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Animal and Plant Health Inspection Service, USDA.
Interim rule; reopening of comment period.
We are reopening the comment period for our interim rule that amended the regulations concerning the importation of animals and animal products to prohibit or restrict the importation of bird and poultry products from regions where any subtype of highly pathogenic avian influenza is considered to exist. The interim rule also imposed restrictions concerning importation of live poultry and birds that have been vaccinated for certain types of avian influenza, or that have moved through regions where any subtype of highly pathogenic avian influenza is considered to exist. This action will allow interested persons additional time to prepare and submit comments.
We will consider all comments that we receive on or before May 18, 2011.
You may submit comments by either of the following methods:
•
•
Dr. Julia Punderson, Senior Staff Veterinarian, National Center for Import and Export, Animal Health Policy and Programs, VS, APHIS, 4700 River Road Unit 38, Riverdale, MD 20737; (301) 734-4356.
On January 24, 2011, we published in the
Comments on the interim rule were required to be received on or before March 25, 2011. We are reopening the comment period on Docket No. APHIS-2006-0074 for an additional 15 days. This action will allow interested persons additional time to prepare and submit comments. We will also consider all comments received between March 26, 2011, and the date of this notice.
7 U.S.C. 450, 1622, 7701-7772, 7781-7786, and 8301-8317; 21 U.S.C. 136 and 136a; 31 U.S.C. 9701; 7 CFR 2.22, 2.80, and 371.4.
Federal Aviation Administration (FAA), DOT.
Final rule.
We are adopting a new airworthiness directive (AD) for the products listed above. This AD results from mandatory continuing airworthiness information (MCAI) issued by an aviation authority of another country to identify and correct an unsafe condition on an aviation product. The MCAI describes the unsafe condition as:
During manufacture of a number of HP Compressor Stage 1 and 2 discs with axial dovetail slots, anomalies at the disc post corners have been found. Fatigue crack initiation and subsequent crack propagation at the disc post may result in release of two blades and the disc post. This may potentially be beyond the containment capabilities of the engine casings. Thus, these anomalies present at the disc posts constitute a potentially unsafe condition.
We are issuing this AD to detect cracks in the high-pressure compressor (HPC) Stage 1 and 2 disc posts, which could result in failure of the disc post and release of HPC blades, release of uncontained engine debris, and damage to the airplane.
This AD becomes effective June 7, 2011. The Director of the Federal Register approved the incorporation by reference of certain publications listed in this AD as of June 7, 2011.
The Docket Operations office is located at Docket Management
Alan Strom, Aerospace Engineer, Engine Certification Office, FAA, Engine and Propeller Directorate, 12 New England Executive Park, Burlington, MA 01803; e-mail:
We issued a notice of proposed rulemaking (NPRM) to amend 14 CFR part 39 to include an AD that would apply to the specified products. That NPRM was published in the
During manufacture of a number of HP Compressor Stage 1 and 2 discs with axial dovetail slots, anomalies at the disc post corners have been found. Fatigue crack initiation and subsequent crack propagation at the disc post may result in release of two blades and the disc post. This may potentially be beyond the containment capabilities of the engine casings. Thus, these anomalies present at the disc posts constitute a potentially unsafe condition.
For the reasons described above, this AD requires repetitive inspections of the axial dovetail slots and follow-on corrective action, depending on findings.
We gave the public the opportunity to participate in developing this AD. We considered the comments received.
Five commenters request that we change the criteria for carrying out the inspections to be consistent with the European Aviation Safety Agency (EASA) AD. The commenters ask that we require performing the inspections at the first shop visit after accumulating 1,000 hours-since-new (HSN) and whenever a Level 3 (Refurbishment) or Level 4 (Overhaul) shop visit occurs. The commenters feel that requiring the inspections any time a major flange is separated would result in more inspections than required by the EASA AD. Some of the inspections would cost significantly more than what is estimated in the Costs of Compliance section of the proposed AD.
We partially agree. We agree that the current wording would result in more inspections than required by the EASA AD, and some of the inspections would cost significantly more than what we estimated in the Costs of Compliance section of the proposed AD. We do not agree with using the Level 3 or Level 4 criteria as a definition of “engine shop visit” for the purpose of this AD. The definitions of Level 3 and Level 4 are not specific enough to ensure the inspections are conducted frequently enough to prevent the unsafe condition. We changed the definition of shop visit in paragraph (f) of the proposed AD from “For * * * an “engine shop visit” is the induction of an engine into the shop for maintenance involving the separation of pairs of major mating engine flanges, * * *” to “For * * * an “engine shop visit” is whenever the engine high-pressure compressor module is separated from the intermediate case.”
One commenter, RR, asks us to consider changing the Summary from “Thus, these anomalies present at the disc posts constitute a potentially unsafe condition” to “Thus, if these anomalies are present at the disc posts, they constitute a potentially unsafe condition.” The commenter believes that the MCAI description implies that all discs have the anomalies in question. The AD does not assume that to be true.
We don't agree. The second paragraph of the Summary quotes the EASA AD. We did not change the AD.
The same commenter asks us to change paragraph (c)(1) part number (P/N) “FK20195” to “FW20195.” The commenter states that the NPRM contains a typographical error.
We agree. We changed the part number in paragraph (c)(1) of the proposed AD from “FK20195” to “FW20195.”
The same commenter asks us to change the unsafe condition statement in the Summary and in paragraph (d) of the proposed AD from “* * * failure of the disc post, which could result in failure of the disc post and HPC blades, release * * * airplane” to “* * * failure of the disc post, resulting in release of HPC blades, release * * * airplane.” The commenter states the NPRM implies that high-pressure compressor blades may themselves fail, when in fact they are released as a result of disk post failure.
We agree. We changed the unsafe condition statement in the Summary and in paragraph (d) of the proposed AD to “which could result in failure of the disc post, release of HPC blades, release of uncontained debris, * * * airplane.”
The same commenter asks us to change paragraph (e)(1) of the proposed AD from “Perform a * * * later. Use paragraph 3.E.(1) through 3.E.(10)(i) * * * inspections” to “Clean and perform * * * later. Use paragraph 3.A through 3.E.(10)(i) * * * inspections.” The commenter believes the change will ensure adequate cleaning before inspection, which is essential to make sure the small cracks are visible.
We agree. Because the corrective action is looking for small cracks underneath a dry film lubricant coating, the cleaning procedure prior to fluorescent penetrant inspection (FPI) is critical to the corrective action. We changed paragraph (e)(1) of the proposed AD to “Clean and perform * * * later. Use paragraph 3.A through 3.E.(11) * * * inspections.” We also added paragraph 3.E.(11) to ensure that the blades will be re-coated prior to re-installation.
One commenter, Hawaiian Airlines, asks us to change “HPC rotor shaft” to “HP compressor drum.” The commenter states that the HPC drum in the Trent 700 engine is a six stage rotor and is referred to as the “HPC rotor shaft.” Since each engine model has different nomenclature, they request that we use a common name when we refer to the subject part such as “HP compressor Drum.” The commenter believes that this will ensure a common understanding of the parts involved.
We don't agree. While the service bulletin uses the term “HPC drum,” the AD consistently refers to the HPC disks by stage number.
We reviewed the available data, including the comments received, and determined that air safety and the public interest require adopting the AD with the changes described previously. We determined that these changes will not increase the economic burden on any operator or increase the scope of the AD.
Based on the service information, we estimate that this AD would affect about 371 products of U.S. registry. We also estimate that it would take about 20 work-hours per product to comply with this AD. The average labor rate is $85 per work-hour. No parts would be
Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. “Subtitle VII: Aviation Programs,” describes in more detail the scope of the Agency's authority.
We are issuing this rulemaking under the authority described in “Subtitle VII, Part A, Subpart III, Section 44701: General requirements.” Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.
We determined that this 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 the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979); and
3. Will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
We prepared a regulatory evaluation of the estimated costs to comply with this AD and placed it in the AD docket.
You may examine the AD docket on the Internet at
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.
(a) This airworthiness directive (AD) becomes effective June 7, 2011.
(b) None.
(c) This AD applies to RR model RB211-524G2-T-19, -524G3-T-19, -524H-T-36, and -524H2-T-19; and RB211 Trent 553-61, 553A2-61, 556-61, 556A2-61, 556B-61, 556B2-61, 560-61, 560A2-61; RB211 Trent 768-60, 772-60, 772B-60; and RB211 Trent 875-17, 877-17, 884-17, 884B-17, 892-17, 892B-17, and 895-17 turbofan engines that have a high-pressure (HP) compressor stage 1 to 4 rotor disc with a part number (P/N) listed in Table 1 of this AD. These engines are installed on, but not limited to, Boeing 747, 767, and 777 series airplanes and Airbus A330 and A340 series airplanes.
(d) This AD results from reports that:
During manufacture of a number of HP Compressor Stage 1 and 2 discs with axial dovetail slots, anomalies at the disc post corners have been found. Fatigue crack initiation and subsequent crack propagation at the disc post may result in release of two blades and the disc post. This may potentially be beyond the containment capabilities of the engine casings. Thus, these anomalies present at the disc posts constitute a potentially unsafe condition.
(e) Unless already done, do the following actions.
(1) Clean and perform a fluorescent penetrant inspection of the HP compressor stage 1 to 4 rotor discs at the first shop visit after accumulating 1000 cycles since new on the stage 1 to 4 rotor disks or at the next shop visit after the effective date of this AD, whichever occurs later. Use paragraph 3.A through 3.E.(11) of the Accomplishment Instructions of Rolls-Royce Alert Service Bulletin (ASB) RB.211-72-AF964, Revision 1, dated June 6, 2008 to do the inspections.
(2) Thereafter at every engine shop visit, perform the inspection specified by paragraph (e)(1) of this AD.
(f) For the purpose of this AD, an “engine shop visit” is whenever the engine high-pressure compressor module is separated from the intermediate case.
(g)
(h) See European Aviation Safety Agency Airworthiness Directive 2009-0073R1, dated April 8, 2009, for related information.
(i) Contact Alan Strom, Aerospace Engineer, Engine Certification Office, FAA, Engine and Propeller Directorate, 12 New England Executive Park, Burlington, MA 01803; e-mail:
(j) You must use Rolls-Royce Alert Service Bulletin RB.211-72-AF964, Revision 1, dated June 6, 2008, to do the actions required by this AD, unless the AD specifies otherwise.
(1) The Director of the Federal Register approved the incorporation by reference of this service information under 5 U.S.C. 552(a) and 1 CFR part 51.
(2) For service information identified in this AD, contact Rolls-Royce plc, P.O. Box 31, Derby, DE24 8BJ, United Kingdom; phone: 011 44 1332 242424, fax: 011 44 1332 249936; e-mail:
(3) You may review copies at the FAA, New England Region, 12 New England Executive Park, Burlington, MA; or at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call (202) 741-6030, or go to:
Federal Aviation Administration (FAA), DOT.
Final rule.
We are adopting a new airworthiness directive (AD) for the products listed above. This AD results from mandatory continuing airworthiness information (MCAI) issued by an aviation authority of another country to identify and correct an unsafe condition on an aviation product. The MCAI describes the unsafe condition as:
During manufacture of high-pressure (HP) compressor stage 1 discs, a small number of parts have been rejected due to a machining defect that was found during inspection. Analysis of the possibility of less severe examples having been undetected and passed into service has concluded that action is required to reduce the risk of failure. It was therefore necessary to reduce the life limit.
This AD becomes effective June 7, 2011.
The Docket Operations office is located at Docket Management Facility, U.S. Department of Transportation, 1200 New Jersey Avenue, SE., West Building Ground Floor, Room W12-140, Washington, DC 20590-0001.
Alan Strom, Aerospace Engineer, Engine Certification Office, FAA, Engine & Propeller Directorate, 12 New England Executive Park, Burlington, MA 01803; e-mail:
We issued a notice of proposed rulemaking (NPRM) and a supplemental notice of proposed rulemaking (SNPRM) to amend 14 CFR part 39 to include an AD that would apply to the specified products. That NPRM was published in the
During manufacture of high-pressure (HP) compressor stage 1 discs, a small number of parts have been rejected due to a machining defect that was found during inspection. Analysis of the possibility of less severe examples having been undetected and passed into service has concluded that action is required to reduce the risk of failure. It was therefore necessary to reduce the life limit.
The HP compressor stage 1 disc is part of the HP compressor stage 1-4 shaft, P/N FK32580. Since we issued the original NPRM on February 10, 2009 (74 FR 7563, February 18, 2009), EASA issued AD 2010-0087, dated May 5, 2010 (corrected May 6, 2010), which retains certain requirements of superseded EASA AD 2008-0099, and imposes more restrictive life limits in the Heavy Flight Profile Parts. You may obtain further information by examining the MCAI in the AD docket.
We gave the public the opportunity to participate in developing this AD. We considered the comments received.
Four commenters, American Airlines, Delta Airlines, Rolls-Royce plc, and The Boeing Company, request that we revise the compliance times to be consistent with the service bulletin and the airworthiness limitations section (ALS) of the engine manual. Doing this would account for the later AD release date and for the entire Trent 800 series fleet instead of just certain US operators' expected cyclic usage. The commenters state that the proposed requirements would have a severe adverse economic impact to operators relative to the service bulletin requirements. The simplified compliance requirements in the SNPRM relative to the service bulletin requirements, may not accurately reflect the risk of an uncontained event, and are confusing.
We do not agree. The requirements in the SNPRM were developed to minimize the risk of uncontained disc failure, based on the age of the parts in the field at the time the SNPRM was issued. The service bulletin requirements were developed at a time when the age of the parts in service was lower than when the SNPRM was issued. Because the risk of failure increases as the age of the parts in the field increase, any revision to the requirements of the SNPRM would again have to take the increased age of the parts in service into account. As such, an analysis would result in removal requirements more stringent than the requirements in the SNPRM, and a follow-on NPRM would be required. Therefore, we determined that it is in the public interest to keep the removal requirements the same as published in the SNPRM. We did not change the AD.
Delta Airlines states that it would be helpful if we could provide some clarity in the AD as to how an operator should interpret the differing information between the AD, the ALS of the Rolls-Royce Time Limits Manual, and the service bulletin. The commenter is concerned that there will be three locations where the life limit of the
We do not agree. The AD and the ALS take precedence over the service bulletin. Operators must comply with the AD and the ALS. We did not change the AD.
Delta Airlines asks for clarification as to whether a part reworked from P/N FK32580 to FW61622, is still required to be removed in accordance with paragraphs (e)(1) and (e)(2) of the AD. The commenter is unsure if a reworked part can be returned to service under the life limit of the new part number.
The AD applies only to P/N FK32580. If the part is reworked to a different P/N, the requirements of the new P/N would apply. We did not change the AD.
American Airlines requests that we revise the AD to use the service bulletin method of determining the number of cycles before removal is required; specifically, based on a date before the effective date of the AD. The commenter states that the simplified compliance in the SNPRM would result in early engine removal and a cumulative loss of about eleven engine-years of useful service to American Airlines.
We do not agree. The compliance thresholds in the AD are a function of usage, which is not directly related to calendar dates. We did not change the AD.
Rolls-Royce plc requests that we update their contact information in the AD to: Rolls-Royce plc, Corporate Communications, P.O. Box 31, Derby, England, DE248BJ, telephone: 011-44-1332-242424; fax: 011-44-1332-245418, or e-mail:
We agree and changed the AD.
We reviewed the available data and determined that air safety and the public interest require adopting the AD with the change described previously.
We have reviewed the MCAI and, in general, agree with its substance. But we have found it necessary to not incorporate the June 4, 2008 compliance date which is in EASA AD 2010-0087, dated May 5, 2010 (corrected May 6, 2010). We updated the compliance times in the AD based on a more recent assessment of the unsafe condition.
Based on the service information, we estimate that this AD will affect about 78 products of U.S. registry. Required parts will cost about $15,095 per product. We estimate that no additional labor costs would be incurred to perform the actions, as we anticipate that the removal from service of the HP compressor stage 1-4 shafts will occur while the engine is inducted into the shop for routine maintenance. Based on these figures, we estimate the cost of the AD on U.S. operators to be $1,177,410.
Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. “Subtitle VII: Aviation Programs,” describes in more detail the scope of the Agency's authority.
We are issuing this rulemaking under the authority described in “Subtitle VII, Part A, Subpart III, Section 44701: General requirements.” Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.
We determined that this 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 the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979); and
3. Will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
We prepared a regulatory evaluation of the estimated costs to comply with this AD and placed it in the AD docket.
You may examine the AD docket on the Internet at
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.
(a) This airworthiness directive (AD) becomes effective June 7, 2011.
(b) None.
(c) This AD applies to Rolls-Royce plc models RB211-Trent 875-17, -Trent 877-17, -Trent 884-17, -Trent 884B-17, -Trent 892-17, -Trent 892B-17, and -Trent 895-17 turbofan engines, with high-pressure (HP) compressor stage 1-4 shafts, part number (P/N) FK32580, installed.
(d) This AD results from mandatory continuing airworthiness information (MCAI) issued by an aviation authority of another country to identify and correct an unsafe condition on an aviation product. European Aviation Safety Agency (EASA) AD 2010-0087, dated May 5, 2010 (corrected May 6, 2010) states the unsafe condition is as follows:
During manufacture of high-pressure (HP) compressor stage 1 discs, a small number of parts have been rejected due to a machining defect that was found during inspection. Analysis of the possibility of less severe examples having been undetected and passed into service has concluded that action is required to reduce the risk of failure. It was therefore necessary to reduce the life limit.
(e) Unless already done, do the following actions.
(1) For RB211-Trent 800 series engines being monitored by “Multiple Flight Profile Monitoring,” remove the HP compressor stage 1-4 shaft, P/N FK32580, before accumulating 5,580 standard duty cycles (SDC) since-new or within 960 SDC from the effective date of this AD, whichever occurs later.
(2) For RB211-Trent 800 series engines being monitored by “Heavy Flight Profile,” remove the HP compressor stage 1-4 shaft, P/N FK32580, before accumulating 5,280 flight cycles since new or within 860 flight cycles from the effective data of this AD, whichever occurs later.
(f) We have found it necessary to not incorporate the June 4, 2008 compliance date which is in EASA AD 2010-0087, dated May 5, 2010 (corrected May 6, 2010). We also updated the compliance times in the AD based on a more recent assessment of the unsafe condition.
(g) The Manager, Engine Certification Office, FAA, has the authority to approve AMOCs for this AD, if requested using the procedures found in 14 CFR 39.19.
(h) Refer to EASA Airworthiness Directive 2010-0087, dated May 5, 2010 (corrected May 6, 2010), and Rolls-Royce plc Alert Service Bulletin No. RB.211-72-AF825, Revision 3, dated August 25, 2009 for related information. Contact Rolls-Royce plc, Corporate Communications, P.O. Box 31, Derby, England, DE248BJ, telephone: 011-44-1332-242424; fax: 011-44-1332-245418; or e-mail via:
(i) Contact Alan Strom, Aerospace Engineer, Engine Certification Office, FAA, Engine & Propeller Directorate, 12 New England Executive Park, Burlington, MA 01803; e-mail:
Federal Aviation Administration (FAA), DOT.
Final rule.
We are adopting a new airworthiness directive (AD) for the products listed above. This AD results from mandatory continuing airworthiness information (MCAI) issued by an aviation authority of another country to identify and correct an unsafe condition on an aviation product. The MCAI describes the unsafe condition as:
In January 2009 a Trent 895 powered Boeing 777-200 aircraft experienced release of a low pressure (LP) compressor blade which failed due to fatigue cracking in the root section of the blade. The released blade (undercut root standard) had received a part life processing to apply a compression layer to the blade root (Service Bulletin SB 72-D672—Introduction of Laser Shock Peening (LSP)) and also a part life upgrade to the retention feature lubrication system. Investigation has revealed that the effectiveness of this upgraded blade root lubrication coating system may be reduced dependant on the extent of previous running with the earlier standard, leading to increased blade root stress levels. In the specific case of the released blade, a review of its in-service modification history has shown that it operated for a relatively high number of flight cycles prior to the compression layer processing and the new retention feature lubrication system. A review of the Engine Health Monitoring data has also identified it operated at high N1 speeds compared to the Trent 800 fleet average N1 speeds. The combination of these factors has resulted in increased fatigue life usage which is considered to have led to crack initiation and propagation prior to reaching the blades declared life limit. A review of all in-service undercut/LSP standard Trent 800 LP compressor blades has identified specific blades that carry a similar increased susceptibility to cracking.
This AD is issued to mitigate the risk of possible multiple fan blades failure affecting those blades identified as described above which could lead to high energy non contained debris from the engine.
We are issuing this AD to prevent LP compressor blades from failing due to blade root cracks, which could lead to uncontained engine failure and damage to the airplane.
This AD becomes effective June 7, 2011. The Director of the Federal Register approved the incorporation by reference of certain publications listed in this AD as of June 7, 2011.
The Docket Operations office is located at Docket Management Facility, U.S. Department of Transportation, 1200 New Jersey Avenue, SE., West Building Ground Floor, Room W12-140, Washington, DC 20590-0001.
Alan Strom, Aerospace Engineer, Engine Certification Office, FAA, Engine & Propeller Directorate, 12 New England Executive Park, Burlington, MA 01803; e-mail:
We issued a notice of proposed rulemaking (NPRM) to amend 14 CFR part 39 to include an AD that would apply to the specified products. That NPRM was published in the
In January 2009 a Trent 895 powered Boeing 777-200 aircraft experienced release of a low pressure (LP) compressor blade which failed due to fatigue cracking in the root section of the blade. The released blade (undercut root standard) had received a part life processing to apply a compression layer to the blade root (Service Bulletin SB 72-D672—Introduction of Laser Shock Peening (LSP)) and also a part life upgrade to the retention feature lubrication system. Investigation has revealed that the effectiveness of this upgraded blade root lubrication coating system may be reduced dependant on the extent of previous running with the earlier standard, leading to increased blade root stress levels. In the specific case of the released blade, a review of its in-service modification history has shown that it operated for a relatively high number of flight cycles prior to the compression layer processing and the new retention feature lubrication system. A review of the Engine Health Monitoring data has also identified it operated at high N1 speeds compared to the Trent 800 fleet average N1 speeds. The combination of these factors has resulted in increased fatigue life usage which is considered to have led to crack initiation and propagation prior to reaching the blades declared life limit. A review of all in-service undercut/LSP standard Trent 800 LP compressor blades has identified specific blades that carry a similar increased susceptibility to cracking.
This AD is issued to mitigate the risk of possible multiple fan blades failure affecting those blades identified as described above which could lead to high energy non contained debris from the engine.
We gave the public the opportunity to participate in developing this AD. We considered the comments received.
Two commenters, the Boeing Company and American Airlines, request that we ensure that the cyclic requirements in the AD are equivalent to the calendar-based requirements in the MCAI and Alert Service Bulletin (ASB) No. RB.211-72-AG244, Revision 1, dated January 26, 2010. American Airlines' engine serial number (S/N) 51137 is identified as having an allowable inspection threshold of 1,680 cycles from the effective date of the proposed AD. Based on American Airlines' cyclic usage, the FAA AD would allow the blades to operate until March 1, 2014, while the RR ASB would only allow the blades to operate until January 1, 2013. The proposed AD appears to be less conservative for the blades in engine S/N 51137.
We agree. We moved engine S/N 51137 from being listed with the 1,680 cycles threshold, to being listed with a 1,027 cycles threshold in row 3C of Table 1 of the AD.
One commenter, RR, recommends that the FAA retain the calendar date format as specified in the referenced ASB No. RB.211-72-AG244, Revision 1, dated January 26, 2010 for compliance, rather than converting to cycles for the inspection threshold for the sub-population of fan sets. At the request of the National Transportation Safety Board, RR analyzed the modification and installation data for each fan set using both hours and cycles. For some operators, the highest risk value was based on hours and for others it was cycles. Whichever gave the highest risk value, together with the average utilization, was then used to determine the dates at which the blades need to have their initial inspection. Therefore, converting to cycles may not be correct for some operators. Rolls-Royce states that it will monitor N1 speed usage. A higher N1 speed usage could result in the risk values being affected and result in RR ASB No. RB.211-72-AG244, being revised and re-issued. Any change to that ASB would necessitate changing the FAA AD. By retaining the date format and the FAA AD referencing that SB then any future changes to the dates in the Appendices of the SB will not affect the AD. The SB is clear and simple, making it easy for the operators to monitor their affected fan blades. Monitoring a number of fan blades using cycles would make the monitoring more difficult for the operator.
We do not agree. We determined the cycles listed in Table 1 of the AD based on projected operator usage, from the calendar dates in the RR ASB. The SB dates were developed based on the logic given in the first justification paragraph above. The cyclic requirements in the AD are inherently consistent with each operator's risk values. We did not change the AD.
One commenter, Delta Airlines, states that the proposed AD requires use of Appendix 1 of RR ASB No. RB.211-72-AG244 to determine whether blades should be rejected after inspection. Appendix 1 only applies to blades that have been removed from the engine. Delta Airlines requests that the AD be changed so it is clear that the blades can be inspected either in or out of the engine, with appropriate rejection criteria for each method.
We agree. Our intent is not to restrict the inspections to blades removed from the engine. We added Appendix 2 to the incorporation by reference, to include blades not removed.
Delta Airlines also requests that we change the incorporation-by-reference requirement, to state that when re-applying dry film lubricant (DFL) to the fan blades after inspection, either Aircraft Maintenance Manual (AMM) task 72-31-11-400-801-R00, or RR SB No. RB.211-72-D347, may be used. The commenter states that the latest information from RR SB No. RB.211-72-D347 is already in AMM task 72-31-11-400-801-R00.
We partially agree. We agree with specifying in the AD, that blades that pass inspection need to have DFL applied before installing the blades. We do not agree that the AMM or RR No. RB.211-72-D347 need to be incorporated by reference in this AD, as this equates to standard maintenance. Under paragraph (e)(3), we added a paragraph that states, for blades that pass inspection, re-apply dry film lubricant, and install all blades in their original position.
Delta Airlines requests that we give previous credit for previous accomplishments of inspections using the original issue of RR ASB No. RB.211-72-AG244, before the effective date of the AD.
We agree. We changed the AD to add previous credit for that ASB.
Delta Airlines requests that we eliminate the reporting requirements from the AD, which were required by default since the proposed AD required using all of paragraph 3 of RR ASB No. RB.211-72-AG244, Revision 1, dated January 26, 2010, and all of Appendix 1, of that AD. The commenter states that these are administrative tasks that do not need to be part of the AD. Each operator is required to document maintenance and AD compliance per the applicable regulations, and each has their own approved processes for doing so.
We agree and eliminated the reporting requirements by specifying only the paragraphs needed to perform the inspections in the AD.
Delta Airlines requests that we revise the AD to state that after the effective date of this AD, blade serial numbers that are listed in RR No. RB.211-72-AG244, which have reached or are within 100 cycles of the initial inspection thresholds of Table 1 of the proposed AD, may only be installed as replacement blades in other engines if they have been successfully inspected per paragraph (e)(3) of this AD before installation. However, they may be removed and reinstalled in the same engine without paragraph (e)(3) inspections provided they do not exceed the initial and repetitive inspection intervals of paragraphs (e)(1) and (e)(2).
Also, Delta Airlines requests that we revise the AD to state that blades that have been ultrasonically inspected prior to the AD effective date, but which have not yet reached Table 1 thresholds, should be considered not yet “initially inspected,” and thus not subject to the repetitive inspection requirements of paragraph (e)(2) until they reach the Table 1 inspection thresholds. On the same subject, American Airlines requests that the AD include a note similar to the SB to the same effect as the above recommendation. Delta Airlines and American Airlines are concerned that the AD might be interpreted that serviceable spare blades
We agree with the comments that the AD could be more clear as to when the inspections must start, and whether UI for other reasons prior to the thresholds in Table 1 would trigger the repetitive inspection requirements of paragraph (e)(2). We do not agree with the wording of the proposed change because it is simpler to define the phrase, “affected blade.” The requirement of paragraph (e)(5) of the proposed AD, does not require inspections more often than every 100 cycles for any affected blade, since proposed AD paragraph (e)(5) refers to paragraph (e)(2) (repetitive UIs required by this AD). We added a definition to the AD compliance to state for the purpose of this AD, an affected blade is a blade listed in Table 1 of this AD that has accumulated cycles within 100 cycles, of the initial inspection thresholds in Table 1 of this AD.
Delta Airlines and American Airlines request that we add a statement to the AD, stating that the engine serial numbers in Table 1 of the proposed AD are for reference only, and that the AD requirements apply to the blade serial numbers, not the engine serial numbers. The Table 1 listing of engine serial numbers could imply the engine requires initial and repetitive inspections even if blades were replaced with non-affected blades.
We agree. We intend for the AD to apply to the specific fan blade serial numbers listed in RR ASB No. RB.211-72-AG244, Revision 1, dated January 26, 2010. The engine serial numbers are listed for convenience only. We changed Table 1 to state that engine serial numbers are provided for reference only.
American Airlines states that engine serial number 51280 appears to be in the wrong row of Table 1 of the proposed AD. They request that we correct the Table by moving the serial number from the top of row 3E to the bottom of row 3D, in that table.
We partially agree. We reviewed the proposed AD, as published in the
Delta Airlines requests that all thresholds in Table 1 of the proposed AD be the same for a given index. Delta Airlines noticed that most fan blade serial numbers being used in their engines were singled out with a lower threshold than the rest of the blades listed in corresponding appendices of the SB.
We do not agree. We changed the inspection requirements in the proposed AD from calendar-based requirements to cycle-based requirements. Because the intent of the AD is to have the same level of safety as the EASA AD, the cyclic usage of each operator was taken into account when converting from calendar to cyclic thresholds. The intent is for the number of cycles quoted to equate to the calendar times shown in the EASA AD. Since operators fly on different routes and have different procedures, the number of cycles accumulated in a given calendar period will vary as a consequence. We did not change the AD.
American Airlines requests that the FAA verify that the row identifiers in Table 1 of the AD, correspond to the Appendix identifiers in RR ASB No. RB.211-72-AG244, Revision 1, dated January 26, 2010, to ensure that operators properly understand the AD requirements.
We partially agree. We agree with ensuring that Table 1 is clearly understood, to avoid operators from having problems complying with the AD. We do not agree with changing the AD, because Table 1 of the AD provides sufficient clarity in defining the compliance time criteria and what the appropriate sections of the ASB are, to be used. The row identifiers in Table 1 of the AD do correspond to the Appendix identifiers in RR ASB No. RB.211-72-AG244, Revision 1, dated January 26, 2010. We did not change the AD.
We reviewed the available data, including the comments received, and determined that air safety and the public interest require adopting the AD with the changes described previously. We determined that these changes will not increase the economic burden on any operator or increase the scope of the AD.
Based on the service information, we estimate that this AD will affect about 20 engines installed on airplanes of U.S. registry. We also estimate that it will take about 18 work-hours per engine to perform the inspections in one year's time. The average labor rate is $85 per work-hour. We estimate that one LP compressor blade per year will need replacement, at a cost of about $82,000. Based on these figures, we estimate the annual cost of the AD on U.S. operators to be $112,600. Our cost estimate is exclusive of possible warranty coverage.
Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. “Subtitle VII: Aviation Programs,” describes in more detail the scope of the Agency's authority.
We are issuing this rulemaking under the authority described in “Subtitle VII, Part A, Subpart III, Section 44701: General requirements.” Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.
We determined that this 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 the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979); and
3. Will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
We prepared a regulatory evaluation of the estimated costs to comply with this AD and placed it in the AD docket.
You may examine the AD docket on the Internet at
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.
(a) This airworthiness directive (AD) becomes effective June 7, 2011.
(b) None.
(c) This AD applies to Rolls-Royce plc (RR) RB211-Trent 875-17, RB211-Trent 877-17, RB211-Trent 884-17, RB211-Trent 884B-17, RB211-Trent 892-17, RB211-Trent 892B-17, and RB211-Trent 895-17 turbofan engines.
(d) This AD results from mandatory continuing airworthiness information (MCAI) issued by an aviation authority of another country to identify and correct an unsafe condition on an aviation product. We are issuing this AD to prevent low-pressure (LP) compressor blades from failing due to blade root cracks, which could lead to uncontained engine failure and damage to the airplane.
(e) Unless already done, do the following actions.
(1) Using the corresponding compliance threshold in Table 1 of this AD, perform an initial ultrasonic inspection (UI) of the affected LP compressor blades identified by serial number (S/N) in Appendices 3A through 3F of RR Alert Service Bulletin (ASB) No. RB.211-72-AG244, Revision 1, dated January 26, 2010.
(2) Thereafter, perform repetitive UIs of the affected LP compressor blades within every 100 flight cycles.
(3) Use paragraphs 3.A.(1) through 3.A.(2) of Accomplishment Instructions of RR ASB No. RB.211-72-AG244, Revision 1, dated January 26, 2010, paragraphs 1 through 3.B. of Appendix 1, and paragraphs 1 through 3.C. of Appendix 2, of that ASB, to perform the UIs.
(4) Remove blades from service before further flight that fail the inspection criteria in Appendix 1 of RR ASB No. RB.211-72-AG244, Revision 1, dated January 26, 2010.
(5) For blades that pass inspection, re-apply dry film lubricant, and install all blades in their original position.
(6) After the effective date of this AD, do not install any affected LP compressor blade unless it has passed the initial and repetitive UIs required by this AD.
(f) An initial UI performed before the effective date of this AD using RR ASB No. RB.211-72-AG244, dated August 7, 2009, satisfies the initial UI requirements of this AD.
(g) This AD differs from European Aviation Safety Agency (EASA) AD 2010-0097, dated May 26, 2010. The EASA AD uses calendar
(h) The Manager, Engine Certification Office, FAA, has the authority to approve AMOCs for this AD, if requested using the procedures found in 14 CFR 39.19.
(i) Refer to EASA AD 2010-0097, dated May 26, 2010, for related information.
(j) Contact Alan Strom, Aerospace Engineer, Engine Certification Office, FAA, Engine & Propeller Directorate, 12 New England Executive Park, Burlington, MA 01803; e-mail:
(k) For the purpose of this AD, an affected blade is a blade listed in Table 1 of this AD that has accumulated cycles within 100 cycles, of the initial inspection thresholds in Table 1 of this AD.
(l) You must use Rolls-Royce plc Alert Service Bulletin No. RB.211-72-AG244, Revision 1, dated January 26, 2010, Appendix 1, Appendix 2, and Appendices 3A through 3F of that ASB, to do the actions required by this AD.
(1) For service information identified in this AD, contact Rolls-Royce plc, P.O. Box 31, DERBY, DE24 8BJ, UK; telephone 44 1332 242424; fax 44 1332 249936; e-mail:
(2) You may review copies at the FAA, New England Region, 12 New England Executive Park, Burlington, MA; or at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call (202) 741-6030, or go to:
Social Security Administration.
Final rules.
We are eliminating the Decision Review Board (DRB) portions of part 405 of our rules, which we currently use as the final step in our administrative review process for adjudicating initial disability claims in our Boston region. As of the effective date of this regulation, we will replace the DRB step with review by the Appeals Council. The Appeals Council will follow most of the rules in parts 404 and 416 that we use in the rest of the country to adjudicate disability claims at the Appeals Council level, with some differences needed to accommodate the rules that govern administrative law judge (ALJ) hearings in the Boston region. We will also authorize attorney advisors in the Boston region to conduct certain prehearing proceedings and make fully favorable decisions as they do in the rest of the country. We are making these changes to improve service to claimants and to increase consistency in our program rules.
These final rules are effective June 13, 2011.
Paul Kryglik, Social Security Administration, 6401 Security Boulevard, Baltimore, MD 21235-6401, (410) 965-3735 for information about these rules. For information on eligibility or filing for benefits, call our national toll-free number, 1-800-772-1213 or TTY 1-800-325-0778, or visit our Internet site, Social Security Online, at
On March 31, 2006, we published final rules in the
We have continually monitored the DSI process and made appropriate changes when necessary. For example, we published final rules on September 6, 2007, that implemented the QDD process nationally.
On December 4, 2009, we published a notice of proposed rulemaking (NPRM),
In these final rules, we are eliminating the DRB and restoring the Boston region to most of the same rules and procedures at the Appeals Council level under parts 404 and 416 that we currently follow in the rest of the country. We will continue to use our rules about hearings before ALJs under part 405 in the Boston region, including our rules that provide 75-day notice of a hearing and require a claimant to submit all evidence 5 days prior to his or her hearing unless he or she shows good cause. We are eliminating the existing rules that require claimants to ask an ALJ to vacate the ALJ's dismissal of a hearing request. Instead, under our new rules, claimants may appeal an ALJ's dismissal of a hearing request
Although we closed a claimant's official record once an ALJ issued his or her decision under the DSI rules,
With the other changes that we have already made to the DSI process, we no longer need many of the DSI rules in part 405 and are removing references to the FedRO from our rules. These final rules do not affect our Disability Prototype and Single Decisionmaker demonstration projects.
The DRB has not functioned as we originally intended; its workload has grown quickly and become overwhelming. We had intended to use an automated predictive model to select the most error-prone cases for DRB review. However, because we were unable to implement this predictive model, the DRB processed 100% of the unfavorable and partially favorable decisions, requiring significantly more resources than we had anticipated.
The DRB is composed of selected ALJs and administrative appeals judges from the Appeals Council. As members of the DRB, they were unavailable for their regular work, and our efforts to reduce the hearing backlog suffered. Before we implemented DSI, requests for review from the Boston region represented a small fraction of the Appeals Council's total requests for review. Because the DRB processed 100% of the unfavorable and partially favorable cases, there were more cases to review. At the same time, we had an increased number of requests for review by the Appeals Council in other areas of the country as we continued to work down our disability hearings backlog and increased the number of ALJ adjudications nationwide. In fiscal year (FY) 2010, the Appeals Council received 20% more requests for review than in FY 2009, up from 106,965 in FY 2009 to 128,703 in FY 2010.
The DRB's workload also reduced needed resources at the ALJ hearing level, as those ALJs who worked full-time on the DRB were unavailable to hold hearings. If we continued the DRB, we would need to assign even more ALJs to the DRB's workload as the number of DRB receipts rose due to our hearings backlog reduction plan. Consequently, the continued use of the DRB adversely affected our ability to reduce the hearings backlog.
We also are adding a new section 405.342 to allow attorney advisors to conduct prehearing proceedings and issue fully favorable decisions on cases that arise in the Boston region in the same manner as they do in the rest of the country. In our proposed rules, we proposed to follow in the Boston region the same hearings-level procedures we use in the rest of the country, including the rules that apply to our attorney advisor program. Even though these final rules do not adopt for the Boston region all of the hearings-level procedures we use in the rest of the country, we are adding this rule to help us reduce the backlog of cases awaiting a hearing.
We are making a number of conforming changes to sections in parts 404, 405, 416, and 422 to reflect this removal of the DRB rules. Some sections in these final rules differ from the language we proposed in the December 4, 2009 NPRM because these final rules retain the part 405 rules about the ALJ hearing level and include changes made after that date by our final rules “Disability Determinations by State Agency Disability Examiners,” which we published in the
We also are making a technical change to the heading of 20 CFR 416.926(e). The former heading was “Responsibility for determining medical equivalence.” We are changing the heading to “Who is responsible for determining medical equivalence?” This change will make the heading consistent with its counterpart in 20 CFR 404.1526(e) and the format of headings in surrounding sections.
We published an NPRM in the
We decided not to use a process similar to the one we used for FedRO cases because the rapid growth in the DRB's workload, the unanticipated need for adjudicative resources, and the impact on other workloads both at the ALJ hearing level and at the Appeals Council are adversely affecting our ability to serve the public. Transferring all pending DRB cases to the Appeals Council on the effective date of these rules will help us use our resources more effectively and provide the best service to claimants.
We will process partially favorable ALJ decisions transferred to the Appeals Council under these final rules in the following manner. The Appeals Council will send partially favorable ALJ decisions that it receives from the DRB to a processing component, and we will effectuate these decisions in the same manner that we do for cases that arise in other parts of the country. In addition, the Appeals Council will notify those claimants whose claims we have transferred that we have deemed that they have filed a request for Appeals Council review of the ALJ's decision. That notice will inform the claimants that they have a right to file a written request for withdrawal of the deemed request for review. If the Appeals Council grants review of a partially favorable ALJ decision, it will review the entire record and may affirm, modify, or reverse the ALJ's decision.
We will start to use these final rules on the effective date stated above. Until then, we will continue to use our current rules.
On the effective date of these final rules, we will transfer all cases pending before the DRB to the Appeals Council and treat these cases as if the claimant had requested Appeals Council review of the hearing decision. The Appeals Council will notify each of these claimants that we have deemed that he or she has filed a request for Appeals Council review of the ALJ's decision and that he or she has the right to file a written request for withdrawal of the deemed request for Appeals Council review. For cases in which a claimant has appealed a dismissal by an ALJ under the procedures in part 405, we will treat the pending request as a request for Appeals Council review of the ALJ's dismissal. We will transfer to the Appeals Council any cases remanded by a Federal court that we assigned to the DRB. We will immediately begin effectuating partially favorable decisions when we forward them for Appeals Council review.
We consulted with the Office of Management and Budget (OMB) and determined that these final rules meet the criteria for a significant regulatory action under Executive Order 12866, as supplemented by Executive Order 13563. Therefore, OMB reviewed them.
We certify that these final rules will not have a significant economic impact on a substantial number of small entities because they affect only individuals. Therefore, a regulatory flexibility analysis as provided in the Regulatory Flexibility Act, as amended, is not required.
These final rules contain reporting requirements in the regulation sections listed below. For some sections in these rules, we previously accounted for the public reporting burdens in the Information Collection Requests for the various forms the public uses to submit the information to us. Consequently, we are not reporting those sections below. The sections below pose new public reporting burdens not covered by an existing OMB-approved form, and we provide burden estimates for them.
We are also seeking comment on our information collections in our current rule sections listed below. We are updating the public reporting burdens for the information collection requirements under OMB control number 0960-0710. The following are updated burden estimates:
We submitted an Information Collection Request for clearance to OMB. We are soliciting comments on the burden estimate; the need for the information; its practical utility; ways to enhance its quality, utility, and clarity; and ways to minimize the burden on respondents, including the use of automated techniques or other forms of information technology. If you would like to submit comments, please send them to the following locations:
You can submit comments until July 5, 2011, which is 60 days after the publication of these rules. However, your comments will be most useful if you send them to us by June 2, 2011, which is 30 days after publication. To receive a copy of the OMB clearance package, contact the SSA Reports Clearance Officer using any of the above contact methods. We prefer to receive comments by e-mail or fax.
Administrative practice and procedure; Blind; Disability benefits; Old-Age, Survivors, and Disability Insurance; Reporting and recordkeeping requirements; Social Security.
Administrative practice and procedure; Blind, Disability benefits; Old-Age, Survivors, and Disability Insurance; Public assistance programs; Reporting and recordkeeping requirements; Social Security; Supplemental Security Income (SSI).
Administrative practice and procedure; Aged, Blind, Disability benefits, Public Assistance programs; Reporting and recordkeeping requirements; Supplemental Security Income (SSI).
Administrative practice and procedure; Organization and functions (Government agencies); Reporting and recordkeeping requirements; Social Security.
For the reasons set out in the preamble, we amend subparts J, P, and Q of part 404, part 405, subparts I, J, and N of part 416, and subparts B and C of part 422 of chapter III of title 20 Code of Federal Regulations as set forth below:
Secs. 201(j), 204(f), 205(a)-(b), (d)-(h), and (j), 221, 223(i), 225, and 702(a)(5) of the Social Security Act (42 U.S.C. 401(j), 404(f), 405(a)-(b), (d)-(h), and (j), 421, 423(i), 425, and 902(a)(5)); sec. 5, Pub. L. 97-455, 96 Stat. 2500 (42 U.S.C. 405 note); secs. 5, 6(c)-(e), and 15, Pub. L. 98-460, 98 Stat. 1802 (42 U.S.C. 421 note); sec. 202, Pub. L. 108-203, 118 Stat. 509 (42 U.S.C. 902 note).
Secs. 202, 205(a)-(b), and (d)-(h), 216(i), 221(a), (i), and (j), 222(c), 223, 225, and 702(a)(5) of the Social Security Act (42 U.S.C. 402, 405(a)-(b), and (d)-(h), 416(i), 421(a), (i), and (j), 422(c), 423, 425, and 902(a)(5)); sec. 211(b), Pub. L. 104-193, 110 Stat. 2105, 2189; sec. 202, Pub. L. 108-203, 118 Stat. 509 (42 U.S.C. 902 note).
(b) * * *
(8) At the administrative law judge and Appeals Council levels, findings, other than the ultimate determination about whether you are disabled, made by State agency medical or psychological consultants and other program physicians or psychologists, or other medical specialists, and opinions expressed by medical experts or psychological experts that we consult based on their review of the evidence in your case record.
(c) * * * At the administrative law judge and Appeals Council levels, we will consider residual functional capacity assessments made by State agency medical and psychological consultants, and other program physicians and psychologists to be “statements about what you can still do” made by nonexamining physicians and psychologists based on their review of the evidence in the case record. * * *
(a) The rate of payment for purchasing medical or other services necessary to make determinations of disability may not exceed the highest rate paid by Federal or public agencies in the State for the same or similar types of service.
* * * A State agency medical consultant must approve the ordering of any diagnostic test or procedure when there is a chance it may involve significant risk. * * *
(c) Consistent with Federal and State laws, the State agency administrator will work to achieve appropriate rates of payment for purchased medical services.
(d) * * *
(2) * * * We will record the presence or absence of the criteria and the rating of the degree of functional limitation on a standard document at the initial and reconsideration levels of the administrative review process, or in the decision at the administrative law judge hearing and Appeals Council levels (in cases in which the Appeals Council issues a decision). * * *
(e)
(1) When a State agency medical or psychological consultant makes the determination together with a State agency disability examiner at the initial or reconsideration level of the administrative review process as provided in § 404.1615(c)(1) of this part, the State agency medical or psychological consultant has overall responsibility for assessing medical severity. A State agency disability examiner may assist in preparing the standard document. However, our medical or psychological consultant must review and sign the document to attest that it is complete and that he or she is responsible for its content, including the findings of fact and any discussion of supporting evidence.
(4) At the administrative law judge hearing and Appeals Council levels, the written decision must incorporate the pertinent findings and conclusions based on the technique. The decision must show the significant history, including examination and laboratory findings, and the functional limitations that were considered in reaching a conclusion about the severity of the mental impairment(s). The decision must include a specific finding as to the degree of limitation in each of the functional areas described in paragraph (c) of this section.
(5) If the administrative law judge requires the services of a medical expert to assist in applying the technique but such services are unavailable, the administrative law judge may return the case to the State agency or the appropriate Federal component, using the rules in § 404.941 of this part, for completion of the standard document. If, after reviewing the case file and completing the standard document, the State agency or Federal component concludes that a determination favorable to you is warranted, it will process the case using the rules found in § 404.941(d) or (e) of this part. If, after reviewing the case file and completing the standard document, the State agency or Federal component concludes that a determination favorable to you is not warranted, it will send the completed standard document and the case to the administrative law judge for further proceedings and a decision.
(d)
(e)
(f) * * *
(1) In claims adjudicated by the State agency, a State agency medical or psychological consultant may make the determination of disability together with a State agency disability examiner or provide one or more medical opinions to a State agency disability examiner when the disability examiner makes the initial or reconsideration determination alone (
(b) * * * In cases decided by a State agency (except in disability hearings under §§ 404.914 through 404.918 of this part and in fully favorable determinations made by State agency disability examiners alone under § 404.1615(c)(3) of this part), a State agency medical or psychological consultant or other medical or psychological consultant designated by the Commissioner directly participates in determining whether your medically determinable impairment(s) could reasonably be expected to produce your alleged symptoms. * * * At the administrative law judge hearing or Appeals Council level of the administrative review process, the adjudicator(s) may ask for and consider the opinion of a medical or psychological expert concerning whether your impairment(s) could reasonably be expected to produce your alleged symptoms. * * *
(a)
(c)
Secs. 205(a), 221, and 702(a)(5) of the Social Security Act (42 U.S.C. 405(a), 421, and 902(a)(5)).
The State will determine the rates of payment for purchasing medical or other services necessary to make determinations of disability. * * *
Secs. 201(j), 205(a)-(b), (d)-(h), and (s), 221, 223(a)-(b), 702(a)(5), 1601, 1602, 1631, and 1633 of the Social Security Act (42 U.S.C. 401(j), 405(a)-(b), (d)-(h), and (s), 421, 423(a)-(b), 902(a)(5), 1381, 1381a, 1383, and 1383b).
(b) * * *
(1) * * * We use the procedures in part 404 subpart J of this chapter, part 416 subpart N of this chapter, or both, for your initial determination.
(2)
(3)
(4)
(5)
(c) * * *
(2)
(3)
As used in this part:
(1) An application for benefits that is based on whether you are disabled under title II of the Act, or
(2) An application for supplemental security income payments that is based on whether you are disabled or blind under title XVI of the Act.
(3) For purposes of this part, the terms “disability claim” or “claim” do not include a continuing disability review or age-18 redetermination.
(a) If you want us to extend the deadline to request administrative or judicial review, you must establish that there is good cause for missing the deadline. * * *
(a) This subpart explains what to do if you are dissatisfied with a reconsidered determination or an initial determination subject to a hearing by an administrative law judge under the procedures in this part as a result of § 404.906(b)(4) or § 416.1406(b)(4) of this chapter. * * *
You may request a hearing before an administrative law judge if you are dissatisfied with the reconsidered determination on your disability claim or an initial determination subject to a hearing by an administrative law judge under the procedures in this part as a result of §§ 404.906(b)(4) or 416.1406(b)(4) of this chapter.
(a)
(3) The specific reasons you disagree with the previous determination,
(b)
After a hearing is requested but before it is held, an attorney advisor may conduct prehearing proceedings as set out in §§ 404.942(c) or 416.1442(c) of this chapter. If, after the completion of these proceedings, we can make a decision that is fully favorable to you and all other parties based on the preponderance of the evidence, an attorney advisor, instead of an administrative law judge, may issue the decision. We use the procedures §§ 404.942 or 416.1442 of this chapter when we conduct prehearing proceedings or issue decisions under this section.
* * * Subject to § 405.401(c), the official record closes once the administrative law judge issues his or her decision regardless of whether it becomes our final decision.
(a) * * *
(2) If the administrative law judge consolidates the claims, he or she will decide both claims, even if we have not yet made an initial determination or a reconsidered determination on the other claim.
(b) * * * Within five days after the hearing, if there are no subsequent changes to the analysis in the oral decision, we will send you a written decision that incorporates such oral decision by reference. * * *
* * * The notice accompanying the decision will explain your right to representation. It also will explain your right to request review of the decision by the Appeals Council.
The decision of the administrative law judge is binding on all parties to the hearing unless—
(a) You or another party requests a review of the decision by the Appeals Council within the stated time period, and the Appeals Council reviews your case;
(b) You or another party requests a review of the decision by the Appeals Council within the stated time period, the Appeals Council denies your request for review, you seek judicial review of your case by filing an action in a Federal district court, and the Federal court reverses the decision or remands it for further administrative action;
(c) An administrative law judge or the Appeals Council revises the decision under § 405.601 of this part;
(d) You use the expedited appeals process described in §§ 404.923 through 404.928 or 416.1423 through 416.1428 of this chapter;
(e) The ALJ decided the case after a Federal court remanded your case to us, and the Appeals Council follows the procedures in §§ 404.984 or 416.1484 of this chapter to assume jurisdiction of your case; or
(f) The Appeals Council reviews the claim on its own motion.
* * * The notice will tell you that you may ask the Appeals Council to review the dismissal and will explain your right to representation. Your request for review by the Appeals Council must be in writing and must be filed within 60 days after the date that you receive notice of the dismissal.
The administrative law judge's dismissal of a request for a hearing is binding and not subject to further review, unless an administrative law judge or the Appeals Council vacates it.
(a) If you (or any other party) are dissatisfied with the hearing decision or with the dismissal of a hearing request under this part, you may request that the Appeals Council review that action. The Appeals Council may also initiate review on its own motion. Except as specifically provided in this subpart, we will follow our rules for Appeals Council review in §§ 404.966 through 404.984 and 416.1466 through 416.1484 of this chapter.
(b) If you seek Appeals Council review, you must file your request within the time period and in accordance with the procedures in §§ 404.968 and 416.1468 of this chapter. The Appeals Council will consider additional evidence only in accordance with paragraph (c) of this section.
(c) If you submit additional evidence, the Appeals Council will consider the additional evidence only where it relates to the period on or before the date of the hearing decision, and only if you show that there is a reasonable probability that the evidence, alone or when considered with the other evidence of record, would change the outcome of the decision, and
(1) Our action misled you;
(2) You had a physical, mental, educational, or linguistic limitation(s) that prevented you from submitting the evidence earlier; or
(3) Some other unusual, unexpected, or unavoidable circumstance beyond your control prevented you from submitting the evidence earlier.
Subject to § 405.401(c), the record is closed as of the date of the administrative law judge's decision, and the Appeals Council will base its action on the same evidence that was before the administrative law judge.
* * * You must file your request with the Appeals Council. * * *
When a Federal court remands a claim decided under this part for further agency consideration, the Appeals Council may make a decision based upon the evidence in the record, or it may remand the claim to an administrative law judge. If the Appeals Council remands a claim to an administrative law judge, the Appeals Council will send you a notice of remand.
Secs. 221(m), 702(a)(5), 1611, 1614, 1619, 1631(a), (c), (d)(1), and (p), and 1633 of the Social Security Act (42 U.S.C. 421(m), 902(a)(5), 1382, 1382c, 1382h, 1383(a), (c), (d)(1), and (p), and 1383b); secs. 4(c) and 5, 6(c)-(e), 14(a), and 15, Pub. L. 98-460, 98 Stat. 1794, 1801, 1802, and 1808 (42 U.S.C. 421 note, 423 note, and 1382h note).
(b) * * *
(8) At the administrative law judge and Appeals Council levels, findings, other than the ultimate determination about whether you are disabled, made by State agency medical or psychological consultants and other program physicians or psychologists, or other medical specialists, and opinions expressed by medical experts or psychological experts that we consult based on their review of the evidence in your case record. See §§ 416.927(f)(2)-(3).
(c) * * * At the administrative law judge and Appeals Council levels, we will consider residual functional capacity assessments made by State agency medical and psychological consultants and other program physicians and psychologists to be “statements about what you can still do” made by nonexamining physicians and psychologists based on their review of the evidence in the case record. * * *
(a) The rate of payment for purchasing medical or other services necessary to make determinations of disability may not exceed the highest rate paid by Federal or public agencies in the State for the same or similar types of service. See §§ 416.1024 and 416.1026 of this part.
* * * A State agency medical consultant must approve the ordering of any diagnostic test or procedure when there is a chance it may involve significant risk. * * *
(c) Consistent with Federal and State laws, the State agency administrator will work to achieve appropriate rates of payment for purchased medical services.
(d) * * *
(2) * * * We will record the presence or absence of the criteria and the rating of the degree of functional limitation on a standard document at the initial and reconsideration levels of the administrative review process, or in the decision at the administrative law judge hearing and Appeals Council levels (in cases in which the Appeals Council issues a decision). * * *
(e)
(1) When a State agency medical or psychological consultant makes the determination together with a State agency disability examiner at the initial or reconsideration level of the administrative review process as provided in § 416.1015(c)(1) of this part, the State agency medical or psychological consultant has overall
(4) At the administrative law judge hearing and Appeals Council levels, the written decision must incorporate the pertinent findings and conclusions based on the technique. The decision must show the significant history, including examination and laboratory findings, and the functional limitations that were considered in reaching a conclusion about the severity of the mental impairment(s). The decision must include a specific finding as to the degree of limitation in each of the functional areas described in paragraph (c) of this section.
(5) If the administrative law judge requires the services of a medical expert to assist in applying the technique but such services are unavailable, the administrative law judge may return the case to the State agency or the appropriate Federal component, using the rules in § 416.1441 of this part, for completion of the standard document. If, after reviewing the case file and completing the standard document, the State agency or Federal component concludes that a determination favorable to you is warranted, it will process the case using the rules found in § 416.1441(d) or (e) of this part. If, after reviewing the case file and completing the standard document, the State agency or Federal component concludes that a determination favorable to you is not warranted, it will send the completed standard document and the case to the administrative law judge for further proceedings and a decision.
(g)
(d)
(e)
(n)
(f) * * *
(1) In claims adjudicated by the State agency, a State agency medical or psychological consultant may make the determination of disability together with a State agency disability examiner or provide one or more medical opinions to a State agency disability examiner when the disability examiner makes the initial or reconsideration determination alone (
(b) * * * In cases decided by a State agency (except in disability hearings under §§ 416.1414 through 416.1418 of this part and in fully favorable determinations made by State agency disability examiners alone under § 416.1015(c)(3) of this part), a State agency medical or psychological consultant or other medical or psychological consultant designated by the Commissioner directly participates in determining whether your medically determinable impairment(s) could reasonably be expected to produce your alleged symptoms. * * * At the
(a)
(c)
Secs. 702(a)(5), 1614, 1631, and 1633 of the Social Security Act (42 U.S.C. 902(a)(5), 1382c, 1383, and 1383b).
The State will determine the rates of payment for purchasing medical or other services necessary to make determinations of disability. * * *
Secs. 702(a)(5), 1631, and 1633 of the Social Security Act (42 U.S.C. 902(a)(5), 1383, and 1383b); sec. 202, Pub. L. 108-203, 118 Stat. 509 (42 U.S.C. 902 note).
Secs. 205, 232, 702(a)(5), 1131, and 1143 of the Social Security Act (42 U.S.C. 405, 432, 902(a)(5), 1320b-1, and 1320b-13), and sec. 7213(a)(1)(A) of Pub. L. 108-458.
(b) * * * An individual who files an application for monthly benefits, the establishment of a period of disability, a lump-sum death payment, or entitlement to hospital insurance benefits or supplementary medical insurance benefits, either on his own behalf or on behalf of another, must establish by satisfactory evidence the material allegations in his application, except as to earnings shown in the Social Security Administration's records (
(c) * * * Section 404.1503 of this chapter has a discussion of the respective roles of State agencies and the Administration in the making of disability determinations and information regarding initial determinations as to entitlement or termination of entitlement in disability claims. * * *
If you are dissatisfied with an initial determination with respect to entitlement to monthly benefits, a lump-sum death payment, a period of disability, a revision of an earnings record, with respect to any other right under title II of the Social Security Act, or with respect to entitlement to hospital insurance benefits or supplementary medical insurance benefits, you may request that we reconsider the initial determination. The information in § 404.1503 of this chapter as to the respective roles of State agencies and the Social Security Administration in making disability determinations is also generally applicable to the reconsideration of initial determinations involving disability. However, in cases in which a disability hearing as described in §§ 404.914 through 404.918 and §§ 416.1414 through 416.1418 of this chapter is available, the reconsidered determination may be issued by a disability hearing officer or the Associate Commissioner for Disability Programs or his or her delegate. After the initial determination has been reconsidered, we will mail you written notice and inform you of your right to a hearing before an administrative law judge (
Secs. 205, 221, and 702(a)(5) of the Social Security Act (42 U.S.C. 405, 421, and 902(a)(5)); 30 U.S.C. 923(b).
This subpart describes in general the procedures relating to hearings before an administrative law judge of the Office of Disability Adjudication and Review, review by the Appeals Council of the hearing decision or dismissal, and court review in cases decided under the procedures in parts 404, 405, 408, 410, and 416 of this chapter. * * * Procedures related to hearings before an administrative law judge, review by the Appeals Council, or court review in claims adjudicated under the procedures in part 405 of this chapter are explained in subparts D, E, and F of part 405 of this chapter. * * *
In rule document 2011-7933 appearing on pages 18384-18388 in the issue of Monday, April 4, 2011, make the following correction:
On page 18385, in the third column, in § 301.6323(b)-1(g)(1), on the fifth line, “lien or” should read “lienor”.
Coast Guard, DHS.
Temporary final rule.
The Coast Guard is establishing a temporary safety zone in the Atlantic Ocean east of Sunny Isles Beach, Florida for the Fourth Annual Offshore Challenge. The Fourth Annual Offshore Challenge will consist of a series of high-speed boat races. The boat races are scheduled to take place from Friday, June 17, 2011 through Sunday, June 19, 2011. The temporary safety zone is necessary for the safety of race participants, participant vessels, spectators, and the general public during the races. Persons and vessels are prohibited from entering, transiting through, anchoring in, or remaining within the safety zone unless authorized by the Captain of the Port Miami or a designated representative.
This rule is effective from 8 a.m. on June 17, 2011 through 5 p.m. on June 19, 2011. This rule will be enforced daily from 8 a.m. until 5 p.m. on June 17, 2011 through June 19, 2011.
Comments and material received from the public, as well as documents mentioned in this preamble as being available in the docket, are part of docket USCG-2011-0034 and are available online by going to
If you have questions on this temporary final rule, call or e-mail Lieutenant Paul A. Steiner, Sector Miami Prevention Department, Coast Guard; telephone 305-535-8724, e-mail
On February 17, 2011, we published a notice of proposed rulemaking (NPRM) entitled Safety Zone; Fourth Annual Offshore Challenge, Sunny Isles Beach, FL in the
Offshore Events, LLC is hosting the Fourth Annual Offshore Challenge, a series of high-speed boat races. The Fourth Annual Offshore Challenge will commence on June 17, 2011 and conclude on June 19, 2011. The boat races will be held in the Atlantic Ocean offshore of Sunny Isles Beach, Florida. Approximately 50 offshore power boats will be participating in the boat races. These vessels will be traveling at high speeds. Approximately 200 spectator vessels are expected to observe the races. The high speed of the participant vessels poses a safety hazard to race participants, participant vessels, spectators, and the general public. The temporary safety zone is necessary to protect race participants, participant vessels, spectators, and the general public from the hazards associated with the high-speed boat races.
There were no comments to the NPRM, and we made no changes to the regulation.
We developed this rule after considering numerous statutes and executive orders related to rulemaking. Below we summarize our analyses based on 13 of these statutes or executive orders.
This rule is not a significant regulatory action under section 3(f) of Executive Order 12866, Regulatory Planning and Review, and does not require an assessment of potential costs and benefits under section 6(a)(3) of that Order. The Office of Management and Budget has not reviewed it under that Order.
The economic impact of this rule is not significant for the following reasons: (1) The rule will be in effect for three days but will only be enforced for a total of nine hours each day; (2) although persons and vessels will not be able to enter, transit through, anchor in, or remain within the safety zone without authorization from the Captain of the Port Miami or a designated representative, they may operate in the surrounding area during the enforcement period; (3) persons and vessels may still enter, transit through, anchor in, or remain within the safety zone if authorized by the Captain of the Port Miami or a designated representative; and (4) advance notification of the safety zone will be made to the local maritime community via local notice to mariners, marine safety information bulletins, and broadcast notice to mariners.
Under the Regulatory Flexibility Act (5 U.S.C. 601-612), we have considered whether this rule would have a significant economic impact on a substantial number of small entities. The term “small entities” comprises small businesses, not-for-profit organizations that are independently owned and operated and are not dominant in their fields, and governmental jurisdictions with populations of less than 50,000.
The Coast Guard certifies under 5 U.S.C. 605(b) that this rule will not have a significant economic impact on a substantial number of small entities for the reasons discussed in the Regulatory Planning and Review section above.
Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Pub. L. 104-121), in the NPRM we offered to assist small entities in understanding the rule so that they could better evaluate its effects
Small businesses may send comments on the actions of Federal employees who enforce, or otherwise determine compliance with, Federal regulations to the Small Business and Agriculture Regulatory Enforcement Ombudsman and the Regional Small Business Regulatory Fairness Boards. The Ombudsman evaluates these actions annually and rates each agency's responsiveness to small business. If you wish to comment on actions by employees of the Coast Guard, call 1-888-REG-FAIR (1-888-734-3247). The Coast Guard will not retaliate against small entities that question or complain about this rule or any policy or action of the Coast Guard.
This rule calls for no new collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520).
A rule has implications for federalism under Executive Order 13132, Federalism, if it has a substantial direct effect on State or local governments and would either preempt State law or impose a substantial direct cost of compliance on them. We have analyzed this rule under that Order and have determined that it does not have implications for federalism.
The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538) requires Federal agencies to assess the effects of their discretionary regulatory actions. In particular, the Act addresses actions that may result in the expenditure by a State, local, or tribal government, in the aggregate, or by the private sector of $100,000,000 or more in any one year. Though this rule will not result in such an expenditure, we do discuss the effects of this rule elsewhere in this preamble.
This rule will not effect a taking of private property or otherwise have taking implications under Executive Order 12630, Governmental Actions and Interference with Constitutionally Protected Property Rights.
This rule meets applicable standards in sections 3(a) and 3(b)(2) of Executive Order 12988, Civil Justice Reform, to minimize litigation, eliminate ambiguity, and reduce burden.
We have analyzed this rule under Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks. This rule is not an economically significant rule and does not create an environmental risk to health or risk to safety that may disproportionately affect children.
This rule does not have tribal implications under Executive Order 13175, Consultation and Coordination with Indian Tribal Governments, because it does not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes.
We have analyzed this rule under Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use. We have determined that it is not a “significant energy action” under that order because it is not a “significant regulatory action” under Executive Order 12866 and is not likely to have a significant adverse effect on the supply, distribution, or use of energy. The Administrator of the Office of Information and Regulatory Affairs has not designated it as a significant energy action. Therefore, it does not require a Statement of Energy Effects under Executive Order 13211.
The National Technology Transfer and Advancement Act (NTTAA) (15 U.S.C. 272 note) directs agencies to use voluntary consensus standards in their regulatory activities unless the agency provides Congress, through the Office of Management and Budget, with an explanation of why using these standards would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., specifications of materials, performance, design, or operation; test methods; sampling procedures; and related management systems practices) that are developed or adopted by voluntary consensus standards bodies.
This rule does not use technical standards. Therefore, we did not consider the use of voluntary consensus standards.
We have analyzed this rule under Department of Homeland Security Management Directive 023-01 and Commandant Instruction M16475.lD, which guide the Coast Guard in complying with the National Environmental Policy Act of 1969 (NEPA) (42 U.S.C. 4321-4370f). We are also issuing a marine event permit for this event. Because the issuance of the marine permit for this event is not an action that is one of a category of actions that do not individually or cumulatively have a significant effect on the human environment, we conducted an environmental assessment for both the issuance of the marine event permit and the establishment of this temporary safety zone. After conducting the environmental assessment for the issuance of the marine event permit and the establishment of this temporary safety zone, we have concluded these actions will not significantly affect the human environment. The environmental assessment and finding of no significant impact are available in the docket where indicated under
Harbors, Marine safety, Navigation (water), Reporting and recordkeeping requirements, Security measures, Waterways.
For the reasons discussed in the preamble, the Coast Guard amends 33 CFR part 165 as follows:
33 U.S.C. 1226, 1231; 46 U.S.C. Chapter 701, 3306, 3703; 50 U.S.C. 191, 195; 33 CFR 1.05-1, 6.04-1, 6.04-6, 160.5; Pub. L. 107-295, 116 Stat. 2064; Department of Homeland Security Delegation No. 0170.1.
(a)
(b)
(c)
(2) Persons and vessels desiring to enter, transit through, anchor in, or remain within the regulated area may contact the Captain of the Port Miami via telephone at 305-535-4472, or a designated representative via VHF radio on channel 16, to seek permission. If permission to enter, transit through, anchor in, or remain within the regulated area is granted by the Captain of the Port Miami or a designated representative, all persons and vessels receiving such permission must comply with the instructions of the Captain of the Port Miami or a designated representative.
(3) The Coast Guard will provide notice of the regulated area via local notice to mariners, marine safety information bulletins, broadcast notice to mariners, and by on-scene designated representatives.
(d)
Office of Government Ethics (OGE).
Proposed rule.
The Office of Government Ethics is issuing a proposed rule amendment that would permit Government employees to participate in particular matters affecting the financial interests of nonprofit organizations in which they serve in an official capacity, notwithstanding the employees' imputed financial interest. This document also proposes an amendment that would clarify that the existing exemptions for interests in the holdings of sector mutual funds also apply to interests in the holdings of sector unit investment trusts.
Comments are invited and must be received on or before July 5, 2011.
You may submit comments, in writing, to OGE on this proposed rule, identified by RIN 3209-AA09, by any of the following methods:
Richard M. Thomas, Associate General Counsel, Office of Government Ethics;
Section 208(a) of title 18 of the United States Code prohibits Government employees from participating in an official capacity in particular Government matters in which, to their knowledge, they or certain other persons specified in the statute have a financial interest, if the particular matter would have a direct and predictable effect on that interest. Section 208(b)(2) of title 18 permits the Office of Government Ethics to promulgate regulations describing financial interests that are too remote or inconsequential to warrant disqualification pursuant to section 208(a).
On August 28, 1995, the Office of Government Ethics published its first interim rule, with request for comments, promulgating certain miscellaneous exemptions under 18 U.S.C. 208(b)(2). 60 FR 44705 (August 28, 1995). On December 18, 1996, the Office of Government Ethics published a comprehensive final rule, “Interpretation, Exemptions and Waiver Guidance Concerning 18 U.S.C. 208 (Acts Affecting a Personal Financial Interest),” codified at 5 CFR part 2640, which promulgated several additional exemptions and also adopted as final, with some modifications, the exemptions promulgated in the earlier interim rule. 61 FR 66829 (December 18, 1996) (final rule); 60 FR 47207 (September 11, 1995) (proposed rule). OGE subsequently has added and amended exemptions by interim rule, with request for comment, 65 FR 16511 (March 29, 2000) (adopted as final, 65 FR 47830 (August 4, 2000)), by final rule (after a proposed rule, 65 FR 53942 (September 6, 2000)), 67 FR 12443 (March 19, 2002), and by interim rule, with request for comment, 70 FR 69041 (November 14, 2005).
The Office of Government Ethics is proposing to amend part 2640 by adding a new regulatory exemption and clarifying the scope of an existing exemption, as explained below. This proposed rule is being published after obtaining the concurrence of the Department of Justice pursuant to section 201(c) of Executive Order 12674. Also, as provided in section 402 of the Ethics in Government Act of 1978, as amended, 5 U.S.C. appendix, section 402, OGE has consulted with both the Department of Justice (as additionally required under 18 U.S.C. 208(d)(2)) and the Office of Personnel Management on this rule.
The proposed rule would add a new regulatory exemption, section 2640.203(m), which would permit employees to participate in particular matters affecting the financial interests of nonprofit organizations in which they participate, in their official Government capacity, as officers, directors or trustees. The proposed rule also would clarify that the existing regulatory exception for certain interests in sector mutual funds, at section 2640.201(b), also covers interests in sector unit investment trusts.
Proposed section 2640.203(m) addresses a situation that was not generally thought to be covered by 18 U.S.C. 208 until the mid-1990s. Until that time, a number of agencies had a practice of assigning employees to participate on the boards of directors of certain outside nonprofit organizations, where such service was deemed to further the statutory mission and/or personnel development interests of the agency. The nonprofit organizations included such entities as professional associations, scientific societies, and health information promotion organizations. At the time, neither the agencies involved nor the Office of Government Ethics viewed such official participation in nonprofit organizations as being prohibited by 18 U.S.C. 208.
However, in 1996, the Office of Legal Counsel (OLC) at the Department of Justice issued an opinion concluding that section 208 generally prohibits an employee from serving, in an official capacity, as an officer, director or trustee of a private nonprofit organization. Memorandum of Deputy Assistant Attorney General, OLC, for General Counsel, Federal Bureau of Investigation, November 19, 1996,
Since the 1996 OLC opinion, some agencies have continued to assign employees to serve on such outside boards by granting the employees individual waivers under 18 U.S.C. 208(b)(1). Other agencies have declined to issue individual waivers (or have done so rarely), often because of discomfort about waiving the application of a criminal statute. OGE has fielded numerous inquiries and has held many meetings with agencies and nonprofit organizations, mostly professional and scientific societies, concerning the application of section 208 to prevent official participation on outside boards. Several of the agencies and nonprofit organizations have argued that the application of section 208 has created unfortunate barriers to professional development and meaningful exchange between Federal and non-Federal experts in certain professions and areas of expertise. Moreover, some of the organizations have pointed out that there is a lack of uniformity within the Executive Branch, owing to the willingness of some agencies to grant waivers and the unwillingness of other agencies to do so, often with respect to participation in the same organization.
Additionally, the Office of Government Ethics has noted the potential for confusion in some instances when employees are permitted to serve only in a private, rather than official, capacity. Especially where the agency has policy interests that overlap with those of the nonprofit organization, it can be very difficult for the employee to avoid the mistaken impression that he or she is acting in an official capacity when participating in the organization. Employees may be uncertain about the extent to which they are permitted to make reference to their official position or to use official time or agency resources.
For all of the above reasons, the Office of Government Ethics in 2006 recommended to the President and Congress that section 208 be amended “to specify that the financial interests of an organization are not imputed to an employee who serves as an officer or director of such organization in his or her official capacity.” OGE,
Then, on March 9, 2009 President Obama issued a Memorandum for the Heads of Executive Departments and Agencies on the topic of scientific integrity. 74 FR 10671, 3 CFR, 2009 Comp., p. 354. In this memorandum, he specifically requested that the Office of Science and Technology Policy (OSTP) provide recommendations to address, among other things, the retention of staff in scientific and technical positions within the Executive branch. In response, the Director of OSTP issued a memorandum urging all agencies to establish policies that promote and facilitate the professional development of Government scientists and engineers. John P. Holdren, Director, OSTP, “Scientific Integrity,” Memorandum for the Heads of Executive Departments and Agencies, at 3, December 17, 2010. The OSTP memorandum specifically calls for policies to “[a]llow full participation in professional or scholarly societies, committees, task forces and other specialized bodies of professional societies,
In response to parallel initiatives, in August of 2010, the Director of the Office of Personnel Management (OPM) wrote to OGE to express several concerns about the application of section 208 to employees serving in their official capacity as officers and directors of scientific and professional organizations. Letter of John Berry, Director, OPM, to Robert I. Cusick, Director, Office of Government Ethics, August 16, 2010 (OPM Letter). Among other things, the Director of OPM wrote:
Policies restricting Federal scientists' and professionals' involvement in professional organizations negatively impact the agencies employing such individuals. Restrictions act as a barrier to employees achieving professional stature in their respective fields, which may discourage scientists and professionals from considering Federal employment. Restrictions also serve to isolate scientists and professionals from the full exchange of knowledge and ideas necessary to stay current and participate fully as members of the greater scientific community. As a result, Federal scientists and professionals are hampered in their ability to provide the best possible advice and service to their respective agencies. These restrictions are particularly burdensome for the “research-grade” scientists whose retention and promotion evaluations depend in part on the recognition of stature by one's scientific peers. U. S. Office of Personnel Management's
To address OPM's concerns, as well as the concerns raised by other agencies and outside organizations since 1996, and consistent with Administration efforts designed to ensure scientific integrity, OGE has concluded that it is now appropriate to exercise its authority under 18 U.S.C. 208(b)(2) to exempt the imputed financial interests of nonprofit organizations in which employees serve as officers, directors or trustees in their official capacity. OGE has determined that such financial interests are too remote or inconsequential to affect the integrity of employees' services, for several reasons. As explained in OGE's 2006 Report, which was issued after consultation with the Department of Justice:
OGE believes that the conflict identified by OLC [between the employee's duty of loyalty to the Government and the employee's fiduciary duties to the outside organization] may be more theoretical than real, particularly because employees assigned to serve on outside boards remain subject to important Federal controls, such as the authority to review and approve (or deny) the official activity in the first place, and the authority to order the individual to limit the activity, or even resign the position, in the event of a true conflict with Federal interests. In addition, an agency generally approves such activities only where the organization's interests are in consonance with the agency's own interests. In an era when ‘public/private partnerships' are promoted as a positive way for Government to achieve its objectives more efficiently, ethics officials find it difficult to explain and justify to agency employees why a waiver is required for official board services that have been determined by the agency to be proper. 2006 Report at 33.
In short, the potential for a real conflict of interest is too remote or inconsequential to affect the integrity of an employee's services under these circumstances.
That is not to say, however, that agencies would be precluded from imposing meaningful controls and limits on employees serving in nonprofit organizations. As made clear in the Note following proposed section 2640.203(m), agencies must satisfy themselves that they have authority to assign employees to serve in such organizations in the first place; the proposed exemption does not itself constitute such authority, but simply removes the bar of the conflict of interest law. Moreover, agency decisions to permit (or not permit) official participation in any particular outside organization will be informed by numerous legal, policy, and managerial considerations, such as: the degree to which the activity will further the agency's statutory mission; the availability of agency funds and other resources to support such activities; the degree to which the agency is able and willing to assign employees to serve in other, similar organizations without appearing to single out one organization unreasonably; and the demands of the agency's workload and the particular employee's other assignments.
Finally, OGE notes that the proposed rule refers generally to “nonprofit” organizations.
Among the regulatory exemptions currently found in subpart B of part 2640 are several that exempt certain financial interests in mutual funds and unit investment trusts. The Office of Government Ethics has promulgated exemptions for interests in the holdings of diversified mutual funds and diversified unit investment trusts (5 CFR 2640.201(a)), in the non-sector holdings of sector mutual funds (5 CFR 2640.201(b)(1)), and in the sector holdings of sector mutual funds when the aggregate market value of the employee's interest in the sector fund or funds does not exceed $50,000 (5 CFR 2640.201(b)(2)). Most recently, the Office of Government Ethics has promulgated one for interests in mutual funds and unit investment trusts other than interests arising from the holdings of such vehicles (5 CFR 2640.201(d)). This exemption is limited to particular matters of general applicability, as defined in 5 CFR 2640.102(m).
In promulgating these exemptions, the Office of Government Ethics recognized that pooled investment vehicles such as mutual funds and unit investment trusts generally pose fewer concerns that the financial interests will affect the integrity of the services of Government employees. The Office of Government Ethics has noted that usually “only a limited portion of the fund's assets [are] placed in the securities of any single issuer” and that “an employee's interest in any one fund is only a small portion of the fund's total assets.” 60 FR 47211 (September 11, 1995) (preamble to proposed rule).
The Office of Government Ethics is proposing to amend the language of the exemptions for the interests in sector mutual funds to include explicitly the interests of sector unit investment trusts. The current regulation, 5 CFR 2640.201(b), does not include the language “sector unit investment trusts.” At the time that the sector fund exemptions were promulgated, the Office of Government Ethics contemplated that the exemptions would also extend to those investment vehicles organized as sector unit investment trusts. In practice, the Office of Government Ethics has permitted executive branch employees to apply the exemptions for interests in sector
Therefore, OGE is proposing to add specific references to sector unit investment trusts to 5 CFR 2640.201(b) in order to clarify that the exemptions for interests in the holdings of sector mutual funds also apply to the interests in the holdings of sector unit investment trusts. OGE also is proposing conforming amendments to the definition in § 2640.102(q), which would define both sector mutual fund and sector unit investment trust.
As Director of the Office of Government Ethics, I certify under the Regulatory Flexibility Act (5 U.S.C. chapter 6) that this proposed rule would not have a significant economic impact on a substantial number of small entities because it primarily affects Federal executive branch employees.
The Paperwork Reduction Act (44 U.S.C. chapter 35) does not apply because this proposed regulation would not contain information collection requirements that require approval of the Office of Management and Budget.
For purposes of the Unfunded Mandates Reform Act of 1995 (2 U.S.C. chapter 25, subchapter II), this proposed rule would not significantly or uniquely affect small governments and will not result in increased expenditures by State, local, and tribal governments, in the aggregate, or by the private sector, of $100 million or more (as adjusted for inflation) in any one year.
The Office of Government Ethics has determined that this proposed involves rulemaking involves a nonmajor rule under the Congressional Review Act (5 U.S.C. chapter 8) and will, before the future final rule takes effect, submit a report thereon to the U.S. Senate, House of Representatives and General Accounting Office in accordance with that.
In proposing this rule amendment, the Office of Government Ethics has adhered to the regulatory philosophy and the applicable principles of regulation set forth in section 1 of Executive Order 12866, Regulatory Planning and Review. This proposed rule has also been reviewed by the Office of Management and Budget under that Executive order. Moreover, in accordance with section 6(a)(3)(B) of E.O. 12866, the preamble to this proposed amendment notes the legal basis and benefits of, as well as the need for, the regulatory action. There should be no appreciable increase in costs to OGE or the executive branch of the Federal Government in administering this proposed regulation, since it only adds to OGE's financial interests regulation a new regulatory exemption and a clarification of an existing exemption. Finally, this rulemaking is not economically significant under the Executive order and would not interfere with State, local or tribal governments.
As Director of the Office of Government Ethics, I have reviewed this proposed amendatory regulation in light of section 3 of Executive Order 12988, Civil Justice Reform, and certify that it meets the applicable standards provided therein.
Conflict of interests, Government employees.
Accordingly, for the reasons set forth in the preamble, the Office of Government Ethics proposes to amend 5 CFR part 2640 as follows:
1. The authority citation for part 2640 continues to read as follows:
5 U.S.C. App. (Ethics in Government Act of 1978); 18 U.S.C. 208; E.O. 12674, 54 FR 15159, 3 CFR, 1989 Comp., p. 215, as modified by E.O. 12731, 55 FR 42547, 3 CFR, 1990 Comp., p. 306.
2. In § 2640.102, paragraph (q) is revised to read as follows:
(q)
3. In § 2640.201, paragraphs (b)(1) and (2) are revised to read as follows:
(b)
(2)(i) An employee may participate in a particular matter affecting one or more holdings of a sector mutual fund or a sector unit investment trust where the disqualifying financial interest in the matter arises because of ownership of an interest in the fund or the unit investment trust and the aggregate market value of interests in any sector fund or funds and any sector unit investment trust or trusts does not exceed $50,000.
(ii) For purposes of calculating the $50,000 de minimis amount in paragraph (b)(2)(i) of this section, an employee must aggregate the market value of all sector mutual funds and sector unit investment trusts in which he has a disqualifying financial interest and that concentrate in the same sector and have one or more holdings that may be affected by the particular matter.
4. Section 2640.203 is amended by adding paragraph (m) to read as follows:
(m)
Nothing in this paragraph shall be deemed independent authority for an agency to assign an employee to serve in an official capacity with a particular nonprofit organization. Agencies will make such determinations based on an evaluation of their own statutory authorities and missions. Individual agency decisions to permit (or not permit) an employee to serve in an official capacity necessarily involve a range of legal, policy, and managerial considerations, and nothing in this paragraph
Food and Nutrition Service, USDA.
Notice of Proposed Rulemaking.
This Notice of Proposed Rulemaking (NPRM) proposes to amend the Supplemental Nutrition Assistance Program (SNAP) (formerly the Food Stamp Program) regulations to implement Section 4116 of the Food, Conservation, and Energy Act of 2008 (the Farm Bill). Section 4116 of the Farm Bill,
This NPRM proposes criteria for changes that would be considered “major changes” in program operations and identifies the types of data State agencies must collect in order to identify problems relating to integrity and access. It also proposes when and how State agencies must report on implementation of a major change.
This NPRM proposes to amend the Management Evaluation (ME) Review regulations by modifying the requirements for Federal and State reviews of State agency operations. It also proposes to revise the definitions of large, medium and small project areas. Finally, it proposes to remove sections of the regulations pertaining to coupons and coupon storage since they are obsolete.
Comments must be received on or before July 5, 2011.
The Food and Nutrition Service (FNS) invites interested persons to submit comments on this proposed rule. Comments may be submitted by any of the following methods:
All submissions will be available for public inspection at the office of FNS during regular business hours (8:30 a.m. to 5 p.m., Monday through Friday) at 3101 Park Center Drive, Room 810, Alexandria, Virginia 22302-1594.
For further information concerning this NPRM you may contact Moira Johnston, Branch Chief, Program Development Division, Supplemental Nutrition Assistance Program, 3101 Park Center Drive, Room 800, Alexandria, Virginia 22302, (703) 305-2501, or by e-mail at
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.
This proposed rule has been designated a “significant regulatory action,” although not economically significant, under section 3(f) of Executive Order 12866. Accordingly, the rule has been reviewed by the Office of Management and Budget.
This action is needed to implement section 4116 of the Farm Bill (Pub. L. 110-234). Section 4116,
In addition, the Department proposes to modify the requirements for Federal and State reviews of State agency operations, which will result in the more efficient use of staff and resources. This rule proposes several changes to the ME review regulations: (1) Remove the requirements that FNS conduct an annual review of a State agency's operation of SNAP and a biennial review of a State agency's ME system; (2) modify the regulations to reflect the elimination of the use of paper coupons and the nationwide implementation of the Electronic Benefit Transfer System (EBT); (3) redefine the terms, large project area, medium project area, and small project area.
This rule will require State agencies to report on the impacts of implementing major changes in State agency operations and to identify and correct problems caused by implementing these changes. This rule will benefit State agencies by requiring them to identify and correct problems before they cause hardships for applicants or recipients or the integrity of the program is compromised. This rule will benefit applicants, recipients or individuals otherwise eligible for SNAP by requiring State agencies to identify and correct adverse impacts.
This rule will modify the requirements for Federal and State reviews of State agency operations. It will allow FNS the flexibility to put resources where the risks are greatest and to conduct more effective reviews. It will benefit State agencies by allowing them more time to conduct higher quality reviews.
The proposed rule will have a minimal cost in FY 2011 and over the 5 years FY 2011 through FY 2015. To estimate the cost impact, we multiplied the total burden hours by the average hourly wage of the staff likely to fulfill the reporting requirements. We assumed 70 percent of the work would be completed by a GS-11 employee, 20 percent by a GS-12 employee, and 10 percent by a GS-13 employee. We used the Step 5 hourly wages in the Rest of U.S. locality pay area. Seventy percent of the 7,696 burden hours are completed by a GS-11 employee with an hourly wage of $31.17 at a cost of $167,919. Twenty percent are completed by a GS-12 employee with an hourly wage of $37.37 at a cost of $57,520, and ten percent are completed by a GS-13 employee with an hour wage of $44.43 at a cost of $34,193. The annual cost is estimated at $259,632 ($167,919 + $57,520 + $34,193) or approximately $1.3 million over the 5 years FY 2011 through FY 2015.
The Regulatory Flexibility Act (5 U.S.C. 601-612) requires Agencies to analyze the impact of rulemaking on small entities and consider alternatives that would minimize any significant impacts on small entities. Pursuant to that review, it is certified that this proposed rule would not have a significant impact on small entities. State agencies that administer SNAP will be affected to the extent they implement major changes in program operations. State agencies will also be affected to the extent they perform ME reviews of large, medium and small project areas.
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 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 Section 202 of the UMRA, the Department 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, or tribal governments, in the aggregate, or to the private sector, of $100 million or more in any one year. When such a statement is needed for a rule, section 205 of the UMRA generally requires the Department to identify and consider a reasonable number of regulatory alternatives and adopt the least costly, more cost-effective or least burdensome alternative that achieves the objectives of the rule.
This rule contains no Federal mandates (under the regulatory provisions of Title II of the UMRA) that impose costs on State, local, or tribal governments or to the private sector of $100 million or more in any one year. This rule is, therefore, not subject to the requirements of sections 202 and 205 of the UMRA.
SNAP is listed in the Catalog of Federal Domestic Assistance under No. 10.551. For the reasons set forth in the final rule in 7 CFR part 3015, Subpart V and related Notice (48 FR 29115), this Program is excluded from the scope of Executive Order 12372, which requires intergovernmental consultation with State and local officials.
Executive Order 13132 requires Federal agencies to consider the impact of their regulatory actions on State and local governments. Where such actions have federalism implications, agencies are directed to provide a statement for inclusion in the preamble to the regulations describing the agency's considerations in terms of the three categories called for under section (6)(b)(2)(B) of Executive Order 13132. FNS has considered the impact of this rule on State and local governments and has determined that this rule does not have federalism implications. This rule does not impose substantial or direct compliance costs on State and local governments. Therefore, under Section 6(b) of the Executive Order, a federalism summary impact statement is not required.
After the Farm Bill was enacted on June 18, 2008, FNS held a series of conference calls with State agencies and FNS regional offices to explain the SNAP provisions included in the law and to answer questions that State agencies had about implementing the changes to the program. On July 3, 2008, FNS issued an implementation memorandum that described each SNAP-related provision in the Farm Bill and provided basic information to assist State agencies in meeting statutorily mandated implementation timeframes. FNS responded to additional questions that State agencies submitted and posted the answers on the FNS Web site. Another forum for consultation with State officials on implementation of the Farm Bill provisions included various conferences hosted by FNS regional offices, State agency professional organizations, and program advocacy organizations. During these conferences, held in the latter part of 2008 and early months of 2009, FNS officials responded to a range of questions posed by State agency officials related to implementation of Farm Bill provisions.
Recently many State agencies have redesigned how they operate SNAP. Some of these changes have been small and have predominately impacted internal State agency operations. Some of the changes have included major overhauls of the State agency operations and how they interact with the public. As States face rising caseloads and shrinking budgets as well as the availability of new technologies that could help streamline State agency operations, the Department anticipates that more State agencies will implement major changes in their operations of SNAP. The provisions of this rule will require States to closely monitor the impact of the changes and to correct any problems before they have a negative effect on applicants and recipients or on the payment error rates of State agencies.
In addition, the regulations concerning Federal monitoring of State agency operations are very prescriptive concerning the nature and frequency of Federal reviews, whereas the Act is not. As resources have become scarce, it has become clear that by regulating itself in this manner FNS is restricting its ability to adapt the nature of Federal reviews to changes in staffing and resource
In drafting this NPRM, FNS considered the impact of the proposed rule on State and local agencies. In addition, the Department is seeking comments on those areas of discretion and will use those comments to inform its decision making before issuing final regulations. This NPRM is required to implement changes required by the Farm Bill, which were effective on June 18, 2008.
This rule has been reviewed under Executive Order 12988, Civil Justice Reform. This rule, when published final, is intended to have preemptive effect with respect to any State or local laws, regulations or policies which conflict with its provisions or which would otherwise impede its full implementation. This rule is not intended to have retroactive effect unless so specified in the “Effective Date” paragraph of the final rule. Prior to any judicial challenge to the provisions of this rule or the application of its provisions, all applicable administrative procedures must be exhausted. In SNAP, the administrative procedures are as follows: For program benefit recipients—State administrative procedures issued pursuant to 7 U.S.C. 2020(e)(1) of the Act and regulations at § 273.15; for State agencies—administrative procedures issued pursuant to 7 U.S.C. 2023 of the Act and regulations at § 276.7 (for rules related to non-Quality Control liabilities) or Part 283 (for rules related to Quality Control liabilities); for Program retailers and wholesalers—administrative procedures issued pursuant to Section 14 of the Act (7 U.S.C. 2023) and regulations at 7 CFR 279.
FNS has reviewed this rule in accordance with the Department Regulation 4300-4, “Civil Rights Impact Analysis,” to identify and address any major civil rights impacts the rule might have on minorities, women, and persons with disabilities. After a careful review of the rule's intent and provisions, and the characteristics of SNAP households and individual participants, FNS has determined that an important impact of this rule will be to help identify and correct the adverse effects of changes in program operations on certain protected classes. All data available to FNS indicate that protected individuals have the same opportunity to participate in SNAP as non-protected individuals. FNS specifically prohibits the State and local government agencies that administer the Program from engaging in actions that discriminate based on race, color, national origin, gender, age, disability, marital or family status (SNAP's nondiscrimination policy can be found at 7 CFR 272.6 (a)). Where State agencies have options, and they choose to implement a certain provision, they must implement it in such a way that it complies with the regulations at 7 CFR 272.6.
The Paperwork Reduction Act of 1995 (44 U.S.C. Chap. 35;
Comments on the information collection pursuant to this proposed rule must be received by July 5, 2011.
Send comments to Moira Johnston, Branch Chief, Program Design Branch, Food and Nutrition Service, U.S. Department of Agriculture, 3101 Park Center Drive, Alexandria, VA 22302. For further information, or for copies of the information collection package, please contact Moira Johnston at the above address or via e-mail at
All responses to this notice will be summarized and included in the request for OMB approval. All comments will also become a matter of public record. For further information, or for copies of the information collection requirements, please contact Moira Johnston at the address indicated above.
In examining the first of the above criterion, it is reasonable to expect States may continue to replace automated systems at one or two per year, but with so many States running older systems and the delays required by their budget difficulties, we are more likely to see three per year beginning in fiscal year 2011. However, it is likely that we will see several more States look into using call centers and developing on-line applications that will be used by larger proportions of their applicants. Since it appears that as many as 30 States will have on-line applications in place and perhaps 20 States will be using phone centers by fiscal year 2012, the number of additional States that might implement these systems in a year is most likely no more than five. The estimate would then be eight States per year would report major changes under this criterion.
With regard to the second criterion, to date only two States have implemented a process that uses non-merit personnel in the certification process. It is unlikely that many more States will pursue this course of action, and while one State exploring such a change every three years would be the most reasonable estimate, one per year will be used in estimating reporting burden to avoid underestimation.
The third criterion, office closings, may become more common with the expanded use of call centers and on-line applications. A fair estimate would be three per year.
The fourth criterion is staff reductions and this tends to fluctuate with States' budgetary situations, caseloads and other changes they make in their program design. We estimate that there would be three significant staff reductions per year.
The fifth criteria would occur in conjunction with or as a result of changes in the States administration. This is the most difficult to predict, but as States continue to take advantage of new technology and streamlined processes, changes of this type may become more common. An estimate of five such changes per year would appear to be reasonable.
The second step in the major change process is FNS determining what, if any, additional data the State will be required to collect and report. FNS believes that most often, the ongoing data collection tools it employs will be sufficient to provide the needed information on a major change. Additional data will sometimes need to be generated from States' automated eligibility systems. In more limited cases, FNS may require the State to gather data by conducting additional case review surveys.
Section 272.12(3) requires that States provide both descriptive and analytic information regarding the major change. FNS believes that States will have completed the majority of the analysis in the normal course of their own planning and decisionmaking. The descriptive information should also be readily available and require minimal data gathering since it is the State's decision to make the major change. We estimate that it will take 8 hours to describe the change and 32 hours to repackage and complete the required analysis for a total of 40 hours per response. Thus, with 20 States reporting one major change per year, the initial reporting and analysis aspect of the rulemaking would be 20 annual responses × 40 hours per State = an estimated 800 burden hours per year (20 States × 1 response per respondent = 20 annual responses × 40 hours per respondent to respond = 800 annual burden hours).
FNS believes that for 30 percent of the major changes States report, no additional reporting will be necessary. In another 35 percent of the major changes some additional reporting of already available information will be necessary and that additional data collection will be required for the final 35 percent of the reported major changes. Therefore for six of the 20 major changes there would be no reporting burden.
For the seven major changes requiring additional reporting without additional data collection, some automated system reprogramming to generate the data will be necessary. At 24 hours per reprogramming effort, this would be 168 hours per year (7 × 24). The reports themselves would be estimated to require 8 hours and that out of 53 States (including Puerto Rico, the Virgin Islands, and Guam), four States would be required to report monthly and three States quarterly.
The total for these seven States would be 168 + 480 hours = 648 total hours for reporting divided by the seven states = (92.6 hours per State per year).
For the last seven States the 648 hours from the above would be required in addition to the time needed to collect additional data. Such data will generally be collected through a sample of case reviews. While the required sample sizes may vary based on the type of major change and the proportion of the State's SNAP caseload it may affect, 200 cases per quarter would likely be an upper limit on what FNS could ask of a State. At an estimated one hour to review and report on a case, this would require 800 hours per year per State. Seven States times 800 hours yields 5,600 hours. (7 State respondents × 1 response per respondent = 7 annual responses × 800 hours per respondent to respond = 5,600 annual burden hours). When the 648 hours is added for the non-sample information, the total for these seven States is 6,248 (892.6 per State per year). With four States reporting monthly and three of the Sates reporting quarterly, there would be 60 responses. (4 States × 12 = 48 annual responses) + (3 states × 4 response per respondent = 12 annual responses) = 60 annual responses. Twenty eight of the 60 reports would contain information from sample data since it would all be reported quarterly from all seven States).
FNS is committed to complying with the E-Government Act of 2002 (Pub. L. 107-347), in order to promote the use of the Internet and other information technologies to provide increased opportunities for citizen access to government information and services and for other purposes.
Section 4116 of the Farm Bill amended Section 11 of the Act to require the Department to define “major changes” in SNAP (or Program) operations, State agencies to notify the Department when they implement a major change in Program operations, and to collect data for use in identifying and correcting problems with Program integrity and access, particularly among vulnerable populations. Many State agencies have changed or are in the process of changing the way they operate SNAP. Some of these changes have been small and have predominately impacted internal State agency operations. Some of the changes have included major overhauls of the State agency operations and how the State interacts with applicants and participants. While the goal of such changes is to improve the efficiency and the effectiveness of the States' operations, some of these changes have adversely impacted the States' payment accuracy rates as well as access to the Program. With most States facing rising caseloads and restricted budgets, many are likely to make use of new technologies that could help streamline their SNAP operations. Section 4116 of the Farm Bill anticipates this and provides the Department the authority to better provide States with technical assistance and monitor implementation of major changes in their operation of SNAP.
We are proposing to update the Management Evaluation (ME) regulations to allow FNS greater flexibility to target its monitoring resources to those States/situations that constitute the greatest risk. In addition we propose to update the States ME requirements to allow States more time to conduct more effective reviews. With limited resources the proposed changes will allow FNS and States to streamline operations while maintaining the integrity of the Program.
In the discussion of the proposed provisions in this rule, we use the following acronyms or other abbreviations to stand in for certain words or phrases:
The Farm Bill requires the Secretary to develop standards for identifying
• Large or substantially-increased numbers of low-income households that do not live in reasonable proximity to an office performing the major functions described in Section 11(e) of the Act (Section 11(e) enumerates the procedural requirements States must adhere to in the certification of households and operation of the Program);
• Substantial increases in reliance on automated systems for the performance of responsibilities previously performed by personnel described in Section 11(e)(6)(B) of the Act (this subsection requires that State agency personnel utilized in the certification process shall be employed in accordance with the standards for a Merit System of Personnel Administration);
• Changes that potentially increase the difficulty of reporting information under Section 11(e) or Section 6(c) of the Act (7 U.S.C. 2015(c)). Section (6)(c) specifies the options and requirements States must implement that govern a household's responsibility to report changes while Section 11(e) requires that each State identify the reporting requirements it has implemented in its plan of operation); and
• Changes that may disproportionately increase the burdens on any of the types of households described in Section 11(e)(2)(A) of the Act. (Section 11(e)(2)(A) of the Act includes elderly households, households living in rural areas, households containing a disabled member, homeless households, non-English speaking households, and households living on a reservation).
The Department is proposing to include the first three types of changes described above as major changes (with additional specificity). The Department believes that the fourth criteria is a critical factor in considering the impact of any major changes and is consequently proposing that it be considered and analyzed in relation to all major changes. The Department proposes to add a fourth and fifth type of change to the definition. The Department includes these changes based upon past experience that demonstrates that they can have a significant impact on State operations:
• The use of non-merit pay staff to perform functions previously performed by merit personnel described in Section 11(e)(6)(B) of the Act (again, this subsection requires that State agency personnel utilized in the certification process shall be employed in accordance with the standards for a Merit System of Personnel Administration); and
• Independent of any other change in operation, significant reductions in the number of State or local staff involved in the operation of SNAP.
To assist States in evaluating if they are making a major change, the Department proposes the following additional guidance for each of the six criteria that would better define when a major change would need to be reported:
Because functions such as data entry and document imaging do not involve interaction with households, the use of non-merit pay staff in activities of this type would not constitute a major change. If a State obtains a waiver from FNS under Section 17 of the Act to allow non-merit pay Staff to conduct interviews or the eligibility decision functions reserved for merit pay staff in the Act and regulations, this would not be reported as a major change since the waiver approval would specify all necessary reporting and evaluation requirements.
The Department recognizes that Section 11(a)(4)(iv) of the Act also identifies “changes that may disproportionately increase the burdens on any of the types of households described in Section (e)(2)(A) [7 U.S.C. 2020 (e)(2)(A)] of the Act”, as a major change. The Department believes that this is such a critical consideration that any major change a State makes needs to be examined to determine if it would have such an effect. Therefore, rather than including this as a major change in and of itself, the Department is requiring that the analysis of the impact of any major change include a determination of whether the major change has such a disproportionate effect on vulnerable households, as defined in Section 11(e)(2)(a) of the Act.
The Department realizes that the specifics of many changes evolve over time and plans for changes are often modified. Many plans for change are never realized because of funding issues or a shift in State leadership and its priorities. Since any properly planned major change would be approved by State leadership well in advance of implementation, the Department proposes that States report any major change to FNS as soon as it is approved by State leadership, but no less than 120 days prior to implementation. If the plans for the major change are modified after the States initial report to FNS, the State would update its report to FNS. The Department is interested in hearing from States on whether some major changes are approved and implementation begun in less than 120 days.
The Department proposes that the initial report to FNS include a description of the change and an analysis of its anticipated impacts on select measures of program performance. The description would explain the change the State is implementing, the schedule for implementation, if the change is State-wide or, if not, it will identify the jurisdictions it will encompass, and what the change is intended to accomplish. It would also include answers to the following questions as they apply to the type of change being implemented.
• How will the change affect recipients? How will they be informed?
• How will the change affect caseworkers? How will they be trained?
• How will the change be tested? Will it be piloted?
• How will impacts of the change be monitored?
• How will the change affect the State automated system?
• If the change in operations creates significant problems, what is the State's contingency plan?
The Department proposes that the analysis portion of the report include the expected impact of the change on:
• Payment accuracy;
• Program access—impact on applicants in filing initial applications and reapplications;
• Negative error rates;
• Application timeliness, including both the households entitled to 7-day expedited service and 30-day processing standards;
• The types of households described in Section 11(e)(2)(A) of the Act (the determination of whether the major change disproportionally increases the burden on these households would include the difficulty these types of households would have: obtaining SNAP information, filing an initial application, providing verification, being interviewed, reporting changes and reapplying for benefits); and
• Customer service. The Department believes that States should measure the impact on customer service depending upon the nature of the major change, but at a minimum the time it takes for a household to contact the State, be interviewed and report changes would need to be evaluated.
In addition, the analysis must include an evaluation of the impact of the change during implementation (pilot/rollout) versus its expected long term impact. The Department believes that it is important to understand States' plans for implementation because even changes that are meant to be beneficial to SNAP operations can often have unintended consequences during long term implementation that can be difficult for States to correct.
The Department believes that much of the information and analysis it is requesting in this proposal will be readily available to most States since they will have thoroughly planned the change and evaluated its potential impacts prior to implementation. If this assumption is correct, the burden on States in developing reports should be minimal. To the extent that this proposal requires additional analysis of the potential impact of the change, this should generally be helpful to the State in its planning and implementation and, in the longer run, beneficial to its SNAP participants. The Department recognizes that, depending upon the nature of the major change, there may be minimal or no impact on one or more of the above areas.
The Department is not proposing any standard format for the initial report required by this rule. The types of
Section 11(a)(4)(B)(ii) of the Act provides that States implementing major changes, “collect such information as the Secretary shall require to identify and correct any adverse effects on program integrity or access, including access by any of the types of households described in Section (e)(2)(A).” FNS will evaluate the initial report provided by a State to determine if it agrees that the change is in fact, “major” and if so will propose what additional information it will require from the State. While the Department reserves the right provided by the Act to require the information it needs to determine the impact of a major change on integrity and access in SNAP, as States make major changes the Department intends to work with States to determine what information is practicable and require only the data that is necessary and not otherwise available. SNAP standard reports provide a good deal of information, but depending on the nature of the major change and how it is implemented, more specific or timely data may be required. States also obtain performance data as part of Program management and monitoring and when possible the Department will meet its needs by obtaining already existing data.
For any major change the Department needs some level of information on the effect of the change on one or more of the five areas States must include in their evaluation of the impact of the change. Within these areas, the Department will require additional, more specific or more timely data as explained below:
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Following are examples of additional data that could be required depending upon the type of major change being implemented.
If a State were to implement a change that allowed or required households to report changes in their individual circumstances through a change center, the following general data could be required:
• The number of changes received;
• The average time to process a change; and
• The number of changes processed.
If a State were to implement a change that allows applicants to apply on-line the following data could be required:
• Number of applications submitted, approved, denied;
• Number of expedited versus regular 30-day processing cases;
• Number of applications abandoned/terminated before completion;
• Processing time for approved applications including those subject to the expedited time frames; and
• Demographic information on the households using on-line applications.
FNS recognizes that States and their call center software are measuring performance using a variety of different definitions and statistics. If a State were to implement a major change that allows applicants to apply through the use of call centers, FNS would expect to negotiate the exact definitions and reporting requirements, but believes the following data elements would be central to understanding the call center's performance:
• Volume of calls to the center;
• Average hold time from the time the request is made to speak to an agent;
• Percentage of calls with excessive total waiting times to speak with a caseworker (e.g. 15 minutes combined time spent waiting for an initial response and holding after the initial response);
• Percentage of calls abandoned prior to and after the initial response; and
• Customer satisfaction based upon survey results.
If a State were to implement a change that allows applicants to apply on-line and through the use of a call center, the following general data could also be required:
• The number of applications and recertifications submitted by paper including faxing; and mailing; online; and call center; and
• The number of applications and recertifications approved by paper including faxing; and mailing; online; and call center.
Whenever FNS believes that the major change has the potential to have a disproportionate impact on these households, specific reports on these households would be required. The decision that such potential exists could
Depending on the type of major change and its implementation schedule, FNS would work with the State to establish either a monthly or quarterly reporting schedule.
While dependent on the type of major change, FNS would need reports for a minimum of one year after the change had been fully implemented. Based upon FNS' assessment of the reports submitted by the State, it may find it necessary to extend the reporting timeframe beyond the one-year minimum. The rule provides FNS with this discretion.
If it came to FNS' attention that a State appeared to be implementing a major change that had not been formally reported, FNS would contact the State about the change, determine if it were major and proceed as specified above.
FNS will evaluate the State's analysis of the impact of its change, and determine if it is a major change that requires additional reporting and if so, what data is necessary to identify potential adverse effects on SNAP access and integrity. While the nature and extent of the change will impact the time necessary to complete its evaluation, FNS intends to respond within 90 days. During this 90-day period FNS will be in communication with appropriate State officials and, to the extent possible, negotiate with them regarding the most efficient way to obtain the needed information.
As with any problem FNS identifies, FNS would work with the State to correct the cause of the problem and provide whatever technical assistance it can. Some problems can be addressed quickly through a simple adjustment to the State operations. In other instances, the cause and/or the solution is more difficult to determine and a formal corrective action plan would be needed. In either case FNS would intend to work in partnership with the State to resolve the issue(s).
FNS proposes to codify these provisions in a new § 272.12.
The proposed regulation will amend the regulations at §§ 275.3 through 275.7. While the Act does not require Federal monitoring of SNAP in the form of annual or biennial reviews, current regulations are very proscriptive about the type and frequency of reviews. For example, the regulations at 7 CFR 275.3(a) and (b) require FNS to conduct an annual review of certain functions performed at the State agency level and a biennial review of each State agency's management evaluation system. However, since the regulations were published, FNS has experienced reductions in staff and resources. Consequently, over time FNS has adjusted its expectations concerning how often and the methods to be used to conduct reviews of the State agency operations of SNAP. In the course of developing program specific ME review guides and in light of the current reality of reduced resources, FNS has recognized the need to redefine what constitutes a Federal review of a State agency's operation of SNAP and change the frequency of reviews. Revising the regulations to modify how often FNS conducts reviews of State agency operations will allow FNS the flexibility to put resources where the risks are greatest and to conduct more effective reviews.
Current regulations at 7 CFR 275.3(a) provide that FNS shall conduct an annual review of State agency operations of SNAP. This review has been called informally a State Agency Operations Review or SAOR. The Department is proposing to remove the requirement that such a review be conducted on an annual basis. In addition, FNS is proposing to use one term to define any Federal review of State agency operations. The use of the term “State Agency Operations Review” will be discontinued and the term Management Evaluation or ME is proposed to cover all future reviews. Since these terms were so often interchanged we believe this change will improve communication across the Program. The Department proposes to revise the regulations at 7 CFR 275.3(a) to reflect these changes.
The Department proposes to remove the regulations at 7 CFR 275.3(b) which requires FNS to review a State agency's ME system on a biennial basis. Removing this requirement will provide FNS the flexibility to conduct reviews of State agencies' ME systems on an at-risk basis resulting in more efficient allocation of staff and resources. In keeping with current practice, FNS will continue to identify national target areas that Regional Offices are required to review each year, which will generally include reviews of State agency ME systems, and will communicate what these areas are via memorandum. In accordance with § 275.8, FNS will also continue to notify State agencies of the national target areas to be incorporated into their reviews of local agencies.
Current regulations at § 275.7 provide for the selection of sub-units for review. Paragraphs 275.7(a)(2) through 275.7(a)(5) define sub-units as issuance offices, data management units, bulk storage points and reporting points. All of these sub-units deal with the issuing or storage of paper coupons and therefore are outdated and obsolete. The regulations at 7 CFR 275.7(b), (c), and (d) also refer to these out-dated sub-units. The Department proposes to remove these paragraphs in their entirety to reflect the elimination of the use of paper coupons and the nationwide implementation of the Electronic Benefit Transfer System (EBT). The Department also proposes to remove 7 CFR 275.7(a)(1) and to modify 7 CFR 275.7(a) to provide that sub-units are the physical locations of organizational entities within project areas responsible for operating various aspects of the SNAP and include but are not limited to certification offices, call centers, and employment and training offices. The Department proposes to renumber 7 CFR 275.7(e) to 7 CFR 275.7(b) and modify it to remove the term “on-site.” The term “on-site'' is outdated since current technology and the availability of data allows many aspects of a review to be conducted effectively off-site. Current regulations at 7 CFR 275.9(b)(1)(iii) and (b)(1) (iv) provide that the State agency review plan shall identify the issuance offices and reporting points selected for review. The Department is proposing to revise the regulations at 7 CFR 275.9(b)(1)(iii) and (b)(1) (iv) to reflect the elimination of the use of paper coupons and the nationwide implementation of the EBT.
Under current regulations at 7 CFR 275.5(b) State agencies are required to conduct a review of large project areas once a year, a review of medium project areas once every two years and a review of small project areas once every three years. Current rules at § 271.2 define the term large project area as project areas with monthly active caseloads of more than 15,000 households; medium project area as project areas with caseloads of 2001 to 15,000 households and small project area as project areas with caseloads of 2,000 households or less.
The Department proposes to modify § 271.2 to redefine the term large project area as those project areas with monthly active caseloads of more than 25,000 households; medium project area as project areas with caseloads of 5000 to 25,000 households; and small project area as project areas with caseloads of 4,999 households or less. The proposed changes will recognize the growth of SNAP over the last 25 years (about 30 percent) and allow States more time to conduct higher quality reviews.
Food stamps, Grant programs—social program, Reporting and recordkeeping.
Alaska, Civil rights, SNAP, Grant programs—social programs, Penalties, Reporting and recordkeeping requirements, Unemployment compensation, Wages.
Administrative practice and procedure, SNAP, Reporting and recordkeeping requirements.
Accordingly, 7 CFR parts 271, 272 and 275 are proposed to be amended as follows:
1. The authority citation for parts 271, 272 and 275 continues to read as follows:
7 U.S.C. 2011-2036.
2. In § 271.2:
a. Amend the definition of
b. Amend the definition of
c. Amend the definition of
3. A new § 272.12 is added to read as follows:
(a)
(2) Major changes shall include the following:
(i) Closure of one or more local offices that perform major functions for 500 or more SNAP households and there is not another office available to serve the affected households within 25 miles or that can be reached via public transportation. An office performing major functions includes any office where households can file an application for SNAP in person.
(ii) Substantial increased reliance on automated systems for the performance of responsibilities previously performed by State merit personnel (as described in Section 11(e)(6)(B) of the Act). This includes the replacement of the State's primary automated systems used by caseworkers during the certification process to determine eligibility and additions to the States' existing system that automate tasks previously performed by caseworkers in the certification of applicant households. Establishment of an online application process through the Internet or the use of call centers to accept applications would not be a major change unless one of these methods is expected to account for 5 percent or more of the State's SNAP applications. Reporting a major change as required in this section does not relieve States of meeting the requirements for new system approvals in § 277.18.
(iii) Changes in operations that potentially increase the difficulty of households reporting required information. This includes implementation of a call center for change reporting, a major modification to any forms that households use to report changes or the discontinuation of an existing avenue for reporting changes, e.g., households can no longer call the local office to report a change. Modifying selected change reporting policy options, or the implementation of policy waivers would not be major changes.
(iv) Use of non-merit pay staff to perform functions previously performed by merit personnel. While the interview and the eligibility decision functions must be performed by merit personnel (unless FNS approves a waiver request under Section 17 of the Act), other functions including obtaining verification of household circumstances, accepting reports of changes in household circumstances, accepting applications and screening households for expedited service may be performed by non-merit personnel (although FNS must approve a State's use of non-merit pay staff before matching funds will be provided for the performance of these functions). Functions such as data entry and document imaging do not involve interaction with households, and consequently, the use of non-merit pay staff in activities of this type would not constitute a major change. If a State obtains a waiver from FNS to allow non-merit Staff to conduct interviews or the eligibility decision functions reserved for merit staff in the Act and regulations, this would not be reported as a major change since the waiver approval would specify all necessary reporting and evaluation requirements.
(v) Any decrease in staffing levels from one year to the next of more than five percent in the number of State or local staff involved in the certification of SNAP households. This would include decreases resulting from State budget cuts or hiring freezes, but not include loss of staff through resignation, retirement or release when the State is seeking to replace the staff.
(3) When a State initially reports a major change to FNS as required in paragraph (a)(1) of this section an analysis of the expected impact of the major change shall accompany the report. The initial report to FNS that the State is making one of the major changes identified in paragraph (a)(2) of this section shall include a description of the change and an analysis of its anticipated impacts on program performance.
(i) The description of the change shall include the following:
(A) Identification of the major change the State is implementing,
(B) An explanation of what the change is intended to accomplish,
(C) The schedule for implementation,
(D) How the change will be tested and whether it will be piloted,
(E) Whether the change is Statewide or identification of the jurisdictions it will encompass,
(F) How the major change is expected to affect recipients and how recipients will be informed,
(G) How the change will affect caseworkers and as applicable how they will be trained,
(I) How the impact of the major change will be monitored,
(J) How the major change will affect operation of the State automated system, and
(K) The State's backup plans if the major change creates significant problems in one or more of the program measures in paragraph (a)(3)(ii) of this section.
(ii) The analysis portion of the State's initial report shall include the projected impact of the major change on:
(A) The State's payment error rate,
(B) Program access, including the impact on applicants filing initial applications and reapplications,
(C) The State's negative error rate,
(D) Application processing timeliness including both the households entitled to 7-day expedited service and those subject to the 30-day processing standards;
(E) Whether the major change will disproportionately increase the difficulty elderly households, households living in rural areas, households containing a disabled member, homeless households, non-English speaking households, and households living on a reservation will have obtaining SNAP information, filing an initial application, providing verification, being interviewed, reporting changes and reapplying for benefits;
(F) Customer service as defined by the State agency, but shall include the time it takes for a household to contact the State, be interviewed, and report changes.
(G) The State's performance as measured by paragraphs 272.12(a)(3)(ii)(A) through (a)(3)(ii)(F) of this section during implementation of the major change.
(b)
(i)
(ii)
(iii)
(iv)
(v)
(2) Additional data that States could be required to provide depending upon the type of major change being implemented includes, but are not be limited to the following:
(i) If a State were to implement a major change that allows applicants to apply on-line, the following data could be required:
(A) Number of applications submitted, approved, denied,
(B) Number of expedited versus regular 30-day processing cases,
(C) Number of applications abandoned/terminated before completion,
(D) Processing time for approved applications including those subject to the expedited time frames, and
(E) Demographic information on the households using on-line applications.
(ii) If a State were to implement a major change that allowed or required households to report changes in their individual circumstances through a change center, the following data could be required:
(A) The number of changes received,
(B) The average time to process change, and
(C) The number of changes processed.
(iii) If a State were to implement a major change that allows applicants to apply through the use of call center, the following data could be required:
(A) Volume of transactions and calls to the center;
(B) Average hold time from the time the request is made to speak to an agent;
(C) Percentage of calls with excessive total waiting times to speak with a caseworker (e.g. 15 minutes combined time spent waiting for an initial response and holding after the initial response);
(D) Percentages of calls abandoned prior to and after the initial response; and
(E) Customer satisfaction based upon survey results.
(iv) If a State were to implement a major change that allows applicants to apply on-line and through the use of a call center, the following additional data could be required:
(A) The number of applications and recertifications submitted by paper including faxing and mailing; online; and call center, and
(B) The number of applications and recertifications approved by paper including faxing and mailing, online, call center.
(3) Depending on the type of major change, its implementation schedule, and negotiations with FNS, States shall submit reports on their major changes either monthly or quarterly.
(4) States shall submit reports for one year after the major change is fully in place. FNS may extend this timeframe as it deems necessary.
(5) If FNS becomes aware that a State appeared to be implementing a major change that had not been formally reported, FNS would work with the State to determine if it is a major change, and if so proceed as required by this section.
(6) If the data a State submits regarding its major change or other information FNS obtains indicates an adverse impact on SNAP access or integrity, FNS would work with the State to correct the cause of the problem and provide whatever technical assistance it can. Depending upon the severity of the problem, FNS may require a formal corrective action plan as identified in § 275.16 and § 275.17 of this chapter.
4. In § 275.3:
a. Revise paragraph (a).
b. Remove paragraph (b).
c. Redesignate paragraph (c) as paragraph (b).
d. Redesignate paragraph (d) as paragraph (c).
The revision reads as follows:
(a)
5. In § 275.7:
a. Revise paragraph (a).
b. Remove paragraph (b).
c. Remove paragraph (c).
d. Remove paragraph (d).
e. Redesignate paragraph (e) as paragraph (b).
f. Amend newly redesignated paragraph (b) by removing the word “on-site”.
The revision reads as follows:
(a)
6. In § 275.9:
a. Revise paragraph (b)(1)(iii).
b. Amend paragraph (b)(1)(iv) by removing the first sentence.
The revision reads as follows:
(b) * * *
(1) * * *
(iii) Identification of the sub-units selected for review and the techniques used to select them;
Nuclear Regulatory Commission.
Proposed rule; correction.
The U.S. Nuclear Regulatory Commission (NRC) is correcting a proposed rule that appeared in the
Howard Benowitz, Office of the General Counsel, U.S. Nuclear Regulatory Commission, Washington DC 20555;
On page 23216, in the first column, the second sentence of the third paragraph is corrected to read: “The NRC Form 670 and proposed rule are available at the NRC's Web site:
For the Nuclear Regulatory Commission.
Nuclear Regulatory Commission.
Notice of availability of preliminary proposed rule language and public meeting.
The U.S. Nuclear Regulatory Commission (NRC) is proposing to amend its regulations to require low-level radioactive waste disposal facilities to conduct site-specific analyses to demonstrate compliance with the performance objectives. While the existing regulatory requirements are adequate to protect public health and safety, these amendments would enhance the safe disposal of low-level radioactive waste. The NRC is proposing additional changes to the regulations to reduce ambiguity, facilitate implementation, and to better align the requirements with current health and safety standards. In addition, the NRC is making available the rulemaking's associated regulatory basis documents. The NRC will conduct a public meeting on May 18, 2011, to discuss the preliminary proposed rule language and its associated regulatory basis documents. The availability of the preliminary proposed rule language and its associated regulatory basis documents are intended to inform stakeholders of the current status of the NRC's activities and solicit early public comments.
Comments on the preliminary proposed rule language and the regulatory basis documents should be postmarked no later than June 18, 2011. Comments received after this date will be considered if it is practical to do so, but the NRC is able to assure consideration only for comments received on or before this date.
Please include Docket ID NRC-2011-0012 in the subject line of your comments. Comments submitted in writing or in electronic form will be posted on the NRC Web site and on the Federal rulemaking Web site,
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You can access publicly available documents related to this proposed rule using the following methods:
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Andrew Carrera, Office of Federal and State Materials and Environmental Management Programs, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, telephone 301-415-1078, e-mail
The NRC is proposing to amend its regulations to require low-level radioactive waste disposal facilities to conduct site-specific analyses to demonstrate compliance with the performance objectives in Title 10 of the
The NRC is making available a preliminary version of the proposed rule language and its associated regulatory basis documents to inform stakeholders of the current status of this proposed rulemaking. The NRC is inviting stakeholders to comment on the preliminary proposed rule language and its associated regulatory basis documents. The preliminary proposed rule language may be subject to additional significant revisions during the rulemaking process prior to publication for formal comment as a proposed rule.
The NRC will review and consider any comments received on the preliminary proposed rule language and regulatory basis documents; however, the NRC will not formally respond to comments. As appropriate, the Statements of Consideration for the proposed rule may briefly discuss any substantive changes made to the proposed rule language as a result of comments received on this preliminary version. Stakeholders will also have an additional opportunity to comment on the rule language when it is published as a proposed rule in accordance with the provisions of the Administrative Procedures Act. The NRC will respond to any such comments in the Statements of Consideration for the final rule.
The NRC may post updates to the preliminary rule language on the Federal rulemaking Web site under Docket ID NRC-2011-0012. The
The NRC plans to conduct a public meeting on May 18, 2011, to discuss the preliminary proposed rule language and the regulatory basis documents. The public meeting will be held from 8:30 a.m. to 4:30 p.m. at The Legacy Hotel and Meeting Centre, 1775 Rockville Pike, Rockville, Maryland 20852. The meeting will provide an opportunity for stakeholders to ask clarifying questions to help formulate written comments. The meeting agenda can be viewed and downloaded electronically from the NRC's Public Meeting Web site.
Attendees are requested to notify Mr. Andrew Carrera at (301) 415-1078 or e-mail
For the Nuclear Regulatory Commission.
Federal Aviation Administration (FAA), DOT.
Notice of proposed rulemaking (NPRM).
We propose to adopt a new airworthiness directive (AD) for the products listed above. This proposed AD results from mandatory continuing airworthiness information (MCAI) originated by an aviation authority of
Surface defects were visually detected on the rudder of * * * [an] in-service aeroplane during scheduled maintenance.
Investigation has determined that the defects reported on both rudders corresponded to areas that had been reworked in production. The investigation confirmed that the surface defects were a result of de-bonding between the skin and honeycomb core.
An extended de-bonding, if not detected and corrected, may degrade the structural integrity of the rudder. The loss of the rudder leads to degradation of the handling qualities and reduces the controllability of the aeroplane.
The proposed AD would require actions that are intended to address the unsafe condition described in the MCAI.
We must receive comments on this proposed AD by June 17, 2011.
You may send comments by any of the following methods:
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For service information identified in this proposed AD, contact Airbus SAS—Airworthiness Office—EAL, 1 Rond Point Maurice Bellonte, 31707 Blagnac Cedex, France; telephone +33 5 61 93 36 96; fax +33 5 61 93 45 80; e-mail
You may examine the AD docket on the Internet at
Vladimir Ulyanov, Aerospace Engineer, International Branch, ANM-116, Transport Airplane Directorate, FAA, 1601 Lind Avenue, SW., Renton, Washington 98057-3356; telephone (425) 227-1138; fax (425) 227-1149.
We invite you to send any written relevant data, views, or arguments about this proposed AD. Send your comments to an address listed under the
We will post all comments we receive, without change, to
The European Aviation Safety Agency (EASA), which is the Technical Agent for the Member States of the European Community, has issued EASA Airworthiness Directive 2010-0127, dated June 23, 2010 (referred to after this as “the MCAI”), to correct an unsafe condition for the specified products. The MCAI states:
Surface defects were visually detected on the rudder of one A319 and one A321 in-service aeroplane during scheduled maintenance.
Investigation has determined that the defects reported on both rudders corresponded to areas that had been reworked in production. The investigation confirmed that the surface defects were a result of de-bonding between the skin and honeycomb core.
Such reworks were also performed on some rudders fitted on A330 and A340-200/-300 aeroplanes.
An extended de-bonding, if not detected and corrected, may degrade the structural integrity of the rudder. The loss of the rudder leads to degradation of the handling qualities and reduces the controllability of the aeroplane.
To address this unsafe condition, EASA issued AD 2010-0021, superseding EASA AD 2009-0156, to require inspections of specific areas and, depending on findings, the accomplishment of corrective actions for those rudders where production reworks have been identified.
In addition, this AD addresses the rudder population that has also been reworked in production but is not part of EASA AD 2010-0021 applicability.
Airbus has issued Mandatory Service Bulletins A330-55-3042 and A340-55-4038, both dated April 22, 2010. The actions described in this service information are intended to correct the unsafe condition identified in the MCAI.
This product has been approved by the aviation authority of another country, and is approved for operation in the United States. Pursuant to our bilateral agreement with the State of Design Authority, we have been notified of the unsafe condition described in the MCAI and service information referenced above. We are proposing this AD because we evaluated all pertinent information and determined an unsafe condition exists and is likely to exist or develop on other products of the same type design.
We have reviewed the MCAI and related service information and, in general, agree with their substance. But we might have found it necessary to use different words from those in the MCAI to ensure the AD is clear for U.S. operators and is enforceable. In making these changes, we do not intend to differ substantively from the information provided in the MCAI and related service information.
We might also have proposed different actions in this AD from those in the MCAI in order to follow FAA policies. Any such differences are highlighted in a Note within the proposed AD.
Based on the service information, we estimate that this proposed AD would affect about 55 products of U.S. registry. We also estimate that it would take
We have received no definitive data that would enable us to provide a cost estimate for the on-condition actions specified in this AD.
Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. “Subtitle VII: Aviation Programs,” describes in more detail the scope of the Agency's authority.
We are issuing this rulemaking under the authority described in “Subtitle VII, Part A, Subpart III, Section 44701: General requirements.” Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.
We determined that this proposed AD would not have federalism implications under Executive Order 13132. This proposed AD would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government.
1. Is not a “significant regulatory action” under Executive Order 12866;
2. Is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979); and
3. Will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
We prepared a regulatory evaluation of the estimated costs to comply with this proposed AD and placed it in the AD docket.
Air transportation, Aircraft, Aviation safety, Incorporation by reference, Safety.
Accordingly, under the authority delegated to me by the Administrator, the FAA proposes to amend 14 CFR part 39 as follows:
1. The authority citation for part 39 continues to read as follows:
49 U.S.C. 106(g), 40113, 44701.
2. The FAA amends § 39.13 by adding the following new AD:
(a) We must receive comments by June 17, 2011.
(b) None.
(c) This AD applies to Airbus Model A330-201, -202, -203, -223, -243, -301, -302, -303, -321, -322, -323, -341, -342, and -343 airplanes and Model A340-211, -212, -213, -311, -312, and -313 airplanes; certificated in any category, all manufacturer serial numbers, if equipped with rudders having part numbers and serial numbers as identified in table 1, table 2, or table 3 of this AD.
(d) Air Transport Association (ATA) of America Code 55: Stabilizers.
(e) The mandatory continuing airworthiness information (MCAI) states:
Surface defects were visually detected on the rudder of * * * [an] in-service aeroplane during scheduled maintenance.
Investigation has determined that the defects reported on both rudders corresponded to areas that had been reworked in production. The investigation confirmed that the surface defects were a result of de-bonding between the skin and honeycomb core.
An extended de-bonding, if not detected and corrected, may degrade the structural integrity of the rudder. The loss of the rudder leads to degradation of the handling qualities and reduces the controllability of the aeroplane.
(f) You are responsible for having the actions required by this AD performed within the compliance times specified, unless the actions have already been done.
(g) For rudders identified in table 1 and table 2 of this AD, within the compliance time in paragraph (g)(1) or (g)(2) of this AD as applicable, do a vacuum loss inspection on the rudder non-ventilated area (Area 1) for damage including de-bonding between the skin and honeycomb core of the rudder, in accordance with the Accomplishment Instructions of Airbus Mandatory Service Bulletin A330-55-3042 or A340-55-4038, both dated April 22, 2010, as applicable.
(1) For rudders identified in table 1 of this AD: Within 1,800 flight hours after the effective date of this AD.
(2) For rudders identified in table 2 of this AD: Within 21 months after the effective date of this AD.
(h) For rudders identified in table 1 and table 2 of this AD, within 21 months after the effective date of this AD, do an elasticity laminate checker inspection on the trailing edge area (Area 2) for damage including de-bonding between the skin and honeycomb core of the rudder, in accordance with the Accomplishment Instructions of Airbus Mandatory Service Bulletin A330-55-3042 or A340-55-4038, both dated April 22, 2010, as applicable. Thereafter, repeat the inspection two more times at intervals not to exceed 4,500 flight cycles but not less than 4,000 flight cycles from the most recent inspection.
(i) For rudders identified in table 3 of this AD, within 4,500 flight cycles but not less than 4,000 flight cycles from the date of the sampling inspection identified in table 4 of this AD, or within 30 days after the effective date of this AD, whichever occurs later, do an elasticity laminate checker inspection on the trailing edge area for damage including de-bonding between the skin and honeycomb core of the rudder, in accordance with the Accomplishment Instructions of Airbus Mandatory Service Bulletin A330-55-3042 or A340-55-4038, both dated April 22, 2010, as applicable. Repeat the inspection once within 4,500 flight cycles after doing the inspection but not less than 4,000 flight cycles from the last inspection.
(j) If damage is found during any inspection required by paragraph (g), (h), (i), or (k)(1) of this AD, before further flight, repair the damage using a method approved by either the Manager, International Branch, ANM 116, Transport Airplane Directorate, FAA; or the European Aviation Safety Agency (EASA) (or its delegated agent).
(k) If no damage is found during any inspection required by paragraph (g) of this AD, before further flight, restore the vacuum loss holes by doing a temporary restoration with self-adhesive disks or tapes, a temporary restoration with resin, or a permanent restoration with resin, in accordance with the Accomplishment Instructions of Airbus Mandatory Service Bulletin A330-55-3042 or A340-55-4038, both dated April 22, 2010, as applicable. Do the applicable actions specified in paragraph (k)(1) or (k)(2) of this AD.
(1) For airplanes on which a temporary restoration with self-adhesive disks or tapes is done, within 900 flight hours after doing the restoration, do a detailed inspection for loose or missing self-adhesive disks or tapes and repeat the inspection thereafter at intervals not to exceed 900 flight hours until the permanent restoration is done, in accordance with the Accomplishment Instructions of Airbus Mandatory Service Bulletin A330-55-3042 or A340-55-4038, both dated April 22, 2010, as applicable. If any loose or missing self-adhesive disks or tapes are found during any inspection required by this AD, before further flight, close the holes, in accordance with the Accomplishment Instructions of Airbus Mandatory Service Bulletin A330-55-3042 or A340-55-4038, both dated April 22, 2010, as applicable. Do the permanent restoration within 21 months after doing the temporary restoration, in accordance with the Accomplishment Instructions of Airbus
(2) For airplanes on which a temporary restoration with resin is done: Within 21 months after doing the temporary restoration, do the permanent restoration, in accordance with the Accomplishment Instructions of Airbus Mandatory Service Bulletin A330-55-3042 or A340-55-4038, both dated April 22, 2010, as applicable.
(l) Submit a report of the findings (positive and negative) of the first inspection required by paragraphs (g), (h), and (i) of this AD to Airbus, at the applicable time specified in paragraph (l)(1) or (l)(2) of this AD. The report must include the inspection results, a description of any discrepancies found, the airplane serial number, and the number of landings and flight hours on the airplane.
(1) If the inspection was done on or after the effective date of this AD: Submit the report within 30 days after the inspection.
(2) If the inspection was done before the effective date of this AD: Submit the report within 30 days after the effective date of this AD.
(m) As of the effective date of this AD, no person may install any affected rudder listed in table 1, table, 2, or table 3 of this AD, on any airplane, unless the rudder is inspected as specified in paragraphs (g), (h), and (i) of this AD, as applicable, and all applicable corrective actions specified in paragraph (j) of this AD and applicable restoration specified in paragraph (k) of this AD are done.
This AD differs from the MCAI and/or service information as follows: No differences.
