMS, and sorbent trap monitoring systems in one of the multiple stacks or ducts and monitor the flows and dilution rates in all multiple stacks or ducts in order to determine total exhaust gas flow rate and pollutant mass emissions rate in accordance with the applicable limit; or
(iv) In the case of multiple ducts feeding into a single stack, install CEMS, PM CPMS, and sorbent trap
(6)
(i) Calculate the pollutant emission rate at each stack or duct for each hour in which valid data are obtained for all parameters;
(ii) Multiply each calculated hourly pollutant emission rate at each stack or duct by the corresponding hourly stack gas flow rate at that stack or duct;
(iii) Sum the products determined under paragraph (a)(5)(iii)(B) of this section; and
(iv) Divide the result obtained in paragraph (a)(5)(iii)(C) of this section by the total hourly stack gas flow rate for the unit, summed across all of the stacks or ducts.
(b) If you use an oxygen (O
(c) If you are required to use a stack gas flow rate monitor, either for routine operation of a sorbent trap monitoring system or to convert pollutant concentrations to units of an electrical output-based emission standard in Table 1 or 2 to this subpart, you must install, certify, operate, and maintain the monitoring system and conduct on-going quality-assurance testing of the system according to part 75 of this chapter. Use only unadjusted, quality-assured flow rate data in the emissions calculations. Do not apply bias adjustment factors to the flow rate data and do not use substitute flow rate data in the calculations.
(d) If you are required to make corrections for stack gas moisture content when converting pollutant concentrations to the units of an emission standard in Table 1 of 2 to this subpart, you must install, certify, operate, and maintain a moisture monitoring system in accordance with part 75 of this chapter. Alternatively, for coal-fired units, you may use appropriate fuel-specific default moisture values from § 75.11(b) of this chapter to estimate the moisture content of the stack gas or you may petition the Administrator under § 75.66 of this chapter for use of a default moisture value for non-coal-fired units. If you install and operate a moisture monitoring system, do not use substitute moisture data in the emissions calculations.
(e) If you use an HCl and/or HF CEMS, you must install, certify, operate, maintain, and quality-assure the data from the monitoring system in accordance with appendix B to this subpart. Calculate and record a 30-boiler operating day rolling average HCl or HF emission rate in the units of the standard, updated after each new boiler operating day. Each 30-boiler operating day rolling average emission rate is the average of all the valid hourly HCl or HF emission rates in the preceding 30 boiler operating days (see section 9.4 of appendix B to this subpart).
(f)(1) If you use an SO
(2) For on-going QA, the SO
(3) Calculate and record a 30-boiler operating day rolling average SO
(4) Use only unadjusted, quality-assured SO
(g) If you use a Hg CEMS or a sorbent trap monitoring system, you must install, certify, operate, maintain and quality-assure the data from the monitoring system in accordance with appendix A to this subpart. You must calculate and record a 30-boiler operating day rolling average Hg emission rate, in units of the standard, updated after each new boiler operating day. Each 30-boiler operating day rolling average emission rate, calculated according to section 6.2 of appendix A to the subpart, is the average of all of the valid hourly Hg emission rates in the preceding 30 boiler operating days. Section 7.1.4.3 of appendix A to this subpart explains how to reduce sorbent trap monitoring system data to an hourly basis.
(h) If you use a PM CPMS to demonstrate continuous compliance with an operating limit, you must install, calibrate, maintain, and operate the PM CPMS and record the output of the system as specified in paragraphs (h)(1) through (5) of this section.
(1) Install, calibrate, operate, and maintain your PM CPMS according to the procedures in your approved site-specific monitoring plan developed in accordance with § 63.10000(d), and meet the requirements in paragraphs (h)(1)(i) through (iii) of this section.
(i) The operating principle of the PM CPMS must be based on in-stack or extractive light scatter, light scintillation, beta attenuation, or mass accumulation detection of the exhaust gas or representative sample. The reportable measurement output from the PM CPMS may be expressed as milliamps, stack concentration, or other raw data signal.
(ii) The PM CPMS must have a cycle time (
(iii) The PM CPMS must be capable, at a minimum, of detecting and responding to particulate matter concentrations of 0.5 mg/acm.
(2) For a new unit, complete the initial PM CPMS performance evaluation no later than October 13, 2012 or 180 days after the date of initial startup, whichever is later. For an existing unit, complete the initial performance evaluation no later than October 13, 2015.
(3) Collect PM CPMS hourly average output data for all boiler operating hours except as indicated in paragraph (h)(5) of this section. Express the PM CPMS output as milliamps, PM concentration, or other raw data signal value.
(4) Calculate the arithmetic 30-boiler operating day rolling average of all of the hourly average PM CPMS output collected during all nonexempt boiler operating hours data (
(5) You must collect data using the PM CPMS at all times the process unit is operating and at the intervals specified in paragraph (h)(1)(ii) of this section, except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, required monitoring system quality assurance or quality control activities (including, as applicable, calibration checks and required zero and span adjustments), and any scheduled maintenance as defined in your site-specific monitoring plan.
(6) You must use all the data collected during all boiler operating hours in assessing the compliance with your operating limit except:
(i) Any data collected during monitoring system malfunctions, repairs associated with monitoring system malfunctions, or required monitoring system quality assurance or quality control activities conducted during monitoring system malfunctions are not used in calculations (report any such periods in your annual deviation report);
(ii) Any data collected during periods when the monitoring system is out of control as specified in your site-specific monitoring plan, repairs associated with periods when the monitoring system is out of control, or required monitoring system quality assurance or quality control activities conducted during out-of-control periods are not used in calculations (report emissions or operating levels and report any such periods in your annual deviation report);
(iii) Any data recorded during periods of startup or shutdown.
(7) You must record and make available upon request results of PM CPMS system performance audits, as well as the dates and duration of periods from when the PM CPMS is out of control until completion of the corrective actions necessary to return the PM CPMS to operation consistent with your site-specific monitoring plan.
(i) If you choose to comply with the PM filterable emissions limit in lieu of metal HAP limits, you may choose to install, certify, operate, and maintain a PM CEMS and record the output of the PM CEMS as specified in paragraphs (i)(1) through (5) of this section. The compliance limit will be expressed as a 30-boiler operating day rolling average of the numerical emissions limit value applicable for your unit in tables 1 or 2 to this subpart.
(1) Install and certify your PM CEMS according to the procedures and requirements in Performance Specification 11—Specifications and Test Procedures for Particulate Matter Continuous Emission Monitoring Systems at Stationary Sources in Appendix B to part 60 of this chapter, using Method 5 at Appendix A-3 to part 60 of this chapter and ensuring that the front half filter temperature shall be 160° ± 14°C (320° ± 25°F). The reportable measurement output from the PM CEMS must be expressed in units of the applicable emissions limit (
(2) Operate and maintain your PM CEMS according to the procedures and requirements in Procedure 2—Quality Assurance Requirements for Particulate Matter Continuous Emission Monitoring Systems at Stationary Sources in Appendix F to part 60 of this chapter.
(i) You must conduct the relative response audit (RRA) for your PM CEMS at least once annually.
(ii) You must conduct the relative correlation audit (RCA) for your PM CEMS at least once every 3 years.
(3) Collect PM CEMS hourly average output data for all boiler operating hours except as indicated in paragraph (i) of this section.
(4) Calculate the arithmetic 30-boiler operating day rolling average of all of the hourly average PM CEMS output data collected during all nonexempt boiler operating hours.
(5) You must collect data using the PM CEMS at all times the process unit is operating and at the intervals specified in paragraph (a) of this section, except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, and required monitoring system quality assurance or quality control activities.
(i) You must use all the data collected during all boiler operating hours in assessing the compliance with your operating limit except:
(A) Any data collected during monitoring system malfunctions, repairs associated with monitoring system malfunctions, or required monitoring system quality assurance or control activities conducted during monitoring system malfunctions in calculations and report any such periods in your annual deviation report;
(B) Any data collected during periods when the monitoring system is out of control as specified in your site-specific monitoring plan, repairs associated with periods when the monitoring system is out of control, or required monitoring system quality assurance or control activities conducted during out of control periods in calculations used to report emissions or operating levels and report any such periods in your annual deviation report;
(C) Any data recorded during periods of startup or shutdown.
(ii) You must record and make available upon request results of PM CEMS system performance audits, dates and duration of periods when the PM CEMS is out of control to completion of the corrective actions necessary to return the PM CEMS to operation consistent with your site-specific monitoring plan.
(j) You may choose to comply with the metal HAP emissions limits using CEMS approved in accordance with § 63.7(f) as an alternative to the performance test method specified in this rule. If approved to use a HAP metals CEMS, the compliance limit will be expressed as a 30-boiler operating day rolling average of the numerical emissions limit value applicable for your unit in tables 1 or 2. If approved, you may choose to install, certify, operate, and maintain a HAP metals CEMS and record the output of the HAP metals CEMS as specified in paragraphs (j)(1) through (5) of this section.
(1)(i) Install and certify your HAP metals CEMS according to the procedures and requirements in you approved site specific test plan as required in § 63.7(e). The reportable measurement output from the HAP metals CEMS must be expressed in units of the applicable emissions limit (
(ii) Operate and maintain your HAP metals CEMS according to the procedures and criteria in your site specific performance evaluation and quality control program plan required in § 63.8(d).
(2) Collect HAP metals CEMS hourly average output data for all boiler operating hours except as indicated in section (j)(4) of this section.
(3) Calculate the arithmetic 30-boiler operating day rolling average of all of the hourly average HAP metals CEMS output data collected during all nonexempt boiler operating hours data.
(4) You must collect data using the HAP metals CEMS at all times the process unit is operating and at the intervals specified in paragraph (a) of this section, except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, and required monitoring system quality assurance or quality control activities.
(i) You must use all the data collected during all boiler operating hours in assessing the compliance with your emission limit except:
(A) Any data collected during monitoring system malfunctions, repairs associated with monitoring system malfunctions, or required monitoring
(B) Any data collected during periods when the monitoring system is out of control as specified in your site-specific monitoring plan, repairs associated with periods when the monitoring system is out of control, or required monitoring system quality assurance or control activities conducted during out of control periods in calculations used to report emissions or operating levels and report any such periods in your annual deviation report;
(C) Any data recorded during periods of startup or shutdown.
(ii) You must record and make available upon request results of HAP metals CEMS system performance audits, dates and duration of periods when the HAP metals CEMS is out of control to completion of the corrective actions necessary to return the HAP metals CEMS to operation consistent with your site-specific performance evaluation and quality control program plan.
(k) If you demonstrate compliance with the HCl and HF emission limits for a liquid oil-fired EGU by conducting quarterly testing, you must also develop a site-specific monitoring plan as provided for in § 63.10000(c)(2)(iii) and Table 7 to this subpart.
(a) You must demonstrate initial compliance with each emissions limit that applies to you by conducting performance testing.
(b) If you are subject to an operating limit in Table 4 to this subpart, you demonstrate initial compliance with HAP metals or filterable PM emission limit(s) through performance stack tests and you elect to use a PM CPMS to demonstrate continuous performance, or if, for a liquid oil-fired unit, and you use quarterly stack testing for HCl and HF plus site-specific parameter monitoring to demonstrate continuous performance, you must also establish a site-specific operating limit, in accordance with Table 4 to this subpart, § 63.10007, and Table 6 to this subpart. You may use only the parametric data recorded during successful performance tests (
(c)(1) If you use CEMS or sorbent trap monitoring systems to measure a HAP (
(2) For a unit that uses a CEMS to measure SO
(d) For candidate LEE units, use the results of the performance testing described in § 63.10005(h) to determine initial compliance with the applicable emission limit(s) in Table 1 or 2 to this subpart and to determine whether the unit qualifies for LEE status.
(e) You must submit a Notification of Compliance Status containing the results of the initial compliance demonstration, according to § 63.10030(e).
(f)(1) You must determine the fuel whose combustion produces the least uncontrolled emissions,
(2) Your cleanest fuel, either natural gas or distillate oil, for use during periods of startup or shutdown determination may take safety considerations into account.
(g) You must follow the startup or shutdown requirements given in Table 3 for each coal-fired, liquid oil-fired, and solid oil-derived fuel-fired EGU.
(a) You must monitor and collect data according to this section and the site-specific monitoring plan required by § 63.10000(d).
(b) You must operate the monitoring system and collect data at all required intervals at all times that the affected EGU is operating, except for periods of monitoring system malfunctions or out-of-control periods (see § 63.8(c)(7) of this part), and required monitoring system quality assurance or quality control activities, including, as applicable, calibration checks and required zero and span adjustments. You are required to affect monitoring system repairs in response to monitoring system malfunctions and to return the monitoring system to operation as expeditiously as practicable.
(c) You may not use data recorded during EGU startup or shutdown or monitoring system malfunctions or monitoring system out-of-control periods, repairs associated with monitoring system malfunctions or monitoring system out-of-control periods, or required monitoring system quality assurance or control activities in calculations used to report emissions or operating levels. You must use all the data collected during all other periods in assessing the operation of the control device and associated control system.
(d) Except for periods of monitoring system malfunctions or monitoring system out-of-control periods, repairs associated with monitoring system malfunctions or monitoring system out-of-control periods, and required monitoring system quality assurance or quality control activities including, as applicable, calibration checks and required zero and span adjustments), failure to collect required data is a deviation of the monitoring requirements.
(a) You must demonstrate continuous compliance with each emissions limit, operating limit, and work practice standard in Tables 1 through 4 to this subpart that applies to you, according to the monitoring specified in Tables 6 and 7 to this subpart and paragraphs (b) through (g) of this section.
(b) Except as otherwise provided in § 63.10020(c), if you use a CEMS to measure SO
(c) If you use a PM CPMS data to measure compliance with an operating limit in Table 4 to this subpart, you must record the PM CPMS output data for all periods when the process is operating and the PM CPMS is not out-of-control. You must demonstrate continuous compliance by using all quality-assured hourly average data collected by the PM CPMS for all operating hours to calculate the arithmetic average operating parameter in units of the operating limit (
(d) If you use quarterly performance testing to demonstrate compliance with one or more applicable emissions limits in Table 1 or 2 to this subpart, you
(1) May skip performance testing in those quarters during which less than 168 boiler operating hours occur, except that a performance test must be conducted at least once every calendar year.
(2) Must conduct the performance test as defined in Table 5 to this subpart and calculate the results of the testing in units of the applicable emissions standard; and
(3) Must conduct site-specific monitoring for a liquid oil-fired unit to ensure compliance with the HCl and HF emission limits in Tables 1 and 2 to this subpart, in accordance with the requirements of § 63.10000(c)(2)(iii). The monitoring must meet the general operating requirements provided in § 63.10020(a).
(e) If you must conduct periodic performance tune-ups of your EGU(s), as specified in paragraphs (e)(1) through (9) of this section, perform the first tune-up as part of your initial compliance demonstration. Notwithstanding this requirement, you may delay the first burner inspection until the next scheduled unit outage provided you meet the requirements of § 63.10005. Subsequently, you must perform an inspection of the burner at least once every 36 calendar months unless your EGU employs neural network combustion optimization during normal operations in which case you must perform an inspection of the burner and combustion controls at least once every 48 calendar months.
(1) As applicable, inspect the burner and combustion controls, and clean or replace any components of the burner or combustion controls as necessary upon initiation of the work practice program and at least once every required inspection period. Repair of a burner or combustion control component requiring special order parts may be scheduled as follows:
(i) Burner or combustion control component parts needing replacement that affect the ability to optimize NO
(ii) Burner or combustion control component parts that do not affect the ability to optimize NO
(2) As applicable, inspect the flame pattern and make any adjustments to the burner or combustion controls necessary to optimize the flame pattern. The adjustment should be consistent with the manufacturer's specifications, if available, or in accordance with best combustion engineering practice for that burner type;
(3) As applicable, observe the damper operations as a function of mill and/or cyclone loadings, cyclone and pulverizer coal feeder loadings, or other pulverizer and coal mill performance parameters, making adjustments and effecting repair to dampers, controls, mills, pulverizers, cyclones, and sensors;
(4) As applicable, evaluate windbox pressures and air proportions, making adjustments and effecting repair to dampers, actuators, controls, and sensors;
(5) Inspect the system controlling the air-to-fuel ratio and ensure that it is correctly calibrated and functioning properly. Such inspection may include calibrating excess O
(6) Optimize combustion to minimize generation of CO and NO
(7) While operating at full load or the predominantly operated load, measure the concentration in the effluent stream of CO and NO
(8) Maintain on-site and submit, if requested by the Administrator, an annual report containing the information in paragraphs (e)(1) through (e)(9) of this section including:
(i) The concentrations of CO and NO
(ii) A description of any corrective actions taken as a part of the combustion adjustment; and
(iii) The type(s) and amount(s) of fuel used over the 12 calendar months prior to an adjustment, but only if the unit was physically and legally capable of using more than one type of fuel during that period; and
(9) Report the dates of the initial and subsequent tune-ups as follows:
(i) If the first required tune-up is performed as part of the initial compliance demonstration, report the date of the tune-up in hard copy (as specified in § 63.10030) and electronically (as specified in § 63.10031). Report the date of each subsequent tune-up electronically (as specified in § 63.10031).
(ii) If the first tune-up is not conducted as part of the initial compliance demonstration, but is postponed until the next unit outage, report the date of that tune-up and all subsequent tune-ups electronically, in accordance with § 63.10031.