(n) The following provisions also apply to this AD:
(1)
(2)
(3)
(o) Refer to MCAI EASA Airworthiness Directive 2010-0127, dated June 23, 2010; Airbus Mandatory Service Bulletin A330-55-3042, dated April 22, 2010; and Airbus Mandatory Service Bulletin A340-55-4038, dated April 22, 2010; for related information.
Federal Aviation Administration (FAA), DOT.
Notice of public meeting.
This notice announces a public meeting to solicit comments and information from the public on the regulatory approach to commercial orbital human spaceflight by the FAA. This public meeting is intended to aid the FAA in its regulatory effort by receiving early input from the affected community.
The meeting is scheduled for Thursday, May 26, 2011, starting at 8:30 a.m. Eastern Daylight Time. Written comments submitted to the docket must be received no later than June 9, 2011.
DoubleTree by Hilton Hotel Cocoa Beach Oceanfront, 2080 North Atlantic Avenue, Cocoa Beach, FL 32931.
Persons who are unable to attend the meeting, or who otherwise wish to submit written comments, may send comments identified by Docket Number FAA-2011-0446 using any of the following methods:
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Randy Repcheck, Deputy Division Manager, Regulations and Analysis Division, AST-300, Office of Commercial Space Transportation, Federal Aviation Administration, 800 Independence Avenue, SW., Washington, DC 20591, Telephone (202) 267-8760, or e-mail at
51 U.S.C. Subtitle V, chapter 509 (Chapter 509) authorizes the Secretary of Transportation and, through delegations, the FAA's Associate Administrator for Commercial Space Transportation, to oversee, license, and regulate both launches and reentries, and the operation of launch and reentry sites when carried out by U.S. citizens or within the United States. 51 U.S.C. 50904, 50905. Chapter 509 directs the FAA to exercise this responsibility consistent with public health and safety, safety of property, and the national security and foreign policy interests of the United States, and to encourage, facilitate, and promote commercial
The Commercial Space Launch Amendments Act of 2004 (CSLAA) assigned the FAA responsibility for regulating commercial human space flight. In December 2006, the FAA issued human space flight regulations in accordance with its authority to protect public health and safety. The CSLAA prohibits the FAA from proposing regulations governing the design or operation of a launch vehicle to protect the health and safety of crew and space flight participants until December 23, 2012, or until a design feature or operating practice has resulted in a serious or fatal injury, or contributed to an event that posed a high risk of causing a death or serious injury, to crew or space flight participants during a licensed or permitted commercial human space flight. 51 U.S.C. 50905(c)(2) and (3). Until such time, the CSLAA only requires that a space flight participant be informed of the risks of taking a ride on a rocket. 51 U.S.C. 50905(b)(5). The FAA may also issue regulations setting reasonable requirements for space flight participants, including medical and training requirements. 51 U.S.C. 50905(b)(6).
Because of recent changes in U.S. policy and the effect they have had on the commercial space transportation industry, the FAA is planning to propose regulations to protect the health and safety of crew and space flight participants for orbital human spaceflight as soon as circumstances require after December 23, 2012. This initiative is driven by the fact that the National Aeronautics and Space Administration (NASA) is planning to contract with the private sector to transport NASA astronauts to the International Space Station within a few years, and is in the process of developing requirements for its procurement of such services. The FAA's role in these flights is still in work, but the transport of private individuals to Earth orbit, which would require an FAA license, is expected to use the same space transportation systems.
The FAA believes it is important to establish a regulatory foundation as early as possible to provide industry assurance that systems built to support NASA's missions will be compatible with future FAA regulations. The CSLAA mandates that any regulations governing the design or operation of a launch vehicle to protect the health and safety of crew and space flight participants must take into consideration the evolving standards of safety in the commercial space flight industry. 51 U.S.C. 50905(c)(3). We fully concur. When developed, the proposed regulations are planned to be a starting point for a regulatory regime that will evolve over time as the industry matures. Moreover, in order to facilitate the development of a successful commercial human space transportation industry, the FAA and NASA must develop complementary safety regimes for orbital human space flight. As noted above, NASA has already begun to develop requirements for its procurement of orbital transport services.
The public meeting will allow a large cross-section of the interested public to share views with each other and the FAA, and assist the FAA in redefining the regulatory framework for orbital human spaceflight. The FAA will share its current philosophy, but is most interested in the public's view on a number of regulatory issues such as—
• What the appropriate regulatory scope and breadth should be,
• What the appropriate mix of performance-based, process-based, and prescriptive requirements should be,
• What the appropriate level of safety the FAA should target with its regulations,
• What, if any, should be the medical requirements for space flight participants,
• How best to incorporate government and industry standards into the licensing process,
• How much flight testing should be required, and
• How much control over a spacecraft ground personnel and flight crew should have.
Any member of the public may present oral statements at the meeting. For planning purposes please inform a person listed in the
Written comments are also welcome during or after the meeting, but must be submitted to the docket by June 9, 2011.
Coast Guard, DHS.
Notice of proposed rulemaking.
The Coast Guard proposes to establish a permanent regulated navigation area (RNA) on Biscayne Bay in Miami, Florida. The RNA would be enforced annually on the Saturday and Sunday of the second week in October (Columbus Day weekend). It would include all waters within one nautical mile of the center of the Intracoastal Waterway between Featherbed Bank and the Rickenbacker Causeway Bridge. All vessels within the RNA would be: Required to transit the regulated navigation area at no more than 15 knots; subject to control by the Coast Guard; and required to follow the instructions of all law enforcement vessels in the area. This RNA is necessary to ensure the safe transit of vessels and to protect the marine environment.
Comments and related material must be received by the Coast Guard on or before July 14, 2011. Requests for public meetings must be received by the Coast Guard on or before June 14, 2011.
You may submit comments identified by docket number USCG-2011-0044 using any one of the following methods:
(1)
(2)
(3)
(4)
To avoid duplication, please use only one of these four methods.
If you have questions on this proposed rule, call or e-mail Lieutenant Paul A. Steiner, Sector Miami Prevention Department, Coast Guard; telephone 305-535-8724, e-mail
We encourage you to participate in this rulemaking by submitting comments and related materials. All comments received will be posted without change to
If you submit a comment, please include the docket number for this rulemaking (USCG-2011-0044), indicate the specific section of this document to which each comment applies, and provide a reason for each suggestion or recommendation. You may submit your comments and material online (via
To submit your comment online, go to
To view comments, as well as documents mentioned in this preamble as being available in the docket, go to
Anyone can search the electronic form of comments received into any of our dockets by the name of the individual submitting the comment (or signing the comment, if submitted on behalf of an association, business, labor union, etc.). You may review a Privacy Act notice regarding our public dockets in the January 17, 2008, issue of the
We do not now plan to hold a public meeting. But you may submit a request for a public meeting on or before June 14, 2011 using one of the four methods specified under
The legal basis for the proposed rule is the Coast Guard's authority to establish regulated navigation areas (RNAs) and limited access areas: 33 U.S.C. 1226, 1231; 46 U.S.C. Chapter 701, 3306, 3703; 50 U.S.C. 191, 195; 33 CFR 1.05-1, 6.04-1, 6.04-6, and 160.5; Pub. L. 107-295, 116 Stat. 2064; Department of Homeland Security Delegation No. 0170.1.
The purpose of the proposed rule is to ensure the safe transit of vessels in the area and to protect all persons, vessels, and the marine environment.
The proposed rule would designate an RNA encompassing all waters within one nautical mile of the center of the Intracoastal Waterway from Featherbed Bank extending 14 nautical miles north to the Rickenbacker Causeway Bridge. The RNA would be enforced daily from 12:01 p.m. until 11:59 p.m. on the Saturday and Sunday of the second week in October (Columbus Day weekend) each year. All vessels within the regulated navigation area would be: (1) Required to transit the area at no more than 15 knots; (2) subject to control by the Coast Guard; and (3) required to follow the instructions of all law enforcement vessels in the area.
The RNA is necessary to ensure the safety of the public. The close proximity of numerous vessels transiting that portion of the Intracoastal Waterway encompassed within the proposed RNA during Columbus Day weekend poses a hazardous condition. The RNA would result in the transiting of vessels at a safer speed, thereby significantly reducing the threat of vessel collisions. Requiring vessels within the RNA to transit at no more than 15 knots would also enable law enforcement officials to identify, respond to, query, and stop operators who may pose a hazard to other vessels in the area. Nothing in this regulation would alleviate vessels or operators from complying with all other Federal, state, and local laws in the area, including manatee slow speed zones.
We developed this proposed rule after considering numerous statutes and executive orders related to rulemaking. Below we summarize our analyses based on 13 of these statutes or executive orders.
This rule is not a significant regulatory action under section 3(f) of Executive Order 12866, Regulatory Planning and Review, as supplemented by Executive Order 13563, and does not require an assessment of potential costs and benefits under section 6(a)(3) of that Order. The Office of Management and Budget has not reviewed it under that Order.
The economic impact of this rule is not significant for the following reasons: (1) The proposed RNA would be in effect for only two days each year; (2) although during the enforcement period vessels would be required to transit the area at no more than 15 knots, be subject to control by the Coast Guard, and be required to follow the instructions of all law enforcement vessels in the area, the RNA does not prohibit vessels from transiting the area; (3) vessels could still operate in surrounding waters that are not encompassed within the RNA without the restrictions imposed by the RNA; and (4) advance notification of the RNA's enforcement would be made to the local maritime community via Local Notice to Mariners and Broadcast Notice to Mariners.
Under the Regulatory Flexibility Act (5 U.S.C. 601-612), we have considered whether this proposed rule would have a significant economic impact on a substantial number of small entities. The term “small entities” comprises small businesses, not-for-profit organizations that are independently owned and operated and are not dominant in their fields, and governmental jurisdictions with populations of less than 50,000.
The Coast Guard certifies under 5 U.S.C. 605(b) that this proposed rule would not have a significant economic impact on a substantial number of small entities. This rule may affect the following entities, some of which may be small entities: the owners or operators of vessels intending to transit the RNA on the Saturday and Sunday of the second week in October (Columbus Day weekend). For the reasons discussed in the Regulatory Planning and Review section above, this proposed rule would not have a significant economic impact on a substantial number of small entities.
If you think that your business, organization, or governmental jurisdiction qualifies as a small entity and that this rule would have a significant economic impact on it, please submit a comment (
Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Pub. L. 104-121), we want to assist small entities in understanding this proposed rule so that they can better evaluate its effects on them and participate in the rulemaking. If the rule would affect your small business, organization, or governmental jurisdiction and you have questions concerning its provisions or options for compliance, please contact Lieutenant Paul A. Steiner, Sector Miami Prevention Department, Coast Guard; telephone 305-535-8724, e-mail
This proposed rule would call for no new collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520).
A rule has implications for federalism under Executive Order 13132, Federalism, if it has a substantial direct effect on State or local governments and would either preempt State law or impose a substantial direct cost of compliance on them. We have analyzed this proposed rule under that Order and have determined that it does not have implications for federalism.
The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538) requires Federal agencies to assess the effects of their discretionary regulatory actions. In particular, the Act addresses actions that may result in the expenditure by a State, local, or tribal government, in the aggregate, or by the private sector of $100,000,000 or more in any one year. Though this proposed rule would not result in such an expenditure, we do discuss the effects of this rule elsewhere in this preamble.
This proposed rule would not cause a taking of private property or otherwise have taking implications under Executive Order 12630, Governmental Actions and Interference with Constitutionally Protected Property Rights.
This proposed rule meets applicable standards in sections 3(a) and 3(b)(2) of Executive Order 12988, Civil Justice Reform, to minimize litigation, eliminate ambiguity, and reduce burden.
We have analyzed this proposed rule under Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks. This rule is not an economically significant rule and would not create an environmental risk to health or risk to safety that might disproportionately affect children.
This proposed rule does not have tribal implications under Executive Order 13175, Consultation and Coordination with Indian Tribal Governments, because it would not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes.
We have analyzed this proposed rule under Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use. We have determined that it is not a “significant energy action” under that order because it is not a “significant regulatory action” under Executive Order 12866 and is not likely to have a significant adverse effect on the supply, distribution, or use of energy. The Administrator of the Office of Information and Regulatory Affairs has not designated it as a significant energy action. Therefore, it does not require a Statement of Energy Effects under Executive Order 13211.
The National Technology Transfer and Advancement Act (NTTAA) (15 U.S.C. 272 note) directs agencies to use voluntary consensus standards in their regulatory activities unless the agency provides Congress, through the Office of Management and Budget, with an explanation of why using these standards would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., specifications of materials, performance, design, or operation; test methods; sampling procedures; and related management systems practices) that are developed or
This proposed rule does not use technical standards. Therefore, we did not consider the use of voluntary consensus standards.
We have analyzed this proposed rule under Department of Homeland Security Management Directive 023-01 and Commandant Instruction M16475.lD, which guide the Coast Guard in complying with the National Environmental Policy Act of 1969 (NEPA) (42 U.S.C. 4321-4370f), and have made a preliminary determination that this action is one of a category of actions that do not individually or cumulatively have a significant effect on the human environment. A preliminary environmental analysis checklist supporting this determination is available in the docket where indicated under
Harbors, Marine safety, Navigation (water), Reporting and recordkeeping requirements, Security measures, Waterways.
For the reasons discussed in the preamble, the Coast Guard proposes to amend 33 CFR part 165 as follows:
1. The authority citation for part 165 continues to read as follows:
33 U.S.C. 1226, 1231; 46 U.S.C. Chapter 701, 3306, 3703; 50 U.S.C. 191, 195; 33 CFR 1.05-1, 6.04-1, 6.04-6, 160.5; Pub. L. 107-295, 116 Stat. 2064; Department of Homeland Security Delegation No. 0170.1.
2. Add 33 CFR 165.779 to read as follows:
(a)
(b)
(c)
(2) At least 48 hours prior to each enforcement period, the Coast Guard will provide notice of the regulated area through advanced notice via Local Notice to Mariners and Broadcast Notice to Mariners.
(d)
Coast Guard, DHS.
Notice of proposed rulemaking.
The Coast Guard proposes to establish a temporary safety zone on Biscayne Bay, east of Bayfront Park, in Miami, Florida during the 2011 Rohto Ironman 70.3 Miami, a triathlon. The Rohto Ironman 70.3 Miami is scheduled to take place on Sunday, October 30, 2011. The temporary safety zone is necessary for the safety of race participants, participant vessels, and the general public during the 1.2 mile swim portion of this competition. Persons and vessels will be prohibited from entering, transiting through, anchoring in, or remaining within the safety zone unless authorized by the Captain of the Port Miami or a designated representative.
Comments and related material must be received by the Coast Guard on or before July 19, 2011.
You may submit comments identified by docket number USCG-2011-0195 using any one of the following methods:
(1)
(2)
(3)
(4)
To avoid duplication, please use only one of these four methods.
If you have questions on this proposed rule, call or e-mail Lieutenant Paul A. Steiner, Sector Miami Prevention Department, Coast Guard; telephone 305-535-8724, e-mail
We encourage you to participate in this rulemaking by submitting comments and related materials. All comments received will be posted without change to
If you submit a comment, please include the docket number for this rulemaking (USCG-2011-0195), indicate the specific section of this document to which each comment applies, and provide a reason for each suggestion or recommendation. You may submit your comments and material online (via
To submit your comment online, go to
To view comments, as well as documents mentioned in this preamble as being available in the docket, go to
Anyone can search the electronic form of comments received into any of our dockets by the name of the individual submitting the comment (or signing the comment, if submitted on behalf of an association, business, labor union, etc.). You may review a Privacy Act notice regarding our public dockets in the January 17, 2008, issue of the
We do not now plan to hold a public meeting. But you may submit a request for a public meeting on or before June 10, 2011 using one of the four methods specified under
On October 30, 2011, Paramount Productions, LLC will be hosting the Rohto Ironman 70.3 Miami. This event includes a 1.2 mile swim, which will take place on the waters of Biscayne Bay located east of Bayfront Park in Miami, Florida. Approximately 2,500 individuals are scheduled to compete in the event. This safety zone is necessary to protect race participants, participant vessels, and the general public during the effective period.
The proposed rule would designate a temporary safety zone around the swim area of the Rohto Ironman 70.3 Miami on Biscayne Bay, east of Bayfront Park, in Miami, Florida. The temporary safety zone will be in effect from 6:45 a.m. until 10 a.m. on October 30, 2011. Persons and vessels will be prohibited from entering, transiting through, anchoring in, or remaining within the safety zone unless specifically authorized by the Captain of the Port Miami or a designated representative. Persons and vessels may request authorization to enter, transit through, anchor in, or remain within the safety zone by contacting the Captain of the Port Miami via telephone at 305-535-4472, or a designated representative via VHF radio on channel 16.
We developed this proposed rule after considering numerous statutes and executive orders related to rulemaking. Below we summarize our analyses based on 13 of these statutes or executive orders.
This proposed rule is not a significant regulatory action under section 3(f) of Executive Order 12866, Regulatory Planning and Review, and does not require an assessment of potential costs and benefits under section 6(a)(3) of that Order. The Office of Management and Budget has not reviewed it under that Order.
The economic impact of this proposed rule is not significant for the following reasons: (1) The safety zone will be in effect for just over three hours; (2) vessel traffic in the area during the effective period will be minimal; (3) although persons and vessels will not be able to enter, transit through, anchor in, or remain within the safety zone without authorization from the Captain of the Port Miami or a designated representative, they will be able to operate in the surrounding area during the effective period; (4) persons and vessels may still enter, transit through, anchor in, or remain within the safety zone if authorized by the Captain of the Port Miami or a designated representative; and (5) advance notification will be made to the local maritime community via Local Notice to Mariners and Broadcast Notice to Mariners.
Under the Regulatory Flexibility Act (5 U.S.C. 601-612), we have considered whether this proposed rule would have a significant economic impact on a substantial number of small entities. The term “small entities” comprises small businesses, not-for-profit organizations that are independently owned and operated and are not dominant in their fields, and governmental jurisdictions with populations of less than 50,000.
The Coast Guard certifies under 5 U.S.C. 605(b) that this proposed rule would not have a significant economic impact on a substantial number of small entities. This rule may affect the following entities, some of which may be small entities: the owners or operators of vessels intending to enter, transit through, anchor in, or remain within the waters of Biscayne Bay that are encompassed within the safety zone from 6:45 a.m. until 10 a.m. on October 30, 2011. For the reasons discussed in the Regulatory Planning and Review section above, this proposed rule will not have a significant economic impact on a substantial number of small entities.
If you think that your business, organization, or governmental jurisdiction qualifies as a small entity and that this rule would have a significant economic impact on it, please submit a comment (
Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Pub. L. 104-121), we want to assist small entities in understanding this proposed rule so that
This proposed rule would call for no new collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520).
A rule has implications for federalism under Executive Order 13132, Federalism, if it has a substantial direct effect on State or local governments and would either preempt State law or impose a substantial direct cost of compliance on them. We have analyzed this proposed rule under that Order and have determined that it does not have implications for federalism.
The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538) requires Federal agencies to assess the effects of their discretionary regulatory actions. In particular, the Act addresses actions that may result in the expenditure by a State, local, or tribal government, in the aggregate, or by the private sector of $100,000,000 or more in any one year. Though this proposed rule would not result in such an expenditure, we do discuss the effects of this rule elsewhere in this preamble.
This proposed rule would not cause a taking of private property or otherwise have taking implications under Executive Order 12630, Governmental Actions and Interference with Constitutionally Protected Property Rights.
This proposed rule meets applicable standards in sections 3(a) and 3(b)(2) of Executive Order 12988, Civil Justice Reform, to minimize litigation, eliminate ambiguity, and reduce burden.
We have analyzed this proposed rule under Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks. This rule is not an economically significant rule and would not create an environmental risk to health or risk to safety that might disproportionately affect children.
This proposed rule does not have tribal implications under Executive Order 13175, Consultation and Coordination with Indian Tribal Governments, because it would not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes.
We have analyzed this proposed rule under Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use. We have determined that it is not a “significant energy action” under that order because it is not a “significant regulatory action” under Executive Order 12866 and is not likely to have a significant adverse effect on the supply, distribution, or use of energy. The Administrator of the Office of Information and Regulatory Affairs has not designated it as a significant energy action. Therefore, it does not require a Statement of Energy Effects under Executive Order 13211.
The National Technology Transfer and Advancement Act (NTTAA) (15 U.S.C. 272 note) directs agencies to use voluntary consensus standards in their regulatory activities unless the agency provides Congress, through the Office of Management and Budget, with an explanation of why using these standards would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (
This proposed rule does not use technical standards. Therefore, we did not consider the use of voluntary consensus standards.
We have analyzed this proposed rule under Department of Homeland Security Management Directive 023-01 and Commandant Instruction M16475.lD, which guide the Coast Guard in complying with the National Environmental Policy Act of 1969 (NEPA) (42 U.S.C. 4321-4370f), and have made a preliminary determination that this action is one of a category of actions that do not individually or cumulatively have a significant effect on the human environment. A preliminary environmental analysis checklist supporting this determination is available in the docket where indicated under
Harbors, Marine safety, Navigation (water), Reporting and recordkeeping requirements, Security measures, Waterways.
For the reasons discussed in the preamble, the Coast Guard proposes to amend 33 CFR part 165 as follows:
1. The authority citation for part 165 continues to read as follows:
33 U.S.C. 1226, 1231; 46 U.S.C. Chapter 701, 3306, 3703; 50 U.S.C. 191, 195; 33 CFR 1.05-1, 6.04-1, 6.04-6, 160.5; Pub. L. 107-295, 116 Stat. 2064; Department of Homeland Security Delegation No. 0170.1.
2. Add a temporary § 165.T07-0195 to read as follows:
(a)
(b)
(c)
(2) Persons and vessels desiring to enter, transit through, anchor in, or remain within the regulated area may contact the Captain of the Port Miami via telephone at 305-535-4472, or a designated representative via VHF radio on channel 16, to seek authorization. If authorization to enter, transit through, anchor in, or remain within the regulated area is granted by the Captain of the Port Miami or a designated representative, all persons and vessels receiving such authorization must comply with the instructions of the Captain of the Port Miami or a designated representative.
(3) The Coast Guard will provide notice of the regulated area via Local Notice to Mariners, Broadcast Notice to Mariners, and by on-scene designated representatives.
(d)
Coast Guard, DHS.
Notice of proposed rulemaking.
The Coast Guard proposes to establish a temporary safety zone around a fireworks display in Cos Cob Harbor, Greenwich, CT, located within the Captain of the Port (COTP) Sector Long Island Sound zone. This action is necessary to provide for the safety of life on navigable waters during the event. Entering into, transiting through, mooring or anchoring within this zone is prohibited unless authorized by the COTP Sector Long Island Sound.
Comments and related material must be received by the Coast Guard on or before June 2, 2011.
Requests for public meetings must be received by the Coast Guard on or before May 18, 2011.
You may submit comments identified by docket number USCG-2011-0148 using any one of the following methods:
(1)
(2)
(3)
(4)
To avoid duplication, please use only one of these four methods.
If you have questions on this proposed rule, call or e-mail Chief Petty Officer Hugh Hamilton, Prevention Department, Coast Guard Sector Long Island Sound, 203-468-4459, e-mail
We encourage you to participate in this rulemaking by submitting comments and related materials. All comments received will be posted without change to
If you submit a comment, please include the docket number for this rulemaking (USCG-2011-0148), indicate the specific section of this document to which each comment applies, and provide a reason for each suggestion or recommendation. You may submit your comments and material online (via
To submit your comment online, go to
To view comments, as well as documents mentioned in this preamble as being available in the docket, go to
Anyone can search the electronic form of comments received into any of our dockets by the name of the individual submitting the comment (or signing the comment, if submitted on behalf of an association, business, labor union, etc.). You may review a Privacy
We do not now plan to hold a public meeting. But you may submit a request for one on or before May 18, 2011 using one of the four methods specified under
The legal basis for the proposed rule is 33 U.S.C. 1226, 1231, 46 U.S.C. Chapter 701, 3306, 3703; 50 U.S.C. 191, 195; Public Law 107-295, 116 Stat. 2064; and Department of Homeland Security Delegation No. 0170.1, which collectively authorize the Coast Guard to define safety zones.
This rule is necessary to ensure the safety of vessels and spectators from hazards associated with fireworks events. The COTP Long Island Sound has determined that fireworks events in close proximity to the navigational channel and Special Anchorage Area pose a significant risk to public safety and property. Such hazards include obstructions to the waterway that may cause marine casualties and the explosive danger of fireworks and debris falling into the water that may cause death or serious bodily harm. Establishing a safety zone around the location of this fireworks event will help ensure the safety of persons and property and help minimize the associated risks.
This safety zone is necessary to ensure the safety of participants, spectators, and vessels during the Rudey and Braga Fireworks event in the COTP Long Island Sound zone as this event may pose a hazard to the public.
The Rudey and Braga families will be hosting a fireworks display as part of a wedding celebration in Greenwich, CT, directly off a private estate in Cos Cob Harbor.
This rule proposes to create a 600 foot safety zone on the navigable waters around the launch site located at approximately 41°00′59″ N, 073°36′05″ W. The safety zone will be in place 30 minutes prior to the event until 30 minutes after the event concludes.
The particular size of the proposed safety zone established for this event was evaluated in accordance with Navigational and Vessel Inspection Circular (NVIC) 07-02; Marine Safety at Firework Displays; the National Fire Protection Association Standard 1123, Code for Fireworks Displays (30-yard distance per inch of diameter of the fireworks mortars), and other pertinent regulations and publications.
We developed this proposed rule after considering numerous statutes and executive orders related to rulemaking. Below we summarize our analyses based on 13 of these statutes or executive orders.
This proposed rule is not a significant regulatory action under section 3(f) of Executive Order 12866, Regulatory Planning and Review, and does not require an assessment of potential costs and benefits under section 6(a)(3) of that Order. The Office of Management and Budget has not reviewed it under that Order.
The Coast Guard determined that this rule is not a significant regulatory action for the following reasons: The regulated area will be of limited duration, there is very little impingement onto the navigable waterway, and the event is designed to avoid, to the extent possible, deep draft, fishing, and recreational boating traffic routes. Persons and/or vessels may enter a safety zone if they obtain permission from the Coast Guard COTP, Long Island Sound.
Under the Regulatory Flexibility Act (5 U.S.C. 601-612), we have considered whether this proposed rule would have a significant economic impact on a substantial number of small entities. The term “small entities” comprises small businesses, not-for-profit organizations that are independently owned and operated and are not dominant in their fields, and governmental jurisdictions with populations of less than 50,000.
The Coast Guard certifies under 5 U.S.C. 605(b) that this proposed rule would not have a significant economic impact on a substantial number of small entities. Persons and/or vessels may enter this safety zone if they obtain permission from the Coast Guard COTP, Long Island Sound.
This proposed rule may affect the following entities, some of which might be small entities: The owners or operators of vessels intending to transit or anchor in a portion of the Cos Cob Harbor from 9 p.m. to 10:15 p.m. on June 25th, 2011.
This proposed safety zone would not have a significant economic impact on a substantial number of small entities for the following reasons. This temporary safety zone would be activated and enforced for only 1 hour and 15 minutes in an area where vessel traffic is expected to be minimal. Vessel traffic could pass safely around the safety zone through the navigational channel. Persons and/or vessels may enter a safety zone if granted permission from the Coast Guard COTP, Long Island Sound.
If you think that your business, organization, or governmental jurisdiction qualifies as a small entity and that this rule would have a significant economic impact on it, please submit a comment (
Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Public Law 104-121), we want to assist small entities in understanding this proposed rule so that they can better evaluate its effects on them and participate in the rulemaking. If the rule would affect your small business, organization, or governmental jurisdiction and you have questions concerning its provisions or options for compliance, please contact Chief Petty Officer Hugh Hamilton, Prevention Department, Coast Guard Sector Long Island Sound, (203) 468-4459 or e-mail
This proposed rule would call for no new collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520.).
A rule has implications for federalism under Executive Order 13132, Federalism, if it has a substantial direct effect on State or local governments and would either preempt State law or impose a substantial direct cost of compliance on them. We have analyzed this proposed rule under that Order and have determined that it does not have implications for federalism.
The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538) requires Federal agencies to assess the effects of their discretionary regulatory actions. In particular, the Act addresses actions that may result in the expenditure by a
This proposed rule would not cause a taking of private property or otherwise have taking implications under Executive Order 12630, Governmental Actions and Interference with Constitutionally Protected Property Rights.
This proposed rule meets applicable standards in sections 3(a) and 3(b)(2) of Executive Order 12988, Civil Justice Reform, to minimize litigation, eliminate ambiguity, and reduce burden.
We have analyzed this proposed rule under Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks. This rule is not an economically significant rule and would not create an environmental risk to health or risk to safety that might disproportionately affect children.
This proposed rule does not have tribal implications under Executive Order 13175, Consultation and Coordination with Indian Tribal Governments, because it would not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes.
We have analyzed this proposed rule under Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use. We have determined that it is not a “significant energy action” under that order because it is not a “significant regulatory action” under Executive Order 12866 and is not likely to have a significant adverse effect on the supply, distribution, or use of energy. The Administrator of the Office of Information and Regulatory Affairs has not designated it as a significant energy action. Therefore, it does not require a Statement of Energy Effects under Executive Order 13211.
The National Technology Transfer and Advancement Act (NTTAA) (15 U.S.C. 272 note) directs agencies to use voluntary consensus standards in their regulatory activities unless the agency provides Congress, through the Office of Management and Budget, with an explanation of why using these standards would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (
This proposed rule does not use technical standards. Therefore, we did not consider the use of voluntary consensus standards.
We have analyzed this proposed rule under Department of Homeland Security Management Directive 023-01 and Commandant Instruction M16475.lD, which guide the Coast Guard in complying with the National Environmental Policy Act of 1969 (NEPA) (42 U.S.C. 4321-4370f), and have made a preliminary determination that this action is one of a category of actions which do not individually or cumulatively have a significant effect on the human environment. This rule is categorically excluded, under figure 2-1, paragraph (34)(g), of the Instruction. This proposed rule involves the establishment of a safety zone. A preliminary environmental analysis checklist supporting this determination is available in the docket where indicated under
Harbors, Marine safety, Navigation (water), Reporting and recordkeeping requirements, Security measures, Waterways.
For the reasons discussed in the preamble, the Coast Guard proposes to amend 33 CFR part 165 as follows:
1. The authority citation for part 165 continues to read as follows:
33 U.S.C. 1226, 1231; 46 U.S.C. Chapters 701, 3306, 3703; 50 U.S.C. 191, 195; 33 CFR 1.05-1, 6.04-1, 6.04-6, and 160.5; Pub. L. 107-295, 116 Stat. 2064; Department of Homeland Security Delegation No. 0170.1.
2. Add § 165.T01-0148 to read as follows:
(a) Location. The following is a Safety Zone: All waters of Long Island Sound in Cos Cob Harbor within a 600-foot radius of the fireworks barge located in approximate position 41°00′59″ N, 073°36′05″ W.
(b) Notification. Coast Guard Sector Long Island Sound will cause notice of the enforcement of this temporary safety zone to be made by all appropriate means to affect the widest publicity among the effected segments of the public, including publication in the Local Notice to Mariners and Broadcast Notice to Mariners.
(c) Enforcement Period. This section will be enforced on 25 June, 2011, from 9 p.m. until 10:15 p.m.
(d) Regulations. (1) The general regulations contained in 33 CFR 165.23 apply. During the enforcement period, entering into, transiting through, mooring or anchoring within this safety zone is prohibited unless authorized by the Captain of the Port or the designated on-scene representatives.
(2) This temporary safety zones is closed to all vessel traffic, except as may be permitted by the Captain of the Port or the designated on-scene representative. The COTP or the designated on scene representative may be contacted via VHF Channel 16 or by telephone at (203) 468-4404.
(3) The “on-scene representative” of the COTP Long Island Sound is any Coast Guard commissioned, warrant, or petty officer who has been designated by the COTP to act on his behalf. The on-scene representative of the COTP Long Island Sound may be aboard either a Coast Guard or Coast Guard Auxiliary vessel.
(4) Vessel operators given permission to enter or operate in the safety zone must comply with all directions given to them by the Captain of the Port or the designated on-scene representative.
(5) The Captain of the Port or the designated on-scene representative may direct the delay, cancellation, or relocation of the specific area to be regulated within the generally described locations listed to ensure safety and compliance with environmental laws. Such changes in implementation of the safety zone may be required as a result of factors that could affect their associated marine events such as weather, vessel traffic density, spectator
Environmental Protection Agency (EPA).
Proposed rule.
EPA is proposing to approve a revision to the Illinois State Implementation Plan (SIP) for ozone. The State is revising its definition of volatile organic compound (VOC) to add two chemical compounds to the list of compounds that are exempt from being considered a VOC. This revision is based on EPA's 2009 determination that these two listed compounds do not significantly contribute to ozone formation.
Comments must be received on or before June 2, 2011.
Submit your comments, identified by Docket ID No. EPA-R05-OAR-2010-0946, by one of the following methods:
1.
2.
3.
4.
5.
Please see the direct final rule which is located in the Rules section of this
Charles Hatten, Environmental Engineer, Control Strategies Section, Air Programs Branch (AR-18J), Environmental Protection Agency, Region 5, 77 West Jackson Boulevard, Chicago, Illinois 60604, (312) 886-6031,
In the Final Rules section of this
Federal Communications Commission.
Petition for reconsideration.
In this document, a Petition for Reconsideration (Petition) has been filed in the Commission's Rulemaking proceeding listed below by Kona Coast Radio, LLC (“Kona Coast”), seeking reconsideration of actions taken in a
Oppositions to the Petition must be filed by May 18, 2011. Replies to an opposition must be filed May 31, 2011.
Federal Communications Commission, 445 12th Street, SW., Washington, DC 20554.
Deborah Dupont, Media Bureau, 202-418-7072.
On February 18, 2011, the Commission, via the Media Bureau released
Number of Petitions Filed: 1.
The Department of Agriculture will submit the following information collection requirement(s) to OMB for review and clearance under the Paperwork Reduction Act of 1995, Public Law 104-13 on or after the date of publication of this notice. Comments regarding (a) Whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility; (b) the accuracy of the agency's estimate of burden including the validity of the methodology and assumptions used; (c) ways to enhance the quality, utility and clarity of the information to be collected; (d) ways to minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology should be addressed to: Desk Officer for Agriculture, Office of Information and Regulatory Affairs, Office of Management and Budget (OMB), New Executive Office Building, Washington, DC;
Comments regarding these information collections are best assured of having their full effect if received by June 2, 2011. Copies of the submission(s) may be obtained by calling (202) 720-8681.
An agency may not conduct or sponsor a collection of information unless the collection of information displays a currently valid OMB control number and the agency informs potential persons who are to respond to the collection of information that such persons are not required to respond to the collection of information unless it displays a currently valid OMB control number.
Animal and Plant Health Inspection Service, USDA.
New information collection; comment request.
In accordance with the Paperwork Reduction Act, this notice announces the Animal and Plant Health Inspection Service's intention to initiate an information collection associated with a new category of plants for planting, also referred to as nursery stock, whose importation is not authorized for importation pending pest risk analysis.
We will consider all comments that we receive on or before July 5, 2011.
You may submit comments by either of the following methods:
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For information on a new category of plants for planting not authorized for importation pending pest risk analysis, contact Dr. Arnold Tschanz, Senior Plant Pathologist, Plants for Planting Policy, Risk Management and Plants for Planting Policy, RPM, PPQ, APHIS, 4700 River Road Unit 133, Riverdale, MD 20737-1236; (301) 734-0627. For copies of more detailed information on the information collection, contact Mrs. Celeste Sickles, APHIS' Information Collection Coordinator, at (301) 851-2908.
The regulations in 7 CFR part 319 prohibit or restrict the importation of certain plants and plant products into the United States to prevent the introduction of plant pests that are not already established in the United States or plant pests that may be established but are under official control to eradicate or contain them within the United States. The regulations in “Subpart—Nursery Stock, Plants, Roots, Bulbs, Seeds, and Other Plant Products,” §§ 319.37 through 319.37-14 (referred to below as the regulations), restrict, among other things, the importation of living plants, plant parts, seeds, and plant cuttings for planting or propagation. These regulations are intended to ensure that imported nursery stock does not serve as a host for plant pests, such as insects or pathogens, that can cause damage to U.S. agricultural and environmental resources.
On July 23, 2009, we published in the
APHIS is in the final rulemaking stage to amend part 319 which, if adopted, will require that requests to remove a taxon from the NAPPRA category be made in accordance with § 319.5, which contains requirements for requests to change the regulations in part 319. The current regulations in § 319.5 will apply, if adopted in the final rule, to the new category of plants for planting. This requirement was not part of the 2009 proposed rule and was added based on commenters' requests to allow only national plant protection organizations (NPPOs) to request that taxa be removed from the NAPPRA list. The final rule will allow any person to request that a taxon be removed from the NAPPRA list, but the regulations in § 319.5 will require the NPPO to be involved in the request, to ensure that APHIS has all the information necessary to evaluate the taxon.
Section 319.5 contains information collection activities for the submission of requests to APHIS that are necessary for us to conduct a PRA, including information about the party making the request, information about the commodity proposed for importation into the United States, shipping information, and a description of pests associated with the commodity.
We are asking the Office of Management and Budget (OMB) to approve our use of this information collection for 3 years.
The purpose of this notice is to solicit comments from the public (as well as affected agencies) concerning our information collection. These comments will help us:
(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 our 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, through use, as appropriate, of automated, electronic, mechanical, and other collection technologies; e.g., permitting electronic submission of responses.
All responses to this notice will be summarized and included in the request for OMB approval. All comments will also become a matter of public record.
Food Safety and Inspection Service, USDA.
Notice and request for comments.
In accordance with the Paperwork Reduction Act of 1995 and the Office of Management and Budget (OMB) regulations, this notice announces the Food Safety and Inspection Service's (FSIS) intention to request a revision of a currently approved information collection. The information collection addresses the paperwork requirements specified in the regulations relating to the application for inspection, accreditation of laboratories, and exemptions. FSIS is revising the information collection to increase the estimate of the total burden hours, and because the OMB approval will expire on July 31, 2011.
Comments on this notice must be received on or before July 5, 2011.
FSIS invites interested persons to submit comments on this notice. Comments may be submitted by either of the following methods:
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Contact John O'Connell, Paperwork Reduction Act Coordinator, Food Safety and Inspection Service, USDA, 1400 Independence Avenue, SW., Room 6065, South Building, Washington, DC 20250, (202) 720-0345.
FSIS is requesting a revision of an approved information collection addressing paperwork requirements specified in the regulations relating to the application for inspection, accreditation of laboratories, and exemptions.
FSIS requires meat and poultry establishments and import facilities to apply for a grant of inspection before receiving Federal inspection (9 CFR 304.1 & 381.17). FSIS also requires plants that wish to receive voluntary inspection to apply for service (9 CFR 350.5, 351.4, 352.3, & 362.3). Establishments that wish to export or import product must also submit certain documents to the Agency.
The FMIA (21 U.S.C. 642), the PPIA (21 U.S.C. 460(b)), and the EPIA (21 U.S.C. 1040) require certain parties to keep records that fully and correctly disclose all transactions involved in their businesses related to relevant animal carcasses and parts and egg products.
FSIS requires accredited non-Federal analytical laboratories to maintain certain paperwork and records (9 CFR 439.20 & 590.580). The Agency uses this collected information to ensure that meat and poultry establishments and egg products plants provide safe, wholesome, and not adulterated product, and that non-Federal laboratories act in accordance with FSIS regulations.
In addition, FSIS also requires establishments to keep records to ensure that meat and poultry products exempted from Agency inspection are not commingled with inspected meat and poultry products (9 CFR 303.1(b)(3) & 381.175), and that firms qualifying for a retail store exemption who have violated the provisions of that exemption are no longer in violation (9 CFR 303.1(d)(3) & 381.10(d)(3)).
The Agency is revising the information collection based on a revised estimate of the number of respondents due to an increase in the number of establishments. This increase in the number of establishments supports the finding of a total increase in burden hours (39.4) from that found in the previously approved information collection.
FSIS has made the following estimates based upon an information collection assessment:
Copies of this information collection assessment can be obtained from John O'Connell, Paperwork Reduction Act Coordinator, Food Safety and Inspection Service, USDA, 1400 Independence Avenue, SW., Room 6065, South Building, Washington, DC 20250, (202) 720-0345.
Responses to this notice will be summarized and included in the request for OMB approval. All comments will also become a matter of public record.
The U.S. Department of Agriculture (USDA) prohibits discrimination in all its programs and activities on the basis of race, color, national origin, gender, religion, age, disability, political beliefs, sexual orientation, and marital or family status. (Not all prohibited bases apply to all programs.) Persons with disabilities who require alternative means for communication of program information (Braille, large print, audiotape, etc.) should contact USDA's Target Center at 202-720-2600 (voice and TTY).
To file a written complaint of discrimination, write USDA, Office of the Assistant Secretary for Civil Rights, 1400 Independence Avenue, SW, Washington, DC 20250-9410 or call 202-720-5964 (voice and TTY). USDA is an equal opportunity provider and employer.
Public awareness of all segments of rulemaking and policy development is important. Consequently, in an effort to ensure that the public and in particular minorities, women, and persons with disabilities, are aware of this notice, FSIS will announce it on-line through the FSIS Web page located at
FSIS also will make copies of this
In addition, FSIS offers an e-mail subscription service which provides automatic and customized access to selected food safety news and information. This service is available at
Forest Service, USDA.
Notice of Meeting.
Pursuant to the authorities in the Federal Advisory Committee Act (Pub. L. 92-463) and under the Secure Rural Schools and Community Self-Determination Act of 2000 (Pub. L. 110-343), the Salmon-Challis National Forest's Central Idaho Resource Advisory Committee will conduct a business meeting which is open to the public.
Friday, June 3, 2011, beginning at 10 a.m.
Public Lands Center, 1206 South Challis Street, Salmon, Idaho
Agenda topics will include, presentation of proposed projects, evaluation of some projects proposals, and approval and recommendation of some projects for Title II funding for 2011 and 2012. Some RAC members may attend the meeting by conference call, telephone, or electronically.
Lyle E. Powers, Acting Forest Supervisor, at 208-756-5557.
Forest Service, USDA.
Notice of meeting.
The El Dorado County Resource Advisory Committee will meet in Placerville, California. The committee is meeting as authorized under the Secure Rural Schools and Community Self-Determination Act (Pub. L. 110-343) and in compliance with the Federal Advisory Committee Act. The RAC will prioritize a list of projects for funding in FY 2011 and FY 2012. The RAC may also be voting to recommend projects for funding.
The meeting will be held on May 23, 2011 beginning at 6 p.m..
The meeting will be held at the El Dorado Center of Folsom Lake College, Community Room, 6699 Campus Drive, Placerville, CA 95667.
Written comments should be sent to Frank Mosbacher; Forest Supervisor's Office; 100 Forni Road; Placerville, CA 95667. Comments may also be sent via e-mail to
All comments, including names and addresses when provided, are placed in the record and are available for public inspection and copying. The public may inspect comments received at 100 Forni Road; Placerville, CA 95667. Visitors are encouraged to call ahead to 530-622-5061 to facilitate entry into the building.
Frank Mosbacher, Public Affairs Officer, Eldorado National Forest Supervisors Office, (530) 621-5268. Individuals who use telecommunication devices for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339 between 8 a.m. and 8 p.m., Eastern Standard Time, Monday through Friday.
The meeting is open to the public. The following business will be conducted: The RAC will prioritize a list of projects for funding in FY 2011 and FY 2012. The RAC may also be voting to recommend projects for funding. More information will be posted on the Eldorado National Forest Web site at
Forest Service, USDA.
Notice of meeting.
The Prince of Wales Resource Advisory Committee will meet in Coffman Cove, Alaska, May 16, 2011 The committee is authorized under the Secure Rural Schools and Community Self-Determination Act (Pub. L 110-343) (the Act) and operates in compliance with the Federal Advisory Committee Act. The purpose of the committee is to improve collaborative relationships and to provide advice and recommendations to the Forest Service concerning projects and funding consistent with the title II of the Act. The meeting is open to the public. The purpose of the meeting is to discuss potential projects under the Secure Rural Schools and Community Self-Determination Act of 2008.
The meeting will be held May 16, 2011 from 10 a.m. to 4 p.m.
The meeting will be held at the Ferry Terminal 110 Stikine Way Coffman Cove, Alaska. Written comments may be submitted as described under
All comments, including names and addresses when provided, are placed in the record and are available for public inspection and copying. The public may inspect comments received at the Craig Ranger District. Please call ahead to 907-826-3271 to facilitate entry into the building to view comments.
Rebecca Sakraida, RAC Coordinator, 907-826-1601 or e-mail
Individuals who use telecommunication devices for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339 between 8 a.m. and 8 p.m., Eastern Standard Time, Monday through Friday. Requests for reasonable accomodation for access to the facility or procedings may be made by contacting the person listed FOR FURTHER INFORMATION.
The following business will be conducted: Review of projects submitted for review. An agenda will be available at the Secure Rural Schools Web site,
Forest Service, USDA.
Notice of Meeting.
The Lincoln County Resource Advisory Committee will meet in Libby, MT. The committee is authorized under the Secure Rural Schools and Community Self-Determination Act (Pub. L. 110-343) (the Act) and operates in compliance with the Federal Advisory Committee Act. The purpose of the committee is to improve collaborative relationships and to provide advice and recommendations to the Forest Service concerning projects and funding consistent with the title II of the Act. The meeting is open to the public. The purpose of the meeting is to review 2011 project proposals.
May 18, 2011 @ 6 p.m.
Forest Supervisor's Office, 31374 Hwy 2, Libby, Montana. Written comments may be submitted as described under
All comments, including names and addresses when provided, are placed in the record and are available for public inspection and copying. The public may inspect comments received at the Forest Supervisor's Office. Please call ahead to 406-283-7764 to facilitate entry into the building to view comments.
Janette Turk, Committee Coordinator, Kootenai National Forest at (406) 283-7764, or e-mail
Individuals who use telecommunication devices for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339 between 8 a.m. and 8 p.m., Eastern Standard Time, Monday through Friday. Requests for reasonable accommodation for access to the facility or proceedings may be made by contacting the person listed under
The following business will be conducted: A vote to fund 2011 projects. If the meeting date or location is changed, notice will be posted in the local newspapers, including the Daily Interlake, based in Kalispell, Montana. Anyone who would like to bring related matters to the attention of the committee may file written statements with the committee staff before or after the meeting. The agenda will include time for people to make oral statements of three minutes or less. Individuals wishing to make an oral statement should request in writing by May 16, 2011 to be scheduled on the agenda. Written comments and requests for time for oral comments must be sent to Forest Supervisor's Office, 31374 Hwy 2, Libby, Montana, or by e-mail to
Forest Service, USDA.
Notice of meeting.
The Siskiyou County Resource Advisory Committee will meet in Yreka, California. The committee is authorized under the Secure Rural Schools and Community Self-Determination Act (Pub. L. 110-343) (the Act) and operates in compliance with the Federal Advisory Committee Act. The purpose of the committee is to improve collaborative relationships and to provide advice and recommendations to the Forest Service concerning projects and funding consistent with the title II of the Act. The meeting is open to the public. The purpose of the meeting is for the committee to hear project status, presentation and review of new project proposals and to vote and make
The meeting will be held Monday June 20, 2011 at 4 p.m.
The meeting will be held at the Klamath National Forest Supervisor's Office, conference room, 1312 Fairlane Road, Yreka, CA 96097. Written comments may be submitted as described under
All comments, including names and addresses when provided, are placed in the record and are available for public inspection and copying. The public may inspect comments received at Klamath National Forest Supervisor's Office. Please call ahead to (530) 841-4484 to facilitate entry into the building to view comments.
Kerry Greene, Community Development and Outreach Specialist, Klamath National Forest, (530) 841-4484,
Individuals who use telecommunication devices for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339 between 8 a.m. and 8 p.m., Eastern Standard Time, Monday through Friday. Requests for reasonable accommodation for access to the facility or proceedings may be made by contacting the person listed
Forest Service, USDA.
Notice of meeting.
The Siskiyou County Resource Advisory Committee will meet in Yreka, California. The committee is authorized under the Secure Rural Schools and Community Self-Determination Act (Pub. L. 110-343) (the Act) and operates in compliance with the Federal Advisory Committee Act. The purpose of the committee is to improve collaborative relationships and to provide advice and recommendations to the Forest Service concerning projects and funding consistent with the title II of the Act. The meeting is open to the public. The purpose of the meeting is for the committee to hear project status, presentation and review of new project proposals and to vote and make recommendations. The meeting is open to the public. Opportunity for public comment will be provided.
The meeting will be held Monday May 16, 2011 at 4 p.m.
The meeting will be held at the Klamath National Forest Supervisor's Office, conference room, 1312 Fairlane Road, Yreka, CA 96097. Written comments may be submitted as described under
All comments, including names and addresses when provided, are placed in the record and are available for public inspection and copying. The public may inspect comments received at Klamath National Forest Supervisor's Office. Please call ahead to (530) 841-4484 to facilitate entry into the building to view comments.
Kerry Greene, Community Development and Outreach Specialist, Klamath National Forest, (530) 841-4484,
Individuals who use telecommunication devices for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339 between 8 a.m. and 8 p.m., Eastern Standard Time, Monday through Friday. Requests for reasonable accomodation for access to the facility or procedings may be made by contacting the person listed
Forest Service, USDA.
Notice of meeting.
The Hiawatha West Resource Advisory Committee will meet in Rapid River, Michigan. The committee is meeting as authorized under the Secure Rural Schools and Community Self-Determination Act (Pub. L. 110-343) and in compliance with the Federal Advisory Committee Act. The purpose is to hold the first meeting of the newly formed committee.
The meeting will be held on June 16, 2011, and will begin at 6:30 p.m.
The meeting will be held at the Masonville Township Offices, 10574 North Main Street, Rapid River, MI 49878. Written comments should be sent to Janel Crooks, Hiawatha National Forest, 2727 North Lincoln Road, Escanaba, MI 49829. Comments may also be sent via e-mail to
All comments, including names and addresses when provided, are placed in the record and are available for public inspection and copying. The public may inspect comments received at Hiawatha National Forest, 2727 North Lincoln Road, Escanaba, MI. Visitors are encouraged to call ahead to 906-786-4062 to facilitate entry into the building.
Janel Crooks, RAC coordinator, USDA,
The meeting is open to the public. The following business will be conducted: (1) Review of submitted projects. Persons who wish to bring related matters to the attention of the Committee may file written statements with the Committee staff before or after the meeting.
Forest Service, USDA.
Notice of meeting.
Pursuant to the authorities in the Federal Advisory Committees Act (Pub. L. 92-463), the Northeast Oregon Forest Resource Advisory Committee (RAC) will meet on May 19, 2011 in John Day, Oregon. The purpose of the meeting is to meet as a Committee to discuss selection of Title II projects under Public Law 110-343, H.R. 1424, the Reauthorization of the Secure Rural Schools and community Self-Determination Act of 2000 (16 U.S.C. 500 note; Pub. L. 106-393), also called “Payments to States” Act.
The meeting will be held on May 19, 2011, from 9 a.m to 4 p.m.
The meeting will be held in the Outpost Pizza and Grill, 201 West Main Street, John Day, Oregon.
Kurt Wiedenmann, Designated Federal Official, USDA, Wallowa-Whitman National Forest, La Grande Ranger District, 3502 Highway 30, La Grande, Oregon 97850;
This will be the third meeting of the Committee since reauthorization of Public Law 106-393. The meeting will focus on introducing new Committee members, becoming familiar with duties and responsibilities, selecting a chairperson, reviewing and recommending 2009 and 2010 project proposals that meet the intent of the Act. The meeting is open to the public. A public input opportunity will be provided at 1:00 p.m., and individuals will have the opportunity to address the committee at that time.
Bureau of Industry and Security, Commerce.
Notice.
The Department of Commerce, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995.
Written comments must be submitted on or before July 5, 2011.
Direct all written comments to Diana Hynek, Departmental Paperwork Clearance Officer, Department of Commerce, Room 6616, 14th and Constitution Avenue, NW., Washington, DC 20230 (or via the Internet at
Requests for additional information or copies of the information collection instrument and instructions should be directed to Larry Hall, BIS ICB Liaison, (202) 482-4895,
The Additional Protocol requires the United States to submit declaration forms to the International Atomic Energy Agency (IAEA) on a number of commercial nuclear and nuclear-related items, materials, and activities that may be used for peaceful nuclear purposes, but also would be necessary elements for a nuclear weapons program. These forms provides the IAEA with information about additional aspects of the U.S. commercial nuclear fuel cycle, including: Mining and milling of nuclear materials; buildings on sites of facilities selected by the IAEA from the U.S. Eligible Facilities List; nuclear-related equipment manufacturing, assembly, or construction; import and export of nuclear and nuclear-related items and materials; and research and development. The Protocol also expands IAEA access to locations where these activities occur in order to verify the data on the form.
Submitted electronically or paper format.
Comments are invited on: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden (including hours and cost) of the proposed collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; and (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology.
Comments submitted in response to this notice will be summarized and/or included in the request for OMB approval of this information collection; they also will become a matter of public record.
Import Administration, International Trade Administration, Department of Commerce
On January 28, 2011, in response to a request from an interested party, the Department of Commerce (the Department) published a notice of initiation of the administrative review of the antidumping duty order on carbazole violet pigment 23 (CVP 23) from India for the period of December 1, 2009, through November 30, 2010. Because the party withdrew its request for an administrative review in a timely manner, the Department is rescinding this review.
Jerrold Freeman or Richard Rimlinger, AD/CVD Operations, Office 5, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue, NW., Washington, DC 20230;
On December 29, 2004, the Department published in the
On April 4, 2011, Meghmani withdrew its request for review of its sales of merchandise subject to the antidumping duty order for the period December 1, 2009, through November 30, 2010.
In accordance with 19 CFR 351.213(d)(1), the Department will rescind an administrative review, in whole or in part, “if a party that requested the review withdraws the request within 90 days of the date of publication of notice of initiation of the requested review.” We received a letter from Meghmani withdrawing its request for review within the 90-day time limit. We received no other requests for review of the antidumping duty order. In accordance with 19 CFR 351.213(d)(1), we are rescinding the review of the antidumping duty order on CVP 23 from India.
The Department will instruct U.S. Customs and Border Protection to assess antidumping duties on all appropriate entries. Antidumping duties shall be assessed at rates equal to the cash deposit of estimated antidumping duties required at the time of entry, or withdrawal from warehouse, for consumption, in accordance with 19 CFR 351.212(c)(1)(i). The Department intends to issue appropriate assessment instructions directly to CBP 15 days after the publication of this notice in the
This notice serves as a final reminder to importers of their responsibility under 19 CFR 351.402(f) to file a certificate regarding the reimbursement of antidumping duties prior to liquidation of the relevant entries during the review period. Failure to comply with this requirement could result in the Department's presumption that reimbursement of antidumping duties occurred and the subsequent assessment of doubled antidumping duties.
This notice serves as a reminder to parties subject to the administrative protective order (APO) of their responsibility concerning the disposition of proprietary information disclosed under APO in accordance with 19 CFR 351.305(a)(3). Timely written notification of the destruction of APO materials or conversion to judicial protective order is hereby requested. Failure to comply with the regulations and terms of an APO is a sanctionable violation.
We are issuing and publishing this notice in accordance with section 777(i)(1) of the Act and 19 CFR 351.213(d)(4).
Import Administration, International Trade Administration, Department of Commerce.
The Department of Commerce (“the Department”) published a notice in the
Sheila E. Forbes, Office of AD/CVD Operations, Customs Unit, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue, NW., Washington, DC 20230, telephone: (202) 482-4697.
In the
Import Administration, International Trade Administration, Department of Commerce.
On January 3, 2011, the Department of Commerce (“Department”) initiated a sunset review of the antidumping duty orders on heavy forged hand tools (“Hand Tools”) (
Effective Date: May 3, 2011.
Emeka Chukwudebe, AD/CVD Operations, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue, NW., Washington, DC 20230;
On January 3, 2011, the Department initiated the third sunset review of the orders on Hand Tools pursuant to section 751(c) of the Act.
The products covered by these orders are Hand Tools comprising the following classes or kinds of merchandise: (1) Hammers and sledges with heads over 1.5 kg (3.33 pounds); (2) bars over 18 inches in length, track tools and wedges; (3) picks and mattocks; and (4) axes, adzes and similar hewing tools. Hand Tools include heads for drilling hammers, sledges, axes, mauls, picks and mattocks, which may or may not be painted, which may or may not be finished, or which may or may not be imported with handles; assorted bar products and track tools including wrecking bars, digging bars, and tampers; and steel wood splitting wedges. Hand Tools are manufactured through a hot forge operation in which steel is sheared to required length, heated to forging temperature, and formed to final shape on forging equipment using dies specific to the desired product shape and size. Depending on the product, finishing operations may include shot blasting, grinding, polishing and painting, and the insertion of handles for handled products. Hand Tools are currently provided for under the following Harmonized Tariff Schedule of the United States (“HTSUS”) subheadings: 8205.20.60, 8205.59.30, 8201.30.00, and 8201.40.60. Specifically excluded from these orders are hammers and sledges with heads 1.5 kg. (3.33 pounds) in weight and under, hoes and rakes, and bars 18 inches in length and under. The tariff classifications are provided for convenience and customs purposes; however, the written description of the scope of the orders is dispositive.
All issues raised in this review are addressed in the “Issues and Decision Memorandum” (“Decision Memorandum”) dated concurrently with this notice. The issues discussed in the Decision Memorandum include the likelihood of continuation or recurrence of dumping and the magnitude of the dumping margin likely to prevail if the
In addition, a complete public version of the Decision Memorandum can be accessed directly on the Web at
The Department determines that revocation of the
This notice also serves as the only reminder to parties subject to administrative protective order (“APO”) of their responsibility concerning the return or destruction of proprietary information disclosed under APO in accordance with 19 CFR 351.305. Timely notification of the return or destruction of APO materials or conversion to judicial protective order is hereby requested. Failure to comply with the regulations and terms of an APO is a violation which is subject to sanction.
We are issuing and publishing these results and notice in accordance with sections 751(c), 752, and 777(i)(1) of the Act.
Import Administration, International Trade Administration, Department of Commerce.
The Department of Commerce (Department) is conducting three new shipper reviews (NSRs) under the antidumping duty order on fresh garlic from the People's Republic of China (PRC). The NSRs cover Shenzhen Bainong Co., Ltd. (Shenzhen Bainong) and Jining Yifa Garlic Produce Co., Ltd. (Jining Yifa) for the period of review (POR) November 1, 2009, through April 30, 2010, and Yantai Jinyan Trading Inc. (Yantai Jinyan) for the POR November 1, 2009, through May 31, 2010. As discussed below, we preliminarily determine that Shenzhen Bainong's and Jining Yifa's sales are not
Jacqueline Arrowsmith (Yantai Jinyan), Milton Koch (Jining Yifa), and Justin Neuman (Shenzhen Bainong), AD/CVD Operations, Office 6, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue, NW., Washington, DC 20230;
On May 28, 2010, the Department received timely requests for an NSR from Jining Yifa, Shenzhen Bainong, and Yantai Jinyan in accordance with 19 CFR 351.214(c). On July 7, 2010, the Department determined that the requests submitted by Shenzhen Bainong, Jining Yifa, and Yantai Jinyan met the threshold requirements for initiation of an NSR and initiated the NSRs.
On July 20, 2010, the Department sent interested parties a letter requesting comments on the surrogate country selection and information pertaining to valuing factors of production.
On November 23, 2010, the Department placed a copy of the U.S. Customs and Border Protection (CBP) data run on the record of this review, which contains all entries of subject merchandise exported from the PRC to the United States during the PORs.
On February 11, 2011, the Department placed on the record of this review, copies of CBP documents pertaining to Shenzhen Bainong's and Jining Yifa's shipments of garlic during the POR. On February 14, 2011, the Department placed on the record of this review, copies of CBP documents pertaining to Yantai Jinyan's shipment of garlic during the POR.
Pursuant to 19 CFR 351.214(g), the POR of the NSRs of Shenzhen Bainong and Jining Yifa is the semi-annual period November 1, 2009, through April 30, 2010. In its request for a new shipper review, Yantai Jinyan requested that we extend the POR for its NSR to capture the entry of its shipment in early May, after the six-month semi-annual NSR POR. When the sale of the subject merchandise occurs within the POR specified by the Department's regulations, but the entry occurs after the POR, the POR may be extended unless it would be likely to prevent the completion of the review within the time limits set by the Department's regulations.
The products covered by the order are all grades of garlic, whole or separated into constituent cloves, whether or not peeled, fresh, chilled, frozen,
The NSR provisions of the Department's regulations require that the entity making a request for an NSR must document and certify, among other things: (i) The date on which the merchandise was first entered, or withdrawn from warehouse, for consumption, or, if it cannot establish the date of first entry, the date on which it first shipped the merchandise for export to the United States; (ii) the volume of that and subsequent shipments; and (iii) the date of the first sale to an unaffiliated customer in the United States.
In its request for an NSR, Yantai Jinyan made a representation and certified that it made a sale on April 19, 2010, to an unaffiliated customer, and that the sale entered the United States on May 25, 2010.
In its Section A response, dated August 18, 2010, however, and its subsequent responses, Yantai Jinyan identified the customer to which its April 19, 2010 sale was made as an affiliated company. Further, the Section A response showed that the sale to the first unaffiliated customer occurred on May 25, 2010, a date outside the original semi-annual POR.
Based on information that Yantai Jinyan submitted after the initiation of the NSR, the Department has now determined that Yantai Jinyan did not meet the minimum requirements in its request for an NSR under 19 CFR 351.214(b)(2)(iv)(C). The sale that Yantai Jinyan certified in its request as its first sale to an unaffiliated customer in the United States was later identified by Yantai Jinyan as a sale to an affiliated customer. Consequently, the Department has now determined that the initiation and expansion of the POR to capture the entry was based on inaccurate information and that there was neither a sale nor an entry during the original POR.
The Department is currently conducting an antidumping duty administrative review for the POR November 1, 2009, through October 31, 2010, which includes Yantai Jinyan and its entries.
Consistent with Department practice, we examined the
Based on the totality of circumstances, we preliminarily find that the sale made by Shenzhen Bainong during the POR was not a
Based on the totality of circumstances, we preliminarily find that the sales made by Jining Yifa during the POR are not
For the foregoing reasons, the Department finds that the sales of Shenzhen Bainong and Jining Yifa are not
If we proceed to a final rescission of Jining Yifa's and Shenzhen Bainong's NSRs, Jining Yifa's and Shenzhen Bainong's entries will be subject to the PRC-wide rate. The Department is currently conducting an administrative review for the POR November 1, 2009, through October 31, 31, 2010, which includes the entries subject to these NSRs. Thus the PRC-wide rate is under review. Upon completion of the administrative review, we will instruct CBP to assess antidumping duties on entries for Jining Yifa and Shenzhen Bainong at the appropriate PRC-wide rate.
If we proceed to a final rescission of the NSR of Yantai Jinyan, we will determine, during the course of the ongoing administrative review, if Yantai Jinyan is entitled to a separate rate. We will instruct CBP to assess antidumping duties on entries by Yantai Jinyan in accordance with the final results of the administrative review.
Effective upon publication of the final rescission of these NSRs or the final results of these NSRs, we will instruct CBP to discontinue the option of posting a bond or security in lieu of a cash deposit for entries of subject merchandise by Jining Yifa, Shenzhen Bainong, and Yantai Jinyan. If we proceed to a final rescission of these NSRs, the cash deposit rate will continue to be for the per-unit PRC wide rate for Jining Yifa, Shenzhen Bainong, and Yantai Jinyan. If we issue a final results of NSR for any of these respondents, we will instruct CBP to collect cash deposits, effective upon the publication of the final results, at the rates established therein.
We will disclose our analysis to parties to this proceeding not later than five days after the date of public announcement, or if there is no public announcement within five days of the date of publication of this notice.
Interested parties are invited to comment on these preliminary results and may submit case briefs and/or written comments within 30 days of the date of publication of this notice, unless otherwise notified by the Department.
Interested parties who wish to request a hearing, or to participate if one is requested, must submit a written request to the Assistant Secretary for Import Administration within 30 days of the date of publication of this notice. Requests should contain: (1) The party's name, address, and telephone number; (2) the number of participants; and (3) a list of issues to be discussed.
This notice serves as a preliminary reminder to importers of their responsibility under 19 CFR 351.402(f)(2) to file a certificate regarding the reimbursement of antidumping duties prior to liquidation of the relevant entries during this review period. Failure to comply with this requirement could result in the Secretary's presumption that reimbursement of antidumping duties occurred and the subsequent assessment of double antidumping duties.
We are issuing and publishing these preliminary results in accordance with sections 751(a)(2)(B) and 777(i) of the Act, and 19 CFR 351.214(h) and 351.221(b)(4).
Dated: April 26, 2011.
International Trade Administration, Commerce.
Notice.
The U.S. Government recognizes that economic recovery and job creation will depend significantly on its ability to work collaboratively with key trading partners to promote free and open trade and investment while also protecting public health and safety, the environment, intellectual property, and consumers' rights. In our trade and investment relationship with the European Union, the main impediments to greater trade and investment—and more open foreign markets for U.S. exporters and investors —are not tariffs or quotas, but rather differences in regulatory measures. These regulatory measures—which include standards developed by a government and used in regulation, standards developed by other bodies at the request or direction of a regulator for use in regulation, or proposals to provide a presumption of compliance to technical requirements developed by a government—may be unnecessary and may increase costs for producers and consumers.
With this Notice, the Department of Commerce's International Trade Administration (ITA), in support of the National Export Initiative (NEI) and the U.S.-EU High Level Regulatory Cooperation Forum (HLRCF), and pursuant to the Secretary of Commerce's role as the chair of Trade Promotion Coordinating Committee, is requesting stakeholders assist the Administration identify opportunities for cooperation between the United States and the European Union to reduce or eliminate divergences in regulatory measures that impede trade in goods in the transatlantic marketplace, in ways that may be unnecessary, as well as any existing or emerging sectors that may benefit from transatlantic regulatory cooperation.
For more information on U.S.-EU regulatory cooperation,
The agency must receive comments on or before June 2, 2011.
Submissions should be made via the internet at
Questions regarding this notice should be directed to
With this notice, the Commerce Department, on behalf of the Administration, is seeking public input to help identify divergences in regulatory measures in the transatlantic marketplace, so that the U.S. Government can work cooperatively with the European Union to address them.
President Obama linked trade to job creation when he announced the National Export Initiative (NEI) in his 2010 State of the Union address and set the ambitious goal of doubling U.S. exports in the next five years to support millions of jobs here at home. To help achieve this goal, the U.S. Government is working to remove unnecessary divergences in regulations and in standards used in regulation between the United States and the European Union. The European Union, with its 27 member countries, is our largest trading partner, accounting for 19 percent of U.S. merchandise exports in 2010.
Since 2005, the U.S. Government has worked with officials from the European Commission, within the framework of the U.S.-EU High Level Regulatory Cooperation Forum (HLRCF), to strengthen regulatory cooperation, to promote better regulation, and to reduce or eliminate unnecessary regulatory differences that hinder trade and reduce competitiveness, when doing so does not compromise those protections Americans expect from their government. In addition, at the conclusion of its December 2010 meeting, the Transatlantic Economic Council, comprised of Cabinet-level officials from the United States and the European Union, endorsed several initiatives aimed at further promoting U.S.-EU regulatory cooperation, including directing the HLRCF to develop a process for identifying, with stakeholder input, sectors in which the United States and the European Union could pursue upstream regulatory cooperation.
In his January 2010 State of the Union address, President Obama announced the NEI to double U.S. exports over five years and support the creation of new jobs. As the President's Export Promotion Cabinet has undertaken to implement the NEI, regional and sectoral plans are being developed to tailor the U.S. Government's NEI efforts based on the realities of trade with key trading partners. For example, bilateral trade between the United States and the European Union was $559.4 billion in 2010. Despite this extensive trade between the United States and the European Union, U.S. exporters indicate that they continue to encounter unnecessary transatlantic divergences in regulatory measures that impede trade.
ITA has developed a Mature Markets Initiative (MMI) to evaluate how best to grow exports, create jobs, and support U.S. business growth in areas where trade is robust. Regulatory cooperation is a key component of the MMI. Accordingly, ITA has identified the European Union as a mature market and will seek ways to ease or eliminate unnecessary differences in regulation and in standards used in regulation that hinder competitiveness and negatively impact trade for U.S. firms, including new-to-market and new-to-export businesses, and particularly for small- and medium-sized enterprises (SMEs).
Trade may be impeded, for example, because countries apply different standards or technical requirements to address common environmental, health, safety, or other concerns with respect to certain products or product categories. In some instances, such divergences may be arbitrary and can lead to delays,
Cooperation with respect to regulation and standards used in regulation can help reduce unjustified divergences and lower costs and burdens for businesses, especially SMEs, as well as for governments and consumers. For example, when regulators in different countries are allowed legally to share full data, studies, and other information on specific regulatory issues, they are more likely to reach similar conclusions, such as on the risks associated with a particular product, appropriate measures to mitigate those risks, and the costs and benefits associated with alternative regulatory approaches. This can lead regulators in these countries to adopt regulatory measures that are more aligned with each other, allow producers to develop economies of scale, reduce compliance costs associated with divergent regulatory measures, and pass on cost savings to consumers. It is important for regulatory cooperation to be transparent and non-discriminatory, reduce unnecessary costs and burdens on producers and consumers, and continue to fulfill each government's public health, safety, environmental, and other legitimate policy objectives.
Regulatory cooperation may include, e.g., equivalency agreements under which a regulator in one country agrees to recognize another country's standards as equivalent to its own, allowing products to be placed on its market that meet the other country's standards, or mutual recognition agreements under which regulators in each country agree to allow products from the other country to be placed on the market based on tests or certifications carried out in that country. The outcome of any such regulatory cooperation must ensure that each government can continue to meet its legitimate policy objectives and advance consumer interests.
In addition, when regulators cooperate with regard to regulatory measures, their cooperation may serve not only to facilitate trade, but may also help to realize common public policy objectives. For example, when regulators in different countries coordinate their efforts in carrying out product recalls, it can help ensure that defective or unsafe products are promptly removed from the market, thereby increasing consumers' confidence in the products they buy and in the global trading system.
Submitters should be as specific as possible in describing the relevant product or product sector in which they believe there is an opportunity to facilitate trade without undermining U.S. public health, safety, environmental, and other legitimate policy objectives. In addition, each comment should include, where appropriate: (a) A description of the specific measure or measures that the recommendation would address (e.g., laws or regulations setting out safety or testing requirements for the relevant product or product sector); (b) an Internet link to or a copy of the measure in English and documentation that may assist ITA in understanding the measure; (c) identification of the key markets in the European Union for the product or product sector; (d) a description of how and to what degree the regulatory measures are affecting trade and their related costs, including for SMEs; (e) information that may affect the recommendation's feasibility (
ITA is interested in receiving recommendations concerning any product sector that, due to the volume of trade between the United States and the European Union, is a justifiable focus of enhanced regulatory cooperation. Submitters are encouraged to work with counterparts and other interested stakeholders in the United States and the European Union to submit comments jointly. ITA will give positive consideration to recommendations that demonstrate strong support from stakeholders in both the United States and the European Union.
All comments and recommendations submitted in response to this notice will be made available to the public. For any comments submitted electronically containing business confidential information, the file name of the business confidential version should begin with the characters “BC”. The top of any page containing business confidential information must be clearly marked “BUSINESS CONFIDENTIAL”. Any person filing comments that
Please do not attach separate cover letters to electronic submissions; rather, include any information that might appear in a cover letter in the comments themselves. Similarly, to the extent possible, please include any exhibits, annexes, or other attachments in the same file as the submission itself, not as separate files.
National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice.
The Department of Commerce, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)).
Written comments must be submitted on or before July 5, 2011.
Direct all written comments to Diana Hynek, Departmental Paperwork Clearance Officer, Department of Commerce, Room 6625, 14th and Constitution Avenue, NW., Washington, DC 20230 (or via the Internet at
Requests for additional information or copies of the information collection instrument and instructions should be directed to Patricia Lawson, 301-713-2289 or at
In 1989, the National Marine Mammal Tissue Bank (NMMTB) was established by the National Marine Fisheries Service (NMFS) Office of Protected Resources in collaboration with the National Institute of Standards and Technology (NIST), Minerals Management Service (MMS), and the US Geological Survey/Biological Resources Division (USGS/BRD). The NMMTB provides protocols, techniques, and physical facilities for the long-term storage of tissues from marine mammals. Scientists can request tissues from this repository for retrospective analyses to determine environmental trends of contaminants and other substances of interest. The NMMTB collects, processes, and stores tissues from specific indicator species (e.g., Atlantic bottlenose dolphins, Atlantic white sided dolphins, pilot whales, harbor porpoises), animals from mass strandings, animals that have been obtained incidental to commercial fisheries, animals taken for subsistence purposes, biopsies, and animals from unusual mortality events through two projects, the Marine Mammal Health and Stranding Response Program (MMHSRP) and the Alaska Marine Mammal Tissue Archival Project (AMMTAP).
The purposes of this collection of information are: (1) To enable NOAA to allow the scientific community the opportunity to request tissue specimen samples from the NMMTB and, (2) to enable the MMHSRP of NOAA to assemble information on all specimens submitted to the Marine Environmental Specimen Bank (Marine ESB), which includes the NMMTB.
Respondents must complete a specimen banking information sheet for every sample submitted to the Bank. Methods of submitting reports include the Internet, mail and facsimile transmission of paper forms. Those requesting samples send the information, and their research findings, mainly via email.
Comments are invited on: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden (including hours and cost) of the proposed collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; and (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology. Comments submitted in response to this notice will be summarized and/or included in the request for OMB approval of this information collection; they also will become a matter of public record.
Defense Acquisition University, DoD.
Meeting Notice.
Under the provisions of the Federal Advisory Committee Act of 1972 (5 U.S.C., Appendix, as amended), the Government in the Sunshine Act of 1976 (5 U.S.C. 552b, as amended), and 41 CFR 102-3.150, the Department of Defense announces that the following Federal advisory committee meeting of the Defense Acquisition University Board of Visitors will take place:
Tuesday, May 17, 2011, from 9 a.m.-2 p.m.
Packard Conference Center, Defense Acquisition University, 9820 Belvoir Rd, Fort Belvoir, VA 22060.
Christen Goulding, Protocol Director, DAU Phone: 703-805-5134, Fax: 703-805-5940, E-mail:
Pursuant to 5 U.S.C. 552b and 41 CFR 102-3.140 through 102-3.165, and the availability of space, this meeting is open to the public. However, because of space limitations, allocation of seating will be made on a first-come, first served basis. Persons desiring to attend the meeting should call Ms. Christen Goulding at 703-805-5134.
Ms. Kelley Berta, 703-805-5412.
Office of the Secretary, DoD.
Notice to alter a system of records.
The Office of the Secretary of Defense proposes to alter a system of records in its inventory of record systems subject to the Privacy Act of 1974 (5 U.S.C. 552a), as amended.
This proposed action would be effective without further notice on June 2, 2011 unless comments are received which result in a contrary determination.
You may submit comments, identified by docket number and/Regulatory Information Number (RIN) and title, by any of the following methods:
•
Follow the instructions for submitting comments.
•
Ms. Cindy Allard at (703) 588-6830, or Chief, OSD/JS Privacy Office, Freedom of Information Directorate, Washington Headquarters Services, 1155 Defense Pentagon, Washington, DC 20301-1155.
The Office of the Secretary of Defense notices for systems of records subject to the Privacy Act of 1974 (5 U.S.C. 552a), as amended, have been published in the
The proposed system report, as required by 5 U.S.C. 552a(r) of the Privacy Act of 1974, as amended, was submitted on April 26, 2011, to the House Committee on Oversight and Government Reform, the Senate Committee on Governmental Affairs, and the Office of Management and Budget (OMB) pursuant to paragraph 4c of Appendix I to OMB Circular No. A-130, “Federal Agency Responsibilities for Maintaining Records About Individuals,” dated February 8, 1996 (February 20, 1996, 61 FR 6427).
Joint Personnel Adjudication System (JPAS), (October 14, 2010, 75 FR 63161).
Delete entry and replace with “Records are destroyed no later than one (1) year after notification of death or not later than five (5) years after separation or transfer of employee or no later than five (5) years after contract relationship expires, whichever is applicable.”
Delete entry and replace with “Individuals seeking to determine whether information about themselves is contained in this system should address written inquiries to the Defense Manpower Data Center (DMDC) Boyers, ATTN: Privacy Act Office, P.O. Box 168, Boyers, PA 16020-0168.
Written requests must contain the full name (and any alias and/or alternate names used), SSN, and date and place of birth.”
Delete entry and replace with “Individuals seeking information about themselves contained in this system should address written inquiries to the Office of the Defense Manpower Data Center (DMDC) Boyers, ATTN: Privacy Act Office, P.O. Box 168, Boyers, PA 16020-0168.
Individuals should provide their full name (and any alias and/or alternate names used), SSN, and date and place of birth.
In addition, the requester must provide a notarized statement or an unsworn declaration made in accordance with 28 U.S.C. 1746, in the following format:
If executed without the United States: ‘I declare (or certify, verify, or state) under penalty of perjury under the laws of the United States of America that the foregoing is true and correct. Executed on (date). (Signature).’
If executed within the United States, its territories, possessions, or commonwealths: ‘I declare (or certify, verify, or state) under penalty of perjury that the foregoing is true and correct. Executed on (date). (Signature).’
Attorneys or other persons acting on behalf of an individual must provide written authorization from that individual for their representative to act on their behalf.
Because JPAS is a “joint” DoD system, it may be necessary to refer specific data to the DoD Component where it originated for a release determination.”
Joint Personnel Adjudication System (JPAS).
Defense Manpower Data Center, DoD Center Monterey Bay, 400 Gigling Road, Seaside, CA 93955-6771.
All Department of Defense active and reserve military personnel; civilian employees and applicants; DoD contractor employees and applicants; National Guard personnel; U.S. Coast Guard military and civilian personnel and applicants requiring access to National Security and/or Sensitive Compartmented Information; “affiliated” personnel (such as Non-Appropriated Fund employees, Red Cross volunteers and staff; USO personnel, and congressional staff members); and foreign nationals whose duties require access to National Security Information (NSI) and/or assignment to a sensitive position.
Complete investigation packages and documenting records conducted by Federal investigative organizations (e.g., U.S. Office of Personnel Management (OPM), Central Intelligence Agency, NASA, etc.) and locator references to such investigations. Records documenting the personnel security adjudicative and management process, to include an individual's Social Security Number (SSN); name (both, current, former and alternate names); date of birth; place of birth; country of citizenship; type of DoD affiliation; employing activity; current employment status; position sensitivity; personnel security investigative basis; status of current adjudicative action; security clearance eligibility and access status; whether eligibility determination was based on a condition, deviation from prescribed investigative standards or waiver of adjudication guidelines; reports of security-related incidents, to include issue files; suspension of eligibility and/or access; denial or revocation of eligibility and/or access; eligibility recommendations or decisions made by an appellate authority; non-disclosure execution dates; indoctrination date(s); level(s) of access granted; debriefing date(s); and reasons for debriefing.
50 U.S.C. 401, Congressional declaration of purpose; 50 U.S.C. 435, Purposes; DoD 5200.2R, Department of Defense Personnel Security Program Regulation; DoD 5105.21-M-1, Sensitive Compartment Information Administrative Security Manual; E.O. 10450, Security Requirements for Government Employment; E.O. 10865, Safeguarding Classified Information Within Industry; E.O. 12333, United States Intelligence Activities; E.O. 12829, National Industrial Security Program; and E.O. 12968, Access to Classified Information; and E.O. 9397 (SSN), as amended.
The Joint Personnel Adjudication System (JPAS) is an enterprise automated system for personnel security management, providing a common, comprehensive medium to record and document personnel security actions within the Department, including granting interim clearances and submitting investigations. Decentralized access is authorized at the nine central adjudication facilities and DoD Component security offices. JPAS also compiles statistical data for use in analyses and studies.
In addition to disclosures generally permitted under 5 U.S.C. 552a(b) of the Privacy Act of 1974, these records may specifically be disclosed outside the DoD as follows to:
To the White House to obtain approval of the President of the United States regarding certain military personnel office actions as provided for in DoD Instruction 1320.4, Military Officer Actions Requiring Approval of the Secretary of Defense or the President, or Confirmation by the Senate.
To the U.S. Citizenship and Immigration Services for use in alien admission and naturalization inquiries.
To the Office of the Director of National Intelligence, the Federal Bureau of Investigation; the National Aeronautics and Space Administration; the Central Intelligence Agency; the Office of Personnel Management; the Department of State, the Department of Treasury; the Internal Revenue Service; the U.S. Postal Service; the U.S. Secret Service; the Bureau of Alcohol, Tobacco, Firearms and Explosives; the U.S. Customs and Border Protection; Department of Homeland Security; any other related Federal agencies for the purpose of determining access to National Security Information (NSI) pursuant to E.O. 12968, Access to Classified Information.
To authorized industry users for the purpose of verifying eligibility and determining access to National Security Information (NSI) of their employees.
The DoD ‘Blanket Routine Uses’ set forth at the beginning of the Office of the Secretary of Defense (OSD) compilation of systems of records notices also apply to this system.
Electronic storage media.
Information is retrieved by full name, SSN, date of birth, state and/or country of birth.
Electronically and optically stored records are maintained in “fail-safe” system software with password-protected access. Records are accessible only to authorized persons with a valid need-to-know, who are appropriately screened, investigated and determined eligible for access. During non-duty hours, alarms systems and/or security or military police guards secure all locations. Only authorized personnel with a valid need-to-know are allowed access to JPAS. Additionally, access to JPAS is based on a user's specific functions, security eligibility and access level.
Records are destroyed no later than one (1) year after notification of death or not later than five (5) years after separation or transfer of employee or no later than five (5) years after contract relationship expires, whichever is applicable.
Director, Defense Manpower Data Center, 1600 Wilson Boulevard, Suite 400, Arlington VA 22209-2593.
Deputy Director, Defense Manpower Data Center, DoD Center Monterey Bay, 400 Gigling Road, Seaside, CA 93955-6771.
Individuals seeking to determine whether information about themselves is contained in this system should address written inquiries to the Defense Manpower Data Center (DMDC) Boyers, ATTN: Privacy Act Office, P.O. Box 168, Boyers, PA 16020-0168.
Written requests must contain the full name (and any alias and/or alternate names used), SSN, and date and place of birth.
Individuals seeking information about themselves contained in this system should address written inquiries to the Office of the Defense Manpower Data Center (DMDC) Boyers, ATTN: Privacy Act Office, P.O. Box 168, Boyers, PA 16020-0168.
Individuals should provide their full name (and any alias and/or alternate
In addition, the requester must provide a notarized statement or an unsworn declaration made in accordance with 28 U.S.C. 1746, in the following format:
If executed without the United States: ‘I declare (or certify, verify, or state) under penalty of perjury under the laws of the United States of America that the foregoing is true and correct. Executed on (date). (Signature).’
If executed within the United States, its territories, possessions, or commonwealths: ‘I declare (or certify, verify, or state) under penalty of perjury that the foregoing is true and correct. Executed on (date). (Signature).’
Attorneys or other persons acting on behalf of an individual must provide written authorization from that individual for their representative to act on their behalf.
Because JPAS is a “joint” DoD system, it may be necessary to refer specific data to the DoD Component where it originated for a release determination.
The OSD rules for accessing records, and for contesting or appealing agency determinations are published in OSD Administrative Instruction 81, 32 CFR part 311; or may be obtained directly from the system manager.
Information contained in this system is derived from the appropriate DoD personnel systems; Consolidated Adjudication Tracking System (CATS); records maintained by the DoD adjudicative agencies; and records maintained by security managers, special security officers, or other officials requesting and/or sponsoring the security eligibility determination for the individual. Additional information may be obtained from other sources (such as personnel security investigations, personal financial records, military service records, medical records and unsolicited sources).
Investigatory material compiled solely for the purpose of determining suitability, eligibility, or qualifications for federal civilian employment, military service, federal contracts, or access to classified information may be exempt pursuant to 5 U.S.C. 552a(k)(5), but only to the extent that such material would reveal the identity of a confidential source.
An exemption rule for this system has been promulgated in accordance with requirements of 5 U.S.C. 553(b)(1), (2), and (3), (c) and (e) and published in 32 CFR part 311. For additional information contact the system manager.
Department of the Army, DoD.
Notice to alter a system of records.
Department of the Army is altering a system of records notices in its existing inventory of record systems subject to the Privacy Act of 1974, (5 U.S.C. 552a), as amended.
This proposed action will be effective without further notice on June 2, 2011 unless comments are received which result in a contrary determination.
You may submit comments, identified by docket number and/Regulatory Information Number (RIN) and title, by any of the following methods:
•
•
Mr. Leroy Jones at (703) 428-6185, or Department of the Army, Privacy Office, U.S. Army Records Management and Declassification Agency, 7701 Telegraph Road, Casey Building, Suite 144, Alexandria, VA 22325-3905.
Department of the Army notices for systems of records subject to the Privacy Act of 1974 (5 U.S.C. 552a), as amended, have been published in the Federal Register and are available from the
The proposed system report, as required by 5 U.S.C. 552a(r) of the Privacy Act of 1974, as amended, was submitted on April 26, 2011 to the House Committee on Government Reform, the Senate Committee on Homeland Security and Governmental Affairs, and the Office of Management and Budget (OMB) pursuant to paragraph 4c of Appendix I to OMB Circular No. A-130, “Federal Agency Responsibilities for Maintaining Records About Individuals,” February 20, 1996, 61 FR 6427.
Defense Casualty Information Processing System (DCIPS)(April 25, 2005, 70 FR 21183).
Delete entry and replace with “Civilian Information: Individual's name, Social Security Number (SSN), date of birth, sex, race, religion, citizenship, DNA tracking information, employment information, financial information, mailing/home address, marital status, medical information, mother's maiden name, mother's middle name, other names used, personal cell telephone number, personal e-mail address, place of birth.
Contact Information: Home of record, and other pertinent information, emergency contact, home contact and address information, home telephone number.
Military Information: Branch of service, organization, duty, Army rank and military occupational specialty (MOS), Air Force Specialty Code (AFSC) and rank, (Navy rank and rate, Marine Corp rank and specialty code, personnel records, inquiries from other agencies and individuals, disability information, internal system ID number.
Casualty Information: DD Form 1300 (Report of Casualty); biometrics; casualty information (cause, circumstances, injuries observed post mortem, injury/illness description, location of death, status, and treatment facility); cemetery contact and address information, funeral, genealogy information.
Beneficiary Information: Correspondence with primary next of
Law Enforcement Information: Incarcerated next-of-kin, legal status.”
Delete entry and replace with “10 U.S.C. 3013, Secretary of the Army, 10 U.S.C. 5013, Secretary of the Navy, 10 U.S.C. 5043, Commandant of the Marine Corps, 10 U.S.C. 8013, Secretary of the Air Force; 44 U.S.C. 3101, Records Management by Federal Agencies; DoDD 1300.15, Military Funeral Support; DoDD 1300.22, Mortuary Affairs Policy; DoDI 1300.18, Personnel Casualty Matters, Policies, and Procedures; Office of the Assistant Secretary of Defense Memorandum, Subject: Defense Casualty Information Processing System, dated Oct 22, 1999; and E.O. 9397 (SSN), as amended.”
Delete entry and replace with “In addition to those disclosures generally permitted under Title 5 U.S.C. 552a(b) of the Privacy Act of 1974, these records contained therein may specifically be disclosed outside the DoD as a routine use pursuant to 5 U.S.C. 552a(b)(3) as follows:
Information from these records may be disclosed to the Department of Veterans Affairs, and other Federal agencies in connection with eligibility, notification and assistance in obtaining benefits due.
If deceased has no spouse, children, representative of minor children, or an executor or personal representative named in the deceased's will, then information from these records may be released to the primary next of kin (PNOK) family member(s) of the injured or deceased DoD personnel to aid in the settlement of the member's estate.
The DoD `Blanket Routine Uses' set forth at the beginning of the Army's compilation of systems of records notices also apply to this system.
This system of records contains individually identifiable health information. The DoD Health Information Privacy Regulation (DoD 6025.18-R) issued pursuant to the Health Insurance Portability and Accountability Act of 1996, applies to most such health information. DoD 6025.18-R may place additional procedural requirements on the uses and disclosures of such information beyond those found in the Privacy Act of 1974 or mentioned in this system of records notice.”
Delete entry and replace with “By individual's name and/or Social Security Number (SSN) or last four of SSN if spouse.”
Delete entry and replace with “Offices having Army-wide responsibility: Records are permanent. Keep in current file area until no longer needed for conducting business, then retire to Records Holding Area (RHA)/Army Electronic Archive (AEA). The RHA/AEA will transfer to the National Archives when 25 years old.
Offices other than having Army-wide responsibility: Keep in current file area until record is 2 years old, and then destroy.”
Delete entry and replace with “Office of the Under Secretary of Defense, Personnel and Readiness, Military Severely Injured Joint Support Operations Center, 2107 Wilson Blvd., Arlington, VA 22201-3058.
Commander, U.S. Army Human Resources Command, 1600 Spearhead Division Avenue, Fort Knox, KY 40122-5001.
Commander, Headquarters Air Force Personnel Center, 550 C Street W, Randolph Air Force Base, TX 78150-4703.
Commander, Navy Personnel Command, 5720 Integrity Drive, Millington, TN 38055-3130.
Commandant of the Marine Corps Headquarters, U.S. Marine Corps, 3280 Russell Road, Quantico, VA 22134-5101.”
Delete entry and replace with “Individuals seeking to determine if information about themselves is contained in this system of records should address written inquiries to the appropriate system manager.
For verification purposes, individual should provide their full name, Social Security Number (SSN), last four only if spouse, any details which may assist in locating records, and their signature.
In addition, the requester must provide a notarized statement or an unsworn declaration made in accordance with 28 U.S.C. 1746, in the following format:
If executed outside the United States: `I declare (or certify, verify, or state) under penalty of perjury under the laws of the United States of America that the foregoing is true and correct. Executed on (date). (Signature)'.
If executed within the United States, its territories, possessions, or commonwealths: `I declare (or certify, verify, or state) under penalty of perjury that the foregoing is true and correct. Executed on (date). (Signature)'.”
Delete entry and replace with “Individuals seeking to determine if information about themselves is contained in this record system should address written inquiries to the appropriate system manager.
For verification purposes, individual should provide their full name, Social Security Number (SSN), last four only if spouse, any details which may assist in locating records, and their signature.
In addition, the requester must provide a notarized statement or an unsworn declaration made in accordance with 28 U.S.C. 1746, in the following format:
If executed outside the United States: `I declare (or certify, verify, or state) under penalty of perjury under the laws of the United States of America that the foregoing is true and correct. Executed on (date). (Signature)'.
If executed within the United States, its territories, possessions, or commonwealths: `I declare (or certify, verify, or state) under penalty of perjury that the foregoing is true and correct. Executed on (date). (Signature)'.”
Defense Casualty Information Processing System (DCIPS).
Office of the Under Secretary of Defense, Personnel and Readiness, Military Severely Injured Joint Support Operations Center, 2107 Wilson Blvd., Arlington, VA 22201-3058.
Commander, U.S. Army Human Resources Command, 1600 Spearhead Division Avenue, Fort Knox, KY 40122-5001.
Commander, Headquarters Air Force Personnel Center, 550 C Street W, Randolph Air Force Base, TX 78150-4703.
Commander, Navy Personnel Command, 5720 Integrity Drive, Millington, TN 38055-3130.
Commandant of the Marine Corps Headquarters, U.S. Marine Corps, 3280 Russell Road, Quantico, VA 22134-5101.
Department of Defense military personnel (active component and reserve component) and their family members; DoD civilian personnel, retired service members, non-DoD civilians, and other individuals that are reported as casualties.
Civilian Information: Individual's name, Social Security Number (SSN), date of birth, sex, race, religion, citizenship, DNA tracking information, employment information, financial information, mailing/home address, marital status, medical information, mother's maiden name, mother's middle name, other names used, personal cell telephone number, personal e-mail address, place of birth.
Contact Information: Home of record, and other pertinent information, emergency contact, home contact and address information, home telephone number.
Military Information: Branch of service, organization, duty, Army rank and military occupational specialty (MOS), Air Force
Specialty Code (AFSC) and rank, (Navy rank and rate, Marine Corp rank and specialty code, personnel records, inquiries from other agencies and individuals, disability information, internal system ID number.
Casualty Information: DD Form 1300 (Report of Casualty); biometrics; casualty information (cause, circumstances, injuries observed post mortem, injury/illness description, location of death, status, and treatment facility); cemetery contact and address information, funeral, genealogy information.
Beneficiary Information: Correspondence with primary next of kin/secondary next of kin, child information, Dependency and Indemnity Compensation beneficiary information, Servicemen's Group Life Insurance (SGLI) beneficiary information, spouse's truncated Social Security Number (SSN).
Law Enforcement Information: Incarcerated next-of-kin, legal status.
10 U.S.C. 3013, Secretary of the Army, 10 U.S.C. 5013, Secretary of the Navy, 10 U.S.C. 5043, Commandant of the Marine Corps, 10 U.S.C. 8013, Secretary of the Air Force; 44 U.S.C. 3101, Records Management by Federal Agencies; DoDD 1300.15, Military Funeral Support; DoDD 1300.22, Mortuary Affairs Policy; DoDI 1300.18, Personnel Casualty Matters, Policies, and Procedures; Office of the Assistant Secretary of Defense Memorandum, Subject: Defense Casualty Information Processing System, dated Oct 22, 1999; and E.O. 9397 (SSN), as amended.
To provide DoD with a single joint military casualty information processing system; to provide support for the management of casualty and mortuary affairs by the Services Casualty and Mortuary Affairs Offices; to respond to inquiries; to provide statistical data comprising type, number, place and cause of incident to DoD Services' members; and to support the families of service members.
In addition to those disclosures generally permitted under Title 5 US Code Section 552a(b) of the Privacy Act of 1974, these records contained therein may specifically be disclosed outside the DoD as a routine use pursuant to Title 5 US Code Section 552a(b)(3) as follows:
Information from these records may be disclosed to the Department of Veterans Affairs, and other Federal agencies in connection with eligibility, notification and assistance in obtaining benefits due.
If deceased has no spouse, children, representative of minor children, or an executor or personal representative named in the deceased's will, then information from these records may be released to the primary next of kin (PNOK) family member(s) of the injured or deceased DoD personnel to aid in the settlement of the member's estate.
The DoD `Blanket Routine Uses' set forth at the beginning of the Army's compilation of systems of records notices also apply to this system.
This system of records contains individually identifiable health information. The DoD Health Information Privacy Regulation (DoD 6025.18-R) issued pursuant to the Health Insurance Portability and Accountability Act of 1996, applies to most such health information. DoD 6025.18-R may place additional procedural requirements on the uses and disclosures of such information beyond those found in the Privacy Act of 1974 or mentioned in this system of records notice.
Paper records in file folders and on electronic storage media.
By individual's name and/or Social Security Number (SSN) or last four of SSN if spouse.
Buildings and/or rooms employ alarms, security guards, and are security-controlled areas accessible only to authorized persons. Hard copy records are maintained in General Service Administration approved security containers, and records in the U.S. Army Investigative Records Repository are stored in security-controlled areas accessible only to authorized persons. Electronically and optically stored records are maintained in ‘fail-safe’ system software with password-protected access. Records are accessible only to authorized persons with a need-to-know who are properly screened, cleared, and trained.
Offices having Army-wide responsibility: Records are permanent. Keep in current file area until no longer needed for conducting business, then retire to Records Holding Area (RHA)/Army Electronic Archive (AEA). Transfer a snap shot of the DCIPS Master File to AEA annually at the end of the fiscal year. The AEA will transfer a snap shot of DCIPS to the National Archives and Records Administration (NARA) one year after the signature by the Archivist of the United States. Thereafter, the AEA will transfer a snap shot of DCIPS to NARA every two years. Legal custody of each snap shot will transfer to NARA when the record is 25 years old.
Offices other than having Army-wide responsibility: Keep in current file area until record is 2 years old, and then destroy.
Office of the Under Secretary of Defense, Personnel and Readiness, Military Severely Injured Joint Support Operations Center, 2107 Wilson Blvd., Arlington, VA 22201-3058.
Commander, U.S. Army Human Resources Command, 1600 Spearhead Division Avenue, Fort Knox, KY 40122-5001.
Commander, Headquarters Air Force Personnel Center, 550 C Street W, Randolph Air Force Base, TX 78150-4703.
Commander, Navy Personnel Command, 5720 Integrity Drive, Millington, TN 38055-3130.
Commandant of the Marine Corps Headquarters, U.S. Marine Corps, 3280 Russell Road, Quantico, VA 22134-5101.
Individuals seeking to determine if information about themselves is contained in this record system should address written inquiries to the appropriate system manager.
For verification purposes, individual should provide their full name, Social Security Number (SSN), last four only if spouse, any details which may assist in locating records, and their signature.
In addition, the requester must provide a notarized statement or an unsworn declaration made in accordance with 28 U.S.C. 1746, in the following format:
If executed outside the United States:
‘I declare (or certify, verify, or state) under penalty of perjury under the laws of the United States of America that the foregoing is true and correct. Executed on (date). (Signature)’.
If executed within the United States, its territories, possessions, or commonwealths: `I declare (or certify, verify, or state) under penalty of perjury that the foregoing is true and correct. Executed on (date). (Signature)'.
Individuals seeking to determine if information about themselves is contained in this record system should address written inquiries to the appropriate system manager.
For verification purposes, individual should provide their full name, Social Security Number (SSN), last four only if spouse, any details which may assist in locating records, and their signature.
In addition, the requester must provide a notarized statement or an unsworn declaration made in accordance with 28 U.S.C. 1746, in the following format:
If executed outside the United States: ‘I declare (or certify, verify, or state) under penalty of perjury under the laws of the United States of America that the foregoing is true and correct. Executed on (date). (Signature)’.
If executed within the United States, its territories, possessions, or commonwealths: ‘I declare (or certify, verify, or state) under penalty of perjury that the foregoing is true and correct. Executed on (date). (Signature)’.
The Army's rules for accessing records, and for contesting contents and appealing initial agency determinations are contained in Army Regulation 340-21; 32 CFR part 505; or may be obtained from the system manager.
From casualty reports and investigations received from commander, medical personnel, medical examiners, and other related official sources.
None.
Department of the Navy, DoD.
Notice.
A notice of availability was published in the
Ms. Christine Stevenson, EHW-2 EIS Project Manager, 1101 Tautog Circle, Silverdale, Washington 98315-1101; or
This notice announces a fifteen-day extension of the public comment period until May 17, 2011.
Comments may be submitted in writing to Naval Facilities Engineering Command Northwest,
Department of Education.
Comment Request.
The Director, Information Collection Clearance Division, Privacy, Information and Records Management Services, Office of Management, invites comments on the submission for OMB review as required by the Paperwork Reduction Act of 1995 (Pub. L. 104-13).
Interested persons are invited to submit comments on or before [insert the 30th day after publication of this notice].
Written comments should be addressed to the Office of Information and Regulatory Affairs,
Section 3506 of the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35) requires that the Office of Management and Budget (OMB) provide interested Federal agencies and the public an early opportunity to comment on information collection requests. The OMB is particularly interested in comments which: (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
Copies of the information collection submission for OMB review may be accessed from the RegInfo.gov Web site at
Individuals who use a telecommunications device for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339.
Department of Education, National Assessment Governing Board.
Notice of Open Meeting and Partially Closed Sessions.
The notice sets forth the schedule and proposed agenda of a forthcoming meeting of the National Assessment Governing Board. This notice also describes the functions of the Board. Notice of this meeting is required under Section 10(a)(2) of the Federal Advisory Committee Act. This document is intended to notify members of the general public of their opportunity to attend. Individuals who will need special accommodations in order to attend the meeting (e.g.: Interpreting services, assistive listening devices, materials in alternative format) should notify Munira Mwalimu at 202-357-6938 or at
May 12-14, 2011
Ad Hoc Committee: Open Session: 9:30 a.m.-11 a.m.
Assessment Development Committee: Closed Session: 11:30 a.m.-4:15 p.m.
Executive Committee: Open Session: 4:30 p.m.-5:15 p.m.; Closed Session: 5:15 p.m.-6 p.m.
Open Session: 8:30 a.m.-9:45 a.m.; Closed Session: 12:45 p.m.-1:30 p.m.; Open Session: 1:45 p.m.-4:30 p.m.
Assessment Development Committee: Open Session: 10 a.m.-12:30 p.m.
Committee on Standards, Design and Methodology: Open Session: 10 a.m.-12:30 p.m.
Reporting and Dissemination Committee: Open Session: 10 a.m.-12:30 p.m.
Nominations Committee: Closed Session: 8 a.m.-8:45 a.m.
Full Board: Open Session: 9 a.m.-10 a.m.
Munira Mwalimu, Operations Officer, National Assessment Governing Board, 800 North Capitol Street, NW., Suite 825, Washington, DC 20002-4233,
The National Assessment Governing Board is established under section 412 of the National Education Statistics Act of 1994, as amended.
The Board is established to formulate policy guidelines for the National Assessment of Educational Progress (NAEP). The Board's responsibilities include the following: Selecting subject areas to be assessed, developing assessment frameworks and specifications, developing appropriate student achievement levels for each grade and subject tested, developing standards and procedures for interstate and national comparisons, developing
On May 12, from 9:30 a.m. to 11 a.m., the Ad Hoc Committee on Parent Engagement will meet in open session. Thereafter, from 11:30 a.m. to 4:15 p.m., the Assessment Development Committee will meet in closed session to review secure test items at the eighth grade for the Technological and Engineering Literacy (TEL) pilot assessment in 2013. The Board will be provided with specific test materials/questions for review that cannot be discussed/disclosed in an open meeting. Premature disclosure of these secure test materials would significantly impede implementation of the NAEP assessments, and is therefore protected by exemption 9(B) of section 552b(c) of Title 5 U.S.C.
On May 12, from 4:30 p.m. to 5:15 p.m., the Executive Committee will meet in open session and thereafter in closed session from 5:15 p.m. to 6 p.m. During the closed session on May 12, the Executive Committee will receive a briefing from the National Center for Education Statistics (NCES) on options for NAEP contracts covering assessment years beyond 2011 and discuss budget implications for the NAEP assessment schedule and for international linking studies. The discussion of contract options and costs will address the congressionally mandated goals and Board policies on NAEP assessments. This part of the meeting must be conducted in closed session because public discussion of this information would disclose independent government cost estimates and contracting options, adversely impacting the confidentiality of the contracting process. Public disclosure of information discussed would significantly impede implementation of the NAEP contracts, and is therefore protected by exemption 9(B) of section 552b(c) of Title 5 U.S.C.
On May 13, the full Board will meet in open session from 8:30 a.m. to 9:45 a.m. The Board will review and approve the meeting agenda and meeting minutes from the March 2011 Board meeting, followed by an oath of office for a newly appointed Board member, and the Chairman's remarks. Thereafter, Portland Board member W. James Popham and Oregon education leaders are scheduled to make welcome remarks and address the Board. The Executive Director of the Governing Board will then provide a report to the Board, followed by updates from the Commissioner of the National Center for Education Statistics and the Director of the Institute of Education Sciences. The Board will recess for Committee meetings on May 13 from 10 a.m. to 12:30 p. m.
The Governing Board's standing committees, the Assessment Development Committee, the Reporting and Dissemination Committee and the Committee on Standards, Design and Methodology will meet in open session on May 13 from 10 a.m. to 12 p.m.
On May 13, from 12:45 p.m. to 1:30 p.m. the full Board will meet in closed session to receive a briefing on the 2010 NAEP U.S. History Report Card. The Board will be provided with results of the assessments that cannot be discussed in an open meeting prior to their official release. Premature disclosure of test results would significantly impede implementation of the NAEP assessment, and is therefore protected by exemption 9(B) of section 552b(c) of Title 5 U.S.C.
From 1:45 p.m. to 2:30 p.m. the Board will meet in open session to receive a briefing and discuss the NAEP Five Largest States Report for 2009 (Mega States). Following this session, from 2:30 p.m. to 3:15 p.m., the Board will discuss ways of improving student achievement and closing achievement gaps. From 3:30 p.m. to 4:30 p.m., the Board will receive a briefing on Oregon's Assessment System from Tony Alpert, the Director of Assessment and Accountability from the Oregon Department of Education.
The May 13, 2010 session of the Board meeting is scheduled to conclude at 4:30 p.m.
On May 14, the Nominations Committee will meet in closed session from 8 a.m. to 8:45 a.m. to review specific names for Board vacancies, and the status of nominees for Board membership for terms beginning October 1, 2011. These discussions pertain solely to internal personnel rules and practices of an agency and will disclose information of a personal nature where disclosure would constitute an unwarranted invasion of personal privacy. As such, the discussions are protected by exemptions 2 and 6 of section 552b(c) of Title 5 U.S.C.
On May 14, the full Board will meet in open session to receive Committee reports and take action on Committee recommendations. The May 14, 2010 session of the Board meeting is scheduled to adjourn at 10 a.m.
Detailed minutes of the meeting, including summaries of the activities of the closed sessions and related matters that are informative to the public and consistent with the policy of section 5 U.S.C. 552b(c) will be available to the public within 14 days of the meeting. Records are kept of all Board proceedings and are available for public inspection at the U.S. Department of Education, National Assessment Governing Board, Suite #825, 800 North Capitol Street, NW., Washington, DC, from 9 a.m. to 5 p.m. Eastern Time, Monday through Friday.
The official version of this document is the document published in the
U.S. Department of Education.
Notice of a Closed Meeting.
This notice sets forth the schedule and proposed agenda of an upcoming closed meeting of the National Advisory Council on Indian Education (the Council) and is intended to notify the general public of the meeting. This notice also describes the functions of the Council. Notice of the Council's meetings is required under Section 10(a)(2) of the Federal Advisory Committee Act.
Location: The closed meeting will be conducted via conference call with NACIE members.
The National Advisory Council on Indian Education is authorized by Section 7141 of the Elementary and Secondary Education Act. The Council is established within the Department of
One of the Council's responsibilities is to develop and provide recommendations to the Secretary of Education on the funding and administration (including the development of regulations, and administrative policies and practices) of any program over which the Secretary has jurisdiction that can benefit Indian children or adults participating in any program which could benefit Indian children. The purpose of this closed meeting is to convene the Council to review, advise, and provide recommendations to the Secretary on the procurement of services to accomplish this responsibility. Council members will discuss contract options and costs during the closed meeting. The meeting must be conducted in closed session because public discussion of procurement information would disclose independent government cost estimates and contracting options, adversely impacting the confidentiality of the contracting process and is therefore protected by exemption 9(B) of section 552b(c) of Title 5 U.S.C.
Jenelle Leonard, Acting Director/Designated Federal Official, Office of Indian Education, U.S. Department of Education, 400 Maryland Avenue, SW., Washington, DC 20202.
A report of the activities of the closed session and related matters that are informative to the public and consistent with the policy of section 5 U.S.C. 552b(c) will be available to the public within 21 days of the meeting. Records are kept of all Council proceedings and are available for public inspection at the at the Office of Indian Education, United States Department of Education, 400 Maryland Avenue, SW., Washington, DC 20202. Monday-Friday, 8:30 a.m.-5 p.m. Eastern Daylight Time.
To use PDF you must have Adobe Acrobat Reader, which is available free at this site. If you have questions about using PDF, call the U.S. Government Printing Office (GPO), toll free at 1-866-512-1830; or in the Washington, DC, area at (202) 512-0000.
The official version of this document is the document published in the
Department of Energy.
Notice of change in the acceptance of Title X claims during fiscal year (FY) 2011.
This Notice announces changes in the Department of Energy (DOE) acceptance of claims in FY 2011 from eligible active uranium and thorium processing site licensees for reimbursement under Title X of the Energy Policy Act of 1992.
In our
Contact David Mathes at (301) 903-7222 of the U.S. Department of Energy, Office of Environmental Management, Office of Disposal Operations.
DOE published a final rule under 10 CFR Part 765 in the
Section 1001-1004 of Public Law 102-486, 106 Stat. 2776 (42 U.S.C. 2296a
Environmental Protection Agency (EPA).
Notice of Decision.
EPA today, pursuant to section 209(e) of the Clean Air Act (Act), 42 U.S.C. 7543(e), is granting California its request for authorization to enforce its emission standards and other requirements for its second tier (“Tier II”) of emission standards for new marine inboard/sterndrive spark ignition engines.
Petitions for review must be filed by July 5, 2011.
The Agency's Decision Document, containing an explanation of the Assistant Administrator's decision, as well as all documents relied upon in making that decision, including those submitted to EPA by California, are available for public inspection in EPA's Air and Radiation Docket and Information Center (Air Docket). Materials relevant to this decision are contained in Docket OAR-2004-0403 at the following location: EPA Air Docket, Room 3334, 1301 Constitution Avenue, NW., Washington, DC 20460. The EPA Docket Center Public Reading Room is open from 8 a.m. to 4:30 p.m. Monday through Friday, except on government holidays. The Air Docket telephone number is (202) 566-1742, and the facsimile number is (202) 566-1741. You may be charged a reasonable fee for photocopying docket materials, as provided in 40 CFR part 2.
Additionally, an electronic version of the public docket is available through the Federal government's electronic public docket and comment system. You may access EPA dockets at
EPA makes available an electronic copy of this Notice via the Internet on the Office of Transportation and Air Quality (OTAQ) homepage (
EPA's Office of Transportation and Air Quality also maintains a Web page that contains general information on its review of California waiver and authorization requests. Included on that page are links to several of the prior waiver
Robert M. Doyle, Attorney-Advisor, Office of Transportation and Air Quality, (6405J), U.S. Environmental Protection Agency, 1200 Pennsylvania Avenue, NW., Washington, DC 20460 (U.S. mail), 1310 L Street, NW., Washington, DC 20005 (courier mail).
Section 209(e)(1) of the Act addresses the permanent preemption of 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.
No State or any political subdivision thereof shall adopt or attempt to enforce any standard or other requirement relating to the control of emissions from either of the following new nonroad engines or nonroad vehicles subject to regulation under this Act—
(A) New engines which are used in construction equipment or vehicles or used in farm equipment or vehicles and which are smaller than 175 horsepower.
(B) New locomotives or new engines used in locomotives. Subsection (b) shall not apply for purposes of this paragraph.
(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 the 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 of California is arbitrary and capricious;
(2) California does not need such standards to meet compelling and extraordinary conditions; or
(3) The California standards and accompanying enforcement procedures are not consistent with section 209 of the Act.
As stated in the preamble to the section 209(e) rule, EPA has interpreted the requirement regarding whether “California standards and accompanying enforcement procedures are not consistent with section 209” to require that California standards and accompanying enforcement procedures must in particular be consistent with section 209(a), section 209(e)(1), and section 209(b)(1)(C), as EPA has interpreted that subsection in the context of motor vehicle waivers.
(a) States are preempted from adopting or enforcing standards or other requirements relating to the control of emissions from new engines smaller than 175 horsepower that are primarily used in farm or construction equipment or vehicles, as defined in this part. For equipment that is used in applications in addition to farming or construction activities, if the equipment is primarily used as farm and/or construction equipment or vehicles (as defined in this part), it is considered farm or construction equipment or vehicles.
§ 1074.12 provides in applicable part:
States and localities are preempted from adopting or enforcing standards or other requirements relating to the control of emissions from new locomotives and new engines used in locomotives.
§ 1074.5 provides definitions of terms used in § 1074.0 and sates in applicable part:
Finally, because California's nonroad standards and enforcement procedures must be consistent with section 209(b)(1)(C), EPA will review nonroad authorization requests under the same “consistency” criteria that are applied to motor vehicle waiver requests. Under section 209(b)(1)(C), the Administrator shall not grant California a motor vehicle waiver if she finds that California's “standards and accompanying enforcement procedures are not consistent with section 202(a)” of the Act. Previous decisions granting waivers of Federal preemption for motor vehicles have stated that State standards are inconsistent with section 202(a) if there is inadequate lead time to permit the development of the necessary technology giving appropriate consideration to the cost of compliance within that time period or if the Federal and State test procedures impose inconsistent certification requirements.
With regard to enforcement procedures accompanying standards, EPA must grant the requested authorization unless it finds that these procedures may cause the California standards, in the aggregate, to be less protective of public health and welfare than the applicable Federal standards promulgated pursuant to section 213(a), or unless the Federal and California certification test procedures are inconsistent.
Once California has received an authorization for its standards and enforcement procedures for a certain group or class of nonroad equipment engines or vehicles, it may adopt other conditions precedent to the initial retail sale, titling or registration of these engines or vehicles without the necessity of receiving an additional authorization.
The California Air Resources Board (CARB) requested EPA's authorization of the IB/SD marine engine emission standards by letter dated March 2, 2004.
After our review of the information submitted by CARB in its requests, and the information presented to the Agency at the public hearing and in the comments received after the hearing, EPA granted authorization for the CARB emission regulations for marine spark-ignition outboard and personal watercraft (PWC) engines in their entirety. EPA also granted authorization for the first Tier of the CARB regulations covering (IB/SD) engines. For the Tier I standards (as well as for the outboard and personal watercraft engines), EPA determined that CARB had successfully shown that these standards were technologically feasible, and thus met the authorization criterion of consistency with section 202(a). Regarding the Tier II IB/SD emission standards, all parties who testified at the hearing and submitted comments after the hearing, with the exception of CARB and MECA, had expressed concern that CARB had not shown that the Tier II IB/SD standards were technologically feasible, because they believed CARB had not shown that catalysts needed for the marine IB/SD engines to comply with the CARB standards were safe and durable in saltwater operation. Accordingly, EPA deferred authorization of these standards until the conclusion of then ongoing joint testing (by CARB, EPA, the U.S. Coast Guard, and the industry), to evaluate the technological feasibility of both the CARB Tier II IB/SD standards and Federal IB/SD standards which, at that time, were expected to be proposed in 2007. These Federal standards were proposed in May 2007 and finalized in October 2008.
Shortly after the EPA IB/SD proposed standards were published, the NMMA wrote to EPA stating that “at this stage of catalyst development, there is little or no additional data to be obtained by completing the (joint test program). * * * NMMA agrees that EPA and CARB can cancel the saltwater test program.” Additionally, NMMA dropped its objection to the “waiver” of the CARB standards because “one manufacturer is already in production with catalysts, and the others will be
EPA, based on the record of this proceeding, cannot find that CARB's Marine Tier II IB/SD protectiveness determination was arbitrary and capricious, that CARB does not need its own standards to meet compelling and extraordinary conditions, or that the CARB standards are inconsistent with section 209 of the Act. Therefore, EPA grants authorization for CARB to enforce the second tier of its regulations for IB/SD engines which set a level of 5.0 g/kW-hr HC plus NO
My decision will affect not only persons in California but also persons outside the State who would need to comply with California's Marine Tier II IB/SD regulations to produce engines for introduction into commerce in California. For this reason, I hereby determine and find that this is a final action of national applicability.
Under 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 July 5, 2011. Under section 307(b)(2) of the Act, judicial review of this final action may not be obtained in subsequent enforcement proceedings.
As with past waiver and authorization 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.
The Congressional Review Act, 5 U.S.C. 801
Finally, the Administrator has delegated the authority to make determinations regarding authorizations under section 209(e) of the Act to the Assistant Administrator for Air and Radiation.
Environmental Protection Agency (EPA).
Initiation of Scoping.
Pursuant to the National Environmental Policy Act (NEPA) (42 U.S.C. 4321-4307h), the Council on Environmental Quality's NEPA regulations (40 CFR parts 1500-1508), and EPA's regulations for implementing NEPA (40 CFR part 6), EPA will prepare an Environmental Assessment (EA) to analyze the potential environmental impacts related to the reissuance of the National Pollutant Discharge Elimination System (NPDES) General Permit for Discharges from Construction Activities. The EA will evaluate the potential environmental impacts from the discharge of pollutants associated with stormwater runoff from construction activities greater than one acre, where EPA is the permitting authority. EPA will use the information in the EA to determine whether to prepare an Environmental Impact Statement (EIS).
This notice initiates the scoping process by inviting comments from Federal, State, and local agencies, Indian tribes, and the public to help identify the environmental issues and reasonable alternatives to be examined in the EA. The scoping process will inform the preparation of the EA, which will be made available for public comment.
Comments must be received by May 27, 2011.
You may submit scoping comments to the Docket ID No. EPA-HQ-OW-2010-0782 by any of the following methods:
•
•
•
•
Comments should be received within 30 days of the date of the publication of the Proposed Construction General Permit in the
Jessica Trice, NEPA Compliance Division, Office of Federal Activities, U.S. Environmental Protection Agency, 1200 Pennsylvania Avenue, NW., Mail Code: 2252A, Washington, DC 20460.
EPA is seeking public comment to determine the scope of environmental issues and
Since 1992, EPA has issued a series of NPDES Construction General Permits (CGP) that cover areas where EPA is the permitting authority. At present, EPA is the permitting authority in four states (Idaho, Massachusetts, New Hampshire, and New Mexico), the District of Columbia, Puerto Rico, all U.S. territories with the exception of the Virgin Islands, federal facilities in four states (Colorado, Delaware, Vermont, and Washington), most Indian lands and a few other specifically designated activities in specific states (e.g., oil and gas activities in Texas and Oklahoma). EPA's current CGP became effective on June 30, 2008 (
EPA is currently planning to analyze two alternatives in the EA: No Action, that is not issuing the CGP; and the proposed action, which is issuing the draft CGP implementing the technology-based Effluent Limitation Guidelines and New Source Performance Standards (C&D Rule). The C&D Rule was issued by EPA for the construction and development industry on December 1, 2009. These requirements include (1) non-numeric effluent limitations that apply to all permitted discharges from construction sites in order to minimize the discharge of pollutants, and (2) a numeric effluent limit that applies to sites over 10 acres. The EA will analyze the potential environmental impacts of both alternatives on threatened and endangered species, water quality, and historic properties.
Direct all PRA comments to Nicholas A. Fraser, Office of Management and Budget, via fax at 202-395-5167 or the Internet at
Written Paperwork Reduction Act (PRA) comments should be submitted on or before June 2, 2011. If you anticipate that you will be submitting PRA comments, but find it difficult to do so within the period of time allowed by this notice, you should advise the FCC contact listed below as soon as possible.
Direct all PRA comments to Nicholas A. Fraser, Office of Management and Budget, via fax at 202-395-5167 or the Internet at
Benish Shah, Office of Managing Director, (202) 418-7866.
The Commission is requesting OMB approval for a revision because on August 7, 2008, the FCC released a
The
All CMS providers are required to submit a CMAS election, including those that were not licensed at the time of the initial filing deadline with the FCC. In addition, any CMS provider choosing to withdraw its election must
The Commission will use the information collected to meet its statutory requirement under the WARN Act to accept licensees' election filings and to establish an effective CMAS that will provide the public with effective mobile alerts in a manner that imposes minimal regulatory burdens on affected entities.
As part of its continuing effort to reduce paperwork burden and as required by the Paperwork Reduction Act (PRA) of 1995 (44 U.S.C. 3501-3520), the Federal Communications Commission invites the general public and other Federal agencies to comment on the following information collection. Comments are requested concerning: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of the Commission, including whether the information shall have practical utility; (b) the accuracy of the Commission's burden estimate; (c) ways to enhance the quality, utility, and clarity of the information collected; (d) ways to minimize the burden of the collection of information on the respondents, including the use of automated collection techniques or other forms of information technology; and (e) ways to further reduce the information collection burden for small business concerns with fewer than 25 employees.
The FCC may not conduct or sponsor a collection of information unless it displays a currently valid OMB control number. No person shall be subject to any penalty for failing to comply with a collection of information subject to the Paperwork Reduction Act (PRA) that does not display a valid OMB control number.
Written Paperwork Reduction Act (PRA) comments should be submitted on or before June 2, 2011. If you anticipate that you will be submitting PRA comments, but find it difficult to do so within the period of time allowed by this notice, you should advise the FCC contact listed below as soon as possible.
Direct all PRA comments to Nicholas A. Fraser, Office of Management and Budget, via fax at 202-395-5167 or the Internet at
Judith B. Herman, Office of Managing Director, (202) 418-0214.
In an Order on Reconsideration (FCC 04-251), the Commission considered four petitions for reconsideration of the Commission's
(1) The Payphone Compensation Rules place liability to compensate PSPs for payphone-originated calls on the facilities-based long distance carriers from whose switches such calls are completed.
(2) The Payphone Compensation Rules define these responsible carriers as “completing carriers” and require them to develop their own system of tracking calls to completion, the accuracy of which must be confirmed and attested to by a third-party auditor.
(3) Completing carriers must file with PSPs a quarterly report and must also submit an attestation by the chief financial officer (CFO) that the payment amount for that quarter is accurate and is based on 100% of all completed calls.
(4) The rules also require reporting obligations for other facilities-based long distance carriers in the call path, if any, and define these carriers as “intermediate carriers”.
(5) Additionally, the rules give parties flexibility to agree to alternative compensation arrangements (ACA) so that small completing carriers may avoid the expense of instituting a tracking system and undergoing an audit.
(6) The Payphone Compensation Rules satisfy section 276 by identifying the party liable for compensation and establishing a mechanism for PSPs to be paid.
The information collected under the Completing Carrier filing of quarterly reports and Intermediate Carrier filing of quarterly reports must be provided to third parties. The information collected under the completing carrier establishment of call tracking system must be provided to third parties and submitted to the Commission. The information is collected annually under completing carrier establishment of call tracking system. Completing carrier
As part of its continuing effort to reduce paperwork burden and as required by the Paperwork Reduction Act (PRA) of 1995 (44 U.S.C. 3501-3520), the Federal Communications Commission invites the general public and other Federal agencies to comment on the following information collection. Comments are requested concerning: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of the Commission, including whether the information shall have practical utility; (b) the accuracy of the Commission's burden estimate; (c) ways to enhance the quality, utility, and clarity of the information collected; (d) ways to minimize the burden of the collection of information on the respondents, including the use of automated collection techniques or other forms of information technology; and (e) ways to further reduce the information collection burden for small business concerns with fewer than 25 employees.
The FCC may not conduct or sponsor a collection of information unless it displays a currently valid OMB control number. No person shall be subject to any penalty for failing to comply with a collection of information subject to the Paperwork Reduction Act (PRA) that does not display a valid OMB control number.
Written Paperwork Reduction Act (PRA) comments should be submitted on or before June 2, 2011. If you anticipate that you will be submitting PRA comments, but find it difficult to do so within the period of time allowed by this notice, you should advise the FCC contact listed below as soon as possible.
Direct all PRA comments to Nicholas A. Fraser, Office of Management and Budget, via fax at 202-395-5167 or the Internet at
Judith B. Herman, Office of Managing Director, (202) 418-0214.
In a Memorandum Opinion and Order in WC Docket No. 07-21 (FCC 08-120) the Commission forbore from many of its cost allocation rules as they apply to the former Bell Operating Companies (BOCs). Therefore, there are fewer respondents affected by the requirements of these rule sections.
Section 64.901 requires carriers to separate their regulated costs from nonregulated costs using the attributable cost method of cost allocation. Carriers must follow the principles described in section 64.901. Carriers subject to section 64.901 are also subject to the provisions of 47 CFR sections 32.23 and 32.27 of the Commission's rules.
Section 64.903(a) requires each local exchange carrier with annual operating revenues that equal or exceed the indexed revenue threshold, as defined in 47 CFR 32.9000, to file with the Commission a manual containing information regarding its allocation of costs between regulated and non-regulated activities.
Section 64.903(b) requires that carriers update their cost allocation manuals (CAMs) at least annually; except that changes to the cost apportionment table and the description of time reporting procedures must be filed at the time of implementation. Proposed changes in the description of time reporting procedures, the statement concerning affiliate transactions, and the cost apportionment table must be accompanied by a statement quantifying the impact of each change on regulated operations. Changes in the description of time reporting procedures and the statement concerning affiliate transactions must be quantified in $100,000 increments at the account level. Changes in the cost apportionment table must be quantified in $100,000 increments at the cost pool level.
Moreover, filing of CAMs and occasional updates are subject to the uniform format and standard procedures specified in Responsible Accounting Officer (RAO) Letter 19. RAO Letter 26 provides guidance to carriers in revising their CAMs to reflect changes to the affiliate transactions rules pursuant to the
The CAM is reviewed by the Commission to ensure that all costs are properly classified between regulated and nonregulated activity. Uniformity in the CAMs helps improve the joint cost allocation process. In addition, this uniformity gives the Commission greater reliability in financial data submitted by the carriers through the Automated Reporting Management Information System (ARMIS).
As part of its continuing effort to reduce paperwork burden and as required by the Paperwork Reduction Act (PRA) of 1995 (44 U.S.C. 3501-3520), the Federal Communications Commission invites the general public and other Federal agencies to take this opportunity to comment on the following information collection(s). Comments are requested concerning: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of the Commission, including whether the information shall have practical utility; (b) the accuracy of the Commission's burden estimate; (c) ways to enhance the quality, utility, and clarity of the information collected; (d) ways to minimize the burden of the collection of information on the respondents, including the use of automated collection techniques or other forms of information technology; and (e) ways to further reduce the information burden for small business concerns with fewer than 25 employees.
The FCC may not conduct or sponsor a collection of information unless it displays a currently valid OMB control number. No person shall be subject to any penalty for failing to comply with a collection of information subject to the Paperwork Reduction Act (PRA) that does not display a valid OMB control number.
Written Paperwork Reduction Act (PRA) comments should be submitted on or before July 5, 2011. If you anticipate that you will be submitting PRA comments, but find it difficult to do so within the period of time allowed by this notice, you should advise the FCC contact listed below as soon as possible.
Submit your PRA comments to Nicholas A. Fraser, Office of Management and Budget, via fax at 202-395-5167 or via Internet at
Benish Shah, Office of Managing Director, (202) 418-7866.
This rule section governs interconnection of private land mobile radio service stations with the public switched telephone network as follows:
(1) Pursuant to 47 CFR section 90.477(a), licensees of interconnected land stations must maintain as part of their station records a detailed description of how interconnection is accomplished.
(2) Pursuant to 47 CFR section 90.477(b)(2) and (d)(2), at least one licensee participating in any cost sharing arrangement for telephone service must maintain cost sharing records, the costs must be distributed at least once a year, and a report of the distribution must be placed in the licensee's station records and made available to participants in the sharing arrangement and the Commission upon request.
(3) Pursuant to 47 CFR 90.477(d)(3), licensees in the Industrial/Business Pool and those licensees who establish eligibility pursuant to 90.20(a)(2), other than persons or organizations charged with specific fire protection activities, persons or organizations charged with specific forestry-conservation activities, or medical emergency systems in the 450-470 MHz band, and who seek to connect within 120 km (75 miles) of 25 cities specified in 90.477(d)(3), must obtain the consent of all co-channel licensees located both within 120 km of the center of the city, and with 120 km of the interconnected base station transmitter. Consensual agreements must specifically state the terms agreed upon and a statement must be submitted to the Commission indicating that all co-channel licensees have consented to the use of interconnection.
In a December 1998
The Federal Communications Commission, as part of its continuing effort to reduce paperwork burden invites the general public and other Federal agencies to take this opportunity to comment on the following information collection(s), as required by the Paperwork Reduction Act (PRA) of 1995, 44 U.S.C. 3501-3520. Comments are requested concerning: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of the Commission, including whether the information shall have practical utility; (b) the accuracy of the Commission's
The FCC may not conduct or sponsor a collection of information unless it displays a currently valid control number. No person shall be subject to any penalty for failing to comply with a collection of information subject to the Paperwork Reduction Act (PRA) that does not display a currently valid OMB control number.
Written Paperwork Reduction Act (PRA) comments should be submitted on or before June 2, 2011. If you anticipate that you will be submitting PRA comments, but find it difficult to do so within the period of time allowed by this notice, you should advise the FCC contact listed below as soon as possible.
Direct all PRA comments to Nicholas A. Fraser, Office of Management and Budget, via fax at 202-395-5167 or via e-mail to
For additional information or copies of the information collection(s), contact Cathy Williams on (202) 418-2918.
47 CFR 76.94(b) requires broadcasters entering into contracts providing for network non-duplication protection to notify cable systems within 60 days of the signing of such a contract. If they are unable to provide notices as provided for in Section 74.94(a), they must provide modified notices that contain the name of the network which has extended non-duplication protection, the time periods by time of day and by network for each day of the week that the broadcaster will be broadcasting programs from that network, and the duration and extent of the protection.
47 CFR 76.94(d) requires broadcasters to provide the following information to cable television systems under the following circumstances: (1) In the event the protection specified in the notices described in 47 CFR 76.94(a) or (b) has been limited or ended prior to the time specified in the notice, or in the event a time period, as identified to the cable system in a notice pursuant to Section 76.94(b) for which a broadcaster has obtained protection is shifted to another time of day or another day (but not expanded), the broadcaster shall, as soon as possible, inform each cable television system operator that has previously received the notice of all changes from the original notice. Notice to be furnished “as soon as possible” under this subsection shall be furnished by telephone, telegraph, facsimile, overnight mail or other similar expedient means. (2) In the event the protection specified in the modified notices described in Section 76.94(b) has been expanded, the broadcaster shall, at least 60 calendar days prior to broadcast of a protected program entitled to such expanded protection, notify each cable system operator that has previously received notice of all changes from the original notice.
47 CFR 76.94(e)(2) and 76.105(c)(2) state that if a cable television system asks a television station for information about its program schedule, the television station shall answer the request.
47 CFR 76.94(f) and 76.107 require a distributor or broadcaster exercising exclusivity to provide to the cable system, upon request, an exact copy of those portions of the contracts, such portions to be signed by both the network and the broadcaster, setting forth in full the provisions pertinent to the duration, nature, and extent of the non-duplication terms concerning broadcast signal exhibition to which the parties have agreed. Providing copies of relevant portions of the contracts is assumed to be accomplished in the notification process set forth in Sections 76.94 and 76.105.
47 CFR 76.95 states that the provisions of Sections 76.92 through 76.94 (including the notification provisions of Section 76.94 shall not apply to a cable system serving fewer than 1,000 subscribers. Within 60 days following the provision of service to 1,000 subscribers, the operator of each such system shall file a notice to that effect with the Commission, and serve a copy of that notice on every television station that would be entitled to exercise network non-duplication protection against it.
47 CFR 76.105(d) requires that in the event the exclusivity specified in Section 76.94(a) has been limited or has ended prior to the time specified in the notice, the distributor or broadcaster who has supplied the original notice shall, as soon as possible, inform each cable television system operator that has previously received the notice of all changes from the original notice. In the event the original notice specified contingent dates on which exclusivity is to begin and/or end, the distributor or broadcaster shall, as soon as possible, notify the cable television system
47 CFR 76.106(b) states that the provisions of Sections 76.101 through 76.105 (including the notification provisions of Section 76.105 shall not apply to a cable system serving fewer than 1,000 subscribers. Within 60 days following the provision of service to 1,000 subscribers, the operator of each such system shall file a notice to effect with the Commission, and serve a copy of that notice on every television station that would be entitled to exercise syndicated exclusivity protection against it.
47 CFR 76.1609 states that network non-duplication provisions of Sections 76.92 through 76.94 shall not apply to cable systems serving fewer than 1,000 subscribers. Within 60 days following the provision of service to 1,000 subscribers, the operator of each system shall file a notice to that effect with the Commission, and serve a copy of that notice on every television station that would be entitled to exercise network non-duplication or syndicated exclusivity protection against it.
Therefore, the information collection requirements that require approval by the Office of Management and Budget (OMB) are as follows:
47 CFR 73.686(e) describes the procedures for measuring the field strength of digital television signals. These procedures will be used to determine whether a household is eligible to receive a distant digital network signal from a satellite television provider, largely rely on existing, proven methods the Commission has already established for measuring analog television signal strength at any individual location, as set forth in Section 73.686(d) of the existing rules, but include modifications as necessary to accommodate the inherent differences between analog and digital TV signals. The new digital signal measurement procedures include provisions for the location of the measurement antenna, antenna height, signal measurement method, antenna orientation and polarization, and data recording.