(f) You must submit the reports required under § 63.10031 and, if applicable, the reports required under appendices A and B to this subpart. The electronic reports required by appendices A and B to this subpart must be sent to the Administrator electronically in a format prescribed by the Administrator, as provided in § 63.10031. CEMS data (except for PM CEMS and any approved alternative monitoring using a HAP metals CEMS) shall be submitted using EPA's Emissions Collection and Monitoring Plan System (ECMPS) Client Tool. Other data, including PM CEMS data, HAP metals CEMS data, and CEMS performance test detail reports, shall be submitted in the file format generated through use of EPA's Electronic Reporting Tool, the Compliance and Emissions Data Reporting Interface, or alternate electronic file format, all as provided for under § 63.10031.
(g) You must report each instance in which you did not meet an applicable emissions limit or operating limit in Tables 1 through 4 to this subpart or failed to conduct a required tune-up. These instances are deviations from the requirements of this subpart. These deviations must be reported according to § 63.10031.
(h) You must keep records as specified in § 63.10032 during periods of startup and shutdown.
(i) You must provide reports as specified in § 63.10031 concerning activities and periods of startup and shutdown.
(a) Following the compliance date, the owner or operator must demonstrate compliance with this subpart on a continuous basis by meeting the requirements of paragraphs (a)(1) through (3) of this section.
(1) For each calendar month, demonstrate compliance with the average weighted emissions limit for the existing units participating in the emissions averaging option as determined in § 63.10009(f) and (g);
(2) For each existing unit participating in the emissions averaging option that is equipped with PM CPMS, maintain the average parameter value at or below the operating limit established during the most recent performance test;
(3) For each existing unit participating in the emissions averaging option venting to a common stack configuration containing affected units from other subcategories, maintain the appropriate operating limit for each unit as specified in Table 4 to this subpart that applies.
(b) Any instance where the owner or operator fails to comply with the continuous monitoring requirements in paragraphs (a)(1) through (3) of this section is a deviation.
(a) During the initial performance test or any such subsequent performance test that demonstrates compliance with the filterable PM, individual non-mercury HAP metals, or total non-mercury HAP metals limit (or for liquid oil-fired units, individual HAP metals or total HAP metals limit, including Hg) in Table 1 or 2, record all hourly average output values (
(b) Determine your operating limit as the highest 1-hour average PM CPMS output value recorded during the performance test. You must verify an existing or establish a new operating limit after each repeated performance test.
(c) You must operate and maintain your process and control equipment such that the 30 operating day average PM CPMS output does not exceed the operating limit determined in paragraphs (a) and (b) of this section.
(a) You must submit all of the notifications in §§ 63.7(b) and (c), 63.8 (e), (f)(4) and (6), and 63.9 (b) through (h) that apply to you by the dates specified.
(b) As specified in § 63.9(b)(2), if you startup your affected source before April 16, 2012, you must submit an Initial Notification not later than 120 days after April 16, 2012.
(c) As specified in § 63.9(b)(4) and (b)(5), if you startup your new or reconstructed affected source on or after April 16, 2012, you must submit an Initial Notification not later than 15 days after the actual date of startup of the affected source.
(d) When you are required to conduct a performance test, you must submit a Notification of Intent to conduct a performance test at least 30 days before the performance test is scheduled to begin.
(e) When you are required to conduct an initial compliance demonstration as specified in § 63.10011(a), you must submit a Notification of Compliance Status according to § 63.9(h)(2)(ii). The Notification of Compliance Status report must contain all the information specified in paragraphs (e)(1) through (7), as applicable.
(1) A description of the affected source(s) including identification of which subcategory the source is in, the design capacity of the source, a description of the add-on controls used on the source, description of the fuel(s) burned, including whether the fuel(s) were determined by you or EPA through a petition process to be a non-waste under 40 CFR 241.3, whether the fuel(s) were processed from discarded non-hazardous secondary materials within the meaning of 40 CFR 241.3, and justification for the selection of fuel(s) burned during the performance test.
(2) Summary of the results of all performance tests and fuel analyses and calculations conducted to demonstrate initial compliance including all established operating limits.
(3) Identification of whether you plan to demonstrate compliance with each applicable emission limit through performance testing; fuel moisture analyses; performance testing with operating limits (
(4) Identification of whether you plan to demonstrate compliance by emissions averaging.
(5) A signed certification that you have met all applicable emission limits and work practice standards.
(6) If you had a deviation from any emission limit, work practice standard, or operating limit, you must also submit a brief description of the deviation, the duration of the deviation, emissions point identification, and the cause of the deviation in the Notification of Compliance Status report.
(7) In addition to the information required in § 63.9(h)(2), your notification of compliance status must include the following:
(i) A summary of the results of the annual performance tests and documentation of any operating limits that were reestablished during this test, if applicable. If you are conducting stack tests once every 3 years consistent with § 63.10006(i), the date of the last three stack tests, a comparison of the emission level you achieved in the last three stack tests to the 50 percent emission limit threshold required in § 63.10006(i), and a statement as to whether there have been any operational changes since the last stack test that could increase emissions.
(ii) Certifications of compliance, as applicable, and must be signed by a responsible official stating:
(A) “This EGU complies with the requirements in § 63.10021(a) to demonstrate continuous compliance.” and
(B) “No secondary materials that are solid waste were combusted in any affected unit.”
(a) You must submit each report in Table 8 to this subpart that applies to you. If you are required to (or elect to) continuously monitor Hg and/or HCl and/or HF emissions, you must also submit the electronic reports required under appendix A and/or appendix B to the subpart, at the specified frequency.
(b) Unless the Administrator has approved a different schedule for submission of reports under § 63.10(a), you must submit each report by the date in Table 8 to this subpart and according to the requirements in paragraphs (b)(1) through (5) of this section.
(1) The first compliance report must cover the period beginning on the compliance date that is specified for your affected source in § 63.9984 and ending on June 30 or December 31, whichever date is the first date that occurs at least 180 days after the compliance date that is specified for your source in § 63.9984.
(2) The first compliance report must be postmarked or submitted electronically no later than July 31 or January 31, whichever date is the first date following the end of the first calendar half after the compliance date that is specified for your source in § 63.9984.
(3) Each subsequent compliance report must cover the semiannual reporting period from January 1 through June 30 or the semiannual reporting period from July 1 through December 31.
(4) Each subsequent compliance report must be postmarked or submitted electronically no later than July 31 or January 31, whichever date is the first date following the end of the semiannual reporting period.
(5) For each affected source that is subject to permitting regulations pursuant to part 70 or part 71 of this chapter, and if the permitting authority has established dates for submitting semiannual reports pursuant to 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A), you may submit the first and subsequent compliance reports according to the dates the permitting authority has established instead of according to the dates in paragraphs (b)(1) through (4) of this section.
(c) The compliance report must contain the information required in paragraphs (c)(1) through (4) of this section.
(1) The information required by the summary report located in 63.10(e)(3)(vi).
(2) The total fuel use by each affected source subject to an emission limit, for each calendar month within the semiannual reporting period, including, but not limited to, a description of the fuel, whether the fuel has received a non-waste determination by EPA or your basis for concluding that the fuel is not a waste, and the total fuel usage amount with units of measure.
(3) Indicate whether you burned new types of fuel during the reporting period. If you did burn new types of fuel you must include the date of the performance test where that fuel was in use.
(4) Include the date of the most recent tune-up for each unit subject to the requirement to conduct a performance tune-up according to § 63.10021(e). Include the date of the most recent burner inspection if it was not done annually and was delayed until the next scheduled unit shutdown.
(d) For each excess emissions occurring at an affected source where you are using a CMS to comply with that emission limit or operating limit, you must include the information required in § 63.10(e)(3)(v) in the compliance report specified in section (c).
(e) Each affected source that has obtained a Title V operating permit pursuant to part 70 or part 71 of this chapter must report all deviations as defined in this subpart in the semiannual monitoring report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A). If an affected source submits a compliance report pursuant to Table 8 to this subpart along with, or as part of, the semiannual monitoring report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A), and the compliance report includes all required information concerning deviations from any emission limit, operating limit, or work practice requirement in this subpart, submission of the compliance report satisfies any obligation to report the same deviations in the semiannual monitoring report. Submission of a compliance report does not otherwise affect any obligation the affected source may have to report deviations from permit requirements to the permit authority.
(f) As of January 1, 2012, and within 60 days after the date of completing each performance test, you must submit the results of the performance tests required by this subpart to EPA's WebFIRE database by using the Compliance and Emissions Data Reporting Interface (CEDRI) that is accessed through EPA's Central Data Exchange (CDX) (
(1) Within 60 days after the date of completing each CEMS (SO
(2) For a PM CEMS, PM CPMS, or approved alternative monitoring using a HAP metals CEMS, within 60 days after the reporting periods ending on March 31st, June 30th, September 30th, and December 31st, you must submit quarterly reports to EPA's WebFIRE database by using the Compliance and Emissions Data Reporting Interface (CEDRI) that is accessed through EPA's Central Data Exchange (CDX) (
(3) Reports for an SO
(4) Submit the compliance reports required under paragraphs (c) and (d) of this section and the notification of compliance status required under § 63.10030(e) to EPA's WebFIRE database by using the Compliance and Emissions Data Reporting Interface (CEDRI) that is accessed through EPA's Central Data Exchange (CDX) (
(5) All reports required by this subpart not subject to the requirements in paragraphs (f)(1) through (4) of this section must be sent to the Administrator at the appropriate address listed in § 63.13. If acceptable to both the Administrator and the owner or operator of a source, these reports may be submitted on electronic media. The Administrator retains the right to require submittal of reports subject to paragraphs (f)(1), (2), and (3) of this section in paper format.
(g) If you had a malfunction during the reporting period, the compliance report must include the number, duration, and a brief description for each type of malfunction which occurred during the reporting period and which caused or may have caused any applicable emission limitation to be exceeded.
(a) You must keep records according to paragraphs (a)(1) and (2) of this section. If you are required to (or elect to) continuously monitor Hg and/or HCl and/or HF emissions, you must also keep the records required under appendix A and/or appendix B to this subpart.
(1) A copy of each notification and report that you submitted to comply with this subpart, including all documentation supporting any Initial Notification or Notification of Compliance Status or semiannual compliance report that you submitted, according to the requirements in § 63.10(b)(2)(xiv).
(2) Records of performance stack tests, fuel analyses, or other compliance demonstrations and performance evaluations, as required in § 63.10(b)(2)(viii).
(b) For each CEMS and CPMS, you must keep records according to paragraphs (b)(1) through (4) of this section.
(1) Records described in § 63.10(b)(2)(vi) through (xi).
(2) Previous (
(3) Request for alternatives to relative accuracy test for CEMS as required in § 63.8(f)(6)(i).
(4) Records of the date and time that each deviation started and stopped, and whether the deviation occurred during a period of startup, shutdown, or malfunction or during another period.
(c) You must keep the records required in Table 7 to this subpart including records of all monitoring data and calculated averages for applicable PM CPMS operating limits to show continuous compliance with each emission limit and operating limit that applies to you.
(d) For each EGU subject to an emission limit, you must also keep the records in paragraphs (d)(1) through (3) of this section.
(1) You must keep records of monthly fuel use by each EGU, including the type(s) of fuel and amount(s) used.
(2) If you combust non-hazardous secondary materials that have been determined not to be solid waste pursuant to 40 CFR 241.3(b)(1), you must keep a record which documents how the secondary material meets each of the legitimacy criteria. If you combust a fuel that has been processed from a discarded non-hazardous secondary material pursuant to 40 CFR 241.3(b)(2), you must keep records as to how the operations that produced the fuel satisfies the definition of processing in 40 CFR 241.2. If the fuel received a non-waste determination pursuant to the petition process submitted under 40 CFR 241.3(c), you must keep a record which documents how the fuel satisfies the requirements of the petition process.
(3) For an EGU that qualifies as an LEE under § 63.10005(h), you must keep annual records that document that your emissions in the previous stack test(s) continue to qualify the unit for LEE status for an applicable pollutant, and document that there was no change in source operations including fuel composition and operation of air pollution control equipment that would cause emissions of the pollutant to increase within the past year.
(e) If you elect to average emissions consistent with § 63.10009, you must additionally keep a copy of the emissions averaging implementation
(f) You must keep records of the occurrence and duration of each startup and/or shutdown.
(g) You must keep records of the occurrence and duration of each malfunction of an operation (
(h) You must keep records of actions taken during periods of malfunction to minimize emissions in accordance with § 63.10000(b), including corrective actions to restore malfunctioning process and air pollution control and monitoring equipment to its normal or usual manner of operation.
(i) You must keep records of the type(s) and amount(s) of fuel used during each startup or shutdown.
(j) If you elect to establish that an EGU qualifies as a limited-use liquid oil-fired EGU, you must keep records of the type(s) and amount(s) of fuel use in each calendar quarter to document that the capacity factor limitation for that subcategory is met.
(a) Your records must be in a form suitable and readily available for expeditious review, according to § 63.10(b)(1).
(b) As specified in § 63.10(b)(1), you must keep each record for 5 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record.
(c) You must keep each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to § 63.10(b)(1). You can keep the records off site for the remaining 3 years.
Table 9 to this subpart shows which parts of the General Provisions in §§ 63.1 through 63.15 apply to you.
(a) This subpart can be implemented and enforced by U.S. EPA, or a delegated authority such as your state, local, or tribal agency. If the EPA Administrator has delegated authority to your state, local, or tribal agency, then that agency (as well as the U.S. EPA) has the authority to implement and enforce this subpart. You should contact your EPA Regional Office to find out if this subpart is delegated to your state, local, or tribal agency.
(b) In delegating implementation and enforcement authority of this subpart to a state, local, or tribal agency under 40 CFR part 63, subpart E, the authorities listed in paragraphs (b)(1) through (4) of this section are retained by the EPA Administrator and are not transferred to the state, local, or tribal agency; moreover, the U.S. EPA retains oversight of this subpart and can take enforcement actions, as appropriate, with respect to any failure by any person to comply with any provision of this subpart.
(1) Approval of alternatives to the non-opacity emission limits and work practice standards in § 63.9991(a) and (b) under § 63.6(g).
(2) Approval of major change to test methods in Table 5 to this subpart under § 63.7(e)(2)(ii) and (f) and as defined in § 63.90, approval of minor and intermediate changes to monitoring performance specifications/procedures in Table 5 where the monitoring serves as the performance test method (see definition of “test method” in § 63.2.
(3) Approval of major changes to monitoring under § 63.8(f) and as defined in § 63.90.
(4) Approval of major change to recordkeeping and reporting under § 63.10(e) and as defined in § 63.90.
Terms used in this subpart are defined in the Clean Air Act (CAA), in § 63.2 (the General Provisions), and in this section as follows:
(1) Having equipment used to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy; and
(2) Producing during the 12-month period starting on the date the unit first produces electricity and during any calendar year after which the unit first produces electricity:
(i) For a topping-cycle cogeneration 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 than 42.5 percent
(ii) For a bottoming-cycle cogeneration 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.
(i) Fails to meet any requirement or obligation established by this subpart including, but not limited to, any emission limit, operating limit, work practice standard, or monitoring requirement; or
(ii) Fails to meet any term or condition that is adopted to implement an applicable requirement in this subpart and that is included in the operating permit for any affected source required to obtain such a permit.
(2) A deviation is not always a violation. The determination of whether a deviation constitutes a violation of the standard is up to the discretion of the entity responsible for enforcement of the standards.
1.1
1.2
1.3
1.4
2.1
2.2
2.2.1
2.2.2
2.2.3
2.2.4
2.2.4.1 When a certified non-redundant backup sorbent trap monitoring system is brought into service, you must follow the procedures for routine day-to-day operation of the system, in accordance with Performance Specification (PS) 12B in appendix B to part 60 of this chapter.
2.2.4.2 When a certified non-redundant backup Hg CEMS or a temporary like-kind replacement Hg analyzer is brought into service, a calibration error test and a linearity check must be performed and passed. A single point system integrity check is also required, unless a NIST-traceable source of oxidized Hg was used for the calibration error test.
2.2.4.3 Each non-redundant backup Hg CEMS or temporary like-kind replacement Hg analyzer shall comply with all required daily, weekly, and quarterly quality-assurance test requirements in section 5 of this appendix, for as long as the system or analyzer remains in service.
2.2.4.4 For the routine, on-going quality-assurance of a non-redundant backup Hg monitoring system, a relative accuracy test audit (RATA) must be performed and passed at least once every 8 calendar quarters at the
2.2.4.5 To use a non-redundant backup Hg monitoring system or a temporary like-kind replacement analyzer for more than 720 hours per year at a particular unit or stack location, a RATA must first be performed and passed at that location.
The following definitions, equipment specifications, procedures, and performance criteria are applicable to the measurement of vapor-phase Hg emissions from electric utility steam generating units, under relatively low-dust conditions (i.e., sampling in the stack or duct after all pollution control devices). The analyte measured by these procedures and specifications is total vapor-phase Hg in the flue gas, which represents the sum of elemental Hg (Hg
3.1
3.1.1
3.1.2
3.1.3
3.1.4
3.1.5
3.1.6
3.1.7
3.1.8
3.1.9
3.1.10
3.1.11
3.1.12
3.1.13
3.1.14
3.1.15
3.1.16
3.1.17
3.1.18
3.1.19
3.1.20 Quality Assurance
3.1.21
3.2
3.2.1
3.2.1.1
3.2.1.1.1
3.2.1.1.2
3.2.1.1.3
3.2.1.1.3.1
3.2.1.1.3.2
3.2.1.1.3.3
3.2.1.1.3.4
3.2.1.1.3.5
3.2.1.1.3.6
3.2.1.1.3.7
3.2.1.1.3.8
3.2.1.1.3.9
3.2.1.2
3.2.1.2.1
3.2.1.2.2
3.2.1.2.2.1
3.2.1.2.2.2
3.2.1.2.2.3
3.2.1.2.2.4
3.2.1.3
3.2.1.4
3.2.1.4.1
3.2.1.4.2
3.2.1.4.3
3.2.2
3.2.3
3.2.3.1
3.2.3.2
3.2.3.3
4.1
4.1.1
4.1.1.1
4.1.1.2
4.1.1.3
4.1.1.4
Either an elemental or oxidized NIST-traceable Hg standard may be used as the high-level gas. Perform the test in two stages—upscale and downscale. The slower of the upscale and downscale response times is the cycle time for the CEMS. Begin each stage of the test by injecting calibration gas after achieving a stable reading of the stack emissions. The cycle time is the amount of time it takes for the analyzer to register a reading that is 95 percent of the way between the stable stack emissions reading and the final, stable reading of the calibration gas concentration. Use the following criterion to determine when a stable reading of stack emissions or calibration gas has been attained—the reading is stable if it changes by no more than 2.0 percent of the span value or 0.5 µg/scm (whichever is less restrictive) for two minutes, or a reading with a change of less than 6.0 percent from the measured average concentration over 6 minutes. Integrated batch sampling type Hg CEMS are exempted from this test; however, these systems must be capable of delivering a measured Hg concentration reading at least once every 15 minutes. If necessary to increase measurement sensitivity of a batch sampling type Hg CEMS for a specific application, you may petition the Administrator for approval of a time longer than 15 minutes between readings.