Therefore, satellite and broadcast industries making field strength measurements shall maintain written records and include the following information: (a) A list of calibrated equipment used in the field strength survey, which for each instrument specifies the manufacturer, type, serial number and rated accuracy, and the date of the most recent calibration by the manufacturer or by a laboratory. Include complete details of any instrument not of standard manufacture; (b) a detailed description of the calibration of the measuring equipment, including field strength meters, measuring antenna, and connecting cable; (c) for each spot at the measuring site, all factors which may affect the recorded field, such as topography, height and types of vegetation, buildings, obstacles, weather, and other local features; (d) a description of where the cluster measurements were made; (e) time and date of the measurements and signature of the person making the measurements; (f) for each channel being measured, a list of the measured value of field strength (in units of dB) after adjustment for line loss and antenna factor) of the five readings made during the cluster measurement process, with the median value highlighted.
Federal Deposit Insurance Corporation (FDIC).
Notice and request for comment.
The FDIC, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on renewal of an existing information collection, as required by the Paperwork Reduction Act of 1995 (44 U.S.C. chapter 35). Currently, the FDIC is soliciting comments on renewal of the information collection titled: Flood Insurance (OMB Number: 3064-0120).
Comments must be submitted on or before July 5, 2011.
Interested parties are invited to submit written comments to the FDIC by any of the following methods:
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Gary A. Kuiper, at the FDIC address above.
Comments are invited on: (a) Whether the collection of information is necessary for the proper performance of the FDIC's functions, including whether the information has practical utility; (b) the accuracy of the estimates of the burden of the information collection, including the validity of the methodology and assumptions used; (c) ways to enhance the quality, utility, and clarity of the information to be collected; and (d) ways to minimize the burden of the information collection on respondents, including through the use of automated collection techniques or other forms of information technology. All comments will become a matter of public record.
Federal Maritime Commission.
Notice and request for comments.
As part of our continuing effort to reduce paperwork and respondent burden, and as required by the Paperwork Reduction Act of 1995, the Federal Maritime Commission (Commission) invites comments on the continuing information collections (extensions with no changes) listed below in this notice.
Written comments must be submitted on or before July 5, 2011.
Address all comments to: Ronald D. Murphy, Managing Director, Office of the Managing Director, Federal Maritime Commission, 800 North Capitol Street, NW., Washington, DC 20573,
Please send separate comments for each specific information collection listed below. You must reference the information collection's title and OMB number in your comments.
Copies of the information collections and instructions, or copies of any comments received, may be obtained by contacting Jane Gregory on (202) 523-5800 or e-mail at
The Commission, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to comment on the continuing information collections listed in this notice, as required by the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
Comments submitted in response to this notice will be included or summarized in our request for Office of Management and Budget (OMB) approval of the relevant information collection. All comments are part of the public record and subject to disclosure. Please do not include any confidential or inappropriate material in your comments. We invite comments on: (1) The necessity and utility of the proposed information collection for the proper performance of the agency's functions; (2) the accuracy of the estimated burden; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) the use of automated collection techniques or other forms of information technology to minimize the information collection burden.
Notice is given that a complaint has been filed with the Federal Maritime Commission (“Commission”) by DNB Exports LLC (“DNB”), and AFI Elektromekanikanik Ve Elektronik San. Tic. Ltd. Sti. (“AFI”), hereinafter “Complainants,” against Barsan Global Lojistiks Ve Gumruk Musavirligi A.S. (“BGL”), Barsan International, Inc. (“Barsan Int'l”), and Impexia Inc. (“Impexia”), hereinafter “Respondents”. Complainant AFI asserts that it is a corporation organized and existing pursuant to the laws of Turkey. Complainant DNB asserts that it is a corporation organized and existing pursuant to the laws of the State of Delaware. Complainant alleges that: Respondent BGL is a corporation organized and existing pursuant to the laws of Turkey; Respondent Barsan Int'l is BGL's subsidiary and is a corporation organized and existing pursuant to the laws of the State of New York; and Respondent Impexia is a corporation existing pursuant to the laws of the State of New Jersey.
Complainants allege that Respondents have violated Section 10(b)(13) of the Shipping Act, 46 U.S.C. 41103(a), by “knowingly disclosing, offering, soliciting and receiving information concerning the nature, kind, quantity, destination, shipper, consignee, and routing of property tendered or delivered to Barsan Int'l by DNB and/or AFI, by, without the consent of DNB and/or AFI, using that information to the detriment and disadvantage of DNB and/or AFI, by unlawfully disclosing that information to Impeixa (sic) as a competitor * * *.” Complainant alleges “[a]s a direct consequence of the unlawful conduct engaged in by Respondents, Complainants have suffered loss of clients, current and future revenues from those clients, not only loss amounts represented by shipments with Respondents, but also with other forwarders, and loss of reputation, all of which has caused and continues to cause Complainants monetary damages of at least $ 1.2 million, and other significant amounts * * *.”
Complainant asks the Commission to: compel respondents to answer the complaint; find the activities of Respondents in violation of the Shipping Act; order reparations be made to Complainants “in the amount as may be proven during the course of this proceeding, with interest as may be lawfully permitted by law, costs and attorneys' fees”; order that Respondents “cease and desist their activities in violation of the Shipping Act”; and revoke Respondent Barsan Int'l's NVOCC and freight forwarder license and prohibit “Respondents BGL, Barsan Int'l and its officers from doing NVOCC and freight forwarding business in the U.S.”
This proceeding has been assigned to the Office of Administrative Law Judges. Hearing in this matter, if any is held, shall commence within the time limitations prescribed in 46 CFR 502.61, and only after consideration has been given by the parties and the presiding officer to the use of alternative forms of dispute resolution. The hearing shall include oral testimony and cross-examination in the discretion of the presiding officer only upon proper showing that there are genuine issues of material fact that cannot be resolved on the basis of sworn statements, affidavits,
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 May 27, 2011.
A. Federal Reserve Bank of Atlanta (Clifford Stanford, Vice President) 1000 Peachtree Street, NE., Atlanta, Georgia 30309:
1.
B. Federal Reserve Bank of Minneapolis (Jacqueline G. King, Community Affairs Officer) 90 Hennepin Avenue, Minneapolis, Minnesota 55480-0291:
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C. Federal Reserve Bank of Dallas (E. Ann Worthy, Vice President) 2200 North Pearl Street, Dallas, Texas 75201-2272:
1.
In compliance with the requirement of Section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995 for opportunity for public comment on proposed data collection projects, the Centers for Disease Control and Prevention (CDC) will publish periodic summaries of proposed projects. To request more information on the proposed projects or to obtain a copy of the data collection plans and instruments, call 404-639-5960 and send written comments to Carol Walker, CDC Acting Reports Clearance Officer, 1600 Clifton Road, MS-D74, Atlanta, GA 30333 or send an e-mail to
The National Health and Nutrition Examination Survey (NHANES)—New—National Center for Health Statistics (NCHS), Centers for Disease Control and Prevention (CDC).
Section 306 of the Public Health Service (PHS) Act (42 U.S.C. 242k), as amended, authorizes that the Secretary of Health and Human Services (DHHS), acting through NCHS, shall collect statistics on the extent and nature of illness and disability; environmental, social and other health hazards; and determinants of health of the population of the United States. This three-year clearance request includes the data collection in 2011 and 2012 and data planning and testing activities for 2013-2014 data collection.
The National Health and Nutrition Examination Survey (NHANES) has, to date, been authorized as a generic clearance under OMB Number 0920-0237. A change in accounting practice for the burden hours, however, requires a shift to a newly-assigned clearance number; thus the submission of a new clearance request. Legislative authority and major activities remain the same as the approval that was received on 11/2/2010. In addition, a new NHANES youth fitness study, beginning in 2012, is now added to the request.
NHANES was conducted periodically between 1970 and 1994, and continuously since 1999 by the National Center for Health Statistics, CDC. Almost 19,000 persons are screened, with about 5,000 participants interviewed and examined annually. Participation in NHANES is completely voluntary and confidential.
NHANES programs produce descriptive statistics which measure the health and nutrition status of the general population. Through the use of questionnaires, physical examinations, and laboratory tests, NHANES studies the relationship between diet, nutrition and health in a representative sample of the United States. NHANES monitors the prevalence of chronic conditions and risk factors related to health such as arthritis, asthma, osteoporosis, infectious diseases, diabetes, high blood
NHANES data users include the U.S. Congress; the World Health Organization; numerous Federal agencies such as the National Institutes of Health, the Environmental Protection Agency, and the United States Department of Agriculture; private groups such as the American Heart Association; schools of public health; private businesses; individual practitioners; and administrators. NHANES data are used to establish, monitor, and/or evaluate recommended dietary allowances, food fortification policies, environmental exposures, immunization guidelines and health education and disease prevention programs. This submission requests approval for three years.
There is no cost to respondents other than their time.
The Centers for Disease Control and Prevention (CDC) publishes a list of information collection requests under review by the Office of Management and Budget (OMB) in compliance with the Paperwork Reduction Act (44 U.S.C. Chapter 35). To request a copy of these requests, call the CDC Reports Clearance Officer at (404) 639-5960 or send an e-mail to
Requirements for a Special Permit to Import Cynomolgus, African Green, or Rhesus Monkeys into the United States (OMB Control No. 0920-0263 exp. 6/30/2011)—Extension—National Center for Emerging and Zoonotic Infectious Diseases, (NCEZID), Centers for Disease Control and Prevention (CDC).
Requirements for a Special Permit to Import Cynomolgus, African Green, or Rhesus Monkeys into the United States (OMB Control No. 0920-0263 exp. 6/30/2011)—Extension—National Center for Emerging and Zoonotic Infectious Diseases, (NCEZID), Centers for Disease Control and Prevention (CDC).
CDC is requesting OMB approval to continue its data collection, “Requirements for a Special Permit to Import Cynomolgus, African Green, or Rhesus Monkeys into the United States”, for another three years. This data collection is currently approved under OMB Control No. 0920-0263. There are no revisions proposed to the currently approved information collection request.
A registered importer must request a special permit to import Cynomolgus, African Green, or Rhesus monkeys. To receive a special permit to import nonhuman primates, the importer must submit a written plan to the Director of CDC which specifies steps that will be taken to prevent exposure of persons and animals during the entire importation and quarantine process for the arriving nonhuman primates.
Under the special permit arrangement, registered importers must submit a plan to CDC for importation and quarantine if they wish to import the specific monkeys covered. The plan must address disease prevention procedures to be carried out in every step of the chain of custody of such monkeys, from embarkation in the country of origin to release from quarantine. Information such as species, origin and intended use for monkeys, transit information, isolation and quarantine procedures, and procedures for testing of quarantined animals is necessary for CDC to make public health decisions. This information enables CDC to evaluate compliance with the standards and to determine whether the measures being taken are adequate to prevent exposure of persons and animals during importation. CDC will monitor at least 2 shipments to be assured that the provisions of a special permit plan are being followed by a new permit holder. CDC will assure that adequate disease control practices are being used by new permit holders before the special permit is extended to cover the receipt of additional shipments under the same plan for a period of 180 days, and may be renewed
Part C (Centers for Disease Control and Prevention) of the Statement of Organization, Functions, and Delegations of Authority of the Department of Health and Human Services (45 FR 67772-76, dated October 14, 1980, and corrected at 45 FR 69296, October 20, 1980, as amended most recently at 76, FR 15984-15985, dated March 22, 2011) is amended to reflect the reorganization of the Center for Global Health, Centers for Disease Control and Prevention.
Section C-B, Organization and Functions, is hereby amended as follows:
After the title and functional statement for the Division of Public Health Systems and Workforce Development (CWF), delete in their entirety the remaining titles and functional statements for the Division of Public Health Systems and Workforce Development (CWF) and insert the following:
Delete in its entirety the function statement for the Office of the Director (CWJ1), Division of Global Disease Detection and Emergency Response (CWJ), and insert the following:
Delete in its entirety item (8) of the functional statement for the Global Disease Detection Branch (CWJB). Delete item (2) and insert the following: (2) provides program support, resources and technical assistance to the Global Disease Detection (GDD) Centers around the world;
Delete items (3), (4), (6), and (7) of the functional statement for the Global Health Security Branch (CWJC) and insert the following accordingly: (3) provides support and coordination at HHS/OGHA regarding the development of policies and priorities on international influenza; (4) serves as liaison with HHS and technical agency (CDC, NIH, FDA) representatives for international pandemic preparedness related to budget formulation, program development, strategic planning, and global health security policy development; (6) provides technical assistance through training, and capacity building in supporting efforts to reduce the public health threat from chemical, biological, and nuclear disasters that are either natural or man-made; (7) provides liaison with the DoS Biosecurity Engagement Program and DoD Defense Threat Reduction Agency to coordinate on global biological threat reduction;
Data for the cross-site evaluation of Project LAUNCH will be collected through: (1) interviews conducted either via telephone or during site-visits to Project LAUNCH grantees, and (2) semi-annual reports that will be submitted electronically on a web-based data-entry system. Information will be collected from all Project LAUNCH grantees.
During either telephone interviews or the site visits, researchers will conduct interviews with Project LAUNCH service providers and collaborators in States/Tribes and local communities of focus. Interviewers will ask program administrators questions about all Project LAUNCH activities, including: infrastructure development; collaboration and coordination among partner agencies, organizations, and service providers; and development, implementation, and refinement of service strategies.
As part of the proposed data collection, Project LAUNCH staff will be asked to submit semi-annual electronic reports on State/Tribal and local systems development and on services that children and families receive. The electronic data reports also will collect data about other Project LAUNCH-funded service enhancements, such as trainings, Project LAUNCH systems change activities, and changes in provider settings. Information provided in these reports will be aggregated on a quarterly basis, and reported semi-annually.
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA) is announcing that a proposed collection of information has been submitted to the Office of Management and Budget (OMB) for review under the Paperwork Reduction Act of 1995.
Fax written comments on the collection of information by June 2, 2011.
To ensure that comments on the information collection are received, OMB recommends that the written comments be faxed to the Office of Information and Regulatory Affairs, OMB,
Elizabeth Berbakos, Office of Information Management, Food and Drug Administration, 1350 Piccard Dr., PI50-400B, Rockville, MD 20850, 301-796-3792,
In compliance with 44 U.S.C. 3507, FDA has submitted the following proposed collection of information to OMB for review and clearance:
On June 22, 2009, the President signed the Family Smoking Prevention and Tobacco Control Act (the Tobacco Control Act) (Pub. L. 111-31) into law. The Tobacco Control Act amended the Federal Food, Drug, and Cosmetic Act (the FD&C Act) by adding a new chapter granting FDA important new authority to regulate the manufacture, marketing, and distribution of tobacco products to protect the public health generally and to reduce tobacco use by minors.
Section 905(j)(1) of the FD&C Act authorizes FDA to establish the form and manner for the submission of information related to substantial equivalence (21 U.S.C. 387e(j)(1)). In a level 1 guidance document issued under the Good Guidances Practices regulation (21 CFR 10.115), FDA provides recommendations intended to assist persons submitting reports under section 905(j) of the FD&C Act, and explains, among other things, FDA's interpretation of the statutory sections related to substantial equivalence (
In the
FDA received one comment in response to the 60-day notice. The commenter indicated that the substantial equivalence requirements were “burdensome to industry in the extreme,” that FDA's estimation of the number of reports to be received was too low, and that the current burden hours to complete each report was unrealistic. Although the commenter asserted that the burden hours were too low and unrealistic, no alternative estimates were provided.
The recommendations in the “Guidance for Industry and FDA Staff—Section 905(j)
With regard to the comment that the number of section 905(j)(1)(A)(i) substantial equivalence reports which FDA estimated to be submitted (150 per year) was too low, FDA has revised its estimate based on information it now has from initial submissions, interactions with industry, and other information, such as the comment received on the 60-day notice on the information collection. As shown below, FDA is increasing the annual estimate of the number of reports received from 150 to 1,000.
With regard to the comment that the number of hours to prepare and submit each report is unrealistic, FDA continues to believe that the currently estimated hours (360 hours annually) is appropriate, particularly given that the premarket requirements for new tobacco products (Section 910 of the FD&C Act) are new and manufacturers' experience with preparing a submission is just beginning to develop. As the requirements and program become more familiar to respondents, FDA may be able to refine these estimates. In addition, as discussed previously, the commenter did not suggest an alternative number of hours. FDA's estimate of 360 hours reflects an amount of time that should provide each submitter enough time to prepare and submit a section 905(j)(1)(A)(i) substantial equivalence report to the Agency.
FDA estimates the burden for this collection of information as follows:
FDA has based these estimates on information it now has available from interactions with the industry, comments regarding the submission of 905(j)(1)(A)(i) substantial equivalence reports, and comments on the 60-day information collection notice request for comments published in the
There are no Capital Costs, Operating Costs, and/or Maintenance Costs to report.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meetings.
The meetings will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meetings.
The meetings will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Notice is hereby given of a meeting of the Advisory Committee to the Director, National Institutes of Health (NIH), Orientation Work Group. The meeting will be closed to the public.
The NIH Director's Pioneer Award and New Innovator Award programs are part of the NIH Common Fund and support exceptionally creative scientists who take highly innovative, potentially high-impact approaches to major challenges in biomedical or behavioral research. The members of the Advisory Committee to the Director, NIH will be participating in an orientation work group meeting for the purpose of receiving instructions on their role and responsibility in the review of these applications requesting NIH research support. Members will be participating in the final review of both the NIH Director's Pioneer Award and New Innovator Award grant reviews during the June 9-10, 2011 meeting of the Advisory Committee to the Director, NIH.
The Orientation Work Group discussions could disclose confidential trade secrets or commercial property such as patentable materials, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Notice is hereby given of a change in the meeting of the Center for Scientific Review Special Emphasis Panel, May 17, 2011, 1 p.m. to May 17, 2011, 4 p.m., National Institutes of Health, 6701 Rockledge Drive, Bethesda, MD 20892 which was published in the
The meeting will be held May 24, 2011. The meeting time and location remain the same. The meeting is closed to the public.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of a meeting of the National Advisory Council on Drug Abuse.
The meeting will be open to the public as indicated below, with attendance limited to space available. Individuals who plan to attend and need special assistance, such as sign language interpretation or other reasonable accommodations, should notify the Contact Person listed below in advance of the meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
This notice is being published less than 15 days prior to the meeting due to the timing limitations imposed by the review and funding cycle.
Any member of the public interested in presenting oral comments to the committee may notify the Contact Person listed on this notice at least 10 days in advance of the meeting. Interested individuals and representatives of organizations may submit a letter of intent, a brief description of the organization represented, and a short description of the oral presentation. Only one representative of an organization may be allowed to present oral comments and if accepted by the committee, presentations may be limited to five minutes. Both printed and electronic copies are requested for the record. In addition, any interested person may file written comments with the committee by forwarding their statement to the Contact Person listed on this notice. The statement should include the name, address, telephone number and when applicable, the business or professional affiliation of the interested person.
Information is also available on the Institute's/Center's home page:
Pursuant to section 10(a) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of meetings of the Interagency Breast Cancer and Environmental Research Coordinating Committee.
The meetings will be open to the public, with attendance limited to space available. Individuals who plan to attend and need special assistance, such as sign language interpretation or other reasonable accommodations, should notify the Contact Person listed below in advance of the meeting.
To attend the meeting, please RSVP via e-mail to
To attend the meeting, please RSVP via e-mail to
Any member of the public interested in presenting oral comments to the committee should submit their remarks in writing at least 10 days in advance of the meeting. Comments in document format (i.e. WORD, Rich Text, PDF) may be submitted via e-mail to
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
This notice is being published less than 15 days prior to the meeting due to the timing limitations imposed by the review and funding cycle.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meetings.
The meetings will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of a meeting of the National Arthritis and Musculoskeletal and Skin Diseases Advisory Council.
The meeting will be open to the public as indicated below, with attendance limited to space available. Individuals who plan to attend and need special assistance, such as sign language interpretation or other reasonable accommodations, should notify the contact person listed below in advance of the meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Any interested person may file written comments with the committee by forwarding the statement to the contact person listed on this notice. The statement should include the name, address, telephone number and when applicable, the business or professional affiliation of the interested person.
In the interest of security, NIH has instituted stringent procedures for entrance onto the NIH campus. All visitor vehicles, including taxicabs, hotel, and airport shuttles will be inspected before being allowed on campus. Visitors will be asked to show one form of identification (for example, a government-issued photo ID, driver's license, or passport) and to state the purpose of their visit.
Pursuant to section 10(a) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of meetings of the Interagency Breast Cancer and Environmental Research Coordinating Committee.
The meetings will be open to the public, with attendance limited to space available. Individuals who plan to attend and need special assistance, such as sign language interpretation or other reasonable accommodations, should notify the Contact Person listed below in advance of the meeting.
Any member of the public interested in presenting oral comments to the committee should submit their remarks in writing at least 10 days in advance of the meeting. Comments in document format (i.e. Word, Rich Text, PDF) may be submitted via e-mail to
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meeting.
The meeting will be open to the public as indicated below, with attendance limited to space available. Individuals who plan to attend and need special assistance, such as sign language interpretation or other reasonable accommodations, should notify the contact person listed below in advance of the meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meetings.
The meetings will be closed to the public in accordance with the
Pursuant to section 10(a) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of meetings of the Interagency Breast Cancer and Environmental Research Coordinating Committee.
The meetings will be open to the public, with attendance limited to space available. Individuals who plan to attend and need special assistance, such as sign language interpretation or other reasonable accommodations, should notify the Contact Person listed below in advance of the meeting.
Any member of the public interested in presenting oral comments to the committee should submit their remarks in writing at least 10 days in advance of the meeting. Comments in document format (i.e. Word, Rich Text, PDF) may be submitted via e-mail to
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meetings.
The meetings will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meetings.
The meetings will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
National Institute on Drug Abuse, National Institutes of Health, Department of Health and Human Services (HHS).
Request for information.
The National Institute on Drug Abuse, a Research Institute of the National Institutes of Health, is seeking on behalf of the Department of Health and Human Services information for an anticipated Surgeon General response to the public health problem of prescription drug abuse among youth.
Individuals and organizations interested in providing information must submit their comments on/or before June 2, 2011. Comments received after this date will not be considered.
Comments may be submitted by any one of the following methods:
•
•
Mary Beth Bigley, Dr.P.H., M.S.N., A.N.P., Acting Director, Office of Science and Communications, Office of the Surgeon General, by telephone at 202-205-5642, or e-mail at
Privacy Office, DHS.
Notice of Privacy Act system of records.
In accordance with the Privacy Act of 1974, the Department of Homeland Security proposes to update and reissue an existing Department of Homeland Security system of records titled, “Department of Homeland Security/United States Coast Guard-002 Employee Assistance Program Records System of Records.” This system will allow the Department of Homeland Security/United States Coast Guard to administer the United States Coast Guard Employee Assistance Program for military personnel. As a result of the required biennial review of this system, records have been updated within “Retention and Disposal” category. This updated system will be included in the Department of Homeland Security's inventory of record system.
Submit comments on or before on or before June 2, 2011. This new system will be effective June 2, 2011.
You may submit comments, identified by docket number DHS-2011-0019 by one of the following methods:
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•
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For general questions please contact: Eileen Yenikaliotis (202-475-3530), Acting Privacy Officer, United States Coast Guard, 2100 2nd Street, SW., Washington, DC 20593. For privacy issues please contact: Mary Ellen Callahan (703-235-0780), Chief Privacy Officer, Privacy Office, Department of Homeland Security, Washington, DC 20528.
In accordance with the Privacy Act of 1974, the Department of Homeland Security (DHS) United States Coast Guard (USCG) proposes to update and reissue an existing DHS system of records titled, “DHS/USCG-002 Employee Assistance Records System of Records.” This system will allow USCG to administer the USCG Employee Assistance Program for military personnel.
As a result of the biennial review of this system, the “Retention and disposal” category has been amended to reflect:
Records are maintained and disposed in accordance with National Archives and Records Administration approved agency Records Schedule, SSIC 1754, item 1 (AUTH: N1-026-07-1, Item1) Employee Assistance Program Coordinator Case Records; if not disclosed under the Privacy Act, records are retained for three years after the client has ceased contact and then destroyed.
Employee Assistance Program client records may contain Department of Transportation-required Substance Abuse evaluations and USCG Sexual Abuse Prevention and Response Program client records; if not disclosed under the Privacy Act, these are destroyed with the Employee Assistance Program Coordinator case records three years after the last contact with the client.
Employee Assistance Program Coordinator Case Records that are disclosed are retained until five years after the client has ceased contact or, if later, for five years after last disclosure of information from the record, as authorized by General Records Schedule 14, item 23.
All records will be retained beyond their normal maintenance period until any pending litigation is completed. This will be true whether or not the client has terminated employment with DHS/USCG. Individual states may require longer retention. The rules in this system notice should not be construed to authorize any violation of such state laws that have greater restrictions.
Files will be destroyed only after the required period of maintenance, with a witness present, by either (1) an DHS or USCG Employee Assistance Program Administrator or an Employee Assistance Program Administrator from another organization that contracts with DHS or USCG for Employee Assistance Program services, or (2) by designated staff of a private or governmental organization under contract with DHS or USCG to provide document destruction services. The witness must be trained in the proper handling of records covered by the Privacy Act and 42 CFR Part 2.
Written records will be destroyed by shredding or burning. Records stored on hard drives will be destroyed using software tools which ensure the protection of the confidential information by making reconstruction or compromise by reuse impracticable. Records contained on back-up tapes/diskettes will be disposed by either physically destroying the tapes/diskettes or by deleting them using software tools which ensure the protection of the confidential information by making reconstruction or compromise by reuse impracticable.
Records located away from the destruction site shall be transferred to the destruction site in the confidential manner. No other information about Employee Assistance Program clients may be maintained once these files have been destroyed.
Consistent with DHS' information sharing mission, information stored in the DHS/USCG-002 Employee Assistance Program Records may be shared with other DHS components, as well as appropriate federal, state, local, tribal territorial, foreign, or international government agencies. This sharing will only take place after DHS determines that the receiving component or agency has a need to know the information to carry out national security, law enforcement, immigration, intelligence, or other functions consistent with the routine uses set forth in this system of record notice. This updated system will be included in DHS' inventory of record systems.
The Privacy Act embodies fair information principles in a statutory framework governing the means by which the United States Government collects, maintains, uses and disseminates individuals' records. The Privacy Act applies to information that is maintained in a “system of records.” A “system of records” is a group of any records under the control of an agency from which information is stored and retrieved by the name of the individual or by some identifying number symbol, or other identifying particular assigned to the individual. In the Privacy Act, an individual is defined to encompass United States citizens and lawful permanent residents. As a matter of policy, DHS extends Privacy Act protections to all individuals where system of records maintain information on U.S. citizens, lawful permanent residents, and visitors. Below is the description of the DHS/USCG-002 Employee Assistance Program Records System of Records.
In accordance with 5 U.S.C. 552a(r), DHS has provided a report of this system of records to the Office of
DHS/USCG-002.
DHS/USCG-002 Employee Assistance Program Records.
Unclassified.
Employee Assistance Program case records are maintained by the USCG's vendor for the Employee Assistance Program. USCG Headquarters (CG-1112) is the point of contact for access to these records. Reports of USCG active duty suicidal behavior, work place violence incidents, critical incidents, and sexual assault reports are maintained at USCG Headquarters by the Office of Work-Life (CG-1112). All other USCG records under this system are located at Work-Life Offices in Washington, DC and field locations. USCG Headquarters (CG-1112) is the point of contact for access to these records.
All USCG active duty, reserve, and retired active duty and reserve military personnel and their eligible dependants/individuals who have been referred for assistance or counseling, are being assisted or counseled, or have been assisted or counseled by the USCG Employee Assistance Program. Eligibility will vary based on status.
Categories of records in this system include:
• Military personnel's name;
• Eligible dependent/individual's name, if applicable;
• Social Security number;
• Employee identification number;
• Date of birth;
• Addresses;
• E-mail address;
• Telephone numbers;
• Job-related information including: job title, rank, duty station, supervisor's name and telephone number, documents received from supervisors or personnel regarding work place problems or performance, leave and attendance records, and workplace-related recommendations made to supervisors as a result of a team meeting;
• Counseling and intervention-related information including: notes and documentation of Employee Assistance Program counselors; records of treatment, including non-clinical educational interventions; counseling referrals; team reports; records of employee attendance at treatment and counseling programs; prognosis of individuals in treatment or counseling programs; insurance data; addresses and contact information of treatment facilities; name and address of individuals providing treatment or counseling or intervention; and Privacy Act notification forms and written consent forms;
• USCG Workplace Violence and related Critical Incident Team records of the Workplace Violence Prevention Program, maintained by USCG Work-Life personnel. These records may include written reports and recommendations to leadership personnel regarding alleged work place violence incidents;
• USCG Critical Incident Stress Management-related records which may include descriptions of incidents, consultations, interventions, and may contain personally-identifying information (for the purpose of follow-on contacts with those thought to be impacted by the critical incident).
• USCG Sexual Assault Prevention and Response Program case records maintained by USCG Work-Life personnel. These records are used to facilitate services for victims and their family members as appropriate. In addition to information cited above these records may contain Victim Reporting Preference Statement, case notes and safety plan. Record may also contain descriptions of alleged assaults;
• USCG Victim Support Person or Victim Advocate maintained by USCG Work-Life personnel. These are maintained in conjunction with efforts to provide assistance to victims of crime. Record will contain signed Victim Support Person or Victim Advocate Statement of Understanding and Victim Support Person or Victim Advocate Supervisor Statement of Understanding, assignment information, and notes regarding results of screening interview, relevant training received, and any other information relevant to the Victim Support Person's or Victim Advocate's provision of support services to victims;
• USCG Critical Incident Stress Management Peer Volunteers maintained by USCG Work-Life personnel. These records contain statement of understanding, notes regarding screening interview, record of related training received and any other information relevant to the peer's provision of services when deployed after a critical incident;
• Case records maintained by USCG Work-Life personnel on USCG Active Duty members who have demonstrated suicidal behavior. The purpose of these records is to facilitate continuity of care for personnel who have exhibited suicidal behavior. These records will contain reports regarding each incident and follow-up case notes;
• Reports of USCG active duty suicidal behavior incidents, work place violence incidents, critical incidents, and sexual assaults are maintained by USCG Headquarters (CG-1112). These reports are received from Work-Life Offices who are responsible for providing services for the related programs described above. Their purpose is to ensure continuity of care and to identify any systemic issues found in aggregate data.
The Homeland Security Act of 2002, Pub. L. 107-296, 6 U.S.C. 121; Federal Records Act, 44 U.S.C. 3101; 6 CFR part 5; 5 U.S.C. app. 3; 5 U.S.C. 301 and Ch. 41; Executive Order 11348, as amended by Executive Order 12107; and Executive Order 9397. 5 U.S.C. 7361, 7362, 7901, 7904.
The Employee Assistance Program will maintain information gathered by and in the possession of USCG Employee Assistance Program, an internal agency program designed to assist employees of USCG and, in certain instances, their eligible dependants/individuals, in regard to a variety of personal and/or work related problems. The program involves counseling, educational, and consultative services provided through the internal and external Employee Assistance Program for alcohol, drug, emotional, or behavioral problems, and addresses mandatory and voluntary counseling following exposure to a traumatic incident, responses to critical incidents that impact employees, and workplace incidents involving actual violence or the threat of violence and necessary follow up.
Disclosure of substance abuse records is limited to the parameters set forth in 42 U.S.C. 290dd, 290ee, and Public Law 100-71, Section 503(e). Accordingly, a Federal employee's substance abuse records may not be disclosed without the prior written consent of the employee, unless the disclosure would be one of the following:
A. To the Department of Justice (including United States Attorney Offices) or other Federal agency
1. DHS or any component thereof;
2. Any employee of DHS in his/her official capacity;
3. Any employee of DHS in his/her individual capacity where DOJ or DHS has agreed to represent the employee; or
4. The United States or any agency thereof, is a party to the litigation or has an interest in such litigation, and DHS determines that the records are both relevant and necessary to the litigation and the use of such records is compatible with the purpose for which DHS collected the records.
B. To appropriate agencies, entities, and persons when:
1. DHS suspects or has confirmed that the security or confidentiality of information in the system of records has been compromised;
2. The Department has determined that as a result of the suspected or confirmed compromise there is a risk of harm to economic or property interests, identity theft or fraud, or harm to the security or integrity of this system or other systems or programs (whether maintained by the Department or another agency or entity) or harm to the individual who relies upon the compromised information;
3. The disclosure made to such agencies, entities, and persons is reasonably necessary to assist in connection with the Department's efforts to respond to the suspected or confirmed compromise and prevent, minimize, or remedy such harm.
C. To contractors and their agents, grantees, experts, consultants, and others performing or working on a contract, service, grant, cooperative agreement, or other assignment for DHS, when necessary to accomplish an agency function related to this system of records. Individuals provided information under this routine use are subject to the same Privacy Act requirements and limitations on disclosure as are applicable to DHS officers and employees.
D. To appropriate State and local authorities to report, under State law, incidents of suspected child abuse or neglect to the extent described under 42 CFR 2.12.
E. To any person or entity to the extent necessary to prevent an imminent and potential crime which directly threatens loss of life or serious bodily injury.
F. To report to appropriate authorities when an individual is potentially at risk to harm himself or herself or others.
G. To medical personnel to the extent necessary to meet a bona fide medical emergency;
H. To qualified personnel for the purpose of conducting scientific research, management audits, financial audits, or program evaluation provided that employees are individually identified;
I. To the employee's medical review official;
J. To the administrator of any Employee Assistance Program in which the employee is receiving counseling or treatment or is otherwise participating;
K. To any supervisory or management official within the employee's agency having authority to take adverse personnel action against such employee; or
L. Pursuant to the order of a court of competent jurisdiction where required by the United States Government to defend against any challenge against any adverse personnel action.
None.
Records in this system are stored electronically or on paper in a locked drawer behind a locked door. The records are stored on magnetic disc, tape, digital media, and CD-ROM.
Data may be retrieved by a Military personnel's, eligible dependant's/individual's name. USCG Critical Incident Stress Management-related records are filed by unit name and are not be retrievable by individual name, rather, by unit name.
Records in this system are safeguarded in accordance with applicable rules and policies, including all applicable DHS automated system security access policies. Strict controls have been imposed to minimize the risk of compromising the information that is being stored. Access to the computer system containing the records in this system is limited to those individuals who have a need to know the information for the performance of their official duties and who have appropriate clearances or permissions.
Records are maintained and disposed in accordance with National Archives and Records Administration approved agency Records Schedule, SSIC 1754, item 1 (AUTH: N1-026-07-1, Item1) Employee Assistance Program (EAP) Coordinator Case Records; if not disclosed under the Privacy Act, records are retained for three years after the client has ceased contact and then destroyed.
Employee Assistance Program client records may contain Department of Transportation-required Substance Abuse evaluations and USCG Sexual Abuse Prevention and Response Program client records; if not disclosed under the Privacy Act, these are destroyed with the EAP Coordinator case records three years after the last contact with the client.
Employee Assistance Program Coordinator Case Records that are disclosed are retained until five years after the client has ceased contact or, if later, for five years after last disclosure of information from the record, as authorized by General Records Schedule 14, item 23.
All records will be retained beyond their normal maintenance period until any pending litigation is completed. This will be true whether or not the client has terminated employment with DHS/USCG. Individual states may require longer retention. The rules in this system notice should not be construed to authorize any violation of such state laws that have greater restrictions.
Files will be destroyed only after the required period of maintenance, with a witness present, by either (1) an DHS or USCG Employee Assistance Program Administrator or an Employee Assistance Program Administrator from another organization that contracts with DHS or USCG for Employee Assistance Program services, or (2) by designated staff of a private or governmental organization under contract with DHS or USCG to provide document destruction services. The witness must be trained in the proper handling of records covered by the Privacy Act and 42 CFR part 2.
Written records will be destroyed by shredding or burning. Records stored on hard drives will be destroyed using software tools which ensure the protection of the confidential information by making reconstruction or compromise by reuse impracticable. Records contained on back-up tapes/diskettes will be disposed by either physically destroying the tapes/diskettes or by deleting them using software tools which ensure the
Records located away from the destruction site shall be transferred to the destruction site in the confidential manner. No other information about Employee Assistance Program clients may be maintained once these files have been destroyed.
Commandant, CG-1112, Office of Work-Life, United States Coast Guard Headquarters, 2100 2nd Street, SW., Washington, DC 20593-0001.
Individuals seeking notification of and access to any record contained in this system of records, or seeking to contest its content, may submit a request in writing to Commandant, CG-1112, Office of Work-Life, United States Coast Guard Headquarters, 2100 2nd Street, SW., Washington, DC 20593-0001.
When seeking records about yourself from this system of records or any other USCG system of records your request must conform with the Privacy Act regulations set forth in 6 CFR part 5. You must first verify your identity, meaning that you must provide your full name, current address and date and place of birth. You must sign your request, and your signature must either be notarized or submitted under 28 U.S.C. 1746, a law that permits statements to be made under penalty of perjury as a substitute for notarization. While no specific form is required, you may obtain forms for this purpose from the Director, Disclosure and FOIA,
• An explanation of why you believe the Department would have information on you;
• Specify when you believe the records would have been created;
• If your request is seeking records pertaining to another living individual, you must include a statement from that individual certifying his/her agreement for you to access his/her records.
Without this bulleted information the USCG will not be able to conduct an effective search, and your request may be denied due to lack of specificity or lack of compliance with applicable regulations.
Records are retained from the following sources:
• USCG Employee Assistance Program: the client, the licensed mental health provider, and collateral sources and resources intended to help the client.
• USCG Workplace Violence and related Critical Incident Team: investigation records, personnel records, critical incident team assembled to make recommendations to command, subject's supervisors, and the subject.
• USCG Critical Incident Stress Management-related records: Work-Life staff, Peers, Incident commander, command(s) affected, individuals impacted by incident, other support persons who may be mobilized to assist those impacted by the event.
• USCG Sexual Assault Prevention and Response Program: victim, victim support person, medical personnel assisting victim, criminal investigations and investigators, and other support personnel intended to assist victim.
• USCG Victim Support Persons (VSP): the victim support person, Work-Life staff, VSP's or Victim Advocate's work supervisor, other support persons who may assist in training.
• USCG Critical Incident Stress Management Peer Volunteers: Peer, Peer's supervisor, Work-Life staff, and other support persons who may assist in training.
• Case records maintained by USCG Work-Life personnel on USCG Duty members who have demonstrated suicidal behavior: the patient, medical personnel, patient's command, and Work-Life staff and other support persons who may assist in helping the patient.
• Reports of USCG active duty suicidal behavior incidents, work place violence incidents, critical incidents, and sexual assaults maintained by USCG Headquarters (CG-1112): Work-Life staff and others as described above under their related programs.
None.
Privacy Office, DHS.
Notice of Privacy Act system of records.
In accordance with the Privacy Act of 1974, the Department of Homeland Security proposes to update and rename an existing Department of Homeland Security system of records titled, “Department of Homeland Security/United States Coast Guard-007 Exceptional Family Member Program System of Records.” This system will allow the Department of Homeland Security United States Coast Guard meet it obligation to assist military personnel, civilian personnel and their eligible dependents with special needs. As a result of the required biennial review of this system, records have been updated to reflect the name change to Department of Homeland Security/United States Coast Guard Special Needs Program Record. This updated system will be included in the Department of Homeland Security's inventory of record systems.
Submit comments on or before June 2, 2011. This updated system will be effective June 2, 2011.
You may submit comments, identified by docket number DHS-2011-0020 by one of the following methods:
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For general questions please contact: Eileen Yenikaliotis (202-475-3515), Acting Privacy Officer, United States Coast
In accordance with the Privacy Act of 1974, the Department of Homeland Security (DHS) United States Coast Guard (USCG) proposes to update and rename an existing DHS system of records titled, “DHS/USCG-007 Exceptional Family Member Program.
This system will allow the Department of Homeland Security/United States Coast Guard to collect and maintain records on civilians, active duty, reserve, retired active duty and retired reserve military personnel, and their eligible dependents with special needs.
As a result of the biennial review of this system, the term “Exceptional Family Member Program” has been replaced by term “Special Needs” in the preamble, Supplementary Information, System Name, and Purpose categories of the SORN.
Consistent with DHS' information sharing mission, information stored in DHS/USCG-007 Special Needs Program Records may be shared with other DHS components, as well as appropriate federal, state, local, tribal, territorial foreign, or international government agencies. This sharing will only occur after DHS determines that the receiving component or agency has a need to know the information to carry out national security, law enforcement, immigration, intelligence, or other functions consistent with the routine uses set forth in this system of records notice. This updated system will be included in DHS' inventory of record systems.
This system of records contains individually identifiable health information. The Department of Defense Health Information Privacy Regulation (DoD 6025.18-R) issued pursuant to the Health Insurance Portability and Accountability Act of 1996, applies to most such health information. Department of Defense 6025.18-R may place additional procedural requirements on the uses and disclosures of such information beyond those found in the Privacy Act of 1974 or mentioned in this system of records notice.
The Privacy Act embodies fair information practice principles in a statutory framework governing the means by which the U.S. Government collects, maintains, uses and disseminates individuals' records. The Privacy Act applies to information that is maintained in a “system of records.” A “system of records” is a group of any records under the control of an agency for which information is retrieved by the name of an individual or by some identifying number, symbol, or other identifying particular assigned to the individual. In the Privacy Act, an individual is defined to encompass U.S. citizens and lawful permanent residents. As a matter of policy DHS extends administrative Privacy Act protections to all individuals where system of records maintain information on U.S. citizens, lawful permanent residents, and visitors. Below is the description of the DHS/USCG—007 Special Needs Program System of Records.
In accordance with 5 U.S.C. 552a(r), DHS has provided a report of this new system of records to the Office of Management and Budget and to Congress.
DHS/USCG-007.
DHS/USCG-007 Special Needs Program.
Unclassified.
Records are maintained at USCG Headquarters in Washington, DC and field locations.
Coast Guard active duty, reserve, retired active duty, retired reserve, and civilian personnel and their eligible dependents who have a long-term physical or mental chronic condition that substantially limits one or more of the major life activities of an individual including professionally diagnosed medical, physical, psychological, and/or educational disabilities.
Categories of records in this system include:
• Military or civilian personnel's name;
• Eligible dependent's name and birth date;
• Service member's, civilian's or eligible dependents home address, phone numbers, and email information;
• Identification number (EMPLID); social security numbers of the service member or civilian personnel are currently in the case records (we will no longer be asking for those in the new policy, but the numbers will still be in all of the old files);
• Eligible dependent's diagnosed special need, including copies of medical, educational, and psychological reports, enrollment forms, correspondence and follow-up, and any other data relevant to the dependent's individual special needs' program files; and
• Benefits, including case management activities, and supports and services received related to the special need.
The Homeland Security Act of 2002, Public Law 107-296, Federal Records Act, 44 U.S.C. 3101; 6 CFR part 5; 5 U.S.C. 301, and COMNDTINST 1754.7 (series).
The purpose of this system is to administer special needs requests of USCG military and civilian personnel to coordinate the special needs program's medical care, mental health treatment, and to provide case management for USCG military and civilian personnel and eligible dependants with special needs.
This system of records contains individually identifiable health information. The Department of Defense Health Information Privacy Regulation (DoD 6025.18-R) issued pursuant to the Health Insurance Portability and Accountability Act of 1996, applies to most such health information. Department of Defense 6025.18-R may place additional procedural requirements on the uses and disclosures of such information beyond those found in the Privacy Act of 1974 or mentioned in this system of records notice.
In addition to those disclosures generally permitted under 5 U.S.C. 552a(b) of the Privacy Act, all or a portion of the records or information contained in this system may be disclosed outside DHS as a routine use pursuant to 5 U.S.C. 552a(b)(3) as follows:
A. To the Department of Justice (including United States Attorney
1. DHS or any component thereof;
2. Any employee of DHS in his/her official capacity;
3. Any employee of DHS in his/her individual capacity where DOJ or DHS has agreed to represent the employee; or
4. The United States or any agency thereof, is a party to the litigation or has an interest in such litigation, and DHS determines that the records are both relevant and necessary to the litigation and the use of such records is compatible with the purpose for which DHS collected the records.
B. To a congressional office from the record of an individual in response to an inquiry from that congressional office made at the request of the individual to whom the record pertains.
C. To the National Archives and Records Administration or other federal government agencies pursuant to records management inspections being conducted under the authority of 44 U.S.C. 2904 and 2906.
D. To an agency, organization, or individual for the purpose of performing audit or oversight operations as authorized by law, but only such information as is necessary and relevant to such audit or oversight function.
E. To appropriate agencies, entities, and persons when:
1. DHS suspects or has confirmed that the security or confidentiality of information in the system of records has been compromised;
2. The Department has determined that as a result of the suspected or confirmed compromise there is a risk of harm to economic or property interests, identity theft or fraud, or harm to the security or integrity of this system or other systems or programs (whether maintained by DHS or another agency or entity) or harm to the individual who relies upon the compromised information; and
3. The disclosure made to such agencies, entities, and persons is reasonably necessary to assist in connection with DHS's efforts to respond to the suspected or confirmed compromise and prevent, minimize, or remedy such harm.
F. To contractors and their agents, grantees, experts, consultants, and others performing or working on a contract, service, grant, cooperative agreement, or other assignment for DHS, when necessary to accomplish an agency function related to this system of records. Individuals provided information under this routine use are subject to the same Privacy Act requirements and limitations on disclosure as are applicable to DHS officers and employees.
G. To an appropriate Federal, State, tribal, local, international, or foreign law enforcement agency or other appropriate authority charged with investigating or prosecuting a violation or enforcing or implementing a law, rule, regulation, or order, where a record, either on its face or in conjunction with other information, indicates a violation or potential violation of law, which includes criminal, civil, or regulatory violations and such disclosure is proper and consistent with the official duties of the person making the disclosure.
H. To any member of the family when a signed release of information is documented in the case record, in furtherance of treating the family member with special needs.
I. To officials and employees of local and state governments and agencies in the performance of their official duties pursuant to the laws and regulations governing local control of communicable diseases, preventive medicine and safety programs, developmental disabilities, and other public health and welfare programs.
K. To the federal, state or local governmental agencies when appropriate in the counseling and treatment of individuals or families with special medical or educational needs, or receiving early intervention or related services.
None.
Records in this system are stored electronically or on paper in a locked drawer behind a locked door. The records are stored on magnetic disc, tape, digital media, and CD-ROM.
Data may be retrieved by a Coast Guard military or civilian personnel's name and/or identification number (EMPLID).
Records in this system are safeguarded in accordance with applicable rules and policies, including all applicable DHS automated systems security and access policies. Strict controls have been imposed to minimize the risk of compromising the information that is being stored. Access to the computer system containing the records in this system is limited to those individuals who have a need to know the information for the performance of their official duties and who have appropriate clearances or permissions.
Case records are maintained at a decentralized location until the USCG military or civilian personnel is separated or retired, eligible family member is no longer an eligible dependent, or the eligible dependent is no longer diagnosed as having a special need. Upon separation or retirement of the USCG military or civilian personnel, the eligible family member is no longer an eligible dependent, or when the eligible dependent is no longer diagnosed as having a special need, the record will be transferred to Commandant, CG-1112. After a 3-year retention, the record is destroyed (N1-026-07-9).
Chief, Office of Work-Life, Director of Health, Safety and Work-Life, CG-11, United States Coast Guard, Washington, DC 20593-0001.
Individuals seeking notification of and access to any open record contained in this system of records, or seeking to contest its content, may submit a request in writing to the Work-Life field office where the case record is maintained. Individuals seeking notification of and access to any closed record contained in this system of records, or seeking to contest its content, may submit a request in writing to the Chief, Office of Work-Life, Director of Health, Safety and Work-Life, CG-11, United States Coast Guard, Washington, DC 20593-0001.
When seeking records about yourself or your minor dependent from this system of records or any other USCG system of records your request must conform with the Privacy Act regulations set forth in 6 CFR part 5. You must first verify your identity, meaning that you must provide your full name, current address and date and place of birth. You must sign your request, and your signature must either be notarized or submitted by you under 28 U.S.C. 1746, a law that permits statements to be made under penalty of perjury as a substitute for notarization. While no specific form is required, you may obtain forms for this purpose from the Director, Disclosure and FOIA,
• An explanation of why you believe the Department would have information on you,
• Specify when you believe the records would have been created,
• If your request is seeking records pertaining to another living individual, you must include a statement from that individual certifying his/her agreement for you to access his/her records.
Without this bulleted information the USCG may not be able to conduct an effective search, and your request may be denied due to lack of specificity or lack of compliance with applicable regulations.
Records are obtained from medical reports that are provided to the USCG.
None.
60-Day Notice of Information Collection Under Review: Form I-693, Report of Medical Examination and Vaccination Record, OMB Control No. 1615-0033.
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 is published to obtain comments from the public and affected agencies. Comments are encouraged and will be accepted for 60 days until July 5, 2011.
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 Officer, 20 Massachusetts Avenue, NW., Washington, DC 20529-2020. Comments may also be submitted to DHS via facsimile to 202-272-0997 or via e-mail at
The address listed in this notice should only be used to submit comments concerning this information collection. Please do not submit requests for individual case status inquiries to this address. If you are seeking information about the status of your individual case, please check “My Case Status” online 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 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 agencies 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.
(1)
(2)
(3)
(4)
(5)
(6)
If you 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., Room 5012, Washington, DC 20529-2020, Telephone number 202-272-8377.
60-Day Notice of Information Collection Under Review; Form G-639, Freedom of Information/Privacy Act Request; OMB Control No. 1615-0102.
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 is published to obtain comments from the public and affected agencies. Comments are encouraged and will be accepted for sixty days until July 5, 2011.
During this 60 day period, USCIS will be evaluating whether to revise the Form G-639. Should USCIS decide to revise Form G-639 we will advise the
Written comments and/or suggestions regarding the item(s) contained in this notice, especially regarding 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 Officer, 20 Massachusetts Avenue, NW., Washington, DC 20529-2020. Comments may also be submitted to DHS via facsimile to 202-272-0997 or via e-mail at
The address listed in this notice should only be used to submit comments concerning this information collection. Please do not submit requests for individual case status inquiries to this address. If you are seeking information about the status of your individual case, please check “My Case Status” online at:
Written comments and suggestions from the public and affected agencies concerning the collection of information should address one or more of the following four points:
(1) Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
(2) Evaluate the accuracy of the agencies 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.
(1)
(2)
(3)
(4)
(5)
(6)
If you need a copy of the information collection instrument, please visit the 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.
30-Day Notice of Information Collection Under Review: Form I-929, Petition for Qualifying Family Member of a U-1 Nonimmigrant, OMB Control No. 1615-0106.
The Department of Homeland Security, U.S. Citizenship and Immigration Services (USCIS) will be submitting 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. The information collection was previously published in the
The purpose of this notice is to allow an additional 30 days for public comments. Comments are encouraged and will be accepted until June 2, 2011. This process is conducted in accordance with 5 CFR 1320.10.
Written comments and/or suggestions regarding the item(s) contained in this notice, especially regarding the estimated public burden and associated response time, should be directed to the Department of Homeland Security (DHS), and to the Office of Management and Budget (OMB) USCIS Desk Officer. Comments may be submitted to: USCIS, Chief, Regulatory Products Division, Office of the Executive Secretariat, Clearance Officer, 20 Massachusetts Avenue, NW., Washington, DC 20529-2020. Comments may also be submitted to DHS via facsimile to 202-272-0997 or via e-mail at
Written comments and suggestions from the public and affected agencies 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, e.g., permitting electronic submission of responses.
(1)
(2)
(3)
(4)
(5)
(6)
If you need a copy of the information collection instrument, please visit the 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 202-272-8377.
30-Day notice of information collection under review: Forms G-325, G-325A, G-325B, and G-325C, Biographic Information; OMB Control No. 1615-0008.
The Department of Homeland Security, U.S. Citizenship and Immigration Services (USCIS) will be submitting 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. The information collection was previously published in the
The purpose of this notice is to allow an additional 30 days for public comments. Comments are encouraged and will be accepted until June 2, 2011. This process is conducted in accordance with 5 CFR 1320.10.
Written comments and/or suggestions regarding the item(s) contained in this notice, especially regarding the estimated public burden and associated response time, should be directed to the Department of Homeland Security (DHS), and to the Office of Management and Budget (OMB) USCIS Desk Officer. Comments may be submitted to: USCIS, Chief, Regulatory Products Division, Office of the Executive Secretariat, Clearance Officer, 20 Massachusetts Avenue, NW., Washington, DC 20529-2020. Comments may also be submitted to DHS via facsimile to 202-272-0997 or via e-mail at
(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 agencies 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.
(1)
(2)
(3)
(4)
(5)
(6)
If you need a copy of the information collection instrument, please visit the 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 202-272-8377.
Office of the Chief Information Officer, HUD.
Notice.
The proposed information collection requirement described below has been submitted to the Office of Management and Budget (OMB) for review, as required by the Paperwork Reduction Act. The Department is soliciting public comments on the subject proposal.
A Public Housing Agency (PHA) which is designated Troubled or substandard under the Public Housing Assessment System (PHAS) must enter into a Memorandum of Agreement (MOA) with HUD to outline its planned improvements. Similarly, a PHA which is a standard performer, but receives a total PHAS score between 70% and 60% must submit an Improvement Plan (IP). These plans are designed to address deficiencies in a PHA's operations found through the PHAS assessment process (management, financial, physical, or resident related) and any other deficiencies identified by HUD through independent assessments or other methods.
Interested persons are invited to submit comments regarding this proposal. Comments should refer to the proposal by name and/or OMB approval Number (2577-0237) and should be sent to: HUD Desk Officer, Office of Management and Budget, New Executive Office Building, Washington, DC 20503; e-mail
Colette Pollard, Reports Management Officer, QDAM, Department of Housing and Urban Development, 451 Seventh Street, SW., Washington, DC 20410; e-mail Colette Pollard at
This notice informs the public that the Department of Housing and Urban Development has submitted to OMB a request for approval of the Information collection described below. This notice is soliciting comments from members of the public and affecting agencies concerning the proposed collection of information to: (1) Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility; (2) Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information; (3) Enhance the quality, utility, and clarity of the information to be collected; and (4) Minimize the burden of the collection of information on those who are to respond; including through the use of appropriate automated collection techniques or other forms of information technology, e.g., permitting electronic submission of responses.
Section 3507 of the Paperwork Reduction Act of 1995, 44 U.S.C. 35, as amended.
Office of the Chief Information Officer, HUD.
Notice.
The proposed information collection requirement described below has been submitted to the Office of Management and Budget (OMB) for review, as required by the Paperwork Reduction Act. The Department is soliciting public comments on the subject proposal.
PHAs will complete a PNA once every 5 years, will update the PNA annually, and will submit information electronically to HUD. The information is used by PHAs as a strategic and capital planning tool. The information uploaded to HUD will be used for aggregation of an estimate of the capital needs across the Public Housing portfolio and evaluation of the impact of the Capital Fund in meeting the physical needs based upon review of the annual updates.
Interested persons are invited to submit comments regarding this proposal. Comments should refer to the proposal by name and/or OMB approval Number (2577-Pending) and should be sent to: HUD Desk Officer, Office of Management and Budget, New Executive Office Building, Washington, DC 20503; e-mail
Colette Pollard, Reports Management Officer, QDAM, Department of Housing and Urban Development, 451 Seventh Street, SW., Washington, DC 20410; e-mail Colette Pollard at
This notice informs the public that the Department of Housing and Urban Development has submitted to OMB a request for approval of the Information collection described below. This notice is soliciting comments from members of the public and affecting agencies concerning the proposed collection of information to: (1) Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility; (2) Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information; (3) Enhance the quality, utility, and clarity of the information to be collected; and (4) Minimize the burden of the collection of information on those who are to respond; including through the use of appropriate automated collection techniques or other forms of information technology, e.g., permitting electronic submission of responses.
Section 3507 of the Paperwork Reduction Act of 1995, 44 U.S.C. 35, as amended.
11 a.m., Tuesday, May 10, 2011.
U.S. Parole Commission, 5550 Friendship Boulevard, Chevy Chase, Maryland.
Closed.
Determinations on three petitions for reconsideration in original jurisdiction cases (28 CFR 2.27).
Patricia W. Moore, Staff Assistant to the Chairman, U.S. Parole Commission, 5550 Friendship Boulevard, Chevy Chase, Maryland 20815, (301) 492-5933.
Notice.
The Department of Labor (DOL) is submitting the Office of Workers' Compensation Programs (OWCP) sponsored information collection request (ICR) titled, “Request for Examination and/or Treatment,” Form LS-1, to the Office of Management and Budget (OMB) for review and approval for continued use in accordance with the Paperwork Reduction Act of 1995 (Pub. L. 104-13, 44 U.S.C. chapter 35).
Submit comments on or before June 2, 2011.
A copy of this ICR, with applicable supporting documentation; including a description of the likely respondents, proposed frequency of response, and estimated total burden may be obtained from the RegInfo.gov Web site,
Submit comments about this request to the Office of Information and Regulatory Affairs,
Contact Michel Smyth by telephone at 202-693-4129 (this is not a toll-free number) or by e-mail at
The Request for Examination and/or Treatment, Form LS-1, is used by employers to authorize medical treatment for injured workers and by physicians to report findings of physical examinations and treatment recommended. This information collection is subject to the PRA.
A Federal agency generally cannot conduct or sponsor a collection of information, and the public is generally
Interested parties are encouraged to send comments to the OMB, Office of Information and Regulatory Affairs at the address shown in the
• Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
• Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
• Enhance the quality, utility, and clarity of the information to be collected; and
• Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology, e.g., permitting electronic submission of responses.
Notice.
The Department of Labor (DOL) is submitting the revised Office of Workers' Compensation Programs (OWCP) sponsored information collection request (ICR) titled, “Claim for Continuance of Compensation,” Form CA-12, to the Office of Management and Budget (OMB) for review and approval for use in accordance with the Paperwork Reduction Act of 1995 (Pub. L. 104-13, 44 U.S.C. chapter 35).
Submit comments on or before June 2, 2011.
A copy of this ICR, with applicable supporting documentation, including a description of the likely respondents, proposed frequency of response, and estimated total burden may be obtained from the RegInfo.gov Web site,
Submit comments about this request to the Office of Information and Regulatory Affairs,
Michel Smyth by telephone at 202-693-4129 (this is not a toll-free number) or by e-mail at
The Claim for Continuance of Compensation, Form CA-12, is used to obtain information from eligible survivors receiving death benefits for an extended period of time. This information is necessary to ensure that compensation being paid is accurate. While the DOL has revised the form to collect a beneficiary's Social Security Number and to make a few formatting changes that require identifying this submission as a revision, those changes are not expected materially to affect the public burden in responding to this information collection.
This information collection is subject to the PRA. A Federal agency generally cannot conduct or sponsor a collection of information, and the public is generally not required to respond to an information collection, unless it is approved by the OMB under the PRA and displays a currently valid OMB Control Number. In addition, notwithstanding any other provisions of law, no person shall generally be subject to penalty for failing to comply with a collection of information if the collection of information does not display a valid OMB control number.
Interested parties are encouraged to send comments to the OMB, Office of Information and Regulatory Affairs at the address shown in the
• Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
• Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
• Enhance the quality, utility, and clarity of the information to be collected; and
• Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology, e.g., permitting electronic submission of responses.
In accordance with Section 223 of the Trade Act of 1974, as amended (“Act”), 19 U.S.C. 2273, the Department of Labor issued a Certification of Eligibility to Apply for Worker Adjustment Assistance on January 28, 2011, applicable to workers of Digital River Education Services, Inc., a division of Digital River, Inc., including on-site leased workers from Serenity Staffing, Accountemps, Silicon Valley and Liaison Resources, Austin and Dallas, Texas. The notice was published in the
At the request of the State agency, the Department reviewed the certification for workers of the subject firm. The workers provide reselling services to third-party vendors, publishers, and product manufactures.
Information shows that Digital River Education Services acquired Journey Education Marketing (JEM) in August 2010. Some workers separated from employment at the Austin and Dallas, Texas locations of the subject firm had their wages reported under a separated unemployment insurance (UI) tax account under the name Journey Education Marketing (JEM).
Accordingly, the Department is amending this certification to properly reflect this matter.
The intent of the Department's certification is to include all workers of the subject firm who were adversely affected by the acquisition of services from a foreign country.
The amended notice applicable to TA-W-74,975 is hereby issued as follows:
All workers of Digital River Education Services, Inc., a division of Digital River, Inc., including workers whose unemployment insurance (UI) wages are paid through Journey Education Marketing (JEM), and including on-site leased workers from Serenity Staffing, Accountemps, Silicon Valley, and Liaison Resources, Austin and Dallas, Texas, who became totally or partially separated from employment on or after December 7, 2009 through January 28, 2013, and all workers in the group threatened with total or partial separation from employment on date of certification through two years from the date of certification, are eligible to apply for adjustment assistance under Chapter 2 of Title II of the Trade Act of 1974, as amended.
In accordance with Section 223 of the Trade Act of 1974, as amended (19 U.S.C. 2273) the Department of Labor herein presents summaries of determinations regarding eligibility to apply for trade adjustment assistance for workers by (TA-W) number issued during the period of April 18, 2011 through April 22, 2011.
In order for an affirmative determination to be made for workers of a primary firm and a certification issued regarding eligibility to apply for worker adjustment assistance, each of the group eligibility requirements of Section 222(a) of the Act must be met.
I. Under Section 222(a)(2)(A), the following must be satisfied:
(1) A significant number or proportion of the workers in such workers' firm have become totally or partially separated, or are threatened to become totally or partially separated;
(2) The sales or production, or both, of such firm have decreased absolutely; and
(3) One of the following must be satisfied:
(A) Imports of articles or services like or directly competitive with articles produced or services supplied by such firm have increased;
(B) Imports of articles like or directly competitive with articles into which one or more component parts produced by such firm are directly incorporated, have increased;
(C) Imports of articles directly incorporating one or more component parts produced outside the United States that are like or directly competitive with imports of articles incorporating one or more component parts produced by such firm have increased;
(D) Imports of articles like or directly competitive with articles which are produced directly using services supplied by such firm, have increased; and
(4) The increase in imports contributed importantly to such workers' separation or threat of separation and to the decline in the sales or production of such firm; or
II. Section 222(a)(2)(B) all of the following must be satisfied:
(1) A significant number or proportion of the workers in such workers' firm have become totally or partially separated, or are threatened to become totally or partially separated;
(2) One of the following must be satisfied:
(A) There has been a shift by the workers' firm to a foreign country in the production of articles or supply of services like or directly competitive with those produced/supplied by the workers' firm;
(B) There has been an acquisition from a foreign country by the workers' firm of articles/services that are like or directly competitive with those produced/supplied by the workers' firm; and
(3) The shift/acquisition contributed importantly to the workers' separation or threat of separation.
In order for an affirmative determination to be made for adversely
(1) A significant number or proportion of the workers in the public agency have become totally or partially separated, or are threatened to become totally or partially separated;
(2) The public agency has acquired from a foreign country services like or directly competitive with services which are supplied by such agency; and
(3) The acquisition of services contributed importantly to such workers' separation or threat of separation.
In order for an affirmative determination to be made for adversely affected secondary workers of a firm and a certification issued regarding eligibility to apply for worker adjustment assistance, each of the group eligibility requirements of Section 222(c) of the Act must be met.
(1) A significant number or proportion of the workers in the workers' firm have become totally or partially separated, or are threatened to become totally or partially separated;
(2) The workers' firm is a Supplier or Downstream Producer to a firm that employed a group of workers who received a certification of eligibility under Section 222(a) of the Act, and such supply or production is related to the article or service that was the basis for such certification; and
(3) Either—
(A) The workers' firm is a supplier and the component parts it supplied to the firm described in paragraph (2) accounted for at least 20 percent of the production or sales of the workers' firm; or
(B) A loss of business by the workers' firm with the firm described in paragraph (2) contributed importantly to the workers' separation or threat of separation.
In order for an affirmative determination to be made for adversely affected workers in firms identified by the International Trade Commission and a certification issued regarding eligibility to apply for worker adjustment assistance, each of the group eligibility requirements of Section 222(f) of the Act must be met.
(1) The workers' firm is publicly identified by name by the International Trade Commission as a member of a domestic industry in an investigation resulting in—
(A) An affirmative determination of serious injury or threat thereof under section 202(b)(1);
(B) An affirmative determination of market disruption or threat thereof under section 421(b)(1); or
(C) An affirmative final determination of material injury or threat thereof under section 705(b)(1)(A) or 735(b)(1)(A) of the Tariff Act of 1930 (19 U.S.C. 1671d(b)(1)(A) and 1673d(b)(1)(A));
(2) The petition is filed during the 1-year period beginning on the date on which—
(A) A summary of the report submitted to the President by the International Trade Commission under section 202(f)(1) with respect to the affirmative determination described in paragraph (1)(A) is published in the
(B) Notice of an affirmative determination described in subparagraph (1) is published in the
(3) The workers have become totally or partially separated from the workers' firm within—
(A) The 1-year period described in paragraph (2); or
(B) Notwithstanding section 223(b)(1), the 1-year period preceding the 1-year period described in paragraph (2).
The following certifications have been issued. The date following the company name and location of each determination references the impact date for all workers of such determination.
The following certifications have been issued. The requirements of Section 222(a)(2)(A) (increased imports) of the Trade Act have been met.
The following certifications have been issued. The requirements of Section 222(a)(2)(B) (shift in production or services) of the Trade Act have been met.
The following certifications have been issued. The requirements of Section 222(c) (supplier to a firm whose workers are certified eligible to apply for TAA) of the Trade Act have been met.
In the following cases, the investigation revealed that the eligibility criteria for worker adjustment assistance have not been met for the reasons specified.
The investigation revealed that the criterion under paragraph (a)(1), or (b)(1), or (c)(1)(employment decline or threat of separation) of section 222 has not been met.
The investigation revealed that the criteria under paragraphs(a)(2)(A) (increased imports) and (a)(2)(B) (shift in production or services to a foreign country) of section 222 have not been met.
I hereby certify that the aforementioned determinations were issued during the period of April 18, 2011 through April 22, 2011. Copies of these determinations may be requested under the Freedom of Information Act. Requests may be submitted by fax, courier services, or mail to FOIA Disclosure Officer, Office of Trade Adjustment Assistance (ETA), U.S. Department of Labor, 200 Constitution Avenue, NW., Washington, DC 20210 or
Employment and Training Administration, Labor.
Notice of Solicitation for Grant Applications.
Through this notice, the Employment and Training Administration (ETA), U.S. Department of Labor (DOL or the Department), announces the availability of approximately $240 million in funds for an H-1B Technical Skills Training Grants program. This grant program is designed to provide education, training, and job placement assistance in the occupations and industries for which employers are using H-1B visas to hire foreign workers, and the related activities necessary to support such training. H-1B technical skills training grants are financed by a user fee paid by employers to bring foreign workers into the United States under the H-1B nonimmigrant visa program. This technical skills training program was authorized under Section 414(c) of the American Competitiveness and Workforce Improvement Act of 1998 (ACWIA), as amended (29 U.S.C. 2916a). Grant awards will be made only to the extent that funds are available.
The Department will make awards to two types of training grants: those that provide On-the-Job Training (OJT) to all participants and those that use other training strategies. Of the awards granted through this Solicitation, at least $150 million will be awarded to grantees that provide OJT to all participants. Between the two types of grants awarded (OJT and other training strategies), DOL intends to fund at least $45 million to applicants proposing to provide training for occupations in the health care industry and at least $60 million to applicants that serve long-term unemployed individuals. While this Solicitation is open, DOL anticipates that additional funding will accrue for this grant program. Such additional funding may be made available for awards during the second round of funding, depending on the quality of applications received.
The Department expects to award approximately 75-100 grants ranging from $1 million to $5 million with up to a 48-month period of performance. The Department will award grants to a partnership of private and public sector entities as defined in ACWIA. This partnership must include at least two entities from among the following groups: (1) Businesses or business-related nonprofit organizations, such as trade associations; (2) education and training providers, including community colleges and other community-based organizations; and (3) entities involved in administering the workforce investment system established under Title I of the WIA, and economic development agencies.
The complete SGA is available in detail on ETA's Web site at
There are two closing dates for receipt of applications which are June 2, 2011 and November 17, 2011.
Jeannette Flowers, 200 Constitution Avenue, NW., Room N4716, Washington, DC 20210; Telephone: 202-693-3322; E-mail:
Petitions have been filed with the Secretary of Labor under Section 221(a) of the Trade Act of 1974 (“the Act”) and are identified in the Appendix to this notice. Upon receipt of these petitions, the Director of the Office of Trade Adjustment Assistance, Employment and Training Administration, has instituted investigations pursuant to Section 221(a) of the Act.
The purpose of each of the investigations is to determine whether the workers are eligible to apply for adjustment assistance under Title II, Chapter 2, of the Act. The investigations will further relate, as appropriate, to the determination of the date on which total or partial separations began or threatened to begin and the subdivision of the firm involved.
The petitioners or any other persons showing a substantial interest in the subject matter of the investigations may request a public hearing, provided such request is filed in writing with the Director, Office of Trade Adjustment Assistance, at the address shown below, not later than May 13, 2011.
Interested persons are invited to submit written comments regarding the subject matter of the investigations to the Director, Office of Trade Adjustment Assistance, at the address shown below, not later than May 13, 2011.
The petitions filed in this case are available for inspection at the Office of the Director, Office of Trade Adjustment Assistance, Employment and Training Administration, U.S. Department of Labor, Room N-5428, 200 Constitution Avenue, NW., Washington, DC 20210.
Notice.
The Department of Labor, as part of its continuing effort to reduce paperwork and respondent burden, conducts a pre-clearance consultation program to provide the general public and Federal agencies with an opportunity to comment on proposed and/or continuing collections of information in accordance with the Paperwork Reduction Act of 1995 (PRA95) [44 U.S.C. 3506(c)(2)(A)]. This program helps to ensure that requested data can be provided in the desired format, reporting burden (time and financial resources) is minimized, collection instruments are clearly understood, and the impact of collection requirements on respondents can be properly assessed. Currently, the Office of Workers' Compensation Programs is soliciting comments concerning the proposed collection: Miner's Claim for Benefits under the Black Lung Benefits Act (CM-911) and Employment History (CM-911A). A copy of the proposed information collection request can be obtained by contacting the office listed below in the
Written comments must be submitted to the office listed in the
Mr. Vincent Alvarez, U.S. Department of Labor, 200 Constitution Ave., NW., Room S-3201, Washington, DC 20210, telephone (202) 693-0372, fax (202) 693-1447, E-mail
• Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
• Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
• Enhance the quality, utility and clarity of the information to be collected; and
• Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology, e.g., permitting electronic submissions of responses.
Comments submitted in response to this notice will be summarized and/or included in the request for Office of Management and Budget approval of the information collection request; they will also become a matter of public record.
Notice.
The Department of Labor, as part of its continuing effort to reduce paperwork and respondent burden, conducts a pre-clearance consultation program to provide the general public and Federal agencies with an opportunity to comment on proposed and/or continuing collections of information in accordance with the Paperwork Reduction Act of 1995 (PRA95) [44 U.S.C. 3506(c)(2)(A)]. This program helps to ensure that requested data can be provided in the desired format, reporting burden (time and financial resources) is minimized, collection instruments are clearly understood, and the impact of collection requirements on respondents can be properly assessed. Currently, the Office of Workers' Compensation Programs is soliciting comments concerning the proposed collection: Representative Payee Report (CM-623), Representative Payee Report, Short Form (CM-623S) and Physician's/Medical Officer's Statement (CM-787). A copy of the proposed information collection request can be obtained by contacting the office listed below in the
Written comments must be submitted to the office listed in the
Mr. Vincent Alvarez, U.S. Department of Labor, 200 Constitution Ave., NW., Room S-3201, Washington, DC 20210, telephone (202) 693-0372, fax (202) 693-1447, E-mail
• Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
• Evaluate the accuracy of the agency's estimate of the burden of the
• Enhance the quality, utility and clarity of the information to be collected; and
• Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology, e.g., permitting electronic submissions of responses.
Comments submitted in response to this notice will be summarized and/or included in the request for Office of Management and Budget approval of the information collection request; they will also become a matter of public record.
National Archives and Records Administration.
Notice and request for comments.
As part of a Federal Government-wide effort to streamline the process to seek feedback from the public on service delivery, we are seeking comment on the development of the following proposed Generic Information Collection Request (Generic ICR): “Generic Clearance for the Collection of Qualitative Feedback on Agency Service Delivery” for approval under the Paperwork Reduction Act (PRA) (44 U.S.C. 3501
Consideration will be given to all comments received by July 5, 2011.
Submit comments by one of the following methods:
•
•
Comments submitted in response to this notice may be made available to the public through relevant Web sites. For this reason, please do not include in your comments information of a confidential nature, such as sensitive personal information or proprietary information. If you send an e-mail comment, your e-mail address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the Internet. Please note that responses to this public comment request containing any routine notice about the confidentiality of the communication will be treated as public comments that may be made available to the public notwithstanding the inclusion of the routine notice.
Requests for additional information or copies of the proposed information collection and supporting statement should be directed to Tamee Fechhelm at telephone number 301-713-1694, or fax number 301-713-7409.
The solicitation of feedback will target areas such as: Timeliness, appropriateness, accuracy of information, courtesy, efficiency of service delivery, and resolution of issues with service delivery. Responses will be assessed to plan and inform efforts to improve or maintain the quality of service offered to the public. If this information is not collected, vital feedback from customers and stakeholders on the Agency's services will be unavailable.
The Agency will only submit a collection for approval under this generic clearance if it meets the following conditions:
• The collections are voluntary;
• The collections are low-burden for respondents (based on considerations of total burden hours, total number of respondents, or burden-hours per respondent) and are low-cost for both the respondents and the Federal Government;
• The collections are non-controversial and do not raise issues of concern to other Federal agencies;
• Any collection is targeted to the solicitation of opinions from respondents who have experience with the program or may have experience with the program in the near future;
• Personally identifiable information (PII) is collected only to the extent necessary and is not retained;
• Information gathered will be used only internally for general service improvement and program management purposes and is not intended for release outside of the agency;
• Information gathered will not be used for the purpose of substantially informing influential policy decisions; and
• Information gathered will yield qualitative information; the collections will not be designed or expected to yield statistically reliable results or used as though the results are generalizable to the population of study.
Feedback collected under this generic clearance provides useful information, but it does not yield data that can be generalized to the overall population. This type of generic clearance for qualitative information will not be used for quantitative information collections that are designed to yield reliably actionable results, such as monitoring trends over time or documenting program performance. Such data uses require more rigorous designs that address: The target population to which generalizations will be made, the sampling frame, the sample design (including stratification and clustering), the precision requirements or power calculations that justify the proposed sample size, the expected response rate, methods for assessing potential non-response bias, the protocols for data collection, and any testing procedures that were or will be undertaken prior to fielding the study. Depending on the degree of influence the results are likely to have, such collections may still be eligible for submission for other generic mechanisms that are designed to yield quantitative results.
As a general matter, information collections will not result in any new system of records containing privacy information and will not ask questions of a sensitive nature, such as sexual behavior and attitudes, religious beliefs, and other matters that are commonly considered private.
Below we provide projected average estimates for the next three years:
All written comments will be available for public inspection at Regulations.gov.
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 Office of Management and Budget control number.
2 p.m., Thursday, May 4, 2011.
Board Room, 7th Floor, Room 7047, 1775 Duke Street, Alexandria, VA 22314-3428.
Closed.
2. Consideration of Supervisory Activity. Closed pursuant to exemptions (8), (9)(A)(ii) and 9(B).
Mary Rupp, Secretary of the Board, Telephone: 703-518-6304.
In accordance with the Federal Advisory Committee Act (Pub. L. 92-463, as amended), the National Science Foundation announces the following meeting:
In accordance with the Federal Advisory Committee Act (Pub. L. 92-463, as amended), the National Science Foundation announces the following meeting:
The National Science Board, pursuant to NSF regulations (45 CFR part 614), the National Science Foundation Act, as amended (42 U.S.C. 1862n-5), and the Government in the Sunshine Act (5 U.S.C. 552b), hereby gives notice in regard to the scheduling of meetings for the transaction of National Science Board business and other matters specified, as follows:
National Science Board.
May 10, 2011 at 8 a.m. through May 11, 2011 at 3:15 p.m.
National Science Foundation, 4201 Wilson Blvd., Room 1235, Arlington, VA 22230. All visitors must report to the NSF visitor desk at the 9th and N. Stuart Streets entrance to receive a visitor's badge. Public visitors must arrange for a visitor's badge in advance. Call 703-292-7000 or e-mail
Some portions open, some portions closed.
Please refer to the National Science Board Web site
Jennie L. Moehlmann,
Dana Topousis,
The National Science Board, pursuant to NSF regulations (45 CFR part 614), the National Science Foundation Act, as amended (42 U.S.C. 1862n-5), and the Government in the Sunshine Act (5 U.S.C. 552b), hereby gives notice in regard to the scheduling of meetings for the transaction of National Science Board business and other matters specified, as follows:
National Science Board.
May 9, 2011 at 8 a.m. through 6:15 p.m.
National Science Foundation, 4201 Wilson Blvd., Room 1235, Arlington, VA 22230. All visitors must report to the NSF visitor desk at the 9th and N. Stuart Streets entrance to receive a visitor's badge. Public visitors must arrange for a visitor's badge in advance. Call 703-292-7000 or e-mail
Some portions open, some portions closed.
Please refer to the National Science Board Web site
Jennie L. Moehlmann,
Dana Topousis,
Nuclear Regulatory Commission (NRC).
Notice of pending NRC action to submit an information collection request to the Office of Management and Budget (OMB) and solicitation of public comment.
The NRC invites public comment about its intention to request the OMB's approval for renewal of an existing information collection that is summarized below. We are required to publish this notice in the
Information pertaining to the requirement to be submitted:
1.
2.
3.
4.
5.
6.
7.
Submit, by July 5, 2011, comments that address the following questions:
1. Is the proposed collection of information necessary for the NRC to properly perform its functions? Does the information have practical utility?
2. Is the burden estimate accurate?
3. Is there a way to enhance the quality, utility, and clarity of the information to be collected?
4. How can the burden of the information collection be minimized, including the use of automated collection techniques or other forms of information technology?
The public may examine and have copied for a fee publicly available documents, including the draft supporting statement, at the NRC's Public Document Room, O1-F21, One White Flint North, 11555 Rockville Pike, Rockville, Maryland 20852. OMB clearance requests are available at the NRC Web site:
For the Nuclear Regulatory Commission.
Nuclear Regulatory Commission (NRC).
Notice of pending NRC action to submit an information collection request to the Office of Management and Budget (OMB) and solicitation of public comment.
The NRC invites public comment about our intention to request the OMB's approval for renewal of an existing information collection that is summarized below. We are required to publish this notice in the
Information pertaining to the requirement to be submitted:
1.
2.
3.
4.
5.
6.
7.
Submit, by July 5, 2011, comments that address the following questions:
1. Is the proposed collection of information necessary for the NRC to properly perform its functions? Does the information have practical utility?
2. Is the burden estimate accurate?
3. Is there a way to enhance the quality, utility, and clarity of the information to be collected?
4. How can the burden of the information collection be minimized, including the use of automated collection techniques or other forms of information technology?
The public may examine and have copied for a fee publicly available documents, including the draft supporting statement, at the NRC's Public Document Room, Room O-1F21, One White Flint North, 11555 Rockville Pike, Rockville, Maryland 20852. OMB clearance requests are available at the NRC Web site:
For the Nuclear Regulatory Commission.
Nuclear Regulatory Commission (NRC).
Solicitation of public comment.
The NRC is seeking public comment on potential alternatives for risk informing the path forward to resolve Generic Safety Issue (GSI) 191, Pressurized Water Reactor (PWR) Sump Performance.
Submit comments by July 5, 2011.
Please include Docket ID NRC-2011-0090 in the subject line of your comments. Comments submitted in writing or in electronic form will be posted on the NRC Web site and on the Federal rulemaking Web site,
The NRC requests that any party soliciting or aggregating comments received from other persons for submission to the NRC inform those persons that the NRC will not edit their comments to remove any identifying or contact information, and therefore, they should not include any information in their comments that they do not want publicly disclosed. You may submit comments by any one of the following methods:
•
•
•
You can access publicly available documents related to this notice using the following methods:
•
•
•
Mr. Stewart Bailey, Chief of Safety Issue Resolution Branch, telephone (301) 415-1321,
The NRC identified a potential susceptibility of PWR emergency core cooling system (ECCS) recirculation sump screens and associated flow paths to debris blockage during design basis accidents that require recirculation operation. As a result, all operating PWR licensees were requested in Generic Letter (GL) 2004-02, Potential Impact of Debris Blockage on Emergency Recirculation during Design Basis Accidents at Pressurized-Water Reactors, to perform a mechanistic evaluation of the recirculation functions and, as appropriate, to take additional actions (
An overview of licensee and NRC staff actions to address GSI-191 can be found in Policy Issue Notation Vote Paper (SECY-10-0113) which presented to the Commission the regulatory path forward options for closure. In a Staff Requirement Memorandum (SRM) dated December 23, 2010, the Commission directed the staff, in part, to explore alternative paths forward for resolving GSI-191.
While GSI-191 has not yet been fully resolved, the NRC believes that measures taken thus far in response to the sump-clogging issue have contributed greatly to the safety of US nuclear power plants. Given the vastly enlarged advanced strainers installed, compensatory measures already taken, and the low probability of challenging pipe breaks, adequate levels of safety and defense-in-depth are currently being maintained. In light of these factors, the Commission directed that the staff should take the time needed to consider all options to a risk-informed, safety conscious resolution to GSI-191.
The SRM to SECY-10-0113 stated that the staff should employ innovation and creativity in fully exploring the policy and technical implications of all available alternatives for risk informing the path forward. These alternatives were to include, but not be limited to, how proposed rule for Title 10 of the
In an effort to facilitate public involvement, the staff previously solicited public input during the 2011 NRC Regulatory Information Conference (RIC), held in Rockville, MD. During the RIC, GSI-191 was the subject of one of the RIC technical sessions. Information concerning the 2011 RIC is available at
For the Nuclear Regulatory Commission.
Pursuant to Section 189a.(2) of the Atomic Energy Act of 1954, as amended (the Act), the U.S. Nuclear Regulatory Commission (the Commission or NRC) is publishing this regular biweekly notice. The Act requires the Commission publish notice of any amendments issued, or proposed to be issued and grants the Commission the authority to issue and make immediately effective any amendment to an operating license upon a determination by the Commission that such amendment involves no significant hazards consideration, notwithstanding the pendency before the Commission of a request for a hearing from any person.
This biweekly notice includes all notices of amendments issued, or proposed to be issued from April 7, 2011, to April 20, 2011. The last biweekly notice was published on April 19, 2011 (76 FR 21917 to 21928).
The Commission has made a proposed determination that the following amendment requests involve no significant hazards consideration. Under the Commission's regulations in Title 10 of the
The Commission is seeking public comments on this proposed determination. Any comments received within 30 days after the date of publication of this notice will be considered in making any final determination.
Normally, the Commission will not issue the amendment until the expiration of 60 days after the date of publication of this notice. The Commission may issue the license amendment before expiration of the 60-day period provided that its final determination is that the amendment involves no significant hazards consideration. In addition, the Commission may issue the amendment prior to the expiration of the 30-day comment period should circumstances change during the 30-day comment period such that failure to act in a timely way would result, for example in derating or shutdown of the facility. Should the Commission take action prior to the expiration of either the comment period or the notice period, it will publish in the
Written comments may be submitted by mail to the Chief, Rules, Announcements and Directives Branch (RADB), TWB-05-B01M, Division of Administrative Services, Office of Administration, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and should cite the publication date and page number of this
Within 60 days after the date of publication of this notice, any person(s) whose interest may be affected by this action may file a request for a hearing and a petition to intervene with respect to issuance of the amendment to the subject facility operating license. Requests for a hearing and a petition for leave to intervene shall be filed in accordance with the Commission's “Rules of Practice for Domestic Licensing Proceedings” in 10 CFR part 2. Interested person(s) should consult a current copy of 10 CFR 2.309, which is available at the Commission's PDR, located at One White Flint North, Room O1-F21, 11555 Rockville Pike (first floor), Rockville, Maryland 20852. Publicly available records will be accessible from the Agencywide Documents Access and Management System's (ADAMS) Public NRC Library on the Internet at the NRC Web site,
As required by 10 CFR 2.309, a petition for leave to intervene shall set forth with particularity the interest of the petitioner in the proceeding, and how that interest may be affected by the results of the proceeding. The petition should specifically explain the reasons why intervention should be permitted with particular reference to the following general requirements: (1) The name, address, and telephone number of the requestor or petitioner; (2) the nature of the requestor's/petitioner's right under the Act to be made a party to the proceeding; (3) the nature and extent of the requestor's/petitioner's property, financial, or other interest in the proceeding; and (4) the possible effect of any decision or order which may be entered in the proceeding on the requestor's/petitioner's interest. The petition must also identify the specific contentions which the requestor/
Each contention must consist of a specific statement of the issue of law or fact to be raised or controverted. In addition, the requestor/petitioner shall provide a brief explanation of the bases for the contention and a concise statement of the alleged facts or expert opinion which support the contention and on which the requestor/petitioner intends to rely in proving the contention at the hearing. The requestor/petitioner must also provide references to those specific sources and documents of which the petitioner is aware and on which the requestor/petitioner intends to rely to establish those facts or expert opinion. The petition must include sufficient information to show that a genuine dispute exists with the applicant on a material issue of law or fact. Contentions shall be limited to matters within the scope of the amendment under consideration. The contention must be one which, if proven, would entitle the requestor/petitioner to relief. A requestor/petitioner who fails to satisfy these requirements with respect to at least one contention will not be permitted to participate as a party.
Those permitted to intervene become parties to the proceeding, subject to any limitations in the order granting leave to intervene, and have the opportunity to participate fully in the conduct of the hearing.
If a hearing is requested, the Commission will make a final determination on the issue of no significant hazards consideration. The final determination will serve to decide when the hearing is held. If the final determination is that the amendment request involves no significant hazards consideration, the Commission may issue the amendment and make it immediately effective, notwithstanding the request for a hearing. Any hearing held would take place after issuance of the amendment. If the final determination is that the amendment request involves a significant hazards consideration, then any hearing held would take place before the issuance of any amendment.
All documents filed in NRC adjudicatory proceedings, including a request for hearing, a petition for leave to intervene, any motion or other document filed in the proceeding prior to the submission of a request for hearing or petition to intervene, and documents filed by interested governmental entities participating under 10 CFR 2.315(c), must be filed in accordance with the NRC E-Filing rule (72 FR 49139, August 28, 2007). The E-Filing process requires participants to submit and serve all adjudicatory documents over the internet, or in some cases to mail copies on electronic storage media. Participants may not submit paper copies of their filings unless they seek an exemption in accordance with the procedures described below.
To comply with the procedural requirements of E-Filing, at least ten (10) days prior to the filing deadline, the participant should contact the Office of the Secretary by e-mail at
Information about applying for a digital ID certificate is available on NRC's public Web site at
If a participant is electronically submitting a document to the NRC in accordance with the E-Filing rule, the participant must file the document using the NRC's online, Web-based submission form. In order to serve documents through EIE, users will be required to install a Web browser plug-in from the NRC Web site. Further information on the Web-based submission form, including the installation of the Web browser plug-in, is available on the NRC's public Web site at
Once a participant has obtained a digital ID certificate and a docket has been created, the participant can then submit a request for hearing or petition for leave to intervene. Submissions should be in Portable Document Format (PDF) in accordance with NRC guidance available on the NRC public Web site at
A person filing electronically using the agency's adjudicatory E-Filing system may seek assistance by contacting the NRC Meta System Help Desk through the “Contact Us” link located on the NRC Web site at
Participants who believe that they have a good cause for not submitting documents electronically must file an exemption request, in accordance with 10 CFR 2.302(g), with their initial paper filing requesting authorization to continue to submit documents in paper format. Such filings must be submitted by: (1) First class mail addressed to the Office of the Secretary of the Commission, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001,
Documents submitted in adjudicatory proceedings will appear in NRC's electronic hearing docket which is available to the public at
Petitions for leave to intervene must be filed no later than 60 days from the date of publication of this notice. Non-timely filings will not be entertained absent a determination by the presiding officer that the petition or request should be granted or the contentions should be admitted, based on a balancing of the factors specified in 10 CFR 2.309(c)(1)(i)-(viii).
For further details with respect to this license amendment application, see the application for amendment which is available for public inspection at the Commission's PDR, located at One White Flint North, Room O1-F21, 11555 Rockville Pike (first floor), Rockville, Maryland 20852. Publicly available records will be accessible from the ADAMS Public NRC Library on the Internet at the NRC Web site,
1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?
The proposed change clarifies the operability requirements for the RCS leakage detection instrumentation and reduces the time allowed for the plant to operate when the only TS-required operable RCS leakage detection instrumentation monitor is the drywell atmospheric gaseous radiation monitor. The monitoring of RCS leakage is not a precursor to any accident previously evaluated. The monitoring of RCS leakage is not used to mitigate the consequences of any accident previously evaluated.
Therefore, it is concluded that this change does not involve a significant increase in the probability of consequences of an accident previously evaluated.
2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?
The proposed change clarifies the operability requirements for the RCS leakage detection instrumentation and reduces the time allowed for the plant to operate when the only TS-required operable RCS leakage detection instrumentation monitor is the drywell atmospheric gaseous radiation monitor. The proposed change does not involve a physical alteration of the plant (no new or different type of equipment will be installed) or a change in the methods governing normal plant operation.
Therefore, it is concluded that the proposed change does not create the possibility of a new or different kind of accident from any previously evaluated.
3. Does the proposed change involve a significant reduction in a margin of safety?
The proposed change clarifies the operability requirements for the RCS leakage detection instrumentation and reduces the time allowed for the plant to operate when the only TS-required operable RCS leakage detection instrumentation monitor is the drywell atmospheric gaseous radiation monitor. Reducing the amount of time the plant is allowed to operate with only the drywell atmospheric gaseous radiation monitor operable increase the margin of safety by increasing the likelihood that an increase in RCS leakage will be detected before it potentially results in gross failure.
Therefore, it is concluded that the proposed change does not involve a significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment request involves no significant hazards consideration.
1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?
The proposed license amendment does not add, delete or modify plant equipment. The proposed changes are administrative in nature. The proposed amendment would relocate the list of pumps, fans and valves in Technical Specification (TS) 4.5.1.lb, Sequence and Power Transfer Test, to the TMI-1 Updated Final Safety Analysis Report (UFSAR) Section 8.2, Table 8.2-11, Engineered Safeguards Loading Sequence. In addition, TS 4.5.1.1b and TS 4.5.1.2b are being modified to include a high level description of equipment required to be included in the Sequence and Power Transfer Test, and the Sequence Test, respectively.
The proposed changes relocate surveillance requirement details that are not required by 10 CFR 50.36. The proposed changes do not change current surveillance requirements. The subject list of pumps, fans and valves that will be relocated to UFSAR Section 8.2, Table 8.2-11, will be controlled under 10 CFR 50.59.
The probability of an accident is not increased by these proposed changes because neither the Sequence and Power Transfer Test nor the Sequence Test are initiators of any design basis event. Additionally, the proposed changes do not involve any physical changes to plant structures, systems, or components (SSCs), or the manner in which these SSCs are operated, maintained, or controlled. The consequences of an accident will not be increased because the proposed administrative changes to the Sequence and Power Transfer Test, and the Sequence Test, will continue to provide a high degree of assurance that the Electric Power System will meet its safety related function.
Therefore, the proposed changes do not involve a significant increase in the probability or consequences of an accident previously evaluated.
2. Does the proposed amendment create the possibility of a new or different kind of accident from any previously evaluated?
The proposed changes do not alter the physical design, safety limits, safety analyses assumptions, or the manner in which the plant is operated or tested. The proposed changes are administrative in nature and the surveillance requirements remain the same. Accordingly, the proposed changes do not introduce any new accident initiators, nor do they reduce or adversely affect the capabilities of any plant SSC in the performance of their safety function.
Therefore, the proposed changes do not create the possibility of a new or different kind of accident from any accident previously evaluated.
3. Does the proposed amendment involve a significant reduction in a margin of safety?
The margin of safety is associated with the confidence in the ability of the fission product barriers (i.e., fuel cladding, reactor coolant pressure boundary, and containment structure) to limit the level of radiation to the public. There are no physical changes to SSCs or operating and testing procedures associated with the proposed amendment.
The proposed changes do not impact the assumptions of any design basis accident, and do not alter assumptions relative to the mitigation of an accident or transient event. The proposed changes are administrative in nature and the surveillance requirements remain the same.
Therefore, the proposed changes do not involve a significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment request involves no significant hazards consideration.
1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?
The proposed changes add a separate Technical Specification (TS) for the Control Room Air Conditioning (AC) system, and renumbers and revises the existing TS for the Control Room Emergency Filtration (CREF) system. Consistent with Technical Specification Task Force (TSTF) Standard TS Change Traveler TSTF-477, the proposed change also adds an action statement for two inoperable Control Room AC subsystems.
The proposed change does not involve a physical alteration of the plant (no new or different type of equipment will be installed). The proposed changes add a separate TS for the Control Room AC system and an action statement for two inoperable control room subsystems. The equipment qualification temperature of the control room equipment is not affected. Future changes to the Bases or licensee-controlled document[s] will be evaluated pursuant to the requirements of 10 CFR 50.59, “Changes, test and experiments,” to ensure that such changes do not result in more than a minimal increase in the probability or consequences of an accident previously evaluated.
The proposed changes do not adversely affect accident initiators or precursors nor alter the design assumptions, conditions, and configuration of the facility or the manner in which the plant is operated and maintained. The proposed changes do not adversely affect the ability of structures, systems and components (SSCs) to perform their intended safety function to mitigate the consequences of an initiating event within the assumed acceptance limits. The proposed changes do not affect the source term, containment isolation, or radiological consequences of any accident previously evaluated. Further, the proposed changes do not increase the types and the amounts of radioactive effluent that may be released, nor significantly increase individual or cumulative occupation/public radiation exposures.
Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.
2. Does the proposed amendment create the possibility of a new or different kind of accident from any accident previously evaluated?
The proposed changes add a separate TS for the Control Room AC system and an
Therefore, the proposed change does not create the possibility of a new or different kind of accident from any previously evaluated.
3. Does the proposed amendment involve a significant reduction in a margin of safety?
The proposed changes add a separate TS for the Control Room AC system and an action statement for two inoperable control room subsystems. Instituting the proposed changes will continue to maintain the control room temperature within design limits. Changes to the Bases or license[e-]controlled document[s] are performed in accordance with 10 CFR 50.59. This approach provides an effective level of regulatory control and ensures that the control room temperature will be maintained within design limits.
The proposed changes maintain sufficient controls to preserve the current margins of safety.
Therefore, the proposed change does not involve a significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment request involves no significant hazards consideration.
1. Does the proposed Technical Specification change involve a significant increase in the probability or consequences of an accident previously evaluated?
The 480V RMOV Boards D or E, the equipment they power, or the automatic power transfer feature provided for these boards are not precursors to any accident previous evaluated in the Updated Final Safety Analysis Report (UFSAR). Therefore, the probability of an evaluated accident is not increased by modifying this equipment. The proposed deletion of the requirement to maintain the automatic transfer capability for the power supply to the LPCI inboard injection valves, RHR [residual heat removal] minimum flow valves and recirculation pump discharge valves does not change the number of Emergency Core Cooling System (ECCS) subsystems credited in the BFN licensing basis. The proposed change does not affect the operational characteristics or function of systems, structures, or components (SSCs), the interfaces between credited SSCs and other plant systems, or the reliability of SSCs. The proposed change does not impact the capability of credited SSCs to perform their required safety functions.
Therefore, the proposed TS changes will not significantly increase the consequences of an accident previously evaluated.
2. Does the proposed Technical Specification change create the possibility of a new or different kind of accident from any accident previously evaluated?
The proposed deletion of the requirement to maintain an automatic transfer capability for the power supply to the LPCI inboard injection valves, RHR minimum flow valves and recirculation pump discharge valves does not introduce new equipment, which could create a new or different kind of accident.
The proposed change does not alter the manner in which equipment operation is initiated, nor will the functional demands on credited equipment be changed. The capability of credited SSCs to perform their required function will not be affected by the proposed change. In addition, the proposed change does not affect the interaction of plant SSCs with other plant SSCs whose failure or malfunction can initiate an accident or transient. As such, no new failure modes are being introduced. No new external threats, release pathways, or equipment failure modes are created. Therefore, the proposed deletion of the requirement to maintain an automatic transfer capability for the power supply to the LPCI inboard injection valves, RHR minimum flow valves and recirculation pump discharge valves will not create a possibility for an accident of a new or different type than those previously evaluated.
3. Does the proposed Technical Specification change involve a significant reduction in a margin of safety?
The proposed deletion of the requirement to maintain an automatic transfer capability for the power supply to the LPCI inboard injection valves, RHR minimum flow valves and recirculation pump discharge valves does not change the conditions, operating configurations, or minimum amount of operating equipment credited in the safety analyses for accident or transient mitigation. The proposed change does not alter the assumptions contained in the safety analyses. The proposed change does not alter the manner in which safety limits, limiting safety system settings or limiting conditions for operation are determined. The proposed change does not impact the safety analysis credited redundancy or availability of SSCs required for accident or transient mitigation, or the ability of the plant to cope with design basis events as assumed in safety analyses. In addition, no changes are proposed in the manner in which the credited SSCs provide plant protection or which create new modes of plant operation. The requirements of 10 CFR 50.46 and Appendix K continue to be met. Therefore, the proposed change does not involve a significant reduction in the margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment request involves no significant hazards consideration.
During the period since publication of the last biweekly notice, the Commission has issued the following amendments. The Commission has determined for each of these amendments that the application complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations. The Commission has made appropriate findings as required by the Act and the Commission's rules and regulations in 10 CFR Chapter I, which are set forth in the license amendment.
Notice of Consideration of Issuance of Amendment to Facility Operating License, Proposed No Significant Hazards Consideration Determination, and Opportunity for A Hearing in connection with these actions was published in the
Unless otherwise indicated, the Commission has determined that these amendments satisfy the criteria for categorical exclusion in accordance with 10 CFR 51.22. Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental
For further details with respect to the action
The Commission's related evaluation of the amendments is contained in a Safety Evaluation dated April 8, 2011.
No significant hazards consideration comments received: No.
The Commission's related evaluation of the amendments is contained in a Safety Evaluation dated April 8, 2011.
No significant hazards consideration comments received: No.
The Commission's related evaluation of the amendment is contained in a Safety Evaluation dated April 7, 2011.
No significant hazards consideration comments received: No.
The Commission's related evaluation of the amendments is contained in a Safety Evaluation dated April 13, 2011.
No significant hazards consideration comments received: No.
The October 15, 2010, and March 14, 2011, supplements contained clarifying information and did not change the NRC staff's initial proposed finding of no significant hazards consideration.
The Commission's related evaluation of the amendments is contained in a Safety Evaluation dated April 15, 2011.
No significant hazards consideration comments received: No.
The Commission's related evaluation of the amendments is contained in a Safety Evaluation dated April 8, 2011.
No significant hazards consideration comments received: No.
The February 2, 2011 and March 17, 2011 supplements contained clarifying information and did not change the NRC staff's initial proposed finding of significant hazards consideration published in the
The Commission's related evaluation of the amendment is contained in a Safety Evaluation dated April 18, 2011.
No significant hazards consideration comments received: No.
The supplemental letters contained clarifying information and did not change the staff's initial proposed finding of no significant hazards consideration.
The Commission's related evaluation of the amendments is contained in a Safety Evaluation dated April 14, 2011.
No significant hazards consideration comments received: No.
The Commission's related evaluation of the requested approval of the amendment, and state consultation, are contained in a safety evaluation dated April 13, 2011. The NRC staff determined that the amendment satisfied the categorical exclusion criterion of 10 CFR 51.22(c) and no environmental assessment was required.
The Commission's related evaluation of the amendments is contained in a Safety Evaluation dated April 14, 2011.
No significant hazards consideration comments received: No.
The Commission's related evaluation of the amendment is contained in a Safety Evaluation dated April 19, 2011.
No significant hazards consideration comments received: No.
For the Nuclear Regulatory Commission.
Nuclear Regulatory Commission.
Weeks of May 2, 9, 16, 23, 30, June 6, 13, 2011.
Commissioners' Conference Room, 11555 Rockville Pike, Rockville, Maryland.
Public and Closed.
This meeting will be webcast live at the Web address—
This meeting will be webcast live at the Web address—
There are no meetings scheduled for the week of May 16, 2011.
This meeting will be webcast live at the Web address—
This meeting will be webcast live at the Web address—
10 a.m. Meeting with the Advisory Committee on Reactor Safeguards (ACRS) (Public Meeting). (
This meeting will be webcast live at the Web address—
This meeting will be webcast live at the Web address—
*The schedule for Commission meetings is subject to change on short notice. To verify the status of meetings, call (recording)—(301) 415-1292. Contact person for more information: Rochelle Bavol, (301) 415-1651.
The NRC Commission Meeting Schedule can be found on the Internet at:
The NRC provides reasonable accommodation to individuals with disabilities where appropriate. If you need a reasonable accommodation to participate in these public meetings, or need this meeting notice or the transcript or other information from the public meetings in another format (
This notice is distributed electronically to subscribers. If you no longer wish to receive it, or would like to be added to the distribution, please contact the Office of the Secretary, Washington, DC 20555 (301-415-1969), or send an e-mail to
It appears to the Securities and Exchange Commission that there is a lack of current and accurate information concerning the securities of Magnum d'Or Resources, Inc. (“Magnum”) because of questions regarding the accuracy of assertions by Magnum in its Web site and in press releases to investors concerning, among other things: (1) The company's current financial condition; and (2) the company's current operations.
The Commission is of the opinion that the public interest and the protection of investors require a suspension of trading in the securities of the above-listed company.
By the Commission.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”),
The Exchange proposes to file a rule change related to the By-Laws of its parent corporation, The NASDAQ OMX Group, Inc. (“NASDAQ OMX”). The text of the proposed rule change is available on the Exchange's Web site at
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
NASDAQ OMX recently made certain clarifying amendments to its By-Laws.
NASDAQ OMX By-Laws previously provided for a Nominating Committee which is appointed pursuant to the By-Laws. In addition to the responsibilities listed in By-Law Article IV, Section 4.13(h), the Nominating Committee also conducts certain governance functions such as consulting with the Board and the management to determine the characteristics, skills and experience desired for the Board as a whole and for its individual members, overseeing the annual director evaluation, and reviewing the overall effectiveness of the Board. Accordingly, NASDAQ OMX renamed and changed all references to the “Nominating Committee” in the By-Laws, to the “Nominating & Governance Committee” so that the title of the committee accurately reflects all of its current functions, including those that are deemed governance functions. The proposal to rename the Nominating Committee did not change the function of the committee, but was intended to clarify the current functions and its governance role with respect to the Board selection process.
Additionally, NASDAQ OMX amended Article 1, Section (o) of NASDAQ OMX's By-Laws to change the reference to “NASDAQ OMX PHLX, Inc.” to “NASDAQ OMX PHLX LLC” to reflect a recently filed rule change by NASDAQ OMX PHLX from a Delaware corporation to a Delaware limited liability company.
Finally, NASDAQ OMX added the words “and broker nonvotes” to NASDAQ OMX's By-Law Article IV, Section 4.4 to make clear that broker nonvotes will not be counted as a vote cast either “for” or “against” that director's election. In its filing to amend NASDAQ OMX's By-Laws, NASDAQ Stock Market LLC noted that NASDAQ OMX's past practice has been to not count a broker nonvote as a vote cast either for or against a director's election.
In 2010, NASDAQ OMX amended its By-Laws to state that in an uncontested election, a majority voting standard would apply to the election of its directors, requiring directors to be elected by the holders of a majority of the votes cast at any meeting for the election of directors at which a quorum is present in an uncontested election.
The Exchange believes that the proposed rule change is consistent with the provisions of Section 6 of the Act,
The Exchange believes changing the name of the Nominating Committee to the Nominating and Governance Committee and amending references to an exchange name to reflect a corporate change to a limited liability company are both clarifying in nature. The changes will ensure that the committee's title accurately reflects its functions and will ensure that the By-Laws accurately and properly reflect an exchange entity name. As discussed above, the amendment that broker nonvotes will not be counted as a vote either “for” or “against” in director elections will codify NASDAQ OMX's past practice, providing clarity and transparency. Accordingly the Exchange believes that the amendments are consistent with investor protection and the public interest.
The Exchange does not believe that the proposed rule change will impose any burden on competition not necessary or appropriate in furtherance of the purposes of the Act.
No written comments were either solicited or received.
The Exchange has filed the proposed rule change pursuant to Section 19(b)(3)(A)(iii) of the Act
A proposed rule change filed under Rule 19b-4(f)(6)
The Commission finds that waiver of the operative delay is consistent with the protection of investors and the public interest. The Commission notes in waiving the 30-day operative delay that the Commission published for comment in the
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 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”): The Meidell Tactical Advantage ETF. 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
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's investment objective is to seek to provide long-term capital appreciation with a secondary emphasis on capital preservation. The Fund is an actively managed exchange-traded fund (“ETF”) and thus does not seek to replicate the performance of a specified index. The Fund is considered a “fund-of-funds” that seeks to achieve its investment objective by primarily investing in other ETFs that offer diversified exposure to global regions, countries, styles (market capitalization, value, growth, etc.) or sectors, and other exchange-traded products (“ETPs,” and, together with ETFs, “Underlying ETPs”),
The Sub-Adviser will seek to achieve the Fund's investment objective by managing a tactical strategy that has the ability to dynamically rebalance the Fund's portfolio from as much as 100% equity-based assets to 100% fixed income-based assets or cash and cash equivalents depending on market trends. This is a long-only tactical strategy that seeks to minimize portfolio losses by rotating out of higher volatility assets and into lower volatility assets when the Sub-Adviser believes there are significant risks in the equity markets. Risk management is an integral part of the Sub-Adviser's investment strategy. The Fund will not invest in leveraged, inverse, or inverse leveraged Underlying ETPs.
The Sub-Adviser uses a quantitative tactical methodology to identify the Underlying ETPs believed to be participating in long-term “durable trends” within the market. This model enables the Sub-Adviser to evaluate, rank, and select the appropriate mix of investments in Underlying ETPs given market conditions.
The Sub-Adviser's investment philosophy emphasizes investments in broad market indexes and market sector indexes. In general, the Fund will
The Sub-Adviser uses a quantitative metric to rank and select the appropriate mix of investments given prevailing market conditions. The Sub-Adviser's quantitative tactical asset allocation model determines asset allocation between bonds and stocks, equity selection, sector concentration, as well as limiting portfolio drawdown. The general guidelines for the Fund's portfolio are as follows:
Depending on the economic and market climate, the portfolio may increase or decrease portfolio concentrations within the ranges shown below.
The Fund's portfolio may temporarily exceed these percentage ranges for short periods without notice, and the Sub-Adviser may alter the percentage ranges when it deems appropriate.
Additional quantitative tools are used to evaluate the probability of investment success within the equity market. These tools allow the Sub-Adviser to get into or out of equity positions, and include but are not limited to:
• Interest rate spreads.
• Options activity.
• Market breadth.
• Equity index trends.
The Fund intends to invest primarily in the securities of Underlying ETPs consistent with the requirements of Section 12(d)(1) of the 1940 Act, or any rule, regulation, or order of the Commission or interpretation thereof. The Fund will only make such investments in conformity with the requirements of Section 817 of the Internal Revenue Code of 1986, as amended (“Code”).
The Fund, through its investment in Underlying ETPs, may invest in equity securities. Equity securities represent ownership interests in a company or partnership and consist of common stocks, preferred stocks, warrants to acquire common stock, securities convertible into common stock, investments in master limited partnerships securities traded in the U.S. on registered exchanges or the over-the-counter market, rights, and Depositary Receipts.
The Fund, through its investments in Underlying ETPs, may invest in the equity securities of foreign issuers, including the securities of foreign issuers in emerging market countries. Emerging or developing markets exist in countries that are considered to be in the initial stages of industrialization.
The Fund, through its investment in Underlying ETPs, may invest in debt securities. A debt security is a security consisting of a certificate or other evidence of a debt (secured or unsecured) on which the issuing company or governmental body promises to pay the holder thereof a fixed, variable, or floating rate of interest for a specified length of time, and to repay the debt on the specified maturity date. Some debt securities, such as zero coupon bonds, do not make regular interest payments, but are issued at a discount to their principal or maturity value. Debt securities include a variety of fixed income obligations, including, but not limited to, corporate debt securities, government securities, municipal securities, convertible securities, and mortgage-backed securities. Debt securities include investment-grade securities, non-investment-grade securities, and unrated securities. Debt securities are subject to a variety of risks, such as interest rate risk, income risk, call/prepayment risk, inflation risk, credit risk, and currency risk.
The Fund, or the Underlying ETPs in which it invests, may invest in U.S. government securities, U.S. Treasury zero-coupon bonds, and real estate investment trusts.
To respond to adverse market, economic, political, or other conditions, the Fund may invest 100% of its total assets, without limitation, in high-quality debt securities and money market instruments either directly or through Underlying ETPs. The Fund may be invested in these instruments for extended periods, depending on the Sub-Adviser's assessment of market conditions. These debt securities and money market instruments include shares of other mutual funds, commercial paper, certificates of deposit, bankers' acceptances, U.S. Government securities, repurchase and reverse repurchase agreements,
The Fund may not (i) with respect to 75% of its total assets, purchase securities of any issuer (except securities issued or guaranteed by the U.S. Government, its agencies or instrumentalities, or shares of investment companies) if, as a result, more than 5% of its total assets would be invested in the securities of such issuer, or (ii) acquire more than 10% of the outstanding voting securities of any one issuer. For purposes of this policy, the issuer of the underlying security will be deemed to be the issuer of any respective Depositary Receipt.
The Fund may not invest 25% or more of its total assets in the securities of one or more issuers conducting their principal business activities in the same industry or group of industries. This limitation does not apply to investments in securities issued or guaranteed by the U.S. Government, its agencies or
The Fund may not purchase illiquid securities.
Except for Underlying ETPs that may hold non-U.S. issues, the Fund will not otherwise invest in non-U.S. issues.
According to the Registration Statement, the Fund will seek to qualify for treatment as a Regulated Investment Company (“RIC”) pursuant to Subchapter M under the Code.
The Fund calculates net asset value (“NAV”) by: (i) Taking the current market value of its total assets; (ii) subtracting any liabilities; and (iii) dividing that amount by the total number of Shares owned by shareholders. The NAV of the Fund will normally be determined as of the close of the regular trading session on the New York Stock Exchange (“NYSE”) (ordinarily 4:00 p.m. Eastern Time) on each business day. In calculating NAV, the Fund generally values investment portfolios at market price. If market prices are unavailable or are unreliable, or when the value of a security has been materially affected by events occurring after the relevant market closes, the Fund will price those securities at fair value as determined in good faith using methods approved by the Fund's Board of Trustees.
Creations and redemptions of Shares occur in large specified blocks of Shares, referred to as “Creation Units.” According to the Registration Statement, the Shares of the Fund are “created” at their NAV by Authorized Participants only in block-size Creation Units of 25,000 Shares or more. An Authorized Participant enters into an agreement (“Participant Agreement”) with the Fund's Distributor or a Depository Trust Company participant that has executed a Participant Agreement with the Distributor, and deposits into the Fund a portfolio of securities closely approximating the holdings of the Fund and a specified amount of cash, together totaling the NAV of the Creation Unit(s), in exchange for 25,000 Shares of the Fund (or multiples thereof). Similarly, Shares can only be redeemed in Creation Units, generally 25,000 Shares or more, principally in-kind for a portfolio of securities held by the Fund and a specified amount of cash together totaling the NAV of the Creation Unit(s). Shares are not redeemable from the Fund except when aggregated in Creation Units. The prices at which creations and redemptions occur are based on the next calculation of NAV after an order is received in a form prescribed in the Participant Agreement.
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,
The Fund'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, a basket composition file, which includes the security names and share quantities 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 National Securities Clearing Corporation. The basket represents one Creation Unit of the Fund.
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
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.
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. Eastern Time 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 Intermarket Surveillance Group (“ISG”) from other exchanges that are members of ISG or with which the Exchange has entered into 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. Eastern Time 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
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. Quotation and last-sale information for the Shares will be available via the CTA high-speed line and, for the Underlying ETPs, will be available from the national securities exchange on which they are listed. In addition, the Portfolio Indicative Value will be disseminated by the Exchange at least every 15 seconds during the Core Trading Session. The Fund's Web site will include a form of the Prospectus for the Fund that may be downloaded, as well as additional quantitative information updated on a daily basis. On each business day, before commencement of trading in Shares in the Core Trading Session on the Exchange, the Fund will disclose on its Web site the Disclosed Portfolio that will form the basis for the Fund's calculation of NAV at the end of the business day. 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 for the Fund 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. 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 additional types of actively-managed exchange-traded products 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 e-mail to rule-comments@sec.gov. Please include File Number SR-NYSEArca-2011-18 on the subject line.
• Send paper comments in triplicate to Elizabeth M. Murphy, Secretary, Securities and Exchange Commission, 100 F Street, NE., Washington DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
FINRA is proposing to amend Section 1 of Schedule A to the FINRA By-Laws to adjust the rate of FINRA's Trading Activity Fee (“TAF”) for transactions in covered equity securities.
The text of the proposed rule change is available on FINRA's Web site at
In its filing with the Commission, FINRA included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. FINRA has prepared summaries, set forth in Sections A, B, and C below, of the most significant aspects of such statements.
FINRA's primary member regulatory pricing structure consists of the following fees: The Personnel Assessment (PA); the Gross Income Assessment (GIA); and the Trading Activity Fee (TAF). These fees are used to fund FINRA's regulatory activities, including examinations; financial monitoring; and FINRA's policymaking, rulemaking, and enforcement activities.
FINRA initially adopted the TAF in 2002 as a replacement for an earlier regulatory fee based on trades reported to Nasdaq's Automated Confirmation Transaction system then in place.
The current TAF rates are $0.000075 per share for each sale of a covered equity security, with a maximum charge of $3.75 per trade; $0.002 per contract for each sale of an option; $0.04 per contract for each round turn transaction of a security future; and $0.00075 per bond for each sale of a covered TRACE-Eligible Security and/or municipal security, with a maximum charge of $0.75 per trade. In addition, if the execution price for a covered security is less than the TAF rate on a per share, per contract, or round turn transaction basis, then no TAF is assessed.
The current TAF rate for covered equity securities of $0.000075 per share has been in place for over six years.
As FINRA noted when it restructured the GIA and the PA, because the GIA is assessed based on a member's annual gross revenue for the preceding calendar year, FINRA's revenues derived from the GIA are subject to the year-to-year volatility of members' revenues. A similar unpredictability of revenue flows exists with the TAF. The TAF generally is assessed on sales of securities by members and is collected from clearing firms on a monthly basis. Although the TAF is generally charged on transactions in equity securities, TRACE-reportable securities, options, and futures, over 95% of TAF revenue is generated by transactions in covered equity securities. Thus, FINRA's revenue from the TAF is substantially affected by changes in trading volume in the equities markets. Because of the substantial decrease in average daily share volumes (ADSV) since 2009, FINRA has seen a commensurate substantial decline in revenue from the TAF.
To stabilize revenue flows necessary to support FINRA's regulatory mission, FINRA is proposing an increase to the
The effective date of the proposed rule change will be July 1, 2011. FINRA will announce the effective date of the proposed rule change in a
FINRA believes that the proposed rule change is consistent with the provisions of Section 15A(b)(5) of the Act,
FINRA does not believe that the proposed rule change will result in any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act.
Written comments were neither solicited nor received.
Within 45 days of the date of publication of this notice in the
(a) By order approve or disapprove such proposed rule change, or
(b) Institute proceedings to determine whether the proposed rule change should be disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an 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.
All submissions should refer to File Number SR-FINRA-2011-020. This file number should be included on the subject line if e-mail is used. To help the Commission process and review your comments more efficiently, please use only one method. The Commission will post all comments on the Commission's Internet Web site (
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1)
The Exchange proposes to amend Rule 440B (Short Sales) to modify the Exchange's procedures for early termination of the short sale price test restrictions of Rule 201 of Regulation SHO (“Rule 201”)
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.
On February 26, 2010, the Commission adopted amendments to Rule 201.
Under Rule 440B(c), when the Exchange is the listing market for a covered security, Exchange systems will determine whether the short sale price test restrictions of Rule 201 have been triggered (
If, however, the Exchange determines that the short sale price test for a covered security was triggered because of a clearly erroneous execution on the Exchange,
For securities for which the Exchange is the listing market, Exchange Rule 440B currently addresses only clearly erroneous triggering transactions deemed to be clearly erroneous executions under the Exchange's rules, and does not address situations where another exchange or a SRO determines, under its respective rules, that a triggering transaction was a clearly erroneous execution. To address this scenario, the Exchange proposes to amend Rule 440B(d)(1) to provide that the Exchange may also lift the short sale price test restrictions before the Short Sale Period ends, for covered securities for which the Exchange is the listing market, if the Exchange has been informed by another exchange or a SRO that a transaction in the covered security that occurred at the Trigger Price
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 that is not necessary or appropriate in furtherance of the purposes of the Act.
No written comments were solicited or received with respect to the proposed rule change.
The Exchange has filed the proposed rule change pursuant to Section 19(b)(3)(A)(iii) of the Act
A proposed rule change filed under Rule 19b-4(f)(6)
The Commission has considered the Exchange's request to waive the 30-day operative delay, and hereby grants the request. The Commission believes that waiving the 30-day operative delay is consistent with the protection of investors and the public interest, as it will permit the Exchange to lift Rule 201's short sale price test restrictions, in a covered security for which the Exchange is the listing market, when such restrictions were triggered by a transaction that another exchange or a SRO has determined to be a clearly erroneous execution, pursuant to the rules of that exchange or SRO.
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 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.
All submissions should refer to File Number SR-NYSE-2011-19. This file number should be included on the subject line if e-mail is used. To help the Commission process and review your comments more efficiently, please use only one method. The Commission will post all comments on the Commission's Internet Web site (
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1)
The Exchange proposes to amend NYSE Amex Equities Rule 440B (Short Sales) to modify the Exchange's procedures for early termination of the short sale price test restrictions of Rule 201 of Regulation SHO (“Rule 201”)
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.
On February 26, 2010, the Commission adopted amendments to Rule 201.
Under NYSE Amex Equities Rule 440B(c), when the Exchange is the listing market for a covered security, Exchange systems will determine whether the short sale price test restrictions of Rule 201 have been triggered (i.e., that a covered security has experienced a decrease in price of 10% or more from the security's closing price as of the end of regular trading hours on the prior day) and will notify the single plan processor responsible for consolidation of information for the covered security pursuant to Rule 603(b) of Regulation NMS.
If, however, the Exchange determines that the short sale price test for a covered security was triggered because of a clearly erroneous execution on the Exchange,
For securities for which the Exchange is the listing market, Exchange Rule 440B currently addresses only clearly erroneous triggering transactions deemed to be clearly erroneous executions under the Exchange's rules, and does not address situations where another exchange or a SRO determines, under its respective rules, that a triggering transaction was a clearly erroneous execution. To address this scenario, the Exchange proposes to amend NYSE Amex Equities Rule 440B(d)(1) to provide that the Exchange may also lift the short sale price test restrictions before the Short Sale Period ends, for covered securities for which the Exchange is the listing market, if the Exchange has been informed by another exchange or a SRO that a transaction in the covered security that occurred at the Trigger Price
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 that is not necessary or appropriate in furtherance of the purposes of the Act.
No written comments were solicited or received with respect to the proposed rule change.
The Exchange has filed the proposed rule change pursuant to Section 19(b)(3)(A)(iii) of the Act
A proposed rule change filed under Rule 19b-4(f)(6)
The Commission has considered the Exchange's request to waive the 30-day operative delay, and hereby grants the request. The Commission believes that waiving the 30-day operative delay is consistent with the protection of investors and the public interest, as it will permit the Exchange to lift Rule 201's short sale price test restrictions, in a covered security for which the Exchange is the listing market, when such restrictions were triggered by a transaction that another exchange or a SRO has determined to be a clearly erroneous execution, pursuant to the rules of that exchange or SRO.
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 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”),
The Exchange proposes to file a rule change related to the By-Laws of its parent corporation, The NASDAQ OMX Group, Inc. (“NASDAQ OMX”). The text of the proposed rule change is available on the Exchange's Web site at
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
NASDAQ OMX recently made certain clarifying amendments to its By-Laws.
NASDAQ OMX By-Laws previously provided for a Nominating Committee which is appointed pursuant to the By-Laws. In addition to the responsibilities listed in By-Law Article IV, Section 4.13(h), the Nominating Committee also conducts certain governance functions such as consulting with the Board and the management to determine the characteristics, skills and experience desired for the Board as a whole and for its individual members, overseeing the annual director evaluation, and reviewing the overall effectiveness of the Board. Accordingly, NASDAQ OMX renamed and changed all references to the “Nominating Committee” in the By-Laws, to the “Nominating & Governance Committee” so that the title of the committee accurately reflects all of its current functions, including those that are deemed governance functions. The proposal to rename the Nominating Committee did not change the function of the committee, but was intended to clarify the current functions and its governance role with respect to the Board selection process.
Additionally, NASDAQ OMX amended Article 1, Section (o) of NASDAQ OMX's By-Laws to change the reference to “NASDAQ OMX PHLX, Inc.” to “NASDAQ OMX PHLX LLC” to reflect a recently filed rule change by the Exchange from a Delaware corporation to a Delaware limited liability company.
Finally, NASDAQ OMX added the words “and broker nonvotes” to NASDAQ OMX's By-Law Article IV, Section 4.4 to make clear that broker nonvotes will not be counted as a vote cast either “for” or “against” that director's election. In its filing to amend NASDAQ OMX's By-Laws, NASDAQ Stock Market LLC noted that NASDAQ OMX's past practice has been to not count a broker nonvote as a vote cast either for or against a director's election.
In 2010, NASDAQ OMX amended its By-Laws to state that in an uncontested election, a majority voting standard would apply to the election of its directors, requiring directors to be elected by the holders of a majority of the votes cast at any meeting for the election of directors at which a quorum is present in an uncontested election.
The Exchange believes that the proposed rule change is consistent with the provisions of Section 6 of the Act,
The Exchange believes changing the name of the Nominating Committee to the Nominating and Governance Committee and amending references to an exchange name to reflect a corporate change to a limited liability company are both clarifying in nature. The changes will ensure that the committee's title accurately reflects its functions and will ensure that the By-Laws accurately and properly reflect an exchange entity name. As discussed above, the amendment that broker nonvotes will not be counted as a vote either “for” or “against” in director elections will codify NASDAQ OMX's past practice, providing clarity and transparency. Accordingly the Exchange believes that the amendments are consistent with investor protection and the public interest.
The Exchange does not believe that the proposed rule change will impose any burden on competition not necessary or appropriate in furtherance of the purposes of the Act.
No written comments were either solicited or received.
The Exchange has filed the proposed rule change pursuant to Section 19(b)(3)(A)(iii) of the Act
A proposed rule change filed under Rule 19b-4(f)(6)
The Commission finds that waiver of the operative delay is consistent with the protection of investors and the public interest. The Commission notes in waiving the 30-day operative delay that the Commission published for comment in the
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 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.
All submissions should refer to File Number SR-Phlx-2011-54. This file number should be included on the subject line if e-mail is used. To help the Commission process and review your comments more efficiently, please use only one method. The Commission will post all comments on the Commission's Internet Web site
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”),
The NASDAQ Stock Market LLC proposes to file a rule change related to the By-Laws of its parent corporation, The NASDAQ OMX Group, Inc. (“NASDAQ OMX”). The text of the proposed rule change is available on the Exchange's Web site at
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
NASDAQ OMX recently made certain clarifying amendments to its By-Laws.
NASDAQ OMX By-Laws previously provided for a Nominating Committee which is appointed pursuant to the By-Laws. In addition to the responsibilities listed in By-Law Article IV, Section 4.13(h), the Nominating Committee also conducts certain governance functions such as consulting with the Board and the management to determine the characteristics, skills and experience desired for the Board as a whole and for its individual members, overseeing the annual director evaluation, and reviewing the overall effectiveness of the Board. Accordingly, NASDAQ OMX renamed and changed all references to the “Nominating Committee” in the By-Laws, to the “Nominating & Governance Committee” so that the title of the committee accurately reflects all of its current functions, including those that are deemed governance functions. The proposal to rename the Nominating Committee did not change the function of the committee, but was intended to clarify the current functions and its governance role with respect to the Board selection process.
Additionally, NASDAQ OMX amended Article 1, Section (o) of NASDAQ OMX's By-Laws to change the reference to “NASDAQ OMX PHLX, Inc.” to “NASDAQ OMX PHLX LLC” to reflect a recently filed rule change by NASDAQ OMX PHLX from a Delaware corporation to a Delaware limited liability company.
Finally, NASDAQ OMX added the words “and broker nonvotes” to NASDAQ OMX's By-Law Article IV, Section 4.4 to make clear that broker nonvotes will not be counted as a vote cast either “for” or “against” that director's election. In its filing to amend NASDAQ OMX's By-Laws, NASDAQ noted that NASDAQ OMX's past practice has been to not count a broker nonvote as a vote cast either for or against a director's election.
In 2010, NASDAQ OMX amended its By-Laws to state that in an uncontested election, a majority voting standard would apply to the election of its directors, requiring directors to be elected by the holders of a majority of the votes cast at any meeting for the election of directors at which a quorum is present in an uncontested election.
The Exchange believes that the proposed rule change is consistent with the provisions of Section 6 of the Act,
The Exchange believes changing the name of the Nominating Committee to the Nominating and Governance Committee and amending references to an exchange name to reflect a corporate change to a limited liability company are both clarifying in nature. The changes will ensure that the committee's title accurately reflects its functions and will ensure that the By-Laws accurately and properly reflect an exchange entity name. As discussed above, the amendment that broker nonvotes will not be counted as a vote either “for” or “against” in director elections will codify NASDAQ OMX's past practice, providing clarity and transparency. Accordingly the Exchange believes that the amendments are consistent with investor protection and the public interest.
The Exchange does not believe that the proposed rule change will impose any burden on competition not necessary or appropriate in furtherance of the purposes of the Act.
No written comments were either solicited or received.
The Exchange has filed the proposed rule change pursuant to Section 19(b)(3)(A)(iii) of the Act
A proposed rule change filed under Rule 19b-4(f)(6)
The Commission finds that waiver of the operative delay is consistent with the protection of investors and the public interest. The Commission notes in waiving the 30-day operative delay that the Commission published for comment in the
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 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 (the “Act”)
The Exchange is filing with the Commission a proposal to amend Phlx Rule 1001 (Position Limits) to increase the position limit for options on the Standard and Poor's Depositary Receipts (“SPDRs®”).
The text of the proposed rule change is available on the Exchange's Web site at
In its filing with the Commission, the self-regulatory organization included statements concerning the purpose of, and basis for, the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
The purpose of the proposal is to amend Rule 1001 to increase the position limit applicable to options on SPDRs®, which are trading under the symbol SPY, from 300,000 to 900,000 contracts on the same side of the market.
The Exchange began trading options on SPDRs® on the Exchange's electronic trading platform for options, Phlx XL, on January 10, 2005. That year, the position limit for these options was increased to the current limit of 300,000 contracts on the same size of the market, and has remained unchanged.
Currently, SPY options have a position limit of only 300,000 contracts on the same side on the market while the significantly lesser-volume QQQ
First, traders have informed the Exchange that the current SPY option position limit of 300,000 contracts, which has remained flat for more than five years despite the tremendous trading volume increase, is no longer sufficient for optimal trading and hedging purposes. SPY options are, as noted, used by large institutions and traders as a means to invest in or hedge the overall direction of the market. Second, options on SPDRs® are 1/10th the size of options on the S&P 500® Index, traded under the symbol SPX. Thus, a position limit of 300,000 contracts in options on SPDRs® is equivalent to a 30,000 contract position limit in options on SPX.
The volume and notional value of options on SPDRs® and QQQ
The options reporting requirement would continue unabated. Thus, the Exchange would require that, just like for options on QQQ
The Exchange believes that position and exercise limits, at their current levels, no longer serve their stated purpose. There has been a steadfast and significant increase over the last decade in the overall volume of exchange-traded options; position limits, however, have not kept up with the volume. Part of this volume is attributable to a corresponding increase in the number of overall market participants, which has, in turn, brought about additional depth and increased liquidity in exchange-traded options.
As the anniversary of listed options trading approaches its fortieth year, the Exchange believes that the existing surveillance procedures and reporting requirements at Phlx, other options exchanges, and at the several clearing firms are capable of properly identifying unusual and/or illegal trading activity. In addition, routine oversight inspections of the Exchange's regulatory programs by the Commission have not uncovered any material inconsistencies or shortcomings in the manner in which the Exchange's market surveillance is conducted. These procedures utilize daily monitoring of market movements via automated surveillance techniques to identify unusual activity in both options and underlying stocks.
Furthermore, large stock holdings must be disclosed to the Commission by way of Schedules 13D or 13G.
The Exchange believes that the current financial requirements imposed by the Exchange and by the Commission adequately address concerns that a member or its customer may try to maintain an inordinately large unhedged position in an option, particularly on SPDRs®. Current margin and risk-based haircut methodologies serve to limit the size of positions maintained by any one account by increasing the margin and/or capital that a member must maintain for a large position held by itself or by its customer. It should also be noted that the Exchange has the authority under Exchange Rule 722(c)(3) to impose a higher margin requirement upon a member or member organization when the Exchange determines a higher requirement is warranted. In addition, the Commission's net capital rule, Rule 15c3-1 under the Act,
Finally, the Exchange believes that while position limit on options on QQQs
The Exchange believes that restrictive option position limits prevent large customers, such as mutual funds and pension funds, from using options to gain meaningful exposure to and hedging protection through the use of options on SPDRs®. This can result in lost liquidity in both the options market and the equity market. The proposed position limit increase will remedy this situation to the benefit of large as well as retail traders, investors, and public customers. The Exchange believes that increasing position and exercise limits for options on would lead to a more liquid and competitive market environment for options on SPDRs® that would benefit customers interested in this product.
The Exchange believes that its proposal is consistent with Section 6(b)
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.
Within 45 days of the date of publication of this notice in the
(A) By order approve or disapprove the 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 e-mail to
• Send paper comments in triplicate to Elizabeth M. Murphy, Secretary, Securities and Exchange Commission, Station Place, 100 F Street, NE., Washington, DC 20549-1090.
All submissions should refer to File Number SR-Phlx-2011-58. This file number should be included on the subject line if e-mail is used. To help the Commission process and review your comments more efficiently, please use only one method. The Commission will post all comments on the Commission's Internet Web site (
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1)
The Exchange proposes to amend NYSE Arca Equities Rule 7.16 (Short Sales) to modify the Exchange's procedures for early termination of the short sale price test restrictions of Rule 201 of Regulation SHO (“Rule 201”)
In its filing with the Commission, the self-regulatory organization included statements concerning the purpose of, and basis for, the proposed rule change
On February 26, 2010, the Commission adopted amendments to Rule 201.
Under NYSE Arca Equities Rule 7.16(f)(iii), when the Exchange is the listing market for a covered security, Exchange systems will determine whether the short sale price test restrictions of Rule 201 have been triggered (i.e., that a covered security has experienced a decrease in price of 10% or more from the security's closing price as of the end of regular trading hours on the prior day) and will notify the single plan processor responsible for consolidation of information for the covered security pursuant to Rule 603(b) of Regulation NMS.
If, however, the Exchange determines that the short sale price test for a covered security was triggered because of a clearly erroneous execution on the Exchange,
For securities for which the Exchange is the listing market, NYSE Arca Equities Rule 7.16 currently addresses only clearly erroneous triggering transactions deemed to be clearly erroneous executions under the Exchange's rules, and does not address situations where another exchange or a SRO determines, under its respective rules, that a triggering transaction was a clearly erroneous execution. To address this scenario, the Exchange proposes to amend NYSE Arca Equities Rule 7.16(f)(iv)(A)
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 that is not necessary or appropriate in furtherance of the purposes of the Act.
No written comments were solicited or received with respect to the proposed rule change.
The Exchange has filed the proposed rule change pursuant to Section 19(b)(3)(A)(iii) of the Act
A proposed rule change filed under Rule 19b-4(f)(6)
The Commission has considered the Exchange's request to waive the 30-day operative delay, and hereby grants the request. The Commission believes that waiving the 30-day operative delay is consistent with the protection of investors and the public interest, as it will permit the Exchange to lift Rule 201's short sale price test restrictions, in a covered security for which the Exchange is the listing market, when such restrictions were triggered by a transaction that another exchange or a SRO has determined to be a clearly erroneous execution, pursuant to the rules of that exchange or SRO.
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 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.
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 May 3, 2011.
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 Stanley S. Colvin, Deputy Assistant Secretary for Private Sector Exchange, U.S. Department of State, SA-5, Floor 5, 2200 C Street, NW., Washington, DC 20522; or e-mail 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 collection is the continuation of information collected and needed by the Bureau of Educational and Cultural Affairs in administering the Exchange Visitor Program (J-Visa) under the provisions of the Mutual Educational and Cultural Exchange Act, as amended.
Access to Form DS-2019 is made available to Department designated sponsors electronically via the Student and Exchange Visitor Information System (SEVIS).
Federal Aviation Administration (FAA), DOT.
Notice of RTCA Special Committee 203 meeting: Unmanned Aircraft Systems.
The FAA is issuing this notice to advise the public of a meeting of RTCA Special Committee 203: Unmanned Aircraft Systems.
The meeting will be held May 17-19, 2011, from 9 a.m. to 5 p.m., unless stated otherwise in agenda.
The meeting will be held at RTCA, Inc., Conference Rooms, 1828 L Street, NW., Suite 805, Washington, DC 20036.
RTCA Secretariat, 1828 L Street, NW., Suite 805, Washington, DC, 20036, telephone (202) 833-9339, fax (202) 833-9434, Web site
Pursuant to section 10(a) (2) of the Federal Advisory Committee Act (Pub. L. 92-463, 5 U.S.C., and Appendix 2), notice is hereby given for a Special Committee 203, Unmanned Aircraft Systems.
Attendance is open to the interested public but limited to space availability. With the approval of the chairman, members of the public may present oral statements at the meeting. Persons wishing to present statements or obtain information should contact the person listed in the
National Highway Traffic Safety Administration (NHTSA), Department of Transportation.
Request for extension of a currently approved collection of information.
This document solicits public comments on continuation of the requirements for the collection of information entitled “Motorcycle Helmet Labeling” (OMB Control Number: 2127-0518).
Before a Federal agency can collect certain information from the public, it must receive approval from the Office of Management and Budget (OMB). Under procedures established by the Paperwork Reduction Act of 1995, before seeking OMB approval, Federal agencies must solicit public comment on proposed collections of information, including extensions and reinstatement of previously approved collections.
You should submit your comments early enough to ensure that Docket Management receives them no later than July 5, 2011.
You may submit comments (identified by the DOT Docket ID Number above) by any of the following methods:
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You may call the Docket at (202) 366-9324.
Regardless of how you submit your comments, you should mention the docket number of this document. Please identify the proposed collection of information for which a comment is provided, by referencing its OMB clearance number. It is requested, but not required, that two copies of the comment be provided.
Note that all comments received will be posted without change to
Complete copies of each request for collection of information may be obtained at no charge from Ms. Shashi Kuppa, U.S. Department of Transportation, NHTSA, 1200 New Jersey Avenue, SE., West Building Room W43-313, NVS-113, Washington, DC 20590. Ms. Kuppa's telephone number is (202) 366-3827 and fax number is (202) 366-7002. Please identify the relevant collection of information by referring to its OMB Control Number.
Under the Paperwork Reduction Act of 1995, before an agency submits a proposed collection of information to OMB for approval, it must first publish a document in the
(i) Whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
(ii) The accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
(iii) How to enhance the quality, utility, and clarity of the information to be collected;
(iv) How to minimize the burden of the collection of information on those who are to respond, including the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology, e.g. permitting electronic submission of responses.
In compliance with these requirements, NHTSA asks for public comments on the following proposed collections of information:
(1)
Using this authority, the agency issued the initial FMVSS No. 218, “Motorcycle helmets,” in 1974. Motorcycle helmets are devices used to protect motorcyclists from head injury in motor vehicle crashes. FMVSS No. 218 S5.6 requires that each helmet shall be labeled permanently and legibly in a manner such that the label(s) can be read easily without removing padding or any other permanent part.
44 U.S.C. 3506(c); delegation of authority at 49 CFR 1.50.
National Highway Traffic Safety Administration (NHTSA), Department of Transportation.
Notice.
In compliance with the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
Comments must be submitted on or before June 2, 2011.
George Stevens, NHTSA 1200 New Jersey Avenue, SE., Room W43-490, Washington, DC 20590. Mr. Stevens' telephone number is (202) 366-5308. Please identify the relevant collection of information by referring to its OMB Control Number.
Send comments, within 30 days, to the Office of Information and Regulatory Affairs, Office of Management and Budget, 725-17th Street, NW., Washington, DC 20503, Attention NHTSA Desk Officer.
A comment to OMB is most effective if OMB receives it within 30 days of publication.
The Surface Transportation Board has received a request from Mayer Brown LLP as outside counsel for BNSF Railway Company (WB461-17 (2)—04/26/11) for permission to use data from all fields from the Board's 1999 through 2009 Carload Waybill Samples. A copy of this request may be obtained from the Office of Economics.
The waybill sample contains confidential railroad and shipper data; therefore, if any parties object to these requests, they should file their objections with the Director of the Board's Office of Economics within 14 calendar days of the date of this notice. The rules for release of waybill data are codified at 49 CFR 1244.9.
Notice.
Pursuant to United States Code, Title 31, section 5135(b)(8)(C), the United States Mint announces the Citizens Coinage Advisory Committee (CCAC) public meeting scheduled for May 25, 2011.
• Advises the Secretary of the Treasury on any theme or design proposals relating to circulating coinage, bullion coinage, Congressional Gold Medals, and national and other medals.
• Advises the Secretary of the Treasury with regard to the events, persons, or places to be commemorated by the issuance of commemorative coins in each of the five calendar years succeeding the year in which a commemorative coin designation is made.
• Makes recommendations with respect to the mintage level for any commemorative coin recommended.
Greg Weinman, Acting United States Mint Liaison to the CCAC; 801 9th Street, NW.; Washington, DC 20220; or call 202-354-7200.
Any member of the public interested in submitting matters for the CCAC's consideration is invited to submit them by fax to the following number: 202-756-6525.
31 U.S.C. 5135(b)(8)(C).
United States Sentencing Commission.
Notice of (1) submission to Congress of amendments to the sentencing guidelines effective November 1, 2011; and (2) request for comment.
The United States Sentencing Commission hereby gives notice of the following actions:
(1) Pursuant to its authority under 28 U.S.C. 994(p), the Commission has promulgated amendments to the sentencing guidelines, policy statements, commentary, and statutory index. This notice sets forth the amendments and the reason for each amendment.
(2) Amendment 2, pertaining to drug offenses, has the effect of lowering guideline ranges. The Commission requests comment regarding whether that amendment should be included in subsection (c) of § 1B1.10 (Reduction in Term of Imprisonment as a Result of Amended Guideline Range (Policy Statement)) as an amendment that may be applied retroactively to previously sentenced defendants. This notice sets forth the request for comment.
The Commission has specified an effective date of November 1, 2011, for the amendments set forth in this notice. Public comment regarding whether Amendment 2, pertaining to drug offenses, should be included as an amendment that may be applied retroactively to previously sentenced defendants should be received on or before June 2, 2011.
Comments should be sent to: United States Sentencing Commission, One Columbus Circle, NE., Suite 2-500, South Lobby, Washington, DC 20002-8002,
Jeanne Doherty, Office of Legislative and Public Affairs, 202-502-4502. The amendments and the request for comment set forth in this notice also may be accessed through the Commission's Web site at
The United States Sentencing Commission is an independent agency in the judicial branch of the United States Government. The Commission promulgates sentencing guidelines and policy statements for federal sentencing courts pursuant to 28 U.S.C. 994(a). The Commission also periodically reviews and revises previously promulgated guidelines pursuant to 28 U.S.C. 994(o) and generally submits guideline amendments to Congress pursuant to 28 U.S.C. 994(p) not later than the first day of May each year. Absent action of Congress to the contrary, submitted amendments become effective by operation of law on the date specified by the Commission (generally November 1 of the year in which the amendments are submitted to Congress).
(1) Submission to Congress of Amendments to the Sentencing Guidelines
Notice of proposed amendments was published in the
(2) Request for Comment on Amendment 2, Pertaining to Drug Offenses
Section 3582(c)(2) of title 18, United States Code, provides that “in the case of a defendant who has been sentenced to a term of imprisonment based on a sentencing range that has subsequently been lowered by the Sentencing Commission pursuant to 28 U.S.C. 994(o), upon motion of the defendant or the Director of the Bureau of Prisons, or on its own motion, the court may reduce the term of imprisonment, after considering the factors set forth in section 3553(a) to the extent that they are applicable, if such a reduction is consistent with applicable policy statements issued by the Sentencing Commission.”
The Commission lists in § 1B1.10(c) the specific guideline amendments that the court may apply retroactively under 18 U.S.C. 3582(c)(2). The background commentary to § 1B1.10 lists the purpose of the amendment, the magnitude of the change in the guideline range made by the amendment, and the difficulty of applying the amendment retroactively to determine an amended guideline range under § 1B1.10(b) as among the factors the Commission considers in selecting the amendments included in § 1B1.10(c). To the extent practicable, public comment should address each of these factors.
28 U.S.C. § 994(a), (o), (p), and (u); USSC Rules of Practice and Procedure 4.1, 4.3.
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“(8) If (A) the defendant was convicted of a Federal health care offense involving a Government health care program; and (B) the loss under subsection (b)(1) to the Government health care program was (i) more than $1,000,000, increase by 2 levels; (ii) more than $7,000,000, increase by 3 levels; or (iii) more than $20,000,000, increase by 4 levels.”.
Section 2B1.1(b) is amended in subdivision (15), as redesignated by this amendment, by striking “(14)” and inserting “(15)”.
The Commentary to § 2B1.1 captioned “Application Notes” is amended in Note 1 by inserting after the paragraph that begins “ ‘Equity securities’ ” the following:
“ ‘Federal health care offense’ has the meaning given that term in 18 U.S.C. 24.”; and by inserting after the
“ ‘Government health care program’ means any plan or program that provides health benefits, whether directly, through insurance, or otherwise, which is funded directly, in whole or in part, by federal or state government. Examples of such programs are the Medicare program, the Medicaid program, and the CHIP program.”.
The Commentary to § 2B1.1 captioned “Application Notes” is amended in Note 3(F) by adding at the end the following:
“(viii)
The Commentary to § 2B1.1 captioned “Application Notes” is amended in Note 7 by striking “(8)” and inserting “(9)” each place it appears;
In Note 8 by striking “(9)” and inserting “(10)” each place it appears;
In Note 9 by striking “(10)” and inserting “(11)” each place it appears;
In Note 10 by striking “(12)” and inserting “(13)” in both places;
In Note 11 and Note 12 by striking “(14)” and inserting “(15)” each place it appears;
In Note 13 by striking “(16)” and inserting “(17)” each place it appears and by striking “(14)” and inserting “(15)” in both places;
In Note 14 by striking “(b)(17)” and inserting “(b)(18)” each place it appears;
In Note 19 by striking “(16)” and inserting “(17)” and by striking “(11)” and inserting “(12)”.
The Commentary to § 2B1.1 captioned “Background” is amended by inserting after the paragraph that begins “Subsection (b)(6)” the following:
“Subsection (b)(8) implements the directive to the Commission in section 10606 of Public Law 111-148.”.
The Commentary to § 2B1.1 captioned “Background” is amended in the paragraph that begins “Subsection (b)(8)(D)” by striking “(8)” and inserting “(9)”;
In the paragraph that begins “Subsection (b)(9)” by striking “(9)” and inserting “(10)”;
In the paragraph that begins “Subsections (b)(10)(A)(i)” by striking “(10)” and inserting “(11)”;
In the paragraph that begins “Subsection (b)(10)(C)” by striking “(10)” and inserting “(11)”;
In the paragraph that begins “Subsection (b)(11)” by striking “(11)” and inserting “(12)”;
In the paragraph that begins “Subsection (b)(13)(B)” by striking “(13)” and inserting “(14)”;
In the paragraph that begins “Subsection (b)(14)(A)” by striking “(14)” and inserting “(15)”;
In the paragraph that begins “Subsection (b)(14)(B)(i)” by striking “(14)” and inserting “(15)”;
In the paragraph that begins “Subsection (b)(15)” by striking “(15)” and inserting “(16)”; and
In the paragraph that begins “Subsection (b)(16)” by striking “(16)” and inserting “(17)” in both places.
The Commentary to § 3B1.2 captioned “Application Notes” is amended in Note 3(A) by adding at the end the following:
“Likewise, a defendant who is accountable under § 1B1.3 for a loss amount under § 2B1.1 (Theft, Property Destruction, and Fraud) that greatly exceeds the defendant's personal gain from a fraud offense and who had limited knowledge of the scope of the scheme is not precluded from consideration for an adjustment under this guideline. For example, a defendant in a health care fraud scheme, whose role in the scheme was limited to serving as a nominee owner and who received little personal gain relative to the loss amount, is not precluded from consideration for an adjustment under this guideline.”.
Appendix A (Statutory Index) is amended by inserting after the line referenced to 12 U.S.C. 4641 the following:
“12 U.S.C. 5382 2H3.1”;
By inserting after the in the line referenced to 15 U.S.C. 78u(c) the following:
“15 U.S.C. 78jjj(c)(1),(2) 2B1.1
15 U.S.C. 78jjj(d) 2B1.1”;
In the line referenced to 29 U.S.C. 1131 by inserting “(a)” after “1131”; and
By inserting after the line referenced to 29 U.S.C. § 1141 the following:
“29 U.S.C. 1149 2B1.1”.
Section 10606(a)(2)(B) of the Patient Protection Act directed the Commission to—
Section 10606(a)(2)(C) directed the Commission to amend the guidelines to provide—
(i) a 2-level increase in the offense level for any defendant convicted of a Federal health care offense relating to a Government health care program which involves a loss of not less than $1,000,000 and less than $7,000,000;
(ii) a 3-level increase in the offense level for any defendant convicted of a Federal health care offense relating to a Government health care program which involves a loss of not less than $7,000,000 and less than $20,000,000;
(iii) a 4-level increase in the offense level for any defendant convicted of a Federal health care offense relating to a Government health care program which involves a loss of not less than $20,000,000; and
(iv) if appropriate, otherwise amend the Federal Sentencing Guidelines and policy statements applicable to persons convicted of Federal health care offenses involving Government health care programs.
Section 10606(a)(3) required the Commission, in carrying out the directive, to “ensure reasonable consistency with other relevant directives and with other guidelines” and to “account for any aggravating or mitigating circumstances that might justify exceptions,” among other requirements.
The amendment implements the directive by adding two provisions to § 2B1.1 (Theft, Property Destruction, and Fraud), both of which apply to cases in which “the defendant was convicted of a Federal health care offense involving a Government health care program”.
The first provision is a new tiered enhancement at subsection (b)(8) that applies in such cases (
The second provision is a new special rule in Application Note 3(F) for determining intended loss in a case in which the defendant is convicted of a Federal health care offense involving a Government health care program. The special rule provides that, in such a case, “the aggregate dollar amount of fraudulent bills submitted to the Government health care program shall constitute prima facie evidence of the amount of the intended loss,
The amendment also adds definitions to the commentary in § 2B1.1 for the terms “Federal health care offense” and “Government health care program”. “Federal health care offense” is defined to have the meaning given that term in 18 U.S.C. 24, as required by section 10606(a)(1) of the Patient Protection Act. “Government health care program” is defined to mean “any plan or program that provides health benefits, whether directly, through insurance, or otherwise, which is funded directly, in whole or in part, by federal or state government.” The amendment lists the Medicare program, the Medicaid program, and the CHIP program as examples of such programs. The Commission adopted this definition because health care fraud involving federally funded programs and health care fraud involving state-funded programs are similar offenses, committed in similar ways and posing similar harms to the taxpaying public. In addition, defining “Government health care program” in this manner avoids application difficulties likely to arise from a narrower definition that would require the disaggregation of losses program by program in cases in which the defendant defrauded both federal and state health care programs. Finally, the statutory language in the directive indicates congressional concern with health care fraud that adversely affects the public fisc beyond health care programs funded solely with federal funds.
Finally, the amendment amends Application Note 3(A) to § 3B1.2 (Mitigating Role) to make clear that a defendant who is accountable under § 1B1.3 (Relevant Conduct) for a loss amount under § 2B1.1 that greatly exceeds the defendant's personal gain from a fraud offense, and who had limited knowledge of the scope of the scheme, is not precluded from consideration for a mitigating role adjustment. The amended commentary provides as an example “a defendant in a health care fraud scheme, whose role in the scheme was limited to serving as a nominee owner and who received little personal gain relative to the loss amount”. This part of the amendment is consistent with the directive in section 10606(a)(3)(D) of the Patient Protection Act that the Commission should “account for any aggravating or mitigating circumstances that might justify exceptions” to the new tiered enhancement.
In addition to responding to the directives, the amendment amends Appendix A (Statutory Index) to include offenses created by both the Patient Protection Act and the Dodd-Frank Act.
The Patient Protection Act created a new offense at 29 U.S.C. 1149 that prohibits making a false statement in connection with the marketing or sale of a multiple employer welfare arrangement under the Employee Retirement Income Security Act. Pursuant to 29 U.S.C. § 1131(b), a person who commits this new offense is subject to a term of imprisonment of not more than 10 years. The amendment references the new offense at 29 U.S.C. 1149 to 2B1.1 because the offense has fraud or misrepresentation as a element of the offense. As a clerical change, the amendment also amends Appendix A (Statutory Index) to make clear that 29 U.S.C. 1131(a), not the new § 1131(b), is referenced to § 2E5.3 (False Statements and Concealment of Facts in Relation to Documents Required by the Employee Retirement Income Security Act; Failure to Maintain and Falsification of Records Required by the Labor Management Reporting and Disclosure Act; Destruction and Failure to Maintain Corporate Audit Records).
The Dodd-Frank Act created two new offenses, 12 U.S.C. 5382 and 15 U.S.C. 78jjj(d). With regard to 12 U.S.C. 5382, under authority granted by sections 202-203 of the Dodd-Frank Act, the Secretary of the Treasury may make a “systemic risk determination” concerning a financial company and, if the company fails the determination, may commence the orderly liquidation of the company by appointing the Federal Deposit Insurance Corporation as receiver. Before making the appointment, the Secretary must either obtain the consent of the company or petition under seal for approval by a federal district court. The Dodd-Frank Act makes it a crime, codified at 12 U.S.C. 5382, to recklessly disclose a systemic risk determination or the pendency of court proceedings on such a petition. A person who violates 12 U.S.C. 5382 is subject to imprisonment for not more than five years. The amendment references 12 U.S.C. 5382 to 2H3.1 (Interception of Communications; Eavesdropping; Disclosure of Certain Private or Protected Information). Section 2H3.1 covers several criminal statutes with similar elements and the same maximum term of imprisonment.
The second new offense, 15 U.S.C. 78jjj(d), makes it a crime for a person to falsely represent that he or she is a member of the Security Investor Protection Corporation or that any person or account is protected or eligible for protection under the Security Investor Protection Act.
2.
The Drug Quantity Table in § 2D1.1(c) and Note 10 of the Commentary to § 2D1.1 captioned “Application Notes” are repromulgated without change.
All provisions of § 2D1.1 not repromulgated by Part A of this amendment are repromulgated without change, except as follows:
The Commentary to § 2D1.1 captioned “Application Notes” is amended by striking Note 28 as follows:
“28.
Among the factors the court should consider in determining whether the defendant ‘maintained’ the premises are (A) whether the defendant held a possessory interest in (
Manufacturing or distributing a controlled substance need not be the sole purpose for which the premises was maintained, but must be one of the defendant's primary or principal uses for the premises, rather than one of the defendant's incidental or collateral uses for the premises. In making this determination, the court should consider how frequently the premises was used by the defendant for manufacturing or distributing a controlled substance and how frequently the premises was used by the defendant for lawful purposes.”,
“28.
Among the factors the court should consider in determining whether the defendant ‘maintained’ the premises are (A) whether the defendant held a possessory interest in (
Manufacturing or distributing a controlled substance need not be the sole purpose for which the premises was maintained, but must be one of the defendant's primary or principal uses for the premises, rather than one of the defendant's incidental or collateral uses for the premises. In making this determination, the court should consider how frequently the premises was used by the defendant for manufacturing or distributing a controlled substance and how frequently the premises was used by the defendant for lawful purposes.”.
Sections 2D1.14, 2K2.4, 3B1.4, and 3C1.1 are repromulgated without change.
Section 2D2.1 is repromulgated without change.
The emergency amendment authority provided in section 8 of the Act required the Commission to promulgate the guidelines, policy statements, or amendments provided for in the Act, and to make such conforming changes to the guidelines as the Commission determines necessary to achieve consistency with other guideline provisions and applicable law, not later than 90 days after the date of enactment of the Act. Pursuant to this emergency directive, the Commission promulgated an amendment effective November 1, 2010, that made temporary, emergency revisions to § 2D1.1 (Unlawful Manufacturing, Importing, Exporting, or Trafficking (Including Possession with Intent to Commit These Offenses); Attempt or Conspiracy) and § 2D2.1 (Unlawful Possession; Attempt or Conspiracy). Conforming changes to certain other guidelines were also promulgated on a temporary, emergency basis.
This amendment re-promulgates the temporary, emergency amendment. Part A re-promulgates the revisions to the crack cocaine quantity levels in the Drug Quantity Table in § 2D1.1 without change. Part B re-promulgates the various aggravating and mitigating provisions in § 2D1.1 without change, except for a revision to the new Application Note 28 (relating to the new enhancement for maintaining premises). Part C re-promulgates the revision to § 2D2.1 accounting for the reduction in the statutory penalties for simple possession of crack cocaine without change.
Part A re-promulgates without change the emergency, temporary revisions to the Drug Quantity Table in § 2D1.1 and related revisions to Application Note 10 to account for the changes in the statutory penalties made in section 2 of the Act. Section 2 of the Act reduced the statutory penalties for offenses involving manufacturing or trafficking in crack cocaine by increasing the quantity thresholds required to trigger a mandatory minimum term of imprisonment. The quantity threshold required to trigger the 5-year mandatory minimum term of imprisonment was increased from 5 grams to 28 grams, and the quantity threshold required to trigger the 10-year mandatory minimum term of imprisonment was increased from 50 grams to 280 grams.
To account for these statutory changes, the amendment conforms the guideline penalty structure for crack cocaine offenses to the approach followed for other drugs,
Estimating the likely future sentencing impact of the amendment to the Drug Quantity Table is difficult because the reductions in the statutory penalties for crack cocaine offenses may result in changes in prosecutorial and other practices. With that important caveat, the Commission estimates that approximately 63 percent of crack cocaine offenders sentenced after November 1, 2011, will receive a lower sentence as a result of the change to the
It is important to note that no crack cocaine offender will receive an increased sentence as a result of the amendment to the Drug Quantity Table. As indicated above, not all crack cocaine offenders sentenced after November 1, 2011, will receive a lower sentence as a result of the change to the Drug Quantity Table. This is the case for a variety of reasons. Among the reasons, compared to the Drug Quantity Table in effect from November 1, 2007 through October 31, 2010, the amendment does not lower the base offense levels, and therefore does not lower the sentences, for offenses involving the following quantities of crack cocaine: less than 500 milligrams; at least 28 grams but less than 35 grams; at least 280 grams but less than 500 grams; at least 840 grams but less than 1.5 kilograms; at least 2.8 kilograms but less than 4.5 kilograms; and 8.5 kilograms or more. In addition, some offenders are sentenced at the statutory mandatory minimum and therefore cannot have their sentences lowered by an amendment to the guidelines.
To provide a means of obtaining a single offense level in cases involving crack cocaine and one or more other controlled substances, the amendment also establishes a marihuana equivalency for crack cocaine under which 1 gram of crack cocaine is equivalent to 3,571 grams of marihuana. (The marihuana equivalency for any controlled substance is a constant that can be calculated using any threshold in the Drug Quantity Table by dividing the amount of marihuana corresponding to that threshold by the amount of the other controlled substance corresponding to that threshold. For example, the threshold quantities at base offense level 26 are 100,000 grams of marihuana and 28 grams of crack cocaine; 100,000 grams divided by 28 is 3,571 grams.) In the commentary to § 2D1.1, the amendment makes a conforming change to the rules for cases involving both crack cocaine and one or more other controlled substances. The amendment deletes the special rules in Note 10(D) for cases involving crack cocaine and one or more other controlled substances, and revises Note 10(C) so that it provides an example of such a case.
Part B re-promulgates the temporary, emergency revisions to § 2D1.1 and accompanying commentary that account for certain aggravating and mitigating factors in drug trafficking cases. These changes implement directives to the Commission in sections 5, 6, and 7 of the Act. The emergency revisions are re-promulgated without change, except for the new Application Note 28 (relating to the new enhancement for maintaining a premises), as explained below.
First, Part B amends § 2D1.1 to add a sentence at the end of subsection (a)(5) (often referred to as the “mitigating role cap”). The new provision provides that if the offense level otherwise resulting from subsection (a)(5) is greater than level 32, and the defendant receives the 4-level (“minimal participant”) reduction in subsection (a) of § 3B1.2 (Mitigating Role), the base offense level shall be decreased to level 32. This provision responds to section 7(1) of the Act, which directed the Commission to ensure that “if the defendant is subject to a minimal role adjustment under the guidelines, the base offense level for the defendant based solely on drug quantity shall not exceed level 32”.
Second, Part B amends § 2D1.1 to create a new specific offense characteristic at subsection (b)(2) providing an enhancement of 2 levels if the defendant used violence, made a credible threat to use violence, or directed the use of violence. The new specific offense characteristic responds to section 5 of the Act, which directed the Commission to “ensure that the guidelines provide an additional penalty increase of at least 2 offense levels if the defendant used violence, made a credible threat to use violence, or directed the use of violence during a drug trafficking offense.”
The amendment also revises the commentary to § 2D1.1 to clarify how this new specific offense characteristic interacts with subsection (b)(1), which provides an enhancement of 2 levels if a dangerous weapon (including a firearm) was possessed. Specifically, Application Note 3 is amended to provide that the enhancements in subsections (b)(1) and (b)(2) may be applied cumulatively. However, in a case in which the defendant merely possessed a dangerous weapon but did not use violence, make a credible threat to use violence, or direct the use of violence, subsection (b)(2) would not apply.
In addition, the amendment makes a conforming change to the commentary to § 2K2.4 (Use of Firearm, Armor-Piercing Ammunition, or Explosive During or in Relation to Certain Crimes) to address cases in which the defendant is sentenced under both § 2D1.1 (for a drug trafficking offense) and § 2K2.4 (for an offense under 18 U.S.C. § 924(c)). In such a case, the sentence under § 2K2.4 accounts for any weapon enhancement; therefore, in determining the sentence under § 2D1.1, the weapon enhancement in § 2D1.1(b)(1) does not apply.
Third, Part B amends § 2D1.1 to create a new specific offense characteristic at subsection (b)(11) providing an enhancement of 2 levels if the defendant bribed, or attempted to bribe, a law enforcement officer to facilitate the commission of the offense. The new specific offense characteristic responds to section 6(1) of the Act, which directed the Commission “to ensure an additional increase of at least 2 offense levels if * * * the defendant bribed, or attempted to bribe, a Federal, State, or local law enforcement official in connection with a drug trafficking offense”.
The amendment also revises the commentary to § 2D1.1 to clarify how this new specific offense characteristic interacts with the adjustment at § 3C1.1 (Obstructing or Impeding the Administration of Justice). Specifically, new Application Note 27 provides that subsection (b)(11) does not apply if the purpose of the bribery was to obstruct or impede the investigation, prosecution, or sentencing of the
Fourth, Part B amends § 2D1.1 to create a new specific offense characteristic at subsection (b)(12) providing an enhancement of 2 levels if the defendant maintained premises for the purpose of manufacturing or distributing a controlled substance. The new specific offense characteristic responds to section 6(2) of the Act, which directed the Commission to “ensure an additional increase of at least 2 offense levels if * * * the defendant maintained an establishment for the manufacture or distribution of a controlled substance, as generally described in section 416 of the Controlled Substances Act (21 U.S.C. 856).”
The amendment also adds commentary in § 2D1.1 at Application Note 28 providing that the enhancement applies to a defendant who knowingly maintains premises (
Application Note 28 also provides that among the factors the court should consider in determining whether the defendant “maintained” the premises are (A) whether the defendant held a possessory interest in (
Fifth, Part B amends § 2D1.1 to create a new specific offense characteristic at subsection (b)(14) providing an enhancement of 2 levels if the defendant receives an adjustment under § 3B1.1 (Aggravating Role) and the offense involved one or more of five specified factors. The new specific offense characteristic responds to section 6(3) of the Act, which directed the Commission “to ensure an additional increase of at least 2 offense levels if * * * (A) the defendant is an organizer, leader, manager, or supervisor of drug trafficking activity subject to an aggravating role enhancement under the guidelines; and (B) the offense involved 1 or more of the following super-aggravating factors:
(i) The defendant—
(I) used another person to purchase, sell, transport, or store controlled substances;
(II) used impulse, fear, friendship, affection, or some combination thereof to involve such person in the offense; and
(III) such person had a minimum knowledge of the illegal enterprise and was to receive little or no compensation from the illegal transaction.
(ii) The defendant—
(I) knowingly distributed a controlled substance to a person under the age of 18 years, a person over the age of 64 years, or a pregnant individual;
(II) knowingly involved a person under the age of 18 years, a person over the age of 64 years, or a pregnant individual in drug trafficking;
(III) knowingly distributed a controlled substance to an individual who was unusually vulnerable due to physical or mental condition, or who was particularly susceptible to criminal conduct; or
(IV) knowingly involved an individual who was unusually vulnerable due to physical or mental condition, or who was particularly susceptible to criminal conduct, in the offense.
(iii) The defendant was involved in the importation into the United States of a controlled substance.
(iv) The defendant engaged in witness intimidation, tampered with or destroyed evidence, or otherwise obstructed justice in connection with the investigation or prosecution of the offense.
(v) The defendant committed the drug trafficking offense as part of a pattern of criminal conduct engaged in as a livelihood.”
The amendment also revises the commentary to § 2D1.1 to provide guidance in applying the new specific offense characteristic at § 2D1.1(b)(14). Specifically, new Application Note 29 provides that if the defendant distributes a controlled substance to an individual or involves an individual in the offense, as specified in subsection (b)(14)(B), the individual is not a “vulnerable victim” for purposes of subsection (b) of § 3A1.1 (Hate Crime Motivation or Vulnerable Victim). Application Note 29 also provides that subsection (b)(14)(C) applies if the defendant committed, aided, abetted, counseled, commanded, induced, procured, or willfully caused the importation of a controlled substance. Subsection (b)(14)(C), however, does not apply if subsection (b)(3) or (b)(5) (as redesignated by the amendment) applies because the defendant's involvement in importation is adequately accounted for by those subsections. In addition, Application Note 29 defines “pattern of criminal conduct” and “engaged in as a livelihood” for purposes of subsection (b)(14)(E) as those terms are defined in § 4B1.3 (Criminal Livelihood).
The amendment also revises the commentary in § 3B1.4 (Using a Minor To Commit a Crime) and § 3C1.1 (Obstructing or Impeding the Administration of Justice) to specify how those adjustments interact with § 2D1.1(b)(14)(B) and (D), respectively. Specifically, Application Note 2 to § 3B1.4 is amended to clarify that the increase of two levels under this section would not apply if the defendant receives an enhancement under § 2D1.1(b)(14)(B). Similarly, Application Note 7 to § 3C1.1 is amended to clarify that the increase of two levels under this section would not apply if the defendant receives an enhancement under § 2D1.1(b)(14)(D).
Sixth, Part B amends § 2D1.1 to create a new specific offense characteristic at subsection (b)(15) providing a 2-level downward adjustment if the defendant receives the 4-level (“minimal participant”) reduction in subsection (a) of § 3B1.2 (Mitigating Role) and the offense involved each of three additional specified factors: namely, the defendant was motivated by an intimate or familial relationship or by threats or fear to commit the offense when the defendant was otherwise unlikely to commit such an offense; was to receive no monetary compensation from the illegal purchase, sale, transport, or storage of controlled substances; and had minimal knowledge of the scope and structure of the enterprise. The specific offense characteristic responds to section 7(2) of the Act, which directed the Commission to ensure that “there is an additional reduction of 2 offense levels if the defendant—
(A) otherwise qualifies for a minimal role adjustment under the guidelines and had a minimum knowledge of the illegal enterprise;
(B) was to receive no monetary compensation from the illegal transaction; and
(C) was motivated by an intimate or familial relationship or by threats or fear when the defendant was otherwise unlikely to commit such an offense.”
Seventh, to reflect the renumbering of specific offense characteristics in § 2D1.1(b) by the amendment, technical and conforming changes are made to the commentary to § 2D1.1 and to § 2D1.14 (Narco-Terrorism).
Part C re-promulgates without change the temporary, emergency revisions to § 2D2.1 to account for the changes in the statutory penalties for simple possession of crack cocaine made in section 3 of the Act. Section 3 of the Act amended 21 U.S.C. 844(a) to eliminate the 5-year mandatory minimum term of imprisonment (and 20-year statutory maximum) for simple possession of more than 5 grams of crack cocaine (or, for certain repeat offenders, more than 1 gram of crack cocaine). Accordingly, the statutory penalty for simple possession of crack cocaine is now the same as for simple possession of most other controlled substances: For a first offender, a maximum term of imprisonment of one year; for repeat offenders, maximum terms of 2 years or 3 years, and minimum terms of 15 days or 90 days, depending on the prior convictions.
3.
“Likewise, an adjustment under § 3B1.3 ordinarily would apply in a case in which the defendant is convicted of a drug offense resulting from the authorization of the defendant to receive scheduled substances from an ultimate user or long-term care facility.
The amendment implements the directive by amending Application Note 8 to § 2D1.1 to provide that an adjustment under § 3B1.3 (Abuse of Position of Trust or Use of Special Skill) ordinarily would apply in a case in which the defendant is convicted of a drug offense resulting from the authorization of the defendant to receive scheduled substances from an ultimate user or long-term care facility. The amendment reflects the likelihood that in such a case the offender abused a position of trust (
4.
It provides an enhancement of 2 levels and a minimum offense level of level 10.
Offenses under section 228 are referenced in Appendix A (Statutory Index) to § 2J1.1 (Contempt), which directs the court to apply § 2X5.1 (Other Offenses), which in turn directs the court to apply the most analogous offense guideline. The commentary to § 2J1.1 provides that, in a case involving a violation of section 228, the most analogous offense guideline is § 2B1.1.
Some circuits have disagreed over whether to apply § 2B1.1(b)(8)(C) in a case involving a violation of section 228. The Second and Eleventh Circuits have held that applying § 2B1.1(b)(8)(C) in a section 228 case is permissible because the failure to pay the child support and the violation of the order are distinct harms.
The amendment resolves the conflict by amending the commentary to § 2J1.1 to specify that, in a case involving a violation of section 228, § 2B1.1(b)(8)(C) does not apply. The Commission determined that in a section 228 case the fact that the offense involved a violation of a court order is adequately accounted for by the base offense level.
5.
“or (III) is convicted under 18 U.S.C. 922(a)(6) or 924(a)(1)(A) and committed the offense with knowledge, intent, or reason to believe that the offense would result in the transfer of a firearm or ammunition to a prohibited person;”;
And in subdivision (6) by striking “or” before “(B)”; and by adding at the end the following:
“or (C) is convicted under 18 U.S.C. 922(a)(6) or 924(a)(1)(A) and committed the offense with knowledge, intent, or reason to believe that the offense would result in the transfer of a firearm or ammunition to a prohibited person;”.
Section 2K2.1(b) is amended by striking subdivision (6) as follows:
“(6) If the defendant used or possessed any firearm or ammunition in connection with another felony offense; or possessed or transferred any firearm or ammunition with knowledge, intent, or reason to believe that it would be used or possessed in connection with another felony offense, increase by 4 levels. If the resulting offense level is less than level 18, increase to level 18.”,
“(6) If the defendant—
(A) Possessed any firearm or ammunition while leaving or attempting to leave the United States, or possessed or transferred any firearm or ammunition with knowledge, intent, or reason to believe that it would be transported out of the United States; or
(B) Used or possessed any firearm or ammunition in connection with another felony offense; or possessed or transferred any firearm or ammunition with knowledge, intent, or reason to believe that it would be used or possessed in connection with another felony offense,
The Commentary to § 2K2.1 captioned “Application Notes” is amended in Note 13(D) by inserting “(B)” after “(b)(6)”.
The Commentary to § 2K2.1 captioned “Application Notes” is amended in Note 14 by inserting “(B)” after “(b)(6)” each place it appears.
The Commentary to § 2K2.1 captioned “Application Notes” is amended by adding at the end the following:
“15.
The Commentary to § 2M5.1 captioned “Statutory Provisions” is amended by inserting “22 U.S.C. 8512; 50 U.S.C. 1705; ” after “2332d;”.
Section 2M5.2(a)(2) is amended by inserting “(A)” before “non-fully”; and by striking “ten” and inserting “two, (B) ammunition for non-fully automatic small arms, and the number of rounds did not exceed 500, or (C) both”.
The Commentary to § 2M5.2 captioned “Statutory Provisions” is amended by inserting “, 8512; 50 U.S.C. 1705” after “2780”.
The Commentary to § 2M5.3 captioned “Statutory Provisions” is amended by inserting “22 U.S.C. 8512;” before “50 U.S.C. “; and by striking “ §1701,”.
Appendix A (Statutory Index) is amended by inserting after the line referenced to 22 U.S.C. 4221 the following:
“22 U.S.C. 8512 2M5.1, 2M5.2, 2M5.3”;
By striking the line referenced to 50 U.S.C. 1701;
And in the line referenced to 50 U.S.C. 1705 by inserting “2M5.1, 2M5.2,” before “2M5.3”.
The amendment amends the primary firearms guideline, § 2K2.1 (Unlawful Receipt, Possession, or Transportation of Firearms or Ammunition; Prohibited Transactions Involving Firearms or Ammunition), to address the general concern of firearms crossing the border and the specific concern about straw purchasers. The amendment also amends the guideline for arms export violations, § 2M5.2 (Exportation of Arms, Munitions, or Military Equipment or Services Without Required Validated Export License), to provide greater penalties for export offenses involving small arms and more guidance on export offenses involving ammunition. Finally, the amendment revises the references in Appendix A (Statutory Index) for certain offenses, including providing a reference for a new offense created by the Comprehensive Iran Sanctions, Accountability, and Divestment Act of 2010, Public Law 111-195.
Subsection (b)(6) provides a 4-level enhancement, and a minimum offense level of 18, if the defendant used or possessed any firearm or ammunition in connection with another felony offense, or possessed or transferred any firearm or ammunition with knowledge, intent, or reason to believe that it would be used or possessed in connection with another felony offense. The amendment establishes a new prong (A) in subsection (b)(6) that applies “if the defendant possessed any firearm or ammunition while leaving or attempting to leave the United States; or possessed or transferred any firearm or ammunition with knowledge, intent, or reason to believe that it would be transferred out of the United States”, and redesignates the existing provision as prong (B). Under the amendment, a defendant receives the 4-level enhancement and minimum offense level 18 if either prong applies. The Commission determined that possessing a firearm while leaving or attempting to leave the United States is conduct sufficiently similar in seriousness to possessing a firearm in connection with another felony offense to warrant similar punishment. Likewise, possessing or transferring a firearm with knowledge, intent, or reason to believe that it would be transported out of the United States is conduct sufficiently similar in seriousness to possessing or transferring a firearm with knowledge, intent, or reason to believe that it would be used or possessed in connection with another felony offense to warrant similar punishment.
Prior to the amendment, some courts have applied subsection (b)(6) to cases in which the defendant has transported or attempted to transport firearms across the border. These courts have concluded that because transporting a firearm outside the United States is generally a felony under federal law, such conduct may qualify as “another felony offense” for purposes of subsection (b)(6).
Second, the amendment amends § 2K2.1 to address the concerns about straw purchasers. The amendment increases penalties for certain defendants convicted under 18 U.S.C. 922(a)(6) or 924(a)(1)(A) for making a false statement in connection with a firearms transaction. Specifically, the amendment increases penalties for a defendant who is convicted under 18 U.S.C. 922(a)(6) or 924(a)(1)(A) and committed the offense with knowledge, intent, or reason to believe that the offense would result in the transfer of a firearm or ammunition to a prohibited person. The base offense level for a defendant convicted under either of these statutes has been level 12, or level 18 if the offense involved a firearm described in 26 U.S.C. 5845(a).
The amendment ensures that defendants convicted under 18 U.S.C. 922(a)(6) or 924(a)(1)(A) receive the same punishment as defendants convicted under a third statute used to prosecute straw purchasers, 18 U.S.C. 922(d), when the conduct is similar. Section 922(d) differs from 18 U.S.C. 922(a)(6) and 924(a)(1)(A) in that it requires as an element of the offense that the defendant sell or otherwise dispose of a firearm or ammunition to a prohibited person knowing or having reasonable cause to believe that such person is a prohibited person. Section 2K2.1 has accounted for the increased offense seriousness and offender culpability in violations of 18 U.S.C. 922(d) by providing base offense levels for convictions under section 922(d) that are generally 2 levels higher than for convictions under 18 U.S.C. 922(a)(6) and 924(a)(1)(A).
In addition, the amendment provides a new Application Note 15 stating that, in a case in which the defendant is convicted under any of the three statutes, a downward departure may be warranted if (A) none of the enhancements in subsection (b) of § 2K2.1 apply, (B) the defendant was motivated by an intimate or familial relationship or by threats or fear to commit the offense and was otherwise unlikely to commit such an offense, and (C) the defendant received no monetary compensation from the offense. The Commission determined that a defendant meeting these criteria may be less culpable than the typical straw purchaser.
Third, the amendment amends § 2M5.2 to narrow the application of the alternative base offense level of 14 at subsection (a)(2). The alternative base offense level of 14 has applied “if the offense involved only non-fully automatic small arms (rifles, handguns, or shotguns) and the number of weapons did not exceed ten.”
The amendment also amends § 2M5.2 to address cases in which the defendant possessed ammunition, either in a case involving ammunition only or in a case involving ammunition and small arms. There appears to be differences in how § 2M5.2 is being applied by the courts in such cases. Under the amendment, a defendant with ammunition will receive the alternative base offense level of 14 if the ammunition consisted of not more than 500 rounds of ammunition for small arms. Such ammunition typically is sold in quantities of not more than 500 rounds, depending on the manufacturer and the type of ammunition. The Commission determined that, as with export offenses involving more than two firearms, export offenses involving more than 500 rounds of ammunition are more serious and more likely to involve trafficking.
Fourth, the amendment amends Appendix A (Statutory Index) to expand the number of guidelines to which offenses under 50 U.S.C. 1705 are referenced. Section 1705 makes it unlawful to violate, attempt to violate, conspire to violate, or cause a violation of any license, order, regulation, or prohibition issued under the International Emergency Economic Powers Act (50 U.S.C. 1701
Finally, the amendment addresses a new offense created by the Comprehensive Iran Sanctions, Accountability, and Divestment Act of 2010, Public Law 111-195. Section 103 of that Act (22 U.S.C. 8512) makes it unlawful to import into the United States certain goods or services of Iranian origin, or export to Iran certain goods, services, or technology, and provides that the penalties under 50 U.S.C. 1705 apply to a violation. The amendment amends Appendix A (Statutory Index) to reference the new offense at 22 U.S.C. 8512 to 2M5.1, 2M5.2, and 2M5.3.
6.
Section 2L1.2(b)(1)(B) is amended by inserting “if the conviction receives criminal history points under Chapter Four or by 8 levels if the conviction does not receive criminal history points” after “12 levels”.
The Commentary to 2L1.2 captioned “Application Notes” is amended in Note 1 by adding at the end the following:
“(C)
The Commentary to 2L1.2 captioned “Application Notes” is amended in Note 7 by inserting after “warranted. (B)” the following: “In a case in which the 12-
The amendment reduces the enhancements at subsections (b)(1)(A) and (B) to 12 or 8 levels, respectively, if the prior conviction does not receive criminal history points under Chapter Four. Subsections (b)(1)(A) and (B) as amended continue to provide a 16- or 12-level enhancement, as applicable, if the prior conviction receives criminal history points under Chapter Four. Thus, for reasons of proportionality, the amendment maintains the 4-level distinction between defendants who receive an enhancement under subsection (b)(1)(A) and those who receive an enhancement under subsection (b)(1)(B), regardless of whether the prior conviction receives criminal history points.
The amendment responds to case law and public comment regarding the magnitude of the enhancement when a defendant's predicate conviction does not receive criminal history points.
Under the amendment, defendants with predicate offenses that qualify for an enhancement under subsections (b)(1)(A) and (B) continue to receive an enhancement, regardless of whether the prior convictions receive criminal history points under Chapter Four. Other provisions in the guidelines exclude consideration of a predicate conviction because of the age of the predicate conviction.
7.
The Commentary to § 3B1.2 captioned “Application Notes” is amended in Note 4 by striking the last sentence.
8.
“(a) The court shall order a term of supervised release to follow imprisonment—
(1) when required by statute (
(2) except as provided in subsection (c), when a sentence of imprisonment of more than one year is imposed.”;
Section 5D1.1 is amended by adding at the end the following:
“(c) The court ordinarily should not impose a term of supervised release in a case in which supervised release is not required by statute and the defendant is a deportable alien who likely will be deported after imprisonment.”.
The Commentary to § 5D1.1 captioned “Application Notes” is amended by striking Notes 1 and 2 and inserting the following:
“1.
2.
3.
(A)
(i) The nature and circumstances of the offense and the history and characteristics of the defendant;
(ii) The need to afford adequate deterrence to criminal conduct, to protect the public from further crimes of the defendant, and to provide the defendant with needed educational or vocational training, medical care, or other correctional treatment in the most effective manner;
(iii) The need to avoid unwarranted sentence disparities among defendants with similar records who have been found guilty of similar conduct; and
(iv) The need to provide restitution to any victims of the offense.
(B)
(C)
4.
5.
Section 5D1.2(a) is amended in subdivision (1) by striking “three” and inserting “two”; and by adding at the end the following: “
Section 5D1.2(a) is amended in subdivision (2) by striking “two years” and inserting “one year”; and by adding at the end the following: “
Section 5D1.2(a) is amended in subdivision (3) by adding at the end the following: “
The Commentary to § 5D1.2 captioned “Application Notes” is amended by adding at the end the following:
“4.
5.
First, the amendment creates an exception to the general rule in § 5D1.1(a) that a term of supervised release be imposed when a sentence of imprisonment of more than one year is imposed or when required by statute. The exception, which appears in a new subsection (c) in § 5D1.1, states that supervised release ordinarily should not be imposed in a case in which supervised release is not required by statute and the defendant is a deportable alien who likely will be deported after imprisonment. A corresponding application note explains that imposing supervised release in such a case is generally unnecessary, although there may be particular cases in which it is appropriate. Non-citizens now are approximately half of the overall population of federal offenders,
Second, the amendment lowers the minimum term of supervised release required by the guidelines for certain defendants (regardless of their citizenship status) when a statute does not require a higher minimum term. Section 5D1.2 requires the court to impose a term of supervised release of at least three years when the defendant is convicted of a Class A or B felony and at least two years when the defendant is convicted of a Class C or D felony. The amendment lowers these minimum terms to two years for a defendant convicted of a Class A and B felony and one year for a defendant convicted of a Class C or D felony. Thus, for reasons of proportionality, the amendment
Finally, the amendment adds commentary in §§ 5D1.1 and 5D1.2 that provides guidance on the factors a court should consider in deciding whether to order a term of supervised release (when not required by statute) and, if so, how long such a term should be. Such factors include the extent of an offender's criminal record, which research shows to be predictive of an offender's likelihood of complying with the conditions of supervision.
9.
The Commentary to § 5K2.0 captioned “Application Notes” is amended in Note 3(C) in the second paragraph by striking “written judgment and commitment order” and inserting “statement of reasons form”; and in Note 5 by striking “written judgment and commitment order” and inserting “statement of reasons form”.
Section 6B1.2(b)(2) is amended by striking “departs from” and inserting “is outside”; and by striking “specifically set forth” and all that follows through “order” and inserting “set forth with specificity in the statement of reasons form”.
Section 6B1.2(c)(2) is amended by striking “departs from” and inserting “is outside”; and by striking “specifically set forth” and all that follows through “order” and inserting “set forth with specificity in the statement of reasons form”.
The Commentary to § 6B1.2 is amended in the second paragraph by striking “departs from” and inserting “is outside”; by striking “(
Appendix A (Statutory Index) is amended by inserting after the line referenced to 18 U.S.C. 2237(a)(2)(B) the following:
“18 U.S.C. 2237(b)(2)(B)(i) 2A1.3, 2A1.4
18 U.S.C. 2237(b)(2)(B)(ii)(I) 2A2.1, 2A2.2
18 U.S.C. 2237(b)(2)(B)(ii)(II) 2A4.1
18 U.S.C. 2237(b)(2)(B)(ii)(III) 2A3.1
18 U.S.C. § 2237(b)(3) 2A2.2
18 U.S.C. 2237(b)(4) 2A2.1, 2A2.2, 2G1.1, 2G1.3, 2G2.1, 2H4.1, 2L1.1”;
and by inserting after the line referenced to 33 U.S.C. 1908 the following:
“33 U.S.C. 3851 2Q1.2”.
First, the amendment updates the policy statement at § 6B1.2 (Standards for Acceptance of Plea Agreements) in light of
The amendment also responds to the Federal Judiciary Administrative Improvements Act of 2010, Public Law 111B174 (enacted May 27, 2010), which amended 18 U.S.C. 3553(c)(2) to require that the reasons for a sentence be set forth in the statement of reasons form (rather than in the judgment and commitment order). The amendment makes appropriate clerical changes to § 6B1.2 and subsection (e) of § 5K2.0 (Grounds for Departure) to reflect this statutory change.
Second, the amendment responds to the Coast Guard Authorization Act of 2010, Public Law 111B281 (enacted October 15, 2010), which provided statutory sentencing enhancements for certain offenses under 18 U.S.C. 2237 (Criminal sanctions for failure to heave to, obstruction of boarding, or providing false information) and created a new criminal offense at 33 U.S.C. 3851.
The amendment addresses the section 2237 offenses by expanding the range of guidelines to which certain section 2237 offenses are referenced. Section 2237 makes it unlawful for—
The operator of a vessel to knowingly fail to obey a law enforcement order to heave to,
A person on board a vessel to forcibly interfere with a law enforcement boarding or other law enforcement action, or to resist arrest,
A person on board a vessel to provide materially false information to a law enforcement officer during a boarding regarding the vessel's destination, origin, ownership, registration, nationality, cargo, or crew,
All three of these offenses are punishable by not more than 5 years of imprisonment. The first two are referenced in Appendix A (Statutory Index) to § 2A2.4 (Obstructing or Impeding Officers); the third is referenced to § 2B1.1 (Theft, Property Destruction, and Fraud). However, the Coast Guard Authorization Act of 2010 provided statutory sentencing enhancements that apply to persons convicted under either of the first two offenses under section 2237 (
If the section 2237 offense results in death, the statutory maximum term of imprisonment is raised to any term of years or life.
If the section 2237 offense involves an attempt to kill, kidnapping or an attempt to kidnap, or an offense under
If the section 2237 offense results in serious bodily injury, the statutory maximum term of imprisonment is raised to 15 years.
If the section 2237 offense involves knowing transportation under inhumane conditions, and is committed in the course of a violation of 8 U.S.C. 1324; chapter 77 of title 18, United States Code; or section 113 or 117 of such title, the statutory maximum term of imprisonment is raised to 15 years.
To §§ 2A2.1 (Assault with Intent to Commit Murder; Attempted Murder) and 2A2.2 to account for when the section 2237 offense involves a violation of section 113, because section 113 offenses are referenced to those guidelines;
To §§ 2G1.1 (Promoting a Commercial Sex Act or Prohibited Sexual Conduct with an Individual Other than a Minor), 2G1.3 (Promoting a Commercial Sex Act or Prohibited Sexual Conduct with a Minor; Transportation of Minors to Engage in a Commercial Sex Act or Prohibited Sexual Conduct; Travel to Engage in Commercial Sex Act or Prohibited Sexual Conduct with a Minor; Sex Trafficking of Children; Use of Interstate Facilities to Transport Information about a Minor), and 2G2.1 (Sexually Exploiting a Minor by Production of Sexually Explicit Visual or Printed Material; Custodian Permitting Minor to Engage in Sexually Explicit Conduct; Advertisement for Minors to Engage in Production) to account for when the section 2237 offense involves a violation of 18 U.S.C. § 1591 (which is within chapter 77), because offenses under section 1591 are referenced to those guidelines;
To § 2H4.1 (Peonage, Involuntary Servitude, Slave Trade, and Child Soldiers) to account for when the section 2237 offense involves a violation of any provision of chapter 77 other than 18 U.S.C. § 1591, because such violations generally are referenced to that guideline; and
to § 2L1.1 (Smuggling, Transporting, or Harboring an Unlawful Alien) to account for when the section 2237 offense involves a violation of 8 U.S.C. § 1324, because section 1324 offenses are referenced to that guideline.
Finally, the amendment addresses the new criminal offense at 33 U.S.C. 3851, which makes it a felony, punishable by imprisonment for not more than six years, to sell or distribute an organotin or to sell, distribute, make, use, or apply an anti-fouling system (
10.
The Commentary to § 2J1.2 captioned “Application Notes” is amended in Note 2(A) by inserting “and Related Adjustments” after “(Obstruction”; and in Note 3 by inserting “and Related Adjustments” after “(Obstruction”.
The Commentary to § 2J1.3 captioned “Application Notes” is amended in Note 2 by inserting “and Related Adjustments” after “(Obstruction”; and in Note 3 by inserting “and Related Adjustments” after “(Obstruction”.
The Commentary to § 2J1.6 captioned “Application Notes” is amended in Note 2 by inserting “and Related Adjustments” after “(Obstruction”; and in Note 4 by striking “Obstruction of Justice” and inserting “Obstructing or Impeding the Administration of Justice”.
The Commentary to § 2J1.9 captioned “Application Notes” is amended in Note 1 by inserting “and Related Adjustments” after “(Obstruction”; and in Note 2 by inserting “and Related Adjustments” after “(Obstruction”.
Section 2Q2.1(c)(1) is amended by inserting “or paleontological resource” after “heritage resource”; and by inserting “or Paleontological Resources” after “Heritage Resources” in both places.
Section 3C1.1 is amended by striking “(A)” and inserting “(1)”; by striking “(B)” and inserting “(2)”; by striking “(i)” and inserting “(A)”; and by striking “(ii)” and inserting “(B)”.
Section 4A1.2(k)(2) is amended by striking “(i)” and inserting “(A)”; by striking “(ii)” and inserting “(B)”; and by striking “(iii)” and inserting “(C)”.
Section 4B1.1(b) is amended by redesignating (A) through (G) as (1) through (7).
The Commentary to § 5E1.2 captioned “Application Notes” is amended in Note 6 by inserting “and Related Adjustments” after “(Obstruction”.
The Commentary to § 8A1.2 captioned “Application Notes” is amended in Note 2 by inserting “and Related Adjustments” after “(Obstruction”.
Section 8B2.1(a) is amended by striking “(c)” and inserting “(b)”.
The Commentary to § 8C2.3 captioned “Application Notes” is amended in Note 2 by inserting “and Related Adjustments” after “(Obstruction”.
First, the amendment makes certain technical and conforming changes in connection with the amendments that the Commission submitted to Congress on April 29, 2010.
(1) Amendment 744 made changes to the organizational guidelines in Chapter Eight, including a change that consolidated subsections (b) and (c) of § 8D1.4 (Recommended Conditions of Probation—Organizations) into a single subsection (b). To reflect this consolidation, subsection (a) of § 8B2.1 (Effective Compliance and Ethics Program) is changed so that it refers to the correct subsection of § 8D1.4.
(2) Amendment 745 expanded the scope of § 2B1.5 (Theft of, Damage to, or Destruction of, Cultural Heritage Resources; Unlawful Sale, Purchase, Exchange, Transportation, or Receipt of Cultural Heritage Resources) to cover not only cultural heritage resources but also paleontological resources. To reflect this expanded scope, a conforming change is made to subsection (c)(1) of § 2Q2.1 (Offenses Involving Fish, Wildlife, and Plants).
Second, the amendment makes technical changes to § 3C1.1 (Obstructing or Impeding the Administration of Justice), subsection (k)(2) of § 4A1.2 (Definitions and
Finally, the amendment makes a series of changes throughout the
(2) Request for Comment on Amendment 2, Pertaining to Drug Offenses.
On April 28, 2011, the Commission submitted to the Congress amendments to the sentencing guidelines and official commentary, which become effective on November 1, 2011, unless Congress acts to the contrary. Such amendments and the reasons for amendment are set forth in this notice.
Amendment 2, pertaining to drug offenses, has the effect of lowering guideline ranges.
The Commission also requests comment regarding whether, if it amends § 1B1.10(c) to include this amendment, it also should amend § 1B1.10 to provide guidance to the courts on the procedure to be used when applying an amendment retroactively under 18 U.S.C. 3582(c)(2).
Amendment 2, pertaining to drug offenses, contains three parts. The Commission seeks comment on whether it should list the entire amendment, or one or more parts of the amendment, in subsection (c) of § 1B1.10 as an amendment that may be applied retroactively to previously sentenced defendants.
Part A changes the Drug Quantity Table in § 2D1.1 for offenses involving crack cocaine. This has the effect of lowering guideline ranges for certain defendants for offenses involving crack cocaine.
Part B contains both mitigating and aggravating provisions for offenses involving drugs, regardless of drug type. The mitigating provisions have the effect of lowering guideline ranges for certain defendants in drug cases, and the aggravating provisions have the effect of raising guideline ranges for certain defendants in drug cases.
Part C deletes the cross reference in § 2D2.1(b)(1) under which an offender who possessed more than 5 grams of crack cocaine was sentenced under § 2D1.1. This has the effect of lowering guideline ranges for certain defendants for offenses involving simple possession of crack cocaine.
For each of these three parts, the Commission requests comment on whether that part should be listed in subsection (c) of § 1B1.10 as an amendment that may be applied retroactively. Note that if Part B were applied retroactively (in isolation, or in combination with Parts A and/or C), the court would determine not only whether any mitigating provisions in Part B applied, but also whether any aggravating provisions in Part B applied. To the extent any aggravating provisions applied, the aggravating effect of those provisions would act to offset the mitigating effect of changes made by Parts A, B, and C, to the extent they apply, but in no event could the net effect result in the defendant receiving a sentence higher than the sentence previously imposed.
For its consideration of Parts A and B, the Commission seeks comment on two options in particular. Option 1 would include Part A as an amendment that may be applied retroactively, but would not include Part B. Option 2 would include both Part A and Part B.
If the Commission does list the entire amendment, or one or more parts of the amendment, in subsection (c) of § 1B1.10 as an amendment that may be applied retroactively to previously sentenced defendants, should the Commission provide further guidance or limitations regarding the circumstances in which and the amount by which sentences may be reduced?
In particular, should the Commission limit retroactivity only to a particular category of defendants, such as (A) defendants in a particular criminal history category or categories (
Should the Commission exclude from retroactivity certain categories of defendants whose offense involved aggravating conduct such as, for example, (A) defendants who received an enhanced penalty under § 2D1.2 (Drug Offenses Occurring Near Protected Locations or Involving Underage or Pregnant Individuals; Attempt or Conspiracy), (B) defendants who received an adjustment under § 3B1.1 (Aggravating Role), (C) defendants who received an adjustment under § 3B1.4 (Using a Minor to Commit a Crime), (D) defendants who received an enhancement under § 2D1.1(b)(1) (
In considering whether to limit retroactivity to a particular category or categories of defendants, how, if at all, should the Commission account for the fact that the jurisprudence that applies to sentencing has changed to expand the discretionary authority of a sentencing court to impose a sentence outside the guidelines framework? Should the Commission limit retroactivity only to, for example, (A) defendants who were sentenced within the guideline range, (B) defendants who were sentenced within the guideline range or who received a departure under Chapter Five, Part K, (C) defendants sentenced before
If the original term of imprisonment imposed was less than the term of imprisonment provided by the guideline range applicable to the defendant at the time of sentencing, a reduction comparably less than the amended guideline range
Should the Commission amend § 1B1.10 to provide further guidance on how the sentencing court, in considering retroactivity, should account for this factor?
The Department of Veterans Affairs gives notice under the Public Law 92-463 (Federal Advisory Committee Act) that the meetings for the following four panels of the Joint Biomedical Laboratory Research and Development and Clinical Science Research and Development Services Scientific Merit Review Board have been rescheduled and not as originally announced in the
The addresses of the hotels and VA Central Office are:
The purpose of the Merit Review Board is to provide advice on the scientific quality, budget, safety and mission relevance of investigator-initiated research proposals submitted for VA merit review consideration. Proposals submitted for review by the Board involve a wide range of medical specialties within the general areas of biomedical, behavioral and clinical science research.
The panel meetings will be open to the public for approximately one hour at the start of each meeting to discuss the general status of the program. The remaining portion of each panel meeting will be closed to the public for the review, discussion, and evaluation of initial and renewal research proposals.
The closed portion of each meeting involves discussion, examination, reference to staff and consultant critiques of research proposals. During this portion of each meeting, discussion and recommendations will deal with qualifications of personnel conducting the studies, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy, as well as research information, the premature disclosure of which could significantly frustrate implementation of proposed agency action regarding such research proposals.
As provided by subsection 10(d) of Public Law 92-463, as amended, closing portions of these panel meetings is in accordance with 5 U.S.C., 552b(c)(6) and (9)(B). Those who plan to attend or would like to obtain a copy of minutes of the panel meetings and rosters of the members of the panels should contact LeRoy G. Frey, Ph.D., Chief, Program Review (121F), Department of Veterans Affairs, 810 Vermont Avenue, NW., Washington, DC 20420 at (202) 443-5674.
By Direction of the Secretary.
(a) the persons listed in the Annex to this order; and
(b) any person determined by the Secretary of the Treasury, in consultation with the Secretary of State:
(a) the making of any contribution or provision of funds, goods, or services by, to, or for the benefit of any person whose property and interests in property are blocked pursuant to this order; and
(b) the receipt of any contribution or provision of funds, goods, or services from any such person.
(b) Any conspiracy formed to violate any of the prohibitions set forth in this order is prohibited.
(a) the term “person” means an individual or entity;
(b) the term “entity” means a partnership, association, trust, joint venture, corporation, group, subgroup, or other organization;
(c) the term “United States person” means any United States citizen, permanent resident alien, entity organized under the laws of the United States or any jurisdiction within the United States (including foreign branches), or any person in the United States; and
(d) the term “Government of Syria” means the Government of the Syrian Arab Republic, its agencies, instrumentalities, and controlled entities.
Environmental Protection Agency.
Proposed rule.
The United States (U.S.) Environmental Protection Agency (EPA or Agency) is proposing national emission standards for hazardous air pollutants (NESHAP) from coal- and oil-fired electric utility steam generating units (EGUs) under Clean Air Act (CAA or the Act) section 112(d) and proposing revised new source performance standards (NSPS) for fossil fuel-fired EGUs under CAA section 111(b). The proposed NESHAP would protect air quality and promote public health by reducing emissions of the hazardous air pollutants (HAP) listed in CAA section 112(b). In addition, these proposed amendments to the NSPS are in response to a voluntary remand of a final rule. We also are proposing 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.
Comments must be received on or before July 5, 2011. Under the Paperwork Reduction Act (PRA), comments on the information collection provisions are best assured of having full effect if the Office of Management and Budget (OMB) receives a copy of your comments on or before June 2, 2011.
Submit your comments, identified by Docket ID. No. EPA-HQ-OAR-2011-0044 (NSPS action) or Docket ID No. EPA-HQ-OAR-2009-0234 (NESHAP action), by one of the following methods:
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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; E-mail address:
The information presented in this preamble is organized as follows:
In December 2000, EPA appropriately concluded that it was appropriate and necessary to regulate hazardous air pollutants (HAP) from EGUs. Today, EPA confirms that finding and concludes that it remains appropriate and necessary to regulate these emissions from EGUs. Hazardous air pollutants from EGUs contribute to adverse health and environmental effects. EGUs are by far the largest U.S. anthropogenic sources of mercury (Hg) emissions into the air and emit a number of other HAP. Both the finding in 2000 and our conclusion that it remains appropriate and necessary to regulate HAP from EGUs are supported by the CAA and scientific and technical analyses.
Mercury is a highly toxic pollutant that occurs naturally in the environment and is released into the atmosphere in significant quantities as the result of the burning of fossil fuels. Mercury in the environment is transformed into a more toxic form, methylmercury (MeHg), and because it is also a persistent pollutant, it accumulates in the food chain, especially the tissue of fish. When people consume these fish they consume MeHg, the consumption of which may cause neurotoxic effects. Children, and, in particular, developing
In addition to Hg, EGUs are significant emitters of HAP metals such as arsenic (As), nickel (Ni), cadmium (Cd), and chromium (Cr), which can cause cancer; HAP metals with potentially serious noncancer health effect such as lead (Pb) and selenium (Se); and other toxic air pollutants such as the acid gases hydrogen chloride (HCl) and hydrogen fluoride (HF). Adverse noncancer health effects associated with non-Hg EGU HAP include chronic health disorders (
Congress recognized the threats posed by emissions of HAP and was dissatisfied with the pace of EPA's progress in reducing them prior to 1990. As a result, it enacted significant changes to the CAA that required EPA to develop stringent standards for the control of these pollutants from both stationary and mobile sources. Congress included the requirements in the 1990 CAA amendments regarding acid rain that would reduce emissions of certain criteria pollutants from EGUs and result in the installation of controls that might achieve HAP emission reduction co-benefits. For that reason, it added the requirement for EPA to make a finding before it could regulate EGUs under section 112. Specifically, Congress required in the air toxics provisions that EPA conduct a study of the public health hazards anticipated to remain from EGU HAP emissions after imposition of these other provisions and regulate EGUs under section 112 if the Agency found, after considering the results of the study, that such regulation was appropriate and necessary. Congress also required EPA to conduct a study of Hg emissions from EGUs and other sources and consider the health and environmental effects of the emissions and the availability and cost of control technologies.
Responding to Congress, EPA published the required studies detailing the hazards posed by emissions of Hg and the risks posed by emissions of Hg and other HAP from fossil fuel-fired EGUs. Following the publication of the studies and after collecting additional relevant data, EPA concluded in December 2000 that the threats to public health and the environment from emissions of Hg and other HAP from EGUs made it both appropriate and necessary to adopt regulations under section 112 to reduce the emissions of Hg and other HAP from coal- and oil-fired EGUs. As a result of its findings, EPA added these sources to the list of stationary sources subject to regulations governing the emissions of HAP. However, in a rulemaking effort completed in 2005, EPA reversed its findings and instead adopted regulations under other provisions of the CAA. The DC Circuit Court vacated the resulting regulations, noting that EPA had sidestepped important legal requirements in the CAA that govern the delisting of source categories. Those requirements provide that EPA can delist a source category only if it can demonstrate that no source within the listed category poses a lifetime cancer risk above one in one million to the individual most exposed and that emissions from no source in the category exceed the level that is adequate to protect public health with an ample margin of safety and that no adverse environmental effects will result from the emissions of any source. CAA 112(c)(9)(B). The DC Circuit Court's action restored EPA's December 2000 determination that it was appropriate and necessary to regulate coal- and oil-fired EGUs under section 112, and EGUs remain a listed source category.
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 EGUs under section 112. Now, more than 10 years have passed since EPA's determination that toxic emissions from coal- and oil-fired EGUs pose a threat to public health and the environment. Although not required, EPA conducted additional, extensive technical analyses based on more recent data, and those analyses confirm that it remains appropriate and necessary to regulate HAPs from coal- and oil-fired EGUs. Accordingly and without further delay, we are proposing a set of HAP emission standards for coal- and oil-fired EGUs that can be met with existing technology that has been available for a significant time.
EPA acknowledges that although EGUs contribute significantly to the total amount of U.S. anthropogenic Hg emissions, other sources both here and abroad also contribute significantly to the global atmospheric burden and U.S. deposition of Hg. It is estimated that the U.S. contributes 5 percent to global anthropogenic Hg and 2 percent the total global Hg pool.
At the time it published the December 2000 Finding, EPA identified certain technologies capable of significantly reducing Hg and other HAP emissions. Since then, additional technologies and improvements to those previously identified have become available. These technologies are also often effective at reducing significantly the emissions of other conventional pollutants such as SO
A number of EGUs operating today were built in the 1950s and 1960s, using now-obsolete and inefficient technologies. Today, new units are far more efficient in their production of electricity, their use of fuel, and the relative quantities of pollution emitted. To the extent that some of the oldest, least efficient, least controlled units are retired by companies who elect not to invest in controlling them, assessments included in the docket to today's notice of proposed rulemaking indicate that there will be a sufficient supply of electricity from newer units. In fact, one consequence of today's proposed rule, if adopted as a final rule, will be that the market for electricity in the U.S. will be more level and no longer skewed in favor of the higher polluting units that were exempted from the CAA at its inception on Congress' assumption that their useful life was near an end. Thus, this proposed rule will require companies to make a decision—control HAP emissions from virtually uncontrolled sources or retire these sometimes 60 year old units and shift their emphasis to more efficient, cleaner modern methods of generation, including modern coal-fired generation.
For the reasons summarized above and discussed in detail in this document, the standards being proposed today will be effective at significantly reducing emissions of Hg and an array of other toxic pollutants from coal- and oil-fired EGUs. In addition, as a result of the HAP reductions and co-benefits of these rules, many premature deaths from exposure to air pollution will be avoided by the application of controls that are well-known, broadly applied, and available. To the extent that isolated issues remain concerning the availability of electricity in some more remote parts of the country, we believe that EPA has the ability to work with companies making good faith efforts to comply with the standards so that consumers in those areas are not adversely affected.
Consistent with the recently issued Executive Order (EO) 13563, “Improving Regulation and Regulatory Review,” we have estimated the cost and benefits of the proposed rule. The estimated net benefits of our proposed rule at a 3 percent discount rate are $48 to 130 billion or $42 to $120 billion at a 7 percent discount rate.
For more information on how EPA is addressing EO 13563, see the executive order discussion, later in the preamble.
The regulated categories and entities potentially affected by the proposed standards are shown in Table 1 of this preamble.
This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be affected by this action. To determine whether your facility, company, business, organization, etc., would 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 63.9982. 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).
Do not submit information containing CBI to EPA through
In addition to being available in the docket, an electronic copy of this proposed rule will also be available on the Worldwide Web (WWW) through the Technology Transfer Network (TTN). Following signature, a copy of the proposed rule will be posted on the TTN's policy and guidance page for newly proposed or promulgated rules at the following address:
EPA will hold three public hearings on this proposal. The dates, times, and locations of the public hearings will be announced separately. If you would like to present oral testimony at one of the hearings, please notify Ms. Pamela Garrett, Sectors Policies and Programs Division (C504-03), U.S. EPA, Research Triangle Park, NC 27711, telephone number (919) 541-7966; e-mail:
In 1990, Congress substantially rewrote provisions of the CAA addressing emissions of HAP from large and small stationary sources in the U.S. Collectively, these sources emit into the air millions of pounds of HAP each year, chemicals that are known to cause or are suspected of causing cancer, birth defects, reproduction problems, and other serious health effects. Many of the sources that emit air toxics are located in urban areas, which generally include predominantly low income, minority or otherwise vulnerable communities, where dense populations mean that large numbers of people may be exposed.
Since 1990, EPA has promulgated regulations covering over 50 industrial sectors, requiring the use of available control technology and other practices to reduce emissions. These standards have reduced emissions of HAP from American industry by more than 60 percent. HAP emissions from smaller sources such as dry cleaners and auto body shops have declined by 30 percent, also due to CAA standards. Greater reductions are expected as greater numbers of smaller sources adopt pollution prevention, efficiency, or install control technologies to comply with EPA emission standards. Emissions from the mobile source sector have also been addressed. Controls for fuels and vehicles are expected to reduce selected HAP from vehicles by more than 75 percent by 2020.
EGUs are the most significant source of HAP in the country that remains unaddressed by Congress's air toxics program. EGUs emit multiple HAP of concern and are by far the largest remaining source of Hg, which is one of the more highly toxic chemicals on Congress's list of HAP and which, once released, stays in the environment permanently. Coal- and oil-fired EGUs also emit HAP such as As, other metals and acid gases in amounts significantly higher than almost any other industrial sector. They are located in nearly every state, and emissions from their stacks affect people nearby as well as hundreds of miles away.
Congress provided a specific path for EPA to regulate HAP emissions from EGUs. It gave explicit instructions about scientific studies EPA needed to develop and then consider in determining whether it was “appropriate and necessary” to regulate HAP emissions from EGUs. Congress anticipated that EPA would complete the studies by 1994. In 2000, EPA found that it was indeed “appropriate and necessary” to regulate HAP emissions from EGUs under section 112. In the decade that has passed since EPA made that finding, EGUs have continued to emit Hg and other HAP, and there are still no national limits on the amount of Hg and other HAP that EGUs can release into the air. And, although some plants have installed available and effective control technologies that reduce these emissions, there is no requirement for EGUs to control for Hg and other HAP.
As our new analyses demonstrate, it remains both appropriate and necessary to set standards for coal- and oil-fired EGUs to protect public health and the environment from the adverse effects of HAP emissions from EGUs. The Agency's appropriate and necessary finding was correct in 2000, and it remains correct today. EPA proposes to set standards for coal- and oil-fired EGUs that will reduce emissions of Hg, Ni and other metal HAP, acid gas HAP, and other harmful HAP. These standards are based on available control technologies and other practices already used by the better-controlled and lower-emitting EGUs. They are achievable, we believe they can be implemented without disruption to the reliable provision of electricity, and will deliver health protection across the U.S.
In this section, we provide an overview of the relevant statutory, regulatory, and litigation background.
Congress enacted section 112 to address HAP emissions from stationary sources. Section 112 contains provisions specific to EGUs, which we will address in this preamble, but we begin with a summary of the overall structure and purpose of the section 112 program.
Prior to the 1990 Amendments, the CAA required EPA to regulate HAP solely on the basis of risk to human
In addition to adopting this two-phased approach to standard-setting, Congress included a series of rigorous deadlines for EPA, including deadlines for listing categories and issuing emission standards for such categories.
The criteria for regulation differ in section 112 depending on whether the source is a major source or an area source. A “major source” is any stationary source
Congress established a specific structure for determining whether to regulate EGUs under section 112.
In section 112(n)(1)(A), EPA is directed to conduct a study 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, and to report the results of such study to Congress by November 15, 1993 (Utility Study Report to Congress;
Once a source category is listed pursuant to section 112(c), the next step is for EPA to establish technology-based emission standards under section 112(d). Under section 112(d), EPA must establish emission standards for major sources that “require the maximum degree of reduction in emissions of the HAP subject to this section” that EPA determines is achievable taking into account certain statutory factors. These are referred to as “maximum achievable control technology” or “MACT” standards. The MACT standards for existing sources must be at least as stringent as the average emissions limitation achieved by the best performing 12 percent of existing sources in the category (for which the Administrator has emissions information) or the best performing 5 sources for source categories with less than 30 sources.
CAA section 112(d)(4) authorizes EPA to set a health-based standard for a limited set of HAP for which a health threshold has been established, and that standard must provide for “an ample margin for safety.” 42 U.S.C. 7412(d)(4). As these standards are potentially less stringent than MACT standards, the Agency must have detailed information on HAP emissions from the subject sources and sources located near the subject sources before exercising its discretion to set such standards.
For area sources, section 112(d)(5) authorizes EPA to issues standards or requirements that provide for the use of generally available control technologies (GACT) or management practices in lieu of promulgating standards pursuant to sections 112(d)(2) and (3).
As noted above, Congress required that various reports concerning EGUs be completed. The first report, the Utility Study, required 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. This report was required by November 15, 1993. The second report, due on November 15, 1994, directed EPA to “conduct a study of mercury emissions from [EGUs], municipal waste combustion units, and other sources, including area sources.”
The last required report was to be completed by the National Institute of Environmental Health Sciences (NIEHS) and submitted to Congress by November 15, 1993. CAA section 112(n)(1)(C) directed NIEHS to conduct “a study to determine the threshold level of Hg exposure below which adverse human health effects are not expected to occur.” In conducting this study, NIEHS was to determine “a threshold for mercury concentrations in the tissue of fish which may be consumed (including consumption by sensitive populations) without adverse effects to public health.” Id. NIEHS submitted this Report to Congress in August, 1995.
In addition, Congress, in conference report language associated with EPA's fiscal year 1999 appropriations, directed EPA to fund the National Academy of Sciences (NAS) to perform an independent evaluation of the available data related to the health impacts of MeHg (“Toxicological Effects of Methylmercury,” hereinafter, NAS Study or MeHg Study).
The NAS Study evaluated the same issues as those required to be considered under section 112(n)(1)(C). The NAS Study was completed 5 years after the NIEHS Study, and, thus, considered additional information not available to NIEHS. Because Congress required that the same issues be addressed in both the NAS and NIEHS Studies and the NAS Study was issued after the NIEHS study, we discuss, for purposes of this document, the content of the NAS Study, as opposed to the NIEHS Study.
EPA conducted the studies required by section 112(n)(1) concerning utility HAP emissions. Prior to issuance of the Mercury Study, EPA engaged in two extensive external peer reviews of the document. Although EPA missed the statutory deadline for completing the studies, the Mercury Study and the Utility Study were complete by 1998. The NIEHS study was completed in 1995, and the NAS Study was completed in 2000.
In December 2000, after considering public input, the studies required by section 112(n)(1) and other relevant information, including Hg emissions data from EGUs, EPA determined that it was appropriate and necessary to regulate EGUs under CAA section 112. Based on that determination, the Agency listed such units for regulation under section 112(c).
Pursuant to a settlement agreement, the deadline for issuing emission standards was March 15, 2005. However, instead of issuing emission standards pursuant to section 112(d), on March 15, 2005, EPA delisted EGUs, finding that it was neither appropriate nor necessary to regulate such units under section 112. That attempt to delist was subsequently invalidated by the DC Circuit Court.
EPA issued the Utility Study in February 1998, over 4 years after the statutory deadline. The Utility Study included numerous analyses. EPA first collected HAP emissions test data from 52 EGUs, including a range of coal-, oil-, and natural gas-fired units, and the test data along with facility specific information were used to estimate HAP emissions from all 684 utility facilities. EPA determined that 67 HAP were emitted from EGUs. In addition, the study evaluated HAP emissions based on two scenarios: (1) 1990 base year; and (2) 2010 projected emissions. The 2010 scenario was selected to meet the section 112(n)(1)(A) mandate to evaluate hazards “after imposition of the requirements of the Act.” EPA also considered potential control strategies for the identified HAP consistent with section 112(n)(1)(A).
EPA evaluated exposures, hazards, and risks due to HAP emissions from coal-, oil-, and natural gas-fired EGUs. EPA conducted a screening level assessment of all 67 HAP to prioritize the HAP for further analysis. A total of 14 HAP were identified as priority HAP that would be further assessed. Twelve HAP (As, beryllium (Be), Cd, Cr, manganese (Mn), Ni, HCl, HF, acrolein, dioxins, formaldehyde, and radionuclides) were identified as a priority for further assessment based on inhalation exposure and risk. Six HAP (Hg, radionuclides, As, Cd, Pb, and dioxins) were considered a priority for multipathway assessment of exposure and risk.
Based on the inhalation estimates for the priority HAP, EPA determined that As and Cr emissions from coal-fired EGUs and Ni emissions from oil-fired EGUs contributed most to the potential cancer related inhalation risks, but those risks were not high. The non-cancer risk assessment due to inhalation exposure indicated exposures were well below the reference levels.
The Agency also conducted multipathway assessments for the six HAP identified above. Based on these analyses, EPA determined that Hg from coal-fired EGUs was the HAP of greatest potential concern. In addition, the screening multipathway assessments for dioxins and As suggested that these two HAP were of potential for multipathway risk.
In addition to the 1990 analysis, EPA also estimated emissions and inhalation risks for the year 2010. HAP emissions from coal-fired utilities were predicted to increase by 10 to 30 percent by the year 2010. Predicted changes included the installation of scrubbers for a small number of facilities, the closing of a few facilities, and an increase in fuel consumption of other facilities. For oil-fired plants, emissions and inhalation risks were estimated to decrease by 30 to 50 percent by the year 2010, primarily due to projected reductions in use of oil for electricity generation. Multipathway risks for 2010 were not assessed.
In estimating future emissions from EGUs, EPA primarily evaluated the effect of implementation of the Acid Rain Program (ARP) on HAP emissions from EGUs. The 2010 scenario also included estimated changes in emissions resulting from projected trends in fuel choices and power demands.
Table 2 of this preamble presents estimated emissions for a subset of priority HAP for 1990 and 2010.
Numerous potential alternative control strategies for reducing HAP emissions from EGUs were identified. These included pre-combustion controls (
EPA issued the Mercury Study in December 1997, 3 years after the statutory deadline. The Mercury Study assessed the magnitude of U.S. Hg emissions by source, the health and environmental implications of those emissions, and the availability and cost of control technologies.
According to the Mercury Study, Hg cycles in the environment as a result of natural and human (anthropogenic) activities. Most of the Hg in the atmosphere is elemental Hg vapor, which circulates in the atmosphere for up to a year, and, hence, can be widely dispersed and transported thousands of miles from likely sources of emission. The Mercury Study also found that most of the Hg in water, soil, sediments, or plants and animals is in the form of inorganic Hg salts and organic forms of Hg (
The Mercury Study estimated that in 1994-1995, anthropogenic U.S. Hg emissions were about 158 tons annually. Roughly 87 percent of those emissions were from combustion sources, including waste and fossil fuel combustion. According to the Mercury Study, current anthropogenic emissions were only one part of the Hg cycle. The Mercury Study noted that current releases from human activities were adding to the Hg reservoirs that already exist in land, water, and air, both naturally and as a result of prior human activities. The Mercury Study concluded that the flux of Hg from the atmosphere to land or water at any one location is comprised of contributions from the natural global cycle, including re-emissions from the oceans, international sources, regional sources, and local sources.
The Mercury Study further described a computer simulation of long-range transport of Hg, which suggested that about one-third (approximately 52 tons) of U.S. anthropogenic emissions are deposited, through wet and dry deposition, within the lower 48 states. The remaining two-thirds (approximately 107 tons) was estimated to be transported outside of U.S. borders where it would diffuse into the global reservoir. The computer simulation further suggested that another 35 tons of Hg from the global reservoir outside the U.S. was deposited annually in the U.S. for a total deposition in the U.S. of roughly 87 tons per year (tpy).
The Mercury Study also found that fish consumption dominates the pathway for human and wildlife exposure to MeHg and that there was a plausible link between anthropogenic releases of Hg from industrial and combustion sources in the U.S. and MeHg in fish. In the Mercury Study, EPA explained that, given the current scientific understanding of the environmental fate and transport of this element, it was not possible to quantify how much of the MeHg in fish consumed by the U.S. population results from U.S. anthropogenic emissions, as compared to other sources of Hg (such as natural sources and re-emissions from the global pool).
The Mercury Study noted that those who regularly and frequently consume large amounts of fish—either marine species that typically have much higher levels of MeHg than other species, or freshwater fish that have been affected by Hg pollution—are more highly exposed. Because the developing fetus may be the most sensitive to the effects from MeHg, women of child-bearing age were the population of greatest interest. EPA concluded in the Mercury Study that approximately 7 percent of women of child-bearing age (
Finally, the Mercury Study concluded that piscivorous (fish-eating) birds and mammals were more highly exposed to Hg than any other known component of aquatic ecosystems, and that adverse effects of Hg on fish, birds and mammals include death, reduced reproductive success, impaired growth and development, and behavioral abnormalities. The Mercury Study also evaluated Hg emissions control technologies and the costs of such technologies.
In the appropriations report for EPA's fiscal 1999 funding, Congress directed EPA to fund the NAS to perform an independent study on the toxicological effects of MeHg and to prepare recommendations on the establishment of a scientifically appropriate MeHg exposure RfD. In response, EPA contracted with NAS, which conducted an 18-month study of the available data on the health effects of MeHg and reported its findings to EPA in July 2000.
The EPA included four charges to NAS: (1) Evaluate the body of evidence that led to EPA's current RfD for MeHg, and on the basis of available human epidemiological and animal toxicity data, determine whether the critical study, end point of toxicity, and uncertainty factors used by EPA in the derivation of the RfD for MeHg are scientifically appropriate, including
The NAS held both public and closed sessions wherein they evaluated data and presentations from government agencies, trade organizations, public interest groups, and concerned citizens. The NAS also evaluated new findings that had emerged since the development of EPA's 1995 RfD and met with the investigators of major ongoing epidemiological studies.
The NAS Study concluded that the value of EPA's 1995 RfD for MeHg, 0.1 micrograms per kilogram (µg/kg) per day, was a scientifically appropriate level for the protection of public health. The NAS Study further concluded that data from both human and animal studies indicated that the developing nervous system was a sensitive target organ for low-dose MeHg exposure. The NAS Study indicated that there was evidence that exposure to MeHg in humans and animals can have adverse effects on both the developing and adult cardiovascular system. Some of the studies observed adverse cardiovascular effects at or below MeHg exposure levels associated with neurodevelopmental effects. The weight of evidence for carcinogenicity of MeHg was inconclusive. There was also evidence from animal studies that the immune and reproductive systems are sensitive targets for MeHg toxicity.
According to the NAS Study, the estimates of MeHg exposures in the U.S. population indicated that the risk of adverse effects from then-current MeHg exposures in the majority of the population was low. However, the NAS Study concluded that individuals with high MeHg exposures from frequent fish consumption might have little or no margin of safety (
On December 20, 2000, 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 section 112 and added such units to the list of source categories subject to regulation under section 112(d). In making that finding, 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 EPA obtained pursuant to an information collection request (ICR) under the authority of section 114 of the CAA. 65 FR 79826-27. EPA collected data on the Hg content of coal from all coal-fired EGUs for the calendar year 1999 and Hg emissions stack test data for certain coal-fired EGUs. 65 FR 79826. EPA also solicited data from the public through a February 29, 2000, notice (65 FR 10783). The public had an opportunity to provide their views on what the section 112(n)(1)(A) appropriate and necessary regulatory finding should be at a public meeting in Chicago, Illinois, on June 13, 2000 (65 FR 18,992). 65 FR 79826.
In the December 2000 notice, EPA explained that it evaluated EGUs based on the type of fossil fuel combusted (
EPA further estimated that about 60 percent of the total Hg deposited in the U.S. came from anthropogenic air emissions originating in the U.S. and that EGUs contributed approximately 30 percent of those anthropogenic air emissions. 65 FR 79827. Based on the record before the Agency at the time, EPA determined that there was a plausible link between Hg emissions from EGUs and MeHg in fish and that Hg emissions from EGUs were a threat to public health and the environment. 65 FR 79827.
In discussing the non-Hg HAP from coal- and oil-fired EGUs, EPA stated that HAP metals such as As, Cr, Ni, and Cd are of potential concern for carcinogenic effects. 65 FR 79827. EPA acknowledged that the risk assessments conducted for these HAP indicated that cancer risks were not high, but the Agency could not conclude the potential concern for public health was eliminated for those metals. 65 FR 79827. EPA further stated that dioxins, HCl, and HF were of potential concern and could be evaluated further during the regulatory development process. 65 FR 79827. EPA also concluded that the remaining HAP evaluated in the Utility Study did not appear to be a public health concern, but the Agency noted that there were limited data and uncertainties associated with this conclusion, and we stated that future data collection efforts could identify additional HAP of potential concern. 65 FR 79827.
EPA also explained that, consistent with Congress's direction in section 112(n)(1)(A), we considered the alternative control strategies available to control the HAP emissions that may warrant control. We noted that currently available controls for criteria pollutants would also be effective at controlling the HAP emissions from EGUs. 65 FR 79828.
EPA then made nine specific conclusions based on the information in the record, some of which are summarized above. 65 FR 79829-30. Based on those conclusions, EPA found that it was “appropriate” to regulate HAP emissions from coal- and oil-fired EGUs because EGUs “are the largest domestic source of Hg emissions, and Hg in the environment presents significant hazards to public health and the environment.” 65 FR 79830. EPA noted that the NAS Study confirmed EPA's own research concluding that “mercury in the environment presents a significant hazard to public health.” 65
Once EPA determined that it was “appropriate” to regulate coal- and oil-fired EGUs under CAA section 112, EPA next concluded that it was also “necessary” to regulate HAP emissions from such units 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 such emissions identified in the Utility RTC and confirmed by the NAS Study, and which section 112 is intended to address.” 65 FR 79830.
For natural gas-fired EGUs, EPA found that regulation of HAP emissions “is not appropriate or necessary because the impacts due to HAP emissions from such units are negligible based on the results of the study documented in the utility RTC.” 65 FR 79831.
In light of the positive appropriate and necessary determination, EPA in December 2000 listed coal- and oil-fired EGUs on the section 112(c) source category list. 65 FR 79831.
On March 29, 2005, EPA issued the Section 112(n) Revision Rule (“2005 Action”) that has since been vacated by the DC Circuit Court. In that rule, EPA reversed the December 2000 Finding and concluded that it was neither appropriate nor necessary to regulate coal- and oil-fired EGUs under section 112 and delisted such units from the section 112(c) source category list. 70 FR 15994. EPA took the position that the December 2000 Finding lacked foundation and that new information confirmed that it was not appropriate or necessary to regulate coal- and oil-fired EGUs under CAA section 112.
In the final rule, EPA provided a detailed interpretation of section 112(n)(1)(A), including the terms “appropriate” and “necessary,” as those terms relate to the regulation of EGUs under section 112. In interpreting the statute, EPA recognized that section 112(n)(1)(A) provided no explicit guidance for determining whether regulation of EGUs is appropriate and necessary. As such, EPA concluded that Congress' direction on the Utility Study provided the only guidance about the substance of the appropriate and necessary finding. Accordingly, EPA extrapolated from Congress' description of the Utility Study when interpreting the terms appropriate and necessary.
Among other things, the Agency interpreted the focus on public health in the Utility Study as precluding EPA from considering environmental impacts. 70 FR 15998. EPA also looked at Congress' focus on EGU emissions in the Study and took the position that EPA could only consider hazards to public health that could be traced directly to HAP emissions from EGUs in assessing whether it was appropriate to regulate. EPA declined to consider the potential adverse public health impacts that may occur as the result of the combination of EGU HAP emissions and HAP emissions from other sources. 70 FR 15998.
In making the determination as to whether it was appropriate to regulate, EPA analyzed whether the level of HAP emissions from EGUs remaining after imposition of the requirements of the CAA would result in a hazard to public health. EPA concluded that if the HAP emissions remaining after imposition of the requirements of the CAA do not pose a hazard to public health, then regulation under section 112 is not appropriate. EPA also maintained that even if it identified a hazard to public health, regulation may still not be “appropriate” based on other relevant factors, such as the cost effectiveness of regulation under section 112. 70 FR 15600.
In the 2005 Action, EPA interpreted the term “necessary” to mean “that it is necessary to regulate EGUs under section 112 only if there are no other authorities available under the CAA that would, if implemented, effectively address the remaining HAP emissions from EGUs.” 70 FR 16001.
Applying these interpretations, the Agency stated that it was neither appropriate nor necessary to regulate HAP emissions from EGUs. The Agency took the position that the December 2000 appropriate finding lacked foundation because the finding was overbroad to the extent that it relied on environmental effects. 70 FR 16002. The EPA next stated that the appropriate determination in the December 2000 Finding lacked foundation because EPA did not fully consider the Hg reductions that would result after imposition of the requirements of the CAA and that new information showed that the level of Hg emissions from EGUs remaining after imposition of the requirements of the CAA do not pose a hazard to public health. 70 FR 16003-4. Specifically, EPA pointed to the promulgation of the Clean Air Interstate Rule (CAIR), issued pursuant to CAA section 110(a)(2)(D), and the Clean Air Mercury Rule (CAMR),
As to the necessary finding, EPA took the position that the December 2000 Finding was in error because EPA did not, at the time, examine whether there were any CAA provisions other than section 112 that, if implemented, would address any identified hazards to public health from HAP emissions from EGUs. 70 FR 16004. Specifically, EPA stated that the error existed because EPA did not consider CAA sections 110(a)(2)(D) and 111 and that, considering actions under these sections, hazard to public health from EGUs would be reduced. 70 FR 16005.
EPA also determined that it was not appropriate and necessary to regulate coal-fired EGUs on the basis of non-Hg HAP emission or oil-fired EGUs on the basis of Ni and non-Ni HAP. 70 FR 16007.
Shortly after issuance of the December 2000 Finding, an industry group challenged that finding in the DC Circuit Court.
Environmental groups, States, and tribes challenged the 2005 Action and CAMR. Among other things, the environmental and state petitioners argued that EPA could not remove EGUs
On February 8, 2008, the DC Circuit Court vacated both the 2005 Action and CAMR. The DC Circuit Court held that EPA failed to comply with the requirements of section 112(c)(9) for delisting source categories. Specifically, the DC Circuit Court held that section 112(c)(9) applies to the removal of “any source category” from the section 112(c) list, including EGUs. The DC Circuit Court rejected the argument that EPA has the inherent authority to correct its mistakes, finding that, by enacting section 112(c)(9), Congress limited EPA's discretion to reverse itself and remove source categories from the section 112(c) list. The DC Circuit Court found that EPA's contrary position would “nullify § 112(c)(9) altogether.”
On December 18, 2008, several environmental and public health organizations (“Plaintiffs”)
As required by the CAA, we determined in December 2000, and confirm that finding here, that it is appropriate to regulate emissions of Hg and other HAP from EGUs because manmade emissions of those pollutants pose hazards to public health and the environment, and EGUs are the largest or among the largest contributors of many of those HAP. It is necessary to do so for a variety of reasons, including that hazards to public health and the environment from EGUs remain after imposition of the requirements of the CAA.
In this section, we address the Agency's determination that it is appropriate and necessary to regulate coal- and oil-fired EGUs under CAA section 112. We first provide our interpretation of the critical terms in CAA section 112(n)(1). As shown below, these interpretations are wholly consistent with the CAA and the December 2000 Finding. We then demonstrate that the December 2000 Finding was valid at the time it was made based on the information available to the Agency at that time. Finally, we explain that, although not required, we recently conducted additional technical analyses given that several years have passed since the December 2000 Finding was issued. Those analyses include both a quantitative and qualitative assessment of the hazards to public health and a qualitative analysis of hazards to the environment associated with Hg and non-Hg HAP from EGUs. The analyses confirm that it remains appropriate and necessary today to regulate EGUs under CAA section 112. We also explain why these analyses and the other information currently before the Agency confirm that regulation of EGUs under section 112 is appropriate and necessary. Accordingly, such units are properly listed pursuant to section 112(c).
CAA section 112(n)(1)(A) requires the Agency to regulate EGUs under section 112 “if the Administrator finds such regulation is
Courts have interpreted the terms “appropriate” and “necessary” in other provisions of the CAA and other statutes, and concluded that those terms convey upon the Agency a wide degree of discretion.
We evaluate the terms “appropriate” and “necessary” within the statutory context in which they appear to determine the meaning of the words.
As explained above, Congress, concerned by the slow pace of EPA's regulation of HAP, “altered section 112 by eliminating much of EPA's discretion in the process.”
Congress' focus on protecting public health and the environment from EGU HAP emissions is reflected in section 112(n)(1), titled “[e]lectric utility steam generating units.” That section directs EPA to evaluate HAP emissions from EGUs. In addition to directing EPA to regulate EGUs under section 112 if it determines that it is appropriate and necessary to do so, section 112(n)(1) requires the completion of three studies related to HAP emissions from EGUs. Those studies include: (1) The Utility Study pursuant to section (n)(1)(A); (2) the Mercury Study pursuant to section (n)(1)(B); and (3) the NIEHS Study (NAS Study) pursuant to section 112(n)(1)(C).
These studies are described above, in detail. In summary, for the Utility Study, Congress required EPA to evaluate the hazards to public health that are reasonably anticipated to occur as the result of EGU emissions following imposition of the requirements of the CAA. Congress also directed EPA to identify alternative control strategies for those HAP that may warrant regulation under section 112.
The Mercury Study required by section 112(n)(1)(B) is both broader and narrower in scope, as compared to the Utility Study. For example, the Mercury Study is narrower in scope, in that it focuses solely on the impacts from Hg emissions, as opposed to all HAP. The Mercury Study is broader in scope, however, in two important respects. First, Congress required EPA to consider environmental effects in addition to health effects. Second, Congress required the Agency to consider the cumulative effects of Hg from all sources, including EGUs. In considering the cumulative effects of Hg, the Agency was not required to apportion the cause of any adverse effects among the various sources of Hg. Both the Utility and Mercury Studies considered the control technologies available to control Hg emissions, but only the Mercury Study called for the evaluation of the costs of such controls. Section 112(n)(1)(B).
EPA believes that Congress directed the Agency to conduct the Utility Study so that the Agency would understand the hazards to public health posed by HAP emissions from EGUs alone, and consider whether any hazards that were identified would be addressed through imposition of the requirements of the CAA applicable to EGUs at that time. Congress provided EPA an additional year to examine the impacts of EGU emissions of Hg on health and the environment in combination with other sources of Hg emissions.
The NAS Study required by section 112(n)(1)(C), which was due at the same time as the Utility Study, was to focus on Hg only and the adverse human health effects associated with Hg. The statute directed the determination of the threshold level of Hg below which adverse effects to human health are not expected to occur. The statute further directed the determination of the threshold for Hg concentrations in the tissue of fish which may be consumed, including by sensitive populations, without adverse effects to public health. Here, unlike the Utility Study and the Mercury Study, the statute specifically requires an evaluation of the adverse human health effects of Hg on sensitive populations.
The remaining critical element of section 112(n)(1) is the direction to EPA to determine whether it is appropriate and necessary to regulate EGUs under section 112, considering the results of the Utility Study. Although the Utility Study is a condition precedent to making the appropriate and necessary determination, nothing in section 112(n)(1)(A) precludes the Agency from considering other information in making that determination.
Taken together, we believe these provisions provide a framework for the Agency's determination of whether to regulate HAP emissions from EGUs under section 112. Through these provisions, Congress sought a prompt review and evaluation of the hazards to public health and the environment associated with Utility HAP emissions. This prompt consideration of health and environmental impacts is consistent with the strict deadlines Congress imposed in section 112 on all other source categories.
Section 112(n)(1)(B) is direct evidence that Congress was concerned with environmental effects and cumulative impacts of HAP emissions from EGUs and other sources, particularly with regard to the bio-accumulative HAP Hg. Section 112(n)(1)(C) provides further evidence that Congress was concerned with limiting HAP emissions from EGUs to a level that protects sensitive populations. We believe the scope of the Utility Study was limited to HAP emissions from EGUs and hazards to public health, not because Congress was unconcerned with adverse environmental effects or the cumulative impact of HAP emissions, but because the Utility Study, as required, was a significant undertaking in itself and Congress wanted the Agency to complete the study within 3 years. Thus, section 112(n)(1) reveals, among other things, Congress' concern for the health and environmental effects of HAP emissions from EGUs, both alone and in conjunction with other sources, the impact of Hg emissions from EGUs, and the availability of controls to address HAP emissions from EGUs.
Finally, significantly, nowhere in section 112(n)(1) does Congress require the consideration of costs in assessing health and environmental impacts. The only reference to costs is in section 112(n)(1)(B) and that reference required the Agency to consider the costs of emission reduction controls for Hg.
Section 112(n)(1)(A) itself provides no clear standard to govern EPA's analysis and determination of whether it is “appropriate and necessary” to regulate utilities under section 112. The statute simply requires EPA to regulate EGUs under section 112 if it determines that such regulation is appropriate and necessary, after considering the results of the Utility Study. As noted above, courts have interpreted the terms appropriate and necessary as conveying considerable discretion to the Agency in determining what is appropriate and necessary in a given context.
As explained more fully below, in this context, we interpret the statute to require the Agency to find it
The following subsections describe in detail our interpretation of the key statutory terms. We also explain below how the interpretations set forth in this notice are wholly consistent with the December 2000 Finding. Further, to the extent our interpretation differs from that set forth in the 2005 Action, we explain the basis for that difference and why the interpretation, as set forth in this preamble, is reasonable.
We interpret section 112(n)(1)(A) to require the Agency to find regulation of EGUs under section 112 appropriate if we determine that HAP emissions from EGUs pose a hazard to public health or the environment at the time the finding is made. The hazard to public health or the environment may be the result of HAP emissions from EGUs alone or the result of HAP emissions from EGUs in conjunction with HAP emissions from other sources. In addition, EPA must find that it is appropriate to regulate EGUs if it determines that any single HAP emitted by utilities poses a hazard to public health or the environment. We further interpret the term “appropriate” to not allow for the consideration of costs in assessing whether HAP emissions from EGUs pose a hazard to public health or the environment. Finally, we may conclude that it is appropriate, in part, to regulate EGUs if we determine that there are controls available to address HAP emissions from EGUs.
As stated above, the appropriate finding may be based on hazards to public health or the environment. Although we believe that Congress' primary concern, as expressed in section 112(n)(1)(A) and 112(n)(1)(C), related to hazards to public health, the inclusion of environmental effects in section 112(n)(1)(B) indicates Congress' interest in protecting the environment from HAP emissions from EGUs as well.
Moreover, the term “appropriate” is extremely broad and nothing in the statute suggests that the Agency should ignore adverse environmental effects in determining whether to regulate EGUs under section 112. Further, had Congress intended to prohibit EPA from considering adverse environmental effects in the “appropriate” finding, it would have stated so expressly. Absent clear direction to the contrary, and considering the purpose of the CAA (
We also maintain that the Agency should base its “appropriate” evaluation on the hazards to public health or the environment that exist at the time the determination is made, not after considering the imposition of the other requirements of the CAA. The Agency evaluates whether imposition of the requirements of the CAA will adequately address any identified hazards only in the context of the necessary finding. Thus, in assessing whether regulation of EGUs is appropriate under section 112, we evaluate the current hazards posed by such units, as opposed to projecting what such hazards may look like after imposition of the requirements of the CAA.
We further interpret the CAA as allowing the Agency to base the appropriate finding on hazards to public health or the environment that result from HAP emissions from EGUs alone or hazards to public health and the environment that result from HAP emissions from EGUs in conjunction with HAP emissions from other sources. Section 112(n)(1) does not focus exclusively on EGU-only HAP emissions.
As explained above, section 112(n)(1)(B) and (C) require either expressly or implicitly the consideration of Hg emissions from all sources, not just EGUs. Section 112(n)(1)(B) is of note because that provision does not require the Agency to determine the hazard posed by Hg from EGUs alone. Rather, Congress required EPA to evaluate the health and environmental effects of Hg emissions from “electric utility steam generating units, municipal waste combustion units, and other sources, including area sources.” Section 112(n)(1)(C) is also relevant because it requires a human health-based assessment of the hazards posed by Hg without regard to the origin of the Hg. Congress could have directed an evaluation of the human health risk attributable to EGUs alone, but it did not. Congress also did not require such an assessment be conducted in the NAS Study.
In addition, Congress directed the Agency in section 112(n)(1)(A) to regulate EGUs under section 112 if the results of the Utility Study caused the Agency to conclude that regulation was appropriate and necessary. Section 112(n)(1)(A) is not written in a manner to preclude consideration of other information when determining whether it is appropriate and necessary to regulate EGUs under section 112, and that includes consideration of all hazards, both health and environmental, posed by HAP emitted by EGUs.
Finally, focusing on HAP emissions from EGUs alone when making the appropriate finding ignores 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 that harm. For this reason, we believe we may consider the hazards to public health and the environment posed by HAP emissions from EGUs alone or in conjunction with HAP emissions from other sources.
Furthermore, the appropriate finding may be based on a finding that any single HAP emitted from EGUs poses a hazard to public health or the environment. Nothing in 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 section 112. Interpreting the statute in this manner would preclude the Agency from addressing under section 112 identified or potential hazards to public health or the environment associated with HAP emissions from EGUs unless
Indeed, Congress' focus in section 112(n)(1)(B) and (C) on Hg indicates Congress' awareness that Hg was a problem and supports the position that EPA could find it appropriate to regulate EGUs based on the adverse health and environmental effects of a single HAP. Furthermore, the statute does not directly or expressly authorize the Agency to regulate only those HAP for which a hazard finding has been made. In fact, the statute requires the Agency to regulate EGUs under section 112 if the Agency finds regulation under section 112 is appropriate and necessary, and regulation under section 112 for major sources requires MACT standards for
We also maintain that the better reading of the term “appropriate” is that it does not allow for the consideration of costs in assessing whether hazards to public health or the environment are reasonably anticipated to occur based on EGU emissions. Had Congress intended to require the Agency to consider costs in assessing hazards to public health or the environment associated with EGU HAP emissions, it would have so stated.
This interpretation is consistent with the overall structure of the CAA. Congress did not authorize the consideration of costs in listing any source categories for regulation under section 112. In addition, Congress did not permit the consideration of costs in evaluating whether a source category could be delisted pursuant to the provisions of section 112(c)(9).
Under section 112(n)(1)(A), EPA is evaluating whether to regulate HAP emissions from EGUs at all. It is reasonable to conclude that costs may not be considered in determining whether to regulate EGUs under section 112 when hazards to public health and the environment are at issue.
Finally, consistent with sections 112(n)(1)(A) and 112(n)(1)(B), we conclude that we may base the appropriate finding on the availability of controls to address HAP emissions from EGUs.
The Agency's interpretation of the term “appropriate,” as set forth above, is wholly consistent with the Agency's appropriate finding in December 2000. As noted above, in 2000, we concluded that it was appropriate to regulate EGUs under section 112 because Hg in the environment posed a hazard to public health and the environment. The Agency also concluded it was appropriate because of uncertainties associated with the hazards posed by other HAP emitted from EGUs. 65 FR 79827. Finally, the EPA concluded that it was appropriate because of the availability of controls to reduce HAP emissions from EGUs. In making the finding as it related to Hg, the Agency considered the hazards posed by Hg in the environment and the contribution of EGUs to that hazard. In addition, EPA did not consider costs when making the appropriate determination. Further, the appropriate finding evaluated the hazards at the time, as opposed to the hazards remaining after imposition of the requirements of the CAA. EPA evaluated whether the other requirements of the CAA would adequately address the hazards in the necessary prong only.
As noted above, in 2005, EPA revised its December 2000 Finding and stated that the appropriate finding: (1) Could not be based on adverse environmental effects; (2) must be made considering only HAP emissions from EGUs; (3) must be made after consideration of the imposition of the requirements of the CAA; and (4) must consider other factors (
First, we change the position taken in 2005 that the appropriate finding could not be based on environmental effects alone. In 2005, we did not properly consider all of the provisions of section 112(n)(1). The Agency should not interpret the CAA to limit the Agency's discretion to protect the environment absent clear direction to that effect. In essence, the Agency's interpretation in 2005 would have required the Agency to ignore a catastrophic environmental harm (
Second, for all of the reasons stated above, we are revisiting the 2005 interpretation that required the Agency to consider HAP emissions from EGUs without considering the cumulative impacts of all sources of HAP emissions. Nothing in section 112(n)(1)(A) prohibits consideration of HAP emissions from EGUs in conjunction with HAP emissions from other sources of HAP. We believe it is more reasonable to interpret the statute to authorize the Agency to consider the cumulative effects of HAP that are emitted from EGUs and other sources. This interpretation allows the Agency to evaluate more fully whether HAP emissions from EGUs pose a hazard to public health or the environment consistent with the manner in which the public and the environment are exposed to HAP emissions.
Third, we are revising the 2005 interpretation that required the Agency to evaluate the hazards to public health after imposition of the requirements of the CAA. We conclude today that in 2005 the Agency improperly conflated the appropriate finding and the necessary finding by requiring consideration of the ameliorative effects of other CAA requirements in both prongs of the appropriate and necessary finding. We believe the Agency must find it appropriate to regulate EGUs under section 112 if we determine that HAP emitted by EGUs pose a hazard to public health or the environment at the time the finding is made. The issue of how and whether those hazards are reduced after imposition of the requirements of the CAA is an issue for the necessary prong of the finding.
Finally, we are rejecting the 2005 interpretation that authorizes the Agency to consider other factors (
Once the Agency has determined that it is appropriate to regulate EGUs under section 112, the Agency must then determine whether it is necessary to regulate EGUs under section 112. As stated above, we have considerable discretion to determine whether regulation of EGUs under section 112 is necessary. The DC Circuit Court 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.”
If the Agency concludes that it is appropriate to regulate EGUs, we believe it is necessary to regulate HAP emissions from EGUs if we determine that the imposition of the requirements of the CAA will not sufficiently address the identified hazards to public health or the environment posed by HAP that are emitted from EGUs. We maintain that we must find it necessary based on such a finding even if regulation under section 112 will not fully resolve the identified hazard to public health or the environment.
We may also determine it is necessary to regulate under section 112 if we are uncertain whether the imposition of the other requirements of the CAA will sufficiently address the identified hazards. We may find it necessary to regulate EGUs under section 112 even if we were to conclude, based on reasonable estimations of emissions reductions, that the imposition of the other requirements of the CAA would, or might, significantly reduce the identified hazard, because the only way to guarantee that such reductions will occur at all EGUs and be maintained is through a section 112(d) standard that directly regulates HAP emissions from utilities. Finally, we may also find it necessary to regulate EGUs under section 112 to further the policy goal of supporting international efforts to reduce HAP emissions, including Hg.
In the Utility Study, Congress directed the Agency to evaluate the hazards to public health posed by HAP emissions from EGUs remaining after imposition of the requirements of the CAA, and it gave EPA 3 years to complete that Study. We interpret the necessary requirement first in the context of the phrase “after imposition of the requirements of [the CAA].” Section 112(n)(1)(A).
Congress did not define the phrase “after imposition of the requirements of the Act.” The plain meaning of the term “requirement” is something that is necessary, or obligatory.
The purpose of the ARP was to reduce the adverse effects of acid deposition (more commonly known as “acid rain”), by limiting the allowable emissions of SO
Moreover, the ARP achieved the required reductions by allocating allowances to emit SO
The other significant requirement that Congress imposed in the 1990 Amendments was to revise the NSPS for NO
There are other requirements of Title I of the Act that could affect EGUs, and they include the National Ambient Air Quality Standards (NAAQS). Congress did not impose these provisions directly on EGUs, however. Instead, EPA is responsible for developing the NAAQS, and states are primarily responsible for assuring attainment and maintenance of the NAAQS. For example, EPA stated in the Utility Study that implementation of the 1997 NAAQS for ozone and PM may lead to reductions in Hg emissions, but those potential reductions could not be sufficiently quantified because states have the ultimate responsibility for implementing the NAAQS. See Utility Study, pages ES-25, 1-3, 2-32, 3-14, and 6-15. States use a broad combination of measures (mobile and stationary) to obtain the reductions needed to meet the NAAQS. These decisions are unique to each state, as each state must identify and assess the sources contributing to nonattainment and determine how best to meet the NAAQS. EPA cannot predict with any certainty precisely how states will ensure that the reductions needed to meet the NAAQS will be realized. Moreover, there are additional uncertainties even were a state to impose requirements on EGUs through a State Implementation Plan (SIP), because each EGU may choose to meet the required reductions in a different manner, which could result in more or less HAP emission reductions. Accordingly, we do not believe it would have been appropriate to include such potential emissions reductions in determining whether it is necessary to
Further, it is reasonable to interpret the phrase “after imposition of the requirements of the Act”, as only requiring consideration of those requirements that Congress directly imposed on EGUs through the CAA as amended in 1990 and for which EPA could reasonably predict emission reductions at the time of the Utility Study. To interpret the phrase otherwise would require the Agency to look ahead two to three decades to forecast what possible requirements might be developed and applied to EGUs under some requirement of the CAA at some point in the future.
Indeed, such an interpretation would be inconsistent with the structure and purpose of section 112. As noted above, Congress gave EPA until 1993 to issue the Utility Study and expected the appropriate and necessary finding would follow shortly thereafter. Congress also required EPA to address HAP emissions rapidly from all source categories. See CAA 112(e), supra. It is reasonable to presume that Congress intended EPA to evaluate the need for EGU HAP controls in light of the requirements imposed upon the industry via the new 1990 requirements. Obviously the central requirement that was new and applied to EGUs was the ARP which would be implemented rapidly following passage of the 1990 amendments to the Act.
Although the above represents a reasonable interpretation of what Congress contemplated the Utility Study would examine with regard to “imposition of the requirements of the Act,” we recognize that we have discretion to look beyond the Utility Study in determining whether it is necessary to regulate EGUs under section 112. Given that several years have passed since the December 2000 Finding, we conducted additional analysis. Although not required, we conducted this analysis to demonstrate that even considering a broad array of diverse requirements, it remains appropriate and necessary to regulate EGUs under section 112.
Specifically, we examined a host of requirements, which in our view, far surpass anything Congress could have contemplated in 1990 we would consider as part of our “necessary” determination. For example, our analysis includes certain state rules regulating criteria pollutants, Federal consent decrees, and settlement agreements for criteria pollutants resolving state-initiated and citizen-initiated enforcement actions.
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.
Furthermore, we believe it is necessary to regulate if we have identified a hazard to public health or the environment that will not be addressed by imposition of the requirements of the CAA even if regulation of EGUs under section 112 will not fully resolve the identified hazard. We conclude that this is particularly true for bio-accumulative HAP such as Hg because EPA can only address such emissions from domestic sources and mitigation of identified risks associated with such HAP is a reasonable goal.
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 final or are still subject to judicial review (
We also may find it necessary to regulate EGUs under section 112 even if we conclude, based on reasonable estimations of emissions reductions, that the imposition of the other requirements of the CAA will significantly reduce the identified hazard. We maintain this is reasonable because the only way to guarantee that the necessary reductions in HAP emissions will occur at all EGUs and be maintained is through a section 112(d) standard that directly regulates HAP emissions from EGUs. This is true because sources could discontinue use of controls for criteria pollutants that achieve HAP reductions as a co-benefit if new control technologies or practices are identified that reduce the relevant criteria pollutants but do not also reduce HAP. For example, scrubbers are often used to reduce SO
Our interpretation of the necessary finding is reasonable and consistent with the December 2000 Finding. In that finding, EPA determined that the imposition of the requirements of the CAA would not address the serious public health and environmental hazards resulting from EGU HAP emissions. We also stated that section 112 is the authority to address hazards from HAP emissions. Because we determined that the imposition of the requirements of the CAA would not address the identified hazards, we correctly concluded it was necessary to regulate under section 112. Although the Agency did not expressly interpret the term necessary in the December 2000 Finding, under the interpretation set forth above, the Agency must find it necessary if we conclude that the imposition of the other requirements of the CAA will not address the identified hazards. Because EPA reached that conclusion, the Agency correctly determined that it was necessary to regulate EGU HAP emissions and did not need to base the 2000 necessary finding on any of the other bases set forth above.
We stated in 2005 that “it is necessary to regulate EGUs under section 112 only if there are no other authorities under the CAA that, if implemented, would effectively address the remaining HAP emissions from EGUs.” 70 FR 16,001.
Congress enacted section 112 for the express purpose of regulating HAP emissions. It is not reasonable to interpret section 112(n)(1)(A) to require the Agency to find another provision of the CAA to address identified hazards to public health or the environment. This is particularly the case where the Agency would not have certainty that such alternative legal theory would withstand judicial scrutiny because section 112 is the authority expressly provided to regulate HAP emissions and no other provision provides express authority to regulate HAP emissions from existing stationary sources.
Furthermore, section 112(n)(1)(A) states explicitly that the Agency shall regulate EGUs “under this section” if the Agency determines it is “appropriate and necessary after considering the results of the (Utility Study).” We reiterate that the only precondition to regulating EGUs is consideration of the results of the Utility Study. We believe it is unreasonable to argue that Congress directed the Agency as part of the Utility Study to scour the CAA for alternative legal authorities for regulating HAP emissions, either directly or indirectly. Indeed, the Agency did not interpret the requirement in section 112(n)(1)(A) to conduct the study in that manner, as evidenced by the Utility Study itself. Absent that interpretation, we think it is unreasonable to conclude that the Agency must undertake such an effort to make the necessary finding because Congress authorized the Agency to base the “appropriate and necessary” finding on the Utility Study alone.
For all the reasons above, we believe it is appropriate to regulate EGUs under section 112 if the Agency determines that HAP emissions from such units pose a hazard to public health or the environment at the time of the finding, and it is necessary to regulate EGUs under section 112 if the imposition of the other requirements of the CAA will not adequately address the identified hazards to public health or the environment, or there are other compelling reasons making it necessary to regulate HAP emissions from EGUs under section 112.
Section 112(n)(1)(A) neither defines the phrase “hazards to public health,” nor sets forth parameters for EPA to use in determining whether HAP emissions from EGUs pose a hazard to public health. The phrase is also not defined elsewhere in the CAA. EPA, therefore, has broad discretion, using its technical and scientific expertise, to determine whether HAP emissions from EGUs pose a hazard to public health.
In evaluating hazards to the environment, however, Congress did provide some direction. Specifically, it defined the term “adverse environmental effects” in section 112(a)(7), and as explained further below, we evaluate hazards to the environment consistent with that definition.
Because Congress did not define “hazard to public health” the Agency must use its scientific and technical expertise to determine what constitutes a hazard to public health in the context of EGU HAP emissions. The Agency considers various factors in evaluating hazards to public health, including, but not limited to, the nature and severity of the health effects associated with exposure to HAP emissions; the degree of confidence in our knowledge of those health effects; the size and characteristics of the populations affected by exposures to HAP emissions; the magnitude and breadth of the exposures and risks posed by HAP emissions from a particular source category, including how those exposures contribute to risk in populations with additional exposures to HAP from other sources; and the proportion of the population exposed above benchmark levels of concern (
Although Congress provided no definition of hazard to public health, section 112(c)(9)(B) is instructive. In that section, Congress set forth a test for removing source categories from the section 112(c) source category list. That
Congress defined the phrase “adverse environmental effect” in section 112(a)(7) to mean “any significant and widespread adverse effect, which may reasonably be anticipated, to wildlife, aquatic life, or other natural resources, including adverse impacts on populations of endangered or threatened species or significant degradation of environmental quality over broad areas.”
Section 112(n)(1)(B) required EPA to examine the environmental effects of Hg emissions. Because Congress defined the term “adverse environmental effect” in section 112(a)(7), we believe that such definition should guide our assessment of whether hazards to the environment posed by Utility HAP emissions exist. As with hazards to public health, however, the Agency must use its discretion to determine whether the adverse environmental effects identified warrant a finding that it is appropriate to regulate HAP emissions from EGUs based on those effects. In evaluating the environmental effects, we have stated that we may consider various aspects of pollutant exposure, including: “[t]oxicity effects from acute and chronic exposures” expected from the source category (as measured or modeled); “persistence in the environment;” “local and long-range transport;” and “tendency for bio-magnification with toxic effects manifest at higher trophic levels.” 67 FR 44,718 (July 3, 2002).
In interpreting the term itself, we believe the broad language in section 112(a)(7) referring to “any” enumerated effect “which may be reasonably anticipated” evinces Congressional intent to not restrict the scope of that term to only certain specific impacts. 62 FR 36440 (July 7, 1997); 63 FR 14094 (March 24, 1998). Further, the section 112(a)(7) reference to “any” enumerated effect in the singular clearly contemplates impacts of limited geographic scope, suggesting that the “widespread” criterion does not present a particularly difficult threshold to cross.
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
In the first sentence, Congress described the study and directed the Agency to evaluate the hazards to public health posed by HAP emissions listed
Furthermore, the DC 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 section 112.
EPA requests comment on section III.A.
EPA reasonably determined in December 2000 that it was appropriate and necessary to regulate HAP emissions from EGUs under CAA section 112. In making that finding, EPA considered all of the information that Congress had identified as most salient, including the Utility Study, the Mercury Study, and the information in the NAS Study.
In making the appropriate and necessary finding in 2000, EPA considered all of the relevant information in the three Studies required by section 112(n)(1) and the NAS Study. 65 FR 79826-27. The Utility, Mercury, and NAS Studies together consisted of thousands of pages of information and technical analyses. All of these studies were peer reviewed prior to issuance. In fact, the Mercury Study was reviewed by over 65
In addition to conducting the studies that Congress required, EPA collected relevant information on Hg emissions and available control technologies. Specifically, pursuant to a CAA section 114 ICR, EPA collected data on the Hg content in coal from all coal-fired EGUs for calendar year 1999. Through the 1999 ICR, EPA also obtained stack test data for certain coal-fired EGUs to verify Hg emissions estimates for the EGU source category. 65 FR 79826. EPA further solicited data from the public through a February 29, 2000, notice (65 FR 10,783), and provided the public an opportunity to provide its views on what the regulatory finding should be at a public meeting. 65 FR 79826 (citing 65 FR 18992). Finally, EPA undertook an evaluation of the Hg control performance of various emission control technologies that were either currently in use on EGUs or that could be applied to such units for Hg control. EPA conducted this evaluation with other parties, including the DOE. 65 FR 79826. EPA also evaluated other emission control approaches that would reduce EGU HAP emissions.
Although Congress did not provide a deadline by which EPA must issue the appropriate and necessary finding, the deadlines Congress provided for completion of the required studies signal that Congress wanted EPA to make the appropriate and necessary finding shortly after completion of the studies. Congress required that the Utility Study and NIEHS Study be submitted by November 15, 1993, and the Mercury Study by November 15, 1994. We reasonably conclude based on the timing of the studies that Congress wanted the Agency to evaluate the hazards to public health and the environment associated with HAP emissions from EGUs as quickly as possible and take steps to regulate such units under section 112 if hazards were identified.
Congress later provided a direct signal as to the timing of the appropriate and necessary finding in the committee report associated with EPA's fiscal year 1999 appropriations bill, which directed the Agency to fund the NAS Study. In that report, Congress indicated that it did not want the Agency to make the appropriate and necessary finding for Hg until the NAS study was completed.
After considering all of the information that Congress considered most relevant, including the NAS Study that was issued in June 2000, EPA determined that it was appropriate and necessary to regulate EGUs under section 112 and listed such units for regulation on December 20, 2000. As explained below, the Agency acted reasonably in issuing the finding at that time because of the identified and potential hazards to public health and the environment associated with HAP emissions from utilities, which the Agency concluded would not be addressed through imposition of the requirements of the CAA. It would not have been reasonable to delay the finding to collect additional information given the considerable delay in completion of the required studies and the hazards to public health and the environment identified as of December 2000.
The December 2000 Finding that it was appropriate to regulate EGUs under section 112 focused largely on hazards to public health and the environment associated with Hg emissions. EPA reasonably focused on this pollutant given that Hg is a persistent, bioaccumulative pollutant that causes serious neurotoxic effects. Indeed, Congress specifically identified this pollutant as one of concern and required two separate studies to be conducted regarding Hg emissions.
By 2000, the Agency had amassed “a truly vast amount of data” on Hg.
We discuss below the central pieces of data and information concerning Hg that formed the basis of our conclusion that Hg posed a threat to public health and the environment.
EPA first concluded that Hg from EGUs was the HAP of greatest concern.
EPA recognized that increased Hg deposition would lead to increased levels of MeHg in fish and such “increased levels in fish [would] * * * lead to toxicity in fish-eating birds and mammals, including humans.” 65 FR 79830. EPA agreed with the NAS that “the long term goal needs to be the reduction in the concentrations of methylmercury in fish” and concluded that reducing Hg emissions from EGUs was “an important step toward achieving that goal.” 65 FR 79830.
The Agency then identified the most affected populations. Specifically, the Agency concluded that women of childbearing age are the population of greatest concern because the developing fetus is the most sensitive to the effects of MeHg. 65 FR 79827. EPA estimated that at that time, 7 percent of women of childbearing age (or about 4,000,000 women) in the continental U.S. were exposed to MeHg at levels that exceeded the RfD and that about 1 percent of women of childbearing age (or about 580,000 women) had MeHg exposures 3 to 4 times the RfD. 65 FR 79827.
The NAS Study affirmed EPA's assessment of the toxicity of MeHg and that the RfD EPA had developed for MeHg was valid. 65 FR 79827. The Agency acknowledged that there was uncertainty with risk at exposure above the RfD, but indicated that risk increased with increased exposure. 65 FR 79827. In addition to focusing on women of childbearing age and developing fetuses, EPA stated a particular concern for subsistence fish-eating populations due to their regular and frequent consumption of relatively large quantities of fish. 65 FR 79830.
As for environmental effects, the Agency observed adverse effects to avian species and wildlife in laboratory studies at levels corresponding to fish tissue MeHg concentrations that are exceeded by a significant percentage of fish sampled in lake surveys. 65 FR 79830. The Agency explained that wildlife consume fish from a more localized geographic area than humans, which can result in elevated levels of Hg in certain fish eating species. Those species include, for example, the kingfisher and some endangered species, such as the Florida panther. 65 FR 79830.
In summary, in the December 2000 Finding, EPA identified Hg in the environment as a hazard to public health and the environment, determined that a significant segment of the most sensitive members of the population were exposed to MeHg at levels exceeding the RfD, and confirmed that the RfD was valid.
In the 2000 finding, the Agency estimated that about 60 percent of the total Hg deposited in the U.S. came from U.S. anthropogenic air emission sources. 65 FR 79827. The Agency stated that the remainder of the Hg deposited in the U.S. was from natural emission sources, reemissions of historic global anthropogenic Hg releases, and non-domestic anthropogenic sources of Hg. 65 FR 79827. EPA identified coal combustion and waste incineration as the source categories likely to bear the greatest responsibility for direct anthropogenic Hg deposition in the continental U.S. 65 FR 79827. EPA further explained that EGUs are the largest unregulated domestic source of Hg emissions, accounting for approximately 30 percent of the current anthropogenic air emissions from domestic sources. 65 FR 79827. These numbers, taken together, reveal that EGUs accounted for approximately 18 percent of the total Hg deposition in the U.S on an annual basis, considering all U.S. anthropogenic sources, natural emission sources, reemissions of historic global anthropogenic Hg releases, and non-domestic anthropogenic sources of Hg.
In 2000, the Agency also found a plausible link between domestic anthropogenic Hg emissions and MeHg in fish. 65 FR 79829. The Agency explained that although that link could not be estimated quantitatively at the time, the facts before the Agency were sufficient for it to conclude that EGU Hg emissions posed a hazard to public health.
Based on the foregoing and all of the information set forth in the December 20, 2000, notice, the Agency found that Hg emissions from EGUs posed a hazard to public health and the environment. In making this finding, the Agency focused on the significant adverse health effects associated with MeHg and the persons most adversely impacted by Hg. The populations most affected were women of childbearing years and their developing fetuses and subsistence fishers. The Agency viewed the adverse health effects and environmental effects described above in conjunction with the then current Hg emissions information provided by EGUs in response to the 1999 ICR. Based on that information, EPA concluded that EGUs accounted for approximately 30 percent of the U.S. anthropogenic emissions of Hg, which translated into about 18 percent of the total Hg deposition in the U.S. at that time. EPA also knew that Hg from EGUs comprised an undetermined amount of the reemissions of Hg.
At the time of the December 2000 Finding, the Agency had issued section 112 or 129 standards for several of the other source categories that were significant Hg emitters, and the Agency was required by the CAA to establish section 112 or 129 standards for the other significant Hg emitters.
EPA also reasonably predicted that incremental reductions in Hg emissions, including from EGUs, would lead to incremental reductions in the MeHg concentration in fish tissue, and that such reductions would, in turn, reduce the risk to public health and the environment. 65 FR 79830. The Mercury Study recognized that Hg is a metal that remains in the environment permanently and can circulate continuously through various environmental media. Although EPA was aware that reductions of Hg from anthropogenic sources may not lead to immediate reductions in fish tissue levels, such reductions would nonetheless serve the long-term goal of reducing the mobilization of Hg to the atmosphere and thus reduce MeHg concentrations in fish.
EPA, therefore, reasonably determined based on the facts that existed at the time that regulation of EGUs was appropriate in order to reduce the hazards to public health and the environment associated with the Hg emissions from EGUs. EPA expressly acknowledged that there were uncertainties concerning the extent of the risk due to Hg emissions from EGUs, because the Agency had not quantified the amount of MeHg in fish that was directly attributable to EGUs compared to other sources of MeHg. 65 FR 79827. That EPA did not quantify in 2000 the amount of MeHg in fish due to EGUs did not preclude EPA from making an “appropriate” finding. Nowhere in section 112(n)(1) or in its direction concerning the NAS Study did Congress require EPA to quantify the amount of MeHg in fish tissue that was directly attributable to EGUs.
In any event, in light of the breadth of the scientific evidence before the Agency and the conclusions the Agency reached, it would not have been reasonable to delay the finding to develop an analytical tool to apportion the Hg in fish. The Hg problem at the time was well documented, and the fact that EGUs represented such a significant portion of the Hg deposition in the U.S. was ample evidence that it was appropriate to regulate emissions from EGUs—the single largest unregulated domestic source of Hg emissions. 65 FR 79827.
Finally, the Agency had already delayed in completing the section 112(n)(1) studies. Additional delay would have been unreasonable because of the persistence of Hg in the environment and its tendency to bioaccumulate up the food chain, both aspects of Hg in the environment that make it critical to limit additional releases to the environment as quickly as possible. In addition, delay would have been unreasonable because EPA estimated at that time that about 7 percent of women of child-bearing age, one of the most at-risk populations, was exposed to Hg at levels exceeding the RfD, and EPA knew that as the level of exposure above the RfD increased, the level of risk and the extent and severity of adverse effects increased. Thus, EPA reasonably made the appropriate and necessary determination in 2000 to ensure that the largest unregulated domestic source of Hg would be required to install controls, thereby achieving an incremental reduction in the risk associated with a persistent, bioaccumulative HAP.
The December 2000 Finding was also reasonable as it pertained to the non-Hg HAP emitted from EGUs. The Agency found it was appropriate to regulate EGUs based on the potential human health concerns from non-Hg HAP, particularly Ni from oil-fired EGUs, and the uncertainties regarding the public health impact of emissions of such HAP. 65 FR 79830. Based on the information in the Utility Study, EPA could not conclude based on the available information that the non-Hg HAP posed no hazards to public health.
Specifically, the Agency noted that several non-Hg HAP metals, including As, Cr, Ni, and Cd, were of potential concern for carcinogenic effects. 65 FR 79827. EPA acknowledged that the risks did not appear high, but it stated that the risks were not sufficiently low to disregard the metals as a potential concern for public health. 65 FR 79827;
EPA did not view the risks associated with non-Hg HAP in a vacuum. Rather, EPA considered the threat to public health, including uncertainties, associated with both Hg and non-Hg HAP emissions from EGUs in determining whether it was appropriate to regulate such units under section 112.