4.1.1.5
4.1.1.5.1
4.1.1.5.2
4.1.1.5.3
4.1.2
4.1.2.1
4.1.2.2 “The special considerations specified in paragraph 4.1.1.5.1 of this section apply to the RATA of a sorbent trap
4.1.2.2.1 For stack Hg concentrations >1 µg/dscm, ≤10% of section 1 Hg mass;
4.1.2.2.2 For stack Hg concentrations ≤1 µg/dscm and >0.5 µg/dscm, ≤ 20% of section 1 Hg mass;
4.1.2.2.3 For stack Hg concentrations ≤0.5 µg/dscm and >0.1 µg/dscm, ≤ 50% of section 1 Hg mass; and
4.1.2.2.4 For stack Hg concentrations ≤0.1µg/dscm, no breakthrough criterion assuming all other QA/QC specifications are met.
4.1.2.3 The type of sorbent material used by the traps during the RATA must be the same as for daily operation of the monitoring system; however, the size of the traps used for the RATA may be smaller than the traps used for daily operation of the system.
4.1.2.4
4.1.2.5
4.1.3
4.2
5.1
5.1.1
5.1.2
5.1.2.1 Calibration error tests of the Hg CEMS are required daily, except during unit outages. Use either NIST-traceable elemental Hg standards or NIST-traceable oxidized Hg standards for these calibrations. Both a zero-level gas and either a mid-level or high-level gas are required for these calibrations.
5.1.2.2 Perform a linearity check of the Hg CEMS in each QA operating quarter, using low-level, mid-level, and high-level NIST-traceable elemental Hg standards. For units that operate infrequently, limited exemptions from this test are allowed for “non-QA operating quarters”. A maximum of three consecutive exemptions for this reason are permitted, following the quarter of the last test. After the third consecutive exemption, a linearity check must be performed in the next calendar quarter or within a grace period of 168 unit or stack operating hours after the end of that quarter. The test frequency for 3-level system integrity checks (if performed in lieu of linearity checks) is the same as for the linearity checks. Use low-level, mid-level, and high-level NIST-traceable oxidized Hg standards for the system integrity checks.
5.1.2.3 If required, perform a single-level system integrity check weekly,
5.1.2.4 The test frequency for the RATAs of the Hg CEMS shall be annual,
5.1.3
5.1.3.1 A 168 unit or stack operating hour grace period is available for quarterly linearity checks and 3-level system integrity checks of the Hg CEMS.
5.1.3.2 A 720 unit or stack operating hour grace period is available for RATAs of the Hg CEMS.
5.1.3.3 There is no grace period for weekly system integrity checks. The test must be completed once every 7 operating days.
5.1.4
5.1.5
5.1.6
5.2
5.2.1 Each sorbent trap monitoring system shall be continuously operated and maintained in accordance with Performance Specification (PS) 12B in appendix B to part 60 of this chapter. The QA/QC criteria for routine operation of the system are summarized in Table 12B-1 of PS 12B. Each pair of sorbent traps may be used to sample the stack gas for up to 14 operating days.
5.2.2 For ongoing QA, periodic RATAs of the system are required.
5.2.2.1 The RATA frequency shall be annual,
5.2.2.2 The same RATA performance criteria specified in Table A-4 for Hg CEMS shall apply to the annual RATAs of the sorbent trap monitoring system.
5.2.2.3 A 720 unit or stack operating hour grace period is available for RATAs of the monitoring system.
5.2.3 Data validation for sorbent trap monitoring systems shall be done in accordance with Table 12B-1 in Performance Specification (PS) 12B in appendix B to part 60 of this chapter. All periods of invalid data shall be counted as hours of monitoring system downtime.
5.3
5.4
5.4.1
5.4.1.1
5.4.1.2
5.4.1.3
5.4.2
5.4.2.1
5.4.2.2
5.4.2.3
5.4.3
5.4.3.1
5.4.3.2
5.4.3.3
5.4.3.4
5.4.3.5
6.1 Data Reduction.
6.1.1 Reduce the data from Hg CEMS to hourly averages, in accordance with § 60.13(h)(2) of this chapter.
6.1.2 For sorbent trap monitoring systems, determine the Hg concentration for each data collection period and assign this concentration value to each operating hour in the data collection period.
6.1.3 For any operating hour in which valid data are not obtained, either for Hg concentration or for a parameter used in the emissions calculations (
6.1.4 Operating hours in which valid data are not obtained for Hg concentration are considered to be hours of monitor downtime. The use of substitute data for Hg concentration is not required.
6.2
6.2.1
6.2.1.1 Select an appropriate emission rate equation from among Equations 19-1 through 19-9 in EPA Method 19 in appendix A-7 to part 60 of this chapter.
6.2.1.2 Calculate the Hg emission rate in lb/MMBtu, using the equation selected from Method 19. Multiply the Hg concentration value by 6.24 × 10
6.2.1.3 Multiply the lb/MMBtu value obtained in section 6.2.1.2 of this appendix by 10
6.2.1.4 The heat input-based Hg emission rate limit in Table 2 to this subpart must be met on a 30 boiler operating day rolling average basis. Use Equation 19-19 in EPA Method 19 to calculate the Hg emission rate for each averaging period. The term E
6.2.2
6.2.2.1 Calculate the Hg mass emissions for each operating hour in which valid data are obtained for all parameters, using Equation A-2 of this section (for wet-basis measurements of Hg concentration) or Equation A-3 of this section (for dry-basis measurements), as applicable:
(
6.2.2.2 Use Equation A-4 of this section to calculate the emission rate for each unit or stack operating hour in which valid data are obtained for all parameters.
6.2.2.3 The applicable electrical output-based Hg emission rate limit in Table 1 or 2 to this subpart must be met on a 30-boiler operating day rolling average basis. Use Equation A-5 of this section to calculate the Hg emission rate for each averaging period.
7.1
7.1.1
7.1.1.1
7.1.1.2
7.1.1.2.1
7.1.1.2.2
7.1.2
7.1.2.1 The date and hour;
7.1.2.2 The unit or stack operating time (rounded up to the nearest fraction of an hour (in equal increments that can range from one hundredth to one quarter of an hour, at the option of the owner or operator);
7.1.2.3 The hourly gross unit load (rounded to nearest MWe); and
7.1.2.4 If applicable, the F-factor used to calculate the heat input-based Hg emission rate.
7.1.3
7.1.3.1 The date and hour;
7.1.3.2 Monitoring system and component identification codes, as provided in the monitoring plan, if the CEMS provides a quality-assured value of Hg concentration for the hour;
7.1.3.3 The hourly Hg concentration, if a quality-assured value is obtained for the hour (µg/scm, rounded to three significant figures);
7.1.3.4 A special code, indicating whether or not a quality-assured Hg concentration is obtained for the hour. This code may be entered manually when a temporary like-kind replacement Hg analyzer is used for reporting; and
7.1.3.5 Monitor data availability, as a percentage of unit or stack operating hours, calculated according to § 75.32 of this chapter.
7.1.4
7.1.4.1 The date and hour;
7.1.4.2 Monitoring system and component identification codes, as provided in the monitoring plan, if the sorbent trap
7.1.4.3 The hourly Hg concentration, if a quality-assured value is obtained for the hour (µg/scm, rounded to three significant figures). Note that when a quality-assured Hg concentration value is obtained for a particular data collection period, that single concentration value is applied to each operating hour of the data collection period.
7.1.4.4 A special code, indicating whether or not a quality-assured Hg concentration is obtained for the hour;
7.1.4.5 The average flow rate of stack gas through each sorbent trap (in appropriate units,
7.1.4.6 The gas flow meter reading (in dscm, rounded to the nearest hundredth), at the beginning and end of the collection period and at least once in each unit operating hour during the collection period;
7.1.4.7 The ratio of the stack gas flow rate to the sample flow rate, as described in section 12.2 of Performance Specification (PS) 12B in Appendix B to part 60 of this chapter; and
7.1.4.8 Monitor data availability, as a percentage of unit or stack operating hours, calculated according to § 75.32 of this chapter.