Finally, even looking solely at non-Hg HAP, EPA's conclusions support regulation of EGUs under section 112. Although Congress provided no metric for the hazard to public health determination, section 112(c)(9) is instructive. Specifically, in that section, Congress set forth a test for removing source categories from the section 112(c) source category list. That test is relevant because it reflects Congress' view as to the level of health effects associated with HAP emissions that Congress thought warranted regulation under section 112. If a source category failed to meet that test, it would remain subject to the requirements of CAA section 112. Thus, CAA section 112(c)(9) can be read to reflect Congress' view of what adverse public health effects from HAP emissions are acceptable and thus do not warrant regulation under CAA section 112.
For carcinogens, which are at issue here, section 112(c)(9)(B)(i) provides that EPA may delete a source category from the section 112(c) list if no source in the category (or group of sources in the case of area sources) emits such HAP in quantities that 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). Thus, section 112(c)(9)(B)(i) prohibits the Agency from delisting a major source category from the section 112(c) list if any single source within that category emits cancer causing HAP at levels that may cause a
In addition to determining that it was appropriate to regulate because of the known and potential hazards to public health and the environment, EPA also concluded that it was appropriate to regulate HAP emissions from EGUs because EPA had identified a number of control options that would effectively reduce HAP emissions from EGUs. 65 FR 79828-30. EPA discussed the various controls available to reduce HAP emissions from EGUs in the December 2000 Finding. The approach of section 112, as amended in 1990, is based on the premise that, to the extent there are controls available to reduce HAP emissions, sources should be required to use them. Thus, it was reasonable to base the appropriate finding in part on the conclusion that controls currently available were expected to reduce HAP emissions from EGUs.
In 2000, EPA found it was necessary to regulate HAP emissions from EGUs under section 112 because the imposition of the other requirements of the CAA would not address the serious public health and environmental hazards arising from such emissions. 65 FR 79830. EPA also noted that Congress enacted section 112 specifically to address HAP emissions from stationary sources, and it was thus reasonable to regulate HAP emissions from EGUs under that section given the hazards to public health and the environment posed by such emissions.
In Table 1 of the December 20, 2000 notice, EPA set forth its projections of HAP emissions for 2010. In assessing those projections in 2000, EPA considered the data that it had obtained as the result of the 1999 ICR. 65 FR 79828. It also considered projected changes in the population of units, fuel consumption, and control device configuration.
Specifically, in estimating the projected 2010 HAP emissions from EGUs, EPA accounted for the HAP reductions that would occur as the result of the controls required to comply with the ARP. Congress added the ARP in CAA Title IV, as part of the 1990 amendments, and that program is primarily directed at EGUs. EPA, therefore, considered the HAP reductions projected to occur as the result of control configurations needed to meet the Acid Rain requirements of the CAA.
As shown in Table 1 of the December 20, 2000 notice, EPA estimated that the level of all HAP emitted by coal-fired EGUs would increase by 2010. 65 FR 79828 (Table 1). For Hg, EPA estimated that EGUs emitted 46 tons of Hg in 1990 and 43 tons of Hg in 1999, and it projected that EGUs would emit approximately 60 tons of Hg in 2010. 65 FR 79827-828. EPA also estimated an overall increase in non-Hg HAP emissions from coal-fired EGUs. Given these estimates and projections, which were based on the best information available at the time, EPA reasonably concluded that the identified and potential hazards associated with HAP from coal-fired EGUs would not be addressed through imposition of the other requirements of the CAA.
For oil-fired EGUs, EPA projected a decline in overall HAP emissions. The decline was primarily due to projected retirements and fuel switching from oil to natural gas. EPA could not conclude based on the information available at the time that the facilities posing the cancer risks, due primarily to Ni emissions, would retire or change fuels. As a result of these uncertainties and the uncertainties as to the extent of the public health impact from oil-fired units, EPA found that it was necessary to regulate such units under section 112.
In 2005, the Agency asserted that the December 2000 Finding lacked foundation for two reasons. First, the Agency stated that the 2000 appropriate finding was overbroad to the extent it relied on adverse environmental effects. Second, the Agency stated that the 2000 appropriate finding lacked foundation because EPA did not fully consider the Hg emissions remaining after imposition of the requirements of the CAA. For the reasons provided below, we reject these assertions as unfounded. As demonstrated above, EPA's 2000 appropriate and necessary finding was sound and fully supported by the record before the Agency in 2000.
EPA reasonably examined the adverse environmental impacts associated with Hg in making the December 2000 Finding. In 2005, EPA changed its interpretation of the broad term “appropriate” to restrict the consideration of environmental effects only to situations where the Agency had determined that a hazard to public health exists as a result of EGU HAP emissions. As such, EPA stated in 2005 that the December 2000 Finding lacked foundation to the extent it was based on environmental effects.
As explained above in Section III.A, EPA's 2005 change in how it interpreted the term “appropriate” lacks merit. Congress gave EPA broad discretion to determine whether it was appropriate to regulate EGUs under section 112. On the one hand, EPA recognized that broad discretion in 2005, but on the other hand, it sought to limit that discretion by only allowing environmental impacts to be considered if a hazard to public health was found. The 2005 interpretation was based on the flawed notion that the Agency should only consider health effects because the Utility Study only required consideration of hazards to public health. But, as noted above, Congress specifically directed EPA in section 112(n)(1)(B) to consider the environmental effects associated with Hg emissions from EGUs. It was entirely reasonable, therefore, for EPA to consider such effects in making its appropriate finding in 2000.
Furthermore, even under the Agency's flawed 2005 interpretation, which allowed consideration of environmental effects only where a hazard to public health exists, EPA properly considered environmental effects in 2000 because we, in fact, found a hazard to public health based on the record at that time.
EPA interprets the “appropriate” finding to require an evaluation of the hazards to public health and the environment at the time of the finding. This interpretation is consistent with the approach taken in 2000. By contrast, in the 2005 “appropriate” analysis, EPA considered the hazards to public health that were reasonably anticipated to occur “after imposition of the requirements of the Act.” In short, EPA infused the “after imposition of the requirements of the Act” inquiry into
As explained in Section III.A, this interpretation improperly conflates the “appropriate” and “necessary” analysis. Accordingly, any assertion that EPA's 2000 appropriate finding is flawed because the Agency failed to consider the other requirements of the CAA should be rejected.
Even considering the Agency's flawed 2005 interpretation of the term “appropriate,” there is nothing in the record to suggest that the Agency erred in 2000 with regard to assessing Hg emissions. As explained above, in 2000, EPA reasonably considered those requirements of the CAA that directly pertained to EGUs (
In addition, in 2000, EPA recognized that EGUs may be subject to requirements pursuant to SIP developed in response to NAAQS. In fact, EPA had projected a potential 11 tpy reduction in EGU Hg emissions as the result of the ozone and PM NAAQS. Utility Study, p. 1-3. EPA explained in the Utility Study, however, why it did not account for such reductions in its 2010 emission projections.
First, EPA explained that some of the Hg reductions associated with the PM and ozone NAAQS would be realized through the implementation of the ARP, and, thus, had already been accounted for in its 2010 projections.
Furthermore, at the time of the Utility Study, no areas had been designated as nonattainment with the 1997 revised PM NAAQS.
EPA also asserted in 2005 that it failed to account for Hg reductions associated with the 1997 Utility NSPS in assessing whether it was appropriate to regulate in 2000. In the Utility Study, EPA noted that EGUs would be implementing the same controls for NO
Finally, EPA asserted in 2005 that it failed to account for the Hg reductions associated with the NO
EPA solicits comment on section III.B.
As shown above, in 2000, EPA reasonably determined, based on the record before it at the time, that it was appropriate and necessary to regulate EGUs under CAA section 112. Once that finding was made, EPA properly listed EGUs pursuant to section 112(c), and EGUs remain a listed source category.
As the DC Circuit Court held in
Here, we have a validly listed source category. EPA could not have met the delisting criteria in 2000 or 2005, and it still cannot meet those criteria today.
The information in the Utility Study shows that HAP emissions from a number of EGUs caused a lifetime cancer risk greater than one in one million. Nothing in the 2005 record suggested anything to the contrary, and as such, the Agency did not delist EGUs in 2005 pursuant to section 112(c)(9). Finally, EPA has conducted 16 case studies based on the data collected in support of this proposed rule and determined that 4 of those facilities evaluated (25 percent) presented a lifetime cancer risk greater than 1 in 1 million. Thus, based on current data and analysis, EGUs fail the first requirement for delisting set forth in section 112(c)(9)(B)(i). Because EGUs do
As explained above, the December 2000 appropriate and necessary determination is wholly supported by the record that was before the Agency at the time it made its decision. Although not required, we conducted additional technical analyses because several years have passed since the December 2000 Finding. These extensive analyses confirm that it remains appropriate and necessary today to regulate EGUs under section 112. We discuss below the new analyses that we conducted. We also explain why these analyses and the other information currently before the Agency confirm that regulation of EGUs under section 112 is appropriate and necessary. We solicit comment on the new analyses.
Utilities are by far the largest remaining source of Hg in the U.S.
These significant HAP emissions pose a known or potential hazard to public health and the environment and, thus, it remains appropriate to regulate EGUs under section 112.
In this section, we describe briefly the health and environmental effects associated with the HAP emitted by EGUs and summarize the new analyses that the Agency conducted to assess the hazards to public health and the environment associated with EGU emissions, including the hazards remaining after imposition of the requirements of the CAA. We then discuss our conclusion that it remains appropriate and necessary to regulate EGUs under section 112.
Specifically, we conclude today that it remains appropriate to regulate EGUs under section 112 because Hg is a persistent, bioaccumulative pollutant, and emissions of Hg from EGUs continue to pose a hazard to public health and to the environment. Because of the persistent nature of Hg in the environment, Hg emitted today can lead to re-emissions of Hg in the future, and as a result continue to contribute to Hg deposition and associated health and environmental hazards in the future.
In addition, we conclude today that it is appropriate to regulate non-Hg HAP because emissions of these HAP from some EGUs pose a cancer risk greater than one in one million to the most exposed individual.
Finally, we find that it remains appropriate to regulate EGUs under section 112 because we have identified a number of currently available control technologies that will adequately address HAP emissions from EGUs. Several of these findings provide an independent basis for our determination consistent with our interpretation of the appropriate finding set forth above, and the combined weight of these findings provides a strong overall basis for our determination that it is and remains appropriate to regulate EGUs under CAA section 112.
We conclude that it remains necessary to regulate HAP emissions from EGUs because the imposition of the requirements of the CAA will not sufficiently address the hazards to public health and the environment posed by Hg emissions or the cancer risk and potential hazards to the environment posed by non-Hg HAP emissions from EGUs. Although the identified hazards will not be fully addressed through regulation under section 112, there will be a significant reduction in domestic Hg and non-Hg HAP emissions as the result of a section 112 regulation. EGUs remain the largest source of HCl and HF emissions in the U.S., and it is essential that those emissions be reduced to the maximum extent achievable, as Congress envisioned pursuant to section 112. Furthermore, it is necessary to regulate EGUs under section 112 because standards under that section assure that reductions in HAP emissions from EGUs will be permanently realized, thereby assuring that recent decreases in HAP emissions from U.S. EGUs will not be reversed in the future. Each of these conclusions independently supports our determination that it remains necessary to regulate EGUs under section 112.
Below we present an overview of EPA's current view of the scientific and technical information relevant to evaluating U.S. EGU Hg emissions and the public health hazards associated with such emissions. We provide general background information on the health hazards and environmental impacts of Hg and its transformation product MeHg; the emissions of those pollutants; the U.S. EGU contribution to these emissions; the predominant exposure pathway by which humans are affected by MeHg, which is by ingestion of fish containing MeHg; EPA's methodology for determining the impacts of U.S. EGU Hg emissions on potential exposures to MeHg in fish; the estimated potential risks associated with recent and future anticipated emissions of Hg from U.S. EGUs; and a qualitative analysis of the environmental hazards associated with Hg deposition. In addition to these analyses of hazards to public health and the environment associated with emissions of Hg from U.S. EGUs, this section also includes analyses of the hazards to public health and the environment from U.S. EGU emissions of non-Hg HAP. We then explain why the hazards to public health and the environment from Hg and non-Hg HAP emissions are reasonably anticipated to remain from U.S. EGUs after imposition of the requirements of the CAA. Finally, we discuss our evaluation of the new data and our finding that it remains appropriate and necessary to regulate EGUs under section 112.
Mercury is a persistent, bioaccumulative toxic metal that is emitted from EGUs in three forms:
In 2000, the National Research Council (NRC) of the NAS issued the NAS Study, which provides a thorough review of the effects of MeHg on human health. There are numerous studies that have been published more recently that report effects on neurologic and other endpoints.
As discussed earlier in Sections II.A.1 and III.B.3.a.i of this preamble, EPA has set and evaluated the RfD for Hg several times, and has received input from the NRC on the appropriateness of the RfD. In 1995, EPA set a health-based ingestion rate for chronic oral exposure to MeHg termed an oral RfD, at 0.0001 milligrams per kilogram per day (mg/kg-day).
The NAS proposed that the Faroe Islands cohort was the most appropriate study for defining an RfD, and specifically selected children's performance on the Boston Naming Test (a neurobehavioral test) as the key endpoint. Results from all three studies were considered in defining the RfD, as published in the “2001 Water Quality for the Protection of Human Health: Methylmercury,” and in the IRIS summary for MeHg: “Rather than choose a single measure for the RfD critical endpoint, EPA based this RfD for this assessment on several scores from the Faroes' measures, with supporting analyses from the New Zealand study, and the integrative analysis of all three studies.”
EPA defined the updated RfD of 0.0001 mg/kg-day in 2001. Although derived from a more complete data set and with a somewhat different methodology, the current RfD is numerically the same as the previous (1995) RfD (0.0001 mg/kg-day, or 0.1 µg/kg-day).
This RfD, consistent with the standard definition, is an estimate (with uncertainty spanning perhaps an order of magnitude) of a daily exposure to the human population (including sensitive subgroups) that is likely to be without an appreciable risk of deleterious effects during a lifetime (EPA, 2002). In general EPA believes that exposures at or below the RfD are unlikely to be associated with appreciable risk of deleterious effects. However, no RfD defines an exposure level corresponding to zero risk; moreover the RfD does not represent a bright line, above which individuals are at risk of adverse effects. EPA's interpretation for this assessment is that any exposures to MeHg above the RfD are of concern given the nature of the data available for Hg that is not necessarily available for many other chemicals. The scientific basis for the Hg RfD includes extensive human data and extensive data on sensitive subpopulations, including pregnant mothers; therefore, the RfD does not include extrapolations from animals to humans, and from the general population to sensitive subpopulations. In addition, there was no evidence of a threshold for MeHg-related neurotoxicity within the range of exposures in the Faroe Islands study which served as the primary basis for the RfD. This additional confidence in the basis for the RfD suggests that all exposures above the RfD can be interpreted with more confidence as causing a potential hazard to public health. Studies published since the current MeHg RfD was released include new analyses of children's neuropsychological effects from the existing Seychelles and Faroe Islands cohorts, including formation of a new cohort in the Faroe Islands study. There are also a number of new studies that were conducted in population-based cohorts in the U.S and other countries. A comprehensive assessment of the new literature has not been completed by EPA. However, 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 Faroes. 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.
In its review of the literature, the NAS found neurodevelopmental effects to be the most sensitive and best documented endpoints and appropriate for establishing an RfD;
The NAS summarized data on cardiovascular effects available up to 2000 (IRIS 2001). Based on these and other studies, the NRC (2000) 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. EPA did not to 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.
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 concluded that evidence that human exposure to MeHg caused 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
Although exposure to some forms of Hg can result in a decrease in immune activity or an autoimmune response,
Based on limited human and animal data, MeHg is classified as a “possible” human carcinogen by the International Agency for Research on Cancer (IARC)
There is also some evidence of reproductive and renal toxicity in humans from MeHg exposure. However, overall, human data regarding reproductive, renal, and hematological toxicity from MeHg are very limited and are based on either 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.
Mercury is an element. There is a fixed amount of it in the world. As long as it is bound up, for example in coal, it cannot affect people or the environment. Once it is released, for example via the combustion process, it enters the environment and becomes available for chemical conversion. Once emitted, Hg remains in the environment, and can bioaccumulate in organisms or be remitted through natural processes. Mercury is emitted through natural and anthropogenic processes; in addition, previously deposited Hg from either process may be re-emitted. Mercury deposition in the U.S. is not directly proportional to total Hg emissions, due to the differing rates at which the three species of Hg (Hg
The categories for anthropogenic Hg emissions include the combustion of fossil-fuels, cement production, waste incineration, metals production, and other industrial processes. Anthropogenic Hg emissions consist of Hg
Mercury re-emissions include previously deposited Hg originating from both natural and anthropogenic sources. At this time, it is not possible to determine the original source of previously deposited Hg, whether its source is natural emissions or re-emissions from previously deposited anthropogenic Hg.
Current estimates of total global Hg emissions based on a 2005 inventory
Although total U.S. anthropogenic Hg has decreased, the EGU sector remains the largest contributor to the total. In 1990, U.S. EGU Hg emissions for coal-fired units above 25 MW were 46 tons out of total U.S. Hg emissions of 264 tons.
Mercury is known to exist in the atmosphere in three forms: Hg
Marsik, F. J., G. J. Keeler,
Emissions data collected through the 2010 ICR during development of this proposed rule show that HCl emissions represent the predominant HAP emitted by U.S. EGUs. Coal- and oil-fired EGUs emit lesser amounts of HF, chlorine (Cl
Exposure to high levels of the various non-Hg HAP emitted by EGUs is associated with a variety of adverse health effects. These adverse health effects include chronic (long-term) health disorders (
Acetaldehyde is classified in EPA's IRIS database as a probable human carcinogen, based on nasal tumors in rats, and is considered toxic by the inhalation, oral, and intravenous routes.
Arsenic, a naturally occurring element, is found throughout the environment and is considered toxic through the oral, inhalation and dermal routes. Acute (short-term) high-level inhalation exposure to As dust or fumes has resulted in gastrointestinal effects (nausea, diarrhea, abdominal pain, and gastrointestinal hemorrhage); central and peripheral nervous system disorders have occurred in workers acutely exposed to inorganic As. Chronic (long-term) inhalation exposure to inorganic As in humans is associated with irritation of the skin and mucous membranes. Chronic inhalation can also lead to conjunctivitis, irritation of the throat and respiratory tract and perforation of the nasal septum.
The EPA's IRIS database lists benzene as a known human carcinogen (causing leukemia) by all routes of exposure, and concludes that exposure is associated with additional health effects, including genetic changes in both humans and animals and increased proliferation of bone marrow cells in mice.
A number of adverse noncancer health effects including blood disorders, such as preleukemia and aplastic anemia, have also been associated with long-term exposure to benzene.
Breathing air with lower levels of Cd over long periods of time (for years) results in a build-up of Cd in the kidney, and if sufficiently high, may result in kidney disease. Lung cancer has been found in some studies of workers exposed to Cd in the air and studies of rats that inhaled Cd. DHHS has determined that Cd and Cd compounds are known human carcinogens. IARC has determined that Cd is carcinogenic to humans. EPA has determined that Cd is a probable human carcinogen.
The acute (short term) toxic effects of Cl
Chromium may be emitted in two forms, trivalent Cr (Cr
Since 1987, EPA has classified formaldehyde as a probable human carcinogen based on evidence in humans and in rats, mice, hamsters, and monkeys.
Formaldehyde exposure also causes a range of noncancer health effects, including irritation of the eyes (burning and watering of the eyes), nose and throat. Effects from repeated exposure in humans include respiratory tract irritation, chronic bronchitis and nasal epithelial lesions such as metaplasia and loss of cilia. Animal studies suggest that formaldehyde may also cause airway inflammation—including eosinophil infiltration into the airways. There are several studies that suggest that formaldehyde may increase the risk of asthma—particularly in the young.
Hydrogen chloride is a corrosive gas that can cause irritation of the mucous membranes of the nose, throat, and respiratory tract. Brief exposure to 35 ppm causes throat irritation, and levels of 50 to 100 ppm are barely tolerable for 1 hour.
Acute (short-term) inhalation exposure to gaseous HF can cause severe respiratory damage in humans, including severe irritation and pulmonary edema. Chronic (long-term) oral exposure to fluoride at low levels has a beneficial effect of dental cavity prevention and may also be useful for the treatment of osteoporosis. Exposure to higher levels of fluoride may cause dental fluorosis. One study reported
The main target for Pb toxicity is the nervous system, both in adults and children. Long-term exposure of adults to Pb at work has resulted in decreased performance in some tests that measure functions of the nervous system. Lead exposure may also cause weakness in fingers, wrists, or ankles. Lead exposure also causes small increases in blood pressure, particularly in middle-aged and older people. Lead exposure may also cause anemia.
Children are more sensitive to the health effects of Pb than adults. No safe blood Pb level in children has been determined. At lower levels of exposure, Pb can affect a child's mental and physical growth. Fetuses exposed to Pb in the womb may be born prematurely and have lower weights at birth. Exposure in the womb, in infancy, or in early childhood also may slow mental development and cause lower intelligence later in childhood. There is evidence that these effects may persist beyond childhood.
There are insufficient data from epidemiologic studies alone to conclude that Pb causes cancer (is carcinogenic) in humans. DHHS has determined that Pb and Pb compounds are reasonably anticipated to be human carcinogens based on limited evidence from studies in humans and sufficient evidence from animal studies, and EPA has determined that Pb is a probable human carcinogen.
Health effects in humans have been associated with both deficiencies and excess intakes of Mn. Chronic exposure to high levels of Mn by inhalation in humans results primarily in central nervous system effects. Visual reaction time, hand steadiness, and eye-hand coordination were affected in chronically-exposed workers. Manganism, characterized by feelings of weakness and lethargy, tremors, a masklike face, and psychological disturbances, may result from chronic exposure to higher levels. Impotence and loss of libido have been noted in male workers afflicted with manganism attributed to inhalation exposures. The EPA has classified Mn in Group D, not classifiable as to carcinogenicity in humans.
Respiratory effects have been reported in humans from inhalation exposure to Ni. No information is available regarding the reproductive or developmental effects of Ni in humans, but animal studies have reported such effects. Human and animal studies have reported an increased risk of lung and nasal cancers from exposure to Ni refinery dusts and nickel subsulfide. The EPA has classified nickel subsulfide as a human carcinogen and nickel carbonyl as a probable human carcinogen.
Acute exposure to elemental Se, hydrogen selenide, and selenium dioxide (SeO
Fossil-fuel fired boilers emit a variety of metal HAP, organic HAP and HAP that are acid gases. Acid gas and metal HAP emissions are discussed below.
Based on the 2010 ICR and the National Air Toxics Assessment (NATA) inventory estimates of acid gas emissions, U.S. EGUs emit the majority of HCl and HF nationally, supporting EPA's view that it remains appropriate to regulate HAP from U.S. EGUs. Acid gas emissions from EGUs include HCl, HF, Cl
U.S. EGUs are the predominant source of emissions nationally for many metal HAP, including Sb, As, Cr, Co, and Se.
Metals are emitted primarily because they are present in fuels. Table 5 of this preamble shows selected metals emitted by EGUs and emission estimates based on data from the 2005 NATA inventory. 2010 estimates of metal HAP emissions are 25 tpy for antimony (Sb), 43 tpy for As, 2 tpy for Be, 3 tpy for Cd, 222 tpy for Cr, 19 tpy for Co, 183 tpy for Mn, 387 tpy for Ni, and 258 tpy for Se.
EPA conducted quantitative risk analyses to evaluate the extent of risk posed by emissions of HAP from U.S. EGUs. These analyses demonstrate that U.S. EGU HAP emissions do create the potential for risks to the public health, as described below.
To evaluate the potential for public health hazards from emissions of Hg and non-Hg HAP from U.S. EGUs, EPA conducted quantitative risk analyses using several methods intended to address specific risk-related questions.
To evaluate the potential for health risks associated with U.S. EGU Hg emissions, EPA conducted a national scale assessment of the impacts of U.S. EGU Hg emissions on exposures to MeHg above the RfD, and as a contributor to exposures above the RfD in conjunction with exposures from other U.S. and non-U.S. Hg emissions. To evaluate risks of U.S. EGU Hg “hotspots,” EPA conducted a national scale assessment based on the Hg deposition modeling used in the national-scale Hg risk assessment. To evaluate inhalation risks of U.S. EGU non-Hg HAP emissions, EPA recently conducted 16 case studies at EGUs. EPA selected these case studies based on HAP emissions information from the ICR. For each case study, EPA estimated the MIR for cancer and non-cancer health effects for each HAP emitted by the case study U.S. EGU facility. Cancer risks for non-Hg HAP are estimated as the number of excess cancer cases per million people. This section briefly describes the methods used in the analyses and the results for the national-scale Hg risk analysis and the non-Hg HAP inhalation risk case studies.
The national-scale Hg risk analysis is based on modeling Hg deposition associated with 2005 U.S. EGU Hg emissions and 2016 projected Hg emissions.
The 2005 base case includes 105 tons of Hg and 430,000 tons of HCl from all sources, of which 53 tons of Hg and 350,000 tons of HCl are from EGUs. The 2016 projected total Hg emissions from all sources used in the risk modeling are 64 tons and HCl emissions are 140,000 tons, with 29 tons of Hg and 74,000 tons of HCl from EGUs. U.S. EGU Hg emissions accounted for 50 percent of total U.S. Hg emissions in 2005 and are projected to account for 45 percent of such emissions in 2016. Details regarding the emissions used in these analyses are provided in the emissions memorandum, “Emissions Overview: Hazardous Air Pollutants in Support of the Proposed Toxics Rule”.
Between 2005 and 2010, Hg emissions in the U.S. have declined as a result of state regulations of Hg or Federal regulatory and enforcement actions that required installation of SO
Given that the 2010 emissions for Hg are much closer to the 2016 projected emissions than to the 2005 emissions, we focus on the results from 2016 from the national-scale Hg risk analysis described below, as the projected emissions are almost the same as current HAP emissions from EGUs.
The national-scale risk assessment for Hg focuses on risk associated with Hg released from U.S. EGUs that deposits to watersheds within the continental U.S., bioaccumulates in fish, and then is consumed as MeHg in fish eaten by subsistence fishers and other freshwater self-caught fish consumers. The risk assessment is intended to assess risk for scenarios representing high-end self-caught fish consumers active at inland freshwater lakes and streams. This reflects our goal of determining whether U.S. EGUs represent a potential public health hazard for the group of fish consumers likely to experience the highest risk attributable to U.S. EGUs. In defining the high fish consuming populations included in the analysis, we have used information from studies of fish consumption to ensure that we have identified fisher populations that are likely active to some extent across the watersheds included in this analysis (
Risk from Hg exposures occurs primarily through the consumption of fish that have bioaccumulated MeHg originally deposited to watersheds following atmospheric release and transport. The population that is most at risk from consumption of MeHg in fish is children born to mothers who were exposed to MeHg during pregnancy through fish consumption. The type of fish consumption likely to lead to the greatest exposure to MeHg attributable to U.S. EGUs is associated with fishing activity at inland freshwater rivers and lakes located in regions with elevated U.S. EGU Hg deposition. Thus we focus on MeHg exposure to women of childbearing age who consume self-caught freshwater fish on a regular basis,
As noted above, current U.S. EGU Hg emissions as reflected in the 2010 ICR are closer to 2016 projected emissions than to the 2005 emissions. For this reason, in discussing risk estimates, we focus on the 2016 results rather than the 2005 results.
The risk assessment compares the U.S. EGU incremental contribution to total potential exposure with the RfD and also evaluates the percent of total Hg exposures from all sources contributed by U.S. EGUs (
We used this information to assess whether a public health hazard is associated with U.S. EGU emissions. Our focus is on women of child-bearing age in subsistence fishing populations who consume freshwater fish that they or their family caught. These populations are likely to experience the greatest risk from Hg exposure when fishing at inland (freshwater) locations that receive the highest levels of U.S. EGU-attributable Hg deposition. We also acknowledge that additional populations are likely exposed to MeHg from consuming fish caught in near-coastal,
Consumption rates for the high-end fishing populations included in the risk assessment are based on studies in the published literature, and are documented in the TSD accompanying this finding.
We do not estimate risks associated with commercial fish consumption because of the expected low contribution of U.S. EGU Hg to this type of fish, relative to non-U.S. Hg emissions, and the high levels of uncertainty in mapping U.S. EGU Hg emissions to concentrations of MeHg in ocean-going fish. The population affected by those U.S. EGU Hg emissions that go into the global pool of Hg will potentially be much larger than the population of the U.S. Thus, the impacts of U.S. EGUs on global exposures to Hg, while highly uncertain, adds additional support to the finding that Hg emissions from U.S. EGUs pose a hazard to public health.
EPA assessed risk from potential exposure to MeHg through fish consumption at a subset of watersheds across the country for which we have measured fish tissue MeHg data. This risk assessment uses estimates of potential exposure for subsistence fisher populations to generate risk metrics based on comparisons of MeHg exposure to the reference dose. We are focusing on exposures above the RfD because it represents a sensitive risk metric that captures a wide range of neurobehavioral health effects. Reductions in exposure to MeHg are also expected to result in reductions in specific adverse effects including lost IQ points, and we discuss the risk analysis related to IQ loss in the National Scale Mercury Risk Assessment TSD.
For the analysis, we have developed a risk characterization framework for integrating two types of U.S. EGU-attributable risk estimates. This framework estimates the percent of watersheds where populations may be at risk due to potential exposures to MeHg attributable to U.S. EGU. The analysis is limited to those watersheds for which we have fish tissue MeHg samples, a total of approximately 2,400 out of 88,000 watersheds in the U.S. This total percent of watersheds includes ones that either have deposition of Hg from U.S. EGUs that is sufficient to lead to potential exposures that exceed the reference dose, even without considering the contributions from other U.S. and non-U.S. sources, or have deposition of Hg from U.S. EGUs that contributes at least 5 percent to total Hg deposition from all sources, in watersheds where potential exposures to MeHg from all sources (U.S. EGU, U.S. non-EGU, and non-U.S.) exceed the RfD.
This framework allows EPA to consider whether U.S. EGUs, evaluated without consideration of other sources, or in combination with other sources of Hg, pose a potential public health hazard.
Several elements of this risk analysis including spatial scale, estimates of Hg deposition, estimates of fish tissue MeHg concentrations, estimates of fish consumptions rates, and calculation of
Watersheds can be defined at varying levels of spatial resolution. For the purposes of this risk analysis, we have selected to use watersheds classified using 12-digit Hydrologic Unit Codes (HUC12),
After estimating total MeHg risk based on modeling consumption of fish at each of these watersheds, the ratio of U.S. EGU to total Hg deposition over each watershed (estimated using Community Multi-scale Air Quality modeling) is used to estimate the U.S. EGU-attributable fraction of total MeHg risk. This apportionment of total risk between the U.S. EGU fraction and the fraction associated with all other sources of Hg deposition is based on the EPA's Office of Water's Mercury Maps (MMaps) approach that establishes a proportional relationship between Hg deposition over a watershed and resulting fish tissue Hg levels, assuming a number of criteria are met.
The fish tissue dataset for the risk assessment includes fish tissue Hg samples from the years 2000 to 2009, with samples distributed across 2,461 HUC12s. The samples are more heavily focused on locations east of the Mississippi River. The fish tissue samples come primarily from three sources: the National Listing of Fish Advisory (NLFA) database managed by EPA;
Deposition of Hg for the continental U.S. was estimated using the Community Multiscale Air Quality model v4.7.1 (
The CMAQ modeling was used to estimate total annual Hg deposition from U.S. and non-U.S. anthropogenic and natural sources over each watershed. In addition, CMAQ simulations were conducted where U.S. EGU Hg emissions were set to zero to determine the contribution of U.S. EGU Hg emissions to total Hg deposition. U.S. EGU-related Hg deposition characterized at the watershed-level for 2005 and 2016 is summarized in Table 6 of this preamble for the complete set of 88,000 HUC12 watersheds.
Table 6 is intended to demonstrate the wide variation across watersheds in the contribution of EGU emissions to deposition. The percentiles of total Hg deposition and U.S. EGU-attributable deposition are not linked,
To give a better idea of the relationship between total deposition and U.S. EGU-attributable deposition, we also summarize the percent of total Hg deposition attributable to U.S. EGUs (by percentile) in Table 7. Table 7 shows the high variability in the percent contribution from U.S. EGU Hg emissions. Tables 6 and 7 cannot be directly compared, as the watershed with the 99th percentile U.S. EGU-attributable deposition is not the same watershed as the watershed with the 99th percentile U.S. EGU-attributable fraction of total Hg deposition. A watershed can have a high U.S. EGU-attributable fraction of total deposition and still have overall low Hg deposition.
U.S. EGUs are estimated to contribute up to 30 percent of total Hg deposition in 2005 and up to 11 percent in 2016.
EPA estimates the relationship between the EGU-attributable Hg deposition and EGU-attributable fish tissue MeHg concentrations using an assumption of linear proportionality based on the agency's MMaps approach. The MMaps assumption specifies that, under certain conditions (
Because the focus of this analysis is on higher-consumption self-caught fisher populations active at inland freshwater locations, we identified surveys of higher consumption fishing populations active at inland freshwater rivers and lakes within the continental U.S. to inform the selection of consumption rate scenarios.
Generally all of the studies identified high-end percentile consumption rates (90th to 99th percentiles for the populations surveyed) ranging from approximately one fish meal every few days to a fish meal a day (
For the scenario representing high-end female fish consumption, we estimated total exposure to MeHg at each of the 2,461 watersheds.
Our estimates of total percent of watersheds where female subsistence fishing populations may be at risk from exposure to U.S. EGU-attributable MeHg are as high as 28 percent. The upper end estimate of 28 percent of watersheds reflects the 99th percentile fish consumption rate for that population, and a benchmark of 5 percent U.S. EGU contribution to total Hg deposition in the watershed. Any contribution of Hg emissions from EGUs to watersheds where potential exposures from total Hg deposition exceed the RfD is a hazard to public health, but for purposes of our analyses we evaluated only those watersheds where we determined EGUs contributed 5 percent or more to deposition to the watershed. EPA believes this is a conservative approach given the increasing risks associated with incremental exposures above the RfD. Of the total number of watersheds where populations may be at risk from exposure to EGU-attributable MeHg, we estimate that up to 22 percent of watersheds included in this analysis could potentially have populations at risk based on consideration of the U.S. EGU attributable fraction (
The two estimates of percent of watersheds where populations may be at risk from EGU-attributable Hg do not sum to the total estimates of 28 percent because some watersheds where U.S. EGUs contribute greater than 5 percent to total Hg deposition also have U.S. EGU attributable exposures that exceed the RfD without consideration of exposures from other U.S. and non-U.S. Hg sources.
Exposures based on the 99th percentile consumption rate represent close to maximum potential individual risk estimates. These consumption rates are based on data reported by fishers in surveys, and, thus, represent actual consumption rates in U.S. populations. There are also a number of case studies in other locations, such as poor urban areas, which provide additional evidence that high fish consumption occurs in a number of locations throughout the U.S.
With regard to the other fisher populations included in the full risk assessment described in the TSD (Vietnamese, Laotians, Hispanics, blacks and whites in the southeast, and tribes in the vicinity of the Great Lakes), our risk estimates suggests that the high-end female consumer assessed at the national-level generally provides coverage (in terms of magnitude of risk) for all of these fisher populations except blacks and whites in the southeast.
There are some uncertainties in EPA's analyses which could lead to under or over prediction of risk to public health from U.S. EGU Hg emissions. Based on sensitivity analyses we have conducted, we conclude that even under different assumptions about the applicability of the MMaps proportionality assumption, Hg from U.S. EGUs constitutes a hazard to public health due to the percent of watersheds where U.S. EGUs cause or contribute to exposures to MeHg above the RfD.
Key sources of uncertainty potentially impacting the risk analysis include: (1) Uncertainty in predicting Hg deposition over watersheds using CMAQ; (2) uncertainty in predicting which watersheds will be subject to high-end fishing activity and the nature of that activity (
As part of the analysis, we have also completed a number of sensitivity analyses focused on exploring the impact of uncertainty related to the application of the MMaps approach in apportioning exposure and risk estimates between sources (U.S. EGU and total) and in predicting changes in fish tissue MeHg levels.
We also examined the potential for under-representation of watersheds highly impacted by U.S.-attributable Hg deposition due to limited MeHg sampling, by identifying watersheds that did not have fish tissue MeHg samples, but had U.S. EGU-attributable Hg deposition at least as high as watersheds that were identified as being at risk of potential exposures greater than the RfD. Comparing the pattern of U.S. EGU-attributable Hg deposition across all watersheds with that for watersheds containing fish tissue MeHg data shows that while we have some degree of coverage for watersheds with high U.S. EGU-attributable deposition, this coverage is limited, especially in areas of Pennsylvania which have high levels of U.S. EGU-attributable deposition. For this reason, we believe that the actual number of watersheds where populations may be at risk from exposures to U.S. EGU-attributable MeHg could be substantially larger than the number estimated based on the available fish tissue MeHg sampling data.
EPA conducted 16 case studies to estimate the potential for human health impacts from current emissions of HAP other than Hg from EGUs. A refined chronic inhalation risk assessment was performed for each case study facility. The results of this analysis were that 4 (out of 16) facilities posed a lifetime cancer risk of greater than 1 in 1 million (the maximum was 10 in 1 million) and 3 more posed a risk at 1 in 1 million. Risk was driven by Ni (the oil-fired unit) and Cr
An initial set of eight case study facilities was selected based on several factors. First, we considered facilities with the highest estimated cancer and non-cancer risks using the 2005 National Emissions Inventory (NEI) data and the Human Exposure Model (HEM). The 2005 NEI data were used because the initial set of case study facilities was selected before we received the bulk of the emissions data from the 2010 ICR. Other factors considered in the selection included whether facilities had implemented emission control measures since 2005, and their proximity to residential areas. After the receipt of more data through the 2010 ICR, additional case study facilities were selected, based on the magnitude of emissions, heat input values (throughput), and level of emission control. There were a total of 16 case study facilities, 15 that use coal as fuel, and 1 that uses oil.
Annual emissions estimates for each EGU (including those in the initial set of case study facilities) were developed using data from the 2010 ICR. The results for the initial set indicated that Ni, Cr
We calculated the MIR for each facility as the cancer risk associated with a continuous lifetime (24 hours per day, 7 days per week, and 52 weeks per year for a 70-year period) exposure to the maximum concentration at the centroid of an inhabited census block, based on application of the unit risk estimate from EPA's IRIS, which is a human health assessment program that evaluates quantitative and qualitative risk information on effects that may result from exposure to environmental contaminants. For Ni compounds, we
The highest estimated lifetime cancer risk from any of the 16 case study facilities was 10 in 1 million (1 × 10
The cancer risk estimates from this assessment indicate that the EGU source category is not eligible for delisting under CAA section 112(c)(9)(B)(i), which specifies that a category may be delisted only when the Administrator determines “* * * that no source in the category (or group of sources in the case of area sources) emits such HAP 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 * * *” We note that, because these case studies do not cover all facilities in the category, and because our assessment does not include the potential for impacts from different EGU facilities to overlap one another (
The Agency has determined that the National-Scale Mercury Risk Analysis supporting EPA's 2011 review of U.S. EGU health impacts should be peer-reviewed. In addition, the Agency has determined that the characterization of the chemical speciation for the emissions of Cr and Ni should be peer-reviewed. The Agency has evaluated the other components of the analyses supporting this finding and determined that the remaining aspects of the case study analyses for non-Hg HAP use methods that have already been subject to adequate peer-review. As a result, the Agency is limiting the peer-review to the National-Scale Mercury Risk Analysis and the speciation of emissions for Cr and Ni. Due to the court-ordered schedule for this proposed rule, EPA will conduct these peer reviews as expeditiously as possible after issuance of this proposed rule and will publish the results of the peer reviews and any EPA response to them before the final rule.
Adverse effects on fish and wildlife have been observed to be occurring today which are the result of elevated exposures to MeHg, although these effects have not been quantitatively assessed.
Elevated MeHg concentrations in fish and wildlife can occur not only in areas of high Hg deposition. Elevated MeHg concentrations can also occur in diverse locations, including watersheds that receive average or even relatively low Hg deposition, but are particularly sensitive to Hg pollution, for example, they have higher than average methylation rates due to high levels of sulfur deposition. Such locations are characterized by moderate deposition levels that have generated high Hg concentrations in biota compared to the surrounding landscape receiving a similar Hg loading. These Hg-sensitive watersheds readily transport inorganic Hg, convert the inorganic Hg to MeHg, and bioaccumulate this MeHg through the food web. Areas of enhanced MeHg in fish and wildlife are not constrained to a single Hg source, because ecosystems respond to the combined effects of Hg pollution from multiple sources.
A review of the literature on effects of Hg on reproduction in fish
U.S. Environmental Protection Agency (U.S. EPA). 2005.
Other fish-eating bird species such as the white ibis and great snowy egret experience a range of adverse effects due to exposure to Hg. The white ibis has been observed to have decreased foraging efficiency
In mammals, adverse effects from Hg including mortality have been observed in mink and river otter, both fish eating species. Other adverse effects may include increased activity, poorer maze performance, abnormal startle reflex, and impaired escape and avoidance behavior.
Although it has been characterized and addressed as a global issue, Hg from U.S. EGUs is shown to deposit in higher quantities close to emission sources, and around some sources can be as high as 3 times the regional average deposition. EPA evaluated the potential for “hot spot” deposition near U.S. EGU emission sources on a national scale, based on the CMAQ modeled Hg deposition for 2005 and 2016.
This analysis shows that there is excess deposition of Hg in the local areas around EGUs, especially those with high Hg emissions. Although this is not necessarily indicative of higher risk of adverse effects from consumption of MeHg contaminated fish from waterbodies around the U.S. EGUs, it does indicate an increased chance that Hg from U.S. EGUs will impact local waterbodies around the EGU sources, and not just impact regional deposition.
Analyses of currently available control technologies for Hg, acid gases,
The control of Hg in a coal combustion flue gas is highly dependent upon the form (or species) of the Hg. The Hg can be present in one of three forms: as Hg
Mercury control can occur as a “co-benefit” of conventional control technologies that have been installed for other purposes. Particulate Hg can be effectively removed along with other flue gas PM (including non-Hg metal HAP) in the primary or secondary PM control device. For units using electrostatic precipitators (ESPs), the effectiveness will depend upon the amount of Hg
Activated carbon injection (ACI) is the most successfully demonstrated Hg-specific control technology. In this case, a powdered AC sorbent is injected into the duct upstream of the primary or a secondary PM control device. The carbon is injected to maximize contact with the flue gas. Mercury binds on the surface of the carbon to form Hg
Mingling of AC with the fly ash can affect the viability for use of the captured fly ash as an additive in concrete production. Use of the TOXECON
Electrostatic precipitators and FFs are the most commonly applied PM control technologies in U.S. coal-fired EGUs. Newer units have tended to install FFs, which usually provide better performance than ESPs. An existing facility that wants to upgrade the PM control may choose to replace the current equipment with newer, better performing equipment. The facility may also consider installation of a downstream secondary PM control device—such as a secondary FF. A wet ESP (WESP) can be installed downstream of a wet FGD scrubber for control of condensable PM.
Acid gases are likely to be removed in typical FGD systems due to their solubility or their acidity (or both). The acid-gas HAP—HCl, HF, and HCN (representing the “cyanide compounds”)—are water-soluble compounds, more soluble in water than is SO
In 2016, EGUs are projected to account for an estimated 45 percent of anthropogenic Hg (excluding fires) in the continental U.S. Application of available Hg controls in 2016 that would be required under section 112 reduces
In 2016, EGUs are projected to account for 53 percent of total U.S. anthropogenic HCl. Application of available HCl controls in 2016 that would be required under section 112 achieves a 68,000 tpy reduction in HCl emissions (a 91 percent reduction in EGU emissions), resulting in a 49 percent reduction of anthropogenic emissions nationally.
Metal HAP emissions are a component of PM, and are expected to be reduced along with PM as a result of application of PM controls. In 2016, application of controls required under section 112 is expected to provide an average reduction in PM for the continental U.S. of 38 percent. Although no specific projection of metals is available for 2016, applying the 38 percent reduction in PM to the 2010 ICR emissions levels of anthropogenic metals,
EPA believes these projected reductions in Hg, acid gases, and metal HAP emissions demonstrate the effectiveness of available controls.
This would allow the U.S. to demonstrate effective technologies to reduce Hg; such leadership could provide confidence to other countries that they can succeed in meeting their commitments. Mercury pollution is a significant international environmental challenge, and it is well understood that efforts that reduce Hg emissions in other countries will reduce Hg that impacts U.S. public health and the environment. Recognizing this, EPA and others in the U.S. Government are actively involved in international efforts to reduce Hg pollution. These efforts include global negotiations aimed at concluding a legally-binding agreement to reduce Hg that were initiated in February 2009 under the UNEP.
The extensive analyses summarized above confirm that it remains appropriate and necessary today to regulate EGUs under section 112. It is appropriate to regulate emissions from coal- and oil-fired EGUs under CAA section 112 because: (1) Hg and non-Hg HAP continue to pose a hazard to public health, and U.S. EGU emissions cause and/or contribute to this hazard; (2) Hg and some non-Hg HAP pose a hazard to the environment; (3) U.S. EGU emissions, accounting for 45 percent of U.S. Hg emissions, are still the largest domestic source of U.S. Hg emissions (by 2016, EPA projects that U.S. EGU Hg emissions will be over 6 times larger than the next largest source, which is iron and steel manufacturing), as well as the largest source of HCl and HF emissions, and a significant source of other HAP emissions; (4) Hg emissions from individual EGUs leads to hot spots of deposition in areas directly surrounding those individual EGUs, and, thus, deposition is not solely the result of regionally transported emissions, and will not be adequately addressed through reductions in regional levels of Hg emissions, requiring controls to be in place at all U.S. EGU sources that emit Hg; (5) Hg emissions from EGUs affect not only deposition, exposures, and risk today, but may contribute to future deposition, exposure and risk due to the processes of reemission of Hg that occur given the persistent nature of Hg in the environment—the delay in issuing Hg regulations under section 112 has already resulted in several hundred additional tons of Hg being emitted to the environment, and that Hg will remain part of the global burden of Hg; and (6) effective controls for Hg and non-Hg HAP are available for U.S. EGU sources.
EPA concludes that Hg emissions from U.S. EGUs are a public health hazard today due to their contribution to Hg deposition that leads to potential MeHg exposures above the RfD. EPA also concludes that U.S. EGU Hg emissions contribute to environmental concentrations of Hg that are harmful to wildlife and can affect production of important ecosystem services, including recreational hunting and fishing, and wildlife viewing. EPA further concludes that non-Hg HAP emissions from U.S. EGU are a public health hazard because they contribute to elevated cancer risks.
Finally, EPA concludes that U.S. EGU's HCl and HF emissions contribute to acidification in sensitive ecosystems and, therefore, pose a risk of adverse effects on the environment.
The CAA does not define what constitutes a hazard to public health. As noted earlier, the agency must use its scientific and technical expertise to determine what constitutes a hazard to public health in the context of Utility Hg emissions. Congress did provide guidance as to what it considered an important benchmark for public health hazards, particularly in regard to Hg. In section 112(n)(1)(C), Congress required the NIEHS to determine “the threshold level of Hg exposure below which adverse human health effects are not expected to occur.” This threshold level is represented by the RfD, and as such, the RfD is the benchmark for determining hazards to public health that is most consistent with Congress's interpretation of adverse health effects. As a result, our assessment of the hazard to public health posed by U.S. EGU Hg emissions is focused on comparisons to the RfD of exposures caused or contributed to by U.S. EGU Hg emissions.
As described above, almost all (98 percent) of the more than 2,400 watersheds for which we have fish tissue data exceed the RfD, above which there is the potential for an increased risk of adverse effects on human health. U.S. EGU-attributable deposition of Hg contributes to a large number of those watersheds in which total potential exposures to MeHg from all sources exceed the RfD and, thus, pose a hazard to public health. For our analysis, we focused on the watersheds to which EGUs contributed at least 5 percent of the total Hg deposition and related
In total, 28 percent of sampled watersheds have populations that are potentially at risk from exposure to MeHg based on the contribution of U.S. EGUs, either because U.S. EGU attributable deposition is sufficient to cause potential exposures to exceed the reference dose even before considering the deposition from other U.S. and non-U.S. sources, or because the U.S. EGU attributable deposition contributes greater than 5 percent of total deposition and total exposure from all sources is greater than the reference dose. At the 99th percentile fish consumption level for subsistence fishers, 22 percent of sampled watersheds where total potential exposures to MeHg exceed the RfD have a contribution from U.S. EGUs of at least 5 percent of Hg deposition.
Although the most complete estimate of potential risk is based on total exposures to Hg, including that due to deposition from U.S. EGU sources, U.S. non-EGU sources, and global sources, the deposition resulting from U.S. EGU Hg emissions is large enough in some watersheds that persons consuming contaminated fish would have exposures that exceed the RfD even before taking into account the deposition from other sources. At the 99th percentile fish consumption level for subsistence fishers, in 12 percent of the sampled watersheds, U.S. EGUs are responsible for deposition that causes the RfD to be exceeded, even before considering the additional deposition from other sources.
In addition, we believe the estimate of where populations may be at risk from U.S. EGU-attributable Hg deposition is likely understated because the data on fish tissue MeHg concentrations is limited in some regions of the U.S., such as Pennsylvania, with very high U.S. EGU attributable Hg deposition, and it is possible that watersheds with potentially high MeHg exposures were excluded from the risk analysis.
Further, scientific studies have found strong evidence of adverse impacts on species of fish-eating birds with high bird-watching value, including loons, white ibis, and great snowy egrets. Studies have also shown adverse effects on insect-eating birds including many songbirds. Adverse effects in fish-eating mammals, such as mink and otter, include neurological responses (impaired escape and avoidance behavior) which can influence survival rates. Because EGUs contribute to Hg deposition in the U.S., we reasonably conclude that EGUs are contributing to the identified adverse environmental effects.
Mercury emitted into the atmosphere persists for years, and once deposited, can be reemitted into the atmosphere due to a number of processes, including forest fires and melting of snow packs. As a result, Hg emitted today can have impacts for many years. In fact, Hg emitted by U.S. EGUs in the past, including over the last decade, is still having impacts on concentrations of Hg in fish today. 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. Although we are not able to quantify the impact of U.S. EGU emissions on the global pool of Hg, U.S. EGUs do contribute to that global pool. Controlling Hg emissions from U.S. EGUs helps to reduce the potential for environmental hazard from Hg now and in the future. These findings independently support a determination that it is appropriate to regulate HAP emissions from EGUs.
EPA recently conducted 16 case studies of U.S. EGUs for which we had 2007 to 2009 emissions data (based on the 2010 ICR) and that we anticipated would have relatively higher emissions of non-Hg HAP compared to other U.S. EGUs. Of the 16 facilities modeled, 4 facilities, 3 coal and 1 oil facility, have estimated risks of greater than 1 in 1 million for the most exposed individual. Although section 112(n)(1)(A) does not specify what constitutes a hazard to public health for the purposes of the appropriate and necessary finding, CAA section 112(c)(9) is instructive. As explained in section III.A above, for carcinogenic HAP, section 112(c)(9) contains a test for delisting source categories based on lifetime risk of cancer. That test reflects Congress' view as to the level of health effects associated with HAP emissions that Congress thought warranted continued regulation under section 112. Specifically, section 112(c)(9) provides that a source category can be delisted only if no source emits HAP in quantities which may cause a lifetime risk of cancer greater than 1 in 1 million to the most exposed individual. As noted above, the results of the case study risk analysis confirm that sources in the EGU source category emit HAP in quantities that cause a lifetime risk of cancer greater than 1 in 1 million. Given Congress' determination that categories of sources which emit HAP resulting in a lifetime cancer risk greater than 1 in 1 million should not be removed from the section 112(c) source category list and should continue to be regulated under 112, we believe risks above that level represent a hazard to public health such that it is appropriate to regulate EGUs under section 112.
Although our case studies did not identify significant chronic non-cancer risks from acid gas emissions from the specific EGUs assessed, the Administrator remains concerned about the potential for acid gas emissions to add to already high atmospheric levels of other chronic respiratory toxicants and to environmental loading and degradation due to acidification. EGUs emit over half of the nationwide emissions of HCl and HF, based on 2010 emissions estimates. In addition, given that many sensitive ecosystems across the country are experiencing acidification, it is appropriate to reduce emissions of this magnitude which carry the potential to aggravate acidification. The Administrator concludes that, in addition to the regulation of non-Hg HAP which cause elevated cancer risks, 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.
These findings independently support a determination that it is appropriate to regulate HAP emissions from EGUs.
Particle-bound Hg can be effectively removed along with other flue gas PM (including non-Hg metal HAP) in primary or secondary PM control devices. Electrostatic precipitators, FF, and wet FGD scrubbers are all effective at removing Hg, with the degree of effectiveness depending on the specific characteristics of the EGU and fuel types. These devices are all effective in removing metal HAP as well. Activated carbon injection is the most successfully demonstrated Hg-specific control technology, although performance may be reduced when used with high sulfur coals. Acid gases are readily removed in typical FGD systems due to their solubility or their acidity (or both). The availability of controls for HAP emissions from EGUs supports the appropriate finding because sources will be able to reduce their emissions effectively and, thereby, reduce the hazards posed by HAP emissions from EGUs.
EPA determined that in 2016 the hazards posed to human health and the environment by HAP emissions from EGUs will not be addressed; therefore, it is necessary to regulate EGUs under section 112. In addition, it is necessary to regulate EGUs under section 112 because the only way to ensure permanent reductions in U.S. EGU emissions of HAP and the associated risks to public health and the environment is through standards set under section 112.
The Agency first evaluates whether it is necessary to regulate HAP emissions from EGUs “after imposition of the requirements of the CAA.” As explained above, we interpret that phrase to require the Agency to consider only those requirements that Congress directly imposed on EGUs through the CAA as amended in 1990 and for which EPA could reasonably predict HAP emission reductions at the time of the Study. Nonetheless, the Agency recognizes that it has discretion to look beyond the Utility Study in determining whether it is necessary to regulate EGUs under section 112. Because several years have passed since the December 2000 Finding, we conducted an additional, updated analysis, examining a broad array of diverse requirements.
Specifically, we analyzed EGU HAP emissions remaining in 2016. Our analysis included the proposed Transport Rule; CAA section 112(g); the ARP; Federal, state, and citizen enforcement actions related to criteria pollutant emissions from EGUs; and some state rules related to criteria pollutant emissions. We included state requirements and citizen and state enforcement action settlements associated with criteria pollutants because those requirements may have a basis under the CAA. We did not, however, conduct an analysis to determine whether the requirements are, in fact, based on requirements of the CAA. As such, we believe there may be instances where we should not have considered certain state rules or state and citizen suit enforcement settlements in our analysis, because those requirements are based solely in state law and are not required by Federal law. We did not include in our analysis any state-only requirements or voluntary actions to reduce HAP emissions because we knew there was no Federal backstop for those requirements and actions.
Our analysis confirms that Hg emissions from EGUs remaining in 2016 still pose a hazard to public health and the environment and, for that reason, it remains necessary to regulate EGUs under section 112. Specifically, we estimate that U.S. EGU emissions of Hg after imposition of the requirements of the CAA will be 29 tpy in 2016, the same as the level of Hg emitted today. As we stated above, we evaluated the hazards to public health and the environment from Hg based on the estimated Hg emissions in 2016 and found that a hazard exists. Because a hazard remains after imposition of the requirements of the CAA, it is necessary to regulate EGUs.
It is necessary to regulate HAP emissions from EGUs, even though the hazards from Hg will not be resolved through regulation under section 112. EPA finds that incremental reductions in Hg are important because as exposure above the RfD increases the likelihood and severity of adverse effects increases.
EGUs are the largest source of Hg in the U.S. and, thus, contribute to the risk associated with exposure to MeHg. By reducing Hg emissions from U.S. EGUs, this proposed rule will help to reduce the risk to public health and the environment from Hg exposure.
We also find that it is necessary to regulate EGUs under section 112 based on non-Hg HAP emissions because we cannot be certain that the identified cancer risks attributable to EGUs will be addressed through imposition of the requirements of the CAA. In addition, the environmental hazards posed by acidification will not be fully addressed through imposition of the CAA.
We also find it necessary to regulate EGUs because regulation under section 112 is the only way to ensure that HAP emissions reductions that have been achieved since 2005 remain permanent.
The difference between the 53 ton 2005 estimate and the 2010 ICR-based estimate of total EGU emissions may be overstated. While EPA has estimated 2010 total EGU Hg emissions of 29 tons based on data from the 2010 ICR database, this may underestimate total 2010 EGU Hg emissions due to the fact that emission factors used to develop the estimates may not accurately account for larger emissions from units with more poorly performing emission controls. The 2010 ICR by which the data used to develop the factors was collected was designed to provide the agency the data to determine the appropriate MACT levels and was not designed to collect data to fully characterize all units' Hg emissions, particularly those that might have poorly performing controls. EPA tested only 50 randomly selected units that were not selected for testing as best performing units (the bottom 85 percent of units), and we used that small sample to attempt to characterize the lower performing units. Because the 50 units were randomly selected, we do not believe we have sufficiently characterized the units that have poorly performing controls. In addition, the methodology for estimating the 2005 and 2010 emission estimates are not the same. The 2005 estimate is based on control configurations as of 2002, therefore, it does not reflect reductions due to control installations that took place between 2002 and 2005. As a result, the apparent difference between 2005 and 2010 is overstated. There are real factors that explain why Hg reductions would have occurred between 2005 and 2010. The actual reductions between 2005 and 2010 are attributable to state Hg regulations and to CAIR and Federal enforcement actions that achieve Hg reductions as a co-benefit of controls for PM, NO
As with Hg, the most recent data on U.S. EGU HCl and HF emissions show a significant reduction between 2005 and 2010. These reductions in HCl and HF are the co-benefit of controls installed to meet other CAA requirements, including enforcement actions, and to a lesser extent, state regulations. There is no guarantee other than regulation under section 112 that these significant decreases in HCl and HF emissions will be permanent. Although we do not have estimates for the remaining HAP emitted from EGUs, we believe it is likely that such emissions have also decreased between 2005 and 2010. Thus, the Administrator finds it necessary to regulate HAP emissions from EGUs to ensure that HAP emissions reductions are permanent.
Finally, direct control of Hg emissions affecting U.S. deposition is only possible through regulation of U.S. emissions; we are unable to control global emissions directly. Although the U.S. is actively involved in international efforts to reduce Hg pollution, the ability of the U.S. to argue effectively in these negotiations for strong international policies to reduce Hg air emissions depends in large part on our domestic policies, programs and regulations to control Hg.
All of these findings independently support a finding that it is necessary to regulate EGUs under section 112.
Therefore, given the Agency's finding that it remains appropriate and necessary to regulate coal- and oil-fired EGUs under CAA section 112, EPA is confirming its inclusion of coal- and oil-fired EGUs on the list of source categories regulated under CAA section 112(c).
Children are at greatest risk of adverse health effects from exposures to Hg, and this risk is amplified for children in minority and low income communities who subsist on locally-caught fish. Today's proposed rule is therefore an important step in addressing disparate impacts on children and environmental justice (EJ) communities.
Children are more vulnerable than adults to many HAP, because of differences in physiology, higher per body weight breathing rates and consumption, rapid development of the brain and bodily systems, and behaviors that increase chances for exposure. Even before birth, the developing fetus may be exposed to HAP through the mother that affect development and permanently harm the individual. Infants and children breathe at much higher rates per body weight than adults, with infants under one year of age having a breathing rate up to five times that of adults.
Mercury is the HAP from EGUs of most concern to early life stages. The adverse affects of Hg on developing neuropsychological systems is well-established and permanent. The prenatal period of development has been established to be the most sensitive lifestage to the neurodevelopmental effects of MeHg.
Other HAP related to EGU emissions present greater risks to children as well. For example, mutagenic carcinogens such as Cr
The adverse effects of individual non-Hg HAP may be more severe for children, particularly the youngest age groups, than adults. A number of epidemiologic studies suggest that children are more vulnerable than adults to lower respiratory symptoms associated with PM.
Within communities overburdened with environmental exposures, the youngest lifestages are likely the most vulnerable. Looking at the health effects for children in those communities can be an important part of appropriately assessing community risks.
EPA has also considered the effects of this rule on EJ communities. The nature of exposures to Hg is such that populations with high levels of self-caught fish consumption are likely to be disproportionately affected. EPA's risk analysis identified many EJ communities, including Laotian, Vietnamese, Hispanic, African-American, tribal, and low income communities, as having higher levels of subsistence fishing activities. Consequently, individuals in these
In 2005, EPA conducted a set of technical analyses to support a revision to the 2000 appropriate and necessary finding.
In the 2005 analysis, EPA made the following statement:
The RfD provides a useful reference point for comparisons with measured or modeled exposure. The Agency defines the RfD as an exposure level below which the Agency believes exposures are likely to be without an appreciable risk over a lifetime of exposure. For the purposes of assessing population exposure due to EGUs, we create an index of daily intake (IDI). The IDI is defined as the ratio of exposure due solely to EGUs to an exposure of 0.1 μg/kg bw/day. The IDI is defined so that an IDI of 1 is equal to an incremental exposure equal to the RfD level, recognizing that the RfD is an absolute level, while the IDI is based on incremental exposure without regard to absolute levels. Note that an IDI value of 1 would represent an absolute exposure greater than the RfD when background exposures are considered.
Upon further consideration, EPA concludes that it did not have a scientific or technical justification for creating a metric other than the HQ
Ninety-eight percent of watersheds with fish tissue MeHg samples have Hg deposition levels such that total potential exposure to MeHg exceeds the RfD, and many have exposures that are many times the RfD.
In addition to developing a flawed exposure indicator based on only U.S. EGU attributable exposure (the IDI), EPA also erred in finding that exposures above the RfD (an IDI greater than 1) did not pose an “unacceptable risk” (
In the 2005 Action, EPA cited the underpinnings of the RfD as introducing a degree of conservatism. In fact, however, as discussed above, EPA has stated consistently, including in the RfD issued in 2001, that the RfD for Hg is a level above which there is the potential for increased risk. Only at levels at or below the RfD does the Agency maintain that exposures are without
In the 2005 Action, EPA identified risk of poor performance on neurobehavioral tests, such as those measuring attention, fine motor function, language skills, visual-spatial abilities (like drawing), and verbal memory as the primary health effects of MeHg exposures. Although not stated explicitly, it is implicit in the 2005 Action that EPA did not consider these health effects to be serious. The Agency did not, and could not have, provided any scientific or policy rationale for dismissing these serious public health effects. For example, as mentioned
In the 2005 Action, EPA made several statements in the technical analysis suggesting that the probability that an IDI of 1 would be exceeded (
Information was available at the time of the 2005 analysis indicating that other populations besides Native Americans engaged in subsistence fishing activities that would result in consumption rates similar to Native Americans. EPA chose to selectively use information only on Native American consumption rates and erroneously concluded that subsistence fishing activities would not occur in a wider set of locations. This choice was in error, as EPA should have investigated whether other subsistence populations could fish in locations heavily impacted by U.S. EGU emissions (
Thus, based on the errors EPA made in the 2005 Action related to evaluating the risks from MeHg exposures attributable to U.S. EGUs, EPA's technical determination in 2005 that risks were acceptable based on that analysis was not justified. As a result the technical determination in 2005 which supported the finding of no public health hazard, and the determination that it was not appropriate or necessary to regulate HAP from U.S. EGUs was in error.
This section summarizes the requirements proposed in this proposed rule. Our rationale for the proposed requirements is provided in Section V of this preamble.
This proposed rule affects coal- and oil-fired EGUs.
An existing affected source for this proposed rule is the collection of coal- and oil-fired EGUs within a single contiguous area and under common control. A new affected source is a 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 electric (MWe) 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 MWe output to any utility power distribution system for sale is also 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 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. As noted below, EPA is proposing a definition to determine whether the combustion unit is “fossil fuel fired” such that it is an EGU for purposes of this proposed rule. The unit must be capable of combusting more than 73 megawatt-electric (MWe) (250 million British thermal units per hour, MMBtu/hr) heat input (equivalent to 25 MWe electrical output) of coal or oil. In addition, using the construct of the definition of “oil-fired” from the ARP, we are proposing that 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 to be considered a “fossil fuel fired” EGU subject to this proposed rule. If a new or existing EGU is not coal- or oil-fired, and the unit burns 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 percent or more of the annual heat input during any 1 of those calendar years, the unit is considered to be natural gas-fired and would not be subject to this proposed rule. As discussed later, we believe that this definition will address those situations where either an EGU fires coal or oil on only a limited basis or co-fires limited amounts of coal or oil with other non-fossil fuels (
To the extent a unit combusts solid waste, that unit is not an EGU under section 112, but rather would be subject to CAA section 129.
The Small Entity Representatives (SERs) serving on the Small Business Advocacy Review Panel (SBAR) established under the Small Business Regulatory Enforcement Fairness Act (SBREFA) suggested that EPA consider developing an area-source (
Nothing in the CAA requires that we issue GACT standards for area sources. Indeed, here, the data show that similar HAP emissions and control technologies are found on both major and area sources greater than 25 MWe. 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, 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. There are EGUs that are physically quite large that are area sources, and EGUs that are small that are major sources. Both large and small EGUs are represented in the MACT floor pools for acid gas, Hg, and non-Hg metal HAP. Finally, given that EPA is regulating both major and area source EGUs at the same time in this rulemaking, a common control strategy consequently appears warranted for these emissions.
If area sources tend to be very different from major sources and the capacity to control those sources is different, we could exercise our discretion under section 112(d)(5) to set GACT standards for area sources. But, as explained above, that is not the case here. Accordingly, we believe it is appropriate to set MACT standards for both major and area source EGUs. EPA solicits comment on its proposed approach. Specifically, we solicit comments on whether there would be a basis for considering area sources to be significantly different from major sources with respect to issues relevant to standard setting. Commenters should also explain the basis of their suggested approach and how that approach would lead to similar health and environmental benefits, including data that would underpin a GACT analysis.
This proposed rule applies to you if you own or operate a coal- or oil-fired EGU as defined in this proposed rule.
In March 2007, the DC Circuit Court issued an opinion (
• Floors for existing sources must reflect the average emission limitation achieved by the best-performing 12 percent of existing sources, not levels EPA considers to be achievable by all sources (479 F.3d at 880-81);
• EPA cannot set floors of “no control.” The DC Circuit Court reiterated its prior holdings, including
• EPA cannot ignore non-technology factors that reduce HAP emissions. Specifically, the DC Circuit Court held that “EPA's decision to base floors exclusively on technology even though non-technology factors affect emissions violates the Act.” (479 F.3d at 883.) The DC Circuit Court also reiterated its position stated in
Based on the
The
A second DC Circuit Court opinion is also relevant to this proposal. In
A third relevant DC Circuit Court opinion is
After the vacatur of the Revision Rule, EPA evaluated the HAP and other emissions data available to establish CAA section 112(d) standards for coal- and oil-fired EGUs and determined that additional HAP emission data were required. EPA initiated an information collection effort entitled “Electric Utility Steam Generating Unit Hazardous Air Pollutant Emissions Information
For the purpose of * * * (iii) carrying out any provision of this Chapter * * * (1) the Administrator may require any person who owns or operates any emission source * * * to * * * (D) sample such emissions (in accordance with such procedures or methods, at such locations, at such intervals, during such periods and in such manner as the Administrator shall prescribe); (E) keep records on control equipment parameters, production variables or other indirect data when direct monitoring of emissions is impractical * * *; (G) provide such other information as the Administrator may reasonably require * * *
Prior to issuance of the information collection effort, information necessary to identify all coal- and oil-fired EGUs as defined in CAA section 112(a)(8) was publicly available for EGUs owned and operated by publicly-owned utility companies, Federal power agencies, rural electric cooperatives, investor-owned utility generating companies, and nonutility generators (such units include, but may not be limited to, independent power producers (IPPs), qualifying facilities, and combined heat and power (CHP) units). The most recent information available was for 2005, and the available information generally did not include any information on permitted HAP emission limits; or monitoring, recordkeeping, and reporting requirements for HAP emissions; and we did not have complete HAP emissions data for any EGU. Additionally, we had little current information on the fuel amounts received, fuel sources, fuel shipment methods, or results of previously conducted fuel analyses for coal- and oil-fired EGUs, or for results from tests conducted since January 1, 2005. We did not have emissions test results that would provide data for emissions of a variety of pollutants, including: PM, PM with an aerodynamic diameter equal to or less than 2.5 micrometers (PM
To obtain the information necessary to evaluate coal- and oil-fired EGUs, EPA developed a two-phase ICR and published the first notice in the
As stated above, the ICR contained two phases or components. The first component solicited information from all potentially affected units. EPA provided the survey in electronic format; however, written responses were also accepted. The survey was submitted to all coal- and oil-fired EGUs listed in the 2007 version of the DOE's Energy Information Administration's (EIA) Forms 860 and 923, “Annual Electric Generator Report,” and “Power Plant Operations Report,” respectively.
The second component required the owners/operators of a limited number of coal-and oil-fired EGUs to conduct stack testing in accordance with an EPA-approved protocol. Some coal-fired units were selected to be tested because we determined based on the information available that the units were among the top performing 15 percent of sources in the coal subcategory for certain types of HAP. Best-performing coal-fired units to be tested were selected to cover three groups of HAP that may be regulated through the use of surrogate standards: (1) Non-Hg metallic HAP (
The testing consisted of three runs at the sampling location and was in accordance with a specified emission test method. The owner/operator of each selected EGU was also required to collect and analyze, in accordance with an acceptable procedure, three fuel samples from the fuel fed to the EGU during each stack test. Additional details of the required sampling may be found in Docket entry EPA-HQ-OAR-2009-0234-0062.
In phase one, all coal- and oil-fired EGUs identified by EPA as being potentially subject sources under the definition in CAA section 112(a)(8), including all integrated gasification combined cycle (IGCC) EGUs and all EGUs fired by petroleum coke, were required to submit information to EPA. The sources were required to provide information on the current operational status of the unit, including applicable controls installed, along with emissions information from the preceding 5 years. This information was necessary for EPA to fully characterize the category and update our database of coal- and oil-fired EGUs.
Phase two was the testing phase. As stated above, coal-fired units to be tested were selected to cover five HAP or groups of HAP, three of which may be regulated through the use of surrogate pollutant standards and were chosen because EPA determined the units were best performing units for one or more of the three HAP surrogate groups. In the stack testing, each facility was required to test after the last control device or at the stack if the stack is not shared with other units using different controls. In this way, the facility would test before any “dilution” by gases from a separately-controlled unit. Under certain circumstances, however, testing after a common control device or at the common stack was allowed.
EPA selected for testing the sources that the Agency believed, based on a variety of factors and information available to the Agency at the time, were the best performing sources for the three HAP surrogate groups for which they were required to test. In targeting the best performing sources, EPA required testing for approximately 15 percent of all coal-fired EGUs for the 3 HAP surrogate groups—non-Hg metal HAP and PM; non-dioxin/furan organic HAP, total hydrocarbon, CO, and VOC; and acid gas HAP and SO
The acid-gas HAP, HCl and HF, are water-soluble compounds and are more soluble in water than is SO
Hydrogen chloride and HF have also been shown to be effectively removed using DSI where a dry, alkaline sorbent (
Chlorine in the fuel coal may also partition in small amounts to Cl
Because the technologies for removal of the acid gases are primarily those that are also used for FGD, we consider emissions of SO
EPA identified the units with the newest FGD controls installed for testing of acid gas HAP based on our analysis that FGD controls are the best at reducing acid gas HAP emissions. EPA also believes that the units with the newest FGD systems represent those units having to comply with the most recent, and, therefore, likely most stringent, emission limits for SO
Dioxin/furan emissions data were obtained in support of the 1998 Utility Report to Congress. However, approximately one-half of those data were listed as being below the minimum detection level (MDL) for the given test. Dioxin/furan emissions from coal-fired EGUs are generally considered to be low, presumably because of the insufficient amounts of available chlorine. As a result of previous work conducted on municipal waste combustors (MWC), it has also been proposed that the formation of dioxins and furans in exhaust gases is inhibited by the presence of sulfur.
For these reasons, we selected 50 units at random from the entire coal-fired EGU population to conduct emission testing for dioxins/furans. EPA has identified AC as a potential control technology for dioxin/furan control based on results of previous work done on MWC units, and several of the units that were selected for testing have ACI systems that had been installed for Hg control. Specifics of the required testing may be found in Docket entry EPA-HQ-OAR-2009-0234-0062.
Emissions of CO, VOC, and/or THC have, in the past, been used as surrogates for the non-dioxin/furan organic HAP based on the theory that efficient combustion leads to lower organic emissions (Portland Cement NESHAP—THC (75 FR 54970; September 9, 2010); Boiler NESHAP—CO (75 FR 32005, June 4, 2010; 75 FR 31895, June 4, 2010 (proposed rules; the final rules were signed on February 21, 2011)); Hazardous Waste Combustor NESHAP—CO (64 FR 52828; September 30, 1999)). Although indications are that organic HAP emissions are low (and perhaps below the MDL), there were very few emissions data available for these compounds from coal-fired EGUs and we determined that it was necessary to obtain additional information on which to establish standards for these HAP. EPA identified the newest units as being representative of the most modern, and, thus, presumed most efficient units. The 170 newest units were selected and were required to test for CO, VOC, and THC; specifics of the required testing may be found in Docket entry EPA-HQ-OAR-2009-0234-0062.
Emissions of certain non-Hg metallic HAP (
EPA identified the units with the newest PM controls installed as the units to test for non-Hg metal HAP. EPA believed that these units represent those units having to comply with the most recent, and, therefore, likely most stringent, emission limits for PM. EPA believes units complying with stringent PM limits represent the top performers with regard to non-Hg metallic HAP emissions, even for those HAP that may at times form in other than the particulate phase. The units selected also included a number with ACI installed. The 170 units with the newest PM controls installed were selected and were required to test after that specific PM control (or at the stack if the PM control device is not shared with one or more other units); specifics of the required testing may be found in Docket entry EPA-HQ-OAR-2009-0234-0062.
The capture of Hg is dependent on several factors including the chloride content of the coal, the sulfur content of the coal, the amount of unburned carbon present in the fly ash, and the flue gas temperature profile. All of these factors affect the chemical form (the speciation) of Hg in the flue gas. Mercury may exist as Hg
To be able to assess the impact of the standards (
All IGCC units were also required to test; specifics of the required testing may be found in Docket entry EPA-HQ-OAR-2009-0234-0062.
EPA was able to identify the best performing coal-fired units for the three HAP surrogate groups but the data obtained in support of the Utility Study and the December 2000 Finding do not indicate that any oil-fired units control beyond some ESP use and the data do not show any correlation between the PM control at oil-fired units and emissions of non-Hg metallic HAP from those units. Further, no oil-fired EGU has been constructed in decades and no oil-fired EGU has a FGD system installed, eliminating the potential basis for the use of compliance with an SO
All petroleum coke-fired units identified were required to test; specifics of the required testing may be found in Docket entry EPA-HQ-OAR-2009-0234-0062.
Pursuant to CAA section 112(q)(3), CAA section 112 as in effect prior to the 1990 CAA amendments remains in effect for radionuclide emissions from coal-fired EGUs at the Administrator's discretion. For this reason, we did not require testing for radionuclides. We are also not proposing standards for radionuclides in this action.
Revised NSPS for SO
EPA has previously developed other non-EGU combustion-related NESHAP under CAA section 112(d) in addition to today's proposed rule for coal- and oil-fired EGUs. EPA signed final NESHAP for major and area source Boiler NESHAP on February 21, 2011 (to be
The two IB NESHAP, CT NESHAP, and this proposed 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 (MWe or Btu/hr), the boiler/furnace technology, or the portion of their electrical output (if any) for sale to any utility power distribution systems.
All of the MWe ratings quoted in the proposed rule are considered to be the original nameplate rated capacity of the unit. Cogeneration is defined as the simultaneous production of power (electricity) and another form of useful thermal energy (usually steam or hot water) from a single fuel-consuming process.
The CT rule regulates HAP emissions from all simple-cycle and combined-cycle stationary CTs producing electricity or steam for any purpose. Because of their combustion technology, simple-cycle and combined-cycle stationary CTs (with the exception of IGCC units that burn gasified coal or petroleum coke syngas) are not considered EGUs for purposes of this proposed rule.
Any combustion unit, regardless of size, that produces steam to serve a generator that produces electricity exclusively for industrial, commercial, or institutional purposes (
As noted earlier, natural gas-fired EGU's were not included in the December 2000 listing. Thus, this proposed rule would not regulate a unit that otherwise meets the CAA section 112(a)(8) definition of an EGU but 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. Such units are considered to be natural gas-fired EGUs and would not be subject to this proposed rule.
The CAA does not define the terms “fossil fuel” and “fossil fuel fired;” therefore, we are proposing definitions for both terms. The definition of “fossil fuel fired” will determine the applicability of the proposed rule to combustion units that sell electricity to the utility power distribution system. A number of units that may otherwise meet the CAA section 112(a)(8) EGU definition fire primarily non-fossil fuels (
Also, a cogeneration facility that sells electricity to any utility power distribution system equal to more than one-third of their potential electric output capacity and more than 25 MWe is considered to be an EGU if it is fossil fuel fired as that term is defined above. For such units, EPA is proposing that the unit must be capable of combusting sufficient coal or oil to generate 25 MWe from the fossil fuel alone, and must provide for sale to any utility power distribution system electricity equal to
We recognize that different section 112 rules may impact a particular unit at different times. For example there will likely be some cogeneration units that are determined to be covered under the Boiler NESHAP. Such unit may make a decision to increase/decrease the proportion of production output being supplied to the electric utility grid, thus causing the unit to meet the EGU cogeneration criteria (i.e., greater than one-third of its potential output capacity and greater than 25 MWe). A unit subject to one of the Boiler NESHAP that increases its electricity output and meets the definition of an EGU would be subject to the proposed EGU NESHAP for the 6-month period after the unit meets the EGU definition. Assuming the unit did not meet the definition of an EGU following that initial occurrence, at the end of the 6-month period it would revert back to being subject to the Boiler NESHAP. This approach is consistent with that taken on the CISWI rulemaking.
EPA solicits comment on the extent to which this situation might occur and whether the 6-month period is appropriate. Given the differences between the rules, should EPA address reclassification of the sources between the rules, particularly with regard to initial and ongoing compliance requirements and schedules? (As noted above, EPA is proposing to consider as an EGU any cogeneration unit that meets the definition noted earlier during any month in a year.) We specifically solicit comments as to how to address sources that may meet the definition of an EGU for only parts of a year. We also solicit comment on whether we should include provisions similar to those included in the final CISWI rule to address units that combust different fuels at different times. See Final CISWI Rule, 40 CFR 60.2145,
Another situation 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, the emissions have to either be apportioned to the appropriate source or the more stringent emission limit must be met. Data needed to apportion emissions are not currently required by this proposed rule or the final Boiler NESHAP. Therefore, EPA is proposing that compliance with the more stringent emission limit be demonstrated.
EPA solicits comment on the extent to which this situation might occur. Given potential differences between the rules, how should EPA address apportionment of the emissions to the individual sources with regard to initial and ongoing compliance requirements? EPA specifically requests comment on the appropriateness of a mass balance-type methodology to determine pollutant apportionment between sources both pre-APCD and post-APCD.
Units that combust “non-hazardous solid waste” as defined by the Administrator under RCRA are regulated under the provisions of CAA section 129. On February 21, 2011, EPA signed the final Non-Hazardous Solid Waste Definition Rule. Any EGU that combusts any solid waste as defined in that final rule is a solid waste incineration unit subject to CAA section 129.
In the Non-Hazardous Solid Waste Definition Rule, 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 the discarded coal refuse is processed in the same manner as currently mined coal refuse, the coal refuse would not be a solid waste and, therefore, the combustion of such material would not subject the unit to regulation under CAA section 129. By contrast, the unit would be subject to this rule if it meets the definition of EGU. If the unit combusts solid waste, it would be subject to emission standards under CAA section 129.
Further, CAA section 129(g)(1)(B) exempts from regulation under CAA section 129
“* * * 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 other forms of useful energy (such as heat) which are used for industrial, commercial, heating or cooling purposes * * *”
Thus, qualifying small power production facilities and cogeneration facilities that burn a homogeneous waste would be exempt from regulation under CAA section 129. If the “homogeneous waste” material combusted is a fossil fuel, then the units that are exempt from regulation under CAA section 129 and that otherwise meet the definition of an EGU under CAA section 112(a)(8) would be covered under this proposed rule. For example, a unit that combusts only coal refuse that is a solid waste would be subject to this proposed rule if the unit met the definition of EGU and the coal refuse was determined to be a “homogenous waste” as that term is defined in the final CAA section 129 CISWI standards (the final rule was signed on February 21, 2011, but has not yet been published in the
We are proposing the emission limitations presented in Tables 10 and 11 of this preamble. Within the two major subcategories of “coal” and “oil,” emission limitations were developed for new and existing sources for five subcategories, two for coal-fired EGUs, one for coal- and solid oil-derived IGCC EGUs, and two for oil-fired EGUs, which we developed based on unit type.
We are proposing that new or existing EGUs are “coal-fired” if they combust coal and meet the proposed definition of “fossil fuel fired.” We are proposing that an EGU is considered to be a “coal-fired unit designed for coal greater than or equal to 8,300 Btu/lb” if the EGU: (1) Combusts coal; (2) meets the proposed definition of “fossil fuel fired;” and (3) burns any coal in an EGU designed to burn a coal having a calorific value (moist, mineral matter-free basis) of
We are proposing that the EGU is considered to be an IGCC unit if the EGU: (1) Combusts gasified coal or solid oil-derived (
We are proposing that the EGU is considered to be “liquid oil” fired if the EGU burns liquid oil and meets the proposed definition of “fossil fuel fired.” We are proposing that the EGU is considered to be “solid oil-derived fuel-fired” if the EGU burns any solid oil-derived fuel (
Pursuant to CAA section 112(h), we are proposing a work practice standard for organic HAP, including emissions of dioxins and furans, from all subcategories of EGU. The work practice standard being proposed for these EGUs would require the implementation of an annual performance (compliance) test program as described elsewhere in this preamble. We are proposing work practice standards because the data confirm that the significant majority of the measured organic HAP emissions from EGUs are below the detection levels of the EPA test methods, and, as such, EPA considers it impracticable to reliably measure emissions from these units. As discussed later in this preamble, EPA believes the inaccuracy of a majority of measurements coupled with the extended sampling times used, fulfill the criteria for these HAP to be subject to a work practice standard under CAA section 112(h).
We are proposing a beyond-the-floor standard for Hg only for all existing coal-fired units designed for coal less than 8,300 Btu/lb based on the use of ACI for Hg control, as described elsewhere in this preamble. We are proposing a beyond-the-floor standard for all pollutants for new IGCC units based on the new-source limits for coal-fired units designed for coal greater than or equal to 8,300 Btu/lb as described elsewhere in this preamble.
As noted elsewhere in this preamble, we are proposing to use total PM as a surrogate for the non-Hg 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 liquid oil-fired EGUs, we are proposing total HAP metal, HCl, and HF emission limitations.
In addition, we are proposing three alternative standards for certain subcategories: (1) SO
The DC Circuit Court vacated portions of two provisions in EPA's CAA section 112 regulations governing the emissions of HAP during periods of SSM. S
Consistent with
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
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. EPA has determined that malfunctions should not be viewed as a distinct operating mode and, therefore, any emissions that occur at such times do not need to be factored into development of CAA section 112(d) standards, which, once promulgated, apply at all times. In
Further, it is reasonable to interpret CAA section 112(d) as not requiring EPA to account for malfunctions in setting emissions standards. For example, we note that CAA section 112 uses the concept of “best performing” sources in defining MACT, the level of stringency that major source standards must meet. Applying the concept of “best performing” to a source that is malfunctioning presents significant difficulties. The goal of best performing sources is to operate in such a way as to avoid malfunctions of their units.
Moreover, even if malfunctions were considered a distinct operating mode, we believe it would be impracticable to take malfunctions into account in setting CAA section 112(d) standards for EGUs. As noted above, by definition, malfunctions are sudden and unexpected events and it would be difficult to set a standard that takes into account the myriad different types of malfunctions that can occur across all sources in the category. Moreover, malfunctions can vary in frequency, degree, and duration, further complicating standard setting.
In the unlikely event that a source fails to comply with the applicable CAA section 112(d) standards as a result of a malfunction event, EPA would determine an appropriate response based on, among other things, the good faith efforts of the source to reduce the likelihood that malfunctions would occur, minimize emissions during malfunction periods, including preventative and corrective actions, as well as root cause analyses to ascertain and rectify excess emissions. EPA would also consider whether the source's failure to comply with the CAA section 112(d) standard was, in fact, “sudden, infrequent, not reasonably preventable” and was not instead “caused in part by poor maintenance or careless operation.”
Finally, 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. (
We are proposing that the 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 concentration of a regulated pollutant under proposed 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 total PM emission limit, then you would conduct HAP metals and PM emissions testing during the same compliance test period and under the same process (
(2) Coal-fired, IGCC, and solid oil-derived fuel-fired units would be required to use a Hg CEMS or sorbent trap monitoring system for continuous compliance using the continuous Hg monitoring provisions of proposed Appendix A to proposed 40 CFR part 63, subpart UUUUU. The initial performance test would consist of all valid data recorded with the certified Hg monitoring system in the first 30 boiler operating days after the compliance date.
(3) For coal-fired and solid oil-derived fuel-fired units and new or reconstructed IGCC units that have SO
(4) For all required performance stack tests, you would conduct concurrent oxygen (O
(5) For liquid oil-fired units, initial performance testing would be conducted as follows. For non-Hg HAP metals, use EPA Method 29. For Hg, conduct emissions testing using EPA Method 29 or Method 30B. For acid gases, conduct HCl and HF testing using EPA Methods 26A or 26. Conduct additional performance testing for Hg at least annually; conduct additional performance tests for HAP metals and acid gases every 2 months if the EGU has emission controls for metals or acid gases, and every month if the EGU does not have these controls.
(6) For existing units that qualify as low emitting EGUs (LEEs), conduct subsequent performance tests for the LEE qualified pollutants every 5 years and perform fuel analysis monthly.
Except for liquid oil-fired units, those EGUs with PM emissions control devices, without HCl CEMS but with HCl control devices, or for LEE, we are proposing that you monitor during initial performance testing specified operating parameters that you would use to demonstrate ongoing compliance. You would calculate the minimum (or maximum, depending on the parameter measured) hourly parameter values measured during each run of a 3-run performance test. The average of the three minimum (or maximum) values from the three runs for each applicable parameter would establish a site-specific operating limit. The applicable operating parameters for which operating limits would be required to be established are based on the emissions limits applicable to your unit as well as the types of add-on controls on the unit. The following is a summary of the operating limits that we are proposing to be established for the various types of the following units:
(1) For units without wet or dry FGD scrubbers that must comply with an HCl emission limit, you must measure the average chlorine content level in the input fuel(s) during the HCl performance test. This is your maximum chlorine input operating limit.
(2) For units with wet FGD scrubbers, you must measure pressure drop and liquid flow rate of the scrubber during the performance test, and determine the maximum value for each test run. The average of the minimum hourly value for the three test runs establishes your minimum site-specific pressure drop and liquid flow rate operating levels. If different average parameter levels are measured during the Hg and HCl tests, the highest of the average values becomes your site-specific operating limit. If you are complying with an HCl emission limit, you must measure pH of the scrubber effluent during the performance test for HCl and determine the minimum hourly value for each test run. The average of the three minimum hourly values from the three test runs establishes your minimum pH operating limit.
(3) For units with dry scrubbers or DSI (including ACI), you would be required to measure the sorbent injection rate for each sorbent used during the performance tests for HCl and Hg and determine the minimum hourly rate of injected sorbent for each test run. The average of the three test run minimum values established during the performance tests would be your site-specific minimum sorbent injection rate operating limit. If different sorbents and/or injection rates are used during the Hg and HCl performance testing, the highest value for each sorbent becomes your site-specific operating limit for the respective HAP. If the same sorbent is used during the Hg and HCl performance testing, but at different injection rates, the highest average value for each sorbent becomes your site-specific operating limit. The type of sorbent used (
(4) For units with FFs in combination with wet scrubbers, you must measure the pH, pressure drop, and liquid flow rate of the wet scrubber during the performance test and calculate the minimum hourly value for each test run. The average of the minimum hourly values from the three test runs establishes your site-specific pH, pressure drop, and liquid flow rate operating limits for the wet scrubber.
(5) For units with an ESP in combination with wet scrubbers, you must measure the pH, pressure drop, and liquid flow rate of the wet scrubber during the HCl performance test and you must measure the voltage and current of each ESP collection field during the Hg and PM performance test. You would then be required to calculate the minimum hourly value of these parameters for each of the three test runs. The average of the three minimum hourly values would establish your site-specific minimum pH, pressure drop, and liquid flow rate operating limit for the wet scrubber and the minimum voltage and current operating limits for the ESP.
(6) For liquid oil-fired or LEEs, you would be required to measure the Hg, Cl, and HAP metal content of the inlet fuel that was burned during the Hg, HCl and HF, and HAP metal emissions performance testing. The fuel content value for each of these compounds is your maximum fuel inlet operating limit for each of these compounds.
(7) For units with FFs, you must measure the output of the bag leak detection system (BLDS) sensor (whether in terms of relative or absolute PM loading) during each Hg, PM, and metals performance test. You would then be required to calculate the minimum hourly value of this output for each test run. The average of the minimum hourly BLDS values would establish your site-specific maximum BLDS sensor output and current operating limit for the BLDS.
(8) For units with an ESP, you must measure the voltage and current of each ESP collection field during each Hg, PM, and metals performance test. You would then be required to calculate the minimum hourly value of these parameters for each test run. The average of the three minimum hourly values would establish your site-specific minimum voltage and current operating limits for the ESP.
(9) Note that you establish the minimum (or maximum) hourly average operating limits based on measurements done during performance testing; should you desire to have differing operating limits which correspond to other loads, you should conduct testing at those other loads to determine those other operating limits.
Instead of operating limits for dioxins and furans and non-dioxin/furan organic HAP, we are proposing that owners or operators of units submit documentation that a “tune up” meeting the requirements of the proposed rule was conducted. Such a “tune-up” would require the owner or operator of a unit to:
(1) As applicable, inspect the burner, and clean or replace any components of the burner as necessary (you may delay the burner inspection until the next scheduled unit shutdown, but you must inspect each burner at least once every 18 months);
(2) Inspect the flame pattern, as applicable, and make any adjustments to the burner necessary to optimize the flame pattern. The adjustment should be consistent with the manufacturer's specifications, if available;
(3) Inspect the system controlling the air-to-fuel ratio, as applicable, and ensure that it is correctly calibrated and functioning properly;
(4) Optimize total emissions of CO and NO
(5) Measure the concentration in the effluent stream of CO and NO
(6) Maintain on-site and submit, if requested by the Administrator, an annual report containing:
(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 and amount of fuel used over the 12 months prior to the adjustment, but only if the unit was physically and legally capable of using more than one type of fuel during that period.
Many, if not most, EGUs have planned annual outages, and the inspection and tune up procedure was designed to occur during this normal occurrence. Nonetheless, we are proposing a maximum period of up to 18 months between inspections and tune ups to account for those EGUs with unusual planned outage schedules. We seek comment on the appropriateness of this period.
To demonstrate continuous compliance with the emission limitations, we are proposing the following requirements:
(1) For IGCC units or units combusting coal or solid oil-derived fuel and electing to use PM as a surrogate for non-Hg HAP metals, you would install, certify, and operate PM CEMS in
IGCC units or units combusting coal or solid oil-derived fuel and electing to comply with the total non-Hg HAP metals emissions limit, would demonstrate continuous compliance by conducting Method 29 testing every two months if PM controls are installed or every month if no PM controls are installed. As an option, PM CEMS could be used to demonstrate continuous compliance as described above. IGCC units or units combusting coal or solid oil-derived fuel and electing to comply with the individual non-Hg HAP metals emissions limits, would have the option to demonstrate continuous compliance only by conducting Method 29; again, testing would be conducted every two months if PM controls are installed or every month if no PM controls are installed. IGCC units or units combusting coal or solid oil-derived fuel with PM controls but not using PM CEMS to demonstrate continuous compliance would also be required to conduct parameter monitoring and meet operating limits established during performance testing. Units using FFs would be required to install and operate BLDS. As mentioned earlier, the BLDS output would be required to be less than or equivalent with the average BLDS output determined during performance testing. Moreover, a source owner or operator would be required to operate the FFs such that the sum duration of alarms from the BLDS would not exceed 5 percent of the process operating time during any 6-month period. Units using an ESP would be required to install and operate sensors to detect and measure current and voltage for each field in the ESP. As mentioned earlier, the current and voltage values for each field in the ESP would need to be greater than or equivalent with the maximum test run averages determined during performance testing.
(2) For IGCC units or units combusting coal or solid oil-derived fuel, we are proposing that Hg CEMS or sorbent trap monitoring systems be installed, certified, maintained, operated, and quality-assured in accordance with proposed Appendix A to 40 CFR part 63, subpart UUUUU, and that Hg levels (averaged on a rolling 30 boiler operating day basis) be maintained at or below the applicable Hg emissions limit. Given that the proposed Appendix A QA procedures for Hg CEMS are based on a Hg emissions trading rule (CAMR), and this proposal is for a not-to-exceed NESHAP, EPA solicits comments on whether these Hg CEMS QA procedures should be adjusted. Further, we are proposing that each pair of sorbent traps be used to collect Hg samples for no more than 14 operating days, and that the traps be replaced in a timely manner to ensure that Hg emissions are sampled continuously. In requiring continuous Hg monitoring, we assumed that most, if not all, of the units that were subject to CAMR purchased Hg CEMS and/or sorbent trap systems prior to the rule vacatur, and that many of these monitoring systems are currently installed and in operation. The Agency's conclusion regarding Hg CEMS purchases and installation is based in part on the significant number of units (over 100) that voluntarily opted to submit Hg CEMS data for the 2010 ICR. We also considered the steps taken by the industry to prepare for CAMR, and the fact that many state regulations currently require the installation and operation of Hg CEMS in order to demonstrate compliance with various SIP and consent decrees.
(3) For new or reconstructed IGCC units or coal-fired or solid oil-derived fuel-fired units with SO
Note that a PS specific to HCl CEMS has not been promulgated yet, but we expect to publish one prior to the compliance date of this proposed rule and to make it available to source owners and operators. In the meantime, the FTIR CEMS (PS 15) may be an appropriate choice for measuring continuous HCl concentrations. Hourly data from the SO
The second option that we are proposing would be for units without SO
For units with dry scrubbers or DSI systems, we are proposing that you continuously monitor the sorbent injection rate and maintain it at or above the operating limits established during the performance tests.
(4) For liquid oil-fired units, we are proposing to require testing as follows. HAP metals testing would be performed every other month if a unit has a non-Hg HAP metals control device, and every month if the unit does not have a non-Hg metals control device. We propose to require HCl and HF testing every other month if a unit has HCl and HF control devices, and monthly if the unit does not have these emissions controls.
(5) For each unit using PM, HCl, SO
(6) For limited-use liquid oil combustion units, we are proposing that those units be allowed to demonstrate compliance with the Hg emission limit, the HAP metals, or the HCl and HF emissions limits separately or in
(7) For existing LEEs, we are proposing that those units that qualify be allowed to demonstrate continuous compliance with the Hg emission limit, the non-Hg HAP metals, or the HCl emissions limits separately or in combination based on fuel analysis rather than performance stack testing. LEE would be those units where performance testing demonstrates that emissions are less than 50 percent of the PM or HCl emissions limits, less than 10 percent of the Hg emissions limits, or less than 22.0 pounds per year (lb/yr) of Hg. Note that for LEE emissions testing for total PM, total HAP metals, individual HAP metals, HCl, and HF, the required minimum sampling volumes shown in Table 2 or this proposed rule must be increased nominally by a factor of two. The LEE cutoff of 22.0 lb/yr represents about 5 percent of the nationwide Hg mass emissions from the coal-fired units represented in the 2010 ICR. Most of the units that emit less than 22.0 lb/yr would be smaller units with relatively low heat input capacities. The 22.0 lb/yr threshold was determined by summing the total Hg emissions from the 1,091 units in operation and determining the 5th percentile of the total mass. The units were then ranked by their annual Hg mass emissions. At the point in the rankings where the cumulative mass was equivalent to the 5th percentile value calculated, the annual mass emissions of that unit (22.0 lb/yr) was selected as the threshold. Five percent of the total mass was chosen as a cut point because comments received on CAMR indicated that 5 percent of the total mass was a reasonable cut point. At this 5th percentile threshold, approximately 394 smaller units out of the 1,091 total units would have the option of using this Hg monitoring methodology.
Under the proposed alternative compliance option, you would maintain fuel records that demonstrate that you burned no new fuels or fuels from a new supplier such that the Hg, non-Hg HAP metal, or the chlorine content of the inlet fuel was maintained at or below your maximum fuel Hg, non-Hg HAP metal, fluorine, or chlorine content operating limit set during the performance stack tests. If you plan to burn a new fuel, a fuel from a new mixture, or a new supplier's fuel that differs from what was burned during the initial performance tests, then you must recalculate the maximum Hg, non-Hg HAP metal, and/or the maximum chlorine input anticipated from the new fuels based on supplier data or own fuel analysis, using the methodology specified in Table 6 of this proposed rule. If the results of recalculating the inputs exceed the average content levels established during the initial test then, you must conduct a new performance test(s) to demonstrate continuous compliance with the applicable emission limit.
(8) For all EGUs, we are proposing that you maintain daily records of fuel use that demonstrate that you have burned no materials that are considered solid waste.
If an owner or operator would like to use a control device other than the ones specified in this section to comply with this proposed rule, the owner/operator should follow the requirements in 40 CFR 63.8(f), which establishes the procedure for submitting a request to the Administrator to use alternative monitoring.
EPA is proposing to simplify compliance with the proposed rule by harmonizing its monitoring and reporting requirements, to the extent possible, with those of 40 CFR part 75. With a few exceptions, the utility industry is already required to monitor and report hourly emissions data according to Part 75 under the Title IV ARP and other emissions trading programs. The Agency is, therefore, proposing Hg monitoring requirements that are consistent with Part 75 and similar to those that had been promulgated for the vacated CAMR regulation. We are proposing that hourly Hg emission data be reported to EPA electronically, on a quarterly basis. At this time, we are proposing not to apply the same electronic reporting for certification and QA test data from HCl or PM CEMS but are instead relying on the existing provisions in Parts 60 and 63.
Our rationale for this is as follows. We considered two possible Hg monitoring and reporting options to demonstrate continuous compliance. The first option would be for Hg CEMS and sorbent trap systems to be certified and quality-assured according to PS 12A and 12B in Appendix B to 40 CFR part 60. Procedure 5 in Appendix F to Part 60 would be followed for on-going QA. Semiannual hard copy reporting of “deviations” would be required, along with data assessment reports (DARs). Even though this option would not require electronic reporting of either hourly Hg emissions data or QA test results, it still would require affected sources to have a data handling system (DAHS) that: (1) Is programmed to capture data from the Hg CEMS; (2) uses the criteria in Appendix F to Part 60 to validate or invalidate the Hg data; (3) calculates hourly averages for Hg concentration and for the auxiliary parameters (
The second option would simply integrate Hg emissions data and QA test results into the existing Part 75-compliant DAHS that is installed at the vast majority of the coal-fired EGUs. We obtained feedback from several DAHS vendors indicating that the cost of modifying the existing Part 75 DAHS systems to accommodate hourly reporting of Hg CEMS and sorbent trap
Requiring the reporting of hourly Hg emissions data from EGUs would be advantageous, both to EPA and industry. The DAHS could be automated to demonstrate compliance with the standard on a continuous basis. The data could then be submitted to the Agency electronically, thereby eliminating the need for the Agency to request additional information for compliance determinations and program implementation.
Today's proposed rule would also require quarterly electronic reporting of hourly SO
Currently, utility sources that are subject to the ARP and other EPA emissions trading programs use the Emissions Collection and Monitoring Plan System (ECMPS) to process and evaluate continuous monitoring data and other information in an electronic format for submittal to the Agency. In addition to receiving hourly emissions data, this system supports the maintenance of an electronic “monitoring plan” and is designed to receive the results of monitoring system certification test data and ongoing QA test data. Emissions data are submitted quarterly through ECMPS, and users are given feedback on the quality of their reports before the data are submitted. This allows them to make corrections or otherwise address issues with the reports prior to making their official submittals. Despite the stringency and thoroughness of the data validation checks performed by the ECMPS software, the implementation of this process has resulted in very few errant reports being submitted each quarter. This has saved both industry and the Agency countless hours of valuable time, which in years past, was spent troubleshooting errors in the quarterly reports. EPA is proposing to apply the same basic quarterly data collection process to Hg, HCl, and PM CEMS data, and to modify ECMPS to be able to accommodate summarized stack test data and semiannual deviation reports.
The ECMPS process divides electronic data into three categories, the first of which is monitoring plan data. The electronic monitoring plan is maintained as a separate entity, and can be updated 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. This includes data from linearity checks, relative accuracy test audits (RATAs), cycle time tests, 7-day calibration error tests, and a number of other QA tests that are required to validate the emissions data. The results of these tests can be submitted to EPA as soon as the results are received, 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 are included in the quarterly electronic reports, along with the hourly emissions data.
The ECMPS system is already set up to receive and process certification and QA data from SO
To accommodate the certification and QA tests for Hg CEMS and sorbent trap monitoring systems, relatively few changes would have to be made to the structure and functionality of ECMPS, because most of the tests are the same ones that are required for other gas monitors. More substantive changes to the system would be required to receive and process the certification and QA tests required for HCl and PM CEMS, and to receive summarized stack test results, and the types of data provided in semiannual compliance reports; however, we believe these changes are implementable. Another modification that could be made to ECMPS would be to disable the Part 75 bias test (which is required for certain types of monitors under EPA's emissions trading programs) for Hg, HCl, and PM CEMS, if bias adjustment of the data from these monitors is believed to be unnecessary or inappropriate for compliance with the proposed rule. We are proposing to make this modification and solicit comment on it.
The third type of data collected through ECMPS is the emissions data, which, as previously noted, is reported on a quarterly schedule. The reports must be submitted 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. Direct measurements made with CEMS, such as gas concentrations, are reported in a Monitor Hourly Value (MHV) record. A typical MHV record for gas concentration includes data fields for: (1) The parameter monitored (
The ECMPS reporting structure is quite flexible, which makes it useful for assessing compliance with various emission limits. The Derived Hourly Value (DHV) record provides the means whereby a wide variety of quantities that can be calculated from the hourly emissions data can be reported. For instance, if an emission limit is expressed in units of lb/MMBtu, the
The ARP and other emissions trading programs that report emissions data to EPA using Part 75 are required to provide 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 may not be appropriate. Today's proposed rule would not require the use of missing data substitution for Hg monitoring systems. We intend to extend this concept to HCl and PM CEMS, if we receive data from those types of monitors. Hours when a monitoring system is out of service would simply be counted as hours of monitor down time, to be counted against the percent monitor availability. We solicit comment on this proposed approach.
As previously stated, EPA is proposing to add Hg monitoring provisions as Appendix A to 40 CFR part 63, subpart UUUUU, and to require these provisions to be used to document continuous compliance with the proposed rule, for units that cannot qualify as LEEs. Proposed Appendix A would consolidate all of the Hg monitoring provisions in one place. Today's proposed rule would provide two basic Hg continuous monitoring options: Hg CEMS and sorbent trap monitoring systems.
Proposed Appendix A would require the Hg CEMS and sorbent trap monitoring systems to be initially certified and then to undergo periodic QA testing. The certification tests required for the Hg CEMS would be 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 RATA. A bias test would not be required. The performance specifications for the required certification tests, which are summarized in Table A-1 of proposed Appendix A, would be the same as those that were published in support of CAMR. For ongoing QA of the Hg CEMS, proposed Appendix A would require daily calibrations, weekly single-point system integrity checks, quarterly linearity checks (or 3-level system integrity checks) and annual RATAs. These QA test requirements and the applicable performance criteria, which, once again, are the same as the ones we had published in support of CAMR, are summarized in Table A-3 in proposed Appendix A. For sorbent trap monitoring systems, a RATA would be required for initial certification, and annual RATAs would be required for ongoing QA. The performance specification for these RATAs would be the same as for the RATAs of the Hg CEMS. Bias adjustment of the measured Hg concentration data would not be required. However, for routine, day-to-day operation of the sorbent trap system, proposed Appendix A provides the owner or operator the option to follow the procedures and QA/QC criteria in PS 12B in Appendix B to 40 CFR part 60. Performance Specification 12B is nearly identical to the vacated Appendix K to Part 75. The Part 75 concepts of: (1) Determining the due dates for certain QA tests on the basis of “QA operating quarters”; and (2) grace periods for certain QA tests, would apply to both Hg CEMS and sorbent trap monitoring systems.
Mercury concentrations measured by Hg CEMS or sorbent trap systems would be used together with hourly flow rate, diluent gas, moisture, and electrical load data, to express the Hg emissions in units of the proposed rule, on an hourly basis (
The proposed rule would specify record keeping and reporting requirements for the two Hg monitoring methodologies. Essential information pertaining to each methodology would be represented in the electronic monitoring plan. Hourly Hg concentration data would be reported in all cases. However, for the sorbent trap option, a single Hg concentration value would be reported for extended periods of time, since a sorbent trap monitoring system does not provide hour-by-hour measurements of Hg concentration. The results of all required certification and QA tests would also be reported. Missing data substitution for Hg concentration would not be required for hours in which quality-assured data are not obtained. Special codes would be reported to identify these hours.
Of all the types of NESHAP compliance data that could be brought into ECMPS (
We are requesting comment on these proposed compliance approaches and on whether our proposed “one stop shopping” approach to reporting MACT compliance information electronically is desirable. In your comments, we ask you to consider the merits of requiring reporting of results from PM CEMS and HCl CEMS to ECMPS and consequent development of a monitoring and reporting scheme for these CEMS that is compatible with ECMPS. If you favor our proposed streamlined continuous compliance approach, we request input on how to make the reporting process user-friendly and efficient. EPA believes that if the essential data that are reported under the Agency's emissions trading programs and the proposed rule are all sent to the same place, this could significantly reduce the burden on industry and bring about national consistency in assessing compliance.
All new and existing sources would be required to comply with certain requirements of the General Provisions (40 CFR part 63, subpart A), which are identified in Table 10 of this proposed rule. The General Provisions include specific requirements for notifications, recordkeeping, and reporting.
Each owner or operator would be required to submit a notification of compliance status report, as required by § 63.9(h) of the General Provisions. This
Except for units that use CEMS for continuous compliance, semiannual compliance reports, as required by § 63.10(e)(3) of subpart A, would be required for semiannual reporting periods, indicating whether or not 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 previously discussed, we are proposing to use the ECMPS system to receive the essential information contained in these semiannual compliance reports electronically. For units using CEMS, quarterly electronic reporting of hourly Hg and associated (O
This proposed rule would require records to demonstrate compliance with each emission limit and work practice standard. These recordkeeping requirements are specified directly in the General Provisions to 40 CFR part 63, and are identified in Table 9 of this proposed rule.
Records of continuously monitored parameter data for a control device if a device is used to control the emissions or CEMS data would be required.
We are proposing that you must keep the following records:
(1) All reports and notifications submitted to comply with this proposed rule.
(2) Continuous monitoring data as required in this proposed rule.
(3) Each instance in which you did not meet each emission limit and each operating limit (
(4) Daily hours of operation by each source.
(5) Total fuel use by each affected liquid oil-fired source electing to comply with an emission limit based on fuel analysis for each 30 boiler operating day period along with a description of the fuel, the total fuel usage amounts and units of measure, and information on the supplier and original source of the fuel.
(6) Calculations and supporting information of chlorine fuel input, as required in this proposed rule, for each affected liquid oil-fired source with an applicable HCl emission limit.
(7) Calculations and supporting information of Hg and HAP metal fuel input, as required in this proposed rule, for each affected source with an applicable Hg and HAP metal (or PM) emission limit.
(8) A signed statement, as required in this proposed rule, indicating that you burned no new fuel type and no new fuel mixture or that the recalculation of chlorine input demonstrated that the new fuel or new mixture still meets chlorine fuel input levels, for each affected source with an applicable HCl emission limit.
(9) A signed statement, as required in this proposed rule, indicating that you burned no new fuels and no new fuel mixture or that the recalculation of Hg and/or HAP metal fuel input demonstrated that the new fuel or new fuel mixture still meets the Hg and/or HAP metal fuel input levels, for each affected source with an applicable Hg and/or HAP metal emission limit.
(10) A copy of the results of all performance tests, fuel analyses, performance evaluations, or other compliance demonstrations conducted to demonstrate initial or continuous compliance with this proposed rule.
(11) A copy of your site-specific monitoring plan developed for this proposed rule as specified in 63 CFR 63.8(e), if applicable.
We are also proposing to require that you 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.
EPA must have performance test data to conduct effective reviews of CAA sections 112 and 129 standards, as well as for many other purposes including compliance determinations, emission factor development, and annual emission rate determinations. In conducting these required reviews, EPA has found it ineffective and time consuming, not only for us, but also for regulatory agencies and source owners and operators, to locate, collect, and submit performance test data because of varied locations for data storage and varied data storage methods. In recent years, though, stack testing firms have typically collected performance test data in electronic format, making it possible to move to an electronic data submittal system that would increase the ease and efficiency of data submittal and improve data accessibility.
Through this proposal, EPA is presenting a step to increase the ease and efficiency of data submittal and improve data accessibility. Specifically, EPA is proposing that owners and operators of EGUs submit electronic copies of required performance test reports to EPA's WebFIRE database. The WebFIRE database was constructed to store performance test data for use in developing emission factors. A description of the WebFIRE database is available at
As proposed above, data entry would be through an electronic emissions test report structure called the Electronic Reporting Tool (ERT). The ERT would be able to transmit the electronic report through EPA's Central Data Exchange (CDX) network for storage in the WebFIRE database making submittal of data very straightforward and easy. A description of the ERT can be found at
The proposal to submit performance test data electronically to EPA would 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
One major advantage of the proposed submittal of performance test data through the ERT is a standardized method to compile and store much of the documentation required to be reported by this rule. Another advantage is that the ERT clearly states what testing information would be required. Another important proposed benefit of submitting these data to EPA at the time the source test is conducted is that it should substantially reduce the effort involved in data collection activities in the future. When EPA has performance test data in hand, there will likely be fewer or less substantial data collection requests in conjunction with prospective required residual risk assessments or technology reviews. This
State, local, and tribal agencies could also benefit from more streamlined and accurate review of electronic data submitted to them. The ERT would 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. Finally, another benefit of the proposed data submittal to WebFIRE electronically is that these data would 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, EPA would be able to ensure that emission factors, when updated, represent the most current range of operational practices. In summary, in addition to supporting regulation development, control strategy development, and other air pollution control activities, having an electronic database populated with performance test data would save industry, state, local, tribal agencies, and EPA significant time, money, and effort while also improving the quality of emission inventories and, as a result, air quality regulations. In this action, as previously stated, EPA is proposing a step to improve data accessibility. Specifically, we are proposing that you submit, to an EPA database, electronic copies of reports of certain performance tests required under the proposed rule through our ERT; however, we request comment on the feasibility of using a modified version of ECMPS, which the utility industry already is familiar with and uses for reporting under the Title IV ARP and other emissions trading programs, to provide this information.
ECPMS could be modified to allow electronic submission of periodic data, including, but not limited to, 30 day averages of parametric data, 30 day average fuel content data, stack test results, and performance of tune up records. These data will need to be submitted and reviewed, and we believe electronic submission via a specific format already in use for other submissions eases understanding, affords transparency, ensures consistency, and saves time and money.
We seek comment on alternatives to the use of a modified ECMPS for electronic data submission. Commenters should describe alternate means for supplying these data and information on associated reliability, the cost, the ease of implementation, and the transparency to the public of the information.
As stated above, EPA added coal- and oil-fired EGUs to the CAA section 112(c) list on December 20, 2000. This proposed rule proposes standards for the subcategories of coal- and oil-fired EGUs as defined in this preamble. Sources in these subcategories may potentially include combustion units that are at times IB units or solid waste incineration units subject to other standards under CAA section 112 or to standards under CAA section 129. We request comment on whether the proposed rule should address how sources that change fuel input (
The scope of the EGU source category is limited to coal- and oil-fired units meeting the CAA section 112(a)(8) definition and the proposed definition of “fossil fuel fired” discussed above.
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. For example, differences between given types of units can lead to corresponding differences in the nature of emissions and the technical feasibility of applying emission control techniques. In the December 2000 listing, EPA initially established and listed two subcategories of fossil fuel-fired EGUs: Coal-fired and oil-fired. The design, operating, and emissions information that EPA has reviewed indicates that there are significant design and operational differences in unit design that distinguish different types of EGUs within these two subcategories, and, because of these differences, we have proposed to establish two subcategories for coal-fired EGUs, two subcategories for oil-fired EGUs, and an IGCC subcategory for gasified coal and solid oil-derived fuel (
EGU systems are designed for specific fuel types and will encounter problems if a fuel with characteristics other than those originally specified is fired. Changes to the fuel type would generally require extensive changes to the fuel handling and feeding system (
The design of the EGU, which is dependent in part on the type of fuel being burned, impacts the degree of combustion, and may impact the level and kind of HAP emissions. EGUs emit a number of different types of HAP emissions. Organic HAP are formed from incomplete combustion and are primarily influenced by the design and operation of the unit. The degree of combustion may be greatly influenced by three general factors: Time, turbulence, and temperature. On the other hand, the amount of fuel-borne HAP (non-Hg metals, Hg, and acid gases) is primarily dependent upon the composition of the fuel. These fuel-borne HAP emissions generally can be controlled by either changing the fuel property before combustion or by removing the HAP from the flue gas after combustion.
We first examined the HAP emissions results to determine if subcategorization by unit design type was warranted. Normally, any basis for subcategorizing (
For Hg emissions from coal-fired units, we have determined that different emission limits for the two subcategories are warranted. 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.
For all HAP emissions from oil-fired units, we have determined that two subcategories are warranted. EGUs designed to burn a solid fuel (
EGUs employing IGCC technology combust a synthetic gas derived from solid coal or solid oil-derived fuel. No solid fuel is directly combusted in the unit during operation (although a coal- or solid oil-derived fuel is fired), and both the process and the emissions from IGCC units are different from units that combust solid coal or petroleum coke. Thus, we are proposing to subcategorize IGCC units as a distinct type of EGU for this proposed rule. EPA solicits comment on these subcategorization approaches.
Additional subcategories have been evaluated, including those suggested by the SERs serving on the SBAR established under the SBREFA. These suggestions include subcategorization of lignite coal vs. other coal ranks; subcategorization of Fort Union lignite coal vs. Gulf Coast lignite coal vs. other coal ranks; subcategorization by EGU size (
EPA has reviewed the available data and does not believe that these suggested approaches merit subcategorization. For example, there are both large and small units among the EGUs comprising the top performing 12 percent of sources and small entities may own minor portions of large EGUs and/or individual EGUs themselves. In addition, because the proposed format of the standards is lb/MMBtu (or TBtu for Hg), the size should only affect the rate at which a unit generates electricity and, with a lower electricity generation rate, there is less fuel consumption and, therefore, less emissions of fuel-borne HAP (i.e., acid gas and metal HAP). Further, with the exception of IGCC and as noted elsewhere regarding boiler height-to-depth ratio, there is no indication that EGU type (
EPA solicits comment on whether we should further subcategorize the source category. In commenting, commenters should provide a definition or threshold that would distinguish the proposed subcategory from the remainder of the EGU population and, to support this distinction, an estimate of how many EGUs would be impacted by the subcategorization approach, the amount of time such impacted units operate, the extent to which such impacted units would move out of and back into the subcategory in a given year (or other period of time), and any other information the commenter believes is pertinent. For example, if a commenter were to suggest subcategorizing low capacity factor or peaking units from the remainder of the EGU population, in addition to the suggested threshold capacity factor, information on the number of such units that would be impacted, the amount of time such units are running (capacity utilization), the extent to which such units are low capacity factor units in a given year vs. operating at a higher capacity factor, and data from the units when operating both as peaking units and as baseload units (among other information) would need to be provided to support the comment. Commenters should further explain how their suggested subcategorizations constitute a “size,” “type,” or “class,” as those terms are used in CAA section 112(d)(1).
This proposed rule includes numerical emission limitations for PM, Hg, and HCl (as well as for other alternate constituents or groups). Numerical emission limitations provide flexibility for the regulated community, because they allow a regulated source to choose any control technology, approach, or technique to meet the emission limitations, rather than requiring each unit to use a prescribed control method that may not be appropriate in each case.
We are proposing numerical emission rate limitations as a mass of pollutant emitted per heat energy input to the EGU for the fuel-borne HAP for existing sources. The most typical units for the limitations are lb/MMBtu of heat input (or, in the case of Hg, lb/TBtu). The mass per heat input units are consistent with other Federal and many state EGU regulations and allows easy comparison between such requirements. Additionally, this proposed rule contains an option to monitor inlet chlorine, fluorine, non-Hg metal, and Hg content in the liquid oil to meet outlet emission rate limitations. This is reasonable because oil-fired units may choose to remove these fuel-borne HAP from the oil before combustion in lieu of installing air pollution control devices. This option can only be done on a mass basis by liquid oil-fired EGUs. We request comment on the viability of this approach for IGCC units.
We are proposing numerical emission rate limitations as a mass of pollutant emitted per megawatt- or gigawatt-hour (MWh or GWh) gross output from the EGU for the fuel-borne HAP for new sources and as an alternate format for existing sources. An outlet numerical emission limit is also consistent with the format of other regulations (
EGUs can emit a wide variety of compounds, depending on the fuel burned. Because of the large number of HAP potentially present and the disparity in the quantity and quality of the emissions information available, EPA grouped the HAP into five categories based on available information about the pollutants and on experiences gained on other NESHAP: Hg, non-Hg metallic HAP, inorganic (i.e., acid gas) HAP, non-dioxin/furan organic HAP, and dioxin/furan organic HAP. The pollutants within each group have similar characteristics and can be controlled with the same techniques. For example, non-Hg metallic HAP can be controlled with PM controls. We chose to look at Hg separately from other metallic HAP due to its different chemical characteristics and its different control technology feasibility.
Next, EPA identified compounds that could be used as surrogates for all the compounds in each pollutant category. Existing technologies that have been installed to control emissions of other (
EGUs routinely measure operating parameters (flow rates, temperatures, pH, pressure drop, etc.) and flue gas composition for process control and monitoring and for emission compliance and verification. Some of these routinely or more easily-measured parameters or components may serve as surrogates or indicators of the level of control of one or more of the HAP that may not be easily or routinely measured or monitored. The use of more easily-measured components or process conditions as surrogates or predictors of HAP emissions can greatly simplify monitoring requirements under this proposed rule and, in some cases, provide more reliable results.
In order to evaluate potential surrogacy relationships, the EPA Office of Research and Development (ORD), in collaboration with OAR, conducted a series of tests in the Agency's Multipollutant Control Research Facility (MPCRF), a pilot-scale combustion and control technology research facility located at EPA's Research Triangle Park campus in North Carolina. The combustor is rated at 4 MMBtu/hr (approximately 1.2 megawatt-thermal (MW
Eleven independent tests were performed in the MPCRF in order to examine potential surrogacy relationships. Three types of coal (eastern bituminous, subbituminous, and Gulf Coast lignite) were tested. The PM control was also varied; in some tests, the ESP was used whereas the FF was used in others. Three potential surrogacy relationships were examined during the testing program. The potential for use of PM control as a surrogate for the control of the non-Hg metal HAP (Be, As, Cd, Co, Cr, Mn, Ni, Pb, Sb, and Se) was examined. The potential for use of HCl or SO
The results of the program indicated that the control of all non-Hg metal HAP (except Se) was consistently similar to the control of the bulk total PM (PM
The results for Se control were less consistent. When subbituminous coal was fired, the control of Se was consistently very good (average 98.9 percent), regardless of the PM control device being used. When using the FF as the primary PM control device, the Se control was consistently very good (average 99.2 percent) regardless of the coal being fired. Control of Se when the ESP was the primary PM control device was variable. When subbituminous coal was fired, the control of Se through the ESP was greater than 99 percent. When lignite was fired, the control through the ESP was about 80 percent. However, when the eastern bituminous coal was fired, the Se control through the ESP ranged from zero to 73 percent.
The variability in the performance of Se control with coal rank and PM control device can be explained by the known behavior and chemistry of Se in the combustion and flue gas environments. Selenium is a metalloid that sits just below sulfur on the periodic table and is, chemically, very similar to sulfur. In the high temperature combustion environment, Se is likely to be present as gas phase SeO
Two of the 11 tests were specifically designated for testing of surrogacy relationships relating to the acid gas HAP. Eastern bituminous coal was fired and duct samples were taken upstream and downstream of the lime-based wet FGD scrubber. Those tests showed, as expected, very high levels of control for HCl (greater than 99.9 percent control). The control of HF was greater than 92 percent for the first run and greater than 76 percent for the second run. The control of Cl
Tests were also conducted to examine potential surrogacy relationships for the non-dioxin/furan organic HAP. The amounts of Hg, non-Hg metals, HCl, HF, and Cl
During the pilot-scale tests, sampling was conducted for semi-volatile and volatile organic HAP and aldehydes. On-line monitors also collected data on THC, CO, O
With complex carbon-based fuels, combustion is rarely ideal and some CO and concomitant organic compounds are expected to be formed. Because CO and organics are both products of poor combustion, it is logical to expect that limiting the concentration of CO would also limit the production of organics. However, it is very difficult to develop direct correlations between the average concentration of CO and the amount of organics produced during the prescribed sampling period in the MPCRF (which was 4 hours for the pilot-scale tests described here). This is especially true for low values of CO as one would expect corresponding low quantities of organics to be produced. Samples of coal combustion flue gas have mostly shown very low quantities of the organic compounds of interest. Some of the flue gas organics may also be destroyed in the high temperature post combustion zone (whereas the CO would remain stable). Semi-volatile organics may also condense on PM and be removed in the PM control device.
The average CO from the pilot-scale tests ranged from 23 to 137 ppm for the bituminous coals tests, from 43 to 48 ppm for the subbituminous coal tests and from 93 to 129 ppm for the Gulf Coast lignite tests. However, it was difficult to correlate that concentration to the quantity of organics produced for several reasons. The most difficult problems are associated with the large number of potential organics that can be produced (both those on the HAP list and those that are not on the HAP list). This is further complicated by the organic compounds tending to be at or below the MDL in coal combustion flue gas samples. Further, there are complications associated with the CO concentration values. Some of the runs with very similar average concentrations of CO had very different maximum concentrations of CO (
In the pilot tests, the THC measurement was inadequate as the detection limit of the instrument was much too high to detect changes in the very low concentrations of hydrocarbons in the flue gas.
Based on the testing described above and the emissions data received under the 2010 ICR, we are proposing surrogate standards for the non-Hg metallic HAP and the non-metallic inorganic (acid gas) HAP. For the non-Hg metallic HAP, we chose to use PM as a surrogate. Most, if not all, non-Hg metallic HAP emitted from combustion sources will appear on the flue gas fly-ash. Therefore, the same control techniques that would be used to control the fly-ash PM will control non-Hg metallic HAP. PM was also chosen instead of specific metallic HAP because all fuels do not emit the same type and amount of metallic HAP but most generally emit PM that includes some amount and combination of all the metallic HAP. The use of PM as a surrogate will also eliminate the cost of performance testing to comply with numerous standards for individual non-Hg metals. Because non-Hg metallic HAP may preferentially partition to the small size particles (i.e., fine particle enrichment), we considered using PM
For non-metallic inorganic (acid gas) HAP, EPA is proposing setting an HCl standard and using HCl as a surrogate for the other non-metallic inorganic HAP for all subcategories except the liquid oil-fired subcategory. The emissions test information available to EPA indicate that the primary non-metallic inorganic HAP emitted from EGUs are acid gases, with HCl present in the largest amounts. Other inorganic compounds emitted are found in smaller quantities. As discussed earlier, control technologies that reduce HCl indiscriminately control other inorganic compounds such as Cl
EPA is proposing work practice standards for non-dioxin/furan organic and dioxin/furan organic HAP. The significant majority of measured emissions from EGUs of these HAP were below the detection levels of the EPA test methods, and, as such, EPA considers it impracticable to reliably measure emissions from these units. As the majority of measurements are so low, doubt is cast on the true levels of emissions that were measured during the tests. Overall, 1,552 out of 2,334, total test runs for dioxin/furan organic HAP contained data below the detection level for one or more congeners, or 67 percent of the entire data set. In several cases, all of the data for a given run were below the detection level; in few cases were the data for a given run all above the detection level. For the non-dioxin/furan organic HAP, for the individual HAP or constituent, between 57 and 89 percent of the run data were comprised of values below the detection level. Overall, the available test methods are technically challenged, to the point of providing results that are questionable for all of the organic HAP. For example, for the 2010 ICR testing, EPA extended the sampling time to 8 hours in an attempt to obtain data above the MDL. However, even with this extended sampling time, such data were not obtained making it questionable that any amount of effort, and, thus, expense, would make the tests viable. Based on the difficulties with accurate measurements at the levels of organic HAP encountered from EGUs and the economics associated with units trying to apply measurement methodology to test for compliance with numerical limits, we are proposing a work practice standard under CAA section 112(h).
We do not believe that this approach is inconsistent with that taken on other NESHAP where we also had issues with data at or below the MDL (
For all the other HAP, as stated above, we are proposing to establish numerical emission rate limitations; however, we did consider using a percent reduction format for Hg (
All standards established pursuant to CAA section 112(d)(2) must reflect MACT, the maximum degree of reduction in emissions of air pollutants that the Administrator, taking into consideration the cost of achieving such emissions reductions, and any nonair
EPA must consider available emissions information to determine the MACT floors. For each pollutant, we calculated the MACT floor for a subcategory of sources by ranking all the available emissions data obtained through the 2010 ICR
Therefore, the MACT floor limits for each of the HAP and HAP surrogates are calculated based on the performance of the lowest emitting (best performing) sources in each of the subcategories.
As discussed above, for coal-fired EGUs, EPA established the MACT floors for non-Hg metallic HAP and non-metallic inorganic (acid gas) HAP based on sources representing 12 percent of the number of sources in the subcategory. For Hg from coal-fired units and all HAP from oil-fired units, EPA established the MACT floors based on sources representing 12 percent of the sources for which the Agency had emissions information. The IGCC and solid oil-fired EGU subcategories each have less than 30 units so the MACT floors were determined using the 5 best performing sources (or 2 sources for IGCC because there are only 2 such sources in the subcategory). The MACT floor limitations for each of the HAP and HAP surrogates (PM, Hg, and HCl) are calculated based on the performance of the lowest emitting (best performing) sources in each of the subcategories. The initial sort of the respective data to determine the MACT floor pool for analysis was made on the “lb/MMBtu” formatted data; this same pool of EGUs was then used for the “lb/MWh” analysis and all analyses were based on the data provided through the 2010 ICR.
We used the emissions data for those best performing affected sources to determine the emission limitations to be proposed, with an accounting for variability. EPA must exercise its judgment, based on an evaluation of the available data, to determine the level of emissions control that has been achieved by the best performing sources under variable conditions. The DC Circuit Court has recognized that EPA may consider variability in estimating the degree of emission reduction achieved by best-performing sources in setting MACT floors.
In determining the MACT floor limitations, we first determine the floor, which is the level achieved in practice by the average of the top 12 percent of similar sources for subcategories with more than 30 sources. We then assess variability of the best performers by using a statistical formula designed to estimate a MACT floor level that is achieved by the average of the best performing sources with some confidence (
We first determined the distribution of the emissions data for the best-performing 12 percent of units within each subcategory prior to calculating UPL values. When the sample size is 15 or larger, one can assume based on the Central Limit theorem, that the sampling distribution of the average or sampling mean of emission data is approximately normal, regardless of the parent distribution of the data. This assumption justifies selecting the normal-distribution based UPL equation for calculating the floor.
When the sample size is smaller than 15 and the distribution of the data is unknown, the Central Limit Theorem can't be used to support the normality assumption. Statistical tests of the kurtosis, skewness, and goodness of fit are then used to evaluate the normality assumption. To determine the distribution of the best performing dataset, we first computed the skewness and kurtosis statistics and then conducted the appropriate small-sample hypothesis tests. The skewness statistic (S) characterizes the degree of asymmetry of a given data distribution. Normally distributed data have a skewness of zero (0). A skewness statistic that is greater (less) than 0 indicates that the data are asymmetrically distributed with a right (left) tail extending towards positive (negative) values. Further, the standard error of the skewness statistic (SES) can be approximated by SES = SQRT(6/N) where N is the sample size. According to the small sample skewness hypothesis test, if S is greater than two times the SES, the data distribution can be considered non-normal. The kurtosis statistic (K) characterizes the degree of peakedness or flatness of a given data distribution in comparison to a normal distribution. Normally distributed data have a kurtosis of 0. A kurtosis statistic that is greater (less) than 0 indicates a
The skewness and kurtosis hypothesis tests were applied to both the reported test values and the lognormal values (using the LN() function in Excel) of the reported test values. If S and K of the reported data set were both less than twice the SES and SEK, respectively, the dataset was classified as normally distributed. If neither S nor K, or only one of these statistics, were less than twice the SES or SEK, respectively, then we looked at the skewness and kurtosis hypothesis test results conducted for the natural log-transformed data. Then, the distribution most similar to a normal distribution was selected as the basis for calculating the UPL. If the results of the skewness and kurtosis hypothesis tests were mixed for the reported values and the natural log-transformed reported values, we chose the normal distribution to be conservative. We believe this approach is more accurate and obtained more representative results than a more simplistic normal distribution assumption.
Because some of the MACT floor emission limitations are based on the average of a 3-run test, and compliance with these limitations will be based on the same, the UPL for data considered to be normally distributed is calculated by:
This calculation was performed using the following Excel function:
Normal distribution: 99% UPL = AVERAGE(Test Runs in Top 12%) + [STDEV(Test Runs in Top 12%) × TINV(2 × probability, n-1 degrees of freedom)*SQRT((1/n)+(1/3))], for a one-tailed t-value (with 2 × probability), probability of 0.01, and sample size of n.
Data from only a single unit was used in establishing the new-source floor. Analysis based solely in these single-data-point-per-unit observations does not capture any within source variability. When additional information (
The calculation of this UPL was performed using the following Excel function:
Normal distribution: 99% UPL = AVERAGE(Test Runs in Top 12%) + [STDEV(Test Runs in Top 12%, stack averages) × TINV(2 × probability, (n-1) degrees of freedom)*SQRT((1/N)+(
The UPL, to test compliance based on a 3-run average and assuming log-normal data, is calculated by (Bhaumik and Gibbons, 2004):
The calculation of the log-normal based UPL was performed using the following Excel function:
Normal distribution: 99% UPL = EXP(AVERAGE(LN(Test Runs in Top 12%)) + VAR(LN(Test Runs in Top 12%))/2) + (99
SQRT(m*EXP(2* AVERAGE(LN(Test Runs in Top 12%))+ VAR(LN(Test Runs in Top 12%)))*(EXP(VAR(LN(Test Runs in Top 12%)))-1)+m‸2* EXP(2* AVERAGE(LN(Test Runs in Top 12%))+ VAR(LN(Test Runs in Top 12%)))*(VAR(LN(Test Runs in Top 12%))/n+ VAR(LN(Test Runs in Top 12%))‸2/(2*(n-1)))).
The 99
Test method measurement imprecision can also be a component of data variability. At very low emissions levels, as encountered in some of the data used to support this proposed rule, the inherent imprecision in the pollutant measurement method has a large influence on the reliability of the data underlying the regulatory floor or beyond-the-floor emissions limit. Of particular concern are those data that are reported near or below a test method's pollutant detection capability. In our guidance for reporting pollutant emissions used to support this proposed rule, we specified the criteria for determining test-specific MDL. Those criteria ensure that there is about a 1 percent probability of an error in deciding that the pollutant measured at the MDL is present when in fact it was absent. Such a probability is also called a false positive or the alpha, Type I, error. Another view of this probability is that one is 99 percent certain of the presence of the pollutant measured at the MDL. Because of matrix effects, laboratory techniques, sample size, and other factors, MDLs normally vary from test to test. We requested sources to identify (
Variability of data due to measurement imprecision is inherently and reasonably addressed in calculating the floor emissions limit when the data distribution, which would include the results of all tests, is significantly above the MDL. Should the data distribution shift such that some or many test results are below the MDL but are reported as MDL values, as is the case for some of our database, then other techniques need to be used to account for data variability. Indeed, under such a shift, the distribution becomes truncated on the lower end, leading to an artificial overabundance of values occurring at the MDL. Such an artificial overabundance of values could, if not adjusted, lead to erroneous floor calculations; those unadjusted floor calculations may be higher than otherwise expected, because no values reported below the MDL are included in the calculation. There is a concern that a floor emissions limit based on a truncated data base may not account adequately for data measurement variability and that a floor emissions limit calculated using values at or near the MDL may not account adequately for data measurement variability, because the measurement error associated with those values provides a large degree of uncertainty—up to 100 percent.
Despite our concern that accounting for measurement imprecision should be an important consideration in calculating the floor emissions limit, we did not adjust the calculated floor for the data used for this proposed rule because we do not know how to develop such an adjustment. We remain open to considering approaches for making such an adjustment, particularly when those approaches acknowledge our inability to detect with certainty those values below the MDL. We request comment on approaches suitable to account for measurement variability in establishing the floor emissions limit when based on measurements at or near the MDL.
As noted above, the confidence level that a value measured at the detection level is greater than 0 is about 99 percent. The expected measurement imprecision for an emissions value occurring at or near the MDL is about 40 to 50 percent. Pollutant measurement imprecision decreases to a consistent relative 10 to 15 percent for values measured at a level about three times the MDL.
The second step would be to determine the value equal to three times the representative MDL and compare it to the calculated floor emissions limit. If three times the representative MDL were less than the calculated floor emissions limit, we would conclude that measurement variability is adequately addressed and we would not adjust the calculated floor emissions limit. If, on the other hand, the value equal to three times the representative MDL were greater than the calculated floor emissions limit, we would conclude that the calculated floor emissions limit does not account entirely for measurement variability. We then would use the value equal to three times the MDL in place of the calculated floor emissions limit to ensure that the floor emissions limit accounts for measurement variability. This adjusted value would ensure measurement variability is adequately addressed in the floor or the emissions limit. This check was part of the variability analysis for all new MACT floors that had below detection level (BDL) or detection level limited (DLL) run data present in the best controlled data set and resulted in the MACT floors being three times the MDL rather than the UPL in a limited number of instances (see “MACT Floor Analysis (2011) for the Subpart UUUUU—National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-fired Electric Utility Steam Generating Units” (MACT Floor Memo) in the docket). We request comment on this approach.
As previously discussed, we account for variability in setting floors, not only because variability is an element of performance, but because it is reasonable to assess best performance over time. For example, we know that the HAP emission data from the best performing units are, for the most part, short-term averages, and that the actual HAP emissions from those sources will vary over time. If we do not account for this variability, we would expect that even the units that perform better than the floor on average could potentially exceed the floor emission levels a part of the time which would mean that variability was not properly taken into account. This variability may include the day-to-day variability in the total fuel-borne HAP input to each unit; variability of the sampling and analysis methods; and variability resulting from site-to-site differences for the best
We believe 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. Both the analysis of the measured emissions from units representative of the top 12 percent, and the variability analysis, are reasonably designed to provide a meaningful estimate of the average performance, or central tendency, of the best controlled 12 percent of units in a given subcategory.
A detailed discussion of the MACT floor methodology is presented in the MACT Floor Memo in the docket.
In developing the proposed MACT floor for the fuel-borne HAP (non-Hg metals, acid gases, and Hg), as described earlier, we are using PM as a surrogate for non-Hg metallic HAP (except for the liquid oil-fired subcategory) and HCl as a surrogate for the acid gases (except for the liquid oil-fired subcategory). Table 12 of this preamble presents the number of units in each of the subcategories, along with the number of units comprising the best performing units (top 12 percent). Table 12 of this preamble also shows the average emission level of the top 12 percent, and the MACT floor including consideration of variability (99 percent UPL of top 12 percent).
For the “Coal-fired unit designed for coal < 8,300 Btu/lb” subcategory, we used 12 percent of the available data (11 data points), or 2 units, in setting the existing source floor for Hg. For the IGCC subcategory, we used data from both units in setting the existing source floor. For the oil-fired subcategory, we did not include data obtained from EGUs co-firing natural gas in the existing-source MACT floor analysis because those emissions are not representative of EGUs firing 100 percent fuel oil.
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. Further, we are proposing a total metals limit for oil-fired EGUs that includes Hg, in lieu of a PM limit, based on compliance through fuel analysis. We solicit comment on whether a PM limit or a total metals limit based on stack testing is an appropriate alternative. We recognize that PM is not an appropriate surrogate for Hg because Hg is not controlled to the same extent by the technologies which control emissions of other HAP metals, but we are soliciting comment as to whether there is anything unique as to oil-fired EGUs that would allow us to conclude that PM is an appropriate surrogate for all HAP metal emissions from such units. We further solicit comment on whether we should be setting a separate standard for Hg if we require end-of-stack testing for a total metals limit. Based on the data we have, that Hg limit would be 0.050 lb/MMBtu (0.000070 lb/GWh) for existing oil-fired units and 0.00010 lb/GWh for new oil-fired units. In this regard, we request additional Hg emissions data from oil-fired EGUs. Although we have some data, additional
CAA section 112(h)(1) states that the Administrator may prescribe a work practice standard or other requirements, consistent with the provisions of CAA sections 112(d) or (f), in those cases where, in the judgment of the Administrator, it is not feasible to enforce an emission standard. CAA section 112(h)(2)(B) further defines the term “not feasible” in this context to apply when “the application of measurement technology to a particular class of sources is not practicable due to technological and economic limitations.”
As noted earlier, the significant majority of the measured emissions from EGUs of dioxin/furan and non-dioxin/furan organic HAP are at or below the MDL of the EPA test methods even though we required 8 hour test runs. As such, EPA considers it impracticable to reliably measure emissions from these units. As mentioned earlier, because the expected measurement imprecision for an emissions value occurring at or near the MDL is about 40 to 50 percent, we are uncertain of the true levels of organic HAP emissions that would be obtained during any test program. Overall, the fact that the organic HAP emission levels found at EGUs are so near the MDL achievable by the available test methods indicates that the results obtained are questionable for all of the organic HAP.
Because the levels of organic HAP emissions from EGUs are so low (at or below the MDL of the available test methods), there is no indication that expending additional cost (
Based on this analysis, and considering the fact that regardless of the cost, the resulting emissions data would be suspect due to the detection level issues, the Administrator is proposing under CAA section 112(h) that it is not feasible to enforce emission standards for dioxin/furan and non-dioxin/furan organic HAP because of the technological and economic infeasibility described above. Thus, a work practice, as discussed below, is being proposed to limit the emission of these HAP for existing EGUs.
For existing units, the only work practice we identified that would potentially control these HAP emissions is an annual performance test. Organic HAP are formed from incomplete combustion of the fuel. The objective of good combustion is to release all the energy in the fuel while minimizing losses from combustion imperfections and excess air. The combination of the fuel with the O
Once the MACT floors were established for each subcategory, we considered various regulatory options more stringent than the MACT floor level of control (
Except for one subcategory, we could not identify better HAP emissions reduction approaches that could achieve greater emissions reductions of HAP than the control technology combination(s) (
Fuel switching to natural gas is an option that would reduce HAP emissions. We determined that fuel switching was not an appropriate beyond-the-floor option. First, natural gas supplies are not available in some areas. Natural gas pipelines are not available in all regions of the U.S., and natural gas may not be available as a fuel for many EGUs. Moreover, even where pipelines provide access to natural gas, supplies of natural gas may not be adequate, especially during peak demand (
Additional detail on the economics of coal-to-gas conversion and illustrative calculations of additional emission reductions versus cost impacts are provided in the “Coal-to-Gas Conversion” TSD in the docket.
As noted earlier, no EGU 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 a EGU with a height-to-depth ratio of 3.82 or greater was found among the top performing 12 percent of sources for Hg emissions, even though some of these units employed ACI. EPA has learned that the units of this design that were using ACI during the testing were using ACI to meet their permitted Hg emission levels. However, EPA believes that the control level being achieved is still not that which could be achieved if ACI were used to its fullest extent. Therefore, EPA is proposing to establish a beyond-the-floor emission limit for existing 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 a EGU with a height-to-depth ratio of 3.82 or greater. The proposed emission limit is 4 lb/TBtu for existing EGUs in this class. This proposed emission limit is based on use of the data from the top performing unit in the subcategory made available to the Agency through the 2010 ICR; the same statistical analyses were conducted as were done to establish the MACT floor values for the other HAP. EPA notes that our analysis shows that the technology installed to achieve the MACT floor
To assess the impacts on the existing EGUs in this subcategory to implement the proposed beyond-the-floor limit, EPA conducted analyses using approaches as discussed in the memoranda “Beyond-the-Floor Analysis (2011) for the Subpart UUUUU—National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-fired Electric Utility Steam Generating Units” and “Emission Reduction Costs for the Beyond-the-Floor Mercury Rate in the Toxics Rule” in the docket. The cost effectiveness of the beyond-the-floor option ranged from $17,375 to $21,393/lb Hg removed in the two approaches. The total costs of the non-air environmental impacts for the proposed beyond-the-floor limit for this subcategory are estimated as $12,310. Non-air quality health impacts were evaluated, but no incremental health impacts were attributable to installation of FF and ACI, because these technologies do not expose electric utility employees or the public to any additional health risks above the risks attributable to current utility operations involving compressed air systems, confined spaces, and exposure to fly ash.
EPA is aware that there may be other means of enhancing the removal of Hg from the flue gas stream (
EPA believes the best potential way of reducing Hg emissions from existing IGCC units is to remove Hg from the syngas before combustion. For example, an existing industrial coal gasification unit has demonstrated a process, using a sulfur-impregnated AC bed, which has proven to yield over 90 percent Hg removal from the coal syngas. (Rutkowski 2002.) We considered using carbon bed technology as beyond-the-floor for existing IGCC units. However, we have no detailed data to support this position at this time and, thus, are not proposing a beyond-the-floor limit for existing IGCC units. EPA requests comments on whether the use of this or other control techniques have been demonstrated to consistently achieve emission levels that are lower than levels from similar sources achieving the proposed existing MACT floor level of control. Comments should include information on emissions, control efficiencies, reliability, current demonstrated applications, and costs, including retrofit costs.
We considered proposing beyond-the-floor requirements for Hg in the other subcategories and for the other HAP in all of the subcategories. Activated carbon injection is used on EGUs designed for coal greater than or equal to 8,300 Btu/lb and, therefore, its effect on Hg removal has already been accounted for in the MACT floor. Further, EPA has no information that would indicate that ACI would provide significantly lower emission levels given the MACT floor Hg standard, and it is also possible that existing sources in this subcategory will utilize ACI to comply with the MACT floor limit. Activated carbon injection has not been demonstrated on liquid oil-fired EGUs. Similarly, ACI has not been demonstrated on solid oil-derived fuel-fired EGUs. EPA has no information that would indicate that ACI would provide significantly lower Hg emission levels on units operating at the level of the MACT floor. For the non-Hg metallic and acid gas HAP, there is no technology that would achieve additional control over that being shown by units making up the floor. Additional combinations of controls (
EPA has attempted to identify subcategories that provide the most reasonable basis for grouping and estimating the performance of generally similar units using the available data. We believe that the subcategories we selected are appropriate.
EPA requests comments on whether additional or different subcategories should be considered. Comments should include detailed information regarding why a new or different subcategory is appropriate (based on the available data and on the statutory constraint of “class, type or size”), how EPA should define any additional and/or different subcategories, how EPA should account for varied or changing fuel mixtures, and how EPA should use the available data to determine the MACT floor for any new or different subcategories.
All standards established pursuant to CAA section 112 must reflect MACT, the maximum degree of reduction in emissions of air pollutants that the Administrator, taking into consideration the cost of achieving such emissions reductions, and any nonair quality health and environmental impacts and energy requirements, determines is achievable for each category. The CAA specifies that MACT for new EGUs shall not be less stringent than the emission control that is achieved in practice by the best-controlled similar source. This minimum level of stringency is the MACT floor for new units. However, EPA may not consider costs or other impacts in determining the MACT floor. EPA must consider cost, nonair quality health and environmental impacts, and energy requirements in connection with any standards that are more stringent than the MACT floor (beyond-the-floor controls).
Similar to the MACT floor process used for existing EGUs, the approach for determining the MACT floor must be based on available emissions test data. Using such an approach, we calculated the MACT floor for a subcategory of sources by ranking the 2010 ICR emissions data from EGUs within the subcategory from lowest to highest (on a lb/MMBtu basis) to identify the best controlled similar source. The MACT floor limitations for each of the HAP and HAP surrogates (PM, Hg, and HCl) are calculated based on the performance (numerical average) of the lowest emitting (best controlled) source for each pollutant in each of the subcategories.
The MACT floor limitations for new sources were calculated using the same formula as was used for existing sources with one exception. For the new source calculations, the results of the three individual emission test runs were used
This approach reasonably ensures that the emission limit selected as the MACT floor adequately represents the average level of control actually achieved by the best controlled similar source, considering ordinary operational variability.
A detailed discussion of the MACT floor methodology is presented in the MACT Floor Memo in the docket.
The approach that we use to calculate the MACT floors for new sources is somewhat different from the approach that we use to calculate the MACT floors for existing sources. Although the MACT floors for existing units are intended to reflect the performance achieved by the average of the best performing 12 percent of sources, the MACT floors for new units are meant to reflect the emission control that is achieved in practice by the best controlled similar source. Thus, for existing units, we are concerned about estimating the central tendency of a set of multiple units, whereas for new units, we are concerned about estimating the level of control that is representative of that achieved by a single best controlled source. As with the analysis for existing sources, the new EGU analysis must account for variability.
In developing the MACT floor for the fuel-borne HAP (PM, HCl, and Hg), as described earlier, we are using PM as a surrogate for non-Hg metallic HAP and HCl as a surrogate for the acid gases (except for the liquid oil-fired subcategory). Table 13 of this preamble presents for each subcategory and fuel-borne HAP the average emission level of the best controlled similar source and the MACT floor which accounts for variability (99 percent UPL).
We are proposing a work practice standards for non-dioxin/furan organic and dioxin/furan organic HAP under CAA section 112(h) that would require the implementation of an annual performance test program for new EGUs. This proposal for new EGUs is based on the same reasons discussed previously for existing EGUs. That is, the measured emissions from EGUs of these HAP are routinely below the detection limits of the EPA test methods, and, as such, EPA considers it impracticable to reliably measure emissions from these units.
Thus, the work practice discussed above for existing EGUs is being proposed to limit the emissions of non-dioxin/furan organic and dioxin/furan organic HAP for new EGUs.
We request comments on this approach.
The MACT floor level of control for new EGUs is based on the emission control that is achieved in practice by the best controlled similar source within each of the subcategories. No technologies were identified that would achieve HAP reduction greater than the new source floors for the subcategories, except for multiple controls in series (
Fuel switching to natural gas is a potential regulatory option beyond the new source floor level of control that would reduce HAP emissions. However, natural gas supplies are not available in some areas. Thus, this potential control option may be unavailable to many sources in practice. Limited emissions reductions in combination with the high cost of fuel switching and considerations about the availability and technical feasibility of fuel switching makes this an unreasonable regulatory option that was not considered further. As discussed above, the uncertainties associated with nonair quality health and environmental impacts also argue against determining that fuel switching is reasonable beyond-the-floor option. In addition,
Although, as discussed earlier for existing EGUs, EPA is proposing to establish a beyond-the-floor emission limit for Hg for existing EGUs designed to burn a nonagglomerating fuel having a calorific value (moist, mineral matter-free basis) of 19,305 kJ/kg (8,300 Btu/lb) or less in a EGU with a height-to-depth ratio of 3.82 or greater, EPA is not proposing to go beyond-the-floor for new EGUs in this subcategory. The proposed emission limit of 0.04 lb/GWh for new EGUs in this subcategory is based on use of ACI on a new unit and, we believe, reflects a level of performance achievable and, as noted above, no technologies were identified that would achieve HAP reduction greater than the new source floors for the subcategories, except for multiple controls in series (
As discussed earlier, because of a lack of data, EPA is not proposing beyond-the-floor emission limits for existing IGCC units. However, EPA believes that the new-source limits derived from the data obtained from the two operating IGCC units are not representative of what a new IGCC unit could achieve. Therefore, EPA looked to the permit issued for the Duke Energy Edwardsport IGCC facility currently under construction.
Similarly, for the reasons discussed earlier for existing EGUs, EPA is not proposing any other beyond-the-floor emission limitations. EPA requests comments on whether the use of any control techniques have been demonstrated to consistently achieve emission levels that are lower than levels from similar sources achieving the proposed new-source MACT floor levels of control. Comments should include information on emissions, control efficiencies, reliability, current demonstrated applications, and costs, including retrofit costs.
We are proposing to set a conventional MACT standard for HCl and, for the reasons explained elsewhere, are proposing that the HCl limit also serve as a surrogate for other acid gas HAP. We also considered whether it was appropriate to exercise our discretionary authority to establish health-based emission standards under CAA section 112(d)(4) for HCl and each of the other relevant HAP acid gases: Cl
As a general matter, CAA section 112(d) requires MACT standards at least as stringent as the MACT floor to be set for all HAP emitted from major sources. However, CAA section 112(d)(4) provides that for HAP with established health thresholds, the Administrator has the discretionary authority to consider such health thresholds when establishing emission standards under CAA section 112(d). This provision is intended to allow EPA to establish emission standards other than conventional MACT standards, in cases where a less stringent emission standard will still ensure that the health threshold will not be exceeded, with an ample margin of safety. In order to exercise this discretion, EPA must first conclude that the HAP at issue has an established health threshold and must then provide for an ample margin of safety when considering the health threshold to set an emission standard.
It is clear the Administrator may exercise her discretionary authority under CAA section 112(d)(4) only with respect to pollutants with a health threshold. Where there is an established threshold, the Administrator interprets CAA section 112(d)(4) to allow her to weigh additional factors, beyond any established health threshold, in making a judgment whether to set a standard for a specific pollutant based on the threshold, or instead follow the traditional path of developing a MACT standard after determining a MACT floor. In deciding whether to exercise her discretion for a threshold pollutant for a given source category, the Administrator interprets CAA section 112(d)(4) to allow her to take into account factors such as the following: the potential for cumulative adverse health effects due to concurrent exposure to other HAP with similar biological endpoints, from either the same or other source categories, where the concentration of the threshold pollutant emitted from the given source category is below the threshold; the potential impacts on ecosystems of releases of the pollutant; and reductions in criteria pollutant emissions and other co-benefits that would be achieved by a MACT standard. Each of these factors is directly relevant to the health and environmental outcomes at which CAA section 112 is fundamentally aimed. If the Administrator does determine that it is appropriate to set a standard based on a health threshold, she must develop emission standards that will ensure the public will not be exposed to levels of the pertinent HAP in excess of the
EPA has exercised its discretionary authority under CAA section 112(d)(4) in a handful of prior rules setting emissions standards for other major source categories, including the Boiler NESHAP issued in 2004, which was vacated on other grounds by the DC Circuit Court. In the Pulp and Paper NESHAP (63 FR 18765; April 15, 1998), and Lime Manufacturing NESHAP (67 FR 78054; December 20, 2002), EPA invoked CAA section 112(d)(4) for HCl emissions for discrete units within the facility. In those rules, EPA concluded that HCl had an established health threshold (in those cases it was interpreted as the RfC for chronic effects) and HCl was not classified as a human carcinogen. In light of the absence of evidence of carcinogenic risk, the availability of information on non-carcinogenic effects, and the limited potential health risk associated with the discrete units being regulated, EPA concluded that it was appropriate to exercise its discretion under CAA section 112(d)(4) for HCl under the circumstances of those rules. EPA did not set an emission standard based on the health threshold; rather, the exercise of EPA's discretion in those cases in effect exempted HCl from the MACT requirement. In more recent rules, EPA decided not to propose a health-based emission standard for HCl emissions under CAA section 112(d)(4) for Portland Cement facilities (75 FR 54970 (September 9, 2010), and for Industrial, Commercial, and Institutional Boilers, (75 FR 32005; June 4, 2010 proposal(major); the final major source rule was signed on February 21, 2011 but has not yet been published). EPA has never implemented a NESHAP that used CAA section 112(d)(4) with respect to HF, Cl
Because any emission standard under CAA section 112(d)(4) must consider the established health threshold level, with an ample margin of safety, in this rulemaking EPA has considered the adverse health effects of the HAP acid gases, beginning with HCl and including HF, Cl
With respect to the potential health effects of HCl, we note the following:
(1) Chronic exposure to concentrations at or below the RfC is not expected to cause chronic respiratory effects;
(2) Little research has been conducted on its carcinogenicity. The one occupational study of which we are aware found no evidence of carcinogenicity;
(3) There is a significant body of scientific literature addressing the health effects of acute exposure to HCl (for a summary,
(4) We are aware of no studies explicitly addressing the toxicity of mixtures of HCl with other respiratory irritants. However, many of the other HAP (and criteria pollutants) emitted by EGUs also are respiratory irritants, and in the absence of information on interactions, EPA assumes an additive cumulative effect (Supplementary Guidance for Conducting Health Risk Assessment of Chemical Mixtures.
In addition to potential health impacts, the Administrator also has evaluated the potential for environmental impacts when considering whether to exercise her discretion under CAA section 112(d)(4). When HCl gas encounters water in the atmosphere, it forms an acidic solution of hydrochloric acid. In areas where the deposition of acids derived from emissions of sulfur and NO
Because the statute requires an ample margin of safety, it would be reasonable to set any CAA section 112(d)(4) emission standard for a pollutant with a health threshold at a level that at least
Finally, we considered the fact that setting conventional MACT standards for HCl as well as PM (as a surrogate for HAP metals) would result in significant reductions in emissions of other pollutants, most notably SO
Given the limitations of the currently available information (
This conclusion is not contrary to EPA's prior decisions noted earlier where we found it appropriate to exercise the discretion to invoke the authority in CAA section 112(d)(4) for HCl, because the circumstances in this case differ from previous considerations. EGUs differ from the other source categories for which EPA has exercised its authority under CAA section 112(d)(4) in ways that affect consideration of any health threshold for HCl. EGUs are much more likely to be significant emitters of acid gas HAP and non-HAP than are other source categories. In fact, they are the largest anthropogenic emitter of HCl and HF in the U.S, emitting roughly half of the estimated nationwide total HCl and HF emissions in 2010. Our case study analyses of the chronic impacts of EGUs did not indicate any significant potential for them to cause any exceedances of the chronic RfC for HCl due to their emissions alone.
We are proposing testing, monitoring, notification, and recordkeeping requirements that are adequate to assure continuous compliance with the requirements of this proposed rule. These requirements are described elsewhere in this preamble. We selected these requirements based upon our determination of the information necessary to ensure that the emission standards and work practices are being followed and that emission control devices and equipment are maintained and operated properly. These proposed requirements ensure compliance with this proposed rule without imposing a significant additional burden for units that must implement them.
We are proposing that units using continuous monitoring systems for PM, HCl, and Hg demonstrate initial compliance by performance testing for non-Hg HAP metals and the surrogate PM, for HCl and its surrogate SO
Additionally, this proposed rule would require annual maintenance be performed so that good combustion continues. Such an annual check will serve to ensure that dioxins, furans, and other organic HAP emissions continue to be at or below MDLs.
We evaluated the feasibility and cost of applying PM CEMS to EGUs. Several electric utility companies in the U.S. have now installed or are planning to install PM CEMS. In recognition of the fact that PM CEMS are commercially available, EPA developed and promulgated PSs for PM CEMS (69 FR 1786, January 12, 2004). Performance Specifications for PM CEMS are established under PS 11 in appendix B to 40 CFR part 60 for evaluating the acceptability of a PM CEMS used for determining compliance with the emission standards on a continuous basis. For PM CEMS monitoring, initial costs were estimated to be $261,000 per
Table 14 holds preliminary cost information. Note that these costs are based on 2010 ICR emissions test estimates and on values in EPA's monitoring costs assessment tool. Particulate matter and metals and SO
The Agency is seeking comment on the cost information presented above. The commenters are encouraged to provide detailed information and data that will help the Agency refine its cost estimates for this rulemaking.
The majority of test methods that this proposed rule would require for the performance stack tests have been required under many other EPA standards. Three applicable voluntary consensus standards were identified: American Society of Mechanical Engineers (ASME) Performance Test Code (PTC) 19-10-1981-Part 10, “Flue and Exhaust Gas Analyses,” a manual method for measuring the oxygen, CO
When a performance test is conducted, we are proposing that parameter operating limitations be determined during the tests. Performance tests to demonstrate compliance with any applicable emission limitations are either stack tests or fuel analysis or a combination of both.
To ensure continuous compliance with the proposed emission limitations and/or operating limits, this proposed rule would require continuous parameter monitoring of control devices and recordkeeping. We selected the following requirements based on reasonable cost, ease of execution, and usefulness of the resulting data to both the owners or operators and EPA for ensuring continuous compliance with the emission limitations and/or operating limits.
We are proposing that certain parameters be continuously monitored for the types of control devices commonly used in the industry. These parameters include pH, pressure drop and liquid flow rate for wet scrubbers; and sorbent injection rate for dry scrubbers and DSI systems. You must also install a BLDS for FFs. These monitoring parameters have been used in other standards for similar industries. The values of these parameters are established during the initial or most recent performance test that demonstrates compliance. These values are your operating limits for the control device.
You would be required to set parameters based on 4-hour block averages during the compliance test, and demonstrate continuous compliance by monitoring 12-hour block average values for most parameters. We selected this averaging period to reflect operating conditions during the performance test to ensure the control system is continuously operating at the same or better level as during a performance test demonstrating compliance with the emission limits.
To demonstrate continuous compliance with the emission and operating limits, you would also need daily records of the quantity, type, and origin of each fuel burned and hours of operation of the affected source. If you are complying with the chlorine fuel input option, you must keep records of the calculations supporting your determination of the chlorine content in the fuel.
If a liquid oil-fired EGU elected to demonstrate compliance with the HCl or individual or total HAP metal limit by using fuel which has a statistically lower pollutant content than the emission limit, we are proposing that the source's operating limit is the emission limit of the applicable pollutant. Under this option, a source is not required to conduct performance
This proposed rule would specify the testing methodology and procedures and the initial and continuous compliance requirements to be used when complying with the fuel analysis options. Fuel analysis tests for total chloride, gross calorific value, Hg, individual and total HAP metal, sample collection, and sample preparation are included in this proposed rule.
If you are a liquid oil-fired EGU and elect to comply based on fuel analysis, you will be required to statistically analyze, using the z-test, the data to determine the 90th percentile confidence level. It is the 90th percentile confidence level that is required to be used to determine compliance with the applicable emission limit. The statistical approach is required to assist in ensuring continuous compliance by statistically accounting for the inherent variability in the fuel type.
We are proposing that a source be required to recalculate the fuel pollutant content only if it burns a new fuel type or fuel mixture and conduct another performance test if the results of recalculating the fuel pollutant content are higher than the level established during the initial performance test.
We are proposing that owners and operators of existing affected sources may demonstrate compliance by emissions averaging for units at the affected source that are within a single subcategory.
As part of EPA's general policy of encouraging the use of flexible compliance approaches where they can be properly monitored and enforced, we are including emissions averaging in this proposed rule. Emissions averaging can provide sources the flexibility to comply in the least costly manner while still maintaining 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 affected source. 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 would allow owners and operators of an affected source to demonstrate that the source complies with the proposed emission limits by averaging the emissions from an individual affected unit that is emitting above the proposed emission limits with other affected units at the same facility that are emitting below the proposed emission limits and that are within the same subcategory.
This proposed rule includes an emissions averaging compliance alternative because emissions averaging represents an equivalent, more flexible, and less costly alternative to controlling certain emission points to MACT levels. We have concluded that a limited form of averaging could be implemented that would not lessen the stringency of the MACT floor limits and would provide flexibility in compliance, cost and energy savings to owners and operators. We also recognize that we must ensure that any emissions averaging option can be implemented and enforced, will be clear to sources, and most importantly, will be no less stringent than unit by unit implementation of the MACT floor limits.
EPA has concluded that it is permissible to establish within a NESHAP a unified compliance regimen that permits averaging within an affected source across individual affected units subject to the standard under certain conditions. 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 NESHAP will not be greater under the averaging mechanism than it could be if each individual affected unit 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 unit, and the statutory requirement that the MACT standard reflect the maximum achievable emissions reductions is, therefore, fully effectuated.
In past rulemakings, 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.
This proposed rule would fully satisfy each of these criteria. First, emissions averaging would only be permitted between individual sources at a single existing affected source, and would only be permitted between individual sources subject to the proposed EGU NESHAP. Further, emissions averaging would not be permitted between two or more different affected sources. Finally, new affected sources could not use emissions averaging. Accordingly, we have concluded that the averaging of emissions across affected units is consistent with the CAA. In addition, this proposed rule would require each facility that intends to utilize emission averaging to submit an emission averaging plan, which provides additional assurance that the necessary criteria will be followed. In this emission averaging plan, the facility must include the identification of: (1) All units in the averaging group; (2) the control technology installed; (3) the process parameter that will be monitored; (4) the specific control technology or pollution prevention measure to be used; (5) the test plan for the measurement of the HAP being averaged; and (6) the operating parameters to be monitored for each control device. Upon receipt, the regulatory authority would not be able to approve an emission averaging plan containing averaging between emissions of different types of pollutants or between sources in different subcategories.
This proposed rule would also exclude new affected sources from the emissions averaging provision. EPA believes emissions averaging is not appropriate for new affected sources because it is most cost effective to integrate state-of-the-art controls into equipment design and to install the technology during construction of new 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. This flexibility is not needed for new affected sources because they can be designed and constructed with compliance in mind.
In addition, we seek comment on use of a discount factor when emissions averaging is used and on the appropriate value of a discount factor, if used. Such discount factors (
The emissions averaging provisions in this proposed 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.
CAA section 112 specifies the dates by which affected sources must comply with the emission standards. New or reconstructed units must be in compliance with this proposed rule immediately upon startup or [DATE THE FINAL RULE IS PUBLISHED IN THE FEDERAL REGISTER], whichever is later. Existing sources may be provided up to 3 years to comply with the final rule; if an existing source is unable to comply within 3 years, a permitting authority has the discretion to grant such a source up to a 1-year extension, on a case-by-case basis, if such additional time is necessary for the installation of controls.
We believe that the requirements of the proposed rule can be met without adversely impacting electric reliability. Our analysis shows that the expected number of retirements is less than many have predicted and that these can be managed effectively with existing tools and processes for ensuring continued grid reliability. Further, the industry has adequate resources to install the necessary controls and develop the modest new capacity required within the compliance schedule provided for in the CAA. Although there are a significant number of controls that need to be installed, with proper planning, we believe that the compliance schedule established by the CAA can be met. There are already tools in place (such as integrated resource planning, and in some cases, advanced auctions for capacity) that ensure that companies adequately plan for, and markets are responsive to, future requirements such as the proposed rule. In addition, EPA itself has already begun reaching out to key stakeholders including not only sources with direct compliance obligations, but also groups with responsibility to assure an affordable and reliable supply of electricity including state Public Utility Commissions (PUC), Regional Transmission Organizations (RTOs), the National Electric Reliability Council (NERC), the Federal Energy Regulatory Commission (FERC), and DOE. EPA intends to continue these efforts during both the development and implementation of this proposed rule. It is EPA's understanding that FERC and DOE will work with entities whose responsibility is to ensure an affordable, reliable supply of electricity, including state PUCs, RTOs, the NERC to share information and encourage them to begin planning for compliance and reliability as early as possible. This effort to identify and respond to any projected local and regional reliability concerns will inform decisions about the timing of retirements and other compliance strategies to ensure energy reliability. EPA believes that the ability of permitting authorities to provide an additional 1 year beyond the 3-year compliance time-frame as specified in CAA section 112, along with other compliance tools, ensures that the emission reductions and health benefits required by the CAA can be achieved while safeguarding completely against any risk of adverse impacts on electricity system reliability. Between proposal and final, EPA will work with DOE and FERC to identify any opportunities offered by the authorities and policy tools at the disposal of DOE and/or FERC that can be pursued to further ensure that the dual goals of substantially reducing the adverse public health impacts of power generation, as required by the CAA, while continuing to assure electric reliability is maintained. EPA also intends to continue to work with DOE, FERC, state PUCs, RTOs and power companies as this rule is implemented to identify and address any challenges to ensuring that both the requirements of the CAA and the need for a reliable electric system are met.
In developing this proposed rule, EPA has performed specific analysis to assess the feasibility (
With regards to feasibility, EPA used IPM to project what types of controls would need to be installed to meet the requirements of this proposed rule. This includes technologies to control acid gases (wet and dry scrubber technology and the use of sorbent injection), the Hg requirements (co-benefits from other controls such as scrubbers and FFs and Hg-specific controls such as ACI), the non-Hg metal requirements (upgrades and or replacements of existing particulate control devices), and other HAP emissions (GCP).
Much of the power sector already has controls in place that remove significant amounts of acid gases. Today over 50 percent of the power generation fleet has scrubbing technology installed and the industry is already working on installations to bring that number to nearly two-thirds of the fleet by 2015. Many of the remaining coal-fired units are smaller, burn lower sulfur coals, and/or do not operate in a base-load mode. Units with these types of characteristics are candidates to use DSI technology which takes significantly less time to install. Units that choose to install dry or wet scrubbing technology should be able to do so within the compliance schedule required by the CAA as this technology can be installed within the 3-year window.
For Hg control, those units that do not meet the requirements with existing controls have several options. Companies with installed scrubbers may be able to make modifications (such as the use of scrubber additives to enhance Hg control). Other companies may use supplemental controls such as ACI. These types of options all take significantly less than 3 years to install.
Units that do not meet the non-Hg metal HAP requirements have several options such as upgrading existing particulate controls, installing
EPA projects that for acid gas control, companies will likely use dry scrubbing and sorbent injection technologies rather than wet scrubbing. For non-Hg metal HAP controls, EPA has assumed that companies with ESPs will likely upgrade them to FFs. As a number of units that were in the MACT floor for non-Hg HAP metals only had ESPs installed, this is likely a conservative assumption. For Hg, EPA projects that companies will comply through either the collateral reductions created by other controls (
Permitting authorities are familiar with the operation of this provision because they have used it in implementing previous NESHAP. This extension can be used to address a range of reasons that installation schedules may take more than 3 years including: staggering installations for reliability or constructability purposes, or other site-specific challenges that may arise related to source-specific construction issues, permitting, or local manpower or resource challenges. EPA is proposing that States consider applying this extension both to the installation of add on controls (
EPA has also considered the impact that potential retirements under this proposed rule will have on reliability. When considering the impact that one specific action has on power plant retirements, it is important to understand that the economics that drive retirements are based on multiple factors including: Expected electric demand, cost of alternative generation, and cost of continuing to generate using an existing unit. EPA's analysis shows that the lower cost of alternative generating sources (particularly the cost of natural gas), as well as reductions in demand, have a greater impact on the number of projected retirements than does the impact of the proposed rule. EPA's assessment looked at the reserve margins in each of 32 subregions in the continental U.S. It shows that with the addition of very little new capacity, average reserve margins are significantly higher than required (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 transmission constraints, the number of retirements projected suggests that the magnitude of any local retirements should be manageable with existing tools and processes. Demand forecasts used were based on EIA projected demand growth.
Reliability concerns caused by local transmission constraints can be addressed through a range of solutions including the development of new generation and/or demand side resources, and/or enhancements to the transmission system. 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 large reserve margins, there are companies ready to implement supply side projects quickly. For instance, in the PJM Interconnection (an RTO) region, there are over 11,600 MW of capacity that have completed feasibility and impact studies and could be on-line by the third quarter of 2014.
EPA also examined the impact on reliability of unit outages to install control equipment. Because these outages usually occur in the shoulder months (outside summer or winter peaking periods) when demand is lower (and, thus, reserve margins are higher), the analysis showed that even with conservative estimates regarding the length of the outages and conservative estimates about how many outages occurred within a 1-year time-frame, reserve margins were maintained. With the potential for a 1-year compliance extension, outages can be further staggered, providing additional flexibility, even if some units require longer outages.
Although EPA's analysis shows that there is sufficient time and grid capacity to allow for compliance with the rule within the 3-year compliance window
There is significant evidence that companies do in fact engage in such forward planning. For instance, in September of 2004 (approximately 6 months before the CAIR and CAMR requirements were finalized); Cinergy announced that it had already begun a construction program to comply. This program involved not only preliminary engineering, but actual construction of scrubbers.
It will also ensure that sufficient notification can be provided to RTOs/ISOs so that the full range of options for addressing any reliability concerns can be considered. Although most RTOs/ISOs only require 90-day notifications for retirements, construction schedules for all but the simplest retrofits will be longer, so sources should be able to notify their RTOs of their retirements earlier. This will also help as multiple sources work with their RTO/ISO to determine outage schedules. The RTOs/ISOs also have a very important role to play and it appears that a number of them are already engaged in preparing for these rules. For instance, PJM Interconnection considered the impact of these anticipated rules at its January 14, 2011, Regional Planning Process Task Force Meeting,
As discussed above, given the large reserve margins that exist, even after consideration of requirements of the proposed rule, EPA believes that any reliability issues are likely to be primarily local in nature and be due to the retirement of a unit in a load constrained area. As demonstrated by the work that PJM Interconnection and MISO are doing, RTOs/ISOs are required to do long range (at least 10 years) capacity planning that includes consideration of future requirements such as EPA regulations. Furthermore, if companies within an RTO/ISO wish to retire a unit, they must first notify the RTO/ISO in advance so that any reliability concerns can be addressed. The RTOs/ISOs, have well established procedures to address such retirements.
Starting assessments early and considering the full range of options will help ensure that the requirements of this rule are met as economically as possible and that power companies are able to provide reliable electric power while significantly reducing their impact on public health. For power companies this includes considering the range of pollution control options available for their existing fleet as well as considering the range of options for replacement power, in the cases where shutting down a unit is the more economic choice. The RTOs/ISOs should consider the full range of options to provide any necessary replacement power including the development of both supply and demand side resources. Environmental regulators should work with their affected sources early to understand their compliance choices. In this way, those regulators will be able to accurately access when use of the 1-year compliance extension is appropriate. By working with regulators early, affected sources will be in a position to have assurance that the 1-year extension will be granted in those situations where it is appropriate.
Section X.c. describes the sensitivity analysis performed by EPA for an Energy Efficiency case, in which a combination of DOE appliance standards and State investments in demand-side efficiency come into place at the same time as compliance with the requirements of this rule. That analysis shows that even in the absence of this rule, moderate actions to promote energy efficiency would lead to retirement of an additional 11 GW in 2015, of 27 GW in 2020, and of 26 GW in 2030, beyond the capacity already projected to retire in the base case. In effect, the timely adoption and implementation of energy efficiency policies would augment currently projected reserve capacities that are instrumental to assuring system reliability.
As noted, instrumental to undertaking such actions are other Federal agencies such as DOE, ISOs and RTOs, and state agencies such as PUCs. Fortunately, in addition to helping to assure system reliability, timely implementation of energy efficiency policies offer these key decision-makers an additional incentive to take action. As the analysis shows, energy efficiency can reduce costs for ratepayers and customers.
First, with or without the proposed Toxic Rule, energy efficiency policies are shown by the analysis to reduce the overall costs of generating electricity, with the cost reductions increasing over time.
The energy savings driven by these energy efficiency policies mean that consumers will pay less for electricity as well. EPA has modeled national average retail electricity prices, including the energy efficiency costs that are paid by the ratepayer. The Toxics Rule increases retail prices by 3.7 percent, 2.6 percent and 1.9 percent in 2015, 2020 and 2030
EPA believes that as it shares these results with PUCs, the commissions will respond in accordance with their ongoing imperative to ensure that electricity costs for ratepayers and consumers remains stable. Specifically, the opportunity created through the deployment of energy efficiency-promoting strategies and initiatives to safeguard system reliability and, especially, to curb cost increases that might otherwise result from implementation of the Toxics Rule should provide PUCs with both the motivation and the justification for providing utilities with the financial and regulatory support they need to begin planning as early as possible for compliance and to incorporate in their plans the kinds of energy efficiency investments needed to achieve both compliance and cost-minimization.
EPA recognizes that both utilities and their regulators often are hesitant to take early action to comply with environmental standards because they avoid incurring costs that they fear may not be required once the final regulation is promulgated. EPA urges utilities and regulators to begin planning and preparations for timely compliance. The same concerns about consumer cost in some cases also dissuade utilities from incurring, and commissions from authorizing, the upfront costs associated with energy efficiency programs. However, EPA also believes that if it takes steps to actively disseminate the results of the energy efficiency analysis, then utilities will be that much more likely to begin, and regulators that much more likely to support, comprehensive assessment and planning as early as possible since compliance approaches that encompass energy efficiency integrated with other actions needed to meet the Toxics Rule's requirements will result in lower costs for ratepayers and consumers. EPA encourages State environmental regulators to consider the extent to which a utility engages in early planning when making a decision regarding granting a 4th year for compliance with the Toxics Rule.
In summary, EPA believes that the large reserve margins, the range of control options, the range of flexibilities to address unit shutdowns, existing processes to assure that sufficient generation exists when and where it is needed, and the flexibilities within the CAA, provide sufficient assurance that the CAA section 112 requirements for the power sector can be met without adversely impacting electric reliability.
EGUs are the subject of several rulemaking efforts that either are or will soon be underway. In addition to this rulemaking proposal, concerning both hazardous air pollutants under section 112 and criteria pollutant NSPS standards under section 111, EGUs are the subject of other rulemakings, including ones under section 110(a)(2)(D) addressing the interstate transport of emissions contributing to ozone and PM air quality problems, coal combustion wastes, and the implementation of section 316(b) of the Clean Water Act (CWA). They will also soon be the subject of a rulemaking under CAA section 111 concerning emissions of greenhouse gases.
EPA recognizes that it is important that each and all of these efforts achieve their intended environmental objectives in a common-sense manner that allows the industry to comply with its obligations under these rules as efficiently as possible and to do so by making coordinated investment decisions and, to the greatest extent possible, by adopting integrated compliance strategies. 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.” Thus, EPA recognizes that it needs to approach these rulemakings, to the extent that its legal obligations permit, 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 the rulemakings must achieve.
The upcoming rulemaking under section 111 regarding GHG emissions from EGUs may provide an opportunity to facilitate the industry's undertaking integrated compliance strategies in meeting the requirements of these rulemakings. First, since that rulemaking will be finalized after a number of the other rulemakings that are currently underway are, the Agency will have an opportunity to take into account the effects of the earlier rulemakings in making decisions regarding potential GHG standards for EGUs.
Second, in that rulemaking, EPA will be addressing both CAA section 111(b) standards for emissions from new and modified EGUs and CAA section 111(d) emission guidelines for states to follow in establishing their plans regarding GHG emissions from existing EGUs. In evaluating potential emission standards and guidelines, EPA may consider the impacts of other rulemakings on both emissions of GHGs from EGUs and the costs borne by EGUs. The Agency expects to have ample latitude to set requirements and guidelines in ways that can support the states' and industry's efforts in pursuing practical, cost-effective and coordinated compliance strategies encompassing a broad suite of its pollution-control obligations. EPA will be taking public comment on such flexibilities in the context of that rulemaking.
As discussed elsewhere in this preamble, we invite comment on this proposed rule. EPA solicits comment on the ability of sources subject to this proposed rule to comply within the statutorily mandated 3-year compliance window and/or the 1-year discretionary extension, as well as comment on specific factors that could prevent a source from achieving, or could enable a source to achieve, compliance. In addition, EPA requests comment on the impact of this proposed rule on electric reliability, and ways to ensure compliance while maintaining the reliability of the grid.
A number of states (or localities) have proactively developed plans to address a suite of environmental issues, an aging generation fleet, and electric reliability (
The Agency has a program pursuant to 40 CFR subpart E, whereby states can take delegation of section 112 emission standards. Among other things, states can seek approval of state rules to the extent they can demonstrate that those rules are no less stringent that the applicable section 112(d) rule. Because overall, some of these state programs may result in greater emission reductions, EPA is taking comment on whether (and if so how) such state plans could be integrated with the proposed rule requirements consistent with the statute. EPA also intends to engage with states who believe that they have such plans to understand whether they believe that there are opportunities to integrate the two sets of requirements in a manner consistent with the requirements of the CAA.
EGUs are the subject of several rulemaking efforts that either are or will soon be underway. In addition to this rulemaking proposal, concerning both HAP under section 112 and criteria pollutant NSPS standards under section 111, EGUs are the subject of other rulemakings, including ones under section 110(a)(2)(D) addressing the interstate transport of emissions contributing to ozone and PM air quality problems, coal combustion wastes, and the implementation of section 316(b) of the CWA. They will also soon be the subject of a rulemaking under CAA section 111 concerning emissions of greenhouse gases (GHG).
EPA recognizes that it is important that each and all of these efforts achieve their intended environmental objectives in a common-sense manner that allows the industry to comply with its obligations under these rules as efficiently as possible and to do so by making coordinated investment decisions and, to the greatest extent possible, by adopting integrated compliance strategies. Thus, EPA recognizes that it needs to approach these rulemakings, to the extent that its legal obligations permit, 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 the rulemakings must achieve.
The upcoming rulemaking under section 111 regarding GHG emissions from EGUs may provide an opportunity to facilitate the industry's undertaking integrated compliance strategies in meeting the requirements of these rulemakings. First, since that rulemaking will be finalized after a number of the other rulemakings that are currently underway are, the agency will have an opportunity to take into account the effects of the earlier rulemakings in making decisions regarding potential GHG standards for EGUs.
Second, in that rulemaking, EPA will be addressing both CAA section 111(b) standards for emissions from new and modified EGUs and CAA section 111(d) emission guidelines for states to follow in establishing their plans regarding GHG emissions from existing EGUs. In evaluating potential emission standards and guidelines, EPA may consider the impacts of other rulemakings on both emissions of GHGs from EGUs and the costs borne by EGUs. The Agency expects to have ample latitude to set requirements and guidelines in ways that can support the states' and industry's efforts in pursuing practical, cost-effective and coordinated compliance strategies encompassing a broad suite of its pollution-control obligations. EPA will be taking public comment on such flexibilities in the context of that rulemaking.
You would be required to comply with the applicable requirements in the NESHAP General Provisions, subpart A of 40 CFR part 63, as described in Table 10 of the proposed 40 CFR part 63, subpart UUUUU. We evaluated the General Provisions requirements and included those we determined to be the minimum notification, recordkeeping, and reporting requirements necessary to ensure compliance with, and effective enforcement of, this proposed rule.
We would require additional recordkeeping if you chose to comply with the chlorine or Hg fuel input option. You would need to keep records of the calculations and supporting information used to develop the chlorine or Hg fuel input operating limit.
The CAA requires that sources subject to this proposed rule be operated pursuant to a permit issued under EPA-approved state operating permit program. The operating permit programs are developed under Title V of the CAA and the implementing regulations under 40 CFR parts 70 and 71. If you are operating in the first 2 years of the current term of your operating permit, you will need to obtain a revised permit to incorporate this proposed rule. If you are in the last 3 years of the current term of your operating permit, you will need to incorporate this proposed rule into the next renewal of your permit.
As discussed above, we are proposing alternate equivalent emission standards (for certain subcategories) to the proposed surrogate standards in three areas: SO
Most, if not all, coal-fired EGUs and solid oil-derived fuel-fired EGUs already have emission limitations for SO
Some sources have expressed a preference for individual non-Hg metal HAP emission limitations rather than the use of PM as a surrogate. Thus, EPA has analyzed the data for that purpose and we are proposing both alternate individual HAP metal limitations and total HAP metal limitations for all subcategories except liquid oil-fired EGUs. These limitations provide equivalent control of metal HAP as the proposed PM limitations.
We are soliciting comments on all aspects of these alternate emission limitations.
New source performance standards implement CAA section 111(b), and are issued for source categories which EPA has determined cause, or contribute significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare. CAA section 111(b)(1)(B) requires the EPA to periodically review and, if appropriate, revise the NSPS to reflect improvements in emissions reduction methods.
CAA section 111 requires that the NSPS reflect the application of the best system of emissions reductions which the Administrator determines has been adequately demonstrated (taking into account the cost of achieving such reduction, any non-air quality health and environmental impacts and energy requirements). This level of control is commonly referred to as best demonstrated technology (BDT).
The current standards for steam generating units are contained in the NSPS for electric utility steam generating units (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). Previous standards that continue to apply to owners/operators of existing affected facilities, but which have been superseded for owner/operators of new affected facilities, are contained in the NSPS for fossil-fuel-fired steam generating units for which construction was commenced after August 17, 1971, but on or before September 18, 1978 (40 CFR part 60, subpart D).
On February 27, 2006, EPA promulgated amendments to the NSPS for EGUs (40 CFR part 60, subpart Da) which established new standards for PM, SO
The emission standards established by the 2006 final rule, which are more stringent than the standards in effect prior to the adoption of the amendments, remain in effect and will continue to apply to affected facilities for which construction was commenced after February 28, 2005, but before May 4, 2011. Following careful consideration of all of the relevant factors, EPA is proposing to establish amended standards for PM, SO
In terms of the timing of our response to the remand, we consider it appropriate to propose revisions to the NSPS in conjunction with proposing the EGU NESHAP. There are some commonalities among the controls needed to comply with the requirements of the two rules and syncing the two rules so that they apply to the same set of new sources will allow owners/operators of those sources to better plan to comply with both sets of requirements. Therefore, we are proposing these revisions in conjunction with proposing the NESHAP, and intend to finalize both rules simultaneously.
As explained in more detail below and in the technical support documents, we have concluded that the proposed PM, SO
Under the existing NSPS, BDT for an owner/operator of a new affected facility is a FF for control of filterable PM and an FGD for control of SO
EPA disagrees with the petitioners claim that the NSPS should be based on the performance of IGCC units. The NSPS is a national standard and IGCC is not appropriate in every situation. Although IGCC units have many advantages, technology choice is based on several factors, including the goals and objectives of the owner or operator constructing a facility, the intended purpose or function of the facility, and the characteristic of the particular site. In addition, the emissions benefits resulting from reduced emissions of criteria pollutants are not sufficient in all instances to justify the higher capital costs of today's IGCC units if IGCC is selected as BDT in establishing a national standard. The emissions benefits may, however, be sufficient to justify the use of IGCC in an individual case, after considering cost and other relevant factors, including those described above.
On January 28, 2009, EPA promulgated amendments separate from the above mentioned amendments to the NSPS for EGUs (40 CFR part 60, subpart Da, 74 FR 5,072). The Utility Air Regulatory Group (UARG) subsequently requested reconsideration of that rulemaking and EPA granted that reconsideration. Specific issues raised by UARG included the opacity monitoring requirements for owners/operators of affected facilities subject to an opacity standard that are not required to install a continuous opacity monitoring system (COMS). Another issue raised by UARG was the opacity standard for owners/operators of affected facilities subject to 40 CFR part 60, subpart D. We are requesting comments on both of these issues in this rulemaking.
The proposed amendments would amend the emission limits for PM, SO
We are proposing to amend the PM, SO
We are proposing an SO
We are co-proposing two options for an amended NO
In addition to proposing revised emission standards, we are also proposing to amend the way an owner/operator of an affected facility would calculate compliance with the proposed standards. Under the existing NSPS, averages are calculated as the arithmetic average of the non out-of-control hourly emissions rates (
We are proposing several amendments that would exempt owners/operators from certain of the proposed amendments. First, we are proposing that owners/operators of innovative emerging technologies that apply for and are granted a commercial demonstration permit by the Administrator for an affected facility that uses a pressurized fluidized bed, a multi-pollutant emissions control system, or advanced combustion controls be exempt from the proposed
A complete list of the corrections and technical amendments and corrections is available in the docket in the form of a redline/strikeout version of the existing regulatory language. These additional amendments are being proposed to clarify the intent of the current requirements, correct inaccuracies, and correct oversights in previous versions that were promulgated. The additional significant amendments are as follows.
We are proposing several definitional changes. First, to provide additional flexibility and recognize the environmental benefit of efficient production of electricity we are proposing to expand the definition of the affected facility under 40 CFR part 60, subpart Da, to include integrated CTs and fuel cells. Second, because petroleum coke is increasingly being burned in EGUs selling over 25 MW of electric output, we are proposing to amend the definition of petroleum to include petroleum coke. Next, to minimize permitting and compliance burdens and avoid situations where an IGCC facility switches between different NSPS (40 CFR part 60, subparts KKKK and Da), we are proposing to amend the definition of an IGCC facility to allow the Administrator to exempt owners/operators from the 50 percent solid-derived fuel requirement during construction and repair of the gasifier. Owners/operators of IGCC units might install and operate the stationary CT prior to completion of the gasification system. Under the existing standards, an owner/operator doing this would first be subject to 40 CFR part 60, subpart KKKK, and applicability would switch once the gasification system is completed. This outcome would not result in any additional reduction in emissions. The proposed change would thus reduce regulatory burden without decreasing environmental protection. Finally, both biodiesel and kerosene have combustion characteristics similar to those of distillate oil. Therefore, we are proposing to expand the definition of distillate oil in 40 CFR part 60, subparts Db and Dc, to include both biodiesel and kerosene such that units burning any of these fuels, either separately or in combination would be subject to the same requirements.
Additional proposed amendments include deleting vacated provisions and additional harmonization across the various steam generating unit NSPS. As explained above, CAMR was vacated by the DC Circuit Court in 2008. As a result, the provisions added to 40 CFR part 60, subpart Da, by CAMR are no longer enforceable. Therefore, we are proposing to delete the provisions in 40 CFR part 60, subpart Da, that reference Hg standards and Hg testing and monitoring provisions. In addition, existing 40 CFR part 60, subpart HHHH (Emission Guidelines and Compliance Times for Coal-Fired Electric Steam Generating Units), which was promulgated as part of CAMR, and was, therefore, also vacated by the court's decision, will be removed and that subpart will be deleted. We are proposing to harmonize all of the steam generating unit NSPS by adding BLDS and ESP parameter monitoring systems as alternatives to the requirement to install a COMS in all the subparts (40 CFR part 60, subparts D, Da, Db, and Dc). We are also proposing to change the date by which owners/operators of affected facilities subject to all of the steam generating unit NSPS are to begin submitting performance test data electronically from July 1, 2011, to January 1, 2012.
The proposed new emission standards for EGUs would apply only to affected sources that begin construction, modification, or reconstruction after May 3, 2011. Based on our review of emission data and control technology information applicable to criteria pollutants, we have concluded that amendments of the PM, SO
The fuel and technology neutral approach provides a single emission limit for steam generating units based on the application of BDT without regard to the specific type of steam generating equipment or fuel being used. We have concluded that this approach provides owners/operators of affected facilities an incentive to carefully consider fuel use, boiler type, and control technology in planning for new units so as to use the most effective combination of add-on control technologies, clean fuels, and boiler design based on the circumstances to meet the emission standards.
To develop a fuel- and technology-neutral emission limit, we first analyzed data on emission control performance from coal-fired units to establish an emission level that represents BDT for units burning coal. We adopted this approach because the higher sulfur, nitrogen, and ash contents for coal compared to oil or gas makes application of BDT to coal-fired units more complex than application of BDT to either oil- or gas-fired units. Because of these complexities, emission levels selected for coal-fired steam generating units using BDT would also be achievable by oil- and gas-fired EGUs. Thus, we are proposing that the
Where feasible, we are proposing output-based (gross basis) standards in furtherance of pollution prevention which has long been one of our highest priorities. In the current context, maximizing the efficiency of energy generation represents a key opportunity to further pollution prevention. An output-based format establishes emission standards that encourage unit efficiency by relating emissions to the amount of useful-energy generated, not the amount of fuel burned. By relating emission limitations to the productive output of the process, output-based emission standards encourage energy efficiency because any increase in overall energy efficiency results in a lower emissions rate. Output-based standards provide owners/operators of regulated sources with an additional compliance option (
The general provisions in 40 CFR part 60 provide that “emissions in excess of the level of the applicable emissions limit during periods of startup, shutdown, and malfunction (shall not be) considered a violation of the applicable emission limit unless otherwise specified in the applicable standard.” 40 CFR 60.8(c). EPA is proposing standards in this rule that apply at all times, including during periods of startup or shutdown, and periods of malfunction. In proposing the standards in this rule, EPA has taken into account startup and shutdown periods and, for the reasons explained below, has not proposed different standards for those periods.
To establish the proposed output-based SO
If any persons believe that our conclusion is incorrect, or that we have failed to consider any relevant information on this point, we encourage them to submit comments. In particular, we note that the general provisions in 40 CFR part 60 require facilities to keep records of the occurrence and duration of any startup, shutdown or malfunction (40 CFR 60.7(b)) and either report to EPA any period of excess emissions that occurs during periods of startup, shutdown, or malfunction (40 CFR 60.7(c)(2)) or report that no excess emissions occurred (40 CFR 60.7(c)(4)). Thus, any comments that contend that sources cannot meet the proposed standard during startup and shutdown periods should provide data and other specifics supporting their claim.
In developing the proposed 30-day SO
Particulate matter and CO data are not reported to CAMD and instead were collected as part of the 2010 ICR. Total PM testing was reported as part of the 2010 ICR and those data were used in both rulemakings. As part of the 2010 ICR, owners/operators reported CO performance test data and whether or not they have a CO CEMS installed on their facility. We requested CO CEMS data from multiple units to compare the relationship between NO
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 60.2.) EPA has determined that malfunctions should not be viewed as a distinct operating mode and, therefore, any emissions that occur at such times do not need to be factored into development of CAA section 111 standards. Further, nothing in CAA section 111 or in case law requires that EPA anticipate and account for the innumerable types of potential malfunction events in setting emission standards.
Further, it is reasonable to interpret CAA section 111 as not requiring EPA to account for malfunctions in setting emissions standards. For example, we note that section 111 provides that EPA set standards of performance which reflect the degree of emission limitation achievable through “the application of the best system of emission reduction” that EPA determines is adequately demonstrated. Applying the concept of “the application of the best system of emission reduction” to periods during which a source is malfunctioning
Moreover, even if malfunctions were considered a distinct operating mode, we believe it would be impracticable to take malfunctions into account in setting CAA section 111 standards for EGUs under 40 CFR part 60, subpart Da. As noted above, by definition, malfunctions are sudden and unexpected events and it would be difficult to set a standard that takes into account the myriad different types of malfunctions that can occur across all sources in the category. Moreover, malfunctions can vary in frequency, degree, and duration, further complicating standard setting.
In the event that a source fails to comply with the applicable CAA section 111 standards as a result of a malfunction event, EPA would determine an appropriate response based on, among other things, the good faith efforts of the source to minimize emissions during malfunction periods, including preventative and corrective actions, as well as root cause analyses to ascertain and rectify excess emissions. EPA would also consider whether the source's failure to comply with the CAA section 111 standard was, in fact, “sudden, infrequent, not reasonably preventable” and was not instead “caused in part by poor maintenance or careless operation.” 40 CFR 60.2 (definition of malfunction).
Finally, EPA recognizes that even equipment that is properly designed and maintained can sometimes fail. Such failure can sometimes cause an exceedance of the relevant emission standard. (
Controls for filterable PM are well established. Either an ESP or FF can control both coarse and fine filterable PM. However, controls for condensable PM are less developed. Condensable PM from a coal-fired boiler is composed primarily of SO
A number of SO
To assess the SO
With the exception of the HL Spurlock 3 and 4 units all of the listed units use wet limestone-based scrubbers. HL Spurlock 3 and 4 are FBC boilers that remove the majority of SO
To determine an appropriate alternate numerical standard, we evaluated the performance of several recently constructed units in addition to the numerical standards for the units in Table 17 of this preamble. Table 18 of this preamble shows the maximum 30-day average SO
The HL Spurlock 3 unit is the only new unit that burns high sulfur coal and that unit could meet the proposed alternate percent reduction standard. However, it would not be expected to achieve a numerical standard based on the performance of the other units. Further, with the exception of the Cross 3 and 4 units, which burn medium sulfur bituminous coals, the remaining units burn lower-sulfur subbituminous coals. To provide the maximum emissions reduction, we further concluded that the alternate numerical standard should be as stringent as the numerical rates achieved by the units used to determine the percent reduction standard. If the alternate numerical standard were less stringent than the emissions rate achieved by the units used to determine the maximum percent reduction, those units would not be required to achieve the maximum percent reduction that has been demonstrated. In addition, the numerical standard should account for variability in today's SO
Based on the performance of the spray dryer at the Springerville TS3 unit, the numerical standard would provide sufficient flexibility such that an owner/operator of an EGU could burn over 90 percent of the subbituminous coals presently being used in combination with a spray dryer. This technology choice provides owners/operators the flexibility to minimize water use and associated waste water discharge, as well as reducing additional CO
Coal refuse (also called waste coal) is a combustible material containing a significant amount of coal that is reclaimed from refuse piles remaining at the sites of past or abandoned coal mining operations. Coal refuse piles are an environmental concern because of acid seepage and leachate production, spontaneous combustion, and low soil fertility. Units that burn coal refuse provide multimedia environmental benefits by combining the production of energy with the removal of coal refuse piles and by reclaiming land for productive use. Consequently, because of the unique environmental benefits that coal refuse-fired EGUs provide, these units warrant special consideration so as to prevent the amended NSPS from discouraging the construction of future coal refuse-fired EGUs in the U.S.
Coal refuse from some piles has sulfur contents at such high levels that they present potential economic and technical difficulties in achieving the same SO
We are proposing to maintain the existing SO
In the 2006 final NSPS amendments (71 FR 9866), EPA concluded that advanced combustion controls were BDT. However, upon further review we have concluded this was not appropriate. Although select existing PC EGUs burning subbituminous coals have been able to achieve annual NO
After re-evaluating the performance, costs, and other environmental impacts of adding SCR in addition to combustion controls, we have concluded that combustion controls in combination with SCR represents BDT for continuous reduction of NO
To assess the NO
All of the units listed in Table 19 of this preamble have demonstrated 0.70 lb/MWh is achievable. Even though some units are achieving a lower emissions rate, the majority of units listed in Table 19 of this preamble have less than a year of operating data. Proposing a more stringent standard might not provide sufficient compliance margin to account for expected variability in the long term performance of NO
Combustion optimization for overall environmental performance is a balance between boiler efficiency, NO
The proposed BDT for NO
In addition, an overly stringent NO
To assess the combined NO
Because CO has not historically been a primary pollutant of concern for owners/operators of EGUs, it has not necessarily been a significant factor when selecting combustion control strategies and has not typically been continuously monitored. Due to the limited availability of CO CEMS data and to account for potential variability we are not aware of, we have concluded it is appropriate in this case to propose a standard with sufficient compliance margin to not inhibit the ability of owner/operators of EGUs to comply with NO
Another potential GHG benefit, beyond boiler efficiency, of a combined NO
The commercial demonstration permit section of the EGU NSPS was included in the original rulemaking in 1979 (44 FR 33580) to assure that the NSPS did not discourage the development of new and promising technologies. In the 1979 rule, the Administrator recognized that the innovative technology waiver provisions under CAA section 111(j) are not adequate to encourage certain capital intensive technologies. (44 FR 33580.) Under the innovative technology provisions, the Administrator may grant waivers for a period of up to 7 years from the date of issuance of a waiver or up to 4 years from the start of operation of a facility, whichever is less. The Administrator recognized that this time frame is not sufficient for amortization of high-capital-cost technologies. The commercial demonstration permit section established less stringent requirements for initial full-scale demonstration plants that received a permit in order to mitigate the potential impact of the rule on emerging technologies and insure that standards did not preclude the development of such technologies.
The authority to issue these permits was predicated on the DC Circuit Court's opinion in
To mitigate the potential impact on emerging technologies, EPA is proposing to maintain similar standards to those finalized in 2006 for demonstration plants using innovative technologies. This should insure that the amended standards do not preclude the development of new technologies and should compensate for problems that may arise when applying them to commercial-scale units. Under the proposal, the Administrator (in consultation with DOE) would issue commercial demonstration permits for the first 1,000 MW of full-scale demonstration units of pressurized fluidized bed technology and EGUs using a multi-pollutant pollution control technology. Owners/operators of these units that are granted a commercial demonstration permit would be exempt from the amended standards and would instead be subject to less stringent emission standards. The proposed commercial demonstration permit standards for SO
The reason we selected these particular technologies is as follows. Multi-pollutant controls (
Because filterable PM emissions are generally negligible for boilers burning natural gas or low sulfur oil, eliminating the PM standard for owners/operators of natural gas and low sulfur oil-fired EGUs would both help harmonize the various steam generating unit NSPS and lower the compliance burden without increasing emissions. Similarly, eliminating the opacity standard for owners/operators of natural gas-fired EGUs would reduce testing and monitoring requirements that do not result in any emissions benefit.
As municipal solid waste (MSW) combustors and CISWI units increase in size it is possible that they could generate sufficient electricity to become subject to the EGU NSPS. We have concluded that it is more appropriate to regulate these units under the CAA section 129 regulations and are, therefore, proposing to exempt owners/operators of affected facilities subject to the standards of performance for large MSW combustors (40 CFR part 60, subpart Eb) and CISWI (40 CFR part 60, subpart CCCC) from complying with the otherwise applicable standards for pollutants that those subparts address. The PM, SO
Similarly, in the final 2007 steam generating unit amendments (72 FR 32,710) we inadvertently expanded the applicability of 40 CFR part 60, subpart Db, to include industrial boilers combusting black liquor and distillate oil at Kraft pulp mills. Even though the distillate oil is generally low sulfur and would otherwise be exempt from the PM standards in 40 CFR part 60, subpart Db, the boilers use ESPs and the addition of “not using a post-combustion technology (except a wet scrubber) to reduce SO
We are also proposing to exempt owners/operators of IBs that meet the applicability requirements and that are complying with the SO
The present definition of a steam generating unit under 40 CFR part 60, subpart Da, starts at the coal bunkers and ends at the stack breeching. It includes the fuel combustion system (including bunker, coal pulverizer, crusher, stoker, and fuel burners, as applicable), the combustion air system, the steam generating system (firebox, boiler tubes,
The proposed rule revision to include integrated CTs and/or fuel cells in the definition of a steam generating unit would increase compliance flexibility and decrease costs. Although we are not aware of any EGUs that have presently integrated either device, using exhaust heat for reheating or preheating boiler feedwater, preheating combustion air, or using the exhaust directly in the boiler to generate steam has high theoretical incremental efficiencies. In addition, using exhaust heat to reheat boiler feedwater would minimize the steam otherwise extracted from the steam turbine used for the reheating process and increase the theoretical electric output for an equivalent sized boiler. Because the exhaust from either an integrated CT or fuel cell would likely not be exhausted through the primary boiler stack, we are requesting comment on the appropriate emissions monitoring for these separate stacks. Because these emissions would likely be relatively small compared to the boiler, we are considering allowing emissions to be estimated using procedures that are similar to those used in the acid rain trading programs as an alternative to an NO
We are requesting comment on whether petroleum coke should be added to the definition of coal instead of petroleum. Both 40 CFR part 60, subparts Db and Dc, the large and small IB NSPS, include petroleum coke under the definition of coal. Including petroleum coke under coal would be consistent with the IB NSPS. However, the proposed emission standards are fuel neutral and because the revised definition would only apply to affected facilities that begin construction, modification, or reconstruction after the proposal date the impact on the regulated community would be the same if we added petroleum coke to the definition of coal as it would if we added it to the definition of petroleum.
We request comments on all aspects of the proposed amendments. All significant comments received will be considered in the development and selection of the final amendments. We specifically solicit comments on additional amendments that are under consideration. These potential amendments are described below.
In addition to recognizing the environmental benefit of minimizing the internal parasitic energy demand generally, net output based standards would serve to further recognize the environmental benefits of the use of supercritical steam conditions because parasitic loads tend to be lower for units using supercritical steam conditions compared to subcritical steam conditions. Furthermore, although the gross efficiencies of IGCC units are projected to be several percentage points higher than a comparable PC facility using supercritical steam conditions, the parasitic energy demands at IGCC units are expected to be much higher at approximately 15 percent. Consequently, on a net output basis, the
In general, the level of filterable PM emissions and the resultant opacity from oil-fired steam generating units is a function of the completeness of fuel combustion as well as the ash content in the oil. Distillate oil contains negligible ash content, so the filterable PM emissions and opacity from distillate oil-fired steam generating units are primarily comprised of carbon particles resulting from incomplete combustion of the oil. Naturally low sulfur crude oil and desulfurized oils are higher quality fuels and exhibit lower viscosity and reduced asphaltene, ash, and sulfur content, which result in better atomization and improved overall combustion properties. To provide additional flexibility and decrease the compliance burden on affected facilities, we are requesting comment on whether the opacity standard should be eliminated for owners/operators of affected facilities burning ultra low sulfur (
We are also requesting comment on amending the opacity requirements for owners/operators of affected facilities using PM CEMS, but not complying with the PM standard under 40 CFR part 60, subpart Da. Owners/operators of these facilities are subject to an opacity standard and are required to periodically monitor opacity. We are requesting comment on the appropriateness of waiving all opacity monitoring for owners/operators of these affected facilities. In addition, we are also requesting comment on allowing owners/operators of 40 CFR part 60, subpart D, affected facilities that opt to comply with the 40 CFR part 60, subpart Da, PM standard and qualify for the corresponding opacity exemption to opt back out. (Under the existing rule, once a 40 CFR part 60, subpart D, affected facility opts to comply with the 40 CFR part 60, subpart Da, PM standard in order to qualify for the corresponding opacity exemption, it cannot subsequently opt to go back to complying with the 40 CFR part 60, subpart D, PM standard.) Finally, we are requesting comment on the appropriateness of eliminating the opacity standard for owners/operators of 40 CFR part 60, subpart D, affected facilities using PM CEMS even if they are not complying with the 40 CFR part 60, subpart Da, PM standard. Consistent with paragraph 40 CFR 60.11(e), as long as these facilities demonstrate continuous compliance with the applicable PM standard on a 3-hour average, the opacity standard would not apply.
In addition, we are requesting comment on eliminating the opacity standard for owners/operators of affected facilities complying with a total PM standard of 15 ng/J (0.034 lb/MMBtu) or less that use control equipment parameter monitoring or some other continuous monitoring approach to demonstrate compliance with that standard. Based on the PM performance test data collected as part of the 2010 ICR, at this total PM emissions rate the filterable portion is expected to be significantly lower than the original 40 CFR part 60, subpart Da, filterable PM standard, 0.030 lb/MMBtu. As described in the 2006 NSPS amendments, at filterable PM emissions at this level, opacity is less useful and eliminating the standards would simplify compliance without decreasing environmental protection.
The 1990 CAA amendments removed the requirement that standards be based on a percent reduction. The percent reduction requirements for NO
The IB NSPS currently does not credit fuel pretreatment toward compliance with the SO
The large IB NSPS (40 CFR part 60, subpart Db) currently includes regulatory language for standards for boilers burning MSW. This language was included to assure the broad applicability of 40 CFR part 60, subpart Db. However, subsequent to the original promulgation of 40 CFR part 60, subpart Db, EPA promulgated specific standards for MWCs and exempted owners/operators of MWCs from 40 CFR part 60, subpart Db. We are requesting comment on deleting all references to MSW in 40 CFR part 60, subpart Db. This would simplify compliance and readability of the rule without increasing emissions to the environment. Owners/operators of these units would still be subject to emission standards under 40 CFR part 60, subpart Db, if they stop burning MSW.
In setting the standards, the CAA requires us to consider alternative emission control approaches, taking into account the estimated costs and benefits, as well as the energy, solid waste and other effects. EPA requests comment on whether it has identified the appropriate alternatives and whether the proposed standards adequately take into consideration the incremental effects in terms of emission reductions, energy and other effects of these alternatives. EPA will consider the available information in developing the final rule.
The costs, environmental, energy, and economic impacts are typically expressed as incremental differences between the impacts on owners/operators of units complying with the proposed amendments relative to complying with the current NSPS emission standards (
To establish the regulatory baseline for NO
Although multiple coal-fired EGUs have recently commenced operation and several are currently under construction, no new coal-fired EGUs have commenced construction in either 2009 or 2010. In addition, forecasts of new generation capacity from both the EIA and the Edison Electric Institute do not project any new coal-fired EGUs being constructed in the short term. This is an indication that, in the near term, few new coal-fired EGUs will be subject to the NSPS amendments. Because the use of natural gas in boiler/
Therefore, we are not projecting that any new, reconstructed, or modified steam generating units would become subject to the proposed amendments over the next 5 years. Even though we are not projecting any impacts from the proposed amendments, in the event a new steam generating units does become subject the proposed amendments we have concluded that the proposed amendments would be appropriate. For more information on these impacts, please refer to the economic impact analysis and technical support documents in the public docket.
Under the proposed Toxics Rule, EPA projects annual HCl emissions reductions of 91 percent in 2015, Hg emissions reductions of 79 percent in 2015, and PM
Under the provisions of this proposed rule, EPA projects that approximately 9.9 GW of coal-fired generation (roughly 3 percent of all coal-fired capacity and 1% of total generation capacity in 2015) may be removed from operation by 2015. These units are predominantly smaller and less frequently used generating units dispersed throughout the area affected by the rule. 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 keep these units operational.
EPA also projects fuel price increases resulting from the proposed Toxics Rule. Average retail electricity prices are shown to increase in the continental U.S. by 3.7 percent in 2015. This is generally less of an increase than often occurs with fluctuating fuel prices and other market factors. Related to this, the average delivered coal price increases by less than 1 percent in 2015 as a result of shifts within and across coal types. EPA also projects that electric power sector-delivered natural gas prices will increase by about 1 percent over the 2015-2030 timeframe and that natural gas use for electricity generation will increase by about less than 300 billion cubic feet (BCF) over that horizon. 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 20 million tons in 2015 from base case levels, which is less than 2 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 proposed Toxics Rule HAP emission standards. In simple terms, these costs are the resource costs of what the power industry will directly expend to comply with EPA's requirements.
EPA projects that the annual incremental compliance cost of the proposed Toxics Rule is $10.9 billion in 2015 ($2007). The annualized incremental cost is the projected additional cost of complying with the proposed 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.
End-use energy efficiency can be an important part of a compliance strategy for this regulation. It can reduce the cost of compliance, lower consumer costs, reduce emissions, and help to ensure reliability of the U.S. power system. Policies to promote end-use energy efficiency are largely outside of EPA's direct control. However this rule can provide an incentive for action to promote energy efficiency. To examine the potential impacts of Federal and state energy efficiency policies, EPA used the Integrated Planning Model (IPM).
An illustrative Energy Efficiency Scenario was developed and run as a sensitivity for both the Base Case and the Toxics Rule Case. The illustrative Energy Efficiency Case assumed adoption of two key energy efficiency policies. First, it assumed that states adopted rate-payer funded energy efficiency programs, such as energy efficiency resource standards, integrated resource planning and demand side management plans. Examples of energy efficiency programs that might be driven by these policies include rebate programs for efficient products and state programs to provide technical assistance and information for energy efficient home retrofits. The electricity demand reduction that could be gained from these programs was taken from work done by Lawrence Berkley National Laboratory (LBNL).
As shown, these policies are estimated to result in a moderate reduction in U.S. electricity demand climbing to over five percent by 2020 and averaging over five percent from 2020 to 2050. These reductions lower annual average electricity demand growth (from 2009 historic data) through 2020 relative to the reference forecast from 1.04 percent to 0.55 percent.
The effects of the Energy Efficiency Scenario on the projected total electricity generating costs of the power sector are shown below in Table 23. In this table we see the projected costs in the Base and Toxics Rule Cases with and without energy efficiency.
In this analysis, the costs of the energy efficiency policies are treated as a component of the cost of generating electricity and are imbedded in the costs seen in Table 23. The modeling estimated that these energy efficiency policies would reduce the total cost of implementing the rule by billions of dollars. EPA looked at a case in which these energy efficiency policies were in place with and without the Toxics Rule. As Table 23 shows, with or without the Toxics Rule, energy efficiency policies reduce the overall costs to generate electricity. The cost reductions increase over time. When comparing the Toxics Rule Case without energy efficiency to the Toxics Rule Case with energy efficiency, the analysis shows that these energy efficiency policies could reduce overall system costs by $2 billion in 2015, $6 billion in 2020, and $11 billion in 2030.
The energy savings driven by these energy efficiency policies, and corresponding lower levels of demand, translate into reductions in electricity prices. EPA's modeling shows that the Toxics Rule increases retail prices by 3.7 percent, 2.6 percent and 1.9 percent in 2015, 2020 and 2030, respectively, relative to the base case. If energy efficiency policies are implemented, the price increase would be smaller in 2015 when retail prices would increase by 3.3 percent. In 2020 and 2030 the reduced demand for electricity is sufficient to reduce the retail price of electricity relative to the Base Case even with the Toxics Rule. If the Toxics Rule is implemented with energy efficiency, retail electricity prices decrease by about 1.6 percent in 2020 and by about 2.3 percent in 2030 relative to the Base.
In the Energy Efficiency Cases, IPM projects considerably more plant retirements than in the Base and Policy Cases. The Base Case with Energy Efficiency in 2020 shows twice as much capacity retiring, and more than double the capacity of coal plant retirements as the Base Case without energy efficiency. The Toxics Rule would increase the amount of capacity retired over the Base Case by 8 GW. If the energy efficiency policies were imposed as the power sector was taking action to come into compliance, the effect of the Toxics Rule on plant retirements would be greater with an additional 25 GW of
In effect, the timely adoption and implementation of energy efficiency policies would augment currently projected reserve capacities that are instrumental to assuring system reliability.
The addition of energy efficiency policies during and beyond the Toxics Rule compliance period can result in very modest reductions in air emissions. This is largely due to lower levels of electricity generation. As a result, with energy efficiency policies the Toxics Rule would achieve reductions of approximately an additional 520 pounds of Hg emissions, an additional 80,000 tons of SO
Although EPA cannot mandate energy efficiency policies, the positive effects of these policies on the cost of rule to industry and consumers could be a strong incentive to undertake them as a part of an overall compliance strategy.
Table 25 presents estimated breakouts of the cost of reducing certain key pollutants under the Toxics Rule. Because many of the strategies to reduce pollutants are multi-pollutant in nature, it is not possible to create a technology-specific breakout of costs (
For this proposed rule, EPA analyzed the costs using IPM. 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
EPA also included an analysis of impacts of the proposed rule to industries outside of the electric power sector by using the Multi-Market Model. This model is a partial equilibrium model that includes 100 sectors that cover energy, manufacturing, and service applications and is designed to capture the short-run effects associated with an environmental regulation. It was used to estimate economic impacts for the recently promulgated Industrial Boiler major and area source standards and CISWI standard.
We use the Multi-Market model to estimate the social cost of the proposed rule. Using this model, we estimate the social costs of the proposal to be $10.9 billion (2007$), which is almost identical to the compliance costs. The usefulness of a Multi-Market model in predicting the estimated effects is limited because the electric power sector affects all sectors of the economy. For the final rule, we will be refining the social cost estimates with general equilibrium models, including an assessment with our upgraded CGE model, EMPAX. Commenters are encouraged to provide other general equilibrium model platforms and to provide other information to refine the social cost assessments for the final rule.
EPA also 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. Such an analysis is of particular concern in the current economic climate as sustained periods of excess unemployment may introduce a wedge between observed (market) wages and the social cost of labor. In such conditions, 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 proposed rule). For that reason, EPA also includes estimates of job impacts associated with the proposed rule. EPA presents an estimate of short-term employment opportunities as a result of increased demand for pollution control equipment. Overall, the results suggest that the proposed rule could support a net of roughly 31,000 job-years
The basic approach to estimate these employment impacts involved using projections from IPM from the proposed rule analysis such as the amount of capacity that will be retrofit with control technologies, for various energy market implications, along with data on labor and resource needs of new pollution controls and labor productivity from secondary sources, to estimate employment impacts for 2015. For more information, please refer to the TSD for this analysis, “Employment Estimates of Direct Labor in Response to the Proposed Toxics Rule in 2015.”
EPA relied to 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 (
Using plant-level Census information between the years 1979 and 1991, Morgenstern,
The ranges of job effects calculated using the Morgenstern,
EPA recognizes there may be other job effects which are not considered in the Morgenstern,
We estimate the monetized benefits of this proposed regulatory action to be $59 billion to $140 billion (2007$, 3 percent discount rate) in 2016. The monetized benefits of the proposed regulatory action at a 7 percent discount rate are $53 billion to $130 billion (2007$). These estimates reflect the economic value of the Hg benefits as well as the PM
Using alternate relationships between PM
These benefits estimates represent the total monetized human health benefits for populations exposed to less PM
To generate the benefit-per-ton estimates, we used a model to convert emissions of PM
For context, it is important to note that the magnitude of the PM benefits is largely driven by the concentration response function for premature mortality. Experts have advised EPA to consider a variety of assumptions, including estimates based both on empirical (epidemiological) studies and judgments elicited from scientific experts, to characterize the uncertainty in the relationship between PM
This analysis does not include the type of detailed uncertainty assessment found in the 2006 PM
It should be emphasized that the monetized benefits estimates provided above do not include benefits from several important benefit categories, including reducing other air pollutants, ecosystem effects, and visibility impairment. The benefits from reducing various HAP have not been monetized in this analysis, including reducing 68,000 tons of HCl, and 3,200 tons of other metals each year. Although we do not have sufficient information or modeling available to provide monetized estimates for this rulemaking, we include a qualitative assessment of the health effects of these air pollutants in the RIA for this proposed rule, which is available in the docket.
For more information on the benefits and cost analysis, please refer to the RIA for this rulemaking, which is available in the docket.
We request comment on all aspects of this proposed rule.
During this rulemaking, we conducted outreach to small entities and convened a SBAR Panel to obtain advice and recommendation of representatives of the small entities that potentially would be subject to the requirements of this proposed rule. As part of the SBAR Panel process we conducted outreach with representatives from various small entities that would be affected by this proposed rule. We met with these SERs to discuss the potential rulemaking approaches and potential options to decrease the impact of the rulemaking on their industries/sectors. We distributed outreach materials to the SERs; these materials included background, project history, CAA section 112 overview, constraints on rulemaking, affected facilities, data, rulemaking options under consideration, potential control technologies and estimated costs, applicable small entity definitions, small entities potentially subject to regulation, and questions for SERs. We met with SERs that will be impacted directly by this proposed rule to discuss the outreach materials and receive feedback on the approaches and alternatives detailed in the outreach packet. The Panel received written comments from the SERs following the meeting in response to discussions at the meeting and the questions posed to the SERs by the Agency. The SERs were specifically asked to provide comment on regulatory alternatives that could help to minimize the rule's impact on small businesses. (See elsewhere in this preamble for further information regarding the SBAR process.)
EPA consulted with state and local officials in the process of developing the proposed action to permit them to have meaningful and timely input into its development. EPA met with 10 national organizations representing state and local elected officials to provide general background on the proposal, answer questions, and solicit input from state/local governments. EPA also consulted with tribal officials early in the process of developing this proposed rule to permit them to have meaningful and timely input into its development. Consultation letters were sent to 584 tribal leaders. The letters provided information regarding EPA's development of NESHAP for EGUs and offered consultation. Three consultation meetings were requested and held. The Unfunded Mandates Reform Act (UMRA) discussion in this preamble includes a description of the consultation. (See elsewhere in this preamble for further information regarding these consultations with state, local, and tribal officials.)
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, EPA submitted this action to the OMB for review under EO 12866 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 28 of this preamble.
When estimating the human health benefits and compliance costs in Table 28 of this preamble, EPA applied methods and assumptions consistent with the state-of-the-science for human health impact assessment, economics and air quality analysis. 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
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 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 section 316(b) of the CWA. They will also soon be the subject of a rulemaking under CAA section 111 concerning emissions of GHG. In developing today's proposed rule, EPA recognizes that it needs to endeavor 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.
In this section, we provide a qualitative description of human health and environmental effects due to exposure to MeHg. In 2000, the NAS Study was issued which provides a thorough review of the effects of MeHg on human health (NRC, 2000). Many of the peer-reviewed articles cited in this section are publications originally cited in the MeHg Study. In addition, EPA has conducted literature searches to obtain other related and more recent publications to complement the material summarized by the NRC in 2000.
In 1995, EPA set a health-based ingestion rate for chronic oral exposure to MeHg, termed an oral RfD, at 0.0001 mg/kg-day. The RfD was based on effects reported to children exposed
The RfD is an estimate (with uncertainty spanning perhaps an order of magnitude) of a daily exposure to the human population (including sensitive subgroups) that is likely to be without an appreciable risk of deleterious effects during a lifetime (EPA, 2002). Data published since 2001, development of risk assessment methods, and continued examination of the concepts underlying benchmark doses and RfDs based on them add to EPA's interpretation of the 2001 MeHg RfD in the current rulemaking. Additional information on EPA's interpretation can be found in Section X of the Appropriate & Necessary TSD.
In their review of the literature, the NRC found neurodevelopmental effects to be the most sensitive endpoints and appropriate for establishing an RfD (NRC, 2000). Studies involving animals found sensory effects and support the conclusions reached by studies involving human subjects, with a similar range of neurodevelopmental effects reported (NRC, 2000). As noted by the NRC, the clinical significance of some of the more subtle endpoints included in the human low-dose studies is difficult to gauge due to the quantal nature of the effects observed (
Little is known about the effects of low-level chronic MeHg exposure in children that can be linked to exposures after birth. The difficulty in identifying a cohort exposed after birth but not prenatally, or separating prenatal from postnatal effects, makes research on the topic complicated. These challenges were present in the three large epidemiologic studies used to derive the RfD, as in all three studies there was postnatal exposure as well.
Several studies have shown neurological effects including delayed peak latencies in brainstem auditory evoked potentials are associated with prenatal or recent MeHg exposures (Debes, et al., 2006; Grandjean, et al., 1997; Murata,
Several studies have also examined the effects of chronic low-dose MeHg exposures on adult neurological and sensory functions (
A number of epidemiological and toxicological studies have evaluated the relationship between MeHg exposures and various cardiovascular effects including acute myocardial infarction (AMI), oxidative stress, atherosclerosis, decreased heart rate variability (HRV), and hypertension. An AMI (
These epidemiological studies evaluated Hg exposures using various measures (including Hg or MeHg in blood, cord blood, hair and toenails) and the associations of these exposures with various effects. The overall results of the available studies (published before and after NRC 2000) are summarized in the following paragraphs.
Studies in two cohorts (the Kuopio Ischemic Heart Disease Risk Factor study, or KIHD study; and the European Community Multicenter Study on Antioxidants, Myocardial Infarction and Breast Cancer, or EURAMIC study), report statistically significant positive associations between MeHg exposure and AMI. A third study (U.S. Health Professionals Study, USHPS) also reported a positive association between Hg exposure and AMI but only after excluding individuals who may have been occupationally exposed to inorganic Hg. However, a fourth study (the Northern Sweden Health and Disease Study, or NSHDS) reported an inverse relationship between MeHg exposure and AMI, and another study (Minamata Cohort) identified no increase in fatal heart attacks following a MeHg poisoning epidemic.
Although each of these AMI studies had strengths and limitations, the EURAMIC and KIHD studies appear to be most robust. Strengths of these two studies include their large sample sizes and control for key potential confounders (such as exposure to omega-3 fatty acid, which are related to decreases in cardiovascular effects). The KIHD study was well-designed and included a population-based recruitment and limited loss to follow-up. Additional strengths of the EURAMIC study include exposure data that were collected shortly after the AMI. In addition, recruitment of participants across nine countries likely resulted in a wide range of MeHg and fish fatty acid intakes. Although the USHPS study was well-conducted, the Hg exposure measure used was potentially confounded by possible inorganic Hg exposures in roughly half of the study population. When these subjects were excluded from the analyses, the power of the study to detect an effect was reduced. Limitations of the NSHDS study included its relatively small sample size and narrow MeHg exposure range. The Minamata study also had important limitations, primarily that the effects of the very high exposures in this population may differ substantially from effects of lower exposures expected at typical environmental levels; also the death certificates were collected starting 10 years after the initial cases of MeHg poisoning.
In summary, the most robust available studies (
The studies that evaluated intermediary effects generally provide some additional evidence of the potential adverse effects of Hg or MeHg to the cardiovascular system. However, results are somewhat inconsistent. For example, two epidemiological studies (the KIHD and the Tapajós River Basin studies) reported positive associations between MeHg exposures and oxidative stress, but one short-term study (the Quebec Sport Fisherman Study) reported a negative association. For atherosclerosis, the results across epidemiological studies are more consistent. Three studies (the KIHD, Faroese Whaler Cohort Study, and Nunavik Inuit Cohort in Quebec) reported a positive association between MeHg exposure and atherosclerosis. Moreover, animal studies and
Another intermediary effect, decreases in heart rate variability (HRV), can be indicative of cardiovascular disease, particularly in the elderly. Associations of decreased HRV with increased MeHg exposures have been reported in four of five studies of adults and three studies of children; however, the clinical significance of decreased HRV in children is not known.
The existing epidemiological studies are inconsistent in showing an association between MeHg and hypertension. A prospective study of the Faroe Islands birth cohort reported statistically significant associations between elevated cord blood Hg levels or maternal hair Hg levels and increased diastolic and systolic blood pressures for 7-year-old children; this association was no longer seen in the children tested at 14 years. Other studies suggest that these are not correlated.
In January 2010, EPA sponsored a workshop in which a group of experts were asked to assess the plausibility of a causal relationship between MeHg exposure and cardiovascular health effects, and to advise EPA on methodologies for estimating population-level cardiovascular health impacts of reduced MeHg exposure. The final workshop report was published in January, 2011, and includes as its key recommendation the development of a dose-response function relating MeHg exposure and AMI incidence for use in regulatory benefits analyses that target Hg air emissions.
The experts identified both intermediary and clinical effects in the published literature. The panelists assessed the strength of evidence associated with three intermediary effects (
The workshop panel concluded that “a causal link between MeHg and AMI
EPA did not develop a quantitative dose-response assessment or quantified estimates of benefits 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.
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 NRC concluded that evidence that human exposure to MeHg caused 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, et al., 2000) reported a direct relationship between MeHg concentration in hair and DNA damage in lymphocytes,; polyploidal aberrations and chromatid breaks observed at Hg hair levels around 7.25 ppm and 10 ppm, respectively. Long-term MeHg exposures in this population were believed to occur through consumption of fish, suggesting that genotoxic effects (largely chromosomal aberrations) may result from dietary, chronic MeHg exposures similar to and above those seen in the Faroes and Seychelles populations.
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). Some persistent immunotoxic effects have been observed in mice treated with MeHg in drinking water at relatively high levels of exposure (Havarinasab,
Based on limited human and animal data, MeHg is classified as a “possible” human carcinogen by the IARC (1994) and in the IRIS (EPA, 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 (
There is also some evidence of reproductive and renal toxicity in humans from MeHg exposure. For example, a smaller than expected number of pregnancies were observed among women exposed via contaminated wheat in the Iraqi poisoning episode of 1956 (Bakir,
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. In the sections that follow, numerous adverse effects have been identified. Further reducing the presence of Hg in the environment may help to alleviate the potential for adverse ecological health outcomes.
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. Although considered to be fish-eating generally, these wading birds have a very wide diet including crayfish, crabs, snails, insects and frogs. These species are experiencing a range of adverse effects due to exposure to Hg. The white ibis has been observed to have decreased foraging efficiency.
Insectivorous birds have also been shown to suffer adverse effects due to Hg exposure. These 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 on Hg in fur nearly equal or exceed a concentration 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.
The proposed rule will also reduce emissions of directly emitted PM and ozone precursors and estimates of the PM
The cost analysis is also subject to uncertainties. Estimating the cost conversion from one process to another is more difficult than estimating the cost of adding control equipment because it is more dependent on plant specific information. More information on the cost uncertainties can be found in the RIA.
A summary of the monetized benefits and net benefits for the proposed rule at discount rates of 3 percent and 7 percent is in Table 28 of this preamble.
For more information on the benefits analysis, please refer to the RIA for this rulemaking, which is available in the docket.
The information collection requirements in this proposed rule will be submitted for approval to the OMB under the PRA, 44 U.S.C. 3501
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 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 proposed rule would require 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.
The annual monitoring, reporting, and recordkeeping burden for this collection (averaged over the first 3 years after the effective date of the standards) is estimated to be $49.1 million. This includes 329,605 labor hours per year at a total labor cost of $27.0 million per year, and total non-labor capital costs of $22.1 million per year. This estimate includes initial and annual performance test, conducting and documenting a tune-up, semiannual excess emission reports, maintenance inspections, developing a monitoring plan, notifications, and recordkeeping. The total burden for the Federal government (averaged over the first 3 years after the effective date of the standard) is estimated to be 18,039 hours per year at a total labor cost of $877 million per year.
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; train personnel to be able to respond to a collection of information; search data sources; complete and review the collection of information; and transmit or otherwise disclose the information.
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 and 48 CFR chapter 15.
To comment on EPA's need for this information, the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden, including the use of automated collection techniques, EPA has established a public docket for this proposed rule, which includes this ICR, under Docket ID number EPA-HQ-OAR-2009-0234. Submit any comments related to the ICR to EPA and OMB.
The 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 proposed rule on small entities, small entity is defined as (as defined by the Small Business Administration's (SBA) regulations at 13 CFR 121.201): (1) A small business according to SBA size standards by the North American Industry Classification System category of the owning entity (for NAICS 221112 and 221122, the range of small business size standards for electric utilities is 4 million
After considering the economic impacts of this proposed rule on small entities, EPA cannot certify that this action will not have a significant economic impact on a substantial number of small entities. This determination, which is included in the Initial Regulatory Flexibility Analysis (IRFA) found in Chapter 10 of the RIA for this proposed rule, is based on the economic impact of this proposed rule to all affected small entities across the electric power sector.
The summary of the IRFA is as follows. EPA has assessed the potential impact of this action on small entities and found that approximately 102 of the estimated 1,400 EGUs potentially affected by today's proposed rule are owned by the 83 potentially affected small entities identified by EPA's analysis. EPA estimates that 59 of the 83 identified small entities will have annualized costs greater than 1 percent of their revenues.
Because the potential existed for a likely significant impact for substantial number of small entities, 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 this rule.
As required by RFA section 609(b), as amended by SBREFA, EPA has conducted outreach to small entities and on October 27, 2010, EPA's Small Business Advocacy Chairperson convened a Panel under RFA section 609(b). In addition to the Chair, the Panel consisted of the Director of the Sector Policies and Programs Division within EPA's Office of Air and Radiation, the Chief Counsel for Advocacy of SBA, and the Administrator of the Office of Information and Regulatory Affairs within OMB.
As part of the SBAR Panel process we conducted outreach with representatives from 18 various small entities that potentially would be affected by this rule. The SERs included representatives of EGUs owned by municipalities, cooperatives, and private investors. We distributed outreach materials to the SERs; these materials included background and project history, CAA section 112 overview, constraints on the rulemaking, rulemaking options under consideration, and potential control technologies and estimated cost. We met with 14 of the SERs, as well as five non-SER participants from organizations representing power producers, on December 2, 2010, to discuss the outreach materials, potential requirements of the rule, and regulatory areas where EPA has discretion and could potentially provide flexibility. The Panel received written comments from, or on behalf of, 10 SERs following the meeting in response to discussions at the meeting and the questions posed to the SERs by the Agency. The SERs were specifically asked to provide comment on regulatory approaches that could help to minimize the rule's impact on small businesses.
Consistent with the RFA/SBREFA requirements, the Panel evaluated the assembled materials and small-entity comments on issues related to elements of the IRFA. A copy of the Final Panel Report (including all comments received from SERs in response to the Panel's outreach meeting) is included in the docket for this proposed rule. In general, the Panel recommended that EPA consider its various flexibilities to the maximum extent possible consistent with CAA requirements to mitigate the impacts of the rulemaking on small businesses and to seek comment on potential adverse economic impacts of the proposed rule on affected small entities and recommendations to mitigate such impacts. With respect to specific issues and options, however, there were varying recommendations from panel members. Issues and options discussed among the panel members included: (1) MACT floor determinations and variability assessment; (2) monitoring, reporting, and recordkeeping requirements; (3) subcategorization; (4) area source standards; (5) work practice standards; (6) health based emission limits; (7) related Federal rules; (8) potential adverse economic impacts; and (9) concerns with the SBAR process. Panel member recommendations regarding each of these issues and options are presented in Chapter 9 of the Final Panel Report. As noted elsewhere in this preamble, this proposal is based on a regulatory alternative that includes subcategorization, MACT floor-based numerical emission limitations, work practice standards, alternative standards, alternative compliance options, and emissions averaging.
We invite comments on all aspects of the proposal and its impacts, including potential adverse impacts, on small entities.
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 proposed 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 for the Proposed Toxics Rule” under UMRA section 202 that is within the RIA and which is summarized below.
As discussed elsewhere in this preamble, the statutory authority for this proposed 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 is presented in the RIA for this rulemaking and in the docket. The regulatory alternative upon which this proposed rule is based represents the MACT floor for all regulated pollutants for four of the five subcategories of EGUs and for all but one regulated pollutant for the fifth subcategory. These proposed MACT floor-based standards represent the least costly and least burdensome alternative. Beyond-the-floor emission limits for Hg are proposed for existing and new EGUs designed to burn coal having a calorific value less than 8,300 Btu/lb.
The RIA prepared for this proposed rule including the Agency's assessment of costs and benefits and is in the docket.
It is estimated that 3 years after implementation of this proposed rule, HAP would be reduced by thousands of tons, including reductions in HCl, HF, metallic HAP (including Hg), and several other organic HAP from EGUs. Studies have determined a relationship between exposure to 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, there are significant reductions in PM
UMRA requires that we estimate, where accurate estimation is reasonably feasible, future compliance costs imposed by this proposed rule and any disproportionate budgetary effects. Our estimates of the future compliance costs of this proposed rule are discussed previously in this preamble.
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. EPA projects that 55 government entities will have compliance costs greater than 1 percent of base generation revenue in 2016, and 37 may experience compliance costs greater than 3 percent of base revenues. Also, one government entity is estimated to have all of its affected units retire. Overall, 17 units owned by government entities retire. It is also worth noting that two-thirds of the net compliance costs shown above are due to lost profits from retirements. More than half of those lost profits arise from retiring two large units, according to EPA modeling. For more details on these results and the methodology behind their estimation, see the results included in the RIA and which are discussed previously in this preamble.
UMRA requires that we estimate the effect of this proposed 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 proposed rule is presented in the RIA in the docket. This analysis provides estimates of the effect of this proposed 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 there will be a less than 4 percent increase in electricity price on average nationwide in 2016, and a less than 7 percent increase in natural gas price nationwide in 2016. Power generation from coal-fired plants will fall by about 1 percent nationwide in 2016.
UMRA requires that we describe the extent of the Agency's prior consultation with affected State, local, and tribal officials, summarize the officials' comments or concerns, and summarize our response to those comments or concerns. In addition, UMRA section 203 requires that we develop a plan for informing and advising small governments that may be significantly or uniquely impacted by a proposal. Consistent with the intergovernmental consultation provisions of UMRA section 204, EPA has initiated consultations with governmental entities affected by this proposed rule. EPA invited the following 10 national organizations representing state and local elected officials to a meeting held on October 27, 2010, in Washington DC: (1) National Governors Association, (2) National Conference of State Legislatures, (3) Council of State Governments, (4) National League of Cities, (5) U.S. Conference of Mayors, (6) National Association of Counties, (7) International City/County Management Association, (8) National Association of Towns and Townships, (9) County Executives of America, and (10) Environmental Council of States. These 10 organizations of elected state and local officials have been identified by EPA as the “Big 10” organizations appropriate to contact for purpose of consultation with elected officials. The purposes of the consultation were to
Consistent with UMRA section 205, EPA has identified and considered a reasonable number of regulatory alternatives. Because the potential existed for a likely significant impact for substantial number of small entities, 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, EPA considered several options. 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 proposed provisions regarding a number of the recommendations resulting from the SBAR Panel process as described below (see elsewhere in this preamble for more detail).
EPA determined that there is a distinguishable difference in emissions characteristics associated with five EGU design types and that these characteristics may affect the feasibility and/or effectiveness of emission control. Thus, the five types of units are proposed to be regulated separately (
The regulatory alternative upon which the proposed standards for coal-fired EGUs are based includes: (1) MACT floor-based numerical emission limitations for HCl (a HAP as well as a surrogate for all other acid gas HAP) and for PM (a surrogate for non-Hg metallic HAP) for existing and new EGUs in all three subcategories; (2) MACT floor-based numerical emission limitations for Hg for existing and new coal-fired units designed to burn coal having a calorific value of 8,300 Btu/lb or greater and IGCC units; (3) beyond-the-floor numerical emission limitations for Hg for existing and new coal-fired units designed to burn virgin coal having a calorific value less than 8,300 Btu/lb; and (4) work practices to limit emissions of dioxin/furan organic HAP and non-dioxin/furan organic HAP for existing and new EGUs in all three subcategories. The regulatory alternative upon which the proposed standards for oil-fired EGUs are based includes: (1) MACT floor-based numerical emission limitations for Hg, total non-Hg metallic HAP, HCl, and HF for existing and new EGUs in both subcategories; and (2) work practices to limit emissions of dioxin/furan organic HAP and non-dioxin/furan organic HAP for existing and new EGUs in both subcategories. The proposed use of surrogate pollutants would result in reduced compliance costs because testing would only be required for the surrogate pollutants (
EPA also is proposing three alternative standards for certain subcategories: (1) SO
The proposed work practice standard, which requires implementation of an annual performance (compliance) test program includes requirements to inspect the burner, flame pattern, and the system controlling the air-to-fuel ratio, and make any necessary adjustments and/or conduct any required maintenance and repairs; minimize CO emissions consistent with the manufacturer's specifications; measure the concentration of CO in the effluent stream before and after any adjustments are made; and submit an annual report containing the concentrations of CO and O
Under EO 13132, EPA may not issue an action that has federalism implications, that imposes substantial direct compliance costs, and that is not required by statute, unless the Federal government provides the funds necessary to pay the direct compliance costs incurred by state and local governments, or EPA consults with state and local officials early in the process of developing the proposed action.
EPA has concluded that this action may have federalism implications, because it may impose substantial direct compliance costs on state or local governments, and the Federal government will not provide the funds necessary to pay those costs. Accordingly, EPA provides the following federalism summary impact statement as required by section 6(b) of EO 13132.
Based on the estimates in EPA's RIA for today's proposed rule, the proposed regulatory option, if promulgated, may have federalism implications because the option may impose approximately $666.3 million in annual direct compliance costs on an estimated 97 state or local governments. Specifically, we estimate that there are 81 municipalities, 5 states, and 11 political subdivisions (
EPA consulted with state and local officials in the process of developing the proposed rule to permit them to have meaningful and timely input into its development. EPA met with 10 national organizations representing state and local elected officials to provide general background on the proposal, answer questions, and solicit input from
In the spirit of EO 13132, and consistent with EPA policy to promote communications between EPA and state and local governments, EPA specifically solicits comment on this proposed action from state and local officials.
Subject to EO 13175 (65 FR 67249, November 9, 2000) 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 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 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.”
EPA has concluded that this action may have tribal implications. However, it will neither impose substantial direct compliance costs on tribal governments, nor preempt tribal law. This proposed rule would impose requirements on owners and operators of EGUs. EPA is aware of three coal-fired EGUs located in Indian Country but is not aware of any EGUs owned or operated by tribal entities.
EPA offered consultation with tribal officials early in the process of developing this proposed regulation to permit them to have meaningful and timely input into its development. Consultation letters were sent to 584 tribal leaders. The letters provided information regarding EPA's development of NESHAP for EGUs and offered consultation. Three consultation meetings were held on December 7, 2010, with the Upper Sioux Community of Minnesota; on December 13 with Moapa Band of Paiutes, Forest County Potawatomi, Standing Rock Sioux Tribal Council, Fond du Lac Band of Chippewa; and on January 5, 2011 with the Forest County Potawatomi, and a representative from the National Tribal Air Association (NTAA). In these meetings, 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 on the reservations. Particularly, 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 lifestyles for fishing communities, the cultural impact of impaired water quality for ceremonial purposes, and the economic impact on tourism. In light of these concerns, the tribes expressed interest in an expedited implementation of the rule, they expressed concerns about how the Agency would consider variability in setting the standards and use tribal-specific fish consumption data from the tribes in our assessments, they were not supportive of using work practice standards as part of the rule, and they asked the Agency to consider going beyond-the-floor to offer more protection for the tribal communities. A more specific list of comments can be found in the Docket.
In addition to these consultations, EPA also conducted outreach on this rule through presentations at the National Tribal Forum in Milwaukee, WI, and on NTAA calls. EPA specifically requested tribal data that could support the appropriate and necessary analysis and the RIA for this rule. We will also hold additional meetings with tribal environmental staff to inform them of the content of this proposal as well as provide additional consultation with tribal elected officials where it is appropriate.
EPA specifically solicits additional comment on this proposed rule from tribal officials.
Executive Order 13045 (62 FR 19,885, April 23, 1997) applies to any rule that: (1) Is determined to be “economically significant” as defined under EO 12866, and (2) concerns an environmental health or safety risk that EPA has reason to believe may have a disproportionate effect on children. If the regulatory action meets both criteria, the Agency must evaluate the environmental health or safety effects of this planned rule on children, and explain why this planned regulation is preferable to other potentially effective and reasonably feasible alternatives considered by the Agency.
This proposed rule is subject to EO 13045 because it is an economically significant regulatory action as defined by EO 12866, and we believe that the action concerns an environmental health risk which may have a disproportionate impact on children. Although this proposed rule is based on technology performance, the statute is designed to require standards that are likely to protect against hazards to public health with an adequate margin of safety as described elsewhere in this document. The protection offered by this proposed rule is especially important for children, especially the developing fetus. As referenced in the section entitled, “Consideration of Health Risks to Children and Environmental Justice Communities” 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 elsewhere in this document.
The public is invited to submit comments or identify peer-reviewed studies and data that assess effects of early life exposure to this proposed rule.
Executive Order 13211, (66 FR 28355, May 22, 2001), provides that agencies shall prepare and submit to the Administrator of the Office of Information and Regulatory Affairs, OMB, a Statement of Energy Effects for certain actions identified as significant energy actions. Section 4(b) of EO 13211 defines “significant energy actions” as “any action by an agency (normally published in the
We estimate a less than 4 percent price increase for electricity nationwide in 2016 and a 1 percent percentage fall in coal-fired power production. EPA projects that delivered natural gas prices will increase by about 1 percent over the 2015 to 2030 timeframe. For more information on the estimated energy effects, please refer to the economic impact analysis for this proposed rule. The analysis is available in the RIA, which is in the public docket.
Therefore, we conclude that this proposed rule when implemented is likely to have a significant adverse effect on the supply, distribution, or use of energy.
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 EPA to use voluntary consensus standards (VCS) in their regulatory and procurement activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (
This rulemaking involves technical standards. EPA cites the following standards in this proposed rule: EPA Methods 1, 2, 2F, 2G, 3A, 3B, 4, 5, 5D, 6, 6C, 9, 19, 26, 26A, 29, 30A, 30B, and 202 of 40 CFR part 60. Consistent with the NTTAA, EPA conducted searches to identify VCS in addition to these EPA methods. No applicable voluntary standards were identified for EPA Methods 2F, 2G, 8, 19, 201A, and 202. The search and review results have been documented and are placed in the docket for this proposed rule.
EPA has decided to use American National Standards Institute (ANSI)/ASME PTC 19-10-1981 Part 10, “Flue and Exhaust Gas Analyses,” acceptable as an alternative to Methods 3B (for CO
Another VCS, ASTM D6735-01, “Standard Test Method for Measurement of Gaseous Chlorides and Fluorides from Mineral Calcining Exhaust Sources Impinger Method,” is an acceptable alternative to EPA Methods 26 and 26A.
An additional VCS, ASTM D6784-02 (2008)—Standard Test Method for Elemental, Oxidized, Particle-Bound and Total Mercury Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro Method) is acceptable as an alternative to Method 29 for Hg, but only if the standard falls within the applicable concentration range of 0.5 to 100 μg/Nm
During the search, if the title or abstract (if provided) of the VCS described technical sampling and analytical procedures that are similar to EPA's reference method, EPA ordered a copy of the standard and reviewed it as a potential equivalent method. All potential standards were reviewed to determine the practicality of the VCS for this rule. This review requires significant method validation data which meets the requirements of EPA Method 301 for accepting alternative methods or scientific, engineering and policy equivalence to procedures in EPA reference methods. EPA may reconsider determinations of impracticality when additional information is available for particular VCS.
The search identified 22 other VCS that were potentially applicable for this rule in lieu of EPA reference methods. After reviewing the available standards, EPA determined that 22 candidate VCS (ASTM D3154-00 (2006), ASME B133.9-1994 (2001), ANSI/ASME PTC 19-10-1981 Part 10, ASTM D5835-95 (2007), International Organization for Standards (ISO) 10396:1993 (2007), ISO 12039:2001, ASTM D6522-00 (2005), Canadian Standards Association (CAN/CSA) Z223.2-M86 (1999), ISO 9096:1992 (2003), ANSI/ASME PTC-38-1980 (1985), ASTM D3685/D3685M-98 (2005), ISO 7934:1998, ISO 11632:1998, ASTM D3464-96 (2007), ASTM D3796-90 (2004), ISO 10780:1994, CAN/CSA Z223.21-M1978, ASTM D3162-94 (2005), CAN/CSA Z223.1-M1977, EN 1911-1,2,3 (1998), EN 13211:2001, CAN/CSA Z223.26-M1987) identified for measuring emissions of pollutants or their surrogates subject to emission standards in the proposed rule would not be practical due to lack of equivalency, documentation, validation data, and other important technical and policy considerations. These 22 methods are listed Attachment 1 to the documentation memo, along with the EPA review comments, which may be found in the docket.
Executive Order 12898 (59 FR 7629, February 16, 1994) establishes Federal executive policy on 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, low-income, and tribal populations in the U.S.
This proposed rule establishes national emission standards for new and existing EGUs that combust coal and oil. EPA estimates that there are approximately 1,400 units located at 550 facilities covered by this proposed rule.
This proposed 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 proposed rule will also result in substantial reductions of criteria pollutants such as CO, PM, and SO
Pursuant to EO 12898 and the “Interim Guidance on Considering Environmental Justice During the Development of an Action” (July 2010), during development of a rule EPA considers whether there are positive or negative impacts of the action that appear to affect low-income, minority, or tribal communities disproportionately. Regardless of whether a disproportionate effect exists, EPA also considers whether there is a chance for these communities to meaningfully participate in the rulemaking process.
Today's proposed rule is one of a group of regulatory actions that EPA will take over the next several years to respond to statutory and judicial mandates that will reduce exposure to HAP and PM
This is an air toxics rule; therefore, it does not permit emissions trading among sources. Instead, this proposed 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 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 proposed 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 was 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 EPA's assessment of both the underlying risks that make this proposed rule appropriate and necessary, and of the analysis of the benefits of reducing exposure to Hg and the other hazardous air pollutants.
EPA's full analysis of risks from consumption of Hg-contaminated fish are contained in the preamble for this rule. The effects of this proposed rule on the health risks from Hg and other HAP are presented in the preamble and in the RIA for this rule. This information can be accessed through docket EPA-HQ-OAR-2009-0234 and from the main EPA webpage for the rule
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 proposed rule, EPA reviewed the aggregate demographic makeup of the communities near EGUs covered by this proposed 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. EGUs 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 Hg and SO
This proximity-to-the-source review is included in the analysis for this proposed rule because some EGUs emit enough Ni or Cr to cause elevated lifetime cancer risks greater than 1 in a million in nearby communities. In addition, EPA's analysis indicates that there are localized areas with elevated levels of Hg deposition around most U.S. EGUs.
The review identified those census blocks within two circular distances (5 km and 50 km) of coal-fired EGUs and determined their demographic and socio-economic composition (
The results of EPA's demographic analysis for coal fired EGUs are shown in the following table:
The data indicate that coal-fired EGUs are located in areas where minority share of the population living within a 3-mile buffer is higher than the national average. For these same areas, the percent of the population below the poverty line is also higher than the national average. At 50 km from the source, however, the demographics are different. Although the percent African American remain above the national average, the percent of minority (including Native Americans) and the percent of the population living below the poverty line decrease below their respective national averages. 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 PM-related annual benefits of the proposed rule for adults include approximately 6600 to 17,000 fewer premature mortalities, 4,300 fewer cases of chronic bronchitis, 10,000 fewer non-fatal heart attacks, 12,000 fewer hospitalizations (for respiratory and cardiovascular disease combined), 4.9 million fewer days of restricted activity due to respiratory illness and approximately 830,000 fewer lost work days. We also estimate substantial health improvements for children in the form of 110,000 fewer asthma attacks, 6,700 fewer hospital admissions due to asthma, 10,000 fewer cases of acute bronchitis, and approximately 210,000 fewer cases of upper and lower respiratory illness.
We also examined the PM
In 2005, people living in the highest-risk counties and in the poorest counties have substantially higher risks of PM
Our analysis finds that this proposed rule will significantly reduce the PM
EPA estimates that the benefits of the proposed rule are distributed among these populations fairly evenly. Therefore, there is no indication that people of particular race, income, or level of education receive a greater benefit (or smaller benefit) than others. However, the analysis does indicate that this proposed rule in conjunction with the implementation of existing or proposed rules (
These results are presented in more detail in the “Benefits Appendix” to this rule, a copy of which is available in the docket.
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 polices. To promote meaningful involvement, EPA has developed a communication and outreach strategy to ensure that interested communities have access to
Once this rule is finalized and implemented, affected EGUs will need to update their operating (Title V) permits to reflect their new emissions limits and any other applicable requirements (
This proposed rule strictly limits the emissions rate of Hg and other HAP from every affected EGU in the U.S. EPA's analysis indicates substantial health benefits, including for vulnerable populations, from reductions in PM
Environmental protection, Administrative practice and procedure, Air pollution control, Hazardous substances, 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 proposed to be amended as follows:
1. The authority citation for part 60 continues to read as follows:
42 U.S.C. 7401,
2. Section 60.17 is amended:
a. By redesignating paragraphs (a)(91) and (a)(92) as paragraphs (a)(94) and (a)(95);
b. By redesignating paragraphs (a)(89) and (a)(90) as paragraphs (a)(91) and (a)(92);
c. By redesignating paragraphs (a)(54) through (a)(88) as paragraphs (a)(55) through (a)(89);
d. By adding paragraph (a)(54);
e. By adding paragraph (a)(90); and
f. By adding paragraph (a)(93) to read as follows:
(54) ASTM D3699—08, Standard Specification for Kerosine, IBR approved for §§ 60.41b of subpart Db of this part and 60.41c of subpart Dc of this part.
(90) ASTM D6751-11, Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels, IBR approved for §§ 60.41b of subpart Db of this part and 60.41c of subpart Dc of this part.
(94) ASTM D7467-10, Standard Specification for Diesel Fuel Oil, Biodiesel Blend (B6 to B20), IBR approved for §§ 60.41b of subpart Db of this part and 60.41c of subpart Dc of this part.
3. The heading to Subpart D is revised to read as follows:
Subpart D—Standards of Performance for Fossil-Fuel-Fired Steam Generators
4. Section 60.40 is amended by revising paragraph (e) to read as follows:
(e) Any facility covered under either subpart Da or KKKK is not covered under this subpart.
5. Section 60.41 is amended by adding the definitions of “natural gas” to read as follows:
Natural gas means:
(1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in geologic formations beneath the earth's surface, of which the principal constituent is methane; or
(2) Liquid petroleum gas, as defined by the American Society of Testing and Materials in ASTM D1835 (incorporated by reference, see § 60.17); or
(3) A mixture of hydrocarbons that maintains a gaseous state at ISO conditions. Additionally, natural gas must either be composed of at least 70 percent methane by volume or have a gross calorific value between 34 and 43 megajoules (MJ) per dry standard cubic meter (910 and 1,150 Btu per dry standard cubic foot).
6. Section 60.42 is amended as follows:
a. By revising paragraph (a) introductory text.
b. By adding paragraph (d).
c. By adding paragraph (e).
(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 and operator of an affected facility that combusts only natural gas and that is subject to a federally enforceable permit limiting fuel use to 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
7. Section 60.45 is amended as follows:
a. By revising paragraph (a).
b. By revising paragraphs (b) introductory text and (b)(1) through (b)(5).
c. By revising paragraph (b)(6) introductory text.
(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) with potential SO
(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 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 section § 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
8. The heading to Subpart Da is revised to read as follows:
9. Section 60.40Da is amended by revising paragraph (e) and by adding paragraph (f) to read as follows:
(e) Applicability of the requirement 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 (e)(3) of this section.
(1) Affected facilities (i.e. heat recovery steam generators used with duct burners) associated with a stationary combustion turbine that are capable of combusting more than 73 MW (250 MMBtu/hr) heat input of fossil fuel are subject to this subpart except in cases when the affected facility (i.e. heat recovery steam generator) meets the applicability requirements and is subject to subpart KKKK of this part.
(2) For heat recovery steam generators used with duct burners subject to this subpart, only emissions resulting from the combustion of fuels in the steam generating unit (i.e. duct burners) are subject to the standards under this subpart. (The emissions resulting from the combustion of fuels in the stationary combustion turbine engine are subject to subpart GG or KKKK, as applicable, of this part).
(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.
(f)
10. Section 60.41Da is amended by revising the definitions of “gaseous fuel,” “integrated gasification combined cycle electric utility steam generating unit,” “petroleum” and “steam generating unit,” adding the definitions of “affirmative defense” and “petroleum coke,” and deleting the definitions of “dry flue gas desulfurization technology,” “emission rate period,” and “responsible official” to read as follows:
11. Revise § 60.42Da to read as follows:
(a) Except as provided in paragraph (a)(4) 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 filterable PM in excess of:
(1) 13 ng/J (0.03 lb/MMBtu) heat input;
(2) 1 percent of the potential combustion concentration (99 percent reduction) when combusting solid fuel; and
(3) 30 percent of potential combustion concentration (70 percent reduction) when combusting liquid fuel.
(4) An owner or operator of an affected facility that combusts only gaseous or liquid fuels (excluding residual oil) with potential SO
(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) 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 are 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 (e) 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 filterable 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.
(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. For an affected facility that commenced construction, reconstruction, or modification, 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 any gases that contain filterable PM in excess of:
(1) 13 ng/J (0.030 lb/MMBtu) heat input, 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) An owner or operator of an affected facility than combusts only gaseous or liquid fuels (excluding residual oil) with potential SO
(f) Except as provided in paragraph (g) 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, modification, or reconstruction after May 3, 2011, shall cause to be discharged into the atmosphere from that affected facility any gases that contain total PM in excess of either:
(1) For an affected facility that commenced construction or reconstruction 7.0 ng/J (0.055 lb/MWh) gross energy output; or
(2) For an affected facility that commenced modification, 15 ng/J (0.034 lb/MMBtu) heat input.
(g) An owner or operator of an affected facility that combusts only natural gas is exempt from the total PM standard specified in paragraph (f) of this section.
(h) The PM emission standards under this section do not apply to an owner or operator of any affected facility that is operated under a PM commercial demonstration permit issued by the Administrator in accordance with the provisions of § 60.47Da.
12. Section 60.43Da is amended as follows:
a. By revising paragraphs (a)(1) through (a)(3).
b. By revising paragraph (f).
c. By revising paragraph (i).
d. By revising paragraph (j).
e. By revising paragraph (k).
f. By adding paragraph (a)(4).
g. By adding paragraph (l).
h. By adding paragraph (m).
i. By adding paragraph (n).
(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 reduction), when emissions are less than 260 ng/J (0.60 lb/MMBtu) heat input;
(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 that commenced 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).
(j) 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 commenced after February 28, 2005, but before May 4, 2011, and that burns 75 percent or more (by heat input) coal refuse on a 12-month rolling average basis, 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) 6 percent of the potential combustion concentration (94 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) 6 percent of the potential combustion concentration (94 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 that commenced 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 (m) and (n) 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 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) 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 that commenced construction, reconstruction, or modification commenced after May 3, 2011, and that burns 75 percent or more (by heat input) coal refuse on a 12-month rolling average basis, shall caused 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) 180 ng/J (1.4 lb/MWh) gross energy output; or
(ii) 6 percent of the potential combustion concentration (94 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).
(n) 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 that commenced 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
13. Section 60.44Da is amended:
a. By revising paragraph (a) introductory text.
b. By revising paragraph (b).
c. By revising paragraph (d).
d. By revising paragraph (e).
e. By revising paragraph (f).
f. By adding paragraph (g).
g. By adding paragraph (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 subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility, except as provided under paragraphs (b), (d), (e), and (f) of this section, any gases that contain NO
(b) The NO
(d)(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 of an affected facility that commenced construction after July 9, 1997, but before March 1, 2005 shall cause to be discharged into the atmosphere any gases that contain NO
(2) 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 affected facility for which reconstruction commenced after July 9, 1997, but before March 1, 2005 shall cause to be discharged into the atmosphere any gases that contain NO
(e) 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, 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 30-day period, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain NO
(g) Compliance with the emission limitations under this section are determined on a 30-boiler operating day rolling average basis, except as provided under § 60.48Da(j)(1).
(h) 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
14. Remove and reserve § 60.45Da.
15. Section 60.47Da is amended as follows:
a. By adding paragraph (f).
b. By adding paragraph (g).
c. By adding paragraph (h).
d. By adding paragraph (i).
(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
(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 controls 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.
16. Section 60.48Da is amended as follows:
a. By revising paragraph (c).
b. By revising paragraph (g).
c. By revising paragraph (k)(1)(i).
d. By revising paragraph (k)(1)(ii).
e. By revising paragraph (k)(2)(i).
f. By revising paragraph (k)(2)(iv).
g. By removing and reserving paragraph (l).
h. By revising paragraph (n).
i. By revising paragraphs (p)(5), (p)(7), and (p)(8).
j. By adding paragraph (r).
(c) For affected facilities that commenced construction, modification, or reconstruction before May 4, 2011, the PM emission standards under § 60.42Da, and the NO
(g) The owner or operator of an affected facility subject to emission limitations in this subpart shall determine compliance as follows:
(1) For affected facilities that commenced construction, modification, or reconstruction before May 4, 2011, compliance with applicable 30 boiler operating day rolling average SO
(2) For affected facilities that commenced construction, modification, or reconstruction before May 4, 2011, compliance with applicable SO
(3) For affected facilities that commenced construction, modification, or reconstruction before May 4, 2011 compliance with applicable daily average PM emission limitations 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. For affected facilities that commence construction, modification, or reconstruction after May 3, 2011, compliance with applicable daily average PM emission limitations is determined by calculating the sum of all PM emissions for PM each boiler operating day divided by the sum of all the gross useful output for PM each boiler operating day, except for data obtained during malfunction. 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.
(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/hr) of NO
(n) Compliance provisions for sources subject to § 60.42Da(c)(1). The owner or operator of an affected facility subject to § 60.42Da(c)(1) 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 divided by the average hourly gross energy output (measured according to the provisions of § 60.49Da(k)).
(p) * * *
(5) At a minimum, non-out-of-control valid 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 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)
(1) 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:
(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 emission limitations 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
(2) The owner or operator of the facility experiencing an exceedance of its emission limit(s) during a malfunction shall notify the Administrator by telephone or facsimile (FAX) transmission as soon as possible, but no later than two business days after the initial occurrence of the malfunction, if it wishes to avail itself of an affirmative defense to civil penalties for that malfunction. The owner or operator seeking to assert an affirmative defense shall also submit a written report to the Administrator within 45 days of the initial occurrence of the exceedance of the standards in §§ 60.42Da, 60.43Da, and 60.44Da to demonstrate, with all necessary supporting documentation, that it has met the requirements set forth in paragraph (a) of this section. The owner or operator may seek an extension of this deadline for up to 30 additional days by submitting a written request to the Administrator before the expiration of the 45 day period. Until a request for an extension has been approved by the Administrator, the owner or operator is subject to the requirement to submit such report within 45 days of the initial occurrence of the exceedance.
17. Section 60.49Da is amended as follows:
a. By revising paragraphs (a)(1), (a)(2), and (a)(3) introductory text.
b. By revising paragraphs (b) introductory text and (b)(2).
c. By revising paragraph (e).
d. By revising paragraph (k) introductory text.
e. By revising paragraph (l).
f. By removing and reserving paragraph (p).
g. By removing and reserving paragraph (q).
h. By removing and reserving paragraph (r).
i. By revising paragraph (t).
j. By revising paragraphs (u)(1)(iii) and (u)(4).
(a) * * *
(1) Except as provided for in paragraph (a)(2) 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; or
(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.
(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 operators 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.
(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, malfunction, and emergency conditions, 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 output for sources demonstrating compliance with an output-based standard.
(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 CD assessment, 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 emission limitation 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).
(4) As of January 1, 2012 and within 60 days after the date of completing each performance test, as defined in § 63.2, conducted to demonstrate compliance with this subpart, you must submit relative accuracy test audit (i.e., reference method) data and performance test (i.e., compliance test) data, except opacity data, electronically to EPA's Central Data Exchange (CDX) by using the Electronic Reporting Tool (ERT) (see
18. Section 60.50Da is amended as follows:
a. By revising paragraphs (b)(2) and (b)(4).
b. By removing paragraph (g).
c. By removing paragraph (h).
d. By removing paragraph (i).
(b) * * *
(2) For the filterable particular matter concentration, Method 5 of appendix A of this part shall be used at affected facilities without wet FGD systems and Method 5B of appendix A of this part shall be used after wet FGD systems.
(4) Total particular matter concentration consists of the sum of the filterable and condensable fractions. The condensable fraction shall be measured using Method 202 of appendix M of part 51, and the filterable fraction shall be measured using Method 5 of appendix A of this part.
19. Section 60.51Da is amended as follows:
a. By revising paragraph (a).
b. By removing and reserving paragraph (g).
c. By revising paragraph (k).
(a) For SO
(k) The owner or operator of an affected facility may submit electronic quarterly reports for SO
20. Section 60.52Da is amended by removing and reserving paragraph (a).
21. Section 60.40b is amended as follows:
a. By revising paragraph (c).
b. By revising paragraph (h).
c. By revising paragraph (i).
d. By adding paragraph (1).
(c) Affected facilities that also meet the applicability requirements under subpart J or subpart Ja (Standards of performance for petroleum refineries) 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 (i.e. heat recovery steam generators) that are associated with stationary combustion turbines and that meet the applicability requirements of subpart KKKK of this part are not subject to this subpart. This subpart will continue to apply to all other affected facilities (i.e. heat recovery steam generators with duct burners) that are capable of combusting more than 29 MW (100 MMBtu/hr) heat input of fossil fuel. If the affected facility (i.e. heat recovery steam generator) is subject to this subpart, only emissions resulting from combustion of fuels in the steam generating unit are subject to this subpart. (The stationary combustion turbine emissions are subject to subpart GG or KKKK, as applicable, of this part.)
(l) Affected facilities that also meet the applicability requirements under subpart BB (Standards of Performance for Kraft Pulp Mills) are subject to the SO
22. Section 60.41b is amended by revising the definition of “distillate oil” to read as follows:
23. Section 60.44b is amended by revising paragraphs (c) and (d) to read as follows:
(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, or a mixture of these fuels with natural gas, and wood, municipal-type solid waste, 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 or distillate oil with a potential SO
24. Section 60.46b is amended by revising paragraph (j)(14) to read as follows:
(j) * * *
(14) As of January 1, 2012, and within 60 days after the date of completing each performance test, as defined in § 63.2, conducted to demonstrate compliance with this subpart, you must submit relative accuracy test audit (i.e., reference method) data and performance test (i.e., compliance test) data, except opacity data, electronically to EPA's Central Data Exchange (CDX) by using the Electronic Reporting Tool (ERT) (see
25. Section 60.48b is amended as follows:
a. By revising paragraphs (a) introductory text and (a)(1)(i).
b. By revising paragraph (j) introductory text.
c. By revising paragraph (j)(5).
d. By revising paragraph (j)(6).
e. By adding paragraph (j)(7).
(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;
(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.
26. Section 60.40c is amended as follows:
a. By revising paragraph (e).
b. By revising paragraph (f).
c. By revising paragraph (g).
(e) Affected facilities (i.e. heat recovery steam generators and fuel heaters) that are associated with stationary combustion turbines and meet the applicability requirements of subpart KKKK of this part are not subject to this subpart. This subpart will continue to apply to all other heat recovery steam generators, fuel heaters, and other affected facilities that are capable of combusting more than or equal to 2.9 MW (10 MMBtu/hr) heat input of fossil fuel but less than or equal to 29 MW (100 MMBtu/hr) heat input of fossil fuel. If the heat recovery steam generator, fuel heater, or other affected facility is subject to this subpart, only emissions resulting from combustion of fuels in the steam generating unit are subject to this subpart. (The stationary combustion turbine emissions are subject to subpart GG or KKKK, as applicable, of this part).
(f) Any 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 of 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.
27. Section 60.41c is amended by removing the definition of “Cogeneration” and revising the definition of “Distillate oil” to read as follows:
28. Section 60.42c is amended as follows:
a. By revising paragraph (d).
b. By revising paragraph (h) introductory text.
c. By revising paragraph (h)(3).
d. By adding paragraph (h)(4).
(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
(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/hr).
(4) Other fuels-fired affected facilities with heat input capacities between 2.9 and 8.7 MW (10 and 30 MMBtu/hr).
29. Section 60.45c is amended by revising paragraph (c)(14) to read as follows:
(c)(14) As of January 1, 2012, and within 60 days after the date of completing each performance test, as defined in § 63.2, conducted to demonstrate compliance with this subpart, you must submit relative accuracy test audit (i.e., reference method) data and performance test (i.e., compliance test) data, except opacity data, electronically to EPA's Central Data Exchange (CDX) by using the Electronic Reporting Tool (ERT) (see
30. Section 60.47c is amended as follows:
a. By revising paragraphs (a) introductory text and (a)(1)(i).
b. By revising paragraph (f).
c. By revising paragraph (g).
d. By adding paragraph (h).
(a) Except as provided in paragraphs (c), (d), (e), (f), (g), and (h) 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), (f), or (g) 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;
(f) Owners and operators of an affected facility that is subject to an opacity standard in § 60.43c(c) and that 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 is not required to operate a COMS.
(g) 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.
(h) Owners and operators of an affected facility that is subject to an opacity standard in § 60.43c(c) and that burns only gaseous fuels and/or fuel oils that contain less than or equal to 0.5 weight percent sulfur and operates according to a written site-specific monitoring plan approved by the permitting authority is not required to operate a COMS. 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.
31. Subpart HHHH is removed and reserved.
32. The authority citation for part 63 continues to read as follows:
42 U.S.C. 7401,
33. Part 63 is amended by adding subpart UUUUU to read as follows:
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). 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.
(a) This subpart applies to each individual or group of one 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.
(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 utility steam generating unit that has switched completely to burning a different coal rank or fuel type is considered to be an existing affected source under this subpart.
The types of EGUs listed in paragraphs (a) through (c) 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), covered by 40 CFR part 63, subpart YYYY.
(b) Any EGU that is not a coal- or oil-fired EGU and combusts natural gas 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.
(c) Any EGU that has the capability of combusting more than 73 MWe (250 million Btu/hr, MMBtu/hr) heat input (equivalent to 25 MWe output) of coal or oil but did not fire 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. 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).
(a) If you have a new or reconstructed EGU, you must comply with this subpart by [DATE THE FINAL RULE IS PUBLISHED IN THE
(b) If you have an existing EGU, you must comply with this subpart no later than [3 YEARS AFTER DATE THE FINAL RULE IS PUBLISHED IN THE
(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.