7.1.5
7.1.5.1 Hourly measurements of stack gas volumetric flow rate during unit operation are required for routine operation of sorbent trap monitoring systems, to maintain the required ratio of stack gas flow rate to sample flow rate (see section 8.2.2 of Performance Specification (PS) 12B in Appendix B to part 60 of this chapter). Hourly stack gas flow rate data are also needed in order to demonstrate compliance with electrical output-based Hg emissions limits, as provided in section 6.2.2 of this appendix.
7.1.5.2 For each affected unit or common stack, if hourly measurements of stack gas flow rate are needed for sorbent trap monitoring system operation or to convert Hg concentrations to the units of the emission standard, use a flow rate monitor that meets the requirements of part 75 of this chapter to record the required data. You must keep hourly flow rate records, as specified in § 75.57(c)(2) of this chapter.
7.1.6
7.1.6.1 Correction of hourly Hg concentration data for moisture is sometimes required when converting Hg concentrations to the units of the applicable Hg emissions limit. In particular, these corrections are required:
7.1.6.1.1 For sorbent trap monitoring systems;
7.1.6.1.2 For Hg CEMS that measure Hg concentration on a dry basis, when you must calculate electrical output-based Hg emission rates; and
7.1.6.1.3 When using certain equations from EPA Method 19 in appendix A-7 to part 60 of this chapter to calculate heat input-based Hg emission rates.
7.1.6.2 If hourly moisture corrections are required, either use a fuel-specific default moisture percentage from § 75.11(b)(1) of this chapter or a certified moisture monitoring system that meets the requirements of part 75 of this chapter, to record the required data. If you use a moisture monitoring system, you must keep hourly records of the stack gas moisture content, as specified in § 75.57(c)(3) of this chapter.
7.1.7
7.1.7.1 When a heat input-based Hg mass emissions limit must be met, in units of lb/TBtu, hourly measurements of CO
7.1.7.2 If hourly measurements of diluent gas concentration are needed, use a certified CO
7.1.8
7.1.8.1 The date and hour;
7.1.8.2 The hourly Hg emissions rate (lb/TBtu or lb/GWh, as applicable, calculated according to section 6.2.1 or 6.2.2 of this appendix, rounded to three significant figures), if valid values of Hg concentration and all other required parameters (stack gas volumetric flow rate, diluent gas concentration, electrical load, and moisture data, as applicable) are obtained for the hour;
7.1.8.3 An identification code for the formula (either the selected equation from Method 19 in section 6.2.1 of this appendix or Equation A-4 in section 6.2.2 of this appendix) used to derive the hourly Hg emission rate from Hg concentration, flow rate, electrical load, diluent gas concentration, and moisture data (as applicable); and
7.1.8.4 A code indicating that the Hg emission rate was not calculated for the hour, if valid data for Hg concentration and/or any of the other necessary parameters are not obtained for the hour. For the purposes of this appendix, the substitute data values required under part 75 of this chapter for diluent gas concentration, stack gas flow rate and moisture content are not considered to be valid data.
7.1.9
7.1.9.1 The reference values, monitor responses, and calculated calibration error (CE) values, and a flag to indicate whether the test was done using elemental or oxidized Hg, for all required 7-day calibration error tests and daily calibration error tests of the Hg CEMS;
7.1.9.2 The reference values, monitor responses, and calculated linearity error (LE) or system integrity error (SIE) values for all linearity checks of the Hg CEMS, and for all single-level and 3-level system integrity checks of the Hg CEMS;
7.1.9.3 The CEMS and reference method readings for each test run and the calculated relative accuracy results for all RATAs of the Hg CEMS and/or sorbent trap monitoring systems;
7.1.9.4 The stable stack gas and calibration gas readings and the calculated results for the upscale and downscale stages of all required cycle time tests of the Hg CEMS or, for a batch sampling Hg CEMS, the interval between measured Hg concentration readings;
7.1.9.5 Supporting information for all required RATAs of the Hg monitoring systems, including records of the test dates, the raw reference method and monitoring system data, the results of sample analyses to substantiate the reported test results, and records of sampling equipment calibrations;
7.1.9.6 For sorbent trap monitoring systems, also keep records of the results of all analyses of the sorbent traps used for routine daily operation of the system, and information documenting the results of all leak checks and the other applicable quality control procedures described in Table 12B-1 of Performance Specification (PS) 12B in appendix B to part 60 of this chapter.
7.1.9.7 For stack gas flow rate, diluent gas, and (if applicable) moisture monitoring systems, you must keep records of all certification, recertification, diagnostic, and on-going quality-assurance tests of these systems, as specified in § 75.59 of this chapter.
7.2
7.2.1
7.2.1.1 Notifications, in accordance with paragraph 7.2.2 of this section;
7.2.1.2 Monitoring plan reporting, in accordance with paragraph 7.2.3 of this section;
7.2.1.3 Certification, recertification, and QA test submittals, in accordance with paragraph 7.2.4 of this section; and
7.2.1.4 Electronic quarterly report submittals, in accordance with paragraph 7.2.5 of this section.
7.2.2
7.2.3
7.2.3.1 Submit the electronic and hard copy information in section 7.1.1.2 of this appendix pertaining to the Hg monitoring systems at least 21 days prior to the applicable date in § 63.9984. Also submit the monitoring plan information in § 75.53.(g) pertaining to the flow rate, diluent gas, and moisture monitoring systems within that same time frame, if the required records are not already in place.
7.2.3.2 Whenever an update of the monitoring plan is required, as provided in paragraph 7.1.1.1 of this section. An electronic monitoring plan information
7.2.3.3 All electronic monitoring plan submittals and updates shall be made to the Administrator using the ECMPS Client Tool. Hard copy portions of the monitoring plan shall be kept on record according to section 7.1 of this appendix.
7.2.4
7.2.5
7.2.5.1 Beginning with the report for the calendar quarter in which the initial compliance demonstration is completed or the calendar quarter containing the applicable date in § 63.9984, the owner or operator of any affected unit shall use the ECMPS Client Tool to submit electronic quarterly reports to the Administrator, in an XML format specified by the Administrator, for each affected unit (or group of units monitored at a common stack) under this subpart.
7.2.5.2 The electronic reports must be submitted within 30 days following the end of each calendar quarter, except for units that have been placed in long-term cold storage.
7.2.5.3 Each electronic quarterly report shall include the following information:
7.2.5.3.1 The date of report generation;
7.2.5.3.2 Facility identification information;
7.2.5.3.3 The information in paragraphs 7.1.2 through 7.1.8 of this section, as applicable to the Hg emission measurement methodology (or methodologies) used and the units of the Hg emission standard(s); and
7.2.5.3.4 The results of all daily calibration error tests of the Hg CEMS, as described in paragraph 7.1.90.1 of this section and (if applicable) the results of all daily flow monitor interference checks.
7.2.5.4
These monitoring provisions apply to the measurement of HCl and/or HF emissions from electric utility steam generating units, using CEMS. The CEMS must be capable of measuring HCl and/or HF in the appropriate units of the applicable emissions standard (e.g., lb/MMBtu, lb/MWh, or lb/GWh).
2.1
2.2
2.3
The initial certification procedures for the HCl or HF CEMS used to provide data under this subpart are as follows:
3.1 The HCl and/or HF CEMS must be certified according to Performance Specification 15 using the procedures for gas auditing and comparison to a reference method (RM) as specified in sections 3.1.1 and 3.1.2 below. (
3.1.1 You must conduct a gas audit of the HCl and/or HF CEMS as described in section 9.1 of Performance Specification 15, with the exceptions listed in sections 3.1.2.1 and 3.1.2.2 below.
3.1.1.1 The audit sample gas does not have to be obtained from the Administrator; however, it must be (1) from a secondary source of certified gases (i.e., independent of any calibration gas used for the daily calibration assessments) and (2) directly traceable to National Institute of Standards and Technology (NIST) or VSL Dutch Metrology Institute (VSL) reference materials through an unbroken chain of comparisons. If audit gas traceable to NIST or VSL reference materials is not available, you may use a gas with a concentration certified to a specified uncertainty by the gas manufacturer.
3.1.1.2 Analyze the results of the gas audit using the calculations in section 12.1 of Performance Specification 15. The calculated correction factor (CF) from Eq. 6 of Performance Specification 15 must be between 0.85 and 1.15. You do not have to test the bias for statistical significance.
3.1.2 You must perform a relative accuracy test audit or RATA according to section 11.1.1.4 of Performance Specification 15 and the requirements below. Perform the RATA of the HCl or HF CEMS at normal load. Acceptable HCl/HF reference methods (RM) are Methods 26 and 26A in appendix A-8 to part 60 of this chapter, Method 320 in Appendix A to this part, or ASTM D6348-03 (Reapproved 2010) “Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy” (incorporated by reference, see § 63.14), each applied based on the criteria set forth in Table 5 of this subpart.