(a) Coal-fired EGUs are subcategorized as defined in paragraphs (a)(1) through
(1) EGUs designed for coal
(2) EGUs designed for coal < 8,300 Btu/lb. (b) Oil-fired EGUs are subcategorized as noted in paragraphs (b)(1) through (b)(2) of this section and as defined in § 63.10042.
(1) EGUs designed to burn liquid oil, and
(2) 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 paragraph (a)(1)(i) and (ii) or under § 63.10009.
(i) You may not use the alternate SO
(ii) You may not use the alternate SO
(iii) You must operate the wet or dry flue gas desulfurization technology installed on the unit at all times in order to qualify to use the alternate SO
(2) You must meet each operating limit in Table 4 to this subpart that applies to your EGU. If you use a control device or combination of control devices not covered in Table 4 to this subpart, or you wish to establish and monitor an alternative operating limit and alternative monitoring parameters, you must apply to the EPA Administrator for approval of alternative monitoring under § 63.8(f).
(b) As provided in § 63.6(g), EPA may approve use of an alternative to the work practice standards in this section.
(a) You must be in compliance with the emission limits and operating limits in this subpart. These limits apply to you at all times.
(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. For non-mercury HAP metals, you demonstrate continuous compliance through use of a particulate matter (PM) CEMS; initial compliance is determined by establishing an operational limit for filterable PM obtained during total PM emissions testing. As an alternative to using a PM CEMS, you may demonstrate initial and continuous compliance by conducting total HAP metals testing or individual non-mercury (Hg) metals testing. For acid gases, you demonstrate initial and continuous compliance through use of a continuous hydrogen chloride (HCl) CEMS. As an alternative to HCl CEMS, you may demonstrate initial and continuous compliance by conducting performance testing. As another alternative to HCl CEMS, you may demonstrate initial and continuous compliance through use of a certified sulfur dioxide (SO
(2) For liquid oil-fired units, you must demonstrate initial and continuous compliance for HCl, hydrogen fluoride (HF), and individual or total HAP metals by conducting performance testing. As an alternative to conducting performance testing, you may demonstrate compliance with the applicable emissions limit for HCl, HF, and individual or total HAP metals using fuel analysis provided the emission rate calculated according to § 63.10011(c) is less than the applicable emission limit.
(d) 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), or through the use of a sorbent trap monitoring system for Hg, 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 or sorbent trap monitoring system. This requirement also applies to you if you petition the EPA 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. The monitoring plan must address the provisions in paragraphs (d)(1) through (7) of this section.
(1) Installation of the CMS 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 (e.g., on or downstream of the last control device).
(2) Performance and equipment specifications for the sample interface, the pollutant concentration or parametric signal analyzer, and the data collection and reduction systems.
(3) Schedule for conducting initial and periodic performance evaluations.
(4) Performance evaluation procedures and acceptance criteria (e.g., calibrations), including ongoing data quality assurance procedures in accordance with the general requirements of § 63.8(d) or Appendix A to this subpart, as applicable.
(5) Ongoing operation and maintenance procedures in accordance with the general requirements of § 63.8(c)(1)(ii), (c)(3), and (c)(4)(ii) or Appendix A to this subpart, as applicable.
(6) Conditions that define a continuous monitoring system 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) or Appendix A to this subpart, as applicable.
(7) Ongoing recordkeeping and reporting procedures in accordance with the general requirements of § 63.10(c), (e)(1), and (e)(2)(i) and Appendix A to this subpart, as applicable.
(e) You must operate and maintain the CMS or sorbent trap monitoring system according to the site-specific monitoring plan.
In response to an action to enforce the standards set forth in paragraph § 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 the respondent fails to meet its 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, the owners or operators of facilities 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 facility 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) The owner or operator of the facility experiencing an exceedence of its emission limit(s) during a malfunction shall notify the EPA Administrator by telephone or facsimile (FAX) transmission as soon as possible, but no later than two (2) business days after the initial occurrence of the malfunction, if it wishes to avail itself of an affirmative defense to civil penalties for that malfunction. The owner or operator seeking to assert an affirmative defense shall also submit a written report to the EPA Administrator within 45 days of the initial occurrence of the exceedence of the standard in § 63.9991 to demonstrate, with all necessary supporting documentation, that it has met the requirements set forth in paragraph (a) of this section. The owner or operator may seek an extension of this deadline for up to 30 additional days by submitting a written request to the Administrator before the expiration of the 45 day period. Until a request for an extension has been approved by the Administrator, the owner or operator is subject to the requirement to submit such report within 45 days of the initial occurrence of the exceedances.
(a)
(b)
(1) For affected EGUs that do not rely on CMS, sorbent trap monitoring systems, or 28 to 30 day Method 30B testing to demonstrate initial compliance, performance test data and results from a prior performance test may be used to demonstrate initial compliance, provided the performance tests meet the following conditions:
(i) The performance test was conducted within the last twelve months;
(ii) The performance test was conducted in accordance with all requirements contained in § 63.10007 and Table 5 of this subpart; and
(iii) You certify, and have and keep documentation demonstrating, that the EGU configuration, control devices, and materials/fuel have remained constant since the prior performance test was conducted.
(2) [Reserved]
(c)
(1) For affected liquid oil-fired EGUs demonstrating compliance with the applicable emissions limits in Tables 1 or 2 of this subpart for HCl or individual or total HAP metals through fuel analysis, your initial compliance requirement is to conduct a fuel analysis for each type of fuel burned in your EGU according to § 63.10008 and Table 6 to this subpart and establish operating limits according to § 63.10011 and Table 8 to this subpart.
(2) For affected liquid oil-fired EGUs that elect to demonstrate compliance with the applicable emissions limits in Tables 1 or 2 of this subpart for HF, your initial compliance requirement is to conduct a fuel analysis for each type of fuel burned in your EGU according to § 63.10008 and Table 6 to this subpart and establish operating limits according to § 63.10011 and Table 8 to this subpart.
(3) Fuel analysis data and results from a prior fuel analysis may be used to demonstrate initial compliance, provided the fuel analysis meets the following conditions:
(i) The fuel analysis was conducted within the last twelve months;
(ii) The fuel analysis was conducted in accordance with all requirements contained in § 63.10008 and Table 6 of this subpart; and
(iii) You certify, and have and keep documentation demonstrating, that the EGU configuration, control devices, and materials/fuel have remained constant since the prior fuel analysis was conducted.
(4) For affected EGUs that combust a single type of fuel, you are exempted from the initial compliance requirements of conducting a fuel analysis for each type of fuel burned in your EGU according to § 63.10008 and Table 6 to this subpart.
(5) For purposes of this subpart, EGUs that use a supplemental fuel only for startup, unit shutdown, or transient flame stability purposes qualify as affected EGUs that combust a single type of fuel, the supplemental fuel is not subject to the fuel analysis requirements under § 63.10008 and Table 6 to this subpart, and you are exempted from the initial compliance requirements of conducting a fuel analysis for each type of fuel burned in your EGU according to § 63.10008 and Table 6 to this subpart.
(d)
(2) For affected liquid oil-fired EGUs that elect to demonstrate initial compliance with the applicable emissions limits in Tables 1 or 2 of this subpart for HF through use of HF CEMS, initial compliance is determined using the average hourly HF concentrations obtained during the first 30 day operating period after the monitoring system is certified.
(3) For affected solid oil-derived fuel- or coal-fired EGUs that demonstrate initial compliance with the applicable emissions limits in Tables 1 or 2 of this subpart for HCl through use of HCl CEMS, initial compliance is determined using the average hourly HCl concentrations obtained during the first 30 day operating period after the monitoring system is certified.
(4) For affected solid oil-derived fuel- or coal-fired EGUs with installed systems that use wet or dry flue gas desulfurization technology to demonstrate initial compliance with the applicable emissions limits in Tables 1 or 2 of this subpart for SO
(5) For affected solid oil-derived fuel- or coal-fired EGUs that demonstrate initial compliance with the applicable emissions limits in Tables 1 or 2 of this subpart for PM through use of PM CEMS, initial compliance is determined using the average hourly PM concentrations obtained during the first 30 day operating period after the monitoring system is certified.
(6) For affected EGUs that demonstrate initial compliance with the applicable emissions limits in Tables 1 or 2 of this subpart for Hg through use of Hg CEMS, initial compliance is determined using the average hourly Hg concentrations obtained during the first 30 day operating period after the monitoring system is certified.
(7) For affected EGUs that elect to demonstrate initial compliance with the applicable emissions limits in Tables 1 or 2 of this subpart for PM, non-Hg HAP metals, HCl, HF, or Hg through use of CPMS, initial compliance is determined using the average hourly PM, non-Hg HAP metals, HCl, HF, or Hg concentrations obtained during the first 30 day operating period.
(e)
(f)
(g) For existing affected sources, you must demonstrate initial compliance no later than 180 days after the compliance 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 10 to this subpart.
(h) If your new or reconstructed affected source commenced construction or reconstruction between May 3, 2011 and [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE
(i) If your new or reconstructed affected source commenced construction or reconstruction between May 3, 2011, and [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE
(j) If your new or reconstructed affected source commences construction or reconstruction after [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE
(k)
(1) With the exception of mercury, emissions less than 50 percent of the appropriate emissions limitation, or
(2) For mercury, emissions less than 10 percent of the mercury emissions limitation or less than 22.0 pounds per year. Only existing affected units may qualify for LEE status for Hg. When qualifying for LEE status for Hg emissions less than 22.0 pounds per year, the affected unit must also demonstrate compliance with the applicable emission limitation.
(3) The following provisions apply in demonstrating that a unit qualifies as a LEE. For all pollutants or surrogates except for Hg, conduct the initial performance tests as described in § 63.10007 but note that the required minimum sampling volume must be increased nominally by a factor of two; follow the instructions in Table 5 to this subpart to convert the test data to the units of the applicable standard. For Hg, you must conduct a 28 to 30 operating day performance test, using Method 30B in appendix A-8 to part 60 of this chapter, to determine Hg concentration. 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-8 to part 60 of this chapter and conduct at least three nominally equal length test runs over the 28 to 30 day test period. You may not use a pair of sorbent traps to sample the stack gas for more than 10 days. Collect diluent gas data over the corresponding time period, and if preferred for calculation of pounds per year of Hg, stack flow rate data using Method 2 in appendix A-1 to part 60 of this chapter or a certified flow rate monitor and moisture data using Method 4 in appendix A-1 to part 60 of this chapter or a moisture monitor. Record parametric data during each performance test, to establish operating limits, in accordance with the applicable provisions of § 63.10010(k)(3). Calculate the average Hg concentration, in μg/m
(1) Startup and Shutdown default values for calculations. For the purposes of this rule and only during periods of startup or shutdown, use a default diluent gas concentration value of 10.0 percent O
(a) For solid oil-derived fuel- and coal-fired EGUs using total PM emissions as a surrogate for non-Hg HAP metals emissions and using PM CEMS to measure filterable PM emissions as a surrogate for total PM emissions, you must conduct all applicable performance tests for PM and non-Hg HAP metals emissions during the same compliance test period and under the same process (
(b) For solid oil-derived fuel- and coal-fired EGUs with installed systems that use wet or dry flue gas desulfurization technology using sulfur dioxide (SO
(c) For affected units meeting the LEE requirements of § 63.1005(k), provided that the unit operates within the operating limits established during the initial performance test, you need only repeat the performance test once every 5 years according to Table 5 and § 63.10007 and conduct fuel sampling and analysis according to Table 6 and § 63.10008 at least every month. However, if the unit fails to operate within the operating limits during any 5 year compliance period, LEE status is lost. If this should occur:
(1) For all pollutants or surrogates except for Hg, you must initiate periodic emission testing, as required in the applicable paragraph(s) of this section, within a six month period.
(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 a one year period.
(d) For solid oil-derived fuel- and coal-fired EGUs without PM CEMS but with PM emissions control devices, you must conduct all applicable performance tests for PM and non-Hg HAP metals emissions during the same compliance test period and under the same process (
(e) For solid oil-derived fuel- and coal-fired EGUs without PM CEMS and without PM emissions control devices, you must conduct all applicable performance tests for non-Hg HAP metals emissions according to Table 5 and § 63.10007 at least every month.
(f) For liquid oil-fired EGUs with non-Hg HAP metals control devices, you must conduct all applicable performance tests for individual or total HAP metals emissions according to Table 5 and § 63.10007 at least every other month.
(g) For liquid oil-fired EGUs without non-Hg HAP metals control devices, you must conduct all applicable performance tests for individual or total HAP metals emissions according to Table 5 and § 63.10007 at least every month.
(h) For solid oil-derived fuel- and coal-fired EGUs without SO
(i) For solid oil-derived fuel- and coal-fired EGUs without SO
(j) For solid oil-derived fuel- and coal-fired EGUs without HCl CEMS but with HCl emissions control devices, you must conduct all applicable performance tests for HCl emissions according to Table 5 and § 63.10007 at least every other month.
(k) For solid oil-derived fuel- and coal-fired EGUs without HCl CEMS and without HCl emissions control devices, you must conduct all applicable performance tests for HCl emissions according to Table 5 and § 63.10007 at least every month.
(l) For liquid oil-fired EGUs without HCl and HF CEMS but with HCl and HF emissions control devices, you must conduct all applicable performance tests for HCl and HF emissions according to Table 5 and § 63.10007 at least every other month.
(m) For liquid oil-fired EGUs without HCl and HF CEMS and without HCl and HF emissions control devices, you must conduct all applicable performance tests for HCl and HF emissions according to Table 5 and § 63.10007 at least every month.
(n) Unless you follow the requirements listed in paragraphs (o) through (q) of this section, performance tests required at least every 5 years must be completed within 58 to 62 months after the previous performance test; performance tests required at least every year must be completed no more than 13 months after the previous performance test; performance tests required at least every 2 months must be completed between 52 and 69 days after the previous performance test; and performance tests required at least every month must be completed between 21 and 38 days after the previous performance test.
(o) For EGUs with annual or more frequent performance testing requirements, you can conduct performance stack tests less often for a given pollutant if your performance stack tests for the pollutant for at least 3 consecutive years show that your emissions are at or below 50 percent of the emissions limit, and if there are no changes in the operation of the affected source or air pollution control equipment that could increase emissions. In this case, you do not have to conduct a performance test for that pollutant for the next 2 years. You must conduct a performance test during the third year and no more than 37 months after the previous performance test. If you elect to demonstrate compliance using emission averaging under § 63.10009, you must continue to conduct performance stack tests at the appropriate frequency given in section (c) through (m) of this paragraph.
(p) If your EGU continues to meet the emissions limit for the pollutant, you may choose to conduct performance stack tests for the pollutant every third year if your emissions are at or below the emission limit, and if there are no changes in the operation of the affected source or air pollution control equipment that could increase emissions, but each such performance test must be conducted no more than 37 months after the previous performance test. If you elect to demonstrate compliance using emission averaging under § 63.10009, you must continue to conduct performance stack tests at the appropriate frequency given in section (c) through (m) of this paragraph.
(q) If a performance test shows emissions in excess of 50 percent of the emission limit, you must conduct performance tests at the appropriate frequency given in section (c) through (m) of this paragraph for that pollutant until all performance tests over a consecutive 3-year period show compliance.
(r) If you are required to meet an applicable tune-up work practice standard, you must conduct a performance tune-up according to § 63.10007. Each performance tune-up specified in § 63.10007 must be no more than 18 months after the previous performance tune-up.
(s) If you demonstrate compliance with the Hg, individual or total non-Hg HAP metals, HCl, or HF emissions limit based on fuel analysis, you must conduct a monthly fuel analysis according to § 63.10008 for each type of fuel burned. If you burn a new type of fuel, you must conduct a fuel analysis before burning the new type of fuel in your EGU. You must still meet all applicable continuous compliance requirements in § 63.10021.
(t) You must report the results of performance tests, performance tune-ups, and fuel analyses within 60 days after the completion of the performance tests, performance tune-ups, and fuel analyses. This report must also verify that the operating limits for your affected EGU have not changed or provide documentation of revised operating parameters established according to § 63.10011 and Table 7 to this subpart, as applicable. The reports for all subsequent performance tests must include all applicable information required in § 63.10031.
(a) You must conduct all performance tests according to § 63.7(c), (d), (f), and (h). You must also develop a site-specific test plan according to the requirements in § 63.7(c).
(b) You must conduct each performance test according to the requirements in Table 5 to this subpart.
(c) You must conduct each performance test under the specific conditions listed in Tables 5 and 7 to this subpart. You must conduct performance tests at the maximum normal operating load while burning the type of fuel or mixture of fuels that has the highest content of chlorine, fluorine, non-Hg HAP metals, and Hg, and you must demonstrate initial compliance and establish your operating limits based on these tests. These requirements could result in the need to conduct more than one performance test. Moreover, should you desire to have differing operating limits which correspond to loads other than maximum normal operating load, you should conduct testing at those other loads to determine those other operating limits. Following each performance test and until the next performance test, you must comply with the operating limit for operating load conditions specified in Table 4 of this subpart.
(d) For performance testing that does not involve CMS or a sorbent trap monitoring system, you must conduct three separate test runs for each performance test required, as specified in § 63.7(e)(3). Each test run must comply with the minimum applicable sampling times or volumes specified in Tables 1 and 2 to this subpart. For performance testing that involves CMS or a sorbent trap monitoring system, compliance shall be determined as described in § 63.10005(d) and (e).
(e) To determine compliance with the emission limits, you must use the F-Factor methodology and equations in sections 12.2 and 12.3 of EPA Method 19 at 40 CFR part 60, Appendix A-7 of this chapter to convert the measured PM concentrations, the measured HCl and HF concentrations, the measured SO
(f) Performance tests shall be conducted under such conditions as the EPA Administrator specifies to the owner or operator based on
(a) You must conduct performance fuel analysis tests according to the procedures in paragraphs (b) through (e) of this section and Table 6 to this subpart, as applicable. You are not required to conduct fuel analyses for fuels used only for startup, unit shutdown, or transient flame stability purposes.
(b) You must develop and submit a site-specific fuel analysis plan to the EPA Administrator for review and approval according to the following procedures and requirements in paragraphs (b)(1) and (2) of this section.
(1) You must submit the fuel analysis plan no later than 60 days before the date that you intend to demonstrate compliance.
(2) You must include the information contained in paragraphs (b)(2)(i) through (vi) of this section in your fuel analysis plan.
(i) The identification of all fuel types anticipated to be burned in each EGU.
(ii) For each fuel type, the notification of whether you or a fuel supplier will be conducting the fuel analysis.
(iii) For each fuel type, a detailed description of the sample location and specific procedures to be used for collecting and preparing the composite samples if your procedures are different from paragraph (c) or (d) of this section. Samples should be collected at a location that most accurately represents the fuel type, where possible, at a point prior to mixing with other dissimilar fuel types.
(iv) For each fuel type, the analytical methods from Table 6, with the expected minimum detection levels, to be used for the measurement of chlorine, fluorine, non-Hg HAP metals, or Hg.
(v) If you request to use an alternative analytical method other than those required by Table 6 to this subpart, you must also include a detailed description of the methods and procedures that you are proposing to use. Methods in Table 6 shall be used until the requested alternative is approved.
(vi) If you will be using fuel analysis from a fuel supplier in lieu of site-specific sampling and analysis, the fuel supplier must use the analytical methods required by Table 6 to this subpart.
(c) At a minimum, you must obtain three composite fuel samples for each fuel type according to the procedures in paragraph (c)(1) or (2) of this section.
(1) If sampling from a belt (or screw) feeder, collect fuel samples according to paragraphs (c)(1)(i) and (ii) of this section.
(i) Stop the belt and withdraw a 6-inch wide sample from the full cross-section of the stopped belt to obtain a minimum two pounds of sample. You must collect all the material (fines and coarse) in the full cross-section. You must transfer the sample to a clean plastic bag.
(ii) Each composite sample will consist of a minimum of three samples collected at approximately equal 1-hour intervals during the testing period.
(2) If sampling from a fuel pile or truck, you must collect fuel samples according to paragraphs (c)(2)(i) through (iii) of this section.
(i) For each composite sample, you must select a minimum of five sampling locations uniformly spaced over the surface of the pile.
(ii) At each sampling site, you must dig into the pile to a depth of 18 inches. You must insert a clean flat square shovel into the hole and withdraw a sample, making sure that large pieces do not fall off during sampling.
(iii) You must transfer all samples to a clean plastic bag for further processing.
(d) You must prepare each composite sample according to the procedures in paragraphs (d)(1) through (7) of this section.
(1) You must thoroughly mix and pour the entire composite sample over a clean plastic sheet.
(2) You must break sample pieces larger than 3 inches into smaller sizes.
(3) You must make a pie shape with the entire composite sample and subdivide it into four equal parts.
(4) You must separate one of the quarter samples as the first subset.
(5) If this subset is too large for grinding, you must repeat the procedure in paragraph (d)(3) of this section with the quarter sample and obtain a one-quarter subset from this sample.
(6) You must grind the sample in a mill.
(7) You must use the procedure in paragraph (d)(3) of this section to obtain a one-quarter subsample for analysis. If the quarter sample is too large, subdivide it further using the same procedure.
(e) You must determine the concentration of pollutants in the fuel (Hg, HAP metals, and/or chlorine) in units of lb/MMBtu of each composite sample for each fuel type according to the procedures in Table 6 to this subpart.
(a) As an alternative to meeting the requirements of § 63.9991 for PM, HF, HCl, non-Hg HAP metals, or Hg on an EGU-specific basis, if 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), you may demonstrate compliance by emission averaging among the existing EGUs in the same subcategory, if your averaged emissions for such EGUs are equal to or less than the applicable emission limit, according to the procedures in this section.
(b) Separate stack requirements. For a group of two or more existing EGUs in the same subcategory that each vent to a separate stack, you may average PM, HF, HCl, non-Hg HAP metals, or Hg emissions to demonstrate compliance with the limits in Table 2 to this subpart if you satisfy the requirements in paragraphs (c), (d), (e), (f), and (g) of this section.
(c) For each existing EGU in the averaging group, the emission rate achieved during the initial compliance test for the HAP being averaged must not exceed the emission level that was being achieved on [
(d) The averaged 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 in § 63.9984.
(e) You must demonstrate initial compliance according to paragraph (e)(1) or (2) of this section using the maximum normal operating load of each EGU and the results of the initial performance tests or fuel analysis.
(1) You must use Equation 1 of this section to demonstrate that the PM, HF, SO
(2) If you are not capable of monitoring heat input, and the EGU generates steam for purposes other than generating electricity, you may use Equation 2 of this section as an alternative to using Equation 1 of this section to demonstrate that the PM, HF, HCl, non-Hg HAP metals, and Hg emissions from all existing units participating in the emissions averaging option do not exceed the emission limits in Table 2 to this subpart.
(f) You must demonstrate compliance on a monthly basis determined at the end of every month (12 times per year) according to paragraphs (f)(1) through (3) of this section. The first monthly period begins on the compliance date specified in § 63.9984.
(1) For each calendar month, you must use Equation 3 of this section to calculate the monthly average weighted emission rate using the actual heat capacity for each existing unit participating in the emissions averaging option.
(2) If you are not capable of monitoring heat input, you may use Equation 4 of this section as an alternative to using Equation 3 of this section to calculate the monthly weighted emission rate using the actual steam generation from the units participating in the emissions averaging option.
(3) Until 12 monthly weighted average emission rates have been accumulated, calculate and report only the monthly
(g) You must develop, and submit to the applicable regulatory authority for review and approval upon request, an implementation plan for emission averaging according to the following procedures and requirements in paragraphs (g)(1) through (4) of this section.
(1) You must submit the implementation plan no later than 180 days before the date that the facility intends to demonstrate compliance using the emission averaging option.
(2) You must include the information contained in paragraphs (g)(2)(i) through (vii) of this section in your implementation plan for all emission sources included in an emissions average:
(i) The identification of all existing EGUs in the averaging group, including for each either the applicable HAP emission level or the control technology installed as of [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE
(ii) The process parameter (heat input 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 emissions from multiple EGUs, the owner or operator must identify each EGU;
(iv) The test plan for the measurement of PM, HF, HCl, individual or total non-Hg HAP metals, or Hg emissions in accordance with the requirements in § 63.10007;
(v) The operating parameters to be monitored for each control system or device consistent with § 63.9991 and Table 4, and a description of how the operating limits will be determined;
(vi) If you request to monitor an alternative operating parameter pursuant to § 63.10010, you must also include:
(A) A description of the parameter(s) to be monitored and an explanation of the criteria used to select the parameter(s); and
(B) A description of the methods and procedures that will be used to demonstrate that the parameter indicates proper operation of the control device; the frequency and content of monitoring, reporting, and recordkeeping requirements; and a demonstration, to the satisfaction of the applicable regulatory authority, that the proposed monitoring frequency is sufficient to represent control device operating conditions; and
(vii) A demonstration that compliance with each of the applicable emission limit(s) will be achieved under representative operating conditions.
(3) The regulatory authority shall review and approve or disapprove the plan according to the following criteria:
(i) Whether the content of the plan includes all of the information specified in paragraph (g)(2) of this section; and
(ii) Whether the plan presents sufficient information to determine that compliance will be achieved and maintained.
(4) The applicable regulatory authority shall not approve an emission averaging implementation plan containing any of the following provisions:
(i) Any averaging between emissions of differing pollutants or between differing sources; or
(ii) The inclusion of any emission source other than an existing unit in the same subcategory.
(h)
(i) For a group of two or more existing units in the same subcategory, each of which vents 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.
(j) For all other groups of units subject to paragraph (h) of this section, the owner or operator may elect to:
(1) Conduct performance tests according to procedures specified in § 63.10007 in the common stack if affected units from other subcategories vent to the common stack. The emission limits that the group must comply with are determined by the use of equation 6.
(2) Conduct performance tests according to procedures specified in § 63.10007 in the common stack. If affected units from nonaffected units vent to the common stack,the units from nonaffected units must be shut down or vented to a different stack during the performance test or each affected and each nonaffected unit must meet the most stringent emissions limit; and
(3) Meet the applicable operating limit specified in § 63.10021 and Table 8 to this subpart for each emissions control system (except that, if each unit venting to the common stack has an applicable opacity operating limit, then a single continuous opacity monitoring system may be located in the common stack instead of in each duct to the common stack).
(k) Combination requirements. The common stack of a group of two or more existing EGUs in the same subcategory subject to paragraph (h) of this section may be treated as a single stack for purposes of paragraph (b) of this section and included in an emissions averaging group subject to paragraph (b) of this section.
(a) In some cases, existing affected units may exhaust through a common stack configuration or may include a bypass stack. Emission monitoring system installation provisions for possible stack configurations are as follows.
(1)
(2)
(i) Install CEMS and sorbent trap monitoring systems described in this section in the duct to the common stack from each unit; or
(ii) Install CEMS and sorbent trap monitoring systems described in this section in the common stack.
(3)
(i) Install CEMS and sorbent trap monitoring systems described in this section in the duct to the common stack from each affected unit; or
(ii) Install CEMS 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).
(4)
(5)
(i) Install CEMS and sorbent trap monitoring systems described in this section in each of the multiple stacks; or
(ii) Install CEMS and sorbent trap monitoring systems described in this section in each of the ducts that feed into the stack.
(b) If you use an oxygen (O
(1) Install, operate, and maintain the O
(2) Conduct a performance evaluation of the CEMS according to the requirements in § 63.8 and according to PS 3 of 40 CFR part 60, Appendix B.
(3) Design and operate the CEMS to complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15-minute period.
(4) Reduce the CEMS data as specified in § 63.8(g)(2) and (4).
(5) Consistent with § 63.10020, calculate and record a 30 boiler operating day rolling average emissions rate on a daily basis. Daily, calculate a new 30 boiler operating day rolling average emissions rate as the average of all of the hourly oxygen emissions data for the preceding 30 boiler operating days.
(c) If you use an HCl CEMS, install, operate, and maintain a CEMS for HCl according to the procedures in paragraphs (c)(1) through (5) of this section by the compliance date specified in § 63.9984. The HCl shall be monitored at the outlet of the EGU.
(1) Install, operate, and maintain the CEMS according to the applicable procedures under Performance Specification (PS) 15 or 6 of 40 CFR part 60, Appendix B; and according to the applicable procedures under Quality Assurance Procedure 1 of 40 CFR part 60, Appendix F; and according to the site-specific monitoring plan developed according to § 63.10000(d).
(2) Conduct a performance evaluation of the CEMS according to the requirements in § 63.8 and according to PS 15 or 6 of 40 CFR part 60, Appendix B.
(3) Design and operate the CEMS to complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15-minute period.
(4) Reduce the CEMS data as specified in § 63.8(g)(2) and (4).
(5) Consistent with § 63.10020, calculate and record a 30 boiler operating day rolling average emissions rate on a daily basis. Daily, calculate a new 30 boiler operating day rolling average emissions rate as the average of all of the hourly HCl emissions data for the preceding 30 boiler operating days.
(d) If you use an HF CEMS, install, operate, and maintain a CEMS for HF according to the procedures in paragraphs (d)(1) through (5) of this section by the compliance date specified in § 63.9984. The HF shall be monitored at the outlet of the EGU.
(1) Install, operate, and maintain the CEMS according to the applicable procedures under Performance Specification (PS) 15 of 40 CFR part 60, Appendix B; and according to the applicable procedures under Quality Assurance Procedure 1 of 40 CFR part 60, Appendix F; and according to the site-specific monitoring plan developed according to § 63.10000(d).
(2) Conduct a performance evaluation of the CEMS according to the requirements in § 63.8 and according to PS 15 or 6 of 40 CFR part 60, Appendix B.
(3) Design and operate the CEMS to complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15-minute period.
(4) Reduce the CEMS data as specified in § 63.8(g)(2) and (4).
(5) Consistent with § 63.10020, calculate and record a 30 boiler operating day rolling average emissions rate on a daily basis. Daily, calculate a new 30 boiler operating day rolling average emissions rate as the average of all of the hourly HF emissions data for the preceding 30 boiler operating days.
(e) If you use an SO
(1) Install, operate, and maintain the CEMS according to the applicable procedures under Performance Specification (PS) 2 of 40 CFR part 60, Appendix B; and according to the applicable procedures under Quality Assurance Procedure 1 of 40 CFR part 60, Appendix F; and according to the site-specific monitoring plan developed according to § 63.10000(d).
(2) Conduct a performance evaluation of the CEMS according to the
(3) Design and operate the CEMS to complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15-minute period.
(4) Reduce the CEMS data as specified in § 63.8(g)(2) and (4).
(5) Consistent with § 63.10020, calculate and record a 30 boiler operating day rolling average emissions rate on a daily basis. Daily, calculate a new 30 boiler operating day rolling average emissions rate is calculated as the average of all of the hourly SO
(6) When electing to use a Part 75 certified SO
(i) You must perform the 7-day calibration error test required in appendix A to Part 75 on the SO
(ii) You must perform the linearity check test required in appendix A to Part 75 on the SO
(iii) The initial and quarterly linearity checks required under appendix A and appendix B of Part 75 must include a calibration gas (at a fourth level, if necessary) nominally at a concentration level equivalent to the applicable emission limit.
(f) If you use a Hg CEMS or a sorbent trap monitoring system for Hg, install, operate, and maintain the monitoring system in accordance with Appendix A to this subpart.
(g) If you use a PM CEMS, install, operate, and maintain a CEMS for PM according to the procedures in paragraphs (g)(1) through (6) of this section by the compliance date specified in § 63.9984. The PM shall be monitored at the outlet of the EGU.
(1) Install, operate, and maintain according to the applicable procedures under Performance Specification (PS) 11 of 40 CFR part 60, Appendix B; and according to the applicable procedures under Quality Assurance Procedure 2 of 40 CFR part 60, Appendix F; and according to the site-specific monitoring plan developed according to § 63.10000(d).
(2) Conduct a performance evaluation of the CEMS according to the requirements in § 63.8 and according to PS 11 of 40 CFR part 60, Appendix B.
(3) Design and operate the CEMS to complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15-minute period.
(4) Reduce the CEMS data as specified in § 63.8(g)(2) and (4).
(5) Consistent with § 63.10020, calculate and record a 30 boiler operating-day rolling average emissions rate on a daily basis. Daily, calculate a new 30 boiler operating day rolling average emissions rate is calculated as the average of all of the hourly particulate emissions data for the preceding 30 boiler operating days.
(h) If you are required to install a continuous parameter monitoring system (CPMS) as specified in Table 5 of this subpart, you must install, operate, and maintain each CPMS according to the requirements in paragraphs (h)(1) through (3) of this section by the compliance date specified in § 63.9984.
(1) Install, operate, and maintain each CPMS according to the procedures in your approved site-specific monitoring plan developed in accordance with § 63.10000(d) of this subpart and the design criteria and quality assurance and quality control procedures specified in paragraphs (h)(1) through (3) of this section. You may request approval of monitoring system quality assurance and quality control procedures alternative to those specified in paragraphs (h)(1) through (3) of this section in your site-specific monitoring plan.
(2) Design and operate the CPMS to collect and record data measurements at least once every 15 minutes (see also § 63.10020), to reduce the measured values to a hourly averages or other appropriate period (e.g., instantaneous alarms) for calculating operating values in terms of the applicable averaging period, and to meet the specific CPMS requirements given in (i) through (v) of this section.
(i) If you have an operating limit that requires the use of a flow monitoring system, you must meet the requirements in (i)(A) through (D) of this section.
(A) Install the flow sensor and other necessary equipment in a position that provides a representative flow.
(B) Use a flow sensor with a measurement sensitivity of no greater than 2 percent of the expected flow rate.
(C) Minimize the effects of swirling flow or abnormal velocity distributions due to upstream and downstream disturbances.
(D) Conduct a flow monitoring system performance evaluation in accordance with your monitoring plan at the time of each performance test but no less frequently than annually.
(ii) If you have an operating limit that requires the use of a pressure monitoring system, you must meet the requirements in (ii)(A) through (F) of this section.
(A) Install the pressure sensor(s) in a position that provides a representative measurement of the pressure (e.g., PM scrubber pressure drop).
(B) Minimize or eliminate pulsating pressure, vibration, and internal and external corrosion.
(C) Use a pressure sensor with a minimum tolerance of 1.27 centimeters of water or a minimum tolerance of 1 percent of the pressure monitoring system operating range, whichever is less.
(D) Perform checks at least once each boiler operating day to ensure pressure measurements are not obstructed (e.g., check for pressure tap pluggage daily).
(E) Conduct a performance evaluation of the pressure measurement monitoring system in accordance with your monitoring plan at the time of each performance test but no less frequently than annually.
(F) If at any time the measured pressure exceeds the manufacturer's specified maximum operating pressure range, conduct a performance evaluation of the pressure monitoring system in accordance with your monitoring plan and confirm that the pressure monitoring system continues to meet the performance requirements in your monitoring plan. Alternatively, install and verify the operation of a new pressure sensor.
(iii) If you have an operating limit that requires a total secondary electric power monitoring system for an electrostatic precipitator (ESP), you must meet the requirements in (iii)(A) through (B) of this section.
(A) Install sensors to measure (secondary) voltage and current to the precipitator plates.
(B) Conduct a performance evaluation of the electric power monitoring system in accordance with your monitoring plan at the time of each performance test but no less frequently than annually.
(iv) If you have an operating limit that requires the use of a monitoring system to measure sorbent injection rate (e.g., weigh belt, weigh hopper, or hopper flow measurement device), you must meet the requirements in (iv)(A) through (B) of this section.
(A) Install each system in a position that provides a representative measurement of the total sorbent injection rate.
(B) Conduct a performance evaluation of the sorbent injection rate monitoring system in accordance with your
(v) If you have an operating limit that requires the use of a fabric filter bag leak detection system to comply with the requirements of this subpart, you must install, calibrate, maintain, and continuously operate a bag leak detection system as specified in (v)(A) through (F) of this section.
(A) Install a bag leak detection sensor(s) in a position(s) that will be representative of the relative or absolute PM loadings for each exhaust stack, roof vent, or compartment (e.g., for a positive pressure fabric filter) of the fabric filter.
(B) Use a bag leak detection system certified by the manufacturer to be capable of detecting PM emissions at concentrations of 10 milligrams per actual cubic meter or less.
(C) Conduct a performance evaluation of the bag leak detection system in accordance with your monitoring plan and consistent with the guidance provided in EPA-454/R-98-015 (incorporated by reference, see § 63.14).
(D) Use a bag leak detection system equipped with a device to continuously record the output signal from the sensor.
(E) Use a bag leak detection system equipped with a system that will alert when an increase in relative PM emissions over a preset level is detected. The alarm must be located where it can be detected and recognized easily by an operator.
(F) Where multiple bag leak detectors are required, the system's instrumentation and alarm may be shared among detectors.
(3) Conduct the CPMS equipment performance evaluations as specified in your site-specific monitoring plan.
(a) You must demonstrate initial compliance with each emission limit that applies to you by conducting initial performance tests and fuel analyses and establishing operating limits, as applicable, according to § 63.10007, paragraph (c) of this section, and Tables 5 and 7 to this subpart.
(b) If you demonstrate compliance through performance testing, you must establish each site-specific operating limit in Table 4 to this subpart that applies to you according to the requirements in § 63.10007, Table 7 to this subpart, and paragraph (c)(6) of this section, as applicable. You must also conduct fuel analyses according to § 63.10008 and establish maximum fuel pollutant input levels according to paragraphs (c)(1) through (5) of this section, as applicable.
(1) You must establish the maximum chlorine fuel input (C
(i) You must determine the fuel type or fuel mixture that you could burn in your EGU that has the highest content of chlorine.
(ii) During the performance testing for HCl, you must determine the fraction of the total heat input for each fuel type burned (Q
(iii) You must establish a maximum chlorine input level using Equation 7 of this section.
(2) You must establish the maximum Hg fuel input level (Mercury
(i) You must determine the fuel type or fuel mixture that you could burn in your EGU that has the highest content of Hg.
(ii) During the compliance demonstration for Hg, you must determine the fraction of total heat input for each fuel burned (Q
(iii) You must establish a maximum Hg input level using Equation 8 of this section.
(3) You must establish the maximum non-Hg HAP metals fuel input level (HAP metal
(i) You must determine the fuel type or fuel mixture that you could burn in your EGU that has the highest content of non-Hg HAP metals.
(ii) During the compliance demonstration for non-Hg HAP metals, you must determine the fraction of total heat input for each fuel burned (Q
(iii) You must establish a maximum non-Hg HAP metal input level using Equation 9 of this section.
(4) You must establish the maximum fluorine fuel input (F
(i) You must determine the fuel type or fuel mixture that you could burn in your EGU that has the highest content of fluorine.
(ii) During the performance testing for HF, you must determine the fraction of the total heat input for each fuel type burned (Q
(iii) You must establish a maximum fluorine input level using Equation 10 of this section.
(6) You must establish parameter operating limits according to paragraphs (c)(4)(i) through (v) of this section.
(i) For a wet PM scrubber, you must establish the minimum liquid flow rate and pressure drop as defined in § 63.10042, as your operating limits during the three-run performance test. If you use a wet PM scrubber and you conduct separate performance tests for PM, non-Hg HAP metals, or Hg emissions, you must establish one set of minimum liquid flow rate and pressure drop operating limits. If you conduct multiple performance tests, you must set the minimum liquid flow rate and pressure drop operating limits at the highest minimum hourly average values established during the performance tests.
(ii) For a wet acid gas scrubber, you must establish the minimum liquid flow rate and pH as defined in § 63.10042, as your operating limits during the three-run performance test. If you use a wet acid gas scrubber and you conduct separate performance tests for HCl, HF, or SO
(iii) For an electrostatic precipitator, you must establish the minimum hourly average secondary voltage and secondary amperage and calculate the total secondary power input as measured during the three-run performance test and as defined in § 63.10042, as your operating limit.
(iv) For a dry scrubber or dry sorbent injection (DSI) system, you must establish the minimum hourly average sorbent injection rate for each sorbent, as measured during the three-run performance test and as defined in § 63.10042, as your operating.
(v) The operating limit for EGUs with fabric filters that choose to demonstrate continuous compliance through bag leak detection systems is that a bag leak detection system be installed according to the requirements in § 63.10010, and that the sum duration of bag leak detection system alarms does not exceed 5 percent of the process operating time during a 6-month period.
(c) If you elect to demonstrate compliance with an applicable emission limit through fuel analysis, you must conduct fuel analyses according to § 63.10008 and follow the procedures in paragraphs (c)(1) through (7) of this section.
(1) If you burn more than one fuel type, you must determine the fuel mixture you could burn in your EGU that would result in the maximum emission rates of the pollutants that you elect to demonstrate compliance through fuel analysis.
(2) You must determine the 90th percentile confidence level fuel pollutant concentration of the composite samples analyzed for each fuel type using the one-sided z-statistic test described in Equation 11 of this section.
(3) To demonstrate compliance with the applicable emission limit for HCl, the HCl emission rate that you calculate for your EGU using Equation 12 of this section must not exceed the applicable emission limit for HCl.
(4) To demonstrate compliance with the applicable emission limit for Hg, the Hg emissions rate that you calculate for your EGU using Equation 13 of this section must not exceed the applicable emission limit for Hg.
(5) To demonstrate compliance with the applicable emission limit for non-Hg HAP metals, the non-Hg HAP metal emissions rate that you calculate for your EGU using Equation 14 of this
(6) To demonstrate compliance with the applicable emission limit for HF, the HF emissions rate that you calculate for your EGU using Equation 15 of this section must not exceed the applicable emission limit for HF.
(d) For units combusting coal or solid oil-derived fuel and electing to use PM as a surrogate for non-Hg HAP metals, you must install, certify, and operate PM CEMS in accordance with Performance Specification (PS) 11 in Appendix B to 40 CFR part 60, and to perform periodic, ongoing quality assurance (QA) testing of the CEMS according to QA Procedure 2 in Appendix F to 40 CFR Part 60. You must determine an operating limit (PM concentration in mg/dscm) during performance testing for initial PM compliance. The operating limit will be the average of the PM filterable results of the three Method 5 performance test runs. To determine continuous compliance, the hourly average PM concentrations will be averaged on a rolling 30 boiler operating day basis. Each 30 boiler operating day average would have to meet the PM operating limit.
(e) You must submit the Notification of Compliance Status containing the results of the initial compliance demonstration according to the requirements in § 63.10030(e).
(f) If you are a LEE, the results of your initial performance test demonstrate your initial compliance.
(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. A monitoring system malfunction is any sudden, infrequent, not reasonably preventable failure of the monitoring system to provide valid data. Monitoring system failures that are caused in part by poor maintenance or careless operation are not malfunctions. 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 monitoring system malfunctions or out-of-control periods, repairs associated with monitoring system malfunctions or 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 out-of-control periods, repairs associated with monitoring system malfunctions or 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 emission limit, operating limit, and work practice standard in Tables 1 through 4 to this subpart that applies to you according to the methods specified in Table 8 to this subpart and paragraphs (a)(1) through (17) of this section.
(1) Following the date on which the initial performance test is completed or is required to be completed under §§ 63.7 and 63.10005, whichever date comes first, you must not operate above any of the applicable maximum operating limits or below any of the applicable minimum operating limits listed in Table 4 to this subpart at any time. Operation above the established maximum or below the established minimum operating limits shall constitute a deviation of established operating limits. Operating limits must be confirmed or reestablished during performance tests.
(2) As specified in § 63.10031(c), you must keep records of the type and amount of all fuels burned in each EGU during the reporting period to demonstrate that all fuel types and mixtures of fuels burned would either result in lower emissions of HCl, HF, SO
(3) If you demonstrate compliance with an applicable HCl emissions limit through fuel analysis and you plan to burn a new type of fuel, you must recalculate the HCl emissions rate using Equation 15 of § 63.10011 according to paragraphs (a)(3)(i) through (iii) of this section.
(i) You must determine the chlorine concentration for any new fuel type in units of lb/MMBtu, based on supplier data or your own fuel analysis, according to the provisions in your site-specific fuel analysis plan developed according to § 63.10008(b).
(ii) You must determine the new mixture of fuels that will have the highest content of chlorine.
(iii) Recalculate the HCl emissions rate from your EGU under these new conditions using Equation 15 of § 63.10011. The recalculated HCl emissions rate must be less than the applicable emission limit.
(4) If you demonstrate compliance with an applicable HCl emissions limit through performance testing and you plan to burn a new type of fuel or a new mixture of fuels, you must recalculate the maximum chlorine input using Equation 7 of § 63.10011. If the results of recalculating the maximum chlorine input using Equation 7 of § 63.10011 are higher than the maximum chlorine input level established during the previous performance test, then you must conduct a new performance test within 60 days of burning the new fuel type or fuel mixture according to the procedures in § 63.10007 to demonstrate that the HCl emissions do not exceed the emissions limit. You must also establish new operating limits based on this performance test according to the procedures in § 63.10011(b).
(5) If you are a liquid oil-fired EGU and demonstrate compliance with an applicable individual Hg emissions limit (rather than the total HAP metal emission limit) through fuel analysis, and you plan to burn a new type of fuel, you must recalculate the Hg emissions rate using Equation 11 of § 63.10011 according to the procedures specified in paragraphs (a)(5)(i) through (iii) of this section.
(i) You must determine the Hg concentration for any new fuel type in units of lb/TBtu, based on supplier data or your own fuel analysis, according to the provisions in your site-specific fuel analysis plan developed according to § 63.10008(b).
(ii) You must determine the new mixture of fuels that will have the highest content of Hg.
(iii) Recalculate the Hg emissions rate from your EGU under these new conditions using Equation 11 of § 63.10011. The recalculated Hg emission rate must be less than the applicable emission limit.
(6) If you demonstrate compliance with an applicable Hg emissions limit through performance testing, and you plan to burn a new type of fuel or a new mixture of fuels, you must recalculate the maximum Hg input using Equation 8 of § 63.10011. If the results of recalculating the maximum Hg input using Equation 8 of § 63.10011 are higher than the maximum Hg input level established during the previous performance test, then you must conduct a new performance test within 60 days of burning the new fuel type or fuel mixture according to the procedures in § 63.10007 to demonstrate that the Hg emissions do not exceed the emissions limit. You must also establish new operating limits based on this performance test according to the procedures in § 63.10011(b).
(7) If you are a liquid oil-fired EGU and demonstrate compliance with an applicable HAP metals emission limit through fuel analysis, and you plan to burn a new type of fuel, you must recalculate the HAP metals emission rate using Equation 14 of § 63.10011 according to the procedures specified in paragraphs (a)(7)(i) through (iii) of this section.
(i) You must determine the HAP metals concentration for any new fuel type in units of lb/MMBtu, based on supplier data or your own fuel analysis, according to the provisions in your site-specific fuel analysis plan developed according to § 63.10008(b).
(ii) You must determine the new mixture of fuels that will have the highest content of HAP metals.
(iii) Recalculate the HAP metals emission rate from your EGU under these new conditions using Equation 14 of § 63.10011. The recalculated HAP metals emission rate must be less than the applicable emissions limit.
(8) If you demonstrate compliance with an applicable HAP metals emissions limit through performance testing, and you plan to burn a new type of fuel or a new mixture of fuels, you must recalculate the maximum HAP metals input using Equation 9 of § 63.10011. If the results of recalculating the maximum Hg input using Equation 9 of § 63.10011 are higher than the maximum HAP metals input level established during the previous performance test, then you must conduct a new performance test within 60 days of burning the new fuel type or fuel mixture according to the procedures in § 63.10007 to demonstrate that the HAP metal emissions do not exceed the emissions limit. You must also establish new operating limits based on this performance test according to the procedures in § 63.10011(b).
(9) If your unit is controlled with a fabric filter, and you demonstrate continuous compliance using a bag leak detection system, you must initiate corrective action within 1 hour of a bag leak detection system alarm and complete corrective actions as soon as practical, and operate and maintain the fabric filter system such that the sum duration of alarms does not exceed 5 percent of the process operating time during a 6-month period. You must also keep records of the date, time, and duration of each alarm, the time corrective action was initiated and completed, and a brief description of the cause of the alarm and the corrective action taken. You must also record the percent of the operating time during each 6-month period that the alarm sounds. In calculating this operating time percentage, if inspection of the fabric filter demonstrates that no corrective action is required, no alarm time is counted. If corrective action is required, each alarm shall be counted as a minimum of 1 hour. If you take longer than 1 hour to initiate corrective action, the alarm time shall be counted as the actual amount of time taken to initiate corrective action.
(10) If you are required to install a CEMS according to § 63.10010(a), then you must meet the requirements in paragraphs (a)(10)(i) through (iii) of this section.
(i) You must continuously monitor oxygen according to §§ 63.10010(a) and 63.10020.
(ii) Keep records of oxygen levels according to § 63.10032(b).
(11) The owner or operator of an affected source using a CEMS measuring PM emissions to meet requirements of this subpart shall install, certify, operate, and maintain the CEMS as specified in paragraphs (a)(11)(i) through (iv) of this section.
(i) The owner or operator shall conduct a performance evaluation of the CEMS according to the applicable requirements of § 60.13 of 40 CFR, Performance Specification 11 in Appendix B of 40 CFR part 60, and procedure 2 in Appendix F of 40 CFR part 60.
(ii) During each PM correlation testing run of the CEMS required by Performance Specification 11 in Appendix B of 40 CFR part 60, PM and O
(iii) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with procedure 2 in Appendix F of this chapter. Relative Response Audits must be performed annually and Response Correlation Audits must be performed every 3 years.
(iv) As of January 1, 2012 and within 60 days after the date of completing each performance test, as defined in § 63.2 and as required in this subpart, you must submit performance test data, except opacity data, electronically to EPA's Central Data Exchange (CDX) by using the Electronic Reporting Tool (ERT) (see
(v) Within 60 days after the date of completing each CEMS performance evaluation test, as defined in § 63.2 and required by this subpart, you must submit the relative accuracy test audit data electronically into EPA's Central Data Exchange by using the Electronic Reporting Tool as mentioned in paragraph (11)(iv) of this section. Only data collected using test methods compatible with ERT are subject to this requirement to be submitted electronically into EPA's WebFIRE database.
(vi) All reports required by this subpart not subject to the requirements in paragraphs (11)(iv) and (v) 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 paragraph (11)(iv) and (v) of this section in paper format.
(12) The owner or operator of an affected source using a CEMS measuring HCl emissions to meet requirements of this subpart shall install, certify, operate, and maintain the CEMS as specified in paragraphs (a)(12)(i) through (iii) of this section.
(i) The owner or operator shall conduct a performance evaluation of the CEMS according to the applicable requirements of § 60.13 of 40 CFR, Performance Specifications 6 or 15 in Appendix B of 40 CFR part 60, and procedure 2 in Appendix F of 40 CFR part 60.
(ii) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with procedure 1 in Appendix F of 40 CFR part 60.
(13) The owner or operator of an affected source using a CEMS measuring SO
(i) The owner or operator shall conduct a performance evaluation of the CEMS according to the applicable requirements of § 60.13 of 40 CFR part 60, Performance Specification 2 or 6 in Appendix B of 40 CFR part 60, and procedure 1 in Appendix F of 40 CFR part 60.
(ii) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with procedure 1 in Appendix F of 40 CFR part 60.
(14) The owner or operator of an affected source using a CEMS measuring Hg emissions to meet requirements of this subpart shall install, certify, operate, and maintain the CEMS as specified in paragraphs (a)(14)(i) through (iii) of this section.
(i) The owner or operator shall conduct a performance evaluation of the CEMS according to the applicable requirements of Appendix A of this subpart.
(ii) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with procedure 5 in Appendix F of 40 CFR part 60.
(15) As an alternative to measuring Hg emissions using Hg CEMS, the owner or operator of an affected source using a sorbent trap monitoring system to meet requirements of this subpart shall install, certify, operate, and maintain the sorbent trap monitoring system in accordance with Appendix A to this subpart.
(16) You must conduct a performance tune-up of the EGU to demonstrate continuous compliance as specified in paragraphs (a)(16)(i) through (a)(16)(vii) of this section.
(i) As applicable, inspect the burner, and clean or replace any components of the burner as necessary (you may delay the burner inspection until the next scheduled unit shutdown, but you must inspect each burner at least once every 18 months);
(ii) Inspect the flame pattern, as applicable, and make any adjustments to the burner necessary to optimize the flame pattern. The adjustment should be consistent with the manufacturer's specifications, if available;
(iii) Inspect the system controlling the air-to-fuel ratio, as applicable, and ensure that it is correctly calibrated and functioning properly;
(iv) Optimize total emissions of CO and NO
(v) Measure the concentration in the effluent stream of CO and NO
(vi) Maintain on-site and submit, if requested by the Administrator, an annual report containing the information in paragraphs (a)(16)(vi)(A) through (C) of this section,
(A) The concentrations of CO and NO
(B) A description of any corrective actions taken as a part of the combustion adjustment; and
(C) The type and amount of fuel used over the 12 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.
(vii) After December 31, 2011, and within 60 days after the date of completing each performance tune-up conducted to demonstrate compliance with this subpart, you must submit a notice of completion of the performance tune-up to EPA by successfully submitting the data electronically into an EPA database.
(17) For LEEs, the results of your initial and subsequent emissions tests, along with records of your fuel analyses, demonstrate your continuous compliance and continued eligibility as a LEE.
(i) As of January 1, 2012 and within 60 days after the date of completing each performance test, as defined in § 63.2 and as required in this subpart, you must submit performance test data, except opacity data, electronically to EPA's Central Data Exchange (CDX) by using the Electronic Reporting Tool (ERT) (see
(ii) Within 60 days after the date of completing each CEMS performance evaluation test, as defined in 63.2 and required by this subpart, you must submit the relative accuracy test audit data electronically into EPA's Central Data Exchange by using the Electronic
(iii) All reports required by this subpart not subject to the requirements in paragraphs (17)(i) and (ii) 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 paragraph (17)(i) and (ii) of this section in paper format.
(b) You must report each instance in which you did not meet each emission limit and operating limit in Tables 1 through 4 to this subpart that apply to you. These instances are deviations from the emission limits in this subpart. These deviations must be reported according to the requirements in § 63.10031.
(c) Consistent with § 63.10010, § 63.10020, and your site-specific monitoring plan, you must determine the 3-hour rolling average of the CPMS data collected for all periods the process is operating.
(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 (8) 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 a wet scrubber for PM control, maintain the 3-hour average parameter values at or below the operating limits established during the most recent performance test;
(3) For each existing unit participating in the emissions averaging option that is equipped with a fabric filter but without PM CEMS, maintain the 3-hour average parameter values at or below the operating limits established during the most recent performance test;
(4) For each existing unit participating in the emissions averaging option that is equipped with dry sorbent injection, maintain the 3-hour average parameter values at or below the operating limits established during the most recent performance test;
(5) For each existing unit participating in the emissions averaging option that is equipped with an ESP, maintain the 3-hour average parameter values at or below the operating limits established during the most recent performance test;
(6) For each existing unit participating in the emissions averaging option that is equipped with an ESP, maintain the monthly fuel content values at or below the operating limits established during the most recent performance test;
(7) For each existing unit participating in the emissions averaging option that has an approved alternative operating plan, maintain the 3-hour average parameter values at or below the operating limits established in the most recent performance test.
(8) 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 (8) of this section is a deviation.
(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 [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE
(c) As specified in § 63.9(b)(4) and (b)(5), if you startup your new or reconstructed affected source on or after [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE
(d) If 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) If 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). For each initial compliance demonstration, you must submit the Notification of Compliance Status, including all performance test results and fuel analyses, before the close of business on the 60th day following the completion of the performance test and/or other initial compliance demonstrations according to § 63.10(d)(2). The Notification of Compliance Status report must contain all the information specified in paragraphs (e)(1) through (6), 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 and fuel analysis; performance testing with operational limits (e.g., CEMS for surrogates or CPMS); CEMS; or sorbent trap monitoring system.
(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 description of the deviation, the duration of the deviation, and the corrective action taken 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 certification of compliance and must be signed by a responsible official:
(i) “This EGU complies with the requirement in § 63.10021(a)(16)(i) through (vi).”
(a) You must submit each report in Table 9 to this subpart that applies to you.
(b) Unless the EPA Administrator has approved a different schedule for submission of reports under § 63.10(a), you must submit each report by the date in Table 9 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 delivered 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 delivered 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 40 CFR part 70 or 40 CFR part 71, 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 (9) of this section.
(1) Company name and address.
(2) Statement by a responsible official with that official's name, title, and signature, certifying the truth, accuracy, and completeness of the content of the report.
(3) Date of report and beginning and ending dates of the reporting period.
(4) 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.
(5) 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 three years consistent with § 63.10006(o) or (p), 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(o) or (p), and a statement as to whether there have been any operational changes since the last stack test that could increase emissions.
(6) A signed statement indicating that you burned no new types of fuel. Or, if you did burn a new type of fuel, you must submit the calculation of chlorine input, using Equation 7 of § 63.10011, that demonstrates that your source is still within its maximum chlorine input level established during the previous performance testing (for sources that demonstrate compliance through performance testing) or you must submit the calculation of HCl emission rate using Equation 15 of § 63.10011 that demonstrates that your source is still meeting the emission limit for HCl emissions (for EGUs that demonstrate compliance through fuel analysis). If you burned a new type of fuel, you must submit the calculation of Hg input, using Equation 8 of § 63.10011, that demonstrates that your source is still within its maximum Hg input level established during the previous performance testing (for sources that demonstrate compliance through performance testing), or you must submit the calculation of Hg emission rate using Equation 11 of § 63.10011 that demonstrates that your source is still meeting the emission limit for Hg emissions (for EGUs that demonstrate compliance through fuel analysis).
(7) If you wish to burn a new type of fuel and you cannot demonstrate compliance with the maximum chlorine input operating limit using Equation 7 of § 63.10011 or the maximum Hg input operating limit using Equation 8 of § 63.10011, you must include in the compliance report a statement indicating the intent to conduct a new performance test within 60 days of starting to burn the new fuel.
(8) If there are no deviations from any emission limits or operating limits in this subpart that apply to you, a statement that there were no deviations from the emission limits or operating limits during the reporting period.
(9) If there were no deviations from the monitoring requirements including no periods during which the CMSs, including CEMS, and CPMS, were out of control as specified in § 63.8(c)(7), a statement that there were no deviations and no periods during which the CMS were out of control during the reporting period.
(10) 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(a)(16)(i) through (vi). 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 deviation from an emission limit or operating limit in this subpart that occurs at an affected source where you are not using a CMS to comply with that emission limit or operating limit, the compliance report must additionally contain the information required in paragraphs (d)(1) through (4) of this section.
(1) The total operating time of each affected source during the reporting period.
(2) A description of the deviation and which emission limit or operating limit from which you deviated.
(3) Information on the number, duration, and cause of deviations (including unknown cause), as applicable, and the corrective action taken.
(4) A copy of the test report if the annual performance test showed a deviation from the emission limits.
(e) For each deviation from an emission limit, operating limit, and monitoring requirement in this subpart 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 paragraphs (e)(1) through (12) of this section. This includes any deviations from your site-specific monitoring plan as required in § 63.10000(d).
(1) The date and time that each deviation started and stopped and description of the nature of the deviation (i.e., what you deviated from).
(2) The date and time that each CMS was inoperative, except for zero (low-level) and high-level checks.
(3) The date, time, and duration that each CMS was out of control, including the information in § 63.8(c)(8).
(4) The date and time that each deviation started and stopped, and whether each deviation occurred during
(5) A summary of the total duration of the deviation during the reporting period and the total duration as a percent of the total source operating time during that reporting period.
(6) An analysis of the total duration of the deviations during the reporting period into those that are due to startup, shutdown, control equipment problems, process problems, other known causes, and other unknown causes.
(7) A summary of the total duration of CMSs downtime during the reporting period and the total duration of CMS downtime as a percent of the total source operating time during that reporting period.
(8) An identification of each parameter that was monitored at the affected source for which there was a deviation.
(9) A brief description of the source for which there was a deviation.
(10) A brief description of each CMS for which there was a deviation.
(11) The date of the latest CMS certification or audit for the system for which there was a deviation.
(12) A description of any changes in CMSs, processes, or controls since the last reporting period for the source for which there was a deviation.
(f) Each affected source that has obtained a title V operating permit pursuant to 40 CFR part 70 or 40 CFR part 71 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 9 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. However, 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.
(g) In addition to the information required in § 63.9(h)(2), your notification must include the following certification(s) of compliance, as applicable, and signed by a responsible official:
(1) “This facility complies with the requirements in § 63.10021(a)(10) to conduct an annual performance test of the unit”.
(2) “No secondary materials that are solid waste were combusted in any affected unit.”
(h)(1) As of January 1, 2012 and within 60 days after the date of completing each performance test, as defined in § 63.2 and as required in this subpart, you must submit performance test data, except opacity data, electronically to EPA's Central Data Exchange (CDX) by using the Electronic Reporting Tool (ERT) (see
(2) Within 60 days after the date of completing each CEMS performance evaluation test, as defined in 63.2 and required by this subpart, you must submit the relative accuracy test audit data electronically into EPA's Central Data Exchange by using the Electronic Reporting Tool as mentioned in paragraph (h)(1) of this section. Only data collected using test methods compatible with ERT are subject to this requirement to be submitted electronically into EPA's WebFIRE database.
(3) All reports required by this subpart not subject to the requirements in paragraphs (h)(1) and (2) 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 paragraph (h)(1) and (2) of this section in paper format.
(i) If you had a malfunction during the reporting period, the 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. The report must also include a description of actions taken by an owner or operator during a malfunction of an affected source to minimize emissions in accordance with § 63.10000(b), including actions taken to correct a malfunction.
(a) You must keep records according to paragraphs (a)(1) through (2) of this section.
(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 (i.e., superseded) versions of the performance evaluation plan as required in § 63.8(d)(3).
(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 8 to this subpart including records of all monitoring data and calculated averages for applicable operating limits such as pressure drop and pH 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 (5) 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) A copy of all calculations and supporting documentation of maximum chlorine fuel input, using Equation 7 of § 63.10011, that were done to demonstrate continuous compliance with the HCl emission limit, for sources
(4) A copy of all calculations and supporting documentation of maximum Hg fuel input, using Equation 8 of § 63.10011, that were done to demonstrate continuous compliance with the Hg emission limit for sources that demonstrate compliance through performance testing. For sources that demonstrate compliance through fuel analysis, a copy of all calculations and supporting documentation of Hg emission rates, using Equation 11 of § 63.10011, that were done to demonstrate compliance with the Hg emission limit. Supporting documentation should include results of any fuel analyses and basis for the estimates of maximum Hg fuel input or Hg emission rates. You can use the results from one fuel analysis for multiple EGUs provided they are all burning the same fuel type. However, you must calculate Hg fuel input, or Hg emission rates, for each EGU.
(5) If consistent with § 63.10032(b) and (c), you choose to stack test less frequently than annually, you must keep annual records that document that your emissions in the previous stack test(s) were less than 90 percent of the applicable emission limit, 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 emission averaging implementation plan required in § 63.10009(g), all calculations required under § 63.10009, including daily records of heat input or steam generation, as applicable, and monitoring records consistent with § 63.10022.
(f) Records of the occurrence and duration of each startup and/or shutdown.
(g) Records of the occurrence and duration of each malfunction of operation (i.e., process equipment) or the air pollution control and monitoring equipment.
(h) 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.
(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 10 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; however, the U.S. EPA retains oversight of this subpart and can take enforcement actions, as appropriate.
(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), and approval of alternative analytical methods requested under § 63.10008(b)(2).
(3) Approval of major change to monitoring under § 63.8(f) and as defined in § 63.90, and approval of alternative operating parameters under §§ 63.9991(a)(2) and 63.10009(g)(2).
(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 of total energy input, if useful thermal energy produced is 15 percent or more of total energy output, or not less than 45 percent of total energy input, if useful thermal energy produced is less than 15 percent of total energy output.
(ii) For a bottoming-cycle 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.
(1) An equivalent sample collection procedure means a published voluntary consensus standard or practice (VCS) or EPA method that includes collection of a minimum of three composite fuel samples, with each composite consisting of a minimum of three increments collected at approximately equal intervals over the test period.
(2) An equivalent sample compositing procedure means a published VCS or EPA method to systematically mix and obtain a representative subsample (part) of the composite sample.
(3) An equivalent sample preparation procedure means a published VCS or EPA method that: Clearly states that the standard, practice or method is appropriate for the pollutant and the fuel matrix; or is cited as an appropriate sample preparation standard, practice or method for the pollutant in the chosen VCS or EPA determinative or analytical method.
(4) An equivalent procedure for determining heat content means a published VCS or EPA method to obtain gross calorific (or higher heating) value.
(5) An equivalent procedure for determining fuel moisture content means a published VCS or EPA method to obtain moisture content. If the sample analysis plan calls for determining metals (especially the Hg, selenium, or arsenic) using an aliquot of the dried sample, then the drying temperature must be modified to prevent vaporizing these metals. On the other hand, if metals analysis is done on an “as received” basis, a separate aliquot can be dried to determine moisture content and the metals concentration mathematically adjusted to a dry basis.
(6) An equivalent pollutant (Hg) determinative or analytical procedure means a published VCS or EPA method that clearly states that the standard, practice, or method is appropriate for the pollutant and the fuel matrix and has a published detection limit equal or lower than the methods listed in Table
(1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in geologic formations beneath the earth's surface, of which the principal constituent is methane; or
(2) Liquid petroleum gas, as defined by ASTM Method D1835-03a (incorporated by reference, see § 63.14(b)(41)).
As stated in § 63.9991, you must comply with the following applicable emission limits:
As stated in § 63.9991, you must comply with the following applicable emission limits:
As stated in § 63.9991, you must comply with the following applicable work practice standards:
As stated in § 63.10007, you must comply with the following requirements for performance testing for existing, new or reconstructed affected sources:
As stated
As stated in § 63.10007, you must comply with the following requirements for establishing operating limits:
As stated in § 63.10021, you must show continuous compliance with the emission limitations for affected sources according to the following:
As stated in § 63.10031, you must comply with the following requirements for reports:
As stated in § 63.10040, you must comply with the applicable General Provisions according to the following:
1.1
1.2
1.3
1.4
2.1
2.2
2.2.1 Install, certify, maintain, and operate the monitoring systems described in paragraph 2.1 of this section in the duct to the common stack from each unit; or
2.2.2 Install, certify, maintain, and operate the monitoring systems described in paragraph 2.1 of this section in the common stack.
2.3
2.3.1 Install, certify, maintain, and operate the monitoring systems described in paragraph 2.1 of this section in the duct to the common stack from each affected unit; or
2.3.2 Install, certify, maintain, and operate the monitoring systems described in paragraph 2.1 of this section in the common stack and attribute all of the Hg emissions measured at the common stack to the affected unit(s).
2.4
2.4.1 Install, certify, maintain, and operate the monitoring systems described in paragraph 2.1 of this section on both the main stack and the bypass stack; or
2.4.2 Install, certify, maintain, and operate the monitoring systems described in paragraph 2.1 of this section only on the main stack, and report the maximum potential Hg concentration (as defined in section 3.2.1.4.1 of this appendix) for each unit operating hour in which the bypass stack is used.
2.5
2.5.1 Install, certify, maintain, and operate the monitoring systems described in paragraph 2.1 of this section in each of the multiple stacks; or
2.5.2 Install, certify, maintain, and operate the monitoring systems described in paragraph 2.1 of this section in each of the ducts that feed into the stack.
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 Calibration Gas means a NIST-traceable gas standard containing known concentration of a gaseous species that is produced and certified in accordance with an EPA traceability protocol.
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
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 Sample Probe. The probe must be made of the appropriate materials as noted in paragraph 3.2.1.1.1 of this section, heated when necessary, as described in paragraph 3.2.1.1.3.4 of this section, and configured with ports for introduction of calibration gases.
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
3.2.3.1.1 Determine the stack gas moisture content using a certified continuous moisture monitoring system; or
3.2.3.1.2 Use the moisture value determined during the most recent Hg emissions test while combusting the fuel type currently in use; or
3.2.3.1.3 For coal combustion, use a fuel-specific moisture default value. For anthracite coal, use 3.0% H
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
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
4.1.2.3
4.1.2.4
4.1.3
4.2
5.1
5.1.1
5.1.2
5.1.2.1 Perform calibration error tests of the Hg CEMS daily. Use either NIST-traceable elemental Hg standards or NIST-traceable oxidized Hg standards for these calibrations. 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 A weekly single-level system integrity check (if required—see third column in Table A-3).
5.1.2.4 The test frequency for the RATAs of the Hg CEMS shall be annual, i.e., once every four QA operating quarters. For units that operate infrequently, extensions of RATA deadlines are allowed for non-QA operating quarters. Following a RATA, if there is a subsequent non-QA quarter, it extends the deadline for the next test by one calendar quarter. However, there is a limit to these extensions—the deadline may not be extended beyond the end of the eighth calendar quarter after the quarter of the last test. At that point, a RATA must either be performed within the eighth calendar quarter or in a 720 hour unit or stac operating hour grace period following that quarter.
5.1.3
5.1.4
5.1.4.1 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.
5.1.4.2 A 720 unit or stack operating hour grace period is available for RATAs of the Hg CEMS.
5.1.4.3 There is no grace period for weekly system integrity checks. The test must be completed once every 168 unit or stack operating hours.
5.1.5
5.2
5.2.1 Each sorbent trap monitoring system shall be continuously operated and maintained in accordance with Performance Specification 12B (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, i.e., once every four QA operating quarters.
5.2.2.2 The same RATA performance criteria specified in Table A-3 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.
5.2.2.4 Data validation for RATAs of the system shall be done in accordance with paragraph 5.1.3 of this section.
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
6.1.1 Reduce the data from Hg CEMS and (as applicable) flow rate, diluent gas, and moisture monitoring systems 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 (i.e., flow rate, diluent gas concentration, or moisture, as applicable), do not calculate the Hg emission rate for that hour.
6.1.4 Operating hours in which valid data are not obtained, either for Hg concentration or for another parameter, are considered to be hours of monitor downtime.
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 If the heat input-based Hg emission rate limit must be met over a specified averaging period (e.g., a 30 boiler operating day rolling average), use Equation 19-19 in EPA Method 19 to calculate the Hg emission rate for each averaging period. Do not include non-operating hours with zero emissions in the average.
6.2.2
6.2.2.1 First, 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 Next, 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 If the electrical output-based Hg emission rate limit must be met over a specified averaging period (e.g., a 30 boiler operating day rolling average), 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 MWge);
7.1.2.4 The hourly heat input rate (MMBtu/hr, rounded to the nearest tenth);
7.1.2.5 An identification code for the formula used to calculate the hourly heat input rate, as provided in the monitoring plan; and
7.1.2.6 The F-factor used for the heat input rate calculation.
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 the nearest tenth);
7.1.3.4 A special code, indicating whether or not a quality-assured Hg concentration is obtained for the hour; and
7.1.3.5 Monitor availability, as a percentage of unit or stack operating hours.
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 system provides a quality-assured value of Hg concentration for the hour;
7.1.4.3 The hourly Hg concentration, if a quality-assured value is obtained for the hour (µg/scm, rounded to the nearest tenth). 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, e.g., liters/min, cc/min, dscm/min);
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 12B in Appendix B to part 60 of this chapter; and
7.1.4.8 Data availability, as a percentage of unit or stack operating hours.
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 12B in Appendix B to part 60 of this chapter). Stack gas flow rate data are also needed in order to demonstrate compliance with heat input-based and electrical output-based Hg emissions limits, as provided in sections 6.2.1 and 6.2.2 of this appendix.
7.1.5.2 For each affected unit or common stack, if measurements of stack gas flow rate are required, use a certified flow rate monitor to record the following information for each unit or stack operating hour:
7.1.5.2.1 The date and hour;
7.1.5.2.2 Monitoring system and component identification codes, as provided in the monitoring plan, if a quality-assured flow rate value is obtained for the hour;
7.1.5.2.3 The hourly average volumetric flow rate, if a quality-assured flow rate value is obtained for the hour (in scfh, rounded to the nearest thousand);
7.1.5.2.4 A special code, indicating whether or not a quality-assured flow rate value is obtained for the hour; and
7.1.5.2.5 Monitor availability, as a percentage of unit or stack operating hours.
7.1.6
7.1.6.1 Correction of Hg concentration data for moisture is sometimes required, when compliance with an applicable Hg emissions limit must be demonstrated, as provided in sections 6.2.1 and 6.2.2 of this appendix. In particular, these corrections are required for sorbent trap monitoring systems and for Hg CEMS that measure Hg concentration on a dry basis.
7.1.6.2 If moisture corrections are required, use a certified moisture monitoring system to record the following information for each unit or stack operating hour (except
7.1.6.2.1 The date and hour;
7.1.6.2.2 Monitoring system and component identification codes for the system, as provided in the monitoring plan, if a quality-assured moisture value is obtained for the hour;
7.1.6.2.3 Hourly average moisture content of the flue gas (percent H
7.1.6.2.4 A special code, indicating whether or not a quality-assured moisture value is obtained for the hour; and
7.1.6.2.5 Monitor availability, as a percentage of unit or stack operating hours.
7.1.7
7.1.7.1 When a heat input-based Hg mass emissions limit must be met (e.g., in units of lb/TBtu), hourly measurements of CO
7.1.7.2 For each affected unit or common stack, if measurements of diluent gas concentration are required, use a certified CO
7.1.7.2.1 The date and hour;
7.1.7.2.2 Monitoring system and component identification codes, as provided in the monitoring plan, if a quality-assured O
7.1.7.2.3 The hourly average O
7.1.8.2.4 A special code, indicating whether or not a quality-assured O
7.1.7.2.5 Monitor availability, as a percentage of unit or stack operating hours.
7.1.8
7.1.8.1 The date and hour;
7.1.8.2 The calculated hourly Hg mass emissions, from Equation A-2 or A-3 in section 6.2.2 of this appendix (lb, rounded to three decimal places), if valid values of Hg concentration, stack gas volumetric flow rate, and (if applicable) moisture data are all obtained for the hour;
7.1.8.3 An identification code for the formula (either Equation A-2 or A-3 in section 6.2.2 of this appendix) used to calculate hourly Hg mass emissions from Hg concentration, flow rate and (if applicable) moisture data; and
7.1.8.4 A code indicating that the Hg mass emissions were not calculated for the hour, if valid data for Hg concentration, flow rate, and/or moisture (as applicable) are not obtained for the hour.
7.1.9
7.1.9.1 The date and hour;
7.1.9.2 The hourly Hg emissions rate (lb/TBtu or lb/GWh, as applicable, rounded to three decimal places), 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;
7.1.9.3 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
7.1.9.4 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.
7.1.10
7.1.10.1 The reference values, monitor responses, and calculated calibration error (CE) values, for all required 7-day calibration error tests and daily calibration error tests of all volumetric flow rate monitors and gas monitors, including Hg CEMS;
7.1.10.2 The results (pass/fail) of the required daily interference checks of flow monitors;
7.1.10.3 The reference values, monitor responses, and calculated linearity error (LE) or system integrity error (SIE) values for all required linearity checks of all gas monitors, including Hg CEMS, and for all single-level and 3-level system integrity checks of Hg CEMS;
7.1.10.4 The results (pass/fail) of all required quarterly leak checks of all differential pressure-type flow monitors (if applicable);
7.1.10.5 The CEMS and reference method readings for each test run and the calculated relative accuracy results for all RATAs of all Hg CEMS, sorbent trap monitoring systems, and (as applicable) flow rate, diluent gas, and moisture monitoring systems;
7.1.10.6 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 all gas monitors, including Hg CEMS;
7.1.10.7 Supporting information for all required RATAs of volumetric flow rate monitoring systems, diluent gas monitoring systems, and moisture monitoring systems, including the raw field data and, as applicable, the results of reference method bias and drift checks, calibration gas certificates, the results of lab analyses, and records of sampling equipment calibrations. For the RATAs of Hg CEMS and sorbent trap monitoring systems, keep sufficient records of the test dates, the raw reference method and monitoring system data, and the results of sample analyses to substantiate the reported test results; and
7.1.10.8 For sorbent trap monitoring systems, 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 12B in Appendix B to part 60 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
7.2.2.1 The date(s) of the required annual RATAs of the Hg CEMS, sorbent trap monitoring systems, and (as applicable) flow rate, diluent gas, and moisture monitoring systems used to provide data under this subpart;
7.2.2.2 The date on which emissions first exhaust through a new stack or flue gas desulfurization system; and
7.2.2.3 The date on which an affected unit is removed from service and placed into long-term cold storage, and the date on which the unit is expected to resume operation.
7.2.3
7.2.3.1 At least 21 days prior to the initial certification testing or recertification testing of a monitoring system used to provide data under this subpart; and
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 update must be submitted either prior to or concurrent with the quarterly report for the calendar quarter in which the update is required.
7.2.4 The results of all required certification, recertification, and quality-
7.2.5
7.2.5.1 Beginning with the calendar quarter containing the program start date, the owner or operator of any affected unit shall submit electronic quarterly reports to the Administrator, in a format specified by the Administrator, for each affected unit (or group of units monitored at a common stack) and each non-affected unit under section 2.3 of this appendix.
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 7.1.19 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 and daily flow monitor interference checks, as described in paragraphs 7.1.10.1 and 7.1.10.2 of this section.
7.2.5.4 Information which is incompatible with electronic reporting (e.g., field data sheets, lab analyses, stratification test results, sampling equipment calibrations, quality control plan information) is excluded from electronic reporting.
7.2.5.5
Fish and Wildlife Service, Interior.
Notice of review.
In this notice of review, we announce our annual petition findings for foreign species, as required under section 4(b)(3)(C)(i) of the Endangered Species Act of 1973, as amended. When, in response to a petition, we find that listing a species is warranted but precluded by higher priority listing actions, we must review the status of the species each year until we publish a proposed rule or make a determination that listing is not warranted. These subsequent status reviews and the accompanying 12-month findings are referred to as “resubmitted” petition findings.
Information contained in this notice describes our status review of 20 foreign taxa that were the subject of previous warranted-but-precluded findings, most recently summarized in our 2009 Notice of Review published on August 12, 2009 (74 FR 40540). Based on our current review, we find that 20 species continue to warrant listing, but their listing remains precluded by higher priority listing actions.
With this annual notice of review (ANOR), we are requesting additional information for the 20 taxa whose listings that remain warranted but precluded by higher priority listing actions. We will consider this information in preparing listing documents and future resubmitted petition findings for these 20 taxa. This information will also help us to monitor the status of the taxa and conserve them.
We will accept information on these resubmitted petition findings at any time.
This notice is available on the Internet at
Chief, Branch of Foreign Species, Endangered Species Program, (
The Endangered Species Act of 1973, as amended (Act) (16 U.S.C. 1531
Under section 4(b)(3)(A) of the Act, when we receive a listing petition, we must determine within 90 days, to the maximum extent practicable, whether the petition presents substantial scientific or commercial information indicating that the petitioned action may be warranted (90-day finding). If we make a positive 90-day finding, we are required to promptly commence a review of the status of the species. Using the information from the status review, in accordance with section 4(b)(3)(B) of the Act, we must make one of three findings within 12 months of the receipt of the petition (12-month finding). The first possible 12-month finding is that listing is not warranted, in which case we need not take any further action on the petition. The second possibility is that we may find that listing is warranted, in which case we must promptly publish a proposed rule to list the species. Once we publish a proposed rule for a species, sections 4(b)(5) and 4(b)(6) of the Act govern further procedures, regardless of whether or not we issued the proposal in response to the petition. The third possibility is that we may find that listing is warranted but precluded. A warranted but-precluded finding on a petition to list means that listing is warranted, but that the immediate proposal and timely promulgation of a final regulation is precluded by higher priority listing actions. In making a warranted-but-precluded finding under the Act, the Service must demonstrate that expeditious progress is being made to add and remove species from the Lists.
Pursuant to section 4(b)(3)(C)(i) of the Act, when, in response to a petition, we find that listing a species is warranted but precluded, we must make a new 12-month finding annually until we publish a proposed rule or make a determination that listing is not warranted. These subsequent 12-month findings are referred to as “resubmitted” petition findings. This notice contains our resubmitted petition findings for foreign species previously described in the 2009 Notice of Review (August 12, 2009, 74 FR 40540).
We maintain this list of candidates for a variety of reasons: To notify the public that these species are facing threats to their survival; to provide advance knowledge of potential listings; to provide information that may stimulate and guide conservation efforts that will remove or reduce threats to these species and possibly make listing unnecessary; to request input from interested parties to help us identify those candidate species that may not require protection under the Act or additional species that may require the Act's protections; and to request necessary information for setting priorities for preparing listing proposals.
On September 21, 1983, we published guidance for assigning a listing priority number (LPN) for each candidate species (48 FR 43098). Using this guidance, we assign each candidate an LPN of 1 to 12, depending on the magnitude of threats, immediacy of threats, and taxonomic status; the lower the LPN, the higher the listing priority (that is, a species with an LPN of 1 would have the highest listing priority). Guidelines for such a priority-ranking guidance system are required under section 4(h)(3) of the Act (15 U.S.C. 1533(h)(3)). As explained below, in using this system we first categorize based on the magnitude of the threat(s), then by the immediacy of the threat(s), and finally by taxonomic status.
Under this priority-ranking system, magnitude of threat can be either “high” or “moderate to low.” This criterion helps ensure that the species facing the greatest threats to their continued
As used in our priority ranking system, immediacy of threat is categorized as either “imminent” or “nonimminent.” It is not a measure of how quickly the species is likely to become extinct if the threats are not addressed; rather, immediacy is based on when the threats will begin. If a threat is currently occurring or likely to occur in the very near future, we classify the threat as imminent. Determining the immediacy of threats helps ensure that species facing actual, identifiable threats are given priority for listing proposals over those for which threats are only potential or species that are intrinsically vulnerable to certain types of threats, but are not known to be presently facing such threats.
Our priority ranking system has three categories for taxonomic status: species that are the sole members of a genus; full species (in genera that have more than one species); and subspecies and distinct population segments of vertebrate species (DPS).
The result of the ranking system entails assigning each candidate a listing priority number of 1 to 12. For example, if the threat(s) is/are of high magnitude, with immediacy classified as imminent, the listable entity is assigned an LPN of 1, 2, or 3 based on its taxonomic status (i.e., a species that is the only member of its genus would be assigned to the LPN 1 category, a full species would be assigned to LPN 2, and a subspecies, DPS, or a species that is endangered or threatened in only a significant portion of its range would be assigned to LPN 3). In summary, the LPN ranking system provides a basis for making decisions about the relative priority for preparing a proposed rule to list a given species. Each species included in this notice is one for which we have sufficient information to prepare a proposed rule to list, because it is in danger of extinction or likely to become endangered within the foreseeable future throughout all or a significant portion of its range.
For more information on the process and standards used in assigning LPNs, a copy of the guidance is available on our Web site at:
This revised notice supersedes all previous annual notices of review for foreign species. The species discussed in this notice were the result of three separate petitions submitted to the U.S. Fish and Wildlife Service (Service) to list a number of foreign bird and butterfly species as endangered or threatened under the Act. We received petitions to list foreign bird species on November 24, 1980, and May 6, 1991 (46 FR 26464, May 12, 1981; and 56 FR 65207, December 16, 1991, respectively). On January 10, 1994, we received a petition to list seven butterfly species as endangered or threatened (59 FR 24117; May 10, 1994).
We took several actions on these petitions. Our most recent review of petition findings was published on August 12, 2009 (74 FR 40540). Previously published petition findings, listing rules, status reviews, and petition finding reviews that included foreign species are also listed in the 2009 ANOR.
Since publication of the previous ANOR on August 12, 2009 (74 FR 40540), we reviewed the available information on candidate species to ensure that listing is warranted for each species, and reevaluated the relative LPN assigned to each species. We also evaluated the need to emergency list any of these species, particularly species with high listing priority numbers (i.e., species with LPNs of 1, 2, or 3). This review ensures that we focus conservation efforts on those species at greatest risk first. In addition to reviewing foreign candidate species since publication of the last ANOR, we have worked on numerous findings in response to petitions to list species and on proposed and final determinations for rules to list species under the Act. Some of these findings and determinations have been completed and published in the
Based on our review of the best available scientific and commercial information, with this ANOR, we have changed the LPN for several candidates. The review of these 20 species is summarized in Table 1.
This notice describes our resubmitted petition findings for 20 foreign species for which we had previously found proposed listing to be warranted but precluded. We have considered all of the new information that we have obtained since the previous finding, and we have reviewed in accordance with our Listing Priority Guidance the listing priority number (LPN) of each taxon for which proposed listing continues to be warranted but precluded.
As a result of our review, we find that warranted-but-precluded findings remain appropriate for these 20 species. We emphasize that we are not proposing these species for listing by this notice, but we do anticipate developing and publishing proposed listing rules for these species in the future, with an objective of making expeditious progress in addressing all 20 of these foreign species within a reasonable timeframe.
Table 1 provides a summary of all updated determinations of the 20 taxa in our review. All taxa in Table 1 of this notice are ones for which we find that listing is warranted but precluded and are referred to as “candidates” under the Act. The column labeled “Priority” indicates the LPN. Following the scientific name of each taxon (third column) is the family designation (fourth column) and the common name, if one exists (fifth column). The sixth column provides the known historic range for the taxon. The avian species in Table 1 are listed taxonomically.
We have found that, for the 20 taxa discussed below, publication of proposed listing rules continues to be warranted but precluded due to the need to complete pending, higher priority listing actions. We will continue to monitor the status of these species as new information becomes available (
The southern helmeted curassow, also known as the horned curassow, is one of the least frequently encountered South American bird species. This may be due to the inaccessibility of its preferred habitat and its apparent intolerance of human disturbance (Herzog and Kessler 1998; Macleod
What is now recognized as the southern helmeted curassow may in fact comprise two separate species that are currently recognized as two subspecies (
In many cases, taxonomy of species can be unclear. There is substantial discussion in scientific literature that debates the classification of species and whether various entities deserve species status rather than subspecies status (Phillimore 2010, pp. 42-53; James 2010, pp. 1-5; Pratt 2010, pp. 79-89). This is sometimes significant with respect to conservation measures,
The southern helmeted curassow inhabits dense, humid, lower montane forest and adjacent evergreen forest at 450 to 1,200 meters (m) (1,476 to 3,937 feet) (Cordier 1971; Herzog and Kessler 1998). It prefers eating nuts of the almendrillo tree (
In Amboró National Park (Yungas Inferiores de Amboró), the southern helmeted curassow was regularly sighted on the upper Saguayo river (Saguayo Río; Wege and Long 1995). Subsequently, it has been observed in the adjacent Amboró and Carrasco National Parks (Herzog and Kessler 1998; Brooks 2006). It was also found in Isiboro-Secure Indigenous Territory and National Park (TIPNIS), and along the western edge of the Cordillera Mosetenes (Mosetenes Mountains), Cochabamba, Bolivia. A recent survey located a few southern helmeted curassows across the northern boundary of Carrasco National Park (Yungas Inferiores de Carrasco), where it was historically found (MacLeod 2007 as cited in BLI 2009a). Surveys conducted between 2004 and 2005 found no evidence of the species anywhere north or east of Amboro, Carrasco, and Isiboro-Secure National Parks in central Bolivia (Macleod
In Peru,
The total population of southern helmeted curassow is estimated to be between 1,000 and 4,999 individuals (BLI 2010a). The population in Peru is estimated to have fewer than 400 individuals (Gastañaga in litt. 2007, as cited in BLI 2010a). The estimated decline in the overall population over 10 years has been 50 to 79 percent (BLI 2009b).
Southern helmeted curassow populations are estimated to be declining very rapidly due to uncontrolled hunting and habitat destruction. This species has a small range and is known only from a few locations, which continue to be subject to habitat loss and hunting pressure. Hunting was indicated to be the biggest threat to southern helmeted curassow in all parts of its range (Gastañaga 2006). The species was often hunted for meat due to its large size and for its unique blue casque, or horn, which the local people used to make cigarette lighters (Cordier 1971; Collar
The Río Leche area in Peru experienced a 100 percent population decline in less than 5 years likely due to hunting or other pressures (Macleod
In Bolivia, forests within the range of the southern helmeted curassow are being cleared for crop cultivation by colonists from the altiplano (Maillard 2006, pp. 95-98). Rural development, including road building, inhibits its dispersal (Herzog and Kessler 1998; Fjeldså in litt. 1999 as cited in BLI 2010). In Peru, southern helmeted curassow habitat is threatened by subsistence agriculture (MacLeod in litt. 2000 as cited in BLI 2010a), forest clearing by colonists, illegal logging, mining, and oil exploration (BLI 2010a).
The southern helmeted curassow is dependent upon pristine habitat. In Bolivia, large parts of southern helmeted curassow habitat are ostensibly protected by inclusion in the Amboro and Carrasco National Parks and in the Isiboro-Secure Indigenous Territory and National Park. However, pressures on the species' populations continue (BLI 2010a). In recent years, extensive field surveys of southern helmeted curassow habitat have resulted in little success in locating the species (Mee
In our 2009 ANOR, the southern helmeted curassow received an LPN of 8. After reevaluating the threats to the
The Bogota rail is found in the East Andes of Colombia on the Ubaté-Bogotá Plateau in Cundinamarca and Boyacá. It occurs in the temperate zone, at 2,500-4,000 m (occasionally as low as 2,100 m) (6,890 ft) in savanna and páramo marshes (BLI 2010b). Bogota rail inhabit wetland habitats with vegetation-rich shallows that are surrounded by tall, dense reeds and bulrushes (Stiles in litt. 1999 as cited in BLI 2010b). It inhabits the water's edge, in flooded pasture and along small overgrown dykes and ponds (Varty
The current population is estimated to range between 1,000 and 2,499 individuals, although numbers are expected to decline over the next 10 years by 10 to 19 percent (BLI 2009). Although the Bogota rail has been observed in at least 21 locations in Cundinamarca, the Bogota rail population is thought to be declining. It is still uncommon to fairly common, with a few notable populations, including nearly 400 birds at Laguna de Tota, approximately 50 bird territories at Laguna de la Herrera, approximately 100 birds at Parque La Florida, and populations at La Conejera marsh and Laguna de Fuquene (BLI 2010b).
Its suitable habitat has become widely fragmented (BLI 2010b). Wetland drainage, pollution, and siltation on the Ubaté-Bogotá plateau have resulted in major habitat loss and few suitably vegetated marshes remain. All major savanna wetlands are threatened, predominately due to draining, but also due to agricultural runoff, erosion, dyking, eutrophication caused by untreated sewage effluent, insecticides, tourism, hunting, burning, reed harvesting, fluctuating water levels, and increasing water demand. Additionally, road construction may result in colonization and human interference, including introduction of exotic species in previously stable wetland environments (Cortes in litt. 2007 as cited in BLI 2010b).
In our 2009 ANOR, the Bogota rail received an LPN of 8. After reevaluating the threats to this species, we have determined that a change in the listing priority number for the species is appropriate. The Bogota rail does not represent a monotypic genus. It faces threats that are high in magnitude due to the pressures on the population's habitat. Its range is very small and is rapidly contracting because of widespread habitat loss and degradation (agricultural encroachment, erosion, dyking, and eutrophication). The population is believed to be between 1,000 and 2,499 individuals, and the population trend is believed to be rapidly declining. Based on new information regarding threats to this species, we find that the threats to the species are occurring now, are ongoing, and are therefore imminent. Thus, we have changed the LPN from an 8 to a 2 to reflect imminent threats of high magnitude.
The takahe, a flightless rail endemic to New Zealand, is the world's largest extant (living) member of the rail family (del Hoyo
When rediscovered in 1948, it was estimated that the takahe population was about 260 pairs (del Hoyo 1996; Heather and Robertson 1997). By the 1970s, takahe populations had declined dramatically, and it appeared that the species was at risk of extinction. In 1981, the population reached a low at an estimated 120 birds. Since then, the population has fluctuated between 100 and 160 birds (Crouchley 1994; Maxwell 2001). At first, translocated populations increased only slowly, possibly in part due to young pair-bonds and the quality of the founding population (Bunin
This species experienced a loss of fitness as a result of recent inbreeding. Relative to other species, it has low genetic diversity (Grueber
As of 2009, the current total population estimate is 227 adults (NZDOC 2009d, p. 11; NZDOC 2009e). Birds under 1 year of age were not counted in these totals. As of 2007, the mainland population, as well as island reserves, were thought to be at carrying capacity (Greaves 2007, p. 17), (NZDOC 2009, p. 29), however a Recovery Plan is underway to address conservation priorities and needs for this species (NZDOC 2009d, entire). Overall, population numbers are slowly increasing due to intensive management of the island reserve populations, but fluctuations in the remnant mainland population continue to occur (NZDOC 2009d; BLI 2010c).
Takahe territories historically have been large; they have been known to be between several hectares (ha) to more than 100 ha (247 acres (ac)) depending on the availability of their preferred food sources (Lee and Jamieson 2001, p. 57). Takahe defend them aggressively against other takahe, which means that they will not form dense colonies even in very good habitat. They are long-lived birds, probably living between 14 and 20 years (Heather and Robertson 1997) and have a low reproductive rate, with clutches consisting of 1 to 3 eggs. They form life-long pair bonds and generally occupy the same territory throughout life (Reid 1967). Generally pairs in the wild only rear one chick. Only a few pairs manage to consistently rear more than one chick each year. Although under normal conditions this is generally sufficient to maintain the population, populations recover slowly from catastrophic events (Crouchley 1994); and this is a concern because this species has such a small population size. To increase the population, NZDOC has been removing some eggs from the wild, captive rearing them, and reintroducing them back into the wild (NZDOC 2009, p. 26).
Originally, the species occurred throughout forest and grass ecosystems. Now takahe occupy alpine grasslands (BLI 2010c). They feed on tussock grasses during much of the year; snow tussocks (
Research by Mills
Although
Rareness of
Several factors have led to the decline in the species' population. The main cause of the species' historical decline was competition for tussock grasses by grazing red deer (
Other potential threats include a competitor, the introduced brush-tailed possum (
Lead exposure may affect this species on some of the islands (Youl 2009, pp. 79-83). Lead levels in the island populations were found to be higher
Since 1983, the NZDOC has been involved in managing a captive-breeding and release program to boost takahe recovery (NZDOC 2009, p. 29). Excess eggs from wild nests are managed to produce birds suitable for releasing back into the wild population in the Murchison Mountains. Some of these captive-reared birds were used to establish five predator-free, offshore island reserves. These captive-breeding efforts have increased the rate of survival of chicks reaching one year of age from 50 to 90 percent (NZDOC 1997; NZDOC 2009d). Takahe that have been translocated to the islands have higher rates of egg infertility and low hatching success when they breed (Jamieson & Ryan 2000). Researchers postulated that the difference in vegetation between the native mainland grassland tussocks and the grasses found on the islands might affect reproductive success. After testing nutrients from available food sources, it remains unclear whether the islands contain adequate nutrients in the available food sources (James
In our 2009 ANOR, the takahe received an LPN of 8. After reevaluating the threats to the takahe, we have determined that no change in the classification of the magnitude and imminence of threats to the species is warranted at this time. The takahe does not represent a monotypic genus. The current population is small (between 150-220 individuals), and the species' distribution is extremely limited. It faces threats that are moderate in magnitude (extremely small population, limited suitable habitat, inbreeding depression, and to some extent predation) because the NZDOC has taken measures to aid the recovery of the species (NZDOC 2009d, 58 pp.; NZDOC 2009e, 3 pp.) and is active in the species conservation and recovery. The NZDOC has implemented a successful deer control program, implemented a captive-breeding and release program to augment the mainland population, and established four offshore island reserves. However, we find that the threats are on-going and therefore, imminent. Predation by introduced species and reduced survivorship resulting from severe winters, combined with the takahe's small population size and naturally low reproductive rate are threats to this species that are moderate in magnitude. Thus, the LPN remains at 8 to reflect imminent threats of moderate magnitude.
The Chatham oystercatcher is the most rare oystercatcher species in the world (NZDOC 2001). It is endemic to the Chatham Island group (Marchant and Higgins 1993; Schmechel and Paterson 2005), which lies 860 km (534 mi) east of mainland New Zealand. The Chatham Island group consists of two large, inhabited islands (Chatham and Pitt) and numerous smaller islands. Two of the smaller islands (Rangatira and Mangere) are nature reserves, which provide vitally needed habitat for the Chatham oystercatcher. The Chatham Island group has a biota quite different from the mainland. The remote marine setting, distinct climate, and physical makeup have led to a high degree of endemism (Aikman
Pairs of Chatham oystercatchers occupy their territory all year, while juveniles and subadults form small flocks or occur alone on vacant sections of the coast. Their scrape nests (shallow-rimmed depressions in soil or vegetation) are usually on sandy beaches just above spring-tide and storm surge level or among rocks above the shoreline and are often under the cover of small bushes or rock overhangs (Heather and Robertson 1997).
In the early 1970s, the Chatham oystercatcher population was approximately 50 birds (del Hoyo 1996). The population increased by 30 percent overall between 1987 and 1999, except trends varied in different areas of the Chatham Islands (Moore
Predation, nest disturbance, invasive plants, and spring tides and storm surges are factors threatening the Chatham oystercatcher population (NZDOC 2001, Moore 2005; Moore 2009a, pp. 8-9). Feral cats (
Another predator, the weka (
Other potential predators include the Norway rat (
Another obstacle to Chatham oystercatcher populations is marram grass (
The birds of the Chatham Island group are protected. The NZDOC focused conservation efforts in the early 1990s on predator trapping and fencing to limit domestic stock access to nesting areas. In 2001, the NZDOC published the Chatham Island Oystercatcher Recovery Plan 2001-2011 (NZDOC 2001, 24 pp.), which outlines actions such as translocation of nests away from the high tide mark and nest manipulation to further the conservation of this species. These actions may have helped to increase hatching success (NZDOC 2008b). Artificial incubation has been attempted but has not increased productivity. Additionally, livestock have been fenced and signs erected to reduce human and dog disturbance. Marram grass control has been successful in some areas. Intensive predator control combined with nest manipulation has resulted in a high number of fledglings (BLI 2009).
In our 2009 ANOR, the Chatham oystercatcher received an LPN of 8. After reevaluating the threats to this species, we have determined that no change in the classification of the magnitude and imminence of threats to the species is warranted at this time. The Chatham oystercatcher does not represent a monotypic genus. The current population estimate is very small—between 50 and 300 individuals—and the species only occurs in a small area. Although it faces threats that are moderate in magnitude (predation, low population numbers, and potential loss due to storm surges); the NZDOC has taken measures to aid the recovery of the species that appear to be effective (the species' population is increasing), However, we find that the threats are still on-going and therefore, imminent. The LPN remains an 8 to reflect imminent threats of moderate magnitude.
The orange-fronted parakeet, also known as Malherbe's parakeet is endemic to New Zealand. It was treated as an individual species until it was proposed to be a color morph of the yellow-crowned parakeet,
At one time, the orange-fronted parakeet was scattered throughout most of New Zealand (Harrison 1970). This species has been described as never being common (Mills and Williams 1979). During the 19th century, the species' distribution included South Island, Stewart Island, and a few other offshore islands of New Zealand (NZDOC 2009a). Currently, there are three known remaining populations. The South Island populations are managed and located within a 30-km (18.6-mi) radius in beech (
This species inhabits southern beech forests, with a preference for locales bordering stands of
The orange-fronted parakeet has an extremely small, fragmented population and limited range, and its population has declined during the past 10 years (BLI 2010e). Currently, BLI estimates its population in the wild to be between 50 and 249 individuals (BLI 2010e, p. 1). NZDOC's population estimate is between 100 to 200 individuals in the wild and they also believe the population is declining (NZDOC 2009a).
There are several reasons for the species' continuing decline; one of the most prominent risks to the species is believed to be predation by introduced species, such as stoats (
In 2007, habitat loss and degradation were considered threats to the orange-fronted parakeet (BLI 2007b). Large areas of native forest have been felled or burnt, decreasing the habitat available for parakeets (NZDOC 2009c). Silviculture of beech forests aims to harvest trees at an age when few will become mature enough to develop suitable cavities for orange-fronted parakeets (Kearvell 2002). The habitat is also degraded by brush-tailed possum (
Other risks to this species' viability exist. Some of these other potential threats include increased competition between the orange-fronted parakeet and the yellow-crowned parakeet for nest sites and food in a habitat substantially modified by humans; competition with introduced finch species; and competition with introduced wasps (
The NZDOC closely monitors all known populations of the orange-fronted parakeet. Nest searches are conducted, nest holes are inspected, and surveys are carried out in other areas to look for evidence of other populations. For example, the surveys successfully located another orange-fronted parakeet population in May 2003 (NZDOC 2009d). A new population was established in 2006 on the predator-free Chalky Island. Eggs were removed from nests in the wild, and foster parakeet parents incubated the eggs and cared for the hatchlings until they fledged and were transferred to the island. Monitoring later in the year (2006) indicated that the birds had successfully nested and reared chicks. Additional birds will be added to the Chalky Island population in an effort to increase the genetic diversity of the population (NZDOC 2009d). A second self-sustaining population has been established on Maud Island (NZDOC 2008).
Because the NZDOC determined that the species' largest threat is predation, they initiated a program to remove predators in some parts of the species' range. “Operation ARK” is their initiative to respond to predator problems in beech forests to prevent species' extinctions, including orange-fronted parakeets. Predators are methodically controlled with traps, toxins in bait stations, bait bags, and aerial spraying, when necessary (NZDOC 2009d). The NZDOC also implemented a captive-breeding program for the orange-fronted parakeet. Using captive-bred birds from the program, NZDOC established two self-sustaining populations of the orange-fronted parakeet on predator-free islands. The NZDOC monitors wild nest sites and is actively managing the conservation of the species, as evidenced by the 2003 discovery of a new population. Despite these controls, predation by introduced species is still a threat because predators have not been eradicated from this species' range.
In our 2009 ANOR, the orange-fronted parakeet received an LPN of 8. After reevaluating the threats to the orange-fronted parakeet, we have determined that no change in the classification of the magnitude of threats to the species is warranted because NZDOC is actively managing the species. The orange-fronted parakeet does not represent a monotypic genus. Although the species' available suitable nesting habitat in beech forests is extremely restricted, translocations have taken place and seem to be successful (BLI 2010e, p. 2). Although the current population is small and declining (between 50 and 249 individuals), and the species' distribution is extremely limited, threats are being mitigated. It has a very small and severely fragmented population that has declined over the past 10 years (BLI 2010e) but it is being closely monitored and may slowly be increasing (van Hal
The Uvea parakeet, previously known as
The Uvea parakeet is found only on the small island of Uvea (also known as both Ouvéa Island and Wallis Island) in the Loyalty Archipelago, New Caledonia (a territory of France) in the South Pacific Ocean. The island is approximately 1,500 km (932 mi) east of Australia. Uvea Island is 110 km
Uvea parakeets feed on fruit, the berries of vines, and the flowers and seeds of native trees and shrubs (del Hoyo
One survey of Uvea parakeet in the early 1990s estimated that the population was between 70 and 90 individuals (Hahn 1993). However, another survey in 1993 (Robinet
Various threats to this species exist. The Uvea parakeet is primarily threatened by lack of nesting sites due to competition from bees and historic habitat loss, and to lesser extents predation and possibly capture of juveniles for the pet trade (Robinet
It is unknown if capture of young Uvea parakeets for the pet trade is still occurring, and if so, to what extent. Capture of juvenile parakeets involves cutting open nesting cavities to extract nestlings, which renders the holes unsuitable for future nesting. Robinet
In 1999, a study of the reproductive biology of Uvea parakeet found that the main cause of chick death was starvation of the third chick within the first week after hatching (Robinet and Salas). However, the reason underlying the starvation is unknown.
Norway rats are prolific invaders of islands and can rapidly establish large populations (Russell 2007). Additionally, impacts of the rat appear to be more severe on smaller islands (Martin
In 30 years, approximately 30 to 50 percent of primary forest was removed (Robinet
Preventive measures have been taken at the port and airport to prevent introduction of invasive rats and should continue to be reinforced, but there is concern that these rats may be introduced in the future (BLI 2010, p. 3). As of 2007, the island remained rat-free (Verfaille in litt. 2007 as cited in BLI 2010). Introductions of Uvea parakeets to the adjacent island of Lifou (to establish a second population) in 1925 and 1963 failed (Robinet
A captive-breeding program has been discussed but not begun (BLI 2010f). A translocation program to restock this species into the southern portion of Uvea was cancelled under the new recovery plan (2003) because the population was considered viable and was expected to increase naturally (Barré in litt. 2003; Anon 2004 as cited in BLI 2010f). Measures are being taken to control predators and prevent colonization by rats (BLI 2010f). Current Uvea parakeet numbers appear to be slowly increasing, but any relaxation of conservation efforts or introduction of nonnative rats or other predators could lead to a rapid decline (BLI 2010f). The Société Calédonienne d'Ornithologie (SCO) received funding to test artificial
Even though populations appear to be currently increasing, any reduction in conservation efforts or introduction of invasive species (particularly cavity-nesting bees, the ship rat, and the Norway rat) could lead to rapid declines (Robinet
In our 2009 ANOR, the Uvea parakeet received an LPN of 8. We reevaluated the threats to the Uvea parakeet and determined that a change in the LPN for the species is warranted. The Uvea parakeet does not represent a monotypic genus. Its population is estimated to be approximately 750 individuals, and it is an island endemic in limited locations with restricted and declining habitat. The Uvea parakeet faces threats that are high in magnitude primarily due to nest competition by bees, predation by goshawk, and the lack of the old-growth forest, on which the birds depend for nesting holes. The birds only occur in an area about 20 km
The blue-throated macaw is endemic to forest islands in the seasonally flooded Beni Lowlands (Lanos de Mojos, also known as Lanos de Moxos) of central Bolivia (Jordan and Munn 1993; Yamashita and de Barros 1997; BLI 2010g). The taxonomic status of this species was long disputed, primarily because the species was unknown in the wild to biologists until fairly recently. Previously, it was considered an aberrant form of the blue-and-yellow macaw (
The species inhabits a mosaic of seasonally inundated savanna, palm groves, forest islands, and humid lowlands. This macaw species is found in areas where palm-fruit food and suitable nesting cavities are available (Herrera
The blue-throated macaw also depends on motacu palms for nesting (BLI 2008d). In 2005, this species was found nesting in an area dominated by the Curupau tree (
BLI (2010g) estimates the total wild population to be between 50 and 300 birds and noted the population has some fragmentation. Surveys indicate the population may have slowly increased following dramatic declines in the 1970s and 1980s, but now the population is believed to be decreasing (BLI 2010g). Biologists surveying for this species in 2004 found more birds than in previous surveys by searching specific habitat types (palm groves and forested islands) (Herrera
The blue-throated macaw was historically at risk from trapping for the national and international bird trade, and some illegal trade may still be occurring. Between the early 1980s and early 1990s, an estimated 1,200 or more wild-caught individuals were exported from Bolivia, and many are now in captivity in the European Union and in North America (World Parrot Trust 2003; BLI 2008b). Although Bolivia outlawed the export of live parrots in 1984 (Brace
Armonia Association (a nonprofit organization in Bolivia) monitored the wild birds that passed through a pet market in Santa Cruz, Bolivia, from August 2004 to July 2005. Although nearly 7,300 parrots were recorded in trade, the blue-throated macaw was absent in the market during the monitoring period, which may point to the effectiveness of the ongoing conservation programs in Bolivia (BLI 2007), or it may be indicative of the scarcity of blue-throated macaws in the wild. There are a number of blue-throated macaws in captivity, with over 1,000 registered in the North American studbook (Waugh 2007c). Because these birds are not difficult to breed, the supply of captive-bred birds has increased (Waugh 2007a), helping to alleviate pressure on, but not completely eliminating illegal collection of wild birds. However, United Nations Environment Programme—World Conservation Monitoring Center (UNEP-WCMC) trade data indicates that no birds of wild origin of this species have been exported from Bolivia since 1993 (UNEP-WCMC, accessed September 3, 2010). A current internet search indicated that captive-bred specimens of this species sell for between $1,500 and $3,000 in the United States (
Other threats to the blue-throated macaw include habitat loss, botfly parasites, and competition from other birds, such as other macaws, toucans, and large woodpeckers (Kyle 2005, pp.
In October 2008, Armonia Association announced it had purchased a large, 3,555-ha (8,785-ac) reserve for the purpose of establishing a protected area for the blue-throated macaw (BLI 2008d; Worldland Trust 2010, accessed July 16, 2010). The Barba Azul Nature Reserve protects savanna habitat, and 20 blue-throated macaws have been observed to nest here. The organization has also been experimenting with artificial nest boxes; the macaws have been using these, and this promises to be a way to boost breeding success while habitat restoration is under way in the new reserve. Despite these efforts, only between 50 and 300 remain in the wild.
In our 2009 ANOR, the blue-throated macaw received an LPN of 8. After reevaluating the available information, we find that a change in the LPN is warranted for this species. The blue-throated macaw does not represent a monotypic genus. It faces threats that are high in magnitude such as limited and decreasing habitat suitability (nesting cavities), competition for nesting cavities from other species (toucans in particular and other more aggressive macaws), and parasitism by botflies. Wildlife managers in Bolivia are actively protecting the species and searching for additional populations, and the species is now protected in one nature reserve. Although wild birds may no longer be imported for commercial purposes as a result of the species' CITES listing, and it is legally protected in Bolivia, there are only between 50 and 300 of these birds left in the wild, and the population is decreasing rapidly, despite conservation efforts. The threats to the species identified are of high magnitude, ongoing, and imminent. Based on the rapidly declining population, we have changed the LPN from an 8 to a 2 to reflect imminent threats of high magnitude.
The helmeted woodpecker is endemic to the southern Atlantic forest region of southeastern Brazil, eastern Paraguay, and northeastern Argentina (BLI 2010h). Its estimated range spans 24,000 km
Field work on the helmeted woodpecker indicated that the species is less rare than once thought (BLI 2010h), although its range is restricted (Mattsson
The most recent population estimate is between 10,000 and 19,999 individuals and decreasing (BLI 2010h); however it is unclear when the last census of this species was conducted. Because the helmeted woodpecker is difficult to locate except when vocalizing and it is silent most of the year, its numbers may be underestimated. Between 1997 and 2006, it was observed in the San Rafael National Park, Paraguay, although infrequently (Esquivel
The greatest threat to the helmeted woodpecker is widespread deforestation (Cockle 2008 as cited in BLI 2009; BLI 2010h). Other threats may be competition from other species, particularly more competitive woodpeckers, which may use fragmented and “edge” habitat more effectively (BLI 2010h).
The Atlantic Forest, habitat in which the helmeted woodpecker resides, extends along the Atlantic coast of Brazil from Rio Grande do Norte in the north to Rio Grande do Sul in the south, and inland as far as Paraguay and Misiones Province of northeastern Argentina (Morellato and Haddad 2000, pp. 786-787; Conservation International 2007a, p. 1; Höfling 2007, p. 1). The Atlantic Forest extends up to 600 km (373 mi) west of the Atlantic Ocean. It consists of tropical and subtropical moist forests, tropical dry forests, and mangrove forests at mostly low-to-medium elevations less than 1,000 m (3,281 ft); however, altitude can reach as high as 2,000 m (6,562 ft) above sea level. It is likely that only between 7 and 10 percent of this habitat remains intact (Morellato and Haddad 2000, p. 786; Oliveira-Filho and Fontes 2000, p. 794). Between 92 to 95 percent of the area historically covered by tropical forests within the Atlantic Forest biome has been converted or severely degraded as a result of various human activities (Morellato and Haddad 2000, p. 786; Myers
A significant portion of Atlantic Forest habitat has been, and continues to be, lost and degraded by various ongoing human activities, including logging, establishment and expansion of plantations and livestock pastures,
In Paraguay, some viable, although fragmented habitat for this species remains in San Rafael National Park (Esquivel
In our 2009 ANOR, the helmeted woodpecker received an LPN of 8. After reevaluating the available information, we find that a change in the LPN for the helmeted woodpecker is not warranted. The helmeted woodpecker does not represent a monotypic genus. The magnitude of threat to the species is moderate because the species' range (24,000 km
The Okinawa woodpecker (also known as Pryer's woodpecker) (
Okinawa is the largest of the Ryukyu Islands, a small island chain located between Japan and Taiwan (Brazil 1991; Stattersfield
This species of woodpecker prefers undisturbed, mature, subtropical evergreen broadleaf forests, with tall trees greater than 20 cm (7.9 in) in diameter (Short 1982; del Hoyo 2002). Trees of this size are generally more than 30 years old and as of 1991 were confined to hilltops (Brazil 1991). The species' main breeding areas are located along the mountain ridges between Mt. Nishime-take and Mt. Iyu-take, although it has been observed nesting in well-forested coastal areas (Research Center, Wild Bird Society of Japan 1993, as cited in BLI 2001). The majority of the broadleaf trees in the Yanbaru area are oak and chinquapin (
The Okinawa woodpecker feeds on large arthropods, notably beetle larvae, spiders, moths, and centipedes, fruit, berries, seeds, acorns, and other nuts (Short 1982; del Hoyo 2002; Winkler
This species is considered one of the world's most rare extant woodpecker species (Winkler
Deforestation and the fragmented nature of its habitat due to logging, dam construction, road-building, agricultural development, and golf course construction are cited to be the main causes of its small population size (BLI 2010i). Between 1979 and 1991, 2,443 ha (6,037 ac) of forest were destroyed in the Yanbaru area (Department of Agriculture, Okinawa Prefectural Government 1992, in Ito
The limited range and tiny population make this species vulnerable to extinction from disease and natural disasters such as typhoons (BLI 2008). Feral dogs and cats, the introduced Javan mongoose (
In our 2009 ANOR, the Okinawa woodpecker received an LPN of 8. After reevaluating the available information, we find that a change in the LPN for the Okinawa woodpecker is warranted. The Okinawa woodpecker does not represent a monotypic genus. It is considered one of the world's most rare extant woodpecker species and faces threats that are high in magnitude even though the species is legally protected in Japan. The best available information does not indicate that this species is being actively managed. The threats to the species are of high magnitude due to the scarcity of old-growth habitat (only 40 km
There is very little information available regarding the yellow-browed toucanet. This species is endemic to Peru and is known from only two localities in north-central Peru—La Libertad, where it is uncommon, and Rio Abiseo National Park, San Martin, where it is thought to be very rare (Wege and Long 1995; del Hoyo
The yellow-browed toucanet's estimated range is 450 km
The narrow distributional band in which yellow-browed toucanets are found may be related to the occurrence of other avian species that may out-compete the yellow-browed toucanet. Recent information indicates that both of the suggested competitors have wider altitudinal ranges that completely encompass that of the yellow-browed toucanet (Collar
Distinguishing features of the yellow-browed toucanet include a bright yellow vent or cloaca, a blackish bill, and a generally green face, (Schulenberg and Parker 1997, p. 719). Its call has been described as a series of 20 to 30 frog-like “krik” notes, delivered at a rate of slightly more than one note per second (recordings housed in Cornell Laboratory of Ornithology, Schulenberg and Parker 1997, p. 717).
Human-related threats to the species include deforestation, mining, and secondary impacts associated with those activities. Deforestation has been widespread in this region, but has largely occurred at lower elevations than habitat occupied by the yellow-browed toucanet (Barnes
In our 2009 ANOR, the yellow-browed toucanet received an LPN of 11. After reevaluating the available information, we find that a change in the LPN for the yellow-browed toucanet is warranted. The yellow-browed toucanet does not represent a monotypic genus. Although the species is believed to exist in the protected Rio Abiseo National Park, there have been no documented sightings since 2003. As of 2010, BLI reported that coca-growers have taken over forest within its altitudinal range (BLI 2010j). The magnitude of threats to the species is high given that the species has a small range and rapidly declining population; and may be in competition for habitat with more competitive avian species. Further, pressures in and around the park exist due to mining and secondary impacts associated with mining. Additionally, the only records of this species are from two small locations and they have not been verified in several years. Based on these factors, we find that the threats are imminent and of high magnitude. Thus, we have reassessed and changed the LPN for this species from an 11 to a 2 to reflect imminent threats of high magnitude.
The Brasilia tapaculo is a small bird endemic to Brazil, specifically in the central to southern-central region of the country. It is found in swampy gallery forests, which are forests that grow along streams and rivers in regions otherwise devoid of trees, within disturbed areas of thick streamside vegetation and dense secondary growth of
The species has been documented in Goiás and Serra da Canastra National Park, Minas Gerais (Negret and Cavalcanti 1985, as cited in Collar
Although the species was once considered rare (Sick and Texeira 1979, as cited in Collar
The species occupies a limited area within a range of 109,000 km
In our 2009 ANOR, the Brasilia tapaculo received an LPN of 8. After reevaluating the available information, we find that a change in the LPN for the Brasilia tapaculo is not warranted. The Brasilia tapaculo does not represent a monotypic genus. The magnitude of threat to the species is moderate because in 2008, their population was estimated at approximately 10,000 birds; at least two of the populations are in protected habitat; and their preferred habitat is swampy and difficult to clear. Threats are imminent, because habitat is still being drained or dammed for agricultural irrigation, and grassland burning limits the extent of suitable habitat. Therefore, a priority rank of 8 remains valid for this species.
The Codfish Island fernbird is found only on Codfish Island, New Zealand. Codfish Island is a nature reserve of 1,396 ha (3,448 ac) located 3 km (1.8 mi) off the northwest coast of Stewart Island (IUCN 1979; McClelland 2007). There are five subspecies of
Although there is no accurate estimate of the current size of the Codfish Island fernbird population (estimates are based on incidental encounter rates in the various habitat types on the island), the population as of 2007 was believed to be several hundred. McClelland (2007) concluded that is it likely that the population peaked and is stable.
Fernbirds are sedentary and are not strong fliers. They are secretive and reluctant to leave cover. They feed in low vegetation or on the ground, eating mainly caterpillars, spiders, grubs, beetles, flies, and moths (Heather and Robertson 1997). Codfish Island's native vegetation has been modified by the introduced Australian brush-tailed possum (
IUCN and BLI only recognize the species
Several specific conservation measures have been undertaken by the
To safeguard the Codfish Island fernbird, the NZ DOC established a second population on Putauhinu Island, a small 144-ha (356-ac), privately owned island located approximately 40 km (25 mi) south of Codfish Island. The Putauhinu population established rapidly, and McClelland (2007) reported that it is also believed to be stable. While there are no accurate data on the population size or trends on Putauhinu, as of 2007, the numbers were estimated to be 200 to 300 birds spread over the island (McClelland 2007). Even with a second population, the Codfish Island fernbird still remains vulnerable to naturally occurring storm events due to its restricted range and small population size.
In our 2009 ANOR, the Codfish Island fernbird received an LPN of 12. After reevaluating the available information, we find that a change in the LPN for this subspecies is not warranted. The information available indicates that the subspecies faces threats that are low to moderate in magnitude because: (1) It exists on an island that is a nature reserve and (2) the removal of invasive predator species and the establishment of a second population have allowed for a rebound in the subspecies' population. Although the actual population numbers for this subspecies are unknown (possibly around 500 individuals), threats are nonimminent because the conservation measures to prevent the invasion of predatory invasive species indicate that they have been successful; the subspecies is being actively managed. Therefore, a priority rank of 12 remains valid for this subspecies. However, we will continue to monitor the status of this subspecies.
The Ghizo white-eye (also known as the splendid white-eye) is endemic to the island of Ghizo. Ghizo is a very densely populated island in the Solomon Islands in the South Pacific ocean, east of Papua New Guinea (BLI 2010m). The Ghizo white-eye is described as a “warbler-like” bird. The island of Ghizo is 11 km long and 5 km wide (7 by 3 mi), and the human population is estimated to be approximately 6,670 as of 2005 (
This species was characterized as being locally common in the 1990s in the remaining tall or old-growth forest, which is very fragmented and is now less than 1 km
The most recent population estimate for this species is 250 to 999 birds (BLI 2010m). Biologists have recommended that systematic surveys be conducted for this species to verify its conservation status (Sherley 2001). While there are no data on population trends, the species is very likely declining due to habitat loss and degradation (BLI 2010m).
The very tall old-growth forest on Ghizo is still under threat from clearance for local use as timber, firewood, and gardens, as are the areas of other secondary growth, which are suboptimal habitats for this species. The species is also under considerable threat from deforestation for agricultural land (BLI 2008).
In our 2009 ANOR, the Ghizo white-eye received an LPN of 8. After reevaluating the available information, we find that a change in the LPN for this species is warranted. The Ghizo white-eye does not represent a monotypic genus. It faces threats that are high in magnitude due to declining suitable habitat; its range is estimated to be less than 35 km
The black-backed tanager is endemic to the coastal Atlantic forest region of southeastern Brazil. The species has been documented in Rio de Janeiro, Sao Paulo, Parana, Santa Catarina, Rio Grande do Sul, and Espirito Santo (Argel-de-Oliveira in litt. 2000, as cited in BLI 2008; BLI 2010n). The species is generally restricted to coastal sand-plain forest and restinga, but has also been located in secondary forests (BLI 2008). Restinga is a Brazilian term that describes white sand forest habitat consisting of a patchwork of vegetation types, such as beach vegetation; open shrubby vegetation; herbaceous, shrubby coastal sand dune habitat; and dry and swamp forests distributed over coastal plains from northeastern to southeastern Brazil (Rocha
The Atlantic Forest, on which this species depends, extends up to 600 km (373 mi) west of the Atlantic Ocean. It consists of tropical and subtropical moist forests, tropical dry forests, and mangrove forests at mostly low-to-medium elevations less than 1,000 m (3,281 ft); however, altitude can reach as high as 2,000 m (6,562 ft) above sea level. Between 7 and 10 percent of this habitat remains intact (Morellato and Haddad 2000, p. 786; Oliveira-Filho and Fontes 2000, p. 794). Based on a number of other estimates, 92 to 95 percent of the area historically covered by tropical forests within the Atlantic Forest biome has been converted or severely degraded as a result of various human activities (Morellato and Haddad 2000, p. 786; Myers
This species' physical characteristics include an underbody color of blue-turquoise and a pale red-brown vent or cloaca. The male has a chestnut colored head and black back. The female is
The black-backed tanager is generally not considered rare within suitable habitat (BLI 2010n). This species is more common in Sao Paulo during the winter, and records from Espirito Santo are only from the winter season. Clarification of the species' seasonal movements would provide an improved understanding of the species' population status and distribution, but currently populations appear small and fragmented and are declining rapidly; likely in response to extensive habitat loss (BLI 2010n). Population estimates range from 2,500 to 10,000 individuals (BLI 2010n).
The primary threat impacting this species is the rapid and widespread loss of habitat for beachfront development. A minor threat may be that it occasionally appears in the illegal bird trade (BLI 2010n). The remaining tracts of suitable habitat in Rio de Janeiro and São Paulo are threatened by ongoing development of coastal areas, primarily for tourism enterprises (
Because this species inhabits coastal areas, sea level rise may also affect this species (Alfredini
In our 2009 ANOR, the black-backed tanager received an LPN of 8. After reevaluating the available information, we find that a change in the LPN for this species is not warranted at this time. The black-backed tanager does not represent a monotypic genus. Threats (primarily habitat loss) to the species are moderate in magnitude due to the species' fairly large range, population size, and apparent flexibility in diet and habitat suitability. Threats are however, imminent because the species is at risk by ongoing and widespread loss of habitat due to beachfront and related development. Therefore, a priority rank of 8 remains valid for this species.
The Lord Howe pied currawong is a subspecies separate from the five mainland pied currawongs (
This subspecies is endemic to Lord Howe Island, New South Wales, Australia. Lord Howe Island is 600 km (373 mi) northeast of Sydney, Australia. This is also the distance to the subspecies' closest relative, the mainland Pied Currawong (
The Lord Howe pied currawong breeds in rainforests and palm forests, particularly along streams. Its territories include sections of streams or gullies that are lined by tall timber (Garnett and Crowley 2000). The highest densities of Lord Howe pied currawong nests have been located on the slopes of Mount Gower and in the Erskine Valley, with smaller numbers on the lower land to the north (Knight 1987, as cited in Garnett and Crowley 2000). The nests are typically situated high in trees and are made in a cup shape with sticks and lined with grass and palm thatch (NSW DECC 2005). As of 2001, most of Lord Howe Island was still forested, and the removal of feral animals resulted in the recovery of the forest understory (WWF 2001).
The Lord Howe pied currawong is omnivorous and eats a wide variety of food, including native fruits and seeds (Hutton 1991). It is the only remaining native island vertebrate predator (NSW DECC 2010). It has been recorded eating seabird chicks, poultry, and chicks of the Lord Howe woodhen (
In the 2000 Action Plan for Australian Birds (Garnett and Crowley 2000), the Lord Howe pied currawong population was estimated at approximately 80 mature individuals. In 2007, the Foundation for National Parks & Wildlife (FNPW 2007) estimated the breeding population of the Lord Howe pied currawong was 80 to 100 pairs, with a nesting territory in the tall forest areas of about 5 ha (12 ac) per pair. The population size is limited by the amount of available habitat and the lack of food during the winter (FNPW 2007). The
The main threat identified for the Lord Howe pied currawong is habitat clearing and modification. Other threats include non-target poisoning, and effects associated with extremely small population sizes (NSW DECC 2010). A lesser threat to the Lord Howe pied currawong is human interaction with the species. Prior to the 1970s, locals would shoot this currawong because it preys on nestling birds (Hutton 1991). The Lord Howe pied currawong remains unpopular with some residents, likely because of its predatory nature on nestlings. It is unclear what effect this localized killing has on the overall population size and distribution of the species (Garnett and Crowley 2000). Also, because the Lord Howe pied currawong often preys on ship (black) rats, it may be subject to nontarget poisoning during rat-baiting programs (DEC 2007b). Close monitoring of the population is needed because this small, endemic population is highly susceptible to catastrophic events, such as disease or introduction of a new predator (Garnett and Crowley 2000).
In our 2009 ANOR, the Lord Howe pied currawong received an LPN of 12. After re-evaluating the threats to the Lord Howe pied currawong, we have determined that a change in the LPN representing the magnitude and imminence of threats to the subspecies is warranted. The Lord Howe pied currawong does not represent a monotypic genus. It faces threats that are high in magnitude due to its extremely small population size, non-target poisoning, and habitat clearing and modification. Despite conservation efforts, the population of the Lord Howe pied currawong has remained around 100 to 200 individuals. Species with small, declining population sizes such as these may be at greater risk of extinction due to synergistic effects (Davies
Harris' mimic swallowtail butterfly is a subspecies endemic to Brazil (Collins and Morris 1985). Although the species' range includes Paraguay, the subspecies has not been confirmed in Paraguay (Collins and Morris 1985; Finnish University and Research Network 2004). Occupying the lowland swamps and sandy flats above the tidal margins of the coastal Atlantic Forest, the subspecies prefers alternating patches of strong sun and deep shade (Collins and Morris 1985; Brown 1996). This subspecies is polyphagous, meaning that its larvae feed on more than one plant species (Kotiaho
The Harris' mimic swallowtail was previously known in Espirito Santo, however, there are no recent confirmations of its occurrence there (Collins and Morris 1985; New and Collins 1991). In Rio de Janeiro, Harris' mimic swallowtail has been confirmed in three localities. Two colonies were identified on the east coast of Rio de Janeiro, at Barra de São João and Macaé, and the other in Poço das Antas Biological Reserve, farther inland. The Barra de São João colony is the best-studied. Between 1984 and 2004, it maintained a stable size, varying between 50 to 250 individuals (Brown 1996; Collins and Morris 1985; Brown in litt. 2004), and was reported to be viable, vigorous, and stable in 2004 (Brown, Jr. in litt. 2004). There are no estimates of the size of the colony in Poço das Antas Biological Reserve where it had not been seen for 30 years prior to its rediscovery there in 1997 (Brown, Jr. in litt. 2004). Population estimates are lacking for the colony at Macaé, where the subspecies was netted in Jurubatiba National Park in the year 2000, after having not been seen in the area for 16 years (Monteiro
Both Barra de São João and the Poço das Antas Biological Reserve lie within the São João River Basin. Conditions at Barra de São João appear to be suitable for long-term survival of this subspecies. The Barra de São João River Basin encompasses a 216,605-ha (535,240-ac) area, 150,700 ha (372,286 ac) of which is managed as protected area. The Harris' mimic swallowtail's preferred environment of open and shady areas continues to be present in the region, with approximately 541 forest patches averaging 127 ha (314 ac) in size, covering nearly 68,873 ha (170,188 ac), and a minimum distance between forest patches of 276 meters (m) (0.17 mi) (Teixeira 2007). In studies between 1984 and 1991, Brown (1996) determined that Harris' mimic swallowtails in Barra de São João flew a maximum distance of 1000 m (0.62 mi). It follows that the average flying distance would be less than this figure. Thus, the average 276 m (0.17 mi) distance between forest patches in the Barra de São João River Basin is clearly within the flying distance of this subspecies. Because the colony at Barra de São João has maintained a stable population for 20 years, it is probable that the conditions available there remain suitable.
Habitat destruction has been the main threat to this subspecies (Collins and Morris 1985; Brown 1996), especially urbanization in Barra de São João, industrialization in Macaé (Jurubatiba National Park), and previous fires that occurred in the Poço das Antas Biological Reserve. As described in detail for the fluminense swallowtail (below), Atlantic Forest habitat has been reduced to 5 to 10 percent of its original cover. More than 70 percent of the Brazilian population lives in the Atlantic forest, and coastal development is ongoing throughout the Atlantic Forest region (Hughes
Another factor affecting many butterfly species is illegal collection. The wildlife trade is extremely lucrative and as wildlife becomes rarer; it is worth more. Although there are laws on illegal wildlife trade, in some countries, many times laws are rarely enforced due to inadequate resources; and only a fraction of smuggled wildlife is caught (
Harris' mimic swallowtail ranges within two protected areas: Poço das Antas Biological Reserve and Jurubatiba National Park. These protected areas are described in detail for the fluminense swallowtail below. The Poço das Antas Biological Reserve (Reserve) was established to protect the golden lion tamarin (
In our 2009 ANOR, the Harris' mimic swallowtail received an LPN of 12. After reevaluating the threats to this species, we have determined that a change in the listing prioritization number is warranted. Harris' mimic swallowtail is a subspecies and is not within a monotypic genus. Although the best-studied colony has maintained a stable and viable size for nearly two decades, there is limited suitable habitat remaining for this subspecies. Habitat destruction remains a threat. These threats are high in magnitude due to its small endemic population and potential catastrophic events such as severe tropical storms or introduction of a new disease or predator. The only known populations are within close proximity to a major, expanding city in Brazil—Rio de Janiero, the second largest city in Brazil. As this species becomes rarer, it becomes even more desirable to collectors (Traffic 2010, pp. 52, 122, 179). Although the species exists in a protected area, collectors will take risks to obtain these rare and desirable species. Because the population is very small and limited to only two small areas, we find the threats are of high magnitude. However, we do not find that these threats are imminent because the subspecies is protected by Brazilian law; and the two colonies are located within protected areas. Based on the best available information, we have changed the LPN from a 12 to a 6 to reflect non-imminent threats of high magnitude.
The Jamaican kite swallowtail is endemic to Jamaica, preferring wooded, undisturbed habitat containing its only known larval host plant West Indian lancewood (
The Jamaican kite swallowtail maintains a low population level. It occasionally becomes locally abundant in Rozelle during the breeding season in early summer and again in early fall (Brown and Heineman 1972; Collins and Morris 1985; Garraway
Habitat destruction has been considered a primary threat to the Jamaican kite swallowtail. Monophagous butterflies (meaning that their larvae feed only on a single plant species) such as the Jamaican kite
Rozelle is also subject to naturally occurring, high-impact stochastic events, such as regularly-occurring hurricanes, as described in the 2007 ANOR (72 FR 20184; April 23, 2007). Hurricane-related weather damage in the last two decades along the coastal zone of Rozelle has resulted in the erosion and virtual disappearance of the once-extensive recreational beach (Economic Commission for Latin America and the Caribbean (ECLAC), United Nations Development Programme (UNDP), and the Planning Institute of Jamaica (PIOJ) (2004)). Hurricane Ivan, a category 5 hurricane, caused severe local damage to Rozelle Beach in 2004, including road collapse caused by the erosion of the cliff face and shoreline. The estimated restoration cost from Hurricane Ivan damage was $23 million USD ($1.6 million Jamaican dollars (J$) (ECLAC
In western parishes, habitat destruction also threatens adult Jamaican kite swallowtails. Cockpit Country, encompassing 30,000 ha (74,131 ac) of rugged forest-karst (a specialized limestone habitat) terrain, spans four western parishes, including Trelawny and St. Elizabeth, where adult Jamaican kite swallowtails have been observed (Gordon and Cambell 2006). As of 2006, 81 percent of this region remained forested, although fragmentation was occurring as a result of human-induced activities (Tole 2006). Threats to Cockpit Country include bauxite mining, unregulated plant collecting, extensive logging, conversion of forest to agriculture, illegal drug cultivation, and expansion of human settlements. These activities contribute to threats to the hydrology system from in-filling, siltation, accumulation of solid waste, and invasion by nonnative, invasive species (Cockpit Country Stakeholders Group and JEAN (Gordon and Cambell 2006; Tole 2006; Jamaica Environmental Advocacy Network 2007)).