3.1.2.1 When ASTM D6348-03 is used as the RM, the following conditions must be met:
3.1.2.1.1 The test plan preparation and implementation in the Annexes to ASTM D6348-03, Sections A1 through A8 are mandatory;
3.1.2.1.2 In ASTM D6348-03 Annex A5 (Analyte Spiking Technique), the percent (%) R must be determined for each target analyte (see Equation A5.5);
3.1.2.1.3 For the ASTM D6348-03 test data to be acceptable for a target analyte, %R must be 70% ≥ R ≤ 130%; and
3.1.2.1.4 The %R value for each compound must be reported in the test report and all field measurements corrected with the calculated %R value for that compound using the following equation:
3.1.2.2 The relative accuracy (RA) of the HCl or HF CEMS must be no greater than 20 percent of the mean value of the RM test data in units of ppm on the same moisture basis. Alternatively, if the mean RM value is less than 1.0 ppm, the RA results are acceptable if the absolute value of the difference between the mean RM and CEMS values does not exceed 0.20 ppm.
3.2 Any additional stack gas flow rate, diluent gas, and moisture monitoring system(s) needed to express pollutant concentrations in units of the applicable emissions limit must be certified according to part 75 of this chapter.
Whenever the owner or operator makes a replacement, modification, or change to a certified CEMS that may significantly affect the ability of the system to accurately measure or record pollutant or diluent gas concentrations, stack gas flow rates, or stack gas moisture content, the owner or operator shall recertify the monitoring system. Furthermore, whenever the owner or operator makes a replacement, modification, or change to the flue gas handling system or the unit operation that may significantly change the concentration or flow profile, the owner or operator shall recertify the monitoring system. The same tests performed for the initial certification of the monitoring system shall be repeated for recertification, unless otherwise specified by the Administrator. Examples of changes that require recertification include: Replacement of a gas analyzer; complete monitoring system replacement, and changing the location or orientation of the sampling probe.
5.1 For on-going QA test requirements for HCl and HF CEMS, implement the quality assurance/quality control procedures of Performance Specification 15 of appendix B to part 60 of this chapter as set forth in sections 5.1.1 through 5.1.3 and 5.3.2 of this appendix.
5.1.1 On a daily basis, you must assess the calibration error of the HCl or HF CEMS using either a calibration transfer standard as specified in Performance Specification 15 Section 10.1 which references Section 4.5 of the FTIR Protocol or a HCl and/or HF calibration gas at a concentration no greater than two times the level corresponding to the applicable emission limit. A calibration transfer standard is a substitute calibration compound chosen to ensure that the FTIR is performing well at the wavelength regions used for analysis of the target analytes. The measured concentration of the calibration transfer standard or HCl and/or HF calibration gas results must agree within ± 5 percent of the reference gas value after correction for differences in pressure.
5.1.2 On a quarterly basis, you must conduct a gas audit of the HCl and/or HF CEMS as described in section 3.1.1 of this appendix. For the purposes of this appendix, “quarterly” means once every “QA operating quarter” (as defined in section 3.1.20 of appendix A to this subpart). You have the option to use HCl gas in lieu of HF gas for conducting this audit on an HF CEMS. To the extent practicable, perform consecutive quarterly gas audits at least 30 days apart. The initial quarterly audit is due in the first QA operating quarter following the calendar quarter in which certification testing of the CEMS is successfully completed. Up to three consecutive exemptions from the quarterly audit requirement are allowed for “non-QA operating quarters” (
5.1.3 You must perform an annual relative accuracy test audit or RATA of the HCl or HF CEMS as described in section 3.1.2 of this appendix. Perform the RATA at normal load. For the purposes of this appendix, “annual” means once every four “QA operating quarters” (as defined in section 3.1.20 of appendix A to this subpart). The first annual RATA is due within four QA operating quarters following the calendar quarter in which the initial certification testing of the HCl or HF CEMS is successfully completed. The provisions in section 5.1.2.4 of appendix A to this subpart pertaining to RATA deadline extensions also apply.
5.2 Stack gas flow rate, diluent gas, and moisture monitoring systems must meet the applicable on-going QA test requirements of part 75 of this chapter.
5.3
5.3.1
5.3.2
5.3.2.1 For the flow rate, diluent gas, and moisture monitoring systems described in section 5.2 of this appendix, a 168 unit or stack operating hour grace period is available for quarterly linearity checks, and a 720 unit or stack operating hour grace period is available for RATAs, as provided, respectively, in sections 2.2.4 and 2.3.3 of appendix B to part 75 of this chapter.
5.3.2.2 For the purposes of this appendix, if the deadline for a required gas audit or RATA of a HCl or HF CEMS cannot be met due to circumstances beyond the control of the owner or operator:
5.3.2.2.1 A 168 unit or stack operating hour grace period is available in which to perform the gas audit; or
5.3.2.2.2 A 720 unit or stack operating hour grace period is available in which to perform the RATA.
5.3.2.3 If a required QA test is performed during a grace period, the deadline for the next test shall be determined as follows:
5.3.2.3.1 For a gas audit or RATA of the monitoring systems described in section 5.1 of this appendix, determine the deadline for the next gas audit or RATA (as applicable) in accordance with section 2.2.4(b) or 2.3.3(d) of appendix B to part 75 of this chapter; treat a gas audit in the same manner as a linearity check.
5.3.2.3.2 For the gas audit of a HCl or HF CEMS, the grace period test only satisfies the audit requirement for the calendar quarter in which the test was originally due. If the calendar quarter in which the grace period audit is performed is a QA operating quarter, an additional gas audit is required for that quarter.
5.3.2.3.3 For the RATA of a HCl or HF CEMS, the next RATA is due within three QA operating quarters after the calendar quarter in which the grace period test is performed.
5.3.4
For the purposes of this appendix, the owner or operator of an affected unit shall not substitute for missing data from HCl or HF CEMS. Any process operating hour for which quality-assured HCl or HF concentration data are not obtained is counted as an hour of monitoring system downtime.
Bias adjustment of hourly emissions data from a HCl or HF CEMS is not required.
The owner or operator shall develop and implement a quality assurance/quality control (QA/QC) program for the HCl and/or HF CEMS that are used to provide data under this subpart. At a minimum, the program shall include a written plan that describes in detail (or that refers to separate documents containing) complete, step-by-step procedures and operations for the most important QA/QC activities. Electronic storage of the QA/QC plan is permissible, provided that the information can be made available in hard copy to auditors and inspectors. The QA/QC program requirements for the other monitoring systems described in section 5.2 of this appendix are specified in section 1 of appendix B to part 75 of this chapter.
8.1
8.1.1
8.1.2
8.1.3
8.2
8.2.1 Keep a written record of the procedures used for each type of QA test required for each HCl and HF CEMS. Explain how the results of each type of QA test are calculated and evaluated.
8.2.2 Explain how each component of the HCl and/or HF CEMS will be adjusted to provide correct responses to calibration gases after routine maintenance, repairs, or corrective actions.
9.1 Design and operate the HCl and/or HF CEMS to complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15-minute period.
9.2 Reduce the HCl and/or HF concentration data to hourly averages in accordance with § 60.13(h)(2) of this chapter.
9.3 Convert each hourly average HCl or HF concentration to an HCl or HF emission rate expressed in units of the applicable emissions limit.
9.3.1 For heat input-based emission rates, select an appropriate emission rate equation from among Equations 19-1 through 19-9 in EPA Method 19 in appendix A-7 to part 60 of this chapter, to calculate the HCl or HF emission rate in lb/MMBtu. Multiply the HCl concentration value (ppm) by 9.43 × 10
9.3.2 For electrical output-based emission rates, first calculate the HCl or HF mass emission rate (lb/h), using an equation that has the general form of Equation A-2 or A-3 in appendix A to this subpart (as applicable), replacing the value of K with 9.43 × 10
9.4 Use Equation A-5 in appendix A of this subpart to calculate the required 30 operating day rolling average HCl or HF emission rates. Round off each 30 operating day average to two significant figures. The term E
10.1 For each HCl or HF CEMS installed at an affected source, and for any other monitoring system(s) needed to convert pollutant concentrations to units of the applicable emissions limit, the owner or operator must maintain a file of all measurements, data, reports, and other information required by this appendix in a form suitable for inspection, for 5 years from the date of each record, in accordance with § 63.10033. The file shall contain the information in paragraphs 10.1.1 through 10.1.8 of this section.