The Blue and John Crow Mountains National Park, located on the inland portions of St. Thomas and St. Andrew and the southeast portion of St. Mary Parishes, is the only protected area in which adult Jamaican Kite swallowtails have been observed (Bailey 1994; Jamaica Conservation and Development Trust (JCDT) 2006). Established in 1990, this Park encompasses 49,520 ha (122,367 ac) of mountainous, forested terrain that ranges in elevation from 150 to 2,256 m (492 to 7,402 ft) and is considered one of the best-managed protected areas in Jamaica (JCDT 2006). However, deforestation consisting of slash-and-burn agriculture and illegal timber harvesting continues to be a threat in the Blue Mountains (Tole 2006; TNC 2010).
The Jamaican kite swallowtail has been collected for commercial trade in the past (Collins and Morris 1985; Melisch 2000; Schütz 2000). The Jamaican Wildlife Protection Act of 1998 carries a maximum penalty of U.S. $1,439 (J $100,000) or 12 months of imprisonment for violating its provisions. This deterrent appears to be effectively protecting this species from illegal trade (NEPA 2005). As of 2008, we were unaware of any recent seizures or smuggling in this species into or out of the United States (Office of Law Enforcement, U.S. Fish and Wildlife Service, Arlington, Virginia in litt.).
In our 2009 ANOR, the Jamaican kite swallowtail received an LPN of 8. After reevaluating the threats to the Jamaican kite swallowtail, we have determined that a change in the listing priority number is warranted. The Jamaican kite swallowtail does not represent a monotypic genus. The current threats to the species are high in magnitude particularly since it only has one known larval host plant. Slash-and-burn agriculture and illegal timber harvesting continues to occur within this species' habitat (TNC 2010). These threats are occurring at the species' only known breeding site and they are exacerbated by the species' restricted distribution of its larval food plant and range. In addition, stochastic events such as hurricanes, tropical storms, and introduction of a new disease are unpredictable. Illegal collection of butterfly species (refer to discussion under Harris' mimic swallowtail) continues to occur which further adds to the pressures affecting this species. Although Jamaica has taken regulatory steps to preserve native swallowtail habitat, the threats affecting this species are imminent; its habitat is decreasing; and this loss of habitat is ongoing. Based on a reevaluation of the threats to this species, we have changed the LPN from an 8 to a 2 to reflect imminent threats of high magnitude.
The fluminense swallowtail is endemic to Brazil's restinga habitat within the Atlantic Forest region in the tropical and subtropical moist broadleaf forests of coastal Brazil (Thomas 2003). Its habitat is characterized by medium-sized trees and shrubs that are adapted to coastal conditions (Kelecom 2002). During the caterpillar stage of its lifecycle, it feeds on a species in the Dutchman's pipe genus (
The fluminense swallowtail is sparsely distributed throughout its range, reflecting the patchy distribution of its preferred habitat (Otero and Brown 1984; Tyler
A population estimate reported in 1984 in Barra de São João was between 20 and 100 individuals (Otero and Brown 1984). The colony within the Poço das Antas Biological Reserve was rediscovered in 1997, after a nearly 30-year absence from this locality (Brown, Jr. in litt. 2004). Researchers noted only that “large numbers” of swallowtails were observed (Brown, Jr. in litt. 2004; Robbins in litt. 2004). There are no population estimates for the other colonies. However, individuals from the viable population in Barra de São João migrate widely in some years, and this is likely to enhance interpopulation gene flow among existing colonies (Brown, Jr. in litt. 2004).
Habitat destruction has been the main threat to this species (Collins and Morris 1985; Brown 1996; Gimenez Dixon 1996). Monophagous butterflies tend to be more threatened than polyphagous species (Kotiaho
One estimate concluded that Rio de Janeiro contains 1,675,457 ha (4,140,127 ac) of suitable habitat (Uehara-Prado and Fonseca 2007). While the presence of suitable habitat should not be used to infer the presence of a species (Uehara-Prado and Fonseca 2007), it should facilitate more focused efforts to identify and confirm additional localities and the conservation status of the fluminense swallowtail. Evaluating the correlation between the distribution of fluminense swallowtail and the existing protected areas within Rio de Janeiro revealed that only two known occurrences of the fluminense swallowtail correlated with protected areas, including the Poço das Antas Biological Reserve (Uehara-Prado and Fonseca 2007). The Poço das Antas Biological Reserve and the Jurubatiba National Park are the only two protected areas considered large enough to support viable populations of the fluminense swallowtail (Otero and Brown 1984; Brown, Jr. in litt. 2004; Robbins in litt. 2004). The Poço das Antas Biological Reserve, established in 1974, encompasses 13,096 ac (5,300 ha) of inland Atlantic Forest habitat (CEPF 2007a; Decree No. 73,791, 1974).
According to the 2005 revised management plan (IBAMA 2005), the Reserve is used solely for protection, research, and environmental education. Public access is restricted, and there is an emphasis on habitat conservation, including protection of the Río São João. This river runs through the Reserve and is integral to creating the restinga conditions preferred by the fluminense swallowtail. The Reserve was plagued by fires in the late 1980s through the early 2000s, but fire is not currently thought to be a threat. Between 2001 and 2006, there was an increase in the number of private protected areas near or adjacent to the Poço das Antas Biological Reserve and Barra de São João (Critical Ecosystem Partnership Fund (CEPF) 2007a). Corridors are being created between existing protected areas and 13 privately protected forests, by planting and restoring habitat previously cleared for agriculture or by fires (De Roy 2002).
The Jurubatiba National Park (14,860 ha; 36,720 mi
Commercial exploitation has been identified as a potential threat to the fluminense swallowtail (Collins and Morris 1985; Melisch 2000; Schütz 2000). The species is easy to capture, and species with restricted distributions or localized populations, such as the fluminense swallowtail, tend to be more vulnerable to overcollection than those with a wider distribution (Brown, Jr. in litt. 2004; Robbins in litt
Parasitism has been indicated to be a factor affecting the fluminense swallowtail. Recently, Tavares
Although Harris' mimic swallowtail and the fluminense swallowtail face similar threats, there are several dissimilarities that influence the magnitude of these threats. Fluminense swallowtails are monophagous (Otero and Brown 1984; Kotiaho
In our 2009 ANOR, the fluminense swallowtail received an LPN of 5. After reevaluating the threats to the fluminense swallowtail, we have determined that a change in the listing priority number is not warranted. The fluminense swallowtail does not represent a monotypic genus. The species is currently at risk from habitat destruction; however, we have determined that overutilization and parasitism are not currently occurring such that they are threats to the fluminense swallowtail. The current threat of habitat destruction is of high magnitude because the species: (1) Occupies highly specialized habitat; (2) requires large areas to maintain a viable colony; and (3) is only found within two protected areas considered to be large enough to support viable colonies. However, additional populations have been reported, increasing previously known population numbers and distribution. The threat of habitat destruction is nonimminent because most habitat modification is the result of historical destruction that has resulted in fragmentation of the current landscape; however, the potential for continued habitat modification exists, and we will continue to monitor the situation. On the basis of this information, the fluminense swallowtail retains a priority rank of 5.
Hahnel's Amazonian swallowtail
Hahnel's Amazonian swallowtail is known in three localities along the tributaries of the middle and lower Amazon River basin in the states of Amazonas and Pará (Collins and Morris 1985; New and Collins 1991; Tyler
Habitat alteration (
This species of swallowtail has been collected for commercial trade (Collins and Morris 1985; Melisch 2000; Schütz 2000). Species with restricted distributions or localized populations, such as the Hahnel's Amazonian swallowtail, are more vulnerable to overcollection than those with a wider distribution (Brown in litt. 2004; Robbins in litt. 2004). Although not strictly protected from collection throughout Brazil, the state of Pará recently declared the capture of Hahnel's Amazonian swallowtail for purposes other than research to be forbidden (Decreto No. 802, 2008). It is not listed in any appendices of CITES. As of 2008, seizures of Hahnel's Amazonian swallowtail into or out of the United States had not been reported (Office of Law Enforcement, U.S. Fish and Wildlife Service, Arlington, Virginia in litt. 2008). The best available information does not indicate that overutilization is a threat to the species.
Competition for host plants has been identified as a potential threat to Hahnel's Amazonian swallowtail. Researchers in the past believed that this species might suffer from host plant competition with other butterfly species in the region (Wells 1983; Collins and Morris 1985; Brown 1996); however, this competition has not been confirmed. It occupies the same range with another swallowtail butterfly,
After reevaluating the threats to the Hahnel's Amazonian swallowtail, we have determined that a change in listing priority number is warranted. Hahnel's Amazonian swallowtail
The Kaiser-I-Hind swallowtail is native to the Himalayan regions of Bhutan, China, India, Laos, Myanmar, Nepal, Thailand, and Vietnam (Shrestha 1997; FRAP 1999; Osada
Habitat destruction is the greatest threat to this species, which prefers undisturbed high-altitude habitat (Collins and Morris 1985; Tordoff
Since 1996, the Kaiser-I-Hind swallowtail has been categorized on the IUCN Red List as a species of “Lower Risk/near threatened”; it has not been reevaluated using the 1997 criteria (Gimenez Dixon 1996; IUCN 2010). The species was considered “Rare” by Collins and Morris (1985). Despite its widespread distribution, local populations are not abundant (Collins and Morris 1985). The known localities and conservation status of the species within each range country follows:
The Kaiser-I-Hind swallowtail is highly valued and has been collected for commercial trade, despite range country regulations prohibiting or restricting such activities (Collins and Morris 1985; Schütz 2000). In China, where the species is protected by the Animals and Plants (Protection of Endangered Species) Ordinance (1989), which restricts import, export, and possession of the species, species purportedly derived from Sichuan were being advertised for sale on the Internet for 60 U.S. Dollars (US$). In India, the Kaiser-I-Hind swallowtail is listed on Schedule II of the Indian Wildlife Protection Act of 1972, which prohibits hunting without a license (Collins and Morris 1985; Indian Wildlife Protection Act 2006). However, between 1990 and 1997, illegally collected specimens were selling for 500 Rupees (12 US$) per female and 30 Rupees (0.73 US$) per male (Bahuguna 1998). In Nepal, the Kaiser-I-Hind swallowtail is protected by the National Parks and Wildlife Conservation Act of 1973 (His Majesty's Government of Nepal (HMGN) 2002). However, the Nepal Forestry Ministry determined in 2002 that the high commercial value of its “Endangered” species on the local and international market may result in local extinctions of species such as the Kaiser-I-Hind (HMGN 2002).
In Thailand, the Kaiser-I-Hind swallowtail and 13 other invertebrates are listed under Thailand's Wild Animal Reservation and Protection Act (WARPA) of 1992 (B.E. 2535 1992), which makes it illegal to collect wildlife (whether alive or dead) or to have the species in one's possession (Hongthong 1998; Pornpitagpan 1999; FAO 2001; Choldumrongkul in litt. 2007). In addition to prohibiting possession, WARPA prohibits hunting, breeding, and trading. Import and export are only allowed for conservation purposes
In Vietnam, Kaiser-I-Hind swallowtails are reported to be among the most valuable of all butterflies (World Bank 2005). In 2006, the species was listed on Schedule IIB of Decree No. 32 on “Management of endangered, precious and rare forest plants and animals.” A Schedule IIB-listing restricts the exploitation or commercial use of species with small populations or that are considered by the country to be in danger of extinction (Canh in litt. 2007). In a recent survey conducted by TRAFFIC Southeast Asia (2007), of 2000 residents in Ha Noi, Vietnam, the Kaiser-I-Hind swallowtail was among 37 Schedule IIB-species that were actively being collected (p. 36). The majority of the survey respondents were unaware of legislation prohibiting collection of Schedule IIB-species (p. 7). This is a highly desirable species, and there is a culture within Vietnam of consuming rare and expensive wild animal dishes, particularly in Ha Noi among the elite (TRAFFIC 2007, p. 9). This practice does not seem to be decreasing; rather it appears to be increasing. Thus, we find that overutilization for illegal domestic use is a threat to this species. Although Vietnam has implemented several action plans to strengthen control of trade in wild fauna and flora (TRAFFIC 2007, p. 9), within-country protections are inadequate to protect the species from illegal collection throughout its range.
The Kaiser-I-Hind swallowtail has been listed in CITES Appendix II since 1987 (UNEP-WCMC 2008a). Between 1991 and 2005, 160 Kaiser-I-Hind swallowtail specimens were traded internationally under CITES permits (UNEP WCMC 2006), and between 2000 and 2008, 157 specimens were traded (UNEP WCMC 2009). Reports that the Kaiser-I-Hind swallowtail is being captive-bred in Taiwan (Yen and Yang 2001) remain unconfirmed. Since 1993, there have been no reported seizures or smuggling of this species into or out of the United States (Office of Law Enforcement, U.S. Fish and Wildlife Service, Arlington, Virginia in litt. 2008). Therefore, on the basis of global trade data, we do not consider legal international trade to be a threat to this species.
After reevaluating the threats to this species, we have determined that a change in listing priority number is not warranted. The Kaiser-I-Hind swallowtail does not represent a monotypic genus. The current threats of habitat destruction and illegal collection are moderate in magnitude due to the species' wide distribution and to the protections in place. We find that the threats are imminent due to ongoing habitat destruction, high market value for specimens, and inadequate domestic protections for the species or its habitat. Based on our reassessment of the threats, we have retained an LPN of 8 to reflect imminent threats of moderate magnitude.
This section describes the actions that continue to preclude the immediate proposal of listing rules for the 20 species described above. In addition, we summarize the expeditious progress we are making, as required by section 4(b)(3)(B)(iii)(II) of the Act, to add qualified species to the lists of endangered or threatened species and to remove from these lists species for which protections of the Act are no longer necessary.
Section 4(b) of the Act states that the Service may make warranted-but-precluded findings only if it can demonstrate that (1) An immediate proposed rule is precluded by other pending proposals and that (2) expeditious progress is being made on other listing actions. Preclusion is a function of the listing priority of a species in relation to the resources that are available and competing demands for those resources. Thus, in any given fiscal year (FY), multiple factors dictate whether it will be possible to undertake work on a proposed listing regulation or whether promulgation of such a proposal is warranted-but-precluded by higher priority listing actions.
The resources available for listing actions are determined through the annual Congressional appropriations process. The appropriation for the Listing Program is available to support work involving the following listing actions: Proposed and final listing rules; 90-day and 12-month findings on petitions to add species to the Lists of Endangered and Threatened Wildlife and Plants (Lists) or to change the status of a species from threatened to endangered; annual determinations on prior “warranted-but-precluded” petition findings as required under section 4(b)(3)(C)(i) of the Act; critical habitat petition findings; proposed and final rules designating critical habitat; and litigation-related, administrative, and program-management functions (including preparing and allocating budgets, responding to Congressional and public inquiries, and conducting public outreach regarding listing and critical habitat).
The work involved in preparing various listing documents can be extensive and may include, but is not limited to: Gathering and assessing the best scientific and commercial data available and conducting analyses used as the basis for our decisions; writing and publishing documents; and obtaining, reviewing, and evaluating public comments and peer review comments on proposed rules and incorporating relevant information into final rules. The number of listing actions that we can undertake in a given year also is influenced by the complexity of those listing actions; that is, more complex actions generally are more costly. The median cost for preparing and publishing a 90-day finding is $39,276; for a 12-month finding, $100,690; for a proposed rule with critical habitat, $345,000; and for a final listing rule with critical habitat, the median cost is $305,000.
We cannot spend more than is appropriated for the Listing Program without violating the Anti-Deficiency Act (see 31 U.S.C. 1341(a)(1)(A)). In addition, in FY 1998 and for each fiscal year since then, Congress has placed a statutory cap on funds which may be expended for the Listing Program, equal to the amount expressly appropriated for that purpose in that fiscal year. This cap was designed to prevent funds appropriated for other functions under the Act (for example, recovery funds for removing species from the Lists), or for other Service programs, from being used for Listing Program actions (see House Report 105-163, 105th Congress, 1st Session, July 1, 1997).
Since FY 2002, the Service's budget has included a critical habitat subcap to ensure that some funds are available for other work in the Listing Program (“The critical habitat designation subcap will ensure that some funding is available to address other listing activities” (House Report No. 107-103, 107th Congress, 1st Session, June 19, 2001)). In FY 2010, we are using some of the critical habitat subcap funds to fund actions with statutory deadlines.
Thus, through the listing cap, the critical habitat subcap, and the amount of funds needed to address court-mandated critical habitat designations, Congress and the courts have in effect determined the amount of money available for other listing activities. Therefore, the funds in the listing cap, other than those needed to address
In FY 2010, expeditious progress is that amount of work that can be achieved with $10,471,000, which is the amount of money that Congress appropriated for the Listing Program (that is, the portion of the Listing Program funding not related to critical habitat designations for species that are already listed). However, these funds were not enough to fully fund all our court-ordered and statutory listing actions in FY 2010, so we used $1,114,417 of our critical habitat subcap funds in order to work on all of our required petition findings and listing determinations. This brings the total amount of funds we had for listing actions in FY 2010 to $11,585,417. Our process is to make our determinations of preclusion on a nationwide basis to ensure that the species most in need of listing will be addressed first and also because we allocate our listing budget on a nationwide basis. The $11,585,417 is being used to fund work in the following categories: Compliance with court orders and court-approved settlement agreements requiring that petition findings or listing determinations be completed by a specific date; section 4 (of the Act) listing actions with absolute statutory deadlines; essential litigation-related, administrative, and listing program-management functions; and high-priority listing actions for some of our candidate species. In 2009, the responsibility for listing foreign species under the Act was transferred from the Division of Scientific Authority (DSA), International Affairs Program, to the Endangered Species Program. Starting in FY 2010, a portion of our funding is being used to work on the actions described above as they apply to listing actions for foreign species.
For FY 2011, on September 29, 2010, Congress passed a continuing resolution which provides funding at the FY 2010 enacted level. Until Congress appropriates funds for FY 2011, we will fund listing work based on the FY 2010 amount.
In addition, available staff resources are also a factor in determining high-priority species provided with funding. Finally, proposed rules for reclassification of threatened species to endangered are lower priority, because as listed species, they are already afforded the protection of the Act and implementing regulations.
Starting in FY 2010, the Washington Office (WO) Endangered Species Program has full responsibility for foreign species' listing actions under the Act. The Branch of Foreign Species (BFS) was established in June 2010 to specifically work on petitions and other actions under Section 4 of the Act for foreign species.
Our expeditious progress also includes work on listing actions that we funded in FY 2010 and FY 2011 but have not yet been completed to date. These actions are listed below. Actions in the top section of the table are being conducted under a deadline set by a court. Actions in the bottom section of the table are being conducted to meet statutory timelines, that is, timelines required under the Act. The funding for domestic and foreign species was not appropriated separately in FY 2010. In addition to the actions demonstrating expeditious progress mentioned above, we list the progress in adding qualified species to the Federal List of Endangered and Threatened Species for domestic species in the 2010 Candidate Notice of Review (75 FR 69822, published November 10, 2010).
BFS may, based on available staff resources, work on species described within this ANOR with an LPN of 2 or 3, and when appropriate, species with a lower priority if they overlap geographically or have the same threats as the species with the high priority. Including these species together in the same proposed rule results in considerable savings in time and funding, when compared to preparing separate proposed rules for each of them in the future. Because the actions below are either the subject of a court-approved settlement agreement or subject to an absolute statutory deadline and, thus, are higher priority than work on proposed listing determinations for the 20 species described above, publication of proposed rules for these 20 species is precluded. For expeditious progress on domestic actions, see the Candidate Notice of Review, published November 10, 2010.
Despite the priorities that preclude publishing proposed listing rules for these 20 species described in this notice, we are making expeditious progress in adding to and removing species from the Federal lists of threatened and endangered species. Our expeditious progress for foreign species since publication of the 2009 Notice of Review, August 12, 2009 (74 FR 40540) to the current date includes preparing and publishing the following:
As explained above, a determination that listing is warranted-but-precluded must also demonstrate that expeditious progress is being made to add or remove qualified species to and from the Lists of Endangered and Threatened Wildlife and Plants. (Although we do not discuss it in detail here, we are also making expeditious progress in removing species from the Lists under the Recovery program, which is funded by a separate line item in the budget of the Endangered Species Program. As with our “precluded” finding, expeditious progress in adding qualified species to the Lists is a function of the resources available and the competing demands for those funds. Given that limitation, we find that we are making progress in FY 2010 in the Listing Program.
We have endeavored to make our listing actions as efficient and timely as possible, given the requirements of the relevant law and regulations, and constraints relating to workload and personnel. We are continually considering ways to streamline processes or achieve economies of scale, such as by batching related actions together. Given our limited budget for implementing section 4 of the Act, these actions described above collectively constitute expeditious progress.
Our expeditious progress also includes work on pending listing actions described above in our “precluded finding,” but for which decisions had not been completed at the time of this publication.
Section 4(b)(3)(C)(iii) of the Act requires us to “implement a system to monitor effectively the status of all species” for which we have made a warranted-but-precluded 12-month finding, and to “make prompt use of the [emergency listing] authority [under section 4(b)(7)] to prevent a significant risk to the well being of any such species.” For foreign species, the Service's ability to gather information to monitor species is limited. The Service welcomes all information relevant to the status of these species, because we have no ability to gather data in foreign countries directly and cannot compel another country to provide information. Thus, this ANOR plays a critical role in our monitoring efforts for foreign species. With each ANOR, we request information on the status of the species included in the notice. Information and comments on the annual findings can be submitted at any time. We review all new information received through this process as well as any other new information we obtain using a variety of methods. We collect information directly from range countries by correspondence, from peer-reviewed scientific literature, unpublished literature, scientific meeting proceedings, and CITES documents (including species proposals and reports from scientific committees). We also obtain information through the permit application processes under CITES, the Act, and the Wild Bird Conservation Act (16 U.S.C. 4901 et seq.). We also consult with the IUCN species specialist groups and staff members of the U.S. CITES Scientific and Management Authorities, and the Division of International Conservation; and we attend scientific meetings to obtain current status information for relevant species. As previously stated, if we identify any species for which emergency listing is appropriate, we will make prompt use of the emergency listing authority under section 4(b)(7) of the Act.
We request the submission of any further information on the species in this notice as soon as possible, or whenever it becomes available. We especially seek information: (1) Indicating that we should remove a taxon from consideration for listing; (2) documenting threats to any of the included taxa; (3) describing the immediacy or magnitude of threats facing these taxa; (4) identifying taxonomic or nomenclatural changes for any of the taxa; or (5) noting any mistakes, such as errors in the indicated historic ranges.
A list of the references used to develop this notice is available upon request (
This Notice of Review was authored by the staff of the Branch of Foreign Species, Endangered Species Program, U.S. Fish and Wildlife Service (
This Notice of Review is published under the authority of the Endangered Species Act of 1973, as amended (16 U.S.C. 1531
Environmental Protection Agency (EPA).
Final rule.
EPA is finalizing a correction to its previous full approval of Texas's Clean Air Act (CAA) Prevention of Significant Deterioration (PSD) program to be a partial approval and partial disapproval and is also promulgating a Federal Implementation Plan (FIP) for Texas. These actions are based on EPA's determination that at the time EPA approved Texas's PSD program, the program was flawed because the state did not address how the program would apply to all pollutants that would become newly subject to regulation in the future, including non-National Ambient Air Quality Standard (NAAQS) pollutants, among them greenhouse gases (GHGs). The partial disapproval requires EPA to promulgate a FIP and EPA is doing so to assure that GHG-emitting sources in Texas are able to proceed with plans to construct or expand.
This action is effective on May 1, 2011.
EPA has established a docket for this rulemaking under Docket ID No. EPA-HQ-OAR-2010-1033. All documents in the docket are listed in the
For information on this rule, contact Ms. Cheryl Vetter, Air Quality Policy Division, Office of Air Quality Planning and Standards (C504-03), Environmental Protection Agency, Research Triangle Park, NC 27711;
The only governmental entity potentially affected by this rule is the State of Texas. Other entities potentially affected by this rule include sources in all industry groups within the State of Texas, which have a direct obligation under the CAA to obtain a PSD permit for GHGs for projects that meet the applicability thresholds set forth in the Tailoring Rule.
The information presented in this preamble is organized as follows:
This notice-and-comment final rulemaking is intended to assure that large GHG-emitting sources in Texas, which became subject to PSD on January 2, 2011, will continue to be able to obtain preconstruction permits under the CAA New Source Review (NSR) PSD program beyond the April 30, 2011, expiration date of the FIP that EPA put in place for this purpose via an Interim Final Rule. “Determinations Concerning Need for Error Correction, Partial Approval and Partial Disapproval, and Federal Implementation Plan Regarding Texas Prevention of Significant Deterioration Program; Interim Final Rule.” 75 FR 82,430 (Dec. 30, 2010). In this manner, this rulemaking will allow those sources to avoid delays in construction or modification.
As in the interim final rulemaking, EPA is determining in this rulemaking that it erred in fully approving Texas's PSD program in 1992 because at that time, the program had a gap, which recent statements by Texas have made particularly evident. The program did not address its application to, or provide assurances that it has adequate legal authority to apply to, all pollutants newly subject to regulation, including non-NAAQS pollutants, among them GHGs. As a result, EPA is correcting its previous full approval to be a partial approval and partial disapproval. EPA is taking this action through the error-correction mechanism provided under CAA section 110(k)(6). The partial disapproval requires EPA, under CAA section 110(c)(1)(B), to promulgate a FIP within 2 years, and, as part of this rulemaking, EPA is exercising its discretion to promulgate the FIP immediately. Under the FIP, EPA will become the permitting authority for, and apply Federal PSD requirements to, large GHG-emitting sources in accordance with the thresholds established under what we call the Tailoring Rule, which EPA published by notice dated June 3, 2010, 75 FR 31,514.
By becoming the permitting authority, EPA will be able to process preconstruction PSD permit applications for GHG-emitting sources and thereby allow the affected sources to avoid delays in construction and modification. According to Texas, 167 GHG-emitting sources will require PSD permits during 2011. These sources have a real need to have a permitting authority in place in Texas. Although the CAA allows states to implement PSD, and Texas has been implementing an EPA-approved PSD program since 1992, Texas has recently informed EPA that it does not have the intention or the authority to apply PSD to GHG-emitting sources, and that it could very well maintain this position even if the U.S. Court of Appeals for the DC Circuit (the DC Circuit) upholds the GHG rules against legal challenges that Texas and other parties have recently brought. Texas's unwillingness to implement this aspect of the Federal PSD program leaves EPA no choice but to resume its role as the permitting authority for this portion, in order to assure that businesses in Texas are not subject to delays or potential legal challenges and are able to move forward with planned construction and expansion projects that will create jobs and otherwise benefit the state's and the nation's economy. EPA has determined that this action is necessary at this time so that there is no period of time when sources are unable to obtain necessary PSD permits.
In order to assure no gap in permitting, EPA is establishing May 1, 2011, as the effective date for the FIP, which immediately follows the expiration of the interim-final FIP EPA published by notice dated December 30, 2010. EPA stated in the interim final rule that the FIP would remain in place until April 30, 2011.
This section reviews background information concerning the CAA requirements for what SIPs must include, the process for state submittals of SIPs, requirements for EPA action on SIPs and SIP revisions, and FIPs.
Congress enacted the NAAQS and SIP requirements in the 1970 CAA Amendments. CAA section 110(a)(1) requires that states adopt and submit to EPA for approval SIPs that implement the NAAQS. CAA section 110(a)(2) contains a detailed list of requirements that all SIPs must include to be approvable by EPA.
Of particular relevance for this action, subparagraph (E)(i) of CAA section 110(a)(2) provides that SIPs must “provide * * * necessary assurances that the state * * * will have adequate personnel, funding, and authority under State * * * law to carry out such implementation plan.* * *” As applicable to PSD programs, this provision means that EPA may approve the SIP PSD provisions only if EPA is satisfied that the state will have adequate legal authority under state law.
After a SIP or SIP revision has been submitted, EPA is authorized to act on it under CAA section 110(k)(3)-(4). Those provisions authorize a full approval or, if the SIP or SIP revision meets some but not all of the applicable requirements, a conditional approval, a partial approval and disapproval, or a full disapproval. If EPA disapproves a required SIP or SIP revision, then EPA must promulgate a FIP at any time within 2 years after the disapproval, unless the state corrects the deficiency within that period of time by submitting a SIP revision that EPA approves. CAA section 110(c)(1).
The CAA provides a mechanism for the correction of SIPs with certain types of inadequacies, under CAA section 110(k)(5), which provides:
Whenever the Administrator finds that the applicable implementation plan for any area is substantially inadequate to * * * comply with any requirement of this Act, the Administrator shall require the State to revise the plan as necessary to correct such inadequacies. The Administrator shall notify the State of the inadequacies and may establish reasonable deadlines (not to exceed 18 months after the date of such notice) for the submission of such plan revisions.
If EPA does not receive the corrective SIP revision by the deadline, CAA section 110(c) authorizes EPA to “find[] that [the] State has failed to make a required submission.” CAA section 110(c)(1)(A). Once EPA makes that finding, CAA section 110(c)(1) requires EPA to “promulgate a Federal implementation plan at any time within 2 years after the [finding] * * * unless the State corrects the deficiency, and [EPA] approves the plan or plan revision, before [EPA] promulgates such [FIP].”
CAA section 110(k)(5), by its terms—specifically, the use of the term “[w]henever”—authorizes, but does not require, EPA to make the specified finding and does not impose any time constraints for EPA to do so. As a result, EPA has discretion in determining whether and when to make the specified finding.
EPA has authority to revise its previous actions concerning SIP submittals. Two mechanisms are available to EPA: The error correction mechanism provided under CAA section 110(k)(6), and EPA's general administrative authority to reconsider its own actions under CAA sections 110 and 301(a), in light of case law.
CAA section 110(k)(6) provides as follows:
Whenever the Administrator determines that the Administrator's action approving, disapproving, or promulgating any plan or plan revision (or part thereof), area designation, redesignation, classification, or reclassification was in error, the Administrator may in the same manner as the approval, disapproval, or promulgation revise such action as appropriate without requiring any further submission from the State. Such determination and the basis thereof shall be provided to the State and public.
As quoted previously, CAA section 110(k)(6) provides EPA with the authority to correct its own “error,” but nowhere does this provision or any other provision in the CAA define what qualifies as “error.” Thus, the term should be given its plain language, everyday meaning, which includes all unintentional, incorrect or wrong actions or mistakes.
The legislative history of CAA section 110(k)(6) is silent regarding the definition of error, but the timing of the enactment of the provision suggests a broad interpretation. The provision was enacted shortly after the Third Circuit decision in
When the court made its determination in
EPA has used CAA section 110(k)(6) in the past to correct errors of a non-technical nature. Most recently, EPA withdrew its approval of SIP PSD
CAA section 110(k)(6), by its terms—specifically, the use of the terms “[w]henever” and “may” and the lack of any time constraints—authorizes, but does not require, EPA to make the specified finding. As a result, EPA has discretion in determining whether and when to make the specified finding.
The provisions in CAA section 110 that authorize EPA to take action on a SIP revision inherently authorize EPA to, on its own initiative, reconsider and revise that action as appropriate. The courts have found that an administrative agency has the inherent authority to reconsider its decisions, unless Congress specifically proscribes the agency's discretion to do so.
Section 301(a) of the CAA, read in conjunction with CAA section 110 and the case law just described, provides further statutory authority for EPA to reconsider its actions under CAA section 110. CAA section 301(a) authorizes EPA “to prescribe such regulations as are necessary to carry out [EPA's] functions” under the CAA. Reconsidering prior rulemakings, when necessary, is part of “[EPA's] functions” under the CAA—in light of EPA's inherent authority as recognized under the case law to do so—and, as a result, CAA section 301(a) confers such authority upon EPA.
EPA finds further support for its authority to narrow its approvals in the Administrative Procedures Act (APA) section 553(e), which requires EPA to give interested persons “the right to petition for the issuance, amendment, or repeal of a rule,” and CAA section 307(b)(1), which expressly contemplates that persons may file a petition for reconsideration under certain circumstances (at the same time that a rule is under judicial review). These authorizations for other persons to petition EPA to amend or repeal a rule suggest that EPA has inherent authority, on its own, to issue such amendment or repeal. This is because EPA may grant a petition from another person for an amendment to or repeal of a rule only if justified under the CAA, and if such an amendment or repeal is justified under the CAA, then EPA should be considered as having inherent authority to initiate the process on its own, even without a petition from another person.
EPA recently used its authority to reconsider prior actions and limit its prior approval of a SIP in connection with California conformity SIPs.
As noted previously, if the state fails to submit a required SIP revision, or does so but EPA then disapproves that SIP revision, then the CAA requires EPA to promulgate a FIP and thereby, in effect, federalize the part of the air pollution control requirements for which the state, through the required SIP revision, would otherwise have been responsible. Specifically, under CAA section 110(c)(1), EPA is required to:
However, CAA section 110(c)(1), as quoted earlier, further provides that if EPA delays promulgating a FIP until later in the 2-year period, and, in the meantime, the state corrects the deficiency by submitting an approvable SIP revision that EPA approves, then EPA is precluded from promulgating the FIP. Similarly, once EPA promulgates a FIP, it stays on the books until the state submits an approvable SIP that EPA then approves.
The PSD program is a preconstruction review and permitting program applicable, under EPA rules, to large new stationary sources and, in general, expansions of existing sources. The PSD program applies in areas that are designated “attainment” or “unclassifiable” for a NAAQS, and is contained in part C of title I of the CAA.
The CAA contemplates that the PSD program be implemented by the states through their SIPs. CAA section 110(a)(2)(C) requires that:
Each implementation plan * * * shall * * * include a program to provide for * * * regulation of the modification and construction of any stationary source within the areas covered by the plan as necessary to assure that national ambient air quality standards are achieved, including a permit program as required in part[] C * * * of this subchapter.
Each implementation plan * * * shall * * * meet the applicable requirements of * * * part C of this subchapter (relating to significant deterioration of air quality and visibility protection).
Each applicable implementation plan shall contain emission limitations and such other measures as may be necessary, as determined under regulations promulgated under this part [C], to prevent significant deterioration of air quality for such region * * * designated * * * as attainment or unclassifiable.
These provisions, read in conjunction with the PSD applicability provisions, CAA sections 165(a)(1) and 169(1), mandate that SIPs include PSD programs that are applicable to any air pollutant that is subject to regulation under the CAA, including, as discussed later in this preamble, GHGs as of January 2, 2011.
Most states have EPA-approved SIP PSD programs, and as a result, in those states, PSD permits are issued by state or local air pollution control agencies. In states that do not have EPA-approved SIP PSD programs, EPA issues PSD permits under its own authority, although in some cases, EPA has delegated such authority to the state or local agency.
EPA has long held the view that PSD applies to “any pollutant subject to regulation under the CAA,” and that includes non-NAAQS pollutants. EPA's long-standing regulations have interpreted CAA section 165(a) broadly enough to capture non-NAAQS pollutants. A detailed discussion of these positions was provided in the Tailoring Rule at 75 FR 31,560/3, and in the Interim Final Rule at 75 FR 82,443.
Under the PSD applicability requirements, PSD applies to sources automatically, that is, by operation of law, as soon as their emissions of pollutants become subject to regulation under the CAA. This is because CAA section 165(a)(1) prohibits “major emitting facilit[ies]” from constructing or modifying without obtaining a permit that meets the PSD requirements, and CAA section 169(1) defines a “major emitting facility” as a source that emits a specified quantity of “any air pollutant,” which, as noted earlier, EPA has long interpreted as any pollutant subject to regulation. Whenever EPA promulgates control requirements for a pollutant for the first time, that pollutant becomes subject to regulation, and any stationary source that emits that pollutant in sufficient quantities becomes a “major emitting facility” that, when it constructs or modifies, becomes subject to PSD without any further action from EPA or a state or local government.
EPA regulations have long codified automatic PSD applicability.
In most states with approved PSD programs, PSD does apply automatically. However, in a minority of
In a recent decision, the U.S. Court of Appeals for the 7th Circuit (7th Circuit), mistakenly citing to PSD provisions when the issue before the court involved the separate and different non-attainment provisions of CAA sections 171-193, concluded that sources could continue to abide by permitting requirements in an existing SIP until amended, even if that SIP does not comport with the law.
In 1972, shortly after the enactment of the 1970 CAA Amendments, Texas submitted to EPA its SIP to attain and maintain the NAAQS that EPA had promulgated by that time. As part of that SIP revision, Texas provided assurances that it had legal authority to carry out the SIP, in accordance with the predecessor to CAA section 110(a)(2)(E)(i). EPA approved Texas's SIP, including the assurances of legal authority, by notice dated May 31, 1972. 37 FR 10,842.
In the 1977 CAA Amendments, Congress enacted the PSD program. In the immediate aftermath, EPA acted as the PSD permitting authority in the states, but EPA began to delegate to various state authorities all or part of EPA's authority to issue PSD permits. In addition, at this time, EPA revised its pre-existing regulations, which had established a preconstruction permitting program, to conform to the 1977 CAA requirements. Each state was required to adopt a PSD program and submit it for approval as a SIP revision, and, if the PSD program met CAA requirements, EPA approved the program, and the state then became the PSD permitting authority. This process occurred for most of the states in the nation, including Texas. A brief history of Texas's initial PSD SIP approval follows.
Beginning in 1980, when EPA was still the permitting authority for Federally required PSD permits in Texas, the State requested delegation of certain aspects of the Federal PSD program, and in a series of actions, EPA granted that authority.
include only those stationary sources and modifications with emissions of air contaminants for which a [NAAQS] has been issued. Under the PSD and [nonattainment] NSR requirements, [Texas's] definitions must include sources with emissions of “
During 1985-1988, Texas submitted a series of SIP revisions comprising its PSD program to EPA for approval. In these SIP revisions, Texas established key components of its PSD rules by incorporating by reference EPA's PSD rules found in 40 CFR 52.21. Of most importance for present purposes, Texas incorporated by reference (IBR'd) EPA's PSD applicability regulations in 52.21.
In adopting a particular SIP revision that IBR'd EPA's regulations, however, Texas intended that IBR to apply to only the EPA regulations as they read as of the date that Texas adopted the SIP revision. Texas did not intend that IBR in that SIP revision to apply to subsequent revisions to those regulations. This became readily apparent during the course of EPA's review of Texas's SIP revisions. The TACB adopted the first SIP revision on July 26, 1985.
(13) The proposed facility shall comply with the Prevention of Significant Deterioration of Air Quality regulations promulgated by the [EPA] in the Code of Federal Regulations at 40 CFR 52.21 as amended * * *, hereby incorporated by
The TACB submitted this SIP revision to EPA on December 11, 1985.
Texas responded with a letter dated October 24, 1986,
An issue of concern * * * is whether the [TACB] intended to incorporate by reference Federal rules prospectively in the PSD rule § 116.3(a)(13) and in the stack height rule § 116.3(a)(14). [A]lthough our intention was not prospective rulemaking and we do not believe the rule language implies such, we have no specific objection to including the date of Federal adoption of any Federal material adopted by reference by the TACB in future SIP revisions (including the proposed PSD and stack height revisions). By initiating the public hearing process for PSD rules again (to incorporate requested revisions), Federal PSD regulations amended on July 12, 1985 will be subject to the state public participation process. This should eliminate the concern expressed in your July 3, 1986 letter.
Accordingly, on July 17, 1987, the TACB adopted a revision to its PSD rule, § 116.3(a)(13), so that the rule continued to IBR EPA's PSD regulatory requirements at 40 CFR 52.21, but referenced the date of November 7, 1986.
However, some 8 months later, by notice published on July 1, 1987, EPA adopted the PM
(13) The proposed facility shall comply with the Prevention of Significant Deterioration (PSD) of Air Quality regulations promulgated by the Environmental Protection Agency (EPA) in the Code of Federal Regulations at 40 CFR 52.21 as amended August 1, 1987 * * *, except for [certain identified] paragraphs [not here relevant].
EPA proposed to approve this SIP revision, with this iteration of the Texas PSD rule, by notice dated December 22, 1989,
This history shows that both EPA and Texas were well aware that Texas's method of incorporating by reference EPA's regulatory requirements into Texas's PSD rule was not prospective and therefore did not automatically update to incorporate a pollutant newly subject to regulation.
The record of Texas's PSD program includes limited references to, or discussion of, legal authority that may be relevant to whether Texas provided assurances that it had adequate legal authority to apply PSD to pollutants newly subject to regulation. The following merit review:
First, in adopting and submitting the PSD SIP revisions, the TACB—the agency charged with taking that action—relied on its general legal authority to adopt and submit the SIP revisions. The TACB adopted regulatory amendments through “Board Orders,” and then submitted those Board Orders to EPA as SIP revisions. The Board Orders typically cited general authority under the Texas CAA. One example is TACB Board Order No. 88-08 (July 15, 1988), which revised the Texas PSD rule to provide a later date for IBR'ing EPA's PSD program, and which comprised one of the SIP revisions that formed the basis for the Texas PSD program that EPA approved by notice dated June 24, 1992 (57 FR 28,093). This Board Order provides, in relevant part, “Section 3.09(a) of the Texas CAA gives the Board authority to make rules and regulations consistent with the general intent and purposes of the Act and to
Second, the 1990 CAA Amendments amended CAA section 169(1) to add another type of source that was subject to PSD: Large municipal combustors. Shortly after the 1990 amendments, and before issuing final approval for the Texas PSD program, EPA asked Texas for assurances that its PSD program would apply to large municipal waste combustors. In a March 30, 1992, letter, EPA stated the following:
Since we proposed approval of this SIP before enactment of the 1990 Clean Air Act Amendments (CAAA), it is necessary that we address several issues in the final approval notice in order to be in conformance with the CAAA.
Municipal Waste Combustion—Section 169(1) is amended by expanding the list of major emitting facilities that are subject to PSD requirements if they emit or have the potential to emit 100 tons per year or more of any regulated pollutant. This list now includes municipal incinerators capable of charging more than fifty tons of refuse per day. This requirement has been effective since November 15, 1990, for all applicable PSD sources. In the conference call [with EPA Region 6], the * * * TACB * * * legal representative said that the TACB has the existing legal authority, and can and will be reviewing such sources for PSD applicability and permitting.
Texas responded in a letter dated April 17, 1992:
We understand that you need confirmation in several areas to conform with the requirements of the 1990 Federal Clean Air Act Amendment * * * before the final delegation will be made.
We will address as a major source subject to PSD review, municipal waste combustors capable of cha[n]ging more than 50 tons of refuse per day as one of the sources subject to PSD review if they emit or have the potential to emit 100 tons per year or more of any regulated pollutant.
Although the TACB Board Order referred to the TACB's general legal authority, the record reveals no discussion or assurances that this legal authority was adequate to apply PSD to pollutants newly subject to regulation. Similarly, the oral assurance that the TACB apparently provided that it had legal authority to apply PSD to large municipal combustors, as required under the then-newly enacted 1990 CAA Amendments, does not address whether Texas had adequate authority to apply PSD to each pollutant that EPA newly subjects to regulation.
The rulemaking record of EPA's approval of Texas's PSD SIP shows that Texas provided two commitments that are relevant for present purposes:
The TACB adopted revisions to TACB Regulation VI on July 17, 1987, which the Governor submitted on October 27, 1987. Those revisions included the following statement, which we call the 1987 Texas PSD Commitments Statement:
Revision To The Texas State Implementation Plan For Prevention Of Significant Deterioration Of Air Quality
The Texas Air Control Board (TACB) will implement and enforce the Federal requirements for Prevention of Significant Deterioration of Air Quality (PSD) as specified in 40 CFR 51.166(a) by requiring all new major stationary sources and major modifications to obtain air quality permits as provided in TACB regulation VI, Control of Air Pollution by Permits for New Construction and Modification. In addition, the TACB will adhere to the following conditions in the implementation of the PSD program:
The TACB will review the adequacy of the Texas PSD plan on an annual basis and within 60 days of the time information becomes available that an applicable increment may be violated. If the TACB determines that an increment is being exceeded due to the violation of a permit condition, appropriate enforcement action will be taken to stop the violation. If an increment is being exceeded due to a deficiency in the state PSD plan, the plan will be revised and the revisions will be subject to public hearing.
This 1987 Texas PSD Commitments Statement does not specifically address the application of PSD to pollutants newly subject to regulation. The first paragraph, as quoted previously in this preamble, commits TACB to require “all new major stationary sources and major modifications to obtain air quality permits as provided in TACB regulation VI * * *,” but this does not commit TACB to address pollutants newly subject to regulation. Instead, this limits the TACB requirement to application of PSD to sources “as provided in TACB regulation VI,” and that regulation VI does not automatically update. As for “4, Plan assessment,” although the first sentence calls for the TACB to review the adequacy of the Texas PSD plan on an annual basis, and although the rest of the provision requires a plan revision if an increment violation is determined to result from a deficiency in the plan, this does not address what happens when a new pollutant becomes subject to regulation and does not require a plan revision to apply to the new pollutant. The fact that Texas agreed to revise the plan if the plan is found to be deficient and that deficiency results in an increment being exceeded serves to highlight the lack of any comparable focus on how the plan would deal with pollutants newly subject to regulation.
EPA's technical support document supporting its proposed approval stated, with respect to this 1987 Texas PSD Commitments Statement:
The “Revision to Texas State Implementation Plan for Prevention of Significant Deterioration of Air Quality” specifies how the TACB will fulfill the requirements of 40 CFR 51.166(a), plan revisions, and plan assessment. The EPA has reviewed the State's commitment and has determined that the TACB has addressed the continuous plan revisions and assessments adequately.
In 1989, as EPA considered Texas's SIP revision submittal, EPA became concerned that a Texas official had made statements that led EPA to question whether Texas would adhere to EPA's interpretation that Best Available Control Technology (BACT) must be implemented through the Top-Down process.
[Y]ou may be assured that the position of the [Texas Air Control Board (TACB)] is, and will continue to be, to implement EPA requirements relative to programs for which we have received State Implementation Plan approval, and to do so as effectively as possible. * * * Again, the TACB is committed to the implementation of EPA decisions regarding PSD program requirements. We look forward
By notice dated December 22, 1989, EPA proposed to fully approve Texas's PSD program.
In adopting the Clean Air Act, Congress designated EPA as the agency primarily responsible for interpreting the statutory provisions and overseeing their implementation by the states. The EPA must approve state programs that meet the requirements of 40 CFR 51.166. Conversely, EPA cannot approve programs that do not meet those requirements. However, PSD is by nature a very complex and dynamic program. It would be administratively impracticable to include all statutory interpretations in the EPA regulations and the SIPs of the various states, or to amend the regulations and SIPs every time EPA interprets the statute or regulations or issues guidance regarding the proper implementation of the PSD program, and the Act does not require EPA to do so. Rather, action by the EPA to approve this PSD program as part of the SIP will have the effect of requiring the state to follow EPA's current and future interpretations of the Act's PSD provisions and EPA regulations, as well as EPA's operating policies and guidance (but only to the extent that such policies are intended to guide the implementation of approved state PSD programs). Similarly, EPA approval also will have the effect of negating any interpretations or policies that the state might otherwise follow to the extent they are at variance with EPA's interpretation and applicable policies. Of course, any fundamental changes in the administration of PSD would have to be accomplished through amendments to the regulations in 40 CFR 52.21 and 51.166, and subsequent SIP revisions.
EPA went on to state that it was basing its proposed approval of Texas's PSD program on Texas's agreement, as contained in the September 5, 1989, letter, that Texas would “implement that PSD SIP approved program in compliance with all of the EPA's statutory interpretations and operating policies.” 54 FR 82,825/2. EPA stated—
* * * EPA's approval of the Texas PSD SIP requires the state to follow EPA's statutory interpretations and applicable policies[], including those concerning [BACT]. * * *
In support of the discussion above, the Executive Director of the TACB has submitted a letter, dated September 5, 1989, which commits the TACB to implement the PSD SIP approved program in compliance with all of the EPA's statutory interpretations and operating policies. Specifically, the TACB's letter states that (1) “* * * you may be assured that the position of the agency is, and will continue to be, to implement EPA requirements relative to programs for which we have received [SIP] approval, and to do so as effectively as possible * * *”, and (2) “* * * the TACB is committed to the implementation of the EPA decisions regarding PSD program requirements * * *”. The EPA has evaluated the content of this letter and has determined that the letter sufficiently commits the TACB to carry out the PSD program in accordance with the Federal requirements as set forth in the [CAA] applicable regulations, and as further clarified in the EPA's statutory and regulatory interpretations, including the proper conduct of BACT analyses. The EPA also interprets this letter as committing the TACB to follow applicable EPA policies such as the “Top-Down” approach. This letter will be incorporated into the SIP upon the final approval action.
EPA issued a final rule to give full approval to the program by notice dated June 24, 1992, 57 FR 28,093. In the final rule, EPA indicated that it had received adverse comments concerning its statements in the proposal that Texas was required to adopt all of EPA's interpretations of the PSD requirements. Accordingly, EPA refined its views. EPA stated:
* * * Texas and other states [have] considerable discretion to implement the PSD program as they see fit.
* * * PSD-SIP approved states remain free to follow their own course, provided that state action is consistent with the letter and spirit of the SIP, when read in conjunction with the applicable statutory and regulatory provisions.
* * *
Consistent with the terms of the TACB letter dated September 5, 1989, EPA views that letter as a commitment on the part of the TACB to “implement EPA program requirements * * * as effectively as possible,” and as a commitment “to the implementation of the EPA decisions regarding PSD program requirements.” EPA
As for the fact that Texas's PSD program was limited to pollutants that were regulated as of the date Texas adopted the program as a SIP revision, but did not automatically apply to newly regulated pollutants, the preamble to the final rule alluded to this limitation:
The State's regulation VI requires review and control of air pollution from new facility construction and modification and allows the TACB to issue permits for stationary sources subject to this regulation. Section 116.3(a)(13) of the TACB Regulation VI incorporates by reference the Federal PSD regulations (40 CFR 52.21) as they existed on August 1, 1987, which include revisions associated with the July 1, 1987, promulgation of revised National Ambient Air Quality Standards for particulate matter (52 FR 24872) and the visibility NSR requirements noted above.
However, there is no indication in the preamble for the final rule that (i) Texas specifically addressed the requirement that its PSD program apply to pollutants newly subject to PSD, including non-NAAQS pollutants, or (ii) Texas provided assurances that it had adequate authority under State law to carry out the PSD program, including applying PSD to pollutants newly subject to regulation, among them non-NAAQS pollutants. Nor is there any indication that EPA asked Texas to do so.
As discussed previously, in 1996 EPA proposed, and in 2002 finalized, what we call the NSR Reform Rule,
As discussed in detail in the rule EPA calls the “Endangerment Finding,”
Some GHGs, such as carbon dioxide (CO
In the United States, the combustion of fossil fuels (
Different GHGs have different heat-trapping capacities. The concept of Global Warming Potential (GWP) was developed to compare the heat-trapping capacity and atmospheric lifetime of one GHG to another. The definition of a GWP for a particular GHG is the ratio of heat trapped by one unit mass of the GHG to that of one unit mass of CO
Over the past year, EPA has completed four distinct actions related to greenhouse gases under the CAA. The result of these rules, in conjunction with the operation of the CAA, has been to trigger PSD applicability for GHG sources on and after January 2, 2011, but to limit the scope of sources covered by PSD. These actions include, as they are commonly called, the “Endangerment Finding” and “Cause or Contribute Finding,” which we issued in a single
In the Endangerment and Cause or Contribute Finding, which is governed by CAA section 202(a), the Administrator exercised her judgment, based on an exhaustive review and analysis of the science, to conclude that “six greenhouse gases taken in combination endanger both the public health and the public welfare of current and future generations.” 74 FR at 66,496. The Administrator also found “that the combined emissions of these greenhouse gases from new motor vehicles and new motor vehicle engines contribute to the greenhouse gas air pollution that endangers public health and welfare under CAA section 202(a).”
The Endangerment Finding led directly to promulgation of the Vehicle Rule, also governed by CAA section 202(a), in which EPA set standards for the emission of greenhouse gases for new motor vehicles built for model years 2012-2016. 75 FR 25,324. The Vehicle Rule established the first controls for GHGs under the CAA.
The Johnson Memo Reconsideration—as well as the Tailoring Rule, which we discuss later—is governed by the PSD and Title V provisions in the CAA. It was issued to address the automatic statutory triggering of the PSD and Title V programs for GHGs due to the Vehicle Rule establishing controls for GHGs. The Johnson Memo Reconsideration provided EPA's interpretation of a pre-existing definition in its PSD regulations delineating the “pollutants” that are taken into account in determining whether a source must obtain a PSD permit and the pollutants each permit must control. The Johnson Memo Reconsideration stated that when the Vehicle Rule takes effect on January 2, 2011, it will, in conjunction with the applicable CAA requirements, trigger the application of PSD to GHG-emitting sources. 75 FR 17,004.
In the Tailoring Rule, EPA limited PSD applicability, at the outset, to only the largest GHG-emitting sources, and to phase-in PSD applicability, as appropriate, to smaller sources over time. 75 FR 31,514. In the Tailoring Rule, EPA identified the air pollutant that, if emitted or potentially emitted by the source in excess of specified thresholds, would subject the source to PSD requirements, as the aggregate of six GHGs: CO
Because PSD is implemented through the SIP system, EPA has taken a series of actions to address the obligations of states (including localities and other jurisdictions, as appropriate) to implement PSD requirements for GHG-emitting sources. EPA has taken these actions through the Tailoring Rule discussed elsewhere in this preamble and a series of subsequent actions.
In the Tailoring Rule, EPA incorporated the PSD thresholds for GHGs in the definition of the term “subject to regulation.” As noted previously, under EPA's PSD regulations, PSD applies to a “major stationary source;” a “major stationary source” is defined as a source that emits 100/250 tons per year (tpy) on a mass basis of a “regulated NSR pollutant;” and a “regulated NSR pollutant,” in turn, is defined as, among other things, a pollutant that is “subject to regulation” under the CAA.
Some states advised EPA that it is likely they would be able to implement the Tailoring Rule thresholds by interpreting the term “subject to regulation” in their SIPs, and without having to take further action. A state's ability to take this approach would have implications for how EPA needed to implement the Tailoring Rule.
To gather this information, EPA, in the Tailoring Rule, asked states to submit letters within 60 days of publication of the Tailoring Rule, which we refer to as the 60-day letters, concerning the status of their PSD program and their legal authority for applying PSD program to GHG-emitting sources. This information would help clarify, for each state, the two central issues for PSD applicability to GHG-emitting sources: (i) Whether the state has an approved PSD program that applies to GHG-emitting sources; and (ii) if so, what action the state would take to limit the applicability of its PSD program to GHG-emitting sources at or
Almost all states submitted 60-day letters, generally by August 4, 2010. The letters, along with other information EPA received through review of state requirements and further communications with state officials, indicate that the states, localities, and other jurisdictions may be divided into three categories, described later in this preamble, for purposes of EPA's implementation of the PSD program to GHG-emitting sources.
The first category, which includes 7 states, 35 subsections of states, the District of Columbia, American Samoa, Guam, Puerto Rico, the U.S. Virgin Islands, and Indian Territory, does not have an approved SIP PSD permitting program. Instead, Federal requirements apply. Thus, implementation of PSD for GHG-emitting sources in these jurisdictions is the simplest of all the states: GHG-emitting sources became subject to PSD and the thresholds in the Tailoring Rule as of January 2, 2011, without further action.
The second category includes 13 states and a number of districts within states that have approved PSD SIPs, but those SIPs do not apply the PSD program to GHG-emitting sources. This group includes Texas, which is the focus of this action. The implementation process for this category is discussed later.
The third category includes the remaining states, which have an approved SIP PSD program that applies to GHG-emitting sources. As for the implementation process for this category, some of these states have indicated that they are able to interpret their SIPs to apply PSD only to GHG emissions at or above the Tailoring Rule thresholds, and that they do not need to revise their SIPs to do so. However, most indicated that they would need to submit SIP revisions to EPA in order to incorporate the Tailoring Rule thresholds. This means that in these states, until they do submit their SIP revisions and EPA approves them, sources emitting GHGs at or above the 100/250 tpy levels are subject to PSD requirements as of January 2, 2011, if they construct or modify. EPA has encouraged these states to submit SIP revisions adopting the Tailoring Rule thresholds as soon as possible and some of these states have already done so. Moreover, almost all of these states are proceeding to revise their state law to reflect the Tailoring Rule thresholds and either did so by January 2, 2011, or very soon thereafter, or are currently in the process of revising their SIPs. In the meantime, EPA has finalized what we call the Narrowing Rule so that as of January 2, 2011, at least for Federal purposes, PSD will apply to GHG-emitting sources only at the Tailoring Rule thresholds or higher.
As just noted, the second category, which includes Texas, includes 13 states and some districts within states whose SIPs have an approved PSD program but do not have the authority to apply that program to GHG-emitting sources. For most of these states, including Texas, the reason is that their PSD applicability provision applies to any “pollutant subject to regulation” under the CAA (or a similar term), but other provisions of state law preclude automatic updating. As a result, this applicability provision covers only pollutants—not including GHGs—that were subject to regulation at the time the state adopted the applicability provision.
After proposing action by notice dated September 2, 2010,
EPA justified its finding that the affected SIPs are “substantially inadequate” to comply with CAA requirements on grounds that (i) the CAA requires that PSD requirements apply to any stationary source that emits specified quantities of any air pollutant subject to regulation under the CAA, and those PSD requirements must be included in the approved SIPs; (ii) as of January 2, 2011, GHG-emitting sources will become subject to PSD; (iii) as a result, the CAA requires PSD programs to apply to GHG-emitting sources; and (iv) accordingly, the failure of any SIP PSD applicability provisions to apply to GHG-emitting sources means that the SIP fails to comply with these CAA requirements.
In the SIP call proposal, EPA discussed in some detail the SIP submittal deadline under CAA section 110(k)(5). Under this provision, in issuing a SIP call, EPA “may establish reasonable deadlines (not to exceed 18 months after the date of such notice) for the submission of such plan revisions.” EPA proposed to allow each of the affected states up to 12 months from the date of signature of the final finding of substantial inadequacy and SIP call within which to submit the SIP revision, unless, during the comment period, the state expressly advised that it would not object to a shorter period—as short as 3 weeks from the date of signature of the
EPA made clear that the purpose of establishing the shorter period as the deadline for any interested state is to accommodate states that wish to ensure that a FIP is in effect as a backstop to avoid any gap in PSD permitting. EPA also made clear that if a state did not advise EPA that it does not object to a shorter deadline, then the 12-month deadline would apply. EPA emphasized that for any state that receives a deadline after January 2, 2011, the affected GHG-emitting sources in that state may be delayed in their ability to receive a Federally approved permit authorizing construction or modification. This is because after January 2, 2011, these sources may not have available a permitting authority to review their permit applications until the date that EPA either approves the SIP submittal or promulgates a FIP.
EPA asked that each of the affected states write EPA a letter during the comment period to identify the deadline for SIP submission to which the state would not object if EPA established. We call these the 30-day letters. Each affected state wrote a 30-day letter to EPA, as requested. Except for Texas, each state identified a SIP submittal deadline, which differed among the states, and which ranged from three weeks to 12 months. In the final SIP call, EPA established SIP submittal deadlines identified by the states, except that EPA established a deadline of 12 months for Texas, in accordance with EPA's proposal. Except for Texas, each state explained in its 30-day letter and in subsequent communications with EPA, that it was planning on either receiving a FIP or adopting a SIP and that it chose a deadline that would result in having either the FIP or an approved SIP, as appropriate, in place by January 2, 2011 or soon enough thereafter so as to avoid any hardship to its sources. In the final SIP call, EPA justified approving this 3-week-to-12-month time period, although expeditious, as meeting the CAA section 110(k)(5) requirement to be a “reasonable” deadline in light of: (i) The SIP development and submission process; (ii) the preference of the state; and (iii) the imperative to minimize the period when sources will be subject to PSD but will not have available a PSD permitting authority to act on their permit application and therefore may face delays in constructing or modifying.
In the final SIP call, based on the states' 30-day letters and other communications, EPA established a SIP submittal deadline of December 22, 2010, for seven states. Each of the states indicated that it did not expect to submit a SIP revision by that date and instead expected to receive a FIP. On December 23, 2010, for each of the seven states, EPA issued a finding of failure to submit its corrective SIP revision by that deadline, and EPA promulgated a FIP.
Except for Texas, EPA expected each of the other states subject to the SIP call to adopt a SIP revision and receive EPA approval of it, or receive a FIP, within the first half of 2011, and, in most cases, substantially sooner. Although none of these states had a permitting authority in place as of January 2, 2011, none of these states expected that gap to pose meaningful difficulties for sources because, depending on the state, the gap would be brief, and the state did not expect any sources to seek a permit during the gap, or even if the state had been the permitting authority during the gap, it could not have completed processing the permits during that time.
As discussed later, Texas has responded to the SIP call differently than the other states. As a result, its GHG-emitting sources do face the prospect of permitting delays. This rulemaking action addresses that situation.
EPA recently summarized the status of its implementation efforts, for all three categories of sources, as follows:
Overall, EPA has received information about the status of 99 jurisdictions (49 states,
Thus, under EPA's implementation program, (i) in every state, (a) only sources at or above the Tailoring Rule thresholds will be subject under Federal law to obtain a PSD permit when they construct or modify as of January 2, 2011, and (b) only those same sources will be subject under state law to obtain a PSD permit when they construct or modify as of January 2, 2011 or very soon thereafter; and (ii) in every state, except for Texas, as of January 2, 2011 or very soon thereafter, GHG sources that construct or modify will be able to receive permits when they need them, so that the sources will not face obstacles to constructing and modifying. Again, Texas has responded to EPA's implementation program in a manner that has resulted in its sources facing obstacles to constructing and modifying, as discussed next, which this rulemaking addresses.
The following describes the progress to date of implementing PSD for GHG emissions in Texas, based on extensive communications between EPA and TCEQ. It should be borne in mind, as noted earlier, that Texas is in the second of the three categories of states: that is, it has an approved PSD program that does not apply to GHGs-emitting sources.
Texas's 60-day letter provides the State's clearest articulation of its response to EPA's efforts to implement PSD for GHG-emitting sources at the Tailoring Rule thresholds beginning January 2, 2011. As noted previously, in the preamble to the final Tailoring Rule, EPA asked each state to send EPA a
In our proposed rule, we also noted that a handful of EPA-approved SIPs fail to include provisions that would apply PSD to GHG sources at the appropriate time. This is generally because these SIPs specifically list the pollutants subject to the SIP PSD program requirements, and do not include GHGs in that list, rather than include a definition of NSR regulated pollutant that mirrors the Federal rule, or because the state otherwise interprets its regulations to limit which pollutants the state may regulate. At proposal, we indicated that we intended to take separate action to identify these SIPs, and to take regulatory action to correct this SIP deficiency.
We ask any state or local permitting agency that does not believe its existing SIP provides authority to issue PSD permits to GHG sources to notify the EPA Regional Administrator by letter, and to do so no later than August 2, 2010. This letter should indicate whether the state intends to undertake rulemaking to revise its rules to apply PSD to the GHG sources that will be covered under the applicability thresholds in this rulemaking, or alternatively, whether the state believes it has adequate authority through other means to issue Federally-enforceable PSD permits to GHG sources consistent with this final rule. For any state that lacks the ability to issue PSD permits for GHG sources consistent with this final rule, we intend to undertake a separate action to issue a SIP call, under CAA section 110(k)(5). As appropriate, we may also impose a FIP through 40 CFR 52.21 to ensure that GHG sources will be permitted consistent with this final rule.
With regard to states in category 3, EPA requested that in the states' 60-day letter,
For any state that is unable or unwilling to adopt the tailoring approach by January 2, 2011, and that otherwise is unable to demonstrate adequate personnel and funding, we will move forward with finalizing our proposal to limit our approval of the existing SIP.
On August 2, 2010, Texas submitted its 60-day letter, signed by the Texas Attorney General and the Chairman of the Texas Commission on Environmental Quality.
Texas' stationary source permitting program encompasses all “federally regulated new source review pollutants,” including, “any pollutant that otherwise is subject to regulation under the [federal Clean Air Act].” 30 Tex. Admin. Code § 116.12(14)(D). The rules of the Texas Commission on Environmental Quality (TCEQ), like the EPA's rules, do not define the phrase “subject to regulation.”
* * * Texas' stationary source permitting program encompasses all “federally regulated new source review pollutants,” including “any pollutant that otherwise is subject to regulation under the [federal Clean air Act].” 30 Tex. Admin. Code § 116.12(14)(D). This delegation of legislative authority to the EPA is limited solely to those pollutants regulated when Texas Rule 116.12 was adopted (1993) and last amended (2006). As the Texas Supreme Court has explained, “The general rule is that when a statute is adopted by a specific descriptive reference, the adoption takes the statute as it exists at that time, and the subsequent amendment thereof would not be within the terms of the adopting act.”
Secondly, Texas took the position that PSD applies only to NAAQS pollutants, and not non-NAAQS pollutants. Texas stated:
The only sensible interpretation of the Clean Air Act is one that requires the EPA to promulgate a National Ambient Air Quality Standard (NAAQS) for greenhouse gases before the EPA can require PSD permitting of greenhouse gases. * * * EPA, however, has not developed a NAAQS for greenhouse gases. * * *
Texas provided a more detailed exposition of its view that PSD applies only to NAAQS pollutants in its challenges before the DC Circuit to EPA's GHG actions, where Texas moved to stay the Endangerment Finding, the Vehicle Rule, and the Johnson Memo Reconsideration (Texas's Motion to Stay Three GHG Actions).
At the close of its 60-day letter, Texas added, “In the event a court concludes EPA's actions comport with the law, Texas specifically reserves and does not waive any rights under the Federal Clean Air Act or other law with respect to the issues raised herein.”
As noted previously, in the GHG PSD SIP call proposal, EPA proposed to establish, for each affected state, a deadline of 12 months from the date of signature of the final SIP call for submitting the corrective SIP revision, unless the state expressly advised EPA in its 30-day letter that it would not object to a shorter period. Texas submitted a 30-day letter on October 4, 2010,
In its 30-day letter, Texas went on to discuss the SIP submission schedule and FIP that EPA proposed, but Texas declined EPA's invitation to identify a specific deadline for the state's SIP submission. As a result, in the final SIP call, EPA was obliged to establish the default SIP submission deadline for Texas of December 1, 2011, in accordance with EPA's proposal. Because Texas has clearly stated that it does not intend, and, in its view, does not have the authority, to adopt a SIP revision to respond to the SIP Call, including to apply PSD to GHG-emitting sources, EPA expects to promulgate a FIP to continue to apply PSD to these sources in December, 2011. But, again, because Texas did not identify an earlier deadline for its SIP submittal, the earliest that EPA could promulgate such a FIP would be December 2, 2011. Under this approach, due to the position Texas has taken, absent further action, sources in Texas could not expect to have a permitting authority with authority to issue preconstruction permits for their GHG emissions until that December 2, 2011, date. As a result, absent further action, sources in Texas would face obstacles in constructing or modifying before that date.
Texas's 30-day letter indicates that Texas was well aware of the consequences of its decision not to identify a specific deadline for its SIP submission, but had several reasons for making that decision. These included its view, again, that PSD applies only to NAAQS pollutants, and also that EPA was required to employ a different process for requiring a SIP revision, one that would have provided the state with 3 years to adopt a SIP revision. Texas 30-day letter at 4-5. In addition, Texas asserted that there is no reason to allow EPA to promulgate an early FIP for the benefit of Texas's sources because, in Texas's view, for practical reasons, EPA could not issue those permits for the “foreseeable future” anyway. Specifically, Texas explained that EPA had not issued guidance for determining BACT, the key element of a PSD permit for a GHG source. Texas added that even after EPA issued that guidance, BACT will, in Texas's view, remain uncertain and contentious, and the guidance will be of limited usefulness until the control technology is proven.
In order to reduce uncertainty for sources and permitting authorities, EPA has issued guidance for use in determining BACT, provided training for permitting authorities and sources, and is continuing to maintain and update resources for use in making these determinations. These resources include question and answer documents and white papers on proven and emerging technologies for reducing greenhouse gas emissions in different industries as well as continued close interaction between sources, permitting authorities, and EPA.
It should be noted that Texas stated in filings before the DC Circuit in which it challenged the Tailoring Rule that it believed 167 projects in Texas would be affected by the lack of a permitting authority during 2011.
In this action, EPA is taking the following actions to ensure that there is a mechanism for large, GHG-emitting sources in Texas to obtain PSD permits under a program that complies with the CAA. First, EPA is determining that the Administrator's action approving the Texas SIP PSD program was in error under CAA section 110(k)(6).
Second, EPA, in the same manner as its past action to approve the Texas SIP PSD program, is revising such action as appropriate without requiring any further submission from Texas.
Third, in this rulemaking, EPA is promulgating a FIP to apply appropriate measures to assure that EPA's PSD regulatory requirements will apply to non-NAAQS pollutants that are newly subject to regulation under the CAA that the Texas PSD program does not already cover. At present, the only such pollutant is GHGs. Therefore, EPA's FIP will at present apply the EPA regulatory PSD program for the GHG portion of PSD permits for GHG-emitting sources in Texas, and EPA commits to take whatever steps are appropriate if, in the future, Texas fails to apply PSD to another newly regulated non-NAAQS pollutant. In light of the immediate need of Texas's GHG-emitting sources for a permitting authority to process their permit applications for GHGs, this rule will be effective on May 1, 2011.
Several commenters disagreed with EPA's position regarding section 165(a) of the CAA and argue that EPA's decision to regulate GHGs had no self-executing effect on the permitting requirements applicable to sources in Texas. These commenters state that the only CAA requirements that are self-executing are found in CAA section 168, a section of the statute that incorporated PSD changes made in the 1977 amendments to the Act. Instead, according to these commenters, GHG-emitting sources became subject to PSD requirements through EPA's revisions to the PSD regulations in 40 CFR 51.166, and those regulations provide states 3 years to revise their SIPS to incorporate changes in the PSD program. Accordingly, one commenter asserted that rather than imposing a “construction permitting moratorium” upon EPA's adoption of a new minimum PSD requirement, the PSD rules provide states a reasonable period of time for incorporating a new minimum PSD requirement, with prospective effect, into SIPs, during which time the EPA-approved SIP continues in force and the state may continue to issue permits under that SIP without addressing the new minimum requirement promulgated by EPA.
EPA indicated in the proposal for this rulemaking, 75 FR at 82,388/2, that in earlier rulemakings, EPA took comment on and resolved the issue of whether the CAA PSD requirements apply by their terms, so that EPA was not soliciting comment on that issue in this rulemaking. In those earlier rulemakings, EPA concluded that the CAA PSD requirements do apply by their terms, so that sources in a state are subject to PSD for their emissions of pollutants newly subject to regulation even if the state has an approved SIP that does not apply PSD to those pollutants.
Even so, for the sake of completeness, and without reopening this issue in this rulemaking, EPA does provide the following response. EPA disagrees with these commenters and EPA continues to take the view that the CAA PSD requirements apply by their terms to pollutants newly subject to regulation, regardless of whether a state with an approved SIP applies PSD to such pollutants. As discussed at length in the preamble to the final PSD GHG SIP call (75 FR 77,707-77,709, Dec 13. 2010), the CAA requirements (i) prohibit a “major emitting facility” from constructing or modifying without obtaining a permit that meets the PSD requirements, CAA section 165(a)(1); and (ii) define a “major emitting facility” as a source that emits a specified quantity of “any air pollutant,” CAA section 169(1), which EPA has long interpreted as any pollutant subject to regulation. 40 CFR 52.166(b)(49)(iv). In this manner, the CAA requirements for PSD applicability are what we call automatically updating, that is, at the very time EPA regulates a previously unregulated pollutant, any source emitting that pollutant in sufficient quantities becomes a “major emitting facility,” and that source cannot construct or modify without receiving a PSD permit. That is, PSD applies to that pollutant at the time it becomes subject to regulation, without further regulatory action by EPA.
EPA regulations have codified this automatically updating aspect of the CAA PSD requirements.
GHG-emitting sources became subject to PSD due to the operation of these CAA and regulatory provisions, in conjunction with the Light-Duty Vehicle Rule. The latter rule subjected GHGs to regulation for the first time, as of January 2, 2011, so that, by operation of the CAA PSD provisions and the associated regulatory provisions, PSD automatically applied to GHG-emitting stationary sources as of that date. The Tailoring Rule codified in 40 CFR 51.166 an interpretation that, read in conjunction with the Light-Duty Vehicle Rule regulations, had the effect of establishing the January 2, 2011 date by which GHGs became subject to regulation,
Accordingly, commenters are incorrect in arguing that the authorization for states to submit PSD SIP revisions within a three-year period, under 40 CFR 51.166(a)(6), means that PSD does not apply to GHG-emitting sources until states submit such a SIP revision. Section 51.166(a)(6) provides, in relevant part: “Any State required to revise its implementation plan
For another, this provision does not apply to the requirement that GHG-emitting sources became subject to PSD as of January 2, 2011. GHG-emitting sources became subject to PSD by operation of the CAA and existing regulations, in conjunction with the Light-Duty Vehicle Rule, not because of any amendment to 40 CFR 51.166. The Tailoring Rule did amend section 51.166, but, again, those amendments did not impose PSD applicability on
Several industry commenters stated that in light of their contention that the PSD program is not self-executing, as discussed earlier in this preamble, then it follows that stationary sources do not violate the CAA if they get permits in accordance with the requirements of an approved state SIP, and they may lawfully construct or modify in accordance with the terms of those permits, even though those permits do not cover their GHG emissions. According to these commenters, sources in Texas need only look to the content of Texas's existing SIP in determining the permitting requirements with which they must comply and sources in Texas can obtain permits now, without addressing GHGs, and lawfully construct or modify in accordance with those permits. One commenter states that CAA Section 113(a)(1) “provides a shield to these sources so long as they comply with the applicable SIP.” Commenters cited the recent decision of the 7th Circuit,
Here, too, EPA stated in the proposal for this rulemaking that because EPA addressed this comment in earlier rulemakings on which this rulemaking is based—including the Tailoring Rule and the GHG PSD SIP Call—EPA was not soliciting comment on this issue and was not required to respond to such comments. 75 FR at 82,388/2,
In the recent
In this action, EPA is determining that EPA's previous approval of Texas's PSD program was in error under CAA section 110(k)(6). In applying CAA section 110(k)(6), EPA must first “determine[] that the Administrator's action approving * * * [the Texas PSD program] was in error * * *.” EPA has determined that the Texas PSD program had flaws at the time Texas submitted it and EPA approved it, so that EPA's approval was in error.
Texas's PSD program, although approved by EPA, contained important gaps concerning the application of PSD to pollutants newly subject to regulation, including non-NAAQS pollutants, and Texas's legal authority for doing so.
The application of the PSD program to pollutants newly subject to regulation, including non-NAAQS pollutants, is a key component of the program. As noted earlier in this preamble, it is EPA's long-standing position that PSD applies to all such pollutants, and most of the states' PSD programs do apply to such pollutants automatically, as soon as those pollutants become subject to regulation.
In particular, as noted previously, EPA made clear to Texas during 1980 and again during 1983 that PSD applies to non-NAAQS pollutants. Because Texas's PSD program, unlike that of most states, did not automatically apply to such pollutants, it was important that during the time when Texas submitted SIP revisions and EPA acted on them, 1985-1992, that Texas address the application of PSD to pollutants newly subject to regulation, including non-NAAQS pollutants.
It is clear from the record that both Texas and EPA were well aware that the Texas PSD rules' IBR of EPA PSD regulatory requirements did not automatically update. Indeed, when EPA promulgated the NAAQS for PM
Had Texas recognized that following approval of its PSD program, EPA would in all likelihood continue to subject previously unregulated pollutants to regulation, and therefore to PSD for the first time, Texas could have addressed how it would handle that situation. For example, Texas could have provided assurances that the state would apply PSD to such pollutants, and could have included those assurances in the form of a SIP revision or as a separate letter. Texas could also have provided information as to the method and timing for applying PSD to such pollutants. The most likely method would be through a separate SIP revision, which would apply PSD specifically with respect to that pollutant. By comparison, as noted earlier in this preamble, Texas committed to submit a SIP revision if a SIP inadequacy led to an increments violation. Alternatively, another method would be to adopt the approach of most other states and adopt a SIP revision to update the program to apply
In addition, depending on how it addressed the need to update its PSD program to apply to pollutants newly subject to regulation, Texas could have addressed the timing of that action. The timing would most likely relate to the time necessary to adopt and submit a SIP revision. This timing issue is important because the sources emitting pollutants are subject to PSD under the CAA as soon as the pollutants become subject to regulation, but if the SIP PSD program does not automatically apply to the sources, then the state does not have authority to issue permits to the sources as soon as the sources become required to obtain the permits.
However, there is no indication in the record of Texas's SIP submissions that Texas specifically addressed this issue of the treatment of pollutants that would newly become subject to PSD after Texas's PSD SIP was approved, or that Texas provided any such information as to method or timing. Nor is there any indication in the record that during this 1985-92 period, EPA identified this issue and sought such information from Texas. As noted elsewhere in this preamble, although both Texas and EPA were well aware that the Texas SIP did not automatically update to include pollutants newly subject to regulation, both failed to look down the road and anticipate that EPA would in all likelihood newly subject more pollutants to regulation. As noted elsewhere in this rulemaking, because the SIP did not address PSD applicability to pollutants newly subject to regulation, the SIP did not meet CAA requirements.
Texas did provide the 1987 Texas PSD Commitments Statement, in which Texas agreed to “implement and enforce the federal requirements for [PSD] as specified in [EPA regulations] by requiring all new major stationary sources and major modifications to obtain air quality permits as provided in TACB regulation VI, Control of Air Pollution by Permits for New Construction and Modification.” However, this 1987 statement does not specifically address the application of PSD to pollutants newly subject to regulation. As just quoted, it commits TACB to require “all new major stationary sources and major modifications to obtain air quality permits as provided in TACB regulation VI* * *”, but that regulation VI does not automatically update, and therefore does not apply to pollutants newly subject to regulation, and does not further address such pollutants.
Texas also provided the 1989 Texas PSD Commitments Letter, in which Texas generally committed “to implement EPA requirements relative to [PSD].” However, as quoted previously, this phrasing is general and therefore cannot be read to commit to apply PSD to pollutants newly subject to regulation, including non-NAAQS pollutants. Nor did the letter identify the method and timing for doing so. Accordingly, we do not read this letter as a commitment by Texas to apply PSD to each newly regulated pollutant, including non-NAAQS pollutants, whether through a SIP revision or some other method, or on any particular time-table. Moreover, although EPA approved the Texas PSD program in reliance on the letter, EPA indicated, in the final approval preamble, that the scope and binding impact of the letter were limited and that Texas retained discretion in implementing the PSD program.
In approving Texas's rule, EPA did not recognize that Texas's SIP did not address pollutants newly subject to regulation. In its 1992 approval rulemaking, EPA noted that “any fundamental changes in the administration of PSD would have to be accomplished through amendments to the regulations in 40 CFR §§ 52.21 and 51.166, and subsequent SIP revisions,” and added:
The EPA did not intend to suggest that Texas is required to follow EPA's interpretations and guidance issued under the Act in the sense that those pronouncements have independent status as enforceable provisions of the Texas PSD SIP, such that mere failure to follow such pronouncements, standing alone, would constitute a violation of the Act* * *.
* * *PSD-SIP approved states remain free to follow their own course, provided that state action is consistent with the letter and spirit of the SIP, when read in conjunction with the applicable statutory and regulatory provisions.
In addition, the rulemaking record for Texas's PSD program does not indicate that Texas provided, as required under CAA section 110(a)(2)(E)(i), assurances that Texas had adequate legal authority to carry out the PSD program, including, insofar as relevant for this rulemaking, applying PSD to pollutants newly subject to regulation, among them non-NAAQS pollutants. Some 15 years previously, in Texas's 1972 submission of its original SIP, the state had provided assurances of legal authority to carry out the SIP, and EPA had approved those assurances. But the record for the PSD SIP submission does not indicate whether, or how, that legal authority applied to PSD applicability to such pollutants. In submitting the PSD SIP program, the TACB provided general references to legal authority, but the TACB did not indicate whether PSD applies to such pollutants either. Nor did the 1989 Texas PSD Commitments Letter specifically identify legal authority to apply PSD to such pollutants. Nor did the assurance of legal authority to apply the Texas PSD program to large municipal waste combustors, as required by the 1990 CAA Amendments, assurances which Texas apparently made in a 1992 conference call with EPA Region 6 officials, and which were referenced in a letter from the Region to TACB, address legal authority to apply PSD to pollutants that newly become subject to PSD as a result of EPA regulation.
Therefore, the Texas PSD SIP submittal contained gaps: it did not address the application of PSD to pollutants newly subject to regulation,
Texas has recently made several statements that confirm that at the time EPA approved the state's PSD program, that program had the gaps described previously.
First, Texas has made clear its view that it is not required to apply PSD to non-NAAQS pollutants that are newly subject to regulation, including GHGs. Specifically, in its August 2, 2010, 60-day letter, Texas stated that it interprets the CAA PSD applicability provisions to apply only to NAAQS pollutants, and therefore to not include non-NAAQS pollutants, among them GHGs. Texas asserted that “the only sensible interpretation of the CAA” is that PSD applies to only NAAQS pollutants. Texas 60-day letter, p. 4. Indeed, in its court challenge to EPA's four GHG rules, Texas stated that its interpretation is mandated under
For present purposes, however, what is important is that Texas takes the position that under a
Texas's EPA-approved SIP PSD applicability provisions apply PSD to “any air pollutant subject to regulation under the [Clean Air] Act.” Although these Texas provisions mirror EPA's provisions—which, again, Texas appears to interpret as limited to applying PSD only to NAAQS pollutants—Texas is authorized to apply its provisions more expansively than the EPA regulations. This is because a state must comply with CAA requirements as a minimum, but retains authority to impose additional or more stringent requirements. CAA section 116. Therefore, it is in accordance with Texas's view that the CAA and EPA regulatory requirements for PSD applicability be limited to NAAQS pollutants, that Texas would nevertheless consider itself authorized—but not required—to apply its PSD program to particular non-NAAQS pollutants. This position would allow Texas, in effect, to choose which non-NAAQS pollutants to subject to PSD, and which not.
In fact, Texas has clearly stated that it does not consider itself required to apply its PSD program to one non-NAAQS pollutant in particular: GHGs. In its 60-day letter, Texas stated: “Texas has neither the authority nor the intention of interpreting, ignoring, or amending its laws in order to compel the permitting of greenhouse gas emissions.” Texas 60-day letter, at 1. Texas's letter went on to provide numerous reasons for why it did not believe EPA lawfully subjected GHGs to PSD; why, in any event, EPA was required to allow states more time before PSD would apply to GHG-emitting sources; and, as noted previously, why, in any event, Texas's SIP does not automatically update to apply PSD to newly regulated pollutants.
With this statement—that “Texas has neither the authority nor the intention of interpreting, ignoring, or amending its laws in order to compel the permitting of greenhouse gas emissions”- Texas has made clear that it does not view itself as obligated to apply PSD to GHGs under the CAA. Thus, this statement is fully consistent with, and highlights, Texas's view that it is not obligated to apply PSD to each newly regulated non-NAAQS, including, of course, GHGs.
These statements from Texas are significant because they confirm that Texas's PSD program, as approved by EPA, had an important gap: Texas did not address the applicability of its PSD program to pollutants newly subject to regulation, including non-NAAQS pollutants, such as by providing assurances that Texas would take action to apply PSD to such pollutants or describing the methods (such as SIP revision) and timing for doing so. Moreover, Texas's recent statements are consistent with the view that Texas's silence on the subject at the time of the PSD SIP action means that Texas did not, at that time, view itself as obligated to apply PSD to each pollutant.
In particular, Texas's recent statement that the CAA PSD provisions are clear by their terms, as a matter of
We further note that Texas itself appears to take the position that an agency's present interpretation of its regulations should be presumed to have been the agency's past interpretation of those regulations, so that Texas's current interpretation that its PSD program does not apply to at least one non-NAAQS, GHGs, should be presumed to be Texas's interpretation of its PSD program in the past, including at the time Texas submitted its program as a SIP revision to EPA and EPA approved it. Specifically, in its 60-day letter, Texas noted that in the Tailoring Rule, EPA asked states to consider whether their SIPs that include the term “subject to regulation” can be interpreted to incorporate the Tailoring Rule thresholds on grounds that the state interprets that term as being sufficiently open-ended. 75 FR 51,581/2. Texas stated,
In the Tailoring Rule you have asked TCEQ to report to you by August 2, 2010, whether it would “interpret” the undefined phrase “subject to regulation” in TCEQ Rule 116.12 consistent with the newly promulgated definition in EPA Rule 51.166, in all its specifics and particulars. That is, you have effectively requested that Texas agree to regulate greenhouse gases in the exact manner and method proscribed by the EPA.
In other words, you have asked Texas to agree that when it promulgated its air quality permitting program rules for pollutants “subject to regulation” in 1993, that Texas really meant to define the term “subject to regulation” as set forth in the dozens of paragraphs and subparagraphs of EPA Rule 51.166, first promulgated in 2010.
By the same token, Texas's recent statements also confirm that the assurances Texas provided in its 1989 Texas PSD Commitments Letter cannot be interpreted as having committed Texas to apply PSD to all pollutants newly subject to regulation, including non-NAAQS pollutants. The assurances, by their terms, were phrased generally and did not address the application of PSD to such pollutants; and EPA, in the preamble for the final approval of Texas's PSD SIP, indicated that the scope and binding impact of the assurances were limited.
As a result, it stands to reason that at the time Texas submitted its PSD program, Texas did not view the CAA as mandating the application of PSD to at least certain pollutants newly subject to regulation, non-NAAQS pollutants. But at a minimum, it can be said that Texas's PSD program contained a gap: EPA required that PSD apply to each pollutant newly subject to regulation, including non-NAAQS pollutants; Texas's program applied only to pollutants already subject to regulation at the time Texas adopted its program, not to subsequently regulated pollutants, including non-NAAQS; and Texas did not address its program's applicability to such pollutants, including how or when its program would so apply. This gap is significant because it facilitates Texas's current position, with which EPA disagrees, that PSD does not apply to non-NAAQS pollutants.
Texas's statement in its 60-day letter that it “has neither the authority nor the intention of interpreting, ignoring, or amending its laws in order to” apply PSD to GHG-emitting sources also highlights that Texas's PSD program had a gap in its failure to provide “necessary assurances” of adequate legal authority to carry out the PSD program.
It is possible that at the time that Texas submitted its PSD program, Texas considered itself under the same limits in its legal authority. At a minimum, in light of these recent statements that it does not have authority to apply PSD to at least one newly regulated, non-NAAQS, GHGs, it is apparent that at the time that Texas submitted its PSD program, Texas did not provide the “necessary assurances” that it “will have adequate * * * authority under State * * * law to carry out such implementation plan (
The Texas PSD program's gaps—which are, again, that Texas did not address the applicability of PSD to all pollutants newly subject to regulation, including non-NAAQS pollutants; and Texas did not provide assurances of adequate legal authority to do so—mean that the state's PSD program has flaws. These flaws were present at the time that EPA approved Texas's PSD program. Moreover, these flaws are significant. They have figured prominently into the present situation in which EPA takes the position that Texas is obligated under the CAA and EPA regulations to apply its PSD program to a newly regulated pollutant—GHGs—but Texas takes the opposite position.
Several commenters, including both the Texas Commission on Environmental Quality (TCEQ) and the Texas Attorney General, object to EPA's determination that the Texas SIP is flawed. TCEQ comments that nothing in “ * * * the CAA or federal PSD rules require that state PSD programs apply to pollutants
EPA disagrees with these comments. Contrary to the TCEQ's comments, as discussed elsewhere in this rulemaking preamble, the PSD requirements in the CAA and regulations do require that PSD SIPs address the applicability of PSD to pollutants newly subject to regulation. As discussed previously, the CAA PSD provisions and EPA's PSD regulations are clear that PSD applies to each newly regulated pollutant, whether a NAAQS pollutant or a non-NAAQS pollutant. Moreover, the CAA is clear that SIPs must include provisions to assure that CAA requirements are met.
With respect to the Texas Attorney General, the comment that EPA's regulations do not require automatic updating of SIPs to incorporate such pollutants misses the point. In the Interim Final Rule and the proposal, EPA did not identify the gap in Texas's SIP PSD provisions as based on the lack of automatic updating to apply PSD to each pollutant newly subject to regulation. Rather, EPA identified the gap as the failure of the State, at the time it submitted and EPA approved the PSD program, to address such pollutants. The State could have specifically acknowledged the issue of the applicability of PSD to newly regulated pollutants and addressed that issue in several different ways. Providing an automatic updating mechanism is one way, which is what most of the other states do. Second, the State could have committed, in either the SIP itself or in a letter accompanying the SIP submittal, that the State would adopt and submit for approval SIP revisions to apply PSD to newly regulated pollutants, and the State could have indicated a schedule for it to do so. Third, it is possible that more general assurances by the State to address the issue could have passed muster. In addition, there may be other ways to address this issue. The record does not indicate that Texas specifically identified the issue or identified any ways that Texas would address the issue. Moreover, as discussed earlier in this preamble, Texas failed to demonstrate that it had adequate legal authority to regulate these pollutants.
In this rulemaking, EPA is “determin[ing]” that EPA's action fully approving Texas's PSD program was “in error” within the meaning of CAA section 110(k)(6). This section contains EPA's basis for that determination.
Under the familiar
As noted previously, the term “error” in CAA section 110(k)(6) is not defined and, as a result, should be given its ordinary, everyday meaning. The dictionary definition of “error” is “a mistake” or “the state or condition of being wrong in conduct or judgment,”
Moreover, CAA section 110(k)(6) authorizes EPA to “determine[]” that its action was in error, and does not direct or constrain that determination in any manner. That is, the provision does not identify any factors that EPA must, or may not, consider in making the determination. This further indicates that this provision confers broad discretion upon EPA.
As previously discussed, the Texas SIP PSD program was flawed because it contained gaps: Texas did not address the applicability of PSD to all pollutants newly subject to regulation, including non-NAAQS pollutants; and Texas did not provide assurances of adequate legal authority to do so. EPA did not address these gaps in its action on Texas SIP PSD program and instead, EPA fully approved the PSD program.
Therefore, EPA's action in fully approving Texas's SIP PSD program in the face of these flaws was “in error” under CAA section 110(k)(6), in accordance with
Even if the term “error” is not considered unambiguously to encompass, under
Several other commenters, however, challenged the use of section 110(k)(6) in this instance. Commenters stated that section 110(k)(6) of the Act has been understood and was intended by Congress to be used as authority to make corrections of a “technical” or ministerial nature, such as “typographical errors.” This section was not, according to commenters intended as a means to make unilateral, substantive changes in SIPs or major policy changes. These commenters view EPA's action here as directly contrary to the Act's cooperative federalism scheme.
For the reasons discussed elsewhere in this preamble, Texas's SIP was flawed and as a result, EPA's action in approving that flawed SIP was in error.
As a result, this rulemaking action is simply the correction of an error, as authorized under CAA § 110(k)(6). Contrary to some comments, this action is not based on a policy shift in EPA's administration of the PSD program. Nor does this action upset federalism concerns or constitute a claim of authority to unilaterally revise any action on any SIP submittal. EPA does not read section 110(k)(6) to provide unlimited discretion to act on SIP submissions, only to provide authority to make error corrections.
In any event, for the reasons noted earlier in this preamble, EPA's action in this rulemaking qualifies as an error correction within the meaning of CAA section 110(k)(6). Whether the affected state—or any other party—agrees or disagrees that the SIP that is the subject of the error correction is flawed is not a criteria under CAA section 110(k)(6).
A commenter focused on the requirement that EPA's action must
As explained previously, we view Texas's recent statements that the CAA does not apply to non-NAAQS pollutants and that Texas has neither the authority nor the intention to apply PSD to GHGs as an indication that at the time Texas submitted its PSD program, Texas did not address the applicability of its program to pollutants newly subject to regulation or provide assurances that it had legal authority to apply its program to such pollutants. Absent specific evidence to the contrary, we are not inclined to conclude that at the time EPA approved the Texas PSD program in 1992, Texas in fact had filled those gaps—by, for example, providing assurances that it would apply PSD to each newly regulated non-NAAQS pollutants and had the legal authority to do so—but that more recently, Texas has failed to comply with those assurances. The CAA is based on a partnership between the states and the Federal government, and we think it more consonant with the principles of that partnership to interpret the evidence as indicating that Texas never addressed the gap or provided the requisite assurances.
However, in the alternative, if one were to conclude that during the course of Texas's submittal of, and EPA's action on, the State's PSD program, Texas did in fact, address the applicability of its program to newly regulated pollutants and did in fact provide the requisite assurances, so that no gaps in Texas's PSD program existed at that time, then Texas's recent statements would amount to failing to comply with, or even rescinding, those assurances. Under these circumstances, EPA would still consider its previous approval of Texas's PSD SIP to have been in error. This is because if Texas should be considered to have addressed the issue and to have provided the appropriate assurances, then EPA should be considered to have based its approval on those assurances. For example, EPA stated in approving the Texas PSD program that EPA was relying on the 1989 Texas PSD Commitments Letter. Rescinding or failing to comply with those assurances—if that is what Texas is considered to have done—would eliminate the basis for EPA's approval.
Under CAA section 110(k)(6), once EPA determines that its previous action approving a SIP revision was in error, EPA “may ... revise such action as appropriate without requiring any further submission from the State. * * *” Under this provision, EPA may revise its previous full approval of Texas's PSD program as appropriate, without requiring any submission from Texas.
This provision offers EPA a great deal of discretion in revising its previous action. For one thing, the use of the term “may” means that this provision simply authorizes, and does not require, EPA to revise its previous action even after EPA has determined the error, and that, in turn, implies that EPA has discretion in determining how to revise its previous action. Moreover, if EPA does decide to revise its previous action, EPA may do so in any way that is “appropriate.” The term “appropriate” offers EPA significant latitude in deciding what type of revision to do.
Here, EPA is revising its previous full approval of Texas's PSD program to be a partial approval and partial disapproval. Specifically, EPA is retaining the approval of Texas's PSD program to the extent of the pollutants that the PSD program already does cover. This amounts to a partial approval. In addition, EPA is disapproving the Texas PSD program to the extent it has not addressed the applicability of its PSD program to each pollutant newly subject to regulation, including non-NAAQS pollutants, and because it has not provided assurances of adequate legal authority to apply its PSD program to such sources.
As an alternative to the error correction provision of CAA section 110(k)(6), EPA is using its inherent administrative authority to reconsider its prior approval actions as a basis for revising its previous full approval of the Texas PSD program to a partial approval and partial disapproval. This authority
As noted earlier, EPA approved the Texas PSD program by notice dated June 24, 1992, 57 FR 28,093, under the authority of CAA section 110(k)(3)-(4). These provisions authorize EPA to approve a SIP submittal “as a whole,” “approve [the SIP submittal] in part and disapprove [it] in part,” or issue a “conditional approval” of a SIP submittal. EPA issued a full approval under CAA section 110(k)(3).
In its approval action under that provision, EPA retained inherent authority to revise that action. The courts have found that an administrative agency has the inherent authority to reconsider its decisions, unless Congress specifically proscribes the agency's discretion to do so.
Section 301(a) of the CAA, read in conjunction with CAA section 110(k)(3) and the case law just described, provides statutory authority for EPA's reconsideration action in this rulemaking. Section 301(a) authorizes EPA “to prescribe such regulations as are necessary to carry out [EPA's] functions” under the CAA. Reconsidering prior rulemakings, when necessary, is part of “[EPA's] functions” under the CAA—in light of EPA's inherent authority as recognized under the case law to do so—and as a result, CAA section 301(a) confers authority upon EPA to undertake this rulemaking.
EPA finds further support for its authority to narrow its approval in APA section 553(e), which requires EPA to give interested persons “the right to petition for the issuance, amendment, or repeal of a rule;” and CAA section 307(b)(1), which expressly contemplates that persons may file a petition for reconsideration under certain circumstances (at the same time that a rule is under judicial review). These authorizations for other persons to petition EPA to amend or repeal a rule suggest that EPA has inherent authority, on its own, to issue such amendment or repeal. This is because EPA may grant a petition from another person for an amendment to or repeal of a rule only if justified under the CAA, and if such an amendment or repeal is justified under the CAA, then EPA should be considered as having inherent authority to initiate the process on its own, even without a petition from another person.
EPA recently used its authority to reconsider prior actions and limit its prior approval of a SIP in connection with California conformity SIPs.
EPA is relying, in the alternative, on this inherent authority to convert its previous approval of Texas's PSD program to a partial approval and partial disapproval for the same reasons discussed previously in connection with the “error” correction provision of CAA section 110(k)(6). That is, EPA approved Texas's PSD program even though that program had significant flaws because Texas did not address the applicability of its PSD program to all pollutants newly subject to regulation, including non-NAAQS, and that Texas had adequate legal authority to do so.
EPA's inherent authority to reconsider its previous action also supports revising its previous action in the same manner, and for the same reasons, as under CAA section 110(k)(6), as described earlier. That is, in light of the flaws in the Texas PSD program, EPA is revising EPA's previous full approval to be a partial approval (to the extent of the pollutants regulated under the CAA that are subject to Texas's PSD program) and a partial disapproval (to the extent Texas's program does not address pollutants newly subject to regulation, including non-NAAQS pollutants).
Several commenters questioned EPA's ability to use section 301(a) given that EPA already has the authority to take this action through the SIP revision process. There is no gap for the Agency to fill with its general rulemaking authority, so, according to these commenters, EPA cannot use this section of the CAA to authorize this SIP revision without going through the notice and comment process required for a SIP revision. One commenter goes on to question whether the enactment of section 110(k)(6) would have been necessary if EPA had authority under section 301(a).
EPA's inherent authority to reconsider its actions in conjunction with CAA section 301(a) is not limited by the availability of the SIP revision process. That process entails the state submitting a revised SIP submission and EPA acting on it, which is fundamentally different than EPA reconsidering its action on the initial SIP submission without the state needing to submit a SIP revision. In addition, the reconsideration authority is broader than the section 110(k)(6) authority because the former is not necessarily limited to the correction of errors. And if, as commenters argue, the section 110(k)(6) authority is limited to only technical or typographical errors, then the reconsideration authority is substantially broader. For these reasons, the reconsideration authority should not be considered to have been pre-empted or otherwise eliminated by the availability of either the SIP revision process or the error correction process.
As for reasons why Congress would have added section 110(k)(6) if the reconsideration authority already existed, several reasons present themselves. Congress may have intended to codify into the CAA the reconsideration authority, which otherwise would have remained in the case law. In doing so, Congress established the criteria and process for error corrections. In addition, three years prior to the enactment of the 1990 CAA Amendments, the U.S. Court of Appeals for the Third Circuit (3rd Circuit) handed down a decision in
As noted previously, EPA has recently taken another action concerning Texas's PSD program as that program relates to GHGs: the GHG PSD SIP call, which we published by notice dated December 13, 2010, 75 FR 77,698. This section describes the relationship of this error-correction/partial-disapproval/FIP action to the SIP call. For convenience, the background for the SIP call, although described in detail earlier in this preamble, is reiterated here.
EPA promulgated the SIP call under CAA section 110(k)(5), which provides:
Whenever the Administrator finds that the applicable implementation plan for any area is substantially inadequate to * * * comply with any requirement of [the CAA], the Administrator shall require the State to revise the plan as necessary to correct such inadequacies. The Administrator * * * may establish reasonable deadlines (not to exceed 18 months) after [notifying the state of the inadequacies] for the submission of such plan revisions.
Accordingly, EPA required each state, including Texas, to submit a corrective SIP revision. EPA established a deadline for the SIP submittal for each state as 12 months from the date of the SIP call, or December 1, 2011, unless the state indicated in its 30-day letter that it did not object to an earlier deadline. Each state for which EPA would finalize the SIP call submitted a 30-day letter, and each, except for Texas, indicated a date sooner than December 1, 2011. Texas did not indicate any particular date and, as a result, EPA established December 1, 2011 as Texas's deadline. In addition, EPA stated that if Texas or any of the other states failed to submit its corrective SIP revision by its deadline, EPA intended to promulgate a FIP immediately thereafter.
The timing of the SIP call—both the time that EPA promulgated the SIP call and the deadlines it established for SIP submittals—was driven by the fact that the affected states did not have authority to issue PSD permits to GHG-emitting sources and as a result, those sources could face delays in construction and modification when they became subject to PSD as early as January 2, 2011. EPA designed the SIP call to maximize the opportunity of each affected state to assure that its sources would have a permitting authority available as of that date or a later date, if the state concluded that a later date would not leave its sources facing delays. EPA did so by allowing each state flexibility for its SIP submittal deadline.
Each of the affected states except Texas responded with a plan that would assure that its sources would not confront permitting delays. Most states—7 of the 13 states—indicated they would not object to EPA's establishing a SIP submittal date of December 22, 2010, recognizing that as a practical matter, that meant that EPA would promulgate a FIP on December 23, 2010. An eighth state (Kentucky) took the same approach for one of its counties (Jefferson County), except that it selected the slightly later date of January 1, 2011.
Texas responded differently than the other states. In its 30-day letter, Texas did not indicate a particular date for its SIP submittal, and as a result, EPA, as we had proposed, established Texas's deadline at December 1, 2011. But shortly before submitting its 30-day letter, Texas stated, in its 60-day letter, that “Texas has neither the authority nor the intention of interpreting, ignoring, or amending its laws in order to compel the permitting of greenhouse gas emission.”
This means that a permitting authority for GHG-emitting sources would not be in place until EPA promulgated a FIP, no earlier than December 2, 2011. Importantly, Texas has indicated that this one-year delay in the availability of a permitting authority would, in fact, mean that under EPA's interpretation of the CAA, Texas's sources would face delays in constructing and modifying.
Moreover, Texas's indication that it does not intend to submit a SIP revision, and that it does not consider its PSD program as being required to apply to non-NAAQS pollutants, including GHGs, has cast a spotlight on underlying flaws in Texas's fully approved PSD SIP, and that, in turn, has brought into play the error-correction provision in CAA section 110(k)(6). All this is discussed in detail earlier in this preamble, but to reiterate for convenience: CAA section 110(k)(6) provides, “Whenever the Administrator determines that the Administrator's action approving * * * any [SIP] * * * was in error, the Administrator may * * * revise such action as appropriate.* * *” Here, the Texas SIP was flawed at the time EPA approved it because it did not address, or assure adequate legal authority for, application of the PSD program to pollutants newly subject to regulation, including non-NAAQS pollutants. As a result, EPA has the authority to determine that its full approval of the SIP was “in error” and to convert that action to a partial approval and partial disapproval; and as a result of that, EPA is authorized to promulgate a FIP immediately.
This is an important reason why EPA is proceeding with this error-correction/partial approval and partial disapproval rulemaking at this time. This approach allowed EPA to implement a FIP immediately as an interim rule, instead of waiting until December, 2011, and as a result, EPA has been able to act as the permitting authority in Texas and in that capacity, allow Texas sources to avoid delays in construction or modification. This same approach allows EPA to continue to keep the FIP in place and continues to act as the permitting authority so that there are no gaps in coverage for sources to obtain permits.
With the interim final rule and the present rulemaking, EPA has both (i) promulgated a SIP call and established a SIP deadline of December 1, 2011 for Texas, under CAA section 110(k)(5); and (ii) corrected its error in previous fully approving Texas's PSD program by converting that action to a partial approval and partial disapproval, under CAA section 110(k)(6), and then promulgating a FIP immediately, under CAA section 110(c)(1)(B). For the reasons just discussed, each of these actions is fully justified under the applicable CAA provisions.
Moreover, there is no preclusion against taking both of these actions with respect to Texas at this time, for the following reasons: First, the two actions are based on CAA provisions—CAA section 110(k)(5) (SIP call), and section 110(k)(6) (error correction)—that overlap, so that it is to be expected that circumstances may arise in which both apply. If EPA approves a flawed SIP, then circumstances could well arise under which EPA has a basis for concluding both that (i) the SIP is “substantially inadequate” to meet a CAA requirement, under CAA section 110(k)(5); and (ii) EPA's action in approving the SIP was “in error,” under CAA section 110(k)(6). The same flaw in the SIP would be the basis for each of those actions.
This is the case with EPA's two actions concerning Texas. As EPA stated in the SIP call, the basis for the finding of “substantial inadequacy” was the failure of Texas's approved SIP PSD program to apply to GHGs, which was rooted in the program's failure to apply pollutants newly subject to regulation. As EPA stated earlier in this preamble, the basis for the determination that EPA's previous full approval of Texas's SIP was “in error” was the gap in the SIP due to the SIP's failure to address, or assure that it has adequate legal authority for, the application to pollutants newly subject to regulation.
Second, each provision, by its terms, is discretionary to EPA, and neither provision precludes the application of the other. CAA section 110(k)(5) applies “[w]henever the Administrator finds” that the SIP is substantially inadequate. CAA section 110(k)(6) applies “[w]henever the Administrator determines” that her previous action was in error. Neither provision references the other. Neither provision includes any requirement or limitation that constrains the application of the other at any time.
Third, each provision serves a different purpose and when applied to this case—including in conjunction with the FIP provision in CAA section 110(c)(1)—leads to a different outcome, but each outcome is neither dependent on, or compromised by, the other outcome. CAA section 110(k)(5), as applied in the current case, is focused on a present problem with the SIP, that is, a “substantial[] inadequacy” that currently exists. This provision mandates that EPA require a corrective SIP revision to address that inadequacy, but further provides that EPA must allow a reasonable deadline for the state to submit the SIP revision. In the GHG PSD SIP call, EPA allowed states to, in effect, choose within a range of deadlines. But if the state fails to submit the required SIP revision by its deadline, then EPA is required to promulgate a FIP under CAA section 110(c)(1)(A). CAA section 110(k)(6), as it applies in the current case, is focused on a past problem with SIP, that is, a flaw that existed at the time EPA approved the SIP, so that EPA's approval was “in error.” This provision authorizes EPA to convert the approval to a disapproval, but does not mandate that the state submit a new SIP revision. This is because the state has already submitted a SIP revision, the one that is flawed, and EPA has acted on it. Instead, EPA is required to promulgate a FIP under CAA section 110(c)(1)(B), and EPA may do so immediately. The FIP will remain in place until the state submits, and EPA approves, a SIP revision.
Viewing the two provisions as applied here together: (i) CAA section 110(k)(5) allows EPA to exercise its discretion to make a finding that Texas's SIP is “substantially inadequate,” and then to establish a SIP submittal schedule for Texas, one that is consistent with whatever choice as to deadline Texas had available to it; and (ii) CAA section 110(k)(6) allows EPA to exercise its discretion to convert its previous approval of Texas's SIP, which EPA made “in error,” to a disapproval, and then to promulgate a FIP immediately. The requirement that Texas submit a corrective SIP revision and do so by a date certain—a date that Texas exercised some control over—serves the useful function of establishing a mechanism and a timeframe for Texas to address the substantial inadequacy in its PSD SIP.
It is true that one of the purposes of the SIP call, as applied here, was to allow states to in effect select an early FIP—by selecting an early SIP submittal date and then not submitting a SIP by that date—so as to assure the availability of a permitting authority for their sources by that early date. And it is further true that Texas, in its 30-day letter, chose not to select such an early date and, on the contrary, stated its opposition to a FIP; yet, in this present rulemaking, EPA is promulgating an immediate FIP for Texas. But this does not mean that the present rulemaking has compromised the SIP call or any choices made available to Texas in the SIP call. The focus of the SIP call, as it related to Texas, was the finding of a substantial inadequacy in Texas's PSD program, the imposition of a requirement for Texas to submit a corrective SIP revision, and—based on Texas's choice—the establishment of a deadline of December 1, 2011 for Texas to do so. The promulgation of an immediate FIP through the present rulemaking does not disturb that. Texas remains subject to the December 1, 2011, SIP submittal schedule that EPA established for it, based on Texas's decision not to respond directly to
It is also true that, as EPA stated in the SIP call, “federalism principles * * * underlie the SIP call process and the SIP system as a whole,” and that means that “in the first instance, it is to the state to whom falls the responsibility of developing pollution controls through an implementation plan.” 75 FR 77,710/2. And it is further true that the immediate promulgation of a FIP through the present error-correction action means that a FIP will be in place in Texas before the December 1, 2011 deadline established under the SIP call for Texas to adopt its SIP. However, imposition of the FIP is fully justified under this error-correction action, as discussed previously, and is essential to assure that Texas sources will not face delays in construction or modification, a risk that Texas acknowledges will occur under EPA's interpretation of the applicable CAA requirements. In any event, Texas's statement that “Texas has neither the authority nor the intention of interpreting, ignoring, or amending its laws in order to compel the permitting of greenhouse gas emission,”
It is also true that under the principles of federalism that underlie the SIP system, states exercise some discretion over controls for their industry, so that a state may impose more stringent controls than minimum CAA requirements. CAA section 116. But this discretion does not mean that Texas is authorized to create the circumstances under which its sources face delays in constructing or modifying and EPA is precluded from promulgating a FIP—when justified under this rulemaking—for the purpose of protecting those sources against such delays. Absent this action, Texas sources would face delays in construction and modification resulting from Texas's decision during the course of the SIP call to neither adopt a SIP promptly nor facilitate an early FIP. Those delays do not result from Texas's decision to impose more stringent controls than the CAA requires. On the contrary, Texas's action is inconsistent with one of the purposes of the PSD provisions, which is “to insure that economic growth will occur in a manner consistent with the preservation of clean air resources.” CAA section 160(3). EPA is justified in interpreting and applying CAA section 110(k)(6) to correct errors related to Texas's SIP PSD program in order to effectuate this purpose of PSD. The DC Circuit has held that the terms of the PSD provisions should be interpreted with the PSD purposes in mind,
EPA is not, at this time, undertaking a similar error-correction rulemaking for any of the other states that are subject to the SIP call. EPA has discretion as to whether and when to undertake such a rulemaking, and each of the other states has chosen a course of action that at present appears to assure that its large GHG-emitting sources will have a permitting authority available when the sources need one, and therefore will not face delays in constructing or modifying. As a result, EPA has not inquired into whether any of these other states have flaws in their SIP PSD programs as Texas does.
Industry commenters, in addition to the State of Texas, raised concerns about this rule treating Texas differently than other states. Other states, such as Arizona, Arkansas, Connecticut, Florida, Idaho, and Kansas, do not have SIPs that automatically update to incorporate new requirements, and so regulate new pollutants in a “stepwise” fashion, according to these commenters. Moreover, these commenters argue that EPA's approval of Texas's SIP cannot be considered to have been in error because, they say, EPA approved other SIPs that, like Texas's, did not automatically apply PSD to each pollutant newly subject to regulation.
Several industry commenters also stated that they believe that EPA's rationale for this rule, read in conjunction with EPA's PSD Narrowing Rule 75 FR 8253682,536 (December 30, 2010) makes it impossible for a state to ever have an approvable SIP. This is because, according to these commenters, states can only have an approvable SIP if they automatically incorporate Federal requirements when EPA adopts them. However, the PSD Narrowing Rule was required because those states that do “impose PSD applicability on new pollutants in an unconstrained manner” in their SIPs do not ensure that states have adequate funding and personnel to implement the new SIP requirements, according to commenters.
EPA disagrees with the comments that we are singling out Texas for unfair treatment for its failure to automatically update its SIP to incorporate new requirements. Texas is, in fact, unlike each of these other states. Texas, uniquely among all the states, has stated that it will not implement PSD requirements for GHGs either by revising or committing to revise its SIP. It is this refusal that has shined a spotlight on EPA's error in previously approving Texas's SIP, for the reasons discussed earlier in this preamble. Moreover, each of the other states identified by commenters has taken measures to ensure that permitting for GHG-sources in its state will be available. Arizona, Arkansas, Florida, and Idaho each have a FIP in place to allow EPA to issue permits to GHG-emitting sources. Connecticut has submitted a SIP revision to enable the state to assume responsibility for PSD permitting of these sources. Kansas already has an approved SIP that applies PSD to GHGs. Accordingly, it has never been necessary for EPA to inquire, and EPA has not inquired, into whether these states have flaws in their PSD SIPs. In addition, the error correction provision is discretionary: it provides that EPA “may” undertake an
EPA also disagrees with the commenters that contend that no SIP could possibly be approvable given the rationales presented for this rule and the SIP Narrowing Rule. In this action, EPA identifies as the flaw in the SIPs the failure to address the applicability of PSD to newly regulated pollutants (along with the failure to provide adequate assurances of legal authority to apply PSD to such pollutants). As noted earlier in this preamble, there are several ways that states could address this flaw, and although providing for automatic updating is one way—and the one that most states have adopted—it is not the only way. A state could, for example, commit to adopt a SIP revision to apply PSD to a newly regulated pollutant. In the course of addressing the applicability of PSD to a newly regulated pollutant, the state could address any associated resource issues. Moreover, as EPA explained in the SIP Narrowing rule, the flaw that needed correcting by that rule was the “combination of that unconstrained applicability and the failure of the SIP to plan for adequate resources for that applicability,
In this rulemaking, EPA is promulgating a FIP to apply EPA's PSD regulatory program to GHG-emitting sources in Texas and to commit to take action as appropriate with respect to pollutants that become newly subject to regulation.
The CAA authority for EPA to promulgate a FIP is found in CAA section 110(c)(1), which provides—
The Administrator shall promulgate a Federal implementation plan at any time within 2 years after the Administrator * * * (B) disapproves a State implementation plan submission in whole or in part, unless the State corrects the deficiency, and the Administrator approves the plan or plan revision, before the Administrator promulgates such [FIP].
As indicated earlier in this notice, EPA is partially disapproving Texas's PSD program by correcting EPA's previous full approval to be a partial approval and partial disapproval. Accordingly, under CAA section 110(c)(1)(B), EPA is required to promulgate a PSD FIP for Texas.
The FIP must be designed to address the flaws in Texas's PSD program. As discussed earlier in this preamble, the Texas PSD program contains significant gaps: It does not address, or provide assurances of adequate legal authority for, application to pollutants newly subject to regulation, including non-NAAQS pollutants. As a practical matter, at present, the only pollutant the program does not address is GHGs. Accordingly, the FIP applies the EPA regulatory PSD program to GHGs. In addition, the FIP commits to address pollutants that become newly subject to regulation, as appropriate.
EPA is promulgating the FIP in this rulemaking, so that it takes effect immediately upon the partial disapproval. This timing for FIP promulgation is authorized under CAA section 110(c)(1), which authorizes us to promulgate a FIP “at any time within 2 years after” EPA disapproves a SIP submission in whole or in part. The quoted phrase, by its terms, establishes a two-year period within which EPA must promulgate the FIP, and provides no further constraints on timing. Accordingly, this provision gives EPA discretion to promulgate the FIP at any point in time within that two-year period, and in this rulemaking, EPA is promulgating the FIP immediately.
The reason why we are exercising our discretion to promulgate the FIP immediately is to minimize any period of time during which larger-emitting sources in Texas may be under an obligation to obtain PSD permits for their GHGs when they construct or modify, but no permitting authority is authorized to issue those permits. We believe that acting immediately is in the best interests of the regulated community. Note that for similar reasons, in EPA's recently promulgated SIP call, EPA stated that if a state failed to submit its required SIP revision by its deadline, EPA would immediately make a finding of failure to submit and immediately thereafter promulgate a FIP. 75 FR 53,889/2.
The lack of constraints in CAA section 110(c)(1)(B) stands in contrast to other CAA provisions that do impose requirements for the timing of proposals.
The FIP consists of two components. The first mirrors the GHG PSD FIP that EPA promulgated for seven states for which EPA issued the PSD GHG SIP call and, subsequently, issued a finding of failure to submit a required SIP submittal. Thus, this component of the FIP consists of the EPA regulations found in 40 CFR 52.21, including the PSD applicability provisions, with a limitation to assure that, strictly for purposes of this rulemaking, the FIP applies only to GHGs. Under the PSD applicability provisions in 40 CFR 52.21(b)(50), the PSD program applies to sources that emit the requisite amounts of any “regulated NSR pollutant[s],” including any air pollutant “subject to regulation.” However, Texas's partially approved SIP already applies PSD to other air pollutants. To appropriately limit the scope of the FIP, EPA amends 40 CFR 52.21(b)(50), as incorporated into the Texas FIP, to limit the applicability provision to GHGs.
We adopt this FIP because, as we stated in the proposed GHG PSD FIP—
In accordance with the Tailoring Rule, * * * the FIP would apply in Step 1 of the phase-in approach only to “anyway sources” (that is, sources undertaking construction or modification projects that are required to apply for PSD permits anyway due to their non-GHG emissions and that emit GHGs in the amount of at least 75,000 tpy on a CO
Under the FIP, with respect to permits for “anyway sources,” EPA will be responsible for acting on permit applications for only the GHG portion of the permit, and the state will retain responsibility for the rest of the permit. Likewise, with respect to permits for sources that meet the 100,000/75,000-tpy threshold, our preferred approach—for reasons of consistency—is that EPA will be responsible for acting on permit applications for only the GHG portion of the permit, that the state permitting authorities will be responsible for the non-GHG portion of the permit, and EPA will coordinate with the state permitting authority as needed in order to fully cover any non-GHG emissions that, for example, are subject to BACT because they exceed the significance levels.
The second component of the FIP consists of a commitment that EPA will take such action as is appropriate to ensure that pollutants that become newly subject to regulation are subject to the FIP. If a pollutant becomes newly subject to regulation in the future, and if Texas does not take steps to subject it to its PSD program, then EPA will take the appropriate action.
In the GHG PSD FIP proposal, commenters raised concerns about how having EPA issue the GHG portions of a permit while allowing states under a FIP to continue to be responsible for issuing the non-GHG portions of a PSD permit will work in practice. Commenters specifically identified the potential for a source to be faced with conflicting requirements and the need to mediate among permit engineers making BACT decisions.
We well recognize that dividing permitting responsibilities between two authorities—EPA for GHGs and the state, Texas, in this case, for all other pollutants—will require coordination between the two authorities to avoid duplication, conflicting determinations, and delays. We note that this situation is not without precedent. In many instances, EPA has been the PSD permitting authority but the state has accepted a delegation for parts of the PSD program, so that a source has had to go to both the state and EPA for its permit. In addition, all nonattainment areas in the nation are in attainment or are unclassifiable for at least one pollutant, so that every nonattainment area is also a PSD area. In some of these areas, the state is the permitting authority for nonattainment NSR and EPA is the permitting authority for PSD. As a result, there are instances in which a new or modifying source in such an area has needed a nonattainment NSR permit from the state and a PSD permit from EPA.
EPA is working expeditiously to develop recommended approaches for EPA regions and affected states to use in addressing the shared responsibility of issuing PSD permits for GHG-emitting sources. EPA delegated the authority to issue PSD permits to GHG-emitting sources to one state, and is working toward similar delegations in other states. In addition, EPA has provided training and guidance for permitting authorities in determining GHG BACT for these sources.
In addition, we note that the concern over dual permitting authorities would become moot if Texas were either to submit and EPA approve a SIP revision that applies PSD to GHGs or request a delegation of permitting responsibility. If it did request and receive a delegation, it would be responsible for issuing both the GHG part and the non-GHG part of the permit, and that would moot concerns about split-permitting.
In the FIP proposal, we stated our intention to leave any promulgated FIP in place for as short a period as possible, and to process any corrective SIP revision submitted by the state to fulfill the requirements of the SIP call as expeditiously as possible. Specifically, we stated:
After we have promulgated a FIP, it must remain in place until the state submits a SIP revision and we approve that SIP revision. CAA section 110(c)(1). Under the present circumstances, we will act on a SIP revision to apply the PSD program to GHG sources as quickly as possible. Upon request of the state, we will parallel-process the SIP submittal. That is, if the state submits to us the draft SIP submittal for which the state intends to hold a hearing, we will propose the draft SIP submittal for approval and open a comment period during the same time as the state hearing. If the SIP submittal that the state ultimately submits to us is substantially similar to the draft SIP submittal, we will proceed to take final action without a further proposal or comment period. If we approve such a SIP revision, we will at the same time rescind the FIP.
We continue to have these same intentions. Thus, we reaffirm our intention to leave the GHG PSD FIP in place only as long as is necessary for the state to submit and for EPA to approve a SIP revision that includes PSD permitting for GHG-emitting sources. As discussed in more detail later in this preamble, EPA continues to believe that the states, including Texas, should remain the primary permitting authority.
Specifically, EPA will rescind the FIP, in full or in part, if (i) Texas submits, and EPA approves, a SIP revision to apply Texas's PSD program to GHG-emitting sources, (ii) Texas provides assurances that in the future, it will apply its PSD program to all pollutants newly subject to regulation, including non-NAAQS pollutants, and (iii) Texas provides “necessary assurances” under CAA section 110(a)(2)(E)(ii) that it “will have adequate * * * authority under State law” to apply its PSD program to such pollutants.
In addition, if Texas does not submit a SIP revision by December 1, 2011, in response to the SIP Call, EPA intends to promulgate, on or about December 2, 2011, the FIP associated with the SIP call. The GHG provisions of the FIP promulgated with this error correction rulemaking will be fully consistent with the provisions in the FIP associated with the SIP call. The remaining components of the FIP promulgated with this error correction rulemaking,
This action to partially approve and partially disapprove Texas's SIP PSD program and to promulgate a FIP is secondary to our overarching goal, which is to assure that it will be Texas that will be the permitting authority. EPA continues to recognize that Texas is best suited to the task of permitting because the state and its sources have experience working together in the state PSD program to process permit applications. EPA seeks to remain solely in its primary role of providing guidance and acting as a resource for Texas as it makes the various required permitting decisions for GHG emissions.
Accordingly, we are prepared to work closely with Texas to help it promptly develop and submit to us a SIP revision that extends its PSD program to GHG-emitting sources and that assures that the program will apply to each pollutant newly subject to regulation in the future. If Texas submits such a SIP revision, we intend to promptly act on it, and if we approve it, then we intend to rescind the FIP immediately. Again, EPA's goal is to have in place in Texas the necessary permitting authority by the time businesses seeking construction permits need to have their applications processed and the permits issued—and to achieve that outcome by means of engaging with Texas directly through a concerted process of consultation and support.
EPA is taking up the additional task of partially disapproving Texas's PSD program and promulgating the FIP at this time only because the Agency believes it is compelled to do so by the need to assure businesses, to the maximum extent possible and as promptly as possible, that a permitting authority is available to process PSD permit applications for GHG-emitting sources once they become subject to PSD requirements. At the same time, we invite Texas to accept a delegation of authority to implement the FIP, so that it will still be the state that processes the permit applications, albeit operating under Federal law.
Under Executive Orders (EO) 12866 (58 FR 51,735, October 4, 1993) and 13563 (76 FR 3,821, January 21, 2011), this action is a “significant regulatory action” because it raises novel legal or policy issues. Accordingly, EPA submitted this action to the Office of Management and Budget (OMB) for review under EOs 12866 and 13563 and any changes made in response to OMB recommendations have been documented in the docket for this action.
This action does not impose any new information collection burden. The OMB has previously approved the information collection requirements contained in the existing regulations for PSD (
The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comments rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions.
For purposes of assessing the impacts of this rule on small entities, small entity is defined as: (1) A small business as defined in the U.S. Small Business Administration's (SBA) regulations at 13 CFR 121.201); (2) a small governmental jurisdiction that is a government of a city, county, town, school district, or special district with a population of less than 50,000; or (3) a small organization that is any not-for-profit enterprise that is independently owned and operated and is not dominant in its field.
Although this rule would lead to Federal permitting requirements for certain sources, those sources are large emitters of GHGs. After considering the economic impacts of this rule on small entities, I certify that this action will not have a significant economic impact on a substantial number of small entities. This final rule will not impose any requirements on small entities.
This action contains no Federal mandates under the provisions of Title II of the Unfunded Mandates Reform Act of 1995 (UMRA, 2 U.S.C. 1531-1538) for state, local or Tribal governments or the private section. The action imposes no enforceable duty on any state, local or Tribal governments or the private sector. With this action, EPA is only revising its previous approval of the Texas PSD SIP to be a partial approval and partial disapproval and promulgating a FIP to address the deficiencies as authorized by the CAA. Thus, this rule is not subject to the requirements of sections 202 or 205 of UMRA.
This action is also not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments.
This action does not have federalism implications. It will not have substantial direct effects on Texas, on the relationship between the national government and Texas, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. The CAA specifies conditions under which states may request, and EPA may approve state implementation of CAA requirements. The CAA also specifies the action EPA is to take, including issuing a FIP, when states have not met their requirements under the CAA. This rulemaking does not change that distribution of power between the states and EPA. With this action, EPA is only revising its previous approval of the Texas PSD SIP to be a partial approval and partial disapproval and promulgating a FIP to address the deficiencies identified in the Texas SIP as authorized by the CAA. Thus, Executive Order 13132 does not apply to this action.
In the spirit of Executive Order 13132, and consistent with EPA policy to promote communications between EPA and state and local governments, EPA solicited comment on the proposal for this action. Comments from state government organizations are addressed within this preamble and supporting materials available in the docket for this rulemaking.
This action does not have Tribal implications, as specified in Executive Order 13175 (65 FR 67,249, November 9, 2000). In this action, EPA is not addressing any Tribal implementation plans. This action is limited to Texas's
EPA interprets EO 13045 (62 FR 19,885, April 23, 1997) as applying only to those regulatory actions that concern health or safety risks, such that the analysis required under section 5-501 of the EO has the potential to influence the regulation. This action is not subject to EO 13045 because EPA is only revising its previous approval of the Texas PSD SIP to be a partial approval and partial disapproval and promulgating a FIP to address the deficiencies as authorized by the CAA.
This action is not a “significant energy action” as defined in Executive Order 13211 (66 FR 28,355 (May 22, 2001)), because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. With this action, EPA is only revising its previous approval of the Texas PSD SIP to be a partial approval and partial disapproval and promulgating a FIP to address the deficiencies as authorized by the CAA. This action will provide energy facilities in Texas that are large emitters of GHG a mechanism to get necessary PSD permits to construct or modify.
Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (“NTTAA”), Public Law 104-113, 12(d) (15 U.S.C. 272 note) directs EPA to use voluntary consensus standards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (
This rulemaking does not involve technical standards. Therefore, EPA is not considering the use of any voluntary consensus standards.
Executive Order 12898 (59 FR 7,629, February 16, 1994) establishes Federal executive policy on environmental justice. Its main provision directs Federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in the U.S.
EPA has determined that this final rule will not have disproportionately high and adverse human health or environmental effects on minority or low-income populations because it does not affect the level of protection provided to human health or the environment. With this action, EPA is only revising its previous approval of the Texas PSD SIP to be a partial approval and partial disapproval and promulgating a FIP to address the deficiencies as authorized by the CAA.
The Congressional Review Act, 5 U.S.C. 801,
Section 307(b)(1) of the CAA specifies which Federal Courts of Appeal have jurisdiction to hear petitions for review of which final actions by EPA. This section provides, in part, that petitions for review must be filed in the Court of Appeals for the District of Columbia Circuit: (i) When the agency action consists of “nationally applicable regulations promulgated, or final actions taken, by the Administrator,” or (ii) when such action is locally or regionally applicable, if “such action is based on a determination of nationwide scope or effect and if in taking such action the Administrator finds and publishes that such action is based on such a determination.”
This rule is based on a determination of nationwide scope or effect. Texas's response to the SIP call—including Texas's statements that it does not intend to submit a SIP revision and its decision not to identify a SIP submittal deadline, which have placed its sources at risk for delays in construction or modification—led us to determine that we should examine whether there may be a flaw in Texas's SIP that was present at the time of our approval. We then conducted a closer inquiry and on the basis of that, we are concluding that in fact a flaw was present. As a result, we are authorized to undertake an error correction, as we are doing in this rulemaking. For all other states subject to the SIP call, their response to the SIP call—which did not raise the concerns Texas's did and which assured that their sources would not be at risk for delays in construction or modification—led us to determine that it was not necessary to examine further whether their SIPs were flawed at the time we approved them. That determination—whether to examine the SIPs further—is a determination of nationwide scope or effect because it affected Texas and the 12 other states subject to the SIP call. Further indication that this is a determination is of nationwide scope or effect is that EPA is making it as part of the complex of rules EPA has promulgated to implement the GHG PSD program for each of the states in the nation. Those rules include (i) the Tailoring Rule and the Johnson Memo Reconsideration, which revise EPA regulations to incorporate the Tailoring Rule thresholds, and which apply in each state that does not have an approved SIP PSD program, and therefore operates under EPA's regulations; (ii) the SIP Call, which applies in each state that has an EPA-approved SIP PSD program but does not apply that program to GHG-emitting sources; and (iii) the PSD Narrowing rule, which applies in each state that has an EPA-approved SIP PSD program
Thus, under section 307(b)(1) of the Act, judicial review of this final action is available by filing of a petition for review in the U.S. Court of Appeals for the District of Columbia Circuit by July 5, 2011.
Pursuant to CAA section 307(d)(1)(B), this action is subject to the requirements of CAA section 307(d) to the extent it promulgates a FIP under CAA section 110(c). In addition, pursuant to CAA section 307(d)(1)(V), which authorizes the Administrator to determines that actions other than those specifically listed in CAA section 307(d)(1) are subject to the provisions of CAA section 307(d), EPA is making that determination for this action to the extent it constitutes an error correction under CAA section 110(k)(6); a rescission of EPA's previous approval and a limited approval and disapproval of Texas's PSD SIP, under CAA section 110(k)(3); or any other action.
The statutory authority for this action is provided by sections 101, 110, 114, 116, 301, and 307(d) of the CAA as amended (42 U.S.C. 7401, 7410, 7414, 7416, 7601, and 7607(d)).
Air pollution control, Carbon dioxide, Carbon dioxide equivalents, Carbon monoxide, Environmental protection, Greenhouse gases, Hydrofluorocarbons, Incorporation by reference; Intergovernmental relations, Lead, Methane, Nitrogen dioxide, Nitrous oxide, Ozone, Particulate matter, Perfluorocarbons, Reporting and recordkeeping requirements, Sulfur hexafluoride, Sulfur oxides, Volatile organic compounds.
For the reasons set out in the preamble, title 40, chapter I of the Code of Federal Regulations is amended as follows:
42 U.S.C. 7401
(a) The requirements of sections 160 through 165 of the Clean Air Act are not met to the extent the plan, as approved, for Texas does not apply with respect to emissions of the pollutant GHGs from certain stationary sources. Therefore, the provisions of § 52.21 except paragraph (a)(1) are hereby made a part of the plan for Texas for:
(1) Beginning on May 1, 2011, the pollutant GHGs from stationary sources described in § 52.21(b)(49)(iv), and
(2) Beginning July 1, 2011, in addition to the pollutant GHGs from sources described under paragraph (a)(1) of this section, stationary sources described in § 52.21(b)(49)(v).
(b) For purposes of this section, the “pollutant GHGs” refers to the pollutant GHGs, as described in § 52.21(b)(49)(i).
(c) In addition, the United States Environmental Protection Agency shall take such action as is appropriate to assure the application of PSD requirements to sources in Texas for any other pollutants that become subject to regulation under the Federal Clean Air Act for the first time after January 2, 2011.