10.1.1
10.1.1.1
10.1.1.2
10.1.1.2.1
10.1.1.2.2
10.1.2
10.1.2.1 The date and hour;
10.1.2.2 The unit or stack operating time (rounded up to the nearest fraction of an hour (in equal increments that can range from one hundredth to one quarter of an hour, at the option of the owner or operator);
10.1.2.3 The hourly gross unit load (rounded to nearest MWge); and
10.1.2.4 If applicable, the F-factor used to calculate the heat input-based pollutant emission rate.
10.1.3
10.1.3.1 The date and hour;
10.1.3.2 Monitoring system and component identification codes, as provided in the electronic monitoring plan, for each hour in which the CEMS provides a quality-assured value of HCl or HF concentration (as applicable);
10.1.3.3 The pollutant concentration, for each hour in which a quality-assured value is obtained. For HCl and HF, record the data in parts per million (ppm), rounded to three significant figures.
10.1.3.4 A special code, indicating whether or not a quality-assured HCl or HF concentration value is obtained for the hour. This code may be entered manually when a temporary like-kind replacement HCl or HF analyzer is used for reporting; and
10.1.3.5 Monitor data availability, as a percentage of unit or stack operating hours, calculated according to § 75.32 of this chapter.
10.1.4
10.1.4.1 Hourly measurements of stack gas volumetric flow rate during unit operation are required to demonstrate compliance with electrical output-based HCl or HF emissions limits (
10.1.4.2 Use a flow rate monitor that meets the requirements of part 75 of this chapter to record the required data. You must keep hourly flow rate records, as specified in § 75.57(c)(2) of this chapter.
10.1.5
10.1.5.1 Correction of hourly pollutant concentration data for moisture is sometimes required when converting concentrations to the units of the applicable Hg emissions limit. In particular, these corrections are required:
10.1.5.1.1 To calculate electrical output-based pollutant emission rates, when using a CEMS that measures pollutant concentrations on a dry basis; and
10.1.5.1.2 To calculate heat input-based pollutant emission rates, when using certain equations from EPA Method 19 in appendix A-7 to part 60 of this chapter.
10.1.5.2 If hourly moisture corrections are required, either use a fuel-specific default moisture percentage for coal-fired units from § 75.11(b)(1) of this chapter, an Administrator approved default moisture value for non-coal-fired units (as per paragraph 63.10010(d) of this subpart), or a certified moisture monitoring system that meets the requirements of part 75 of this chapter, to record the required data. If you elect to use a moisture monitoring system, you must keep hourly records of the stack gas moisture content, as specified in § 75.57(c)(3) of this chapter.
10.1.6
10.1.6.1 To assess compliance with a heat input-based HCl or HF emission rate limit in units of lb/MMBtu, hourly measurements of CO
10.1.6.2 If hourly measurements of diluent gas concentration are needed, you must use a certified CO
10.1.7
10.1.7.1 The date and hour;
10.1.7.2 The hourly HCl and/or HF emissions rate (lb/MMBtu, lb/MWh, or lb/GWh, as applicable, rounded to three significant figures), for each hour in which valid values of HCl or HF concentration and all other required parameters (stack gas volumetric flow rate, diluent gas concentration, electrical load, and moisture data, as applicable) are obtained for the hour;
10.1.7.3 An identification code for the formula used to derive the hourly HCl or HF emission rate from HCl or HF concentration, flow rate, electrical load, diluent gas concentration, and moisture data (as applicable); and
10.1.7.4 A code indicating that the HCl or HF emission rate was not calculated for the hour, if valid data for HCl or HF concentration and/or any of the other necessary parameters are not obtained for the hour. For the purposes of this appendix, the substitute data values required under part 75 of this chapter for diluent gas concentration, stack gas flow rate and moisture content are not considered to be valid data.
10.1.8
10.1.8.1
10.1.8.1.1 For all required daily calibrations (including calibration transfer standard tests) of the HCl or HF CEMS, record the test dates and times, reference values, monitor responses, and calculated calibration error values;
10.1.8.1.2 For gas audits of HCl or HF CEMS, record the date and time of each spiked and unspiked sample, the audit gas reference values and uncertainties. Keep records of all calculations and data analyses required under sections 9.1 and 12.1 of Performance Specification 15, and the results of those calculations and analyses.
10.1.8.1.3 For each RATA of a HCl or HF CEMS, record the date and time of each test run, the reference method(s) used, and the reference method and HCl or HF CEMS values. Keep records of the data analyses and calculations used to determine the relative accuracy.
10.1.8.2
11.1
11.1.1 Notifications, in accordance with paragraph 11.2 of this section;
11.1.2 Monitoring plan reporting, in accordance with paragraph 11.3 of this section;
11.1.3 Certification, recertification, and QA test submittals, in accordance with paragraph 11.4 of this section; and
11.1.4 Electronic quarterly report submittals, in accordance with paragraph 11.5 of this section.
11.2
11.3
11.3.1 Submit the electronic and hard copy information in section 10.1.1.2 of this appendix pertaining to the HCl and/or HF monitoring systems at least 21 days prior to the applicable date in § 63.9984. Also, if applicable, submit monitoring plan information pertaining to any required flow rate, diluent gas, and/or moisture monitoring systems within that same time frame, if the required records are not already in place.
11.3.2 Update the monitoring plan when required, as provided in paragraph 10.1.1.1 of this appendix. An electronic monitoring plan information update must be submitted either prior to or concurrent with the quarterly report for the calendar quarter in which the update is required.
11.3.3 All electronic monitoring plan submittals and updates shall be made to the Administrator using the ECMPS Client Tool. Hard copy portions of the monitoring plan shall be kept on record according to section 10.1 of this appendix.
11.4
11.4.1 For daily calibrations (including calibration transfer standard tests), report the information in § 75.59(a)(1) of this chapter, excluding paragraphs (a)(1)(ix) through (a)(1)(xi).
11.4.2 For each quarterly gas audit of a HCl or HF CEMS, report:
11.4.2.1 Facility ID information;
11.4.2.2 Monitoring system ID number;
11.4.2.3 Type of test (
11.4.2.4 Reason for test;
11.4.2.5 Certified audit (spike) gas concentration value (ppm);
11.4.2.6 Measured value of audit (spike) gas, including date and time of injection;
11.4.2.7 Calculated dilution ratio for audit (spike) gas;
11.4.2.8 Date and time of each spiked flue gas sample;
11.4.2.9 Date and time of each unspiked flue gas sample;
11.4.2.10 The measured values for each spiked gas and unspiked flue gas sample (ppm);
11.4.2.11 The mean values of the spiked and unspiked sample concentrations and the expected value of the spiked concentration as specified in section 12.1 of Performance Specification 15 (ppm);
11.4.2.12 Bias at the spike level as calculated using equation 3 in section 12.1 of Performance Specification 15; and
11.4.2.13 The correction factor (CF), calculated using equation 6 in section 12.1 of Performance Specification 15.
11.4.3 For each RATA of a HCl or HF CEMS, report:
11.4.3.1 Facility ID information;
11.4.3.2 Monitoring system ID number;
11.4.3.3 Type of test (i.e., initial or annual RATA);
11.4.3.4 Reason for test;
11.4.3.5 The reference method used;
11.4.3.6 Starting and ending date and time for each test run;
11.4.3.7 Units of measure;
11.4.3.8 The measured reference method and CEMS values for each test run, on a consistent moisture basis, in appropriate units of measure;
11.4.3.9 Flags to indicate which test runs were used in the calculations;
11.4.3.10 Arithmetic mean of the CEMS values, of the reference method values, and of their differences;
11.4.3.11 Standard deviation, as specified in Equation 2-4 of Performance Specification 2 in appendix B to part 60 of this chapter;
11.4.3.12 Confidence coefficient, as specified in Equation 2-5 of Performance Specification 2 in appendix B to part 60 of this chapter; and
11.4.3.13 Relative accuracy calculated using Equation 2-6 of Performance Specification 2 in appendix B to part 60 of this chapter or, if applicable, according to the alternative procedure for low emitters described in section 3.1.2.2 of this appendix. If applicable use a flag to indicate that the alternative RA specification for low emitters has been applied.
11.4.4
11.5
11.5.1 Beginning with the report for the calendar quarter in which the initial compliance demonstration is completed or the calendar quarter containing the applicable date in § 63.10005(g), (h), or (j) (whichever is earlier), the owner or operator of any affected unit shall use the ECMPS Client Tool to submit electronic quarterly reports to the Administrator, in an XML format specified by the Administrator, for each affected unit (or group of units monitored at a common stack).
11.5.2 The electronic reports must be submitted within 30 days following the end of each calendar quarter, except for units that have been placed in long-term cold storage.
11.5.3 Each electronic quarterly report shall include the following information:
11.5.3.1 The date of report generation;
11.5.3.2 Facility identification information;
11.5.3.3 The information in sections 10.1.2 through 10.1.7 of this appendix, as applicable to the type(s) of monitoring system(s) used to measure the pollutant concentrations and other necessary parameters.
11.5.3.4 The results of all daily calibrations (including calibration transfer standard tests) of the HCl or HF monitor as described in section 10.1.8.1.1 of this appendix; and
11.5.3.5 If applicable, the results of all daily flow monitor interference checks, in accordance with section 10.1.8.2 of this appendix.
11.5.